[Federal Register Volume 89, Number 113 (Tuesday, June 11, 2024)]
[Rules and Regulations]
[Pages 49280-49586]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2024-10872]
[[Page 49279]]
Vol. 89
Tuesday,
No. 113
June 11, 2024
Part II
Department of Energy
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Federal Energy Regulatory Commission
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18 CFR Part 35
Building for the Future Through Electric Regional Transmission Planning
and Cost Allocation; Final Rule
Federal Register / Vol. 89, No. 113 / Tuesday, June 11, 2024 / Rules
and Regulations
[[Page 49280]]
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DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
18 CFR Part 35
[Docket No. RM21-17-000; Order No. 1920]
Building for the Future Through Electric Regional Transmission
Planning and Cost Allocation
AGENCY: Federal Energy Regulatory Commission, Department of Energy.
ACTION: Final order.
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SUMMARY: The Federal Energy Regulatory Commission (Commission) revises
the pro forma Open Access Transmission Tariff (OATT) to remedy
deficiencies in the Commission's existing regional and local
transmission planning and cost allocation requirements. In this final
order, the Commission requires transmission providers to conduct Long-
Term Regional Transmission Planning that will ensure the
identification, evaluation, and selection, as well as the allocation of
the costs, of more efficient or cost-effective regional transmission
solutions to address Long-Term Transmission Needs. The Commission also
directs other reforms to improve coordination of regional transmission
planning and generator interconnection processes, require consideration
of certain alternative transmission technologies in regional
transmission planning processes, and improve transparency of local
transmission planning processes and coordination between regional and
local transmission planning processes. These reforms are intended to
ensure that existing regional and local transmission planning and cost
allocation requirements are just, reasonable, and not unduly
discriminatory or preferential.
DATES: This final order is effective August 12, 2024.
FOR FURTHER INFORMATION CONTACT:
David Borden (Technical Information), Office of Energy Policy and
Innovation, 888 First Street NE, Washington, DC 20426, (202) 502-8734,
[email protected].
Noah Lichtenstein (Technical Information), Office of Energy Market
Regulation, 888 First Street NE, Washington, DC 20426, (202) 502-8696,
[email protected].
Michael Kellermann (Legal Information), Office of the General
Counsel, 888 First Street NE, Washington, DC 20426, (202) 502-8491,
[email protected].
SUPPLEMENTARY INFORMATION:
Table of Contents
Paragraph Nos.
I. Introduction and Background.......................... 1
A. Historical Framework: Order Nos. 888, 890, and 14
1000...............................................
B. ANOPR and Technical Conference................... 20
C. Joint Federal-State Task Force on Electric 22
Transmission.......................................
D. Notice of Proposed Rulemaking.................... 26
E. High-Level Overview of NOPR Comments............. 36
F. Use of Terms..................................... 37
II. The Overall Need for Reform......................... 47
A. NOPR Proposal.................................... 47
B. Comments......................................... 49
C. Commission Determination......................... 85
1. The Transmission Investment Landscape Today.. 90
2. Unjust, Unreasonable, and Unduly 112
Discriminatory or Preferential Commission-
Jurisdictional Transmission Planning and Cost
Allocation Processes...........................
3. Benefits of Long-Term Regional Transmission 134
Planning and Cost Allocation To Identify and
Plan for Long-Term Transmission Needs..........
4. Conclusion................................... 139
III. Long-Term Regional Transmission Planning........... 140
A. Requirement To Participate in Long-Term Regional 140
Transmission Planning..............................
1. NOPR Proposal................................ 140
2. Comments..................................... 145
a. General Comments......................... 145
b. Requests for Flexibility in Transmission 151
Planning...................................
c. Comments Regarding More Comprehensive 163
Transmission Planning......................
d. Concerns Regarding Favoring Renewable 172
Resources..................................
e. Concerns Regarding Uncertainty, Over- 176
Building, and Costs........................
f. Concerns Regarding Incentives for 187
Resource Development.......................
g. Comments Regarding Definition of Long- 189
Term Regional Transmission Facility........
h. Challenges to Commission Jurisdiction or 190
Authority..................................
i. Other Issues............................. 215
j. Miscellaneous Concerns................... 217
3. Commission Determination..................... 224
a. Participation in Long-Term Regional 224
Transmission Planning......................
b. Definition of Long-Term Regional 250
Transmission Facility......................
c. Legal Authority To Adopt Reforms for Long- 253
Term Regional Transmission Planning........
B. Development of Long-Term Scenarios............... 284
1. NOPR Proposal................................ 284
2. Comments..................................... 286
a. General Comments......................... 286
b. Applying Scenario Planning to Reliability 296
and Economic Planning......................
3. Commission Determination..................... 298
C. Long-Term Scenarios Requirements................. 307
1. Transmission Planning Horizon................ 307
a. NOPR Proposal............................ 307
b. Comments................................. 309
c. Commission Determination................. 344
2. Frequency of Long-Term Scenario Revisions.... 352
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a. NOPR Proposal............................ 352
b. Comments................................. 354
c. Commission Determination................. 377
3. Categories of Factors........................ 387
a. Requirement To Incorporate Categories of 387
Factors....................................
b. Specific Categories of Factors........... 422
c. Treatment of Specific Categories of 495
Factors....................................
d. Stakeholder Process and Transparency..... 519
4. Number and Development of Long-Term Scenarios 538
a. NOPR Proposal............................ 538
b. Comments................................. 541
c. Commission Determination................. 559
5. Types of Long-Term Scenarios................. 564
a. NOPR Proposal............................ 564
b. Comments................................. 566
c. Commission Determination................. 575
6. Sensitivities for High-Impact, Low-Frequency 578
Events.........................................
a. NOPR Proposal............................ 578
b. Comments................................. 580
c. Commission Determination................. 593
7. Specificity of Data Inputs................... 602
a. NOPR Proposal............................ 602
b. Comments................................. 606
c. Commission Determination................. 633
8. Identification of Geographic Zones........... 645
a. NOPR Proposal............................ 645
b. Comments................................. 650
c. Commission Determination................. 665
D. Evaluation of the Benefits of Regional 667
Transmission Facilities............................
1. Requirement for Transmission Providers To Use 669
a Set of Seven Required Benefits...............
a. NOPR Proposal............................ 669
b. Comments................................. 673
c. Commission Determination................. 719
2. Required Benefits............................ 740
a. The Seven Required Benefits.............. 740
3. Identification, Measurement, and Evaluation 823
of the Benefits of Long-Term Regional
Transmission Facilities........................
a. NOPR Proposal............................ 823
b. Comments................................. 824
c. Commission Determination................. 837
4. Evaluation of Transmission Benefits Over a 843
Longer Time Horizon............................
a. NOPR Proposal............................ 843
b. Comments................................. 845
c. Commission Determination................. 859
5. Evaluation of the Benefits of Portfolios of 871
Transmission Facilities........................
a. NOPR Proposal............................ 871
b. Comments................................. 872
c. Commission Determination................. 889
6. Issues Related to Use of Benefits............ 891
a. NOPR Proposal............................ 891
b. Comments................................. 892
c. Commission Determination................. 902
E. Evaluation and Selection of Long-Term Regional 904
Transmission Facilities............................
1. Requirement To Adopt an Evaluation Process 904
and Selection Criteria.........................
a. NOPR Proposal............................ 904
b. Comments................................. 906
c. Commission Determination................. 911
2. Flexibility.................................. 919
a. NOPR Proposal............................ 919
b. Comments................................. 920
c. Commission Determination................. 924
3. Minimum Requirements......................... 927
a. NOPR Proposal............................ 927
b. Comments................................. 930
c. Commission Determination................. 954
4. Role of Relevant State Entities.............. 972
a. NOPR Proposal............................ 972
b. Comments................................. 973
c. Commission Determination................. 994
5. Voluntary Funding Opportunities.............. 1003
a. NOPR Proposal............................ 1003
b. Comments................................. 1004
c. Commission Determination................. 1012
6. No Selection Requirement..................... 1019
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a. NOPR Proposal............................ 1019
b. Comments................................. 1020
c. Commission Determination................. 1026
7. Other Issues................................. 1029
a. Comments................................. 1029
b. Commission Determination................. 1031
8. Reevaluation................................. 1033
a. NOPR Proposal............................ 1033
b. Comments................................. 1035
c. Commission Determination................. 1048
F. Implementation of Long-Term Regional Transmission 1062
Planning...........................................
1. NOPR Proposal................................ 1062
2. Comments..................................... 1064
a. Comments on the Initial Timing Sequence.. 1064
b. Comments on Periodic Forums.............. 1067
3. Commission Determination..................... 1071
a. Initial Timing Sequence Implementation... 1071
b. Periodic Forums.......................... 1075
IV. Coordination of Regional Transmission Planning and 1076
Generator Interconnection Processes....................
A. Need for Reform and Overall Reform............... 1076
1. NOPR Proposal................................ 1076
2. Comments..................................... 1079
a. On the Overall Reform.................... 1079
b. Requesting Additional Reform............. 1081
c. Concerns With the Overall Reform......... 1085
d. Cost Allocation.......................... 1093
e. Interconnection Queue Gaming 1095
Considerations.............................
f. Miscellaneous............................ 1098
3. Need for Reform.............................. 1100
4. Commission Determination..................... 1106
B. Transmission Planning Process Evaluation......... 1122
1. NOPR Proposal................................ 1122
2. Comments..................................... 1123
3. Commission Determination..................... 1126
C. Qualifying Criteria.............................. 1130
1. NOPR Proposal................................ 1130
2. Comments..................................... 1134
3. Commission Determination..................... 1145
V. Consideration of Dynamic Line Ratings and Advanced 1163
Power Flow Control Devices.............................
A. General Proposal................................. 1163
1. NOPR Proposal................................ 1163
2. Comments on General Proposal................. 1167
3. Need for Reform.............................. 1194
4. Commission Determination..................... 1198
B. Specific Alternative Transmission Technologies... 1217
1. NOPR Proposal................................ 1217
2. Comments on Specific Technologies............ 1218
3. Commission Determination..................... 1239
VI. Regional Transmission Cost Allocation............... 1248
A. Cost Allocation for Long-Term Regional 1248
Transmission Facilities............................
1. Cost Allocation Methods for Long-Term 1248
Regional Transmission Facilities...............
a. NOPR Proposal............................ 1248
b. Comments................................. 1252
c. Commission Determination................. 1291
2. Requirement that Transmission Providers Seek 1308
the Agreement of Relevant State Entities
Regarding the Cost Allocation Method or Methods
for Long-Term Regional Transmission Facilities.
a. NOPR Proposal............................ 1308
b. Comments................................. 1313
c. Commission Determination................. 1354
3. Proposals Relating to the Design and 1369
Operation of State Agreement Processes.........
a. NOPR Proposal............................ 1369
b. Comments................................. 1371
c. Commission Determination................. 1402
4. Filing Rights Under the FPA.................. 1422
a. Comments................................. 1422
b. Commission Determination................. 1428
5. Time Period and Related Issues in the Long- 1432
Term Regional Transmission Planning Cost
Allocation Processes for State-Negotiated
Alternate Cost Allocation Method...............
a. NOPR Proposal............................ 1432
b. Comments................................. 1436
c. Commission Determination................. 1456
B. Long-Term Regional Transmission Facility Cost 1458
Allocation Compliance With the Existing Six Order
No. 1000 Regional Cost Allocation Principles.......
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1. NOPR Proposal................................ 1458
2. Comments..................................... 1459
a. General Proposal......................... 1459
b. Comments Specific to a State Agreement 1467
Process....................................
3. Commission Determination................. 1469
C. Identification of Benefits Considered in Cost 1480
Allocation for Long-Term Regional Transmission
Facilities.........................................
1. NOPR Proposal................................ 1480
2. Comments..................................... 1482
a. Agree With Proposal...................... 1482
b. Requests To Reflect the Full Breadth of 1491
Benefits in Cost Allocation Methods While
Maintaining Flexibility....................
c. Disagree With Proposal, Mostly Require 1492
Benefits...................................
d. Alignment of Benefits Between 1497
Transmission Planning and Cost Allocation..
e. Additional Benefits or Suggestions for 1502
Refinement.................................
3. Commission Determination..................... 1505
D. Miscellaneous Cost Allocation Comments and 1516
Proposals..........................................
1. Comments..................................... 1516
2. Commission Determination..................... 1521
VII. Construction Work in Progress Incentive............ 1524
A. NOPR Proposal.................................... 1524
B. Comments......................................... 1525
1. Interest in the NOPR Proposal................ 1525
2. Concerns With the NOPR Proposal.............. 1532
3. Interaction of the CWIP Incentive With the 1545
Abandoned Plant Incentive......................
C. Commission Determination......................... 1547
VIII. Exercise of a Federal Right of First Refusal in 1548
Commission-Jurisdictional Tariffs and Agreements.......
A. NOPR Proposal.................................... 1548
B. Comments......................................... 1553
1. General Perspectives and Approach to Reform.. 1553
2. Comments on the NOPR's Joint Ownership 1560
Proposal.......................................
C. Commission Determination......................... 1563
IX. Local Transmission Planning Inputs in the Regional 1565
Transmission Planning Process..........................
A. Need for Reform.................................. 1565
1. NOPR......................................... 1565
2. Comments..................................... 1567
3. Commission Determination..................... 1569
B. Enhanced Transparency of Local Transmission 1578
Planning Inputs in the Regional Transmission
Planning Process...................................
1. NOPR Proposal................................ 1578
2. Comments..................................... 1581
a. Interest in Enhanced Transparency of 1581
Local Transmission Planning Inputs.........
b. Suggested Modifications to the NOPR 1586
Proposal...................................
c. Concern With the NOPR Proposal........... 1591
d. Specific Stakeholder Meeting Requirements 1601
e. Additional Issues........................ 1613
3. Commission Determination..................... 1625
a. Specific Stakeholder Meeting Requirements 1638
b. Additional Issues........................ 1647
C. Identifying Potential Opportunities to Right-Size 1649
Replacement Transmission Facilities................
1. Eligibility.................................. 1649
a. NOPR Proposal............................ 1649
b. Comments................................. 1652
c. Commission Determination................. 1677
2. Right of First Refusal....................... 1693
a. NOPR Proposal............................ 1693
b. Comments................................. 1694
c. Commission Determination................. 1702
3. Cost Allocation.............................. 1710
a. NOPR Proposal............................ 1710
b. Comments................................. 1712
c. Commission Determination................. 1716
4. Miscellaneous................................ 1723
a. Comments................................. 1723
b. Commission Determination................. 1735
X. Interregional Transmission Coordination.............. 1740
A. NOPR Proposal.................................... 1740
B. Comments......................................... 1744
C. Commission Determination......................... 1751
XI. Compliance Procedures............................... 1759
A. NOPR Proposal.................................... 1759
B. Comments......................................... 1761
C. Commission Determination......................... 1768
XII. Information Collection Statement................... 1775
XIII. Environmental Analysis............................ 1784
XIV. Regulatory Flexibility Act......................... 1785
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XV. Document Availability............................... 1789
XVI. Effective Date and Congressional Notification...... 1792
I. Introduction and Background
1. In this final order, the Commission acts under section 206 of
the Federal Power Act (FPA) to adopt reforms to its electric
transmission planning and cost allocation requirements.\1\ The reforms
herein will remedy deficiencies in the Commission's existing regional
and local transmission planning and cost allocation requirements to
ensure that the rates, terms, and conditions for transmission service
provided by public utility transmission providers (transmission
providers) \2\ remain just and reasonable and not unduly discriminatory
or preferential. This final order builds upon Order No. 888, Order No.
890,\3\ and Order No. 1000,\4\ in which the Commission incrementally
developed the requirements that govern regional transmission planning
and cost allocation processes to ensure that Commission-jurisdictional
rates remain just and reasonable and not unduly discriminatory or
preferential. Specifically, in this final order, we find that there is
substantial evidence to support the conclusion that the existing
regional transmission planning and cost allocation processes are
unjust, unreasonable, and unduly discriminatory or preferential because
the Commission's existing transmission planning and cost allocation
requirements do not require transmission providers to: (1) perform a
sufficiently long-term assessment of transmission needs that identifies
Long-Term Transmission Needs; \5\ (2) adequately account on a forward-
looking basis for known determinants of Long-Term Transmission Needs;
and (3) consider the broader set of benefits of regional transmission
facilities planned to meet those Long-Term Transmission Needs.
Accordingly, we believe that it is necessary to revisit existing
transmission planning and cost allocation requirements. We conclude
that adopting the reforms of this final order, as previously
contemplated in the notice of proposed rulemaking (NOPR),\6\ will
remedy the identified deficiencies in existing regional and local
transmission planning and cost allocation requirements, as discussed
below, and will ensure the identification, evaluation, and selection,
as well as the allocation of the costs, of more efficient or cost-
effective regional transmission solutions to address Long-Term
Transmission Needs.
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\1\ 16 U.S.C. 824e.
\2\ Section 201(e) of the FPA, 16 U.S.C. 824(e), defines
``public utility'' to mean ``any person who owns or operates
facilities subject to the jurisdiction of the Commission under this
subchapter.'' As stated in the Order No. 888 pro forma Open Access
Transmission Tariff (OATT), ``transmission provider'' is a ``public
utility (or its Designated Agent) that owns, controls, or operates
facilities used for the transmission of electric energy in
interstate commerce and provides transmission service under the
Tariff.'' Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Servs. by Pub. Utils.; Recovery of
Stranded Costs by Pub. Utils. & Transmitting Utils., Order No. 888,
61 FR 21540 (May 10, 1996), FERC Stats. & Regs. ] 31,036 (1996)
(cross-referenced at 75 FERC ] 61,080), order on reh'g, Order No.
888-A, 62 FR 12274 (Mar. 14, 1997), FERC Stats. & Regs. ] 31,048
(cross-referenced at 78 FERC ] 61,220), order on reh'g, Order No.
888-B, 81 FERC ] 61,248 (1997), order on reh'g, Order No. 888-C, 82
FERC ] 61,046 (1998), aff'd in relevant part sub nom. Transmission
Access Pol'y Study Grp. v. FERC, 225 F.3d 667 (D.C. Cir. 2000),
aff'd sub nom. N.Y. v. FERC, 535 U.S. 1 (2002); Pro forma OATT
section I.1 (Definitions). The term ``transmission provider''
includes a public utility transmission owner when the transmission
owner is separate from the transmission provider, as is the case in
regional transmission organizations (RTO) and independent system
operators (ISO).
\3\ Preventing Undue Discrimination & Preference in Transmission
Serv., Order No. 890, 72 FR 12266 (Mar. 15, 2007), FERC Stats. &
Regs. ] 31,241, 118 FERC ] 61,119 (2007), order on reh'g, Order No.
890-A, 73 FR 2984 (Jan. 16, 2008), FERC Stats. & Regs. ] 31,261
(2007) (cross-referenced at 118 FERC ] 61,119), order on reh'g and
clarification, Order No. 890-B, 73 FR 39092 (July 8, 2008), 123 FERC
] 61,299 (2008), order on reh'g, Order No. 890-C, 74 FR 12540 (Mar.
25, 2009), 126 FERC ] 61,228 (2009), order on clarification, Order
No. 890-D, 74 FR 61511 (Nov. 25, 2009), 129 FERC ] 61,126 (2009).
\4\ Transmission Plan. & Cost Allocation by Transmission Owning
& Operating Pub. Utils., Order No. 1000, 76 FR 49842 (Aug. 11,
2011), 136 FERC ] 61,051 (2011), Order No. 1000-A, 77 FR 32184 (May
31, 2012), 139 FERC ] 61,132 (2012), order on reh'g & clarification,
Order No. 1000-B, 141 FERC ] 61,044 (2012), aff'd sub nom. S.C. Pub.
Serv. Auth. v. FERC, 762 F.3d 41 (D.C. Cir. 2014).
\5\ All capitalized terms are defined below. Infra Use of Terms
section.
\6\ Bldg. for the Future Through Elec. Reg'l Transmission
Planning & Cost Allocation & Generator Interconnection, 87 FR 26504
(May 4, 2022), 179 FERC ] 61,028 (2022) (NOPR); see also Bldg. for
the Future Through Elec. Reg'l Transmission Planning & Cost
Allocation & Generator Interconnection, 86 FR 40266 (July 27, 2021),
176 FERC ] 61,024 (2021) (advanced notice of proposed rulemaking
(ANOPR)).
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2. Specifically, the reforms adopted in this final order require
transmission providers in each transmission planning region to
participate in a regional transmission planning process that includes
Long-Term Regional Transmission Planning.\7\ This final order adopts
specific requirements regarding how transmission providers must conduct
Long-Term Regional Transmission Planning, including, among other
things, the use of scenarios to identify Long-Term Transmission Needs
and Long-Term Regional Transmission Facilities to meet those needs.
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\7\ For purposes of this final order, and consistent with Order
No. 1000, a transmission planning region is one in which
transmission providers, in consultation with stakeholders and
affected states, have agreed to participate for purposes of regional
transmission planning and development of a single regional
transmission plan. See Order No. 1000, 136 FERC ] 61,051 at P 160.
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3. This final order also requires transmission providers to measure
and use at least the seven specified benefits to evaluate Long-Term
Regional Transmission Facilities as part of Long-Term Regional
Transmission Planning. In addition, this final order requires
transmission providers to calculate the benefits of Long-Term Regional
Transmission Facilities over a time horizon that covers, at a minimum,
20 years starting from the estimated in-service date of the
transmission facilities and requires that this minimum 20-year benefit
horizon be used both for the evaluation and selection of Long-Term
Regional Transmission Facilities in the regional transmission plan for
purposes of cost allocation.\8\
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\8\ We recognize that some transmission planning regions may
include Long-Term Regional Transmission Facilities, or a portfolio
of such Facilities, in a regional transmission plan, but may not
necessarily include these Facilities for purposes of cost
allocation. See Order No. 1000, 136 FERC ] 61,051 at P 63. For
purposes of this final order, unless otherwise noted, when
referencing Long-Term Regional Transmission Facilities (or a
portfolio of such Facilities) that are selected, we intend
``selected'' to mean that those Facilities are selected in the
regional transmission plan for purposes of cost allocation.
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4. This final order requires transmission providers to include in
their OATTs an evaluation process, including selection criteria, that
they will use to identify and evaluate Long-Term Regional Transmission
Facilities for potential selection to address Long-Term Transmission
Needs.
5. Further, this final order requires transmission providers to
file one or more ex ante Long-Term Regional Transmission Cost
Allocation Methods to allocate the costs of Long-Term Regional
Transmission Facilities (or a portfolio of such Facilities) that are
selected. This final order further permits, but does not require,
[[Page 49285]]
transmission providers to adopt a State Agreement Process, wherein
Relevant State Entities agree to such a State Agreement Process that
would provide up to six months after selection for its participants to
determine, and transmission providers to file, a cost allocation method
for specific Long-Term Regional Transmission Facilities. This final
order establishes a six-month time period (Engagement Period), during
which transmission providers must: (1) provide notice of the starting
and end dates for the six-month time period; (2) post contact
information that Relevant State Entities may use to communicate with
transmission providers about any agreement among Relevant State
Entities on a Long-Term Regional Transmission Cost Allocation Method(s)
and/or a State Agreement Process, as well as a deadline for
communicating such agreement; and (3) provide a forum for negotiation
of a Long-Term Regional Transmission Cost Allocation Method(s) and/or a
State Agreement Process that enables robust participation by Relevant
State Entities.
6. This final order also requires transmission providers to include
in their OATTs a process to provide Relevant State Entities and
interconnection customers the opportunity to voluntarily fund the cost
of, or a portion of the cost of, a Long-Term Regional Transmission
Facility that otherwise would not meet the transmission providers'
selection criteria. This final order requires transmission providers to
include in their OATTs provisions that require transmission providers--
in certain circumstances--to reevaluate Long-Term Regional Transmission
Facilities that previously were selected.
7. In addition, this final order requires that transmission
providers evaluate for potential selection in their existing Order No.
1000 regional transmission planning processes regional transmission
facilities that will address certain identified interconnection-related
transmission needs associated with certain interconnection-related
network upgrades \9\ originally identified through the generator
interconnection process.
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\9\ The Commission's pro forma Large Generator Interconnection
Procedures (LGIP) and pro forma Large Generator Interconnection
Agreement (LGIA) provide that, ``Network Upgrades shall mean the
additions, modifications, and upgrades to the Transmission
Provider's Transmission System required at or beyond the point at
which the Interconnection Facilities connect to the Transmission
Provider's Transmission System to accommodate the interconnection of
the Large Generating Facility to the Transmission Provider's
Transmission System.'' See Improvements to Generator Interconnection
Procedures & Agreements, Order No. 2023, 88 FR 61014 (Sept. 6,
2023), 184 FERC ] 61,054, at P 13 n.23, order on reh'g, 185 FERC ]
61,063 (2023), order on reh'g, Order No. 2023-A, 89 FR 27006 (Apr.
16, 2024), 186 FERC ] 61,199 (2024). In this final order, we refer
to network upgrades developed through the generator interconnection
process as interconnection-related network upgrades.
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8. This final order requires transmission providers in each
transmission planning region to consider more fully the alternative
transmission technologies of dynamic line ratings, advanced power flow
control devices, advanced conductors, and transmission switching in
Long-Term Regional Transmission Planning and existing Order No. 1000
regional transmission planning and cost allocation processes.
9. This final order does not finalize the NOPR proposal to not
permit transmission providers to take advantage of the recovery of 100%
of construction work in progress for Long-Term Regional Transmission
Facilities, and the Commission will instead continue to consider
transmission incentives issues in other proceedings. This final order
similarly does not finalize the NOPR proposal with respect to
permitting the exercise of Federal rights of first refusal for selected
transmission facilities, conditioned on the incumbent transmission
provider with the Federal right of first refusal establishing joint
ownership of the transmission facilities, and the Commission will
instead continue considering the NOPR proposal and potential Federal
right of first refusal issues in other proceedings.
10. This final order adopts the NOPR proposal to require
transmission providers to adopt enhanced transparency requirements for
local transmission planning processes and improve coordination between
regional and local transmission planning with the aim of identifying
potential opportunities to ``right-size'' replacement transmission
facilities.
11. This final order requires transmission providers to revise
their interregional transmission coordination processes to reflect the
Long-Term Regional Transmission Planning reforms adopted in this final
order. This final order also requires that transmission providers meet
additional information sharing and transparency requirements with
respect to their interregional transmission coordination processes.
12. This final order requires that each transmission provider
submit a compliance filing within ten months of the effective date of
this final order revising its OATT and other document(s) subject to the
Commission's jurisdiction to demonstrate that it meets the requirements
of this final order, with the exception of those requirements adopted
in the Interregional Transmission Coordination section in this final
order. This final order requires that each transmission provider submit
a compliance filing within 12 months of the effective date of this
final order revising its OATT and other document(s) subject to the
Commission's jurisdiction as necessary to demonstrate that it meets the
interregional transmission coordination requirements adopted in this
final order.
13. We recognize that transmission providers have ongoing efforts
to address transmission planning and cost allocation. This final order
is not intended to interfere with the potential progress represented by
those efforts, and we encourage transmission providers to continue to
innovate to improve their transmission planning and cost allocation
processes.
A. Historical Framework: Order Nos. 888, 890, and 1000
14. Over the last several decades, the Commission has taken
multiple significant actions on transmission planning and cost
allocation, including issuing Order Nos. 888, 890, and 1000. In 1996,
the Commission issued Order No. 888, which implemented open access to
transmission facilities owned, operated, or controlled by a public
utility and included certain minimum requirements for transmission
planning. In 2007, the Commission issued Order No. 890 to address
identified deficiencies in the pro forma OATT after more than 10 years
of experience since Order No. 888. Among other OATT reforms, the
Commission required all public utility transmission providers' local
transmission planning processes to satisfy nine transmission planning
principles: (1) coordination; (2) openness; (3) transparency; (4)
information exchange; (5) comparability; (6) dispute resolution; (7)
regional participation; (8) economic planning studies; and (9) cost
allocation for new projects.\10\
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\10\ Order No. 890, 118 FERC ] 61,119 at PP 418-601.
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15. In 2011, the Commission recognized the need for further
transmission planning reforms with its issuance of Order No. 1000. The
Commission based the reforms it adopted in Order No. 1000 on changes in
the energy industry, its experience implementing Order No. 890, and a
robust record developed through technical conferences and comments
[[Page 49286]]
from a diverse range of stakeholders.\11\ The Commission stated in
Order No. 1000 that ``the electric industry is currently facing the
possibility of substantial investment in future transmission facilities
to meet the challenge of maintaining reliable service at a reasonable
cost.'' \12\ In establishing the requirements of Order No. 1000, the
Commission found that the existing requirements of Order No. 890 were
not adequate, noting that Order No. 1000 ``expands upon the reforms
begun in Order No. 890 by addressing new concerns that have become
apparent in the Commission's ongoing monitoring of these matters.''
\13\ The Commission then enumerated multiple concerns that it had
regarding existing transmission planning practices, including concerns
about: (1) the lack of an affirmative obligation to develop a
transmission plan evaluating if a regional transmission facility ``may
be more efficient or cost-effective than solutions identified in local
transmission planning processes''; (2) the lack of a requirement to
address Public Policy Requirements; \14\ (3) the Federal right of first
refusal for incumbent transmission developers to build upgrades to
their existing transmission facilities; (4) the lack of procedures to
identify and evaluate the benefits of interregional transmission
facilities; and (5) cost allocation for regional and interregional
transmission facilities.\15\
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\11\ For purposes of this final order, and consistent with Order
No. 1000, a stakeholder includes any party interested in the
transmission planning processes. See Order No. 1000, 136 FERC ]
61,051 at P 151 n.143.
\12\ Id. P 2.
\13\ Id. P 21.
\14\ Public Policy Requirements are requirements established by
local, state, or Federal laws or regulations (i.e., enacted statutes
passed by the legislature and signed by the executive and
regulations promulgated by a relevant jurisdiction, whether within a
state or at the Federal level). Id. P 2. Order No. 1000-A clarified
that Public Policy Requirements include local laws or regulations
passed by a local governmental entity, such as a municipal or county
government. Order No. 1000-A, 139 FERC ] 61,132 at P 319.
\15\ Order No. 1000, 136 FERC ] 61,051 at P 3.
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16. Order No. 1000 included reforms intended to ensure that the
transmission planning and cost allocation requirements embodied in the
pro forma OATT could support the development of more efficient or cost-
effective transmission facilities.\16\ The reforms in Order No. 1000
included: (1) regional transmission planning; (2) transmission needs
driven by Public Policy Requirements; (3) nonincumbent transmission
developer reforms; (4) regional and interregional cost allocation,
including a set of principles for each category of cost allocation; and
(5) interregional transmission coordination. The reforms focused on the
process by which transmission providers engage in regional transmission
planning and the associated cost allocation rather than on the outcomes
of the process.\17\
---------------------------------------------------------------------------
\16\ Id. PP 11-12, 42-44; Order No. 1000-A, 139 FERC ] 61,132 at
PP 3, 4-6.
\17\ Order No. 1000, 136 FERC ] 61,051 at P 12.
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17. Among other regional transmission planning reforms in Order No.
1000, the Commission required that the following Order No. 890
transmission planning principles apply to regional transmission
planning processes: (1) coordination; (2) openness; (3) transparency;
(4) information exchange; (5) comparability; (6) dispute resolution;
and (7) economic planning studies.\18\
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\18\ The Commission did not include the regional participation
or cost allocation transmission planning principles with respect to
regional transmission planning processes because those issues were
addressed by other reforms in Order No. 1000. Id. P 151.
---------------------------------------------------------------------------
18. In addition, with respect to the Order No. 1000 reforms, the
Commission made a distinction between a transmission facility
``included'' in a regional transmission plan and a transmission
facility ``selected.'' A transmission facility selected in a regional
transmission plan for purposes of cost allocation is a transmission
facility that has been selected pursuant to a transmission planning
region's Commission-approved regional transmission planning process for
inclusion in a regional transmission plan for purposes of cost
allocation because it is a more efficient or cost-effective
transmission facility needed to meet regional transmission needs. Both
regional transmission facilities and interregional transmission
facilities are eligible for potential ``selection'' in a regional
transmission plan for purposes of cost allocation.\19\
---------------------------------------------------------------------------
\19\ Id. P 63. A regional transmission facility and an
interregional transmission facility are defined below. Infra Use of
Terms section.
---------------------------------------------------------------------------
19. Selected transmission facilities often will not comprise all of
the transmission facilities that are included in a regional
transmission plan.\20\ Some transmission facilities are merely ``rolled
up'' and listed in a regional transmission plan without going through
an analysis at the regional level, and/or are merely considered for
reliability implications upon a transmission system, and therefore, are
not eligible for selection and regional cost allocation.\21\ For
example, a local transmission facility is a transmission facility
located solely within a transmission provider's retail distribution
service territory or footprint that is not selected.\22\ Thus, a local
transmission facility may be rolled up and ``included'' in a regional
transmission plan for informational purposes, but it is not
``selected.''
---------------------------------------------------------------------------
\20\ Order No. 1000, 136 FERC ] 61,051 at P 63.
\21\ Id. PP 7, 226, 318.
\22\ Id. P 63. The Commission clarified in Order No. 1000-A that
a local transmission facility is one that is located within the
geographical boundaries of a public utility transmission provider's
retail distribution service territory, if it has one; otherwise, the
area is defined by the public utility transmission provider's
footprint. In the case of an RTO/ISO whose footprint covers the
entire region, a local transmission facility is defined by reference
to the retail distribution service territories or footprints of its
underlying transmission owing members. Order No. 1000-A, 139 FERC ]
61,132 at P 429.
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B. ANOPR and Technical Conference
20. In July 2021, the Commission issued the ANOPR \23\ presenting
potential reforms to improve the regional transmission planning and
cost allocation and generator interconnection processes. In issuing the
ANOPR, the Commission noted that, in part because more than a decade
had passed since Order No. 1000, it was now an appropriate time to
review its regulations governing regional transmission planning and
cost allocation to determine whether reforms are needed to ensure
Commission-jurisdictional rates remain just and reasonable and not
unduly discriminatory or preferential.\24\ The Commission noted that
the electricity sector is transforming as the generation fleet shifts
from resources located close to population centers toward resources
that may often be located far from load centers. The Commission also
highlighted the growth of new resources seeking to interconnect to the
transmission system and that the differing characteristics of those
resources are creating new demands on the transmission system. The
Commission explained that ensuring just and reasonable Commission-
jurisdictional rates during these changes, while maintaining grid
reliability, remains the Commission's priority in adopting requirements
for the regional transmission planning and cost allocation and
generator interconnection processes. As a result, the Commission issued
the ANOPR to consider whether there should be changes in the regional
transmission planning and cost allocation and generator interconnection
processes and, if so, which changes are necessary to ensure that
Commission-jurisdictional rates remain just and reasonable and not
unduly
[[Page 49287]]
discriminatory or preferential and that reliability is maintained.
---------------------------------------------------------------------------
\23\ ANOPR, 176 FERC ] 61,024.
\24\ Id. P 3.
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21. On November 15, 2021, the Commission convened a staff-led
technical conference (November 2021 Technical Conference or Technical
Conference) to examine in detail issues and potential reforms related
to regional transmission planning as described in the ANOPR.
Specifically, the Technical Conference included three panels covering
issues to consider in long-term scenarios, consideration of long-term
scenarios in regional transmission planning processes, and identifying
geographic zones with high renewable resource potential for use in
regional transmission planning processes.\25\ Following the Technical
Conference, the Commission invited all interested persons to file
comments to address issues raised during the Technical Conference.
---------------------------------------------------------------------------
\25\ Bldg. for the Future Through Elec. Reg'l Transmission
Planning & Cost Allocation & Generator Interconnection, Further
Supplemental Notice of Technical Conference, Docket No. RM21-17-000
(issued Nov. 12, 2021) (attaching agenda).
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C. Joint Federal-State Task Force on Electric Transmission
22. On June 17, 2021, the Commission established a Joint Federal-
State Task Force on Electric Transmission (Task Force) to formally
explore broad categories of transmission-related topics.\26\ The
Commission explained that the development of new transmission
infrastructure implicates a host of different issues, including how to
plan and pay for these facilities. Given that Federal and state
regulators each have authority over transmission-related issues and
given the impact of transmission infrastructure development on numerous
different priorities of Federal and state regulators, the Commission
determined that the topic was ripe for greater Federal-state
coordination and cooperation.\27\ The Task Force was composed of all
sitting FERC Commissioners as well as representatives from 10 state
commissions nominated by the National Association of Regulatory Utility
Commissioners (NARUC), with two originating from each NARUC region.\28\
---------------------------------------------------------------------------
\26\ Joint Fed.-State Task Force on Elec. Transmission, 175 FERC
] 61,224, at PP 1, 6 (2021).
\27\ Id. P 2.
\28\ An up-to-date list of Task Force members, as well as
additional information on the Task Force, is available on the
Commission's website at: https://www.ferc.gov/TFSOET. Public
materials related to the Task Force, including transcripts from
public meetings, are available in the Commission's eLibrary in
Docket No. AD21-15-000.
---------------------------------------------------------------------------
23. The Task Force has convened multiple formal meetings with eight
meetings held thus far to discuss regional transmission planning and
cost allocation issues, convening on November 10, 2021, February 16,
2022, May 6, 2022, July 20, 2022, November 15, 2022, February 15, 2023,
July 16, 2023, and February 28, 2024.
24. The discussion at the November 2021 meeting was focused on
incorporating state perspectives into regional transmission
planning.\29\ The February 2022 meeting included discussion of specific
categories and types of transmission benefits that transmission
providers should consider for the purposes of transmission planning and
cost allocation.\30\ The May 2022 meeting focused on barriers to the
efficient, expeditious, and reliable interconnection of new
resources.\31\ The July 2022 meeting focused on interregional
transmission planning and transmission project development and the
NOPR.\32\ The November 2022 meeting focused on regulatory gaps and
challenges in oversight of transmission development.\33\ The February
2023 meeting focused on the physical security of the Nation's
transmission system, and featured guest speakers from the North
American Electric Reliability Corporation and US DOE.\34\ The July 2023
meeting focused on grid enhancing technologies, featuring a guest
speaker from the Electric Power Research Institute.\35\ The February
2024 meeting focused on transmission siting, featuring guest speakers
from US DOE.\36\
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\29\ Joint Fed.-State Task Force on Elec. Transmission, Notice
of Meeting, Docket No. AD21-15-000 (issued Oct. 27, 2021) (attaching
agenda).
\30\ Joint Fed.-State Task Force on Elec. Transmission, Notice
of Meeting, Docket No. AD21-15-000 (issued Feb. 2, 2022) (attaching
agenda).
\31\ Joint Fed.-State Task Force on Elec. Transmission, Notice
of Meeting, Docket No. AD21-15-000 (issued Apr. 22, 2022) (attaching
agenda).
\32\ Joint Fed.-State Task Force on Elec. Transmission, Notice
of Meeting, Docket No. AD21-15-000 (issued June 30, 2022) (attaching
agenda).
\33\ Joint Fed.-State Task Force on Elec. Transmission, Notice
of Meeting, Docket No. AD21-15-000 (issued Nov. 1, 2022) (attaching
agenda).
\34\ Joint Fed.-State Task Force on Elec. Transmission, Notice
of Meeting, Docket No. AD21-15-000 (issued Feb. 1, 2023) (attaching
agenda).
\35\ Joint Fed.-State Task Force on Elec. Transmission, Notice
of Meeting, Docket No. AD21-15-000 (issued June 30, 2023) (attaching
agenda).
\36\ Joint Fed.-State Task Force on Elec. Transmission, Notice
of Meeting, Docket No. AD21-15-000 (issued Feb. 13, 2024) (attaching
agenda).
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25. In light of the Task Force expiring three years from its first
public meeting, i.e., on November 10, 2024,\37\ on March 21, 2024, the
Commission established the Federal and State Current Issues
Collaborative (Collaborative).\38\ The Collaborative will be comprised
of all Commissioners, as well as representative from 10 state
commissions. The Collaborative will provide a venue for Federal and
state regulators to share perspectives, increase understanding, and
where appropriate, identify potential solutions regarding challenges
and coordination on matters that impact specific state and Federal
regulatory jurisdiction.\39\
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\37\ Joint Fed.-State Task Force on Elec. Transmission, 175 FERC
] 61,224 at P 4.
\38\ Joint Fed.-State Task Force on Elec. Transmission, 186 FERC
] 61,189 (2024).
\39\ Id. PP 5-6.
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D. Notice of Proposed Rulemaking
26. On April 21, 2022, the Commission issued the NOPR, proposing
reforms focused on long-term regional transmission planning and cost
allocation processes. In particular, the Commission proposed in the
NOPR that transmission providers in each transmission planning region
participate in a regional transmission planning process that includes
Long-Term Regional Transmission Planning.\40\ The Commission also
proposed to require that transmission providers develop Long-Term
Scenarios as part of Long-Term Regional Transmission Planning.\41\
---------------------------------------------------------------------------
\40\ NOPR, 179 FERC ] 61,028 at PP 64, 68.
\41\ Id. P 84.
---------------------------------------------------------------------------
27. The Commission proposed that transmission providers consider,
as part of their Long-Term Regional Transmission Planning, regional
transmission facilities that address certain interconnection-related
transmission needs that the transmission provider has identified
multiple times in the generator interconnection process but that have
never been constructed due to the withdrawal of the relevant
interconnection request(s).\42\
---------------------------------------------------------------------------
\42\ Id. P 166.
---------------------------------------------------------------------------
28. The Commission proposed 12 benefits that transmission providers
may consider in Long-Term Regional Transmission Planning and cost
allocation processes.\43\ The Commission stated that the list of
potential benefits was neither mandatory nor exhaustive, and that
pursuant to the proposal, transmission providers would have flexibility
to propose which benefits to use as part of their Long-Term Regional
Transmission Planning.\44\
---------------------------------------------------------------------------
\43\ Id. P 185.
\44\ Id. P 184.
---------------------------------------------------------------------------
29. The Commission proposed, with regard to the selection of Long-
Term Regional Transmission Facilities in the regional transmission plan
for purposes of cost allocation, to require that transmission
providers, as part of their Long-Term Regional Transmission Planning,
include in their OATTs: (1) transparent and not unduly
[[Page 49288]]
discriminatory criteria, which seek to maximize benefits to consumers
over time without over-building transmission facilities, to identify
and evaluate transmission facilities for potential selection that
address transmission needs driven by changes in the resource mix and
demand; and (2) a process to coordinate with the Relevant State
Entities in developing such criteria.\45\
---------------------------------------------------------------------------
\45\ Id. P 241.
---------------------------------------------------------------------------
30. The Commission proposed to require transmission providers to
more fully consider the incorporation into transmission facilities of
dynamic line ratings and advanced power flow control devices in
regional transmission planning and cost allocation processes.\46\
---------------------------------------------------------------------------
\46\ Id. P 272.
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31. The Commission proposed to require, with regard to allocating
the costs of Long-Term Regional Transmission Facilities, transmission
providers to revise their OATTs to include: (1) a Long-Term Regional
Transmission Cost Allocation Method to allocate the costs of Long-Term
Regional Transmission Facilities; (2) a State Agreement Process by
which one or more Relevant State Entities may voluntarily agree to a
cost allocation method; or (3) a combination thereof.\47\ The
Commission proposed to require transmission providers to seek the
agreement of Relevant State Entities within the transmission planning
region regarding the Long-Term Regional Transmission Cost Allocation
Method, State Agreement Process, or combination thereof.\48\ The
Commission proposed to require transmission providers to identify on
compliance the benefits they will use in ex ante Long-Term Regional
Transmission Cost Allocation Methods associated with Long-Term Regional
Transmission Planning, how they will calculate those benefits, and how
the benefits will reasonably reflect the benefits of regional
transmission facilities to meet identified transmission needs driven by
changes in the resource mix and demand.\49\
---------------------------------------------------------------------------
\47\ Id. P 302.
\48\ Id. P 303.
\49\ Id. P 326.
---------------------------------------------------------------------------
32. The Commission further proposed to not permit transmission
providers to take advantage of the allowance for inclusion of 100% of
construction work in progress costs in rate base in certain
circumstances for Long-Term Regional Transmission Facilities.\50\
---------------------------------------------------------------------------
\50\ Id. P 333.
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33. Finally, the Commission proposed to permit the exercise of
Federal rights of first refusal for selected transmission facilities,
conditioned on the incumbent transmission provider with the Federal
right of first refusal for such regional transmission facilities
establishing joint ownership of the transmission facilities consistent
with certain proposed requirements described in the NOPR.\51\
---------------------------------------------------------------------------
\51\ Id. P 351.
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34. The Commission also proposed to require transmission providers
to revise the regional transmission planning process in their OATTs
with additional provisions to enhance transparency of: (1) the
criteria, models, and assumptions that they use in their local
transmission planning process; (2) the local transmission needs that
they identify through that process; and (3) the potential local or
regional transmission facilities that they will evaluate to address
those local transmission needs.\52\ The Commission proposed to require
transmission providers to evaluate whether transmission facilities
operating at or above 230 kV that an individual transmission provider
that owns the transmission facility anticipates replacing in-kind with
a new transmission facility during the next 10 years can be ``right-
sized'' to more efficiently or cost-effectively address regional
transmission needs identified in Long-Term Regional Transmission
Planning.\53\
---------------------------------------------------------------------------
\52\ Id. P 400.
\53\ Id. P 403.
---------------------------------------------------------------------------
35. The Commission further proposed to require transmission
providers in neighboring transmission planning regions to revise their
existing interregional transmission coordination procedures (and
regional transmission planning processes as needed) to provide for: (1)
the sharing of information regarding their respective transmission
needs identified in Long-Term Regional Transmission Planning, as well
as potential transmission facilities to meet those needs; and (2) the
identification and joint evaluation of interregional transmission
facilities that may be more efficient or cost-effective transmission
facilities to address transmission needs identified through Long-Term
Regional Transmission Planning.\54\ Finally, the Commission proposed to
require transmission providers in neighboring transmission planning
regions to revise their interregional transmission coordination
procedures (and regional transmission planning processes as needed) to
allow an entity to propose an interregional transmission facility in
the regional transmission planning process as a potential solution to
transmission needs identified through Long-Term Regional Transmission
Planning.\55\
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\54\ Id. P 427.
\55\ Id. P 428.
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E. High-Level Overview of NOPR Comments
36. The Commission received a great many comments from a diverse
set of parties in response to the NOPR.\56\ One hundred and ninety-six
parties, including Federal agencies, state regulatory commissions,
state policy makers and other state representatives, ratepayer
advocates, municipalities, RTOs/ISOs, RTO/ISO market monitors,
transmission providers, transmission-dependent utilities, electric
cooperatives, municipal power providers, independent power producers,
transmission developers, generation trade associations, transmission
trade associations, industry interest groups, consumer interest groups,
energy policy and law interest groups, individual businesses,
landowners, and individuals, filed initial comments that totaled over
15,000 pages with attachments. A similarly diverse set of 92 parties
filed reply comments that totaled nearly 1,900 pages.
---------------------------------------------------------------------------
\56\ See appendix A for a list of commenters and the abbreviated
names of commenters that are used in this final order.
---------------------------------------------------------------------------
F. Use of Terms
37. Before turning to the detailed requirements of this final
order, we note several of the key terms used herein. We further address
the definitions of these terms, including any modifications to
definitions proposed in the NOPR, in the relevant later sections of
this final order.
38. For purposes of this final order, Long-Term Regional
Transmission Planning means regional transmission planning on a
sufficiently long-term, forward-looking, and comprehensive basis to
identify Long-Term Transmission Needs, identify transmission facilities
that meet such needs, measure the benefits of those transmission
facilities, and evaluate those transmission facilities for potential
selection in the regional transmission plan for purposes of cost
allocation as the more efficient or cost-effective regional
transmission facilities to meet Long-Term Transmission Needs.
39. For purposes of this final order, Long-Term Transmission Needs
are transmission needs identified through Long-Term Regional
Transmission Planning by, among other things and as discussed in this
final order, running
[[Page 49289]]
scenarios and considering the enumerated categories of factors.\57\
---------------------------------------------------------------------------
\57\ Further discussion on Long-Term Transmission Needs can be
found below. Infra Development of Long-Term Scenarios subsection
under the Long-Term Regional Transmission Planning section.
---------------------------------------------------------------------------
40. For purposes of this final order, Long-Term Scenarios are
scenarios that incorporate various assumptions using best available
data inputs about the future electric power system over a sufficiently
long-term, forward-looking transmission planning horizon to identify
Long-Term Transmission Needs and enable the identification and
evaluation of transmission facilities to meet such transmission needs.
41. For purposes of this final order, a Long-Term Regional
Transmission Facility is a regional transmission facility \58\ that is
identified as part of Long-Term Regional Transmission Planning to
address Long-Term Transmission Needs.
---------------------------------------------------------------------------
\58\ For purposes of this final order, and consistent with Order
No. 1000, a regional transmission facility is a transmission
facility located entirely in one transmission planning region. An
interregional transmission facility is a transmission facility that
is located in two or more transmission planning regions. A local
transmission facility is a transmission facility located solely
within a transmission provider's retail distribution service
territory or footprint that is not selected in the regional
transmission plan for purposes of cost allocation. Order No. 1000,
136 FERC ] 61,051 at PP 63, 482 n.374.
---------------------------------------------------------------------------
42. For purposes of this final order, best available data inputs
are data inputs that are timely, developed using best practices and
diverse and expert perspectives, and adopted via a process that
satisfies the transmission planning principles of Order Nos. 890 and
1000, and reflect the list of factors that transmission providers
account for in their Long-Term Scenarios.
43. For purposes of this final order, a Long-Term Regional
Transmission Cost Allocation Method is an ex ante regional cost
allocation method for one or more selected Long-Term Regional
Transmission Facilities (or a portfolio of such Facilities) that are
selected in the regional transmission plan for purposes of cost
allocation.
44. For purposes of this final order, a Relevant State Entity is
any state entity responsible for electric utility regulation or siting
electric transmission facilities within the state or portion of a state
located in the transmission planning region, including any state entity
as may be designated for that purpose by the law of such state.
45. For purposes of this final order, a State Agreement Process is
a process by which one or more Relevant State Entities may voluntarily
agree to a cost allocation method for Long-Term Regional Transmission
Facilities (or a portfolio of such Facilities) before or no later than
six months after they are selected.
46. For purposes of this final order, federally-recognized Tribes
are those Tribes listed in the most recent notice provided by the
Bureau of Indian Affairs and published in the Federal Register.\59\
---------------------------------------------------------------------------
\59\ See, e.g., Indian Entities Recognized by and Eligible to
Receive Servs. from the U.S. Bureau of Indian Affairs, Federal
Register, 89 FR 944 (Jan. 8, 2024).
---------------------------------------------------------------------------
II. The Overall Need for Reform
A. NOPR Proposal
47. The Commission issued the NOPR on April 21, 2022, proposing to
reform the pro forma OATT and the pro forma LGIA to remedy deficiencies
in the Commission's existing regional transmission planning and cost
allocation requirements. The Commission stated that, over the last 25
years, it has undertaken a series of significant reforms to ensure that
transmission planning and cost allocation processes result in
Commission-jurisdictional rates that are just and reasonable and not
unduly discriminatory or preferential.\60\ The Commission noted that it
has now been more than a decade since Order No. 1000--its last
significant regional transmission planning and cost allocation rule--
and that there is mounting evidence that its regional transmission
planning and cost allocation requirements may be inadequate to ensure
that Commission-jurisdictional rates remain just and reasonable and not
unduly discriminatory or preferential.\61\
---------------------------------------------------------------------------
\60\ NOPR, 179 FERC ] 61,028 at P 24.
\61\ Id.
---------------------------------------------------------------------------
48. The Commission found that, in particular, although transmission
providers are required to participate in regional transmission planning
and cost allocation processes under Order No. 1000, it was concerned
that those processes may not be planning transmission on a sufficiently
long-term, forward-looking basis to meet transmission needs driven by
changes in the resource mix and demand. The Commission stated that, as
a result, the regional transmission planning and cost allocation
processes that transmission providers adopted to comply with Order No.
1000 may not be identifying the more efficient or cost-effective
transmission facilities.\62\ The Commission stated that it was
concerned that the absence of sufficiently long-term, forward-looking,
comprehensive transmission planning processes appears to be resulting
in piecemeal transmission expansion to address relatively near-term
transmission needs, and that continuing with the status quo approach
may cause transmission providers to undertake relatively inefficient
investments in transmission infrastructure, the costs of which are
ultimately recovered through Commission-jurisdictional rates. The
Commission stated that this dynamic may result in transmission
customers paying more than necessary to meet their transmission needs,
customers forgoing benefits that outweigh their costs, or some
combination thereof--either or both of which could potentially render
Commission-jurisdictional rates unjust and unreasonable or unduly
discriminatory or preferential. Based on the evidence, the Commission
preliminarily concluded that revisions to its existing transmission
planning and cost allocation requirements established in Order Nos. 890
and 1000 are necessary to ensure that Commission-jurisdictional
services are provided at rates, terms, and conditions that are just and
reasonable and not unduly discriminatory and preferential.\63\
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\62\ Id. PP 24-25.
\63\ Id. PP 25, 27, 34-35.
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B. Comments
49. A significant majority of commenters, including transmission
providers, transmission developers, transmission customers, members of
Congress, states, state commissions, consumer advocates, trade
associations, and public interest organizations, among others, agree
that existing regional transmission planning and cost allocation
processes need to be reformed.\64\ Advanced Energy Buyers
[[Page 49290]]
note that the electric system is presently undergoing one of the most
significant transformations in a century.\65\ Other commenters agree
that electric energy supply and demand is evolving quickly.\66\ Clean
Energy Buyers agree with the Commission that there is a need for reform
to meet these drastic changes in the resource mix and load and to
ensure continued reliability and cost-effective transmission
service.\67\
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\64\ See, e.g., Acadia Center and CLF Initial Comments at 1-2;
ACEG Initial Comments at 11-12, 21-22; ACORE Initial Comments at 2-
5; ACORE Supplemental Comments at 1; Advanced Energy Buyers Initial
Comments at 2-3; AEE Initial Comments at 7-8; AEP Initial Comments
at 1-3; Amazon Initial Comments at 1-2; Ameren Initial Comments at
1-2; American Municipal Power Initial Comments at 4; Anbaric Initial
Comments at 1; Arizona Commission Initial Comments at 3-4; Avangrid
Initial Comments at 5-6; BP Initial Comments at 3; Breakthrough
Energy Initial Comments at 5-6; Breakthrough Energy Supplemental
Comments at 1; Business Council for Sustainable Energy Initial
Comments at 2-3; California Commission Initial Comments at 1-2;
California Energy Commission Initial Comments at 1; CAISO Initial
Comments at 1; City of New Orleans Council Initial Comments at 4, 7-
9; Cross Sector Representatives Supplemental Comments at 1; DC and
MD Offices of People's Counsel Initial Comments at 4-5; US Senators
Supplemental Comments at 1; EEI Initial Comments at 4-5; ELCON
Initial Comments at 4; Enel Initial Comments at 2, 7; ENGIE Initial
Comments at 1-2; Entergy Initial Comments at 2-3; Environmental
Legislators Caucus Supplemental Comments at 1; Evergreen Action
Initial Comments at 1-3; Eversource Initial Comments at 1-2, 5-9;
Exelon Initial Comments at 1-2; Grid United Initial Comments at 1-2;
Handy Law Initial Comments at 1-7; Harvard ELI Initial Comments at
1; Illinois Commission Initial Comments at 3; Indicted PJM TOs
Initial Comments at 1-2; Indicated US Senators and Representatives
Initial Comments at 1; Interwest Initial Comments at 2-3; Invenergy
Initial Comments at 2, 5; ISO-NE Initial Comments at 2, 8-9; ISO/RTO
Council Initial Comments at 2; Kansas Commission Initial Comments at
10-11; Massachusetts Attorney General Initial Comments at 3-6;
Michigan Commission Initial Comments at 2, 4; Michigan State
Entities Initial Comments at 3-4; Minnesota State Entities Initial
Comments at 2-3; National Grid Initial Comments at 1, 6; National
and State Conservation Organizations Initial Comments at 1; NESCOE
Initial Comments at 2, 7, 14-15; New Jersey Commission Initial
Comments at 1-2; New York Commission and NYSERDA Initial Comments at
1-3; NextEra Reply Comments at 1; Non-RTO NASUCA Initial Comments at
4-5; NYISO Initial Comments at 2-3; Onward Energy Initial Comments
at 1-2; [Oslash]rsted Initial Comments at 2-3; Pattern Energy
Initial Comments at 1; PacifiCorp and NV Energy Initial Comments at
2, 7-8; Pacific Northwest State Agencies Initial Comments at 1, 8;
PG&E Initial Comments at 1; PIOs Initial Comments at 6-7; Policy
Integrity Initial Comments at 1-2; Renewable Northwest Initial
Comments at 3-4; RMI Supplemental Comments at 1-2; SPP Market
Monitor Initial Comments at 3-4; SEIA Initial Comments at 2; Shell
Initial Comments at 1, 9; US Senator Barrasso Supplemental Comments
at 2; Senator Whitehouse Supplemental Comments at 2; Southeast PIOs
Initial Comments at 1; SREA Initial Comments at 1; State Officials
Supplemental Comments at 1; TAPS Initial Comments at 1-2; US DOE
Initial Comments at 1-4; US DOJ and FTC Initial Comments 1, 5;
Vermont State Entities Initial Comments at 2; Western State
Representatives Initial Comments at 3-4; WIRES Initial Comments at
2, 5.
\65\ Advanced Energy Buyers Initial Comments at 2.
\66\ See, e.g., AEE Initial Comments at 1; Cross Sector
Representatives Supplemental Comments at 1; Eversource Initial
Comments at 5-8 (citing ISO-NE, 2020 Regional Electricity Outlook,
at 35 (2020)); Indicated PJM TOs Initial Comments at 1-2; Kansas
Commission Initial Comments at 2; Pattern Energy Initial Comments at
1; PG&E Initial Comments at 1; Policy Integrity Initial Comments at
2; Renewable Northwest Initial Comments at 5; State Agencies Initial
Comments at 12-13; WIRES Initial Comments at 3.
\67\ Clean Energy Buyers Initial Comments at 7.
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50. Many commenters argue that current regional transmission
planning and cost allocation processes across the country are not
ensuring efficient and cost-effective transmission development, are not
satisfying the purposes of Order Nos. 890 and 1000, and are not meeting
transmission needs at a reasonable cost. For example, several
commenters assert that Order Nos. 890 and 1000 have not solved
longstanding problems with regional transmission planning and cost
allocation.\68\ Northwest and Intermountain claim that Order No. 1000
has been inadequate to meet transmission needs, particularly in the
non-RTO/ISO West.\69\ Michigan State Entities assert that the current
lack of long-term transmission planning has led to significantly higher
costs for residential ratepayers, costs that will increase without
reforms.\70\ SREA argues that reform is needed to correct the
unintended consequences of Order No. 1000 in the Southeast, where
transmission planning ``has grown into an enormously elaborate and
extremely expensive black box,'' without any meaningful review by state
regulatory bodies.\71\
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\68\ See, e.g., Acadia Center and CLF Initial Comments at 1;
ACEG Initial Comments at 17-18, 20 (citing Order No. 1000, 136 FERC
] 61,051 at P 3; NOPR, 179 FERC ] 61,028 at PP 24-25); AEE Initial
Comments at 1-2; CARE Coalition Initial Comments at 3; NERC Initial
Comments at 5; Massachusetts Attorney General Initial Comments at 5-
6; Northwest and Intermountain Initial Comments at 6-7; Pine Gate
Initial Comments at 8-10; PIOs Initial Comments at 2-3; Southeast
PIOs Initial Comments at 7-9, 11, 16-17, 43-44; SPP Market Monitor
Initial Comments at 3-4; SREA Reply Comments at 4; US DOE Initial
Comments at 3-4, 7-8.
\69\ Northwest and Intermountain Initial Comments at 6-7.
\70\ Michigan State Entities Initial Comments at 1-2.
\71\ SREA Reply Comments at 4.
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51. PIOs assert that transmission owners can evade Order No. 1000
requirements through investments in local transmission projects, which
has led to billions of dollars in excessive costs.\72\ PIOs explain
that financial incentives drive utilities to upgrade their own systems
at the expense of building a more integrated and robust transmission
system to meet the needs and demands of the future.\73\ PIOs observe
that, between 2013 and 2017, about one-half of the approximately $70
billion in aggregate transmission investments by Commission-
jurisdictional transmission owners in RTO/ISO regions were approved
outside of regional transmission planning processes or with limited
stakeholder engagement.\74\ Ohio Consumers add that since 2017, less
than 25% of new transmission investments in Ohio have been associated
with large regional transmission projects needed for reliability or
economic efficiency.\75\ Competition Coalition argues that incumbent
transmission owners have used reliability designations to justify
projects with higher costs.\76\
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\72\ PIOs Initial Comments at 8 (citing Johannes P.
Pfeifenberger et al., The Brattle Group, Cost Savings Offered by
Competition in Electric Transmission: Experience to Date and the
Potential for Additional Customer Value, at 19-20, and Section I
(Apr. 2019) (Brattle Apr. 2019 Competition Report), https://www.brattle.com/wp-content/uploads/2021/05/16726_cost_savings_offered_by_competition_in_electric_transmission.pdf).
\73\ Id. at 6-7.
\74\ Id. at 9 (citing Brattle Apr. 2019 Competition Report at
4).
\75\ Ohio Consumers Initial Comments at 5.
\76\ Competition Coalition Initial Comments at 15-16.
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52. Citing to a report from Lawrence Berkeley National Laboratory,
US DOE concludes that many existing regional transmission planning
approaches are likely understating the economic value of new
transmission. US DOE suggests that the need for increased transmission
capacity to address persistent and worsening transmission congestion
demonstrates that these processes may not fully anticipate present and
future transmission needs.\77\ In addition, US DOE notes the unfair
burden on interconnection customers that must bear increasing costs,
especially for interconnection-related network upgrades that provide
system-wide benefits.\78\ US DOJ and FTC agree that reforms are
necessary to encourage needed regional and interregional transmission
investment and that a larger, more integrated transmission system would
improve resilience, promote competition, and lower costs for
consumers.\79\
---------------------------------------------------------------------------
\77\ US DOE Initial Comments at 3-4.
\78\ Id. at 7-8.
\79\ US DOJ and FTC Initial Comments at 1, 5 (citing NOPR, 179
FERC ] 61,028 at P 6; P. R. Brown & A. Botterud, The Value of Inter-
Regional Coordination and Transmission in Decarbonizing the US
Electricity System, 5 Joule 115, 115-134 (2021); Eric Larson et al.,
Princeton Univ., Net-Zero America: Potential Pathways,
Infrastructure, and Impacts, at 108 (Oct. 2021), https://netzeroamerica.princeton.edu/the-report).
---------------------------------------------------------------------------
53. Many commenters contend that inadequate regional transmission
planning and cost allocation processes have resulted in, or are
threatening to cause, unjust, unreasonable, and unduly discriminatory
or preferential rates.\80\ Michigan State Entities cite renewable
energy curtailments, which limit the supply of energy that customers
can access, and the lack of regional and interregional transmission
lines, which limit the transfer of lower-priced power.\81\ New Jersey
Commission asserts that better transmission planning
[[Page 49291]]
can reduce overall system costs by billions of dollars.\82\ Certain
TDUs add that Commission action is essential now to ensure that
necessary transmission expansion occurs in a way that protects
customers from excessive costs and that results in just and reasonable
transmission rates.\83\ CARE Coalition argues that the Commission's
current failure to require transmission planners to internalize siting-
related costs and risks results in unjust, unreasonable, and unduly
discriminatory or preferential rates.\84\ In a similar vein,
[Oslash]rsted and Massachusetts Attorney General claim that failure to
proactively plan for offshore wind generation buildout could lead to
transmission rates that are unjust, unreasonable, and unduly
discriminatory or preferential.\85\
---------------------------------------------------------------------------
\80\ See, e.g., ACORE Initial Comments at 3, AEE Initial
Comments at 27 (citing NOPR, 179 FERC ] 61,028 at PP 47, 55, 78;
S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 56); CARE Coalition
Initial Comments at 17; Certain TDUs Initial Comments at 2; Clean
Energy Associations Initial Comments at 3, 7; Clean Energy Buyers
Initial Comments at 10; Harvard ELI Initial Comments at 1;
Massachusetts Attorney General Initial Comments at 5-6; New Jersey
Commission Initial Comments at 1-2; PIOs Initial Comments at 6; SEIA
Initial Comments at 2-3; Southeast PIOs Reply Comments at 2; US DOE
Initial Comments at 2, 6-7.
\81\ Michigan State Entities Initial Comments at 3.
\82\ New Jersey Commission Initial Comments at 3-9.
\83\ Certain TDUs Initial Comments at 2.
\84\ CARE Coalition Initial Comments at 17.
\85\ Massachusetts Attorney General Initial Comments at 5;
[Oslash]rsted Initial Comments at 3-5.
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54. Several commenters agree with the Commission's concerns that
the expansion of the high-voltage transmission system is increasingly
occurring outside of the regional transmission planning process through
other mechanisms such as the generator interconnection process, which
results in piecemeal transmission development.\86\ AEE agrees that
limited development of regional transmission facilities, increased
spending on local transmission projects, and backlogged interconnection
queues all show that the existing regional transmission planning
requirements are not sufficient to meet customers' transmission
needs.\87\ Likewise, Exelon argues that relying on interconnection
studies as the primary transmission planning method results in
piecemeal and inefficient transmission investment.\88\ PIOs add that
many generation developers have to bear the full costs of transmission
upgrades, which leads to interconnection request withdrawals,
inefficiencies, and higher system-wide costs.\89\ In addition, Clean
Energy States note that interconnection queues are extremely large and
that the current one-plant-at-a-time approach to transmission upgrades
drives up costs and misses opportunities for improvements to the system
as a whole.\90\
---------------------------------------------------------------------------
\86\ See, e.g., Acadia Center and CLF Initial Comments at 3-4;
Anbaric Initial Comments at 5; Clean Energy Associations Initial
Comments at 4-7; Exelon Initial Comments at 1-2, 5; Joint Consumer
Advocates Initial Comments at 5; Non-RTO NASUCA Initial Comments at
4; [Oslash]rsted Initial Comments at 4-5; Pine Gate Initial Comments
at 8-10; SEIA Initial Comments at 2; see also AEP Initial Comments
at 8.
\87\ AEE Initial Comments at 1-2 (citing NOPR, 179 FERC ] 61,028
at PP 47-55).
\88\ Exelon Initial Comments at 5.
\89\ PIOs Initial Comments at 9-10.
\90\ Clean Energy States Initial Comments at 2.
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55. Non-RTO NASUCA agrees with the Commission that Long-Term
Regional Transmission Planning is necessary to help alleviate
generation interconnection issues.\91\ According to Harvard ELI,
current transmission planning processes have failed to address
backlogged interconnection queues and operational challenges that are
best addressed at the regional level, as well as to include inexpensive
technologies that can increase transmission capacity.\92\
---------------------------------------------------------------------------
\91\ Non-RTO NASUCA Initial Comments at 4.
\92\ Harvard ELI Initial Comments at 1.
---------------------------------------------------------------------------
56. ACEG argues that there is no evidence that any regional
reliability or economic transmission planning performed in non-RTO/ISO
regions, like the Southeastern Regional Transmission Planning region
(SERTP), is equal to or superior to the techniques or outcomes in the
NOPR.\93\ ACEG further contends that, instead, most new transmission
facilities built since Order No. 1000 have been built for local
transmission needs, thereby resulting in less efficient and cost-
effective transmission development that does not address the larger
needs of the transmission system for reliability and resilience.\94\
Relatedly, SREA states that no state fully participates in SERTP, and
that instead, each state in the Southeast uses its own state planning
process, with no platform for states to collaborate. As a result, SREA
argues that ``transmission planning in the Southeast has many holes and
is threadbare.'' \95\ SREA catalogs deficiencies in many Southeastern
states' planning processes, including a lack of transparency.\96\
---------------------------------------------------------------------------
\93\ ACEG Reply Comments at 9 (citing Alabama Commission Initial
Comments at 2-3; Southern Initial Comments at 5-6, Ex. 2 at 2-3).
\94\ Id. at 9-10 (citing PIOs Initial Comments at 7).
\95\ SREA Reply Comments at 4.
\96\ Id. at 5-18.
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57. Western PIOs argue that, outside of CAISO, transmission
planning in the West is ineffective.\97\ Specifically, Western PIOs
assert that Western transmission planning groups have not developed new
transmission projects using their Order No. 1000 transmission planning
processes, but have instead built transmission projects that their
utility members have already proposed.\98\ Relatedly, SEIA argues that
``non-RTO areas do not engage in sufficient or transparent transmission
planning,'' and that transmission planning in non-RTO/ISO regions is
exclusionary, based on inconsistent and inaccurate data, and
disjointed.\99\ More broadly, NRECA contends that incumbent investor-
owned utilities control transmission planning, and that some incumbent
investor-owned utilities develop transmission without transparency,
leading to disparities in transmission rates in different RTO/ISO local
zones.\100\
---------------------------------------------------------------------------
\97\ Western PIOs Initial Comments at 4-28.
\98\ Id. at 28.
\99\ SEIA Reply Comments at 5-6 (citing Southern Initial
Comments at 13-14).
\100\ NRECA Initial Comments at 15-16.
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58. Several commenters specify other reasons that transmission
planning reforms are needed.\101\ Americans for Fair Energy Prices
agree with PIOs that there is a need for regional transmission planning
instead of the balkanized process that currently exists.\102\ DC and MD
Offices of People's Counsel assert that the NOPR provides a once-in-a-
generation opportunity to meet the energy transition in a just,
equitable, efficient, reliable, and resilient fashion by recognizing
the benefits of long-term transmission planning and developing rules
that incorporate those broad benefits. DC and MD Offices of People's
Counsel state that current transmission planning processes do not fully
consider all of the benefits of transmission development, including
enhanced reliability and resilience that will serve as a necessary
bulwark against disruptions caused by extreme weather.\103\ ACEG argues
that current transmission planning processes have not led to investment
in interregional transmission capacity, and that more interregional
transmission capacity could have avoided some of the $25 billion to $70
billion in yearly costs caused by severe weather events.\104\ EEI
states that robust transmission development will provide a host of
benefits for customers, including greater resilience, enhanced system
reliability, and cost-savings from greater access to low-cost
resources.\105\ Some commenters emphasize the importance of the
Commission taking prudent action to remedy deficiencies in the
Commission's existing regional transmission planning and cost
[[Page 49292]]
allocation requirements,\106\ and to strengthen electric reliability
and resilience, while controlling costs.\107\
---------------------------------------------------------------------------
\101\ See, e.g., Americans for Fair Energy Prices Reply Comments
at 5; SREA Reply Comments at 4.
\102\ Americans for Fair Energy Prices Reply Comments at 5
(citing PIOs Initial Comments at 34).
\103\ DC and MD Offices of People's Counsel Reply Comments at 1-
2.
\104\ ACEG Initial Comments at 21-22 (citing Grid Strategies,
LLC, Transmission Makes the Power System Resilient to Extreme
Weather, at 1-3, 12 (July 2021) (Grid Strategies July 2021 Extreme
Weather Report)).
\105\ EEI Supplemental Comments at 1.
\106\ US Senators Supplemental Comments at 1; Senator Whitehouse
Supplemental Comments at 2.
\107\ US Senator Barrasso Supplemental Comments at 1-2.
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59. Several commenters argue that the need to reform transmission
planning includes addressing environmental justice and equity
issues.\108\ Center for Biological Diversity states that energy justice
and environmental justice considerations are appropriately included in
transmission planning.\109\ Center for Biological Diversity further
asserts that it is within the Commission's authority to consider these
costs and benefits, as the benefits of decarbonization and related
energy justice objectives will be far greater than the costs.\110\
Grand Rapids NAACP, CARE Coalition, and PIOs argue that to ensure just,
reasonable, and nondiscriminatory rates, transmission planning must
consider energy equity and environmental justice.\111\ Grand Rapids
NAACP further argues that high energy burdens can be unjust,
unreasonable, and unduly discriminatory or preferential.\112\ Grand
Rapids NAACP argues that the Commission's duty under the FPA to promote
the public interest requires it to ensure that energy justice and
equity considerations are included in transmission planning
processes.\113\ WE ACT relatedly argues that, due to under-investment,
the transmission system is unreliable and vulnerable to extreme weather
events, which is both a reliability and environmental justice issue
because communities of color and low-income communities are more
susceptible to power outages during extreme weather.\114\
---------------------------------------------------------------------------
\108\ See, e.g., CARE Coalition Initial Comments at 2; Center
for Biological Diversity Initial Comments at 20-24; Environmental
Groups Supplemental Comments at 2; Environmental Legislators Caucus
Supplemental Comments at 1; Grand Rapids NAACP Initial Comments at
20-21; Massachusetts Attorney General Initial Comments at 53-54
(citing Massachusetts Attorney General ANOPR Initial Comments at 32-
34); Montclair Congregation Supplemental Comments at 1; NESCOE Reply
Comments at 8-9; New England for Offshore Wind Initial Comments at
5; PIOs Reply Comments at 11-17; US DOE Initial Comments at 9; WE
ACT Initial Comments at 1-2.
\109\ Center for Biological Diversity Initial Comments at 20-24
(citing Pacific Northwest National Laboratory & Sandia National
Laboratories, Advancing Energy Equity in Grid Planning (Apr. 2022),
https://netl.doe.gov/sites/default/files/netl-file/Advancing%20Energy%20Equity%20in%20Grid%20Planning.pdf; Office of
Energy Justice and Equity, US DOE, Justice40 Initiative, https://www.energy.gov/diversity/justice40-initiative).
\110\ Id. at 23 (citing Neb. Pub. Power Dist. v. FERC, 957 F.3d
932, 942 (8th Cir. 2020)).
\111\ Grand Rapids NAACP Reply Comments at 4 (citing 16 U.S.C.
824(a); Re Nat'l Ass'n for the Advancement of Colored People, Inc.,
95 P.U.R.3d 357 (F.P.C. 1972), vacated and remanded sub nom. NAACP
v. FPC, 520 F.2d 432 (D.C. Cir. 1975), aff'd, 425 U.S. 662 (1976));
CARE Coalition Initial Comments at 2; PIOs Reply Comments at 14.
\112\ Id. at 20-21.
\113\ Id. at 17-19.
\114\ WE ACT Initial Comments at 1-2.
---------------------------------------------------------------------------
60. Advanced Energy Buyers state that failure to prepare the grid
for the energy transition would be problematic for three primary
reasons: (1) insufficient transmission investment will leave customer
cost savings on the table; (2) lack of available transmission capacity
will constrain its members' ability to meet decarbonization and clean
energy goals; and (3) failure to plan and build adequate transmission
will hamper the transition to a cleaner and more reliable electric
grid.\115\ New Jersey Commission contends that the lack of holistic
multi-driver transmission planning is inflating consumers' electricity
costs by billions of dollars every year.\116\ Northwest and
Intermountain explain that due to insufficient transmission capacity
from renewable rich zones, utilities must attempt to meet their
renewable energy policy targets with new resources that are close to
load but more expensive, less reliable, and less efficient than more
distant alternatives, even considering the potential costs of
transmission expansion.\117\ Clean Energy Associations add that the
lack of transmission capacity imposes real and demonstrable costs
today, as evidenced by geographic differences in real-time power
prices, and that the lack of robust and proactive transmission planning
rules renders current rates unjust, unreasonable, and unduly
discriminatory or preferential.\118\
---------------------------------------------------------------------------
\115\ Advanced Energy Buyers Initial Comments at 3.
\116\ New Jersey Commission Initial Comments at 2-9.
\117\ Northwest and Intermountain Initial Comments at 6.
\118\ Clean Energy Associations Initial Comments at 5 (citing
Dev Millstein et al., Lawrence Berkeley National Laboratory,
Empirical Estimates of Transmission Value Using Locational Marginal
Prices, at 3 (Aug. 2022), https://eta-publications.lbl.gov/sites/default/files/lbnlempirical_transmission_value_study-august_2022.pdf
(LBNL Aug. 2022 Transmission Value Study)).
---------------------------------------------------------------------------
61. Southeast PIOs contend that the ``snowballing'' inefficiencies
created by numerous small-scale transmission ``band-aids'' result in
unjust, unreasonable, and unduly discriminatory or preferential rates,
and that reforms are particularly needed in the Southeast, where there
is minimal utility coordination and a balkanized transmission
system.\119\ According to ACEG, short-term, piecemeal transmission
planning is unlikely to identify the more efficient or cost-effective
solutions to transmission needs and thus will result in unjust,
unreasonable, and unduly discriminatory or preferential rates.\120\
---------------------------------------------------------------------------
\119\ Southeast PIOs Reply Comments at 1-2.
\120\ ACEG Initial Comments at 21.
---------------------------------------------------------------------------
62. Many commenters argue that reforms are necessary to meet state
policy goals \121\ and that greater state involvement or consideration
of state policies is needed to avoid transmission planning
inefficiencies.\122\ For example, ACORE cites a recent National
Renewable Energy Laboratory (NREL) report highlighting the need for new
transmission to aid in achieving zero carbon goals.\123\ NextEra opines
that the passage of the Inflation Reduction Act of 2022 will increase
the demand for renewables and drive corresponding demands on the
transmission system.\124\ Pacific Northwest State Agencies argue that
reforms are critical to successfully achieving their respective state
clean energy laws and policies and to ensuring that there is sufficient
clean, safe, reliable, and affordable energy.\125\ Michigan State
Entities note that some states may pursue aggressive renewable energy
portfolio standards, and others may have no such requirements, but
these policy choices will inevitably affect the price and reliability
of energy for all customers across the states in question and that not
planning for that reality imposes costs on unwilling customers.\126\
---------------------------------------------------------------------------
\121\ See, e.g., Acadia Center and CLF Initial Comments at 1;
ACORE Reply Comments at 1; Breakthrough Energy Initial Comments at
5-6; Business Council for Sustainable Energy Initial Comments 2-3;
Illinois Commission Initial Comments at 3-4; ISO-NE Initial Comments
at 2; Michigan State Entities Initial Comments at 2-3; National Grid
Initial Comments at 6-7; NESCOE Initial Comments at 9-10, 15-16;
NextEra Reply Comments at 5, 25; Northwest and Intermountain Initial
Comments at 5-6; [Oslash]rsted Initial Comments at 1-3; Pacific
Northwest State Agencies Initial Comments at 1; PacifiCorp and NV
Energy Initial Comments at 10-11; State Agencies Initial Comments at
16-17; Vermont Electric and Vermont Transco Initial Comments at 2;
Western State Representatives Initial Comments at 3.
\122\ See, e.g., AEE Reply Comments at 3-4; California
Democratic Representatives Supplemental Comments at 1-2; US Senators
Supplemental Comments at 1 (citing to National Academies of
Sciences, Engineering, and Medicine, Accelerating Decarbonization in
the United States: Technology, Policy, and Societal Dimensions
(2023)); Maryland Energy Admin Initial Comments at 1; North Carolina
Commission and Staff Initial Comments at 2, 4; PJM States Initial
Comments at 1; SREA Reply Comments at 4.
\123\ ACORE Reply Comments at 1 (citing Paul Denholm, et al.,
NREL, Examining Supply-Side Options to Achieve 100% Clean
Electricity by 2035 (Sept. 2022), https://www.nrel.gov/docs/fy22osti/81644.pdf).
\124\ NextEra Reply Comments at 5, 25.
\125\ Pacific Northwest State Agencies at 1.
\126\ Michigan State Entities Initial Comments at 2-3.
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[[Page 49293]]
63. PacifiCorp and NV Energy similarly assert that the need for
reform in the West is driven by the diverse policy priorities in its
six-state transmission system, and they note that decisions are subject
to state oversight and the participation of disparately situated
transmission providers without inclination or authority to accept any
cost allocation.\127\ National Grid asserts that ISO New England's
(ISO-NE) 2050 Transmission Study demonstrates a direct connection
between state laws and requirements to meet clean energy goals and the
need for new and expanded transmission facilities.\128\ Indicated PJM
TOs add that maintaining a reliable and resilient transmission system
requires forward-looking assessments informed by evolving public
policy, changing generation mix and demand patterns, and stakeholder
input.\129\
---------------------------------------------------------------------------
\127\ PacifiCorp and NV Energy Initial Comments at 10-11.
\128\ National Grid Initial Comments at 6-7 (citing the then-
preliminary findings from the ISO-NE 2050 Transmission Study).
\129\ Indicated PJM TOs Initial Comments at 1.
---------------------------------------------------------------------------
64. Maryland Energy Administration contends that Maryland has
experienced unfair and costly consequences of inadequate consultation
with state authorities in regional transmission planning
processes.\130\ AEE argues that if current transmission planning
processes fail to incorporate factors such as state laws, corporate
targets, and retail demand, then transmission needs will be unmet,
risking unjust, unreasonable, and unduly discriminatory or preferential
rates.\131\
---------------------------------------------------------------------------
\130\ Maryland Energy Administration Initial Comments at 1
(citing Maryland Energy Administration ANOPR Initial Comments at 2).
\131\ AEE Reply Comments at 3-4.
---------------------------------------------------------------------------
65. Many commenters argue that, based on the record, the Commission
has an obligation under the FPA to take action to ensure that
transmission planning and cost allocation results in rates that are
just and reasonable and not unduly discriminatory.\132\ ACEG states
that the Commission's broad authority to remedy unduly discriminatory
behavior pursuant to FPA section 206 applies to transmission planning
and cost allocation, as the U.S. Court of Appeals for the District of
Columbia Circuit held in South Carolina Public Service Authority v.
FERC.\133\ PIOs contend that the Commission is required by the FPA to
use its authority to address market abuses and undue discrimination
that have led to unjust, unreasonable, and unduly discriminatory or
preferential rates for consumers, who bear the costs of inefficiencies
in the current transmission planning process.\134\
---------------------------------------------------------------------------
\132\ See, e.g., ACEG Initial Comments at 11; Clean Energy
Associations Initial Comments at 7-10; Grand Rapids NAACP Initial
Comments at 17; Massachusetts Attorney General Initial Comments at
3-4; Pine Gate Initial Comments at 10-14; PIOs Initial Comments at
8.
\133\ 762 F.3d at 57. See also ACEG Initial Comments at 13-14;
Harvard ELI Initial Comments at 1-2; SEIA Initial Comments at 3.
\134\ PIOs Initial Comments at 8.
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66. Southeast PIOs assert that the NOPR adequately demonstrated
that existing regional transmission planning processes have intrinsic
flaws, making the integrated resource planning and request for proposal
processes ill-equipped to efficiently address changes in the resource
mix and demand.\135\ Specifically, Southeast PIOs cite the following
preliminary findings from the NOPR: (1) existing transmission planning
processes utilize a limited planning horizon; (2) many transmission
planning processes provide an inaccurate portrayal of the comparative
benefits of different transmission facilities; and (3) rapid changes to
the generation fleet and demand are creating increasingly urgent
transmission needs.\136\
---------------------------------------------------------------------------
\135\ Southeast PIOs Reply Comments at 4 (citing Duke Initial
Comments at 6-9; SERTP Sponsors Initial Comments at 31-36; Southern
Initial Comments at 36-40).
\136\ Id. at 5-6 (citing NOPR, 179 FERC ] 61,028 at PP 45, 47,
49, 53).
---------------------------------------------------------------------------
67. Southeast PIOs cite the finding in South Carolina Public
Service Authority v. FERC that the threshold of substantial evidence
could be met without ``empirical evidence'' as long as the Commission
provides evidence based on ``reasonable economic propositions.'' \137\
Southeast PIOs also note that South Carolina Public Service Authority
v. FERC upheld the Commission's findings in Order No. 1000, which were
based on (1) a threat to just and reasonable rates from existing
regional transmission planning and cost allocation practices, (2)
significant changes in the industry driven by increases in renewable
energy resources, and (3) recent increases in transmission
investment.\138\ Moreover, Southeast PIOs note that findings need not
be region-specific, as the ``Commission may rely on generic or general
findings of a systemic problem to support imposition of an industry-
wide solution.'' \139\
---------------------------------------------------------------------------
\137\ Id. at 6-7 (citing S.C. Pub. Serv. Auth. v. FERC, 762 F.3d
at 65).
\138\ Id. at 6-7 (citing S.C. Pub. Serv. Auth. v. FERC, 762 F.3d
at 65-66).
\139\ Id. at 7 (citing S.C. Pub. Serv. Auth. v. FERC, 762 F.3d
at 67).
---------------------------------------------------------------------------
68. ACEG similarly asserts that the Commission has shown the need
for transmission planning reform based on findings that existing
transmission planning requirements do not adequately identify
transmission needs driven by changes in the resource mix and demand,
and that failure to identify such needs causes customers to pay for
less efficient or cost-effective transmission investments.\140\
Relatedly, ACEG argues that pursuing region-specific solutions will
lead to siloed and disjunctive transmission planning policies that will
not solve the problems facing the Nation's electric transmission
system.\141\
---------------------------------------------------------------------------
\140\ ACEG Reply Comments at 7-8 (citing Alabama Commission
Initial Comments at 2-3; Duke Initial Comments at 6-9; Idaho Power
Initial Comments at 2-3; NRECA Initial Comments at 11; North
Carolina Commission and Staff Initial Comments at 14; Pacific
Northwest Utilities Initial Comments at 9-10; Utah Commission
Initial Comments at 9-12).
\141\ Id. at 17.
---------------------------------------------------------------------------
69. Colorado Consumer Advocate and Joint Consumer Advocates aver
that the Commission has a statutory duty under the FPA to reform
current regional transmission planning processes because they lack
transparency, coordination, and openness, and because they create
opportunities for monopoly transmission developers to exert dominant
influence and promote their own economic self-interest at customers'
and other stakeholders' expense.\142\ According to New Jersey
Commission, current transmission planning processes are inefficient and
unnecessarily burden ratepayers with excessive costs without providing
additional benefits. New Jersey Commission contends that those
processes are therefore per se unjust and unreasonable, and that the
Commission thus has FPA section 206 authority to require that
transmission providers employ practices like long-term, holistic,
multi-driver transmission planning.\143\
---------------------------------------------------------------------------
\142\ Colorado Consumer Advocate Initial Comments at 21-23;
Joint Consumer Advocates Initial Comments at 18-20.
\143\ New Jersey Commission Initial Comments at 3-4.
---------------------------------------------------------------------------
70. Similarly, Harvard ELI states that deficient transmission
planning threatens the justness and reasonableness of transmission
rates, and therefore the Commission has legal authority and
jurisdiction to order changes to transmission planning to remedy that
deficiency.\144\ Harvard ELI further asserts that the Commission must
remedy undue discrimination due to incumbent transmission owners'
unduly discriminatory influence in regional transmission planning.\145\
Massachusetts Attorney General also
[[Page 49294]]
argues that the Commission's proposed reforms are necessary to fulfill
the Commission's statutory obligation to ensure that transmission rates
are just and reasonable.\146\
---------------------------------------------------------------------------
\144\ Harvard ELI Initial Comments at 1-2 (citing S.C. Pub.
Serv. Auth. v. FERC, 762 F.3d 41; Order No.1000-A, 139 FERC ] 61,132
at PP 56-75).
\145\ Id. at 3.
\146\ Massachusetts Attorney General Initial Comments at 3-6.
---------------------------------------------------------------------------
71. Some commenters argue that there is insufficient evidence for
the Commission to find that existing jurisdictional rates are unjust,
unreasonable, and unduly discriminatory or preferential.\147\ For
example, while Idaho Commission recognizes that there are deficiencies
in existing transmission planning and cost allocation processes, Idaho
Commission disagrees with the NOPR's claim that their failure to
identify and plan for transmission needs driven by changes in the
resource mix and demand is resulting in unjust, unreasonable, and
unduly discriminatory or preferential Commission-jurisdictional
rates.\148\ Mississippi Commission also disagrees that the lack of
long-term regional transmission planning will result in unjust,
unreasonable, and unduly discriminatory or preferential rates.\149\
ELCON questions a finding of unjust, unreasonable, and unduly
discriminatory or preferential rates, and it states that the NOPR's
focus on Long-Term Regional Transmission Planning solely to address
changes in resource mix and demand, if adopted, could fail to produce
better outcomes for customers and may exceed the Commission's authority
under the FPA.\150\
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\147\ See, e.g., ELCON Initial Comments at 7; Idaho Commission
Initial Comments at 2; Mississippi Commission Initial Comments at 2,
9; NRECA Initial Comments at 14-16; Undersigned States Reply
Comments at 6-7.
\148\ Idaho Commission Initial Comments at 2 (citing NOPR, 179
FERC ] 61,028 at P 34).
\149\ Mississippi Commission Initial Comments at 2.
\150\ ELCON Initial Comments at 7.
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72. Louisiana Commission states that the Commission's finding that,
absent reforms, transmission rates universally are not just and
reasonable and are discriminatory is not based on individual analysis
of each RTO or region, is not supported, and should be retracted.\151\
Mississippi Commission also states that the Commission should, instead,
initiate region-specific investigations pursuant to FPA section
206.\152\ Southern argues that the Commission has failed to satisfy the
first prong of its FPA section 206 burden of proof, noting that the
NOPR's preliminary conclusion, that existing regional transmission
planning processes are not sufficient to address changes in the
resource mix and demand, cannot reasonably be made of Southern or
SERTP.\153\
---------------------------------------------------------------------------
\151\ Louisiana Commission Reply Comments at 5-6.
\152\ Mississippi Commission Reply Comments at 7-9.
\153\ Southern Initial Comments at 40; Southern Reply Comments
at 1-3.
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73. Similarly, Industrial Customers argue that the Commission has
not satisfied the first prong of FPA section 206, which requires the
Commission to find, and provide substantial evidence supporting its
finding, that existing rates are unjust, unreasonable, and unduly
discriminatory or preferential.\154\ Industrial Customers claim that
demand growth should be the primary factor in identifying transmission
needs, and that demand is growing more slowly than in previous periods.
Industrial Customers add that, in contrast, investment in transmission
is rising relative to demand, which is the opposite of the
circumstances that prevailed in 2007 when the Commission issued Order
No. 890.\155\ According to Industrial Customers, changes in demand are
not significant enough in historical terms to warrant major changes in
transmission planning. Moreover, Industrial Customers state that
changes in demand are unpredictable because technological changes are
inherently difficult to forecast and the risks to consumers of making
mistakes are too high. Industrial Customers argue that, if anything,
the rapid growth of renewables indicates that current processes are
already facilitating changes in the resource mix.\156\ Similarly, NRG
argues that long-term forecasts of important factors are often wrong,
which has real-world impacts on customers.\157\
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\154\ Industrial Customers Initial Comments at 6-7.
\155\ Id. at 8-10.
\156\ Id. at 10-11.
\157\ NRG Initial Comments at 10-12 (noting, for example, that
``[p]redictions for the future price of natural gas and thus the
economics of gas generation in long-term forecasts have been
notoriously inaccurate.'' (citing Lawrence Berkeley National
Laboratory, Comparison of AEO 2008 Natural Gas Price Forecast to
NYMEX Futures Prices (Jan. 2008)).
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74. Further, Industrial Customers contend that the NOPR does not
clearly define the term ``changes in the resource mix and demand,''
despite using such changes as the justification for the proposals.
Industrial Customers argue that transmission should only be planned in
order to maintain reliability and should not be based on the demand for
certain fuel sources or the fuel type of the generation fleet.\158\
Industrial Customers argue that current transmission planning is based
on known and measurable factors, and that any attempt to plan for
potential future changes in the resource mix without determining
precisely what these changes will be would result in the overbuilding
of the system for generation that may not be built. Industrial
Customers argue that this outcome would be unjust and unreasonable and
would force transmission customers to pay for generation that is non-
existent.\159\
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\158\ Industrial Customers Initial Comments at 7-8.
\159\ Id. at 15.
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75. Other commenters agree that the Commission lacks a specific
record to support the need for reform.\160\ For example, former Kansas
Commission Chair Keen avers that there is no analytical or evidentiary
basis in the NOPR for a complete and thorough overhaul or revision of
transmission planning processes.\161\
---------------------------------------------------------------------------
\160\ See, e.g., Alabama Commission Initial Comments at 4-5;
Duke Initial Comments 6-9; Idaho Commission Initial Comments at 2;
Industrial Customers Initial Comments at 1, 6-11, 15; Kansas
Commission Chair Keen Initial Comments at 1-2; Nebraska Commission
Initial Comments at 1-2; NRECA Initial Comments at 14-16; NRG
Initial Comments at 3; Ohio Commission Federal Advocate Initial
Comments at 5-6; Potomac Economics Initial Comments at 3-4; Southern
Initial Comments at 40.
\161\ Kansas Commission Chair Keen Initial Comments at 2.
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76. Duke asserts that the NOPR does not provide robust and specific
support as to how and why current regional transmission planning
processes are failing to plan for transmission needs driven by changes
in the resource mix and demand, leading to inefficient investment.\162\
Duke asserts that the NOPR does not support the presumption that the
absence of significant regional transmission investment is evidence of
inefficient transmission planning.\163\ Duke also asserts that, to
ensure legal durability, the Commission should identify evidence that
justifies a nationwide finding that current transmission planning
processes are failing to plan for transmission needs driven by changes
in the resource mix and demand, leading to inefficient investment and
unjust, unreasonable, and unduly discriminatory or preferential
rates.\164\
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\162\ Duke Initial Comments at 6-7.
\163\ Id. at 7-8.
\164\ Id. at 9 (citing Emera Me. v. FERC, 854 F.3d 9, 24 (D.C.
Cir. 2017)).
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77. Undersigned States argue that the Commission does not have
evidence in the record that current rates are unjust, unreasonable, or
unduly discriminatory or preferential, which FPA section 206
requires.\165\ Undersigned States argue
[[Page 49295]]
that, contrary to the preliminary findings in the NOPR, the Southeast
has developed significant and sufficient transmission infrastructure
and renewable energy from 2015-2020. Undersigned States further argue
that the Commission is supposed to enhance reliability, and that,
because renewables are intermittent and inherently less reliable,
forcing ratepayers to subsidize their use through financing the
construction of additional transmission infrastructure is not
consistent with the Commission's mission. Undersigned States also argue
that the Commission has not justified replacing existing transmission
planning processes with a new approach, so the NOPR is arbitrary and
capricious.\166\ Further, Undersigned States argue that the Commission
has not offered a detailed justification for countering prior precedent
in Order No. 1000 that ``the regional transmission planning process is
not the vehicle by which integrated resource planning is conducted.''
\167\
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\165\ Undersigned States Reply Comments at 6-7. The Undersigned
States that submitted reply comments include the States of Texas,
Utah, Alabama, Alaska, Arkansas, Florida, Georgia, Kansas, Kentucky,
Louisiana, Mississippi, Montana, Nebraska, Ohio, Oklahoma, South
Carolina, and West Virginia. Id. at 1. The Undersigned States that
submitted initial comments include the States of Utah, Alaska,
Georgia, Idaho, Indiana, Kansas, Kentucky, Louisiana, Mississippi,
Montana, Nebraska, North Dakota, Ohio, Oklahoma, South Carolina,
Texas, West Virginia, and Wyoming. Undersigned States Initial
Comments at 5-6.
\166\ Undersigned States Reply Comments at 6-8.
\167\ Id. at 8 (citing Order No. 1000, 136 FERC ] 61,051 at P
154).
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78. Some commenters assert that the intention of the NOPR is to
improperly favor certain energy resources.\168\ Consumer Organizations
argue that solutions that allow for an equitable transition and make
space for advancing technology and smaller energy systems are
preferrable to a rushed plan that favors certain resources, such as
wind, solar, and battery storage, that have already proven to be
inadequate.\169\ ELCON adds that Congress did not give the Commission
express authority to balance the FPA's just and reasonable rates
requirement with the policy goal of connecting renewable resources to
the transmission system.\170\ SERTP Sponsors argue that Congress has
not clearly provided the Commission with jurisdiction to presuppose
generation decisions and thereby effect particular, substantive
transmission outcomes; rather, SERTP Sponsors continue, Congress has
expressly and unequivocally reserved generation authority to the
states.\171\ Louisiana Commission argues that the FPA does not confer
on the Commission authority to engage in wide-scale public policymaking
by enacting sweeping energy policy changes with far-reaching,
nationwide effects.\172\
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\168\ See, e.g., Consumers Organizations Initial Comments at 1-
3; ELCON Initial Comments at 9-10.
\169\ Consumers Organizations Initial Comments at 1-3.
\170\ ELCON Initial Comments at 9-10 (citing 16 U.S.C.
824q(b)(4)).
\171\ SERTP Sponsors Initial Comments at 18.
\172\ Louisiana Commission Initial Comments at 6 (citing West
Virginia v. EPA, 597 U.S. 697 (2022)).
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79. Ohio Commission Federal Advocate states that the NOPR may be
intended ``to establish policies designed to encourage the massive
transmission build-out that will doubtless be required to transition to
an aspirational renewable future'' and ``to achieve narrow
environmental policy objectives, not to address legitimate requirements
under the Federal Power Act like ensuring just and reasonable rates or
reliability.'' \173\ Former Kansas Commission Chair Keen claims that
the NOPR encourages an extensive and expensive transmission build-out
without considering the impact on state-jurisdictional generation
mixes. He also claims that some of the NOPR proposals impose an
accelerated pace for the transition from dispatchable to renewable
resources, which could hasten the premature retirement of dispatchable
generation and compromise regional and state power reliability. He also
expresses concern that the NOPR proposals would force ratepayers in
some states to pay for neighboring states' transmission projects to
advance public policy goals that they do not share.\174\
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\173\ Ohio Commission Federal Advocate Initial Comments at 4-5
(citing NOPR, 179 FERC ] 61,028, Danly, Comm'r, dissenting, at PP 2-
3).
\174\ Kansas Commission Chair Keen Initial Comments at 3.
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80. Some commenters challenge aspects of the need for reform. For
example, Nebraska Commission believes that the established structures
in RTO/ISO regions are generally working and that many aspects of the
NOPR are thus unnecessary there.\175\ Potomac Economics disagrees with
some of the Commission's arguments for requiring Long-Term Regional
Transmission Planning, contending that the Commission's proposals are
based on anticipated future generation and other speculative factors
and seem to be incorrectly premised on a presumption that congestion
should not exist or may limit investment in economic generation.
Potomac Economics states that investment should occur only to the
extent that the savings of reducing congestion are larger than the
investment costs. According to Potomac Economics, congestion that is
caused by generators' siting decisions should be borne by the
generation developers, as it will incent them to propose the lowest-
cost projects taking transmission costs into account. Potomac Economics
argues that, if transmission is expanded preemptively to facilitate
generation investment in a particular location, such costs are
equivalent to subsidies for the developer.\176\
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\175\ Nebraska Commission Initial Comments at 1-2.
\176\ Potomac Economics Initial Comments at 3-4.
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81. Mississippi Commission disagrees that too much expansion of
high-voltage transmission has occurred through the generator
interconnection process instead of through regional transmission
planning.\177\ Similarly, North Carolina Commission and Staff disagree
with the Commission's conclusion that the growth in interconnection-
related network upgrades demonstrates a failure of regional
transmission planning as it relates to North Carolina.\178\ Southern
adds that, contrary to statements in the NOPR, it is not significantly
expanding its transmission system through the generator interconnection
process.\179\
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\177\ Mississippi Commission Initial Comments at 9.
\178\ North Carolina Commission and Staff Initial Comments at 5.
\179\ Southern Initial Comments at 38-40.
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82. Alabama Commission asserts that Alabama has a resource planning
process that accounts for needed transmission buildout to maintain
reliable service, and thus, Alabama Power plans its transmission system
proactively both to maintain deliveries from existing resources and to
accommodate Alabama Commission-certified generation additions. Alabama
Commission claims that the SERTP process builds on the integrated
resource planning efforts of its sponsor states, ensuring that there
are no regional transmission solutions that are more efficient or cost-
effective than solutions identified through the underlying state-
jurisdictional processes.\180\
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\180\ Alabama Commission Initial Comments at 4.
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83. Duke argues that, for certain transmission providers, the local
transmission planning process may more effectively meet transmission
needs, especially when combined with state-regulated integrated
resource planning and a bottom-up regional transmission planning
process. Duke contends that a regional transmission facility may not
fully address local transmission needs such that a local transmission
facility would still be needed, and thus, the regional transmission
facility is not necessarily more efficient or cost-effective than the
local transmission facility.\181\
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\181\ Duke Initial Comments at 7-9.
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[[Page 49296]]
84. NRECA states that certain of its members in RTOs/ISOs believe
that regional transmission planning is working well to meet long-term
needs (e.g., those in MISO) and that the NOPR proposals would burden
transmission providers' limited resources. NRECA states that other
NRECA members in RTOs/ISOs believe that existing RTO/ISO transmission
planning processes contain discrete deficiencies that the NOPR
proposals will not remedy. According to NRECA, these electric
cooperatives believe that some incumbent investor-owned transmission
owners develop local transmission projects without transparency
concerning need or costs, leading to disparities in transmission rates
across RTO/ISO transmission zones, and that incumbent transmission
owners control the transmission planning process such that no regional
transmission planning occurs. NRECA states that, in these cooperatives'
view, the criteria to determine the eligibility of a regional
transmission project is the barrier, and that requiring Long-Term
Regional Transmission Planning, by itself, will not solve the
problem.\182\
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\182\ NRECA Initial Comments at 14-16.
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C. Commission Determination
85. Based on the record, we find that there is substantial evidence
to support the conclusion that the Commission's existing regional
transmission planning and cost allocation requirements are unjust,
unreasonable, and unduly discriminatory or preferential. We therefore
adopt the preliminary findings in the NOPR concerning the need for
reform. Specifically, we find that the absence of sufficiently long-
term, forward-looking, and comprehensive transmission planning
requirements is causing transmission providers to fail to adequately
anticipate and plan for future system conditions. It causes
transmission providers to fail to appropriately evaluate the benefits
of transmission infrastructure, and results in piecemeal transmission
expansion to address relatively near-term transmission needs. We find
that this status quo causes transmission providers to undertake
relatively inefficient investments in transmission infrastructure, the
costs of which are ultimately recovered through Commission-
jurisdictional rates. This dynamic results in, among other things,
transmission customers paying more than necessary or appropriate to
meet their transmission needs and forgoing benefits that outweigh their
costs, which results in less efficient or cost-effective transmission
investments. As explained below, we find that these deficiencies render
Commission-jurisdictional regional transmission planning and cost
allocation processes unjust, unreasonable, and unduly discriminatory or
preferential.
86. The Commission has authority under FPA section 206 to issue
this final order. Specifically, FPA section 206 ``instructs the
Commission to remedy `any . . . practice' that `affect[s]' a rate for
interstate electricity service `demanded' or `charged' by `any public
utility' if such practice is `unjust, unreasonable, unduly
discriminatory or preferential.''' \183\ As the D.C. Circuit has
recognized, regional transmission planning and cost allocation
processes are practices affecting rates subject to the Commission's
exclusive jurisdiction.\184\ As the Court explained in South Carolina
Public Service Authority v. FERC, transmission providers use those
processes to ``determine which transmission facilities will more
efficiently or cost-effectively meet'' transmission needs, the
development of which directly impacts the rates, terms, and conditions
of Commission-jurisdictional service.\185\ In particular, because these
processes identify, evaluate, and select the regional transmission
facilities whose costs will be recovered through transmission rates, we
find that they directly affect those rates.\186\ In addition, as
discussed below, such transmission facilities contribute to the
development of a more robust transmission system, supporting continuity
of service in the face of growing reliability challenges and providing
wholesale electric customers greater access to lower-cost generation
supplied by a wider range of resources. Accordingly, regional
transmission planning and cost allocation processes, as well as ``the
rules and practices that determine how those [processes]
operate,''\187\ have a direct effect on the rates that customers pay
for both the transmission and sale of electric energy in interstate
commerce.\188\ The Commission may act pursuant to FPA section 206 if
the Commission first establishes, through substantial evidence,\189\
that the existing practices are unjust, unreasonable, or unduly
discriminatory or preferential and, second, establishes that the
replacement practices are just and reasonable.\190\
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\183\ S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 55 (quoting 16
U.S.C. 824e(a)).
\184\ Id. at 55-59, 84 (affirming the Commission's authority to
regulate transmission planning and cost allocation as practices
affecting rates); see also Order No. 1000-A, 139 FERC ] 61,132 at P
577 (holding that ``requirements regarding transmission planning and
cost allocation . . . are practices affecting rates.'').
\185\ S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 56 (citing
Order No. 1000, 136 FERC ] 61,051 at PP 112, 116); see also Emera
Me. v. FERC, 854 F.3d at 674.
\186\ That is true even if regional transmission planning and
cost allocation processes do not result in the development, siting,
and construction of every regional transmission facility that
transmission providers select to more efficiently or cost-
effectively meet transmission needs. See, e.g., Conn. Dep't of Pub.
Util. Control v. FERC, 569 F.3d 477, 485 (D.C. Cir. 2009) (holding
that ``even if all [that] the I[nstalled] C[apacity] R[equirement]
did was help to find the right [capacity] price,'' rather than
result in the construction or procurement of any new capacity, ``it
would still amount to a `practice . . . affecting' rates.'' (citing
16 U.S.C. 824e(a) (omission in original))).
\187\ FERC v. Elec. Power Supply Ass'n, 577 U.S. 260, 279 (2016)
(EPSA).
\188\ 16 U.S.C. 824e(a).
\189\ S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 54 (``The
Commission's factual findings are conclusive if supported by
substantial evidence.''). Courts have held that substantial evidence
in this context does not necessarily require the Commission to
provide empirical evidence for every proposition. Rather, FPA
section 206 empowers the Commission to address a mere threat of
unjust and unreasonable rates. See S.C. Pub. Serv. Auth. v. FERC,
762 F.3d at 64-65, 85.
\190\ 16 U.S.C. 824e(a); see also EPSA, 577 U.S. at 277
(affirming the Commission ``has the authority--and indeed, the
duty--to ensure that rules or practices `affecting' wholesale rates
are just and reasonable'').
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87. With regard to the first showing under FPA section 206, we find
that, while Order No. 890 requires transmission providers to satisfy
certain principles in their local transmission planning processes and
Order No. 1000 requires transmission providers to participate in
regional transmission planning and cost allocation processes that
satisfy the requirements set forth therein, these existing transmission
planning and cost allocation requirements do not result in regional
transmission planning that is conducted on a sufficiently long-term,
forward-looking, and comprehensive basis to plan for Long-Term
Transmission Needs. As a result, we find that transmission providers
are often not identifying, evaluating, or selecting more efficient or
cost-effective regional transmission solutions to meet Long-Term
Transmission Needs. This gap in existing regional transmission planning
processes results in piecemeal, inefficient, and less cost-effective
transmission planning that imposes real costs on customers, who pay
Commission-jurisdictional transmission rates for less efficient or
cost-effective transmission facilities and do not realize the benefits
that would result from long-term, forward-looking, and more
comprehensive regional transmission planning and cost allocation
processes that identify, evaluate, and select more efficient or cost-
effective transmission
[[Page 49297]]
solutions to Long-Term Transmission Needs.
88. We find that these deficiencies in the Commission's existing
transmission planning and cost allocation requirements render those
requirements unjust, unreasonable, and unduly discriminatory or
preferential in violation of FPA section 206.
89. We also find that the Commission's existing transmission
planning and cost allocation requirements are insufficient to ensure
just and reasonable and not unduly discriminatory or preferential
rates. Given these findings, we are now requiring, pursuant to FPA
section 206, that transmission providers engage in and conduct
sufficiently long-term, forward-looking, and comprehensive transmission
planning and cost allocation processes to identify and plan for Long-
Term Transmission Needs. We find that these reforms will facilitate a
process by which transmission providers can better identify, evaluate,
and select more efficient or cost-effective transmission solutions to
meet Long-Term Transmission Needs, which will ensure that Commission-
jurisdictional rates are just and reasonable and not unduly
discriminatory or preferential.
1. The Transmission Investment Landscape Today
90. As the Commission explained in the NOPR, a robust, well-planned
transmission system is foundational to ensuring an affordable, reliable
supply of electricity.\191\ Due to continuing changes in the industry,
ongoing investment in transmission facilities is necessary to ensure
the transmission system continues to serve load in a reliable,\192\
affordable, and economically efficient fashion. Such investments
support enhanced reliability, as larger, more integrated transmission
systems result in a diversity of supply and demand conditions and a
certain degree of redundancy that allows the system to better withstand
failures during extreme events.\193\ Proactive, forward-looking
transmission planning that considers both evolving reliability needs
and other drivers of transmission needs more comprehensively can enable
transmission providers to identify potential reliability problems and
economic constraints, as well as to evaluate potential transmission
solutions, well in advance of these issues affecting the transmission
system,\194\ which can facilitate the selection of more efficient or
cost-effective transmission facilities to meet Long-Term Transmission
Needs.
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\191\ NOPR, 179 FERC ] 61,028 at P 28 (citing 16 U.S.C. 824,
824d, 824e); see also US DOE ANOPR Initial Comments at 2 (stating
that ``strengthening and expanding existing transmission
infrastructure, particularly the development of regional and inter-
regional transmission projects, is key to continued access to
reliable, resilient, lower-cost, and clean electricity for all'').
\192\ See, e.g., MISO ANOPR Initial Comments at 40; Testimony of
James B. Robb Before the U.S. Senate Energy and Natural Resources
Committee, Reliability, Resiliency, and Affordability of Electric
Service in the United States Amid the Changing Energy Mix and
Extreme Weather Events, at 8-9 (Mar. 11, 2021), https://www.energy.senate.gov/services/files/D47C2B83-A0A7-4E0B-ABF2-9574D9990C11 (testifying that more transmission infrastructure is
required to ensure the reliability and resilience of the bulk power
system in light of changing conditions).
\193\ ACORE ANOPR Initial Comments Ex. 4, Grid Strategies July
2021 Extreme Weather Report; Mark Chupka & Pearl Donohoo-Vallett,
Recognizing the Role of Transmission in Electric System Resilience
(May 2018), https://wiresgroup.com/wp-content/uploads/2020/06/2018-05-09-Brattle-Group-Recognizing-the-Role-of-Transmission-in-Electric-System-Resilience-.pdf; NERC ANOPR Initial Comments at 17-
18; US DOE ANOPR Initial Comments at 18.
\194\ MISO's Multi-Value Project (MVP) regional transmission
planning process, for example, eliminated the need for approximately
$300 million in reliability transmission facilities, resolving
reliability violations and mitigating system instability conditions,
through a forward-looking approach. Midcontinent Independent System
Operator, MTEP17 MVP Triennial Review: A 2017 review of the public
policy, economic, and qualitative benefits of the Multi-Value
Project Portfolio, at 11, 33 (Sept. 2017) (MTEP2017 Review).
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91. In addition, transmission infrastructure can unlock the forces
of competition, changing who can sell to whom, eliminating barriers to
entry, and mitigating market power.\195\ Increased competition, in
turn, can provide a host of benefits for customers, including cost-
savings from greater access to low-cost power and a wider range of
resources.\196\ Transmission infrastructure can also serve as a form of
insurance against future uncertainties because a more robust,
integrated transmission system has the potential to provide consumers
with the benefits of competition and enhanced reliability even if
supply and demand fundamentals change over time.\197\
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\195\ Policy Integrity ANOPR Initial Comments at 13 n.40 (``A
new transmission project can enhance competition by both increasing
the total supply that can be delivered to consumers and the number
of suppliers that are available to serve load.'' (citing Mohamed
Awad et al., The California ISO Transmission Economic Assessment
Methodology (TEAM): Principles and Applications to Path 26, at 3
(2006)); PIOs ANOPR Initial Comments Ex. A, Johannes Pfeifenberger
et al., The Brattle Group and Grid Strategies, Transmission Planning
for the 21st Century: Proven Practices that Increase Value and
Reduce Costs, at 48-49 (Oct. 2021) (Brattle-Grid Strategies Oct.
2021 Report), https://www.brattle.com/wp-content/uploads/2021/10/2021-10-12-Brattle-GridStrategies-Transmission-Planning-Report_v2.pdf (``Expansion of the transmission network typically
increases the number of independent wholesale electricity suppliers
that are able to compete to supply electricity at locations in the
transmission network served by the upgrade . . . .'' (quoting F.A.
Wolak, World Bank, Managing Unilateral Market Power in Electricity,
Policy Research Working Paper No. 3691, at 8 (2005))).
\196\ See, e.g., PJM Interconnection, L.L.C., PJM Value
Proposition, at 1-2 (2019), https://www.pjm.com/about-pjm/~/media/
about-pjm/pjm-value-proposition.ashx (PJM's planning of resource
adequacy over a large region is estimated to result in savings of
$1.2-1.8 billion.); Midcontinent Independent System Operator, MISO
Value Proposition (2020), https://www.misoenergy.org/meet-miso/MISO_Strategy/miso-value-proposition/ (MISO estimated $517-572
million in savings from more efficient use of existing assets and
$2.5-3.2 billion from reduced need for additional assets.); SPP
Transmission Planning, Southwest Power Pool, SPP's Value of
Transmission: 2021 Report and Update (Mar. 31, 2022) (SPP estimated
$382.7 million in adjusted product costs savings in 2020 due to
transmission investment.); see also ACEG Initial Comments at 3-4
(``The benefits generated by MISO's MVPs and SPP's Priority Projects
exceeded the costs by 2.2 to 3.5 times and means that every dollar
spent on transmission will enable access to generation that is $3 to
$4 cheaper than would otherwise be available.'').
\197\ US DOE, National Electric Transmission Congestion Study,
at 11 (Sept. 2015), https://www.energy.gov/sites/prod/files/2015/09/f26/2015%20National%20Electric%20Transmission%20Congestion%20Study_0.pdf
(stating transmission expansion can strengthen and increase the
flexibility of the overall network and ``create real options to use
the transmission system in ways that were not originally
envisioned''); Vikram S. Budhraja et al., Improving Electricity
Resource Planning Processes by Considering the Strategic Benefits of
Transmission, 22 ELEC. J. 54 (Mar. 2009) (high voltage transmission
affords ``mitigation of risks as a form of insurance against extreme
events'').
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92. With that overview, we again begin with the key facts on the
ground.\198\ Since the issuance of Order No. 1000, transmission
spending has continued to increase nationwide. A study by US DOE found
that ``annual investment [in transmission] first exceeded $5 billion
per year in 2006 . . . and has increased consistently since that time.
Annual investment [] doubled to more than $10 billion per year by 2010
and then [] doubled again by 2016. Annual investment has been between
$18 billion and $22 billion annually since 2014.'' \199\ A separate
study, noted by the Commission in the NOPR, estimated that transmission
developers in the United States invested $20 to $25 billion annually in
transmission facilities from 2013 to 2020.\200\ Unsurprisingly, in
regions that saw a significant increase in transmission expenditures,
transmission costs have also become an increasing
[[Page 49298]]
share of customers' overall electricity bills, underscoring the
importance of ensuring that transmission investments are efficient and
cost-effective.\201\
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\198\ NOPR, 179 FERC ] 61,028 at P 36.
\199\ California Commission Reply Comments at 9 n.27 (quoting US
DOE, National Electric Transmission Congestion Study, at 9-10 (Sept.
2020), https://www.energy.gov/sites/default/files/2020/10/f79/2020%20Congestion%20Study%20FINAL%2022Sept2020.pdf).
\200\ NOPR, 179 FERC ] 61,028 at P 39 (citing Brattle-Grid
Strategies Oct. 2021 Report at 2); Brattle Apr. 2019 Competition
Report at 2-3 & fig.1.
\201\ Resale Iowa Initial Comments at 3 (``[T]ransmission costs
have comprised an increasing percentage of [] total wholesale
electric costs [for Resale Iowa's members]. Currently, transmission
and ancillary services constitute approximately 43% of such costs,
as compared to 18.1% in 2009.''); Industrial Customers Initial
Comments at 5 (showing that transmission costs made up just 7% of
the total PJM electricity bill in 2011 but 27% by 2020); Rob
Gramlich and Jay Caspary, Americans for a Clean Energy Grid,
Planning for the Future: FERC's Opportunity to Spur More Cost-
Effective Transmission Infrastructure, at 26-28 (Jan. 2021), https://cleanenergygrid.org/wp-content/uploads/2021/01/ACEG_Planning-for-the-Future1.pdf (ACEG Jan. 2021 Planning Report) (stating that the
current approach to transmission planning ``results in higher total
energy bills for customers than would result from more forward-
looking, holistic transmission planning''); see also California
Municipal Utilities Initial Comments at 10 (projecting that between
2022 and 2040, total high and low-voltage transmission access
charges will nearly double and noting that ``[g]one are the days
when transmission was a de minimis portion of the overall bill and
increases had little impact on the end consumer''); Public Systems
Initial Comments at 5 (noting that ``New England's Regional Network
Service transmission rate has grown nine-fold, from $15.60 per kW-
year (in 2003) to $140.98 per kW-year (in 2021)'').
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93. Furthermore, the record demonstrates that transmission
investment is likely to substantially increase in coming years. A
number of studies project significant and sustained transmission
spending through at least 2050. For example, one projection cited by
the US DOJ and FTC states that ``high voltage transmission capacity
must expand by 60 percent by 2030 at a capital cost of $330 billion,
and must triple by 2050 at a capital cost of $2.2 trillion.'' \202\
TAPS cites a separate study projecting $750 billion of new transmission
investment between 2023 and 2050.\203\ SoCal Edison ``estimates that
grid investments of up to $75 billion, including transmission upgrades,
will be required from 2030 to 2045 in California alone to integrate
bulk renewable generation and storage and serve load growth associated
with electrification.'' \204\ And ISO-NE's recently-completed 2050
Transmission Study estimates that transmission investment in New
England will range from $16 billion to $26 billion between 2024 and
2050, depending on the amount of load growth realized in the
region.\205\
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\202\ US DOJ and FTC Initial Comments at 3 (citing Eric Larson
et al., Net-Zero America: Potential Pathways, Infrastructure, and
Impacts, Princeton Univ., 108 (Oct. 2021), https://netzeroamerica.princeton.edu/the-report).
\203\ TAPS Initial Comments at 46 & n.133 (citing J[uuml]rgen
Weiss et al., The Brattle Group, The Coming Electrification of the
North American Economy, at iii (2019), https://wiresgroup.com/wp-content/uploads/2020/05/2019-03-06-Brattle-Group-The-Coming-Electrification-of-the-NA-Economy.pdf)).
\204\ SoCal Edison Initial Comments at 2 (citing Southern
California Edison, Pathway 2045: Update to the Clean Power and
Electrification Pathway (2019), https://download.newsroom.edison.com/create_memory_file/?f_id=5dc0be0b2cfac24b300fe4ca&content_verified=True) (emphasis
added)).
\205\ ISO-NE, 2050 Transmission Study, at 55-56 (Feb. 12, 2024),
https://www.iso-ne.com/static-assets/documents/100008/2024_02_14_pac_2050_transmission_study_final.pdf.
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94. The growing need for new transmission infrastructure,
particularly over a longer time horizon, is being driven by a number of
factors. First, longer-term reliability needs are changing. The NOPR
explained that transmission system operators are increasing their
reliance on regional transmission facilities to ensure operational
stability, particularly because of the growing frequency of extreme
weather events and increasing share of variable resources entering the
resource mix.\206\ The comments submitted in response to the NOPR
support that preliminary finding. The record shows that changing
reliability needs are driving a significant shift in demands placed on
the transmission system,\207\ and that because extreme weather events
are occurring with greater frequency, transmission is increasingly
critical to ensuring system reliability.\208\ For example, Winter Storm
Uri demonstrated that transmission infrastructure can make critical
contributions to system reliability during extreme weather events,\209\
as well as how transmission constraints can prevent operational
generation resources from being able to serve load during tight supply
conditions.\210\ Consistent with experience from Winter Storm Uri, US
DOE's Lawrence Berkeley National Laboratory provides further evidence
of the significant value of transmission during unanticipated events,
with research suggesting that 50% of the value created by alleviating
transmission system congestion occurs during only 5% of the hours
during which the transmission system is used.\211\ Thus, transmission
investment is likely to be more critical, and produce more reliability
benefits, for customers as extreme weather and other system
contingencies become more frequent.\212\ For some communities who can
be more susceptible to the impacts of extreme weather, like communities
of color and
[[Page 49299]]
low-income communities, transmission investment has the potential to be
even more critical.\213\ Conversely, failure to adequately plan the
transmission system to meet such changing reliability needs will forgo
many of those potential benefits, jeopardize system reliability, and
force customers to pay for transmission facilities that may not
efficiently or cost-effectively address urgent reliability needs.
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\206\ NOPR, 179 FERC ] 61,028 at P 45.
\207\ ACEG Initial Comments at 5 (noting that weather-related
power outages cost Americans $25-70 billion annually (citing Grid
Strategies July 2021 Extreme Weather Report at 1)); id. at 52
(explaining that ``[c]hanges to the transmission planning processes
that would allow for certain transmission upgrades identified in the
interconnection process to be addressed and ultimately constructed
through the transmission planning process will only serve to
increase the resiliency and reliability of the transmission
system.''); ACEG Reply Comments at 5-6 (``[R]eliability requires
long term transmission planning that incorporates known and knowable
information about the future resource mix.''); NERC Initial Comments
at 6 (``Transmission will be the key to support the resource
transformation enabling delivery of energy from areas that have
surplus energy to areas which are deficient. The frequency of such
occurrences are increasing as extreme weather conditions resulting
from climate change impact the fuel sources for variable energy
resources. Regional transmission planning can ensure that sufficient
amounts of transmission capacity will be needed to address these
more frequent extreme weather conditions.'').
\208\ See DC and Maryland Offices of People's Counsel Reply
Comments at 2 (noting that new transmission development has benefits
including enhanced reliability and resilience that will serve as a
necessary bulwark against disruptions caused by extreme weather);
Indicated PJM TOs Initial Comments at 1 (explaining that maintaining
a ``reliable and resilient'' transmission system requires holistic
planning); NESCOE Initial Comments at 32-33 (``ISO-NE explains that
energy-security risks in New England are well documented,
highlighting the importance of conducting comprehensive energy
security assessments covering a wide range of operating conditions,
including low-probability, high-impact reliability risks (tail
risks) related to extreme weather'' (internal quotations omitted));
NYISO Initial Comments at 16 (expressing a desire to engage in
actionable scenario planning to plan for future reliability
challenges that may arise due to extreme weather, including the loss
of all generation connected to a pipeline or other fuel sources,
loss of an entire transmission line, and impacts from weather events
like hurricanes or wildfires).
\209\ ACEG Initial Comments at 22 n.63 (During Winter Storm Uri,
``[a]n additional 1 gigawatt (GW) of transmission ties between ERCOT
and the Southeastern U.S. could have saved nearly $1 billion and
kept power flowing to hundreds of thousands of Texans.'' (citing
Grid Strategies July 2021 Extreme Weather Report at 1-3, 12)); Grid
Strategies July 2021 Extreme Weather Report at 7-8 (``The value of
transmission for resilience can be seen in the drastically different
outcomes of MISO and SPP relative to ERCOT during [Winter Storm
Uri]. . . . In contrast to the 13,000 MW MISO was importing during
the peak of [the] event, ERCOT was only able to import about 800 MW
of power throughout the event.''); NARUC Initial Comments at 67
n.192 (During Winter Storm Uri, SPP's `` `relationships and
interconnections with neighboring systems were critical. Usually a
net exporter of energy, SPP relied significantly on imported energy
to serve load during the winter event, with net amounts exceeding
6,000 megawatts (MW) at times. This emphasizes the value these
relationships and robust transmission interconnections provide
during emergency events and the opportunity to further strengthen
them.' '' (quoting Southwest Power Pool, A Comprehensive Review of
Southwest Power Pool's Response to the February 2021 Winter Storm:
Analysis and Recommendations, at 9 (July 2021), https://spp.org/documents/65037/comprehensive%20review%20of%20spp%27s%20response%20to%20the%20feb.%202021%20winter%20storm%202021%2007%2019.pdf (brackets omitted))).
\210\ See Advanced Energy Buyers Initial Comments at 3.
\211\ ACORE Initial Comments at 10-11 (citing LBNL Aug. 2022
Transmission Value Study at 33); US DOE Initial Comments at 5-6 &
n.13.
\212\ ACORE Initial Comments at 11 (citing LBNL Aug. 2022
Transmission Value Study at 33; see also Clean Energy Associations
Initial Comments at 5.
\213\ See, e.g., WE ACT Initial Comments at 1-2 & n.3 (citing
Jeff Turrentine, NRDC, A Roadmap for Frontline Communities (Dec.
2019)); see also Grand Rapids NAACP Initial Comments at 8 n.20
(``[P]ower outages uniquely burden low-income communities of color
`given that they are unable to `bounce back' as quickly from events
that damage food and medicine supplies' '' (citing Shalanda Baker et
al., The Energy Justice Workbook 20 (2019), https://iejusa.org/wp-content/uploads/2019/12/The-Energy-Justice-Workbook-2019-web.pdf)).
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95. Second, demand is changing. After many years of flat or minimal
load growth in regions across the country, demand, on both a national
and a regional basis, is projected to significantly increase in the
coming decades, and it will require an increasingly robust transmission
system to reliably serve this load growth. As stated in the NOPR,
changes in electric demand and associated load profiles are occurring
as load-serving entities work to meet increasing needs due to
electrification trends, as well as new large loads associated with
evolving industrial and commercial needs, such as growth in data
centers.\214\ The comments submitted in this record demonstrate that,
in regions across the country, customers are electrifying everything
from household appliances to vehicles.\215\ Comments also substantiate
the fact that, in many regions, large loads associated with new and
emerging industrial needs, like data centers, are driving rapid load
growth.\216\ Estimates quantifying the magnitude of this shift show
that it is significant, with nationwide demand for electricity
projected to increase by 5% to 15% (200 to 600 TWh) by 2030.\217\ That
trend is projected not just to continue but to accelerate, with
nationwide demand for electricity projected to increase by 25% to 85%
(1,100 to 3,700 TWh) by 2050.\218\ Industrial customers in many regions
are driving much of this increase; industry executives have reported
that electrification initiatives, through which many of the Nation's
largest companies plan to electrify their manufacturing processes,
transportation, and heating operations, are well underway or soon to
begin.\219\ Importantly, the record shows that these increases in
aggregate demand for electricity will have significant consequences for
the transmission system. To serve more load, the capacity of the
already-oversubscribed transmission system will need to increase.\220\
Moreover, load growth driven primarily by electrification can create a
load profile that has a higher load factor and that is thus more
challenging to serve.\221\
---------------------------------------------------------------------------
\214\ NOPR, 179 FERC ] 61,028 at PP 45, 51. The continuation
and, in some instances, acceleration of these trends identified in
the ANOPR and NOPR counters certain commenters' concerns that
changes in demand are inherently unpredictable or that existing
regional transmission planning processes are adequately identifying
and addressing transmission needs. Compare infra notes 21515-2188
and accompanying discussion, with Potomac Economics Initial Comments
at 3-4 (arguing that Long-Term Regional Transmission Planning that
requires speculating about future uncertainty is not advisable), and
Industrial Customers Initial Comments at 10-11 (arguing that changes
in demand are unpredictable).
\215\ AEE Initial Comments at 1, 14 (noting that, as of 2022,
``[n]ine states have also taken steps directly to promote
electrification of transportation and buildings. Individuals and
governments are also adopting electric vehicles; for example, light-
duty electric vehicle sales have increased from 10,092 vehicles in
2011 to 459,426 vehicles in 2021, over a 4400% increase.'');
Renewable Northwest Initial Comments at 20 (explaining that heat
pumps installed as part of building electrification could add large
new weather-dependent loads, estimated at 20,000 to 40,000 MW of
incremental peak capacity by 2050 across the Pacific Northwest); see
also AMP Initial Comments at 4; ISO-NE, Operational Impact of
Extreme Weather Events: Final Report on the Probabilistic Energy
Adequacy Tool (PEAT) Framework and 2027/2032 Study Results, at 190-
94 (Nov. 2023) (providing sensitivity that included 15% and 10%
increases in peak load and average hourly loads, respectively,
driven by heating and vehicle electrification); U.S. Energy Info.
Admin. (EIA), Incentives and Lower Costs Drive Electric Vehicle
Adoption in Our Annual Energy Outlook, (May 15, 2023) (noting that,
per 2023 Annual Energy Outlook Projections, electric vehicles will
account for between 13% and 29% of new light-duty vehicle sales in
the United States, and between 11% and 26% of then on-road light
duty vehicle stocks, by 2050).
\216\ See, e.g., Transmission Dependent Utilities Initial
Comments at 4-5 (``For example, the PJM Interconnection, L.L.C.
Transmission Expansion Advisory Committee recently posted that
Dominion Energy Virginia will need over $603 million in transmission
upgrades through 2025--just three years from now--to accommodate
significant data center load growth in Northern Virginia.'' (citing
PJM Transmission Advisory Committee, Reliability Analysis Update, at
3, 5 (Aug. 9, 2022))). These trends are continuing and even
accelerating. See PJM Interconnection, L.L.C., PJM Load Forecast
Report, at 1 (Jan. 2024), https://www.pjm.com/-/media/library/reports-notices/load-forecast/2024-load-report.ashx (noting upward
adjustments in 2024 load forecasts for certain zones to account for
large, unanticipated load growth driven by data centers, a chip
processing plant, and port electrification, among other factors);
id. at 78 (projecting increase from 2,333 GWh in 2024 to 130,489 GWh
in 2039 due to plug-in electric vehicles); id. at 30 (showing 1.0%
higher load growth projection for 2024, 6% higher load growth
projection for 2029, and 10.4% higher load growth projection for
2034, as compared to 2023 Load Forecast Report).
\217\ National Grid Initial Comments at 8 (citing J[uuml]rgen
Weiss et al., The Brattle Group, The Coming Electrification of the
North American Economy (Mar. 2019), https://wiresgroup.com/wp-content/uploads/2020/05/2019-03-06-Brattle-Group-The-Coming-Electrification-of-the-NA-Economy.pdf).
\218\ Id.; see also John D. Wilson and Zach Zimmerman, Grid
Strategies, The Era of Flat Power Demand is Over, at 3 (Dec. 2023),
https://gridstrategiesllc.com/wp-content/uploads/2023/12/National-Load-Growth-Report-2023.pdf (``Over [2023], grid planners nearly
doubled the 5-year load growth forecast. The nationwide forecast of
electricity demand shot up from 2.6% to 4.7% growth over the next
five years, as reflected in 2023 FERC [Form 714] filings. Grid
planners forecast peak demand growth of 38 gigawatts (GW) through
2028.''); N. Amer. Elec. Reliability Corp., 2023 Long-Term
Reliability Assessment, at 33 (Dec. 2023), https://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/NERC_LTRA_2023.pdf
(``Electricity peak demand and energy growth forecasts over the 10-
year assessment period are higher than at any point in the past
decade. The aggregated assessment area summer peak demand forecast
is expected to rise by 79 GW, and aggregated winter peak demand
forecasts are increasing by nearly 91 GW. Furthermore, the growth
rates of forecasted peak demand and energy have risen sharply since
the 2022 [Long-Term Reliability Assessment], reversing a decades-
long trend of falling or flat growth rates.'').
\219\ Renewable Northwest Initial Comments at 20 (``A recent
study done by Deloitte showed that 70 percent of executives in
industrial manufacturing industries have plans for the
electrification of industrial processes, and 50 percent of the
executives who responded have goals to electrify vehicle fleets and
space and water heating within their companies by 2030.'' (citing
Stanley Porter et al., Deloitte, Electrification in Industrials
(Aug. 2020), https://www2.deloitte.com/us/en/insights/industry/power-and-utilities/electrification-in-industrials.html)).
\220\ See, e.g., National Grid Initial Comments at 6 (discussing
preliminary findings of the ISO-NE 2050 Transmission Study, which
show ``significant new transmission will be needed to reliably
serve'' increased future loads assumed in the study (citing ISO-NE,
2050 Transmission Study (2023), https://www.iso-ne.com/static-assets/documents/2023/08/2050_study_ma_cetwg_2023_aug_final.pdf));
Northwest and Intermountain Initial Comments at 5 n.12 (``For
example, Bonneville Power Administration (`BPA') owns about 75
percent of the transmission lines in the Pacific Northwest. In BPA's
2022 Transmission Service Expansion Plan cluster study, customers
submitted 153 separate transmission service requests totaling 11,831
MW of transmission capacity. BPA was able to offer service (without
requiring detailed studies and transmission upgrades) to only 275
MWs of those service requests.'' (citing BPA, TSR Study and
Expansion Process, at 12 (Dec. 2021), https://www.bpa.gov/-/media/Aep/transmission/atc-methodology/2021-22tsep-overview.pdf.)).
\221\ MISO Initial Comments at 54 (``In addition, a return to
load growth driven primarily by the electrification of
transportation, space heating and water heating is creating a load
profile that has a higher load factor and is more challenging to
serve.''). Load factor refers to ``[t]he ratio of the average load
to peak load during a specified time interval.'' U.S. Energy Info.
Admin. (EIA), Glossary (last visited Mar. 2024), https://www.eia.gov/tools/glossary/index.php?id=L.
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96. Third, supply is changing. As the NOPR explained, Federal,
state, and local policies are incentivizing various forms of generation
resources and other technologies,\222\ resulting in changes to the
Nation's resource mix. The comments in this record show that these
policies are widespread and now span
[[Page 49300]]
many regions of the country. States and cities in the Northeast,\223\
Mid-Atlantic,\224\ Midwest,\225\ West,\226\ and Southeast \227\ have
adopted binding state laws requiring emissions reductions. Moreover,
with the passage of the Inflation Reduction Act in 2022, Congress has
enacted legislation that will further spur investment nationwide in
renewable and non-emitting resources.\228\
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\222\ NOPR, 179 FERC ] 61,028 at P 45.
\223\ National Grid Initial Comments at 6-7 (explaining how all
six states in New England have renewable energy standards and how
ISO-NE's 2050 Transmission Study demonstrates the demands that
meeting those standards will place on New England's transmission
system); id. at 7 (explaining how the Climate Leadership and
Community Protection Act enacted in New York State requires 70%
renewable generation by 2030, zero-emissions by 2040, and 85%
economy-wide emissions reductions by 2050, and that transmission
infrastructure will be critical in meeting those goals); NESCOE
Initial Comments at 15 (``Achieving a decarbonized system is
required by laws and mandates in Connecticut, Maine, Massachusetts,
Rhode Island, and Vermont.'').
\224\ DC and MD Offices of People's Counsel Initial Comments at
18 (noting that ``both Maryland and the District have adopted
ambitious jurisdiction-wide decarbonization policies applicable to
the [electric distribution companies] regulated by their respective
public service commissions.'').
\225\ Illinois Commission Initial Comments at 5 (explaining that
``[i]n Illinois, the Climate and Equitable Jobs Act of 2021 . . .
will affect the future resource mix and demand and lead to
decarbonization and electrification. For example, [it] requires
Illinois to completely transition to clean energy by 2050 and
facilitates electrification through the promotion of electric
vehicles.'').
\226\ Renewable Northwest Initial Comments at 6 (explaining
that, ``[c]urrently, 80 percent of NorthernGrid's load is subject to
state clean energy laws, and by 2040 NorthernGrid will have 65
percent carbon-free energy.''); id. at 21 (explaining that
Washington state's ``SB 5974 sets a goal of all vehicles sold in
2030 and beyond to be [electric vehicles], with that goal becoming a
mandate in 2035[.]'').
\227\ SREA Initial Comments at 25 (noting that North Carolina
has adopted Renewable Energy and Energy Efficiency Portfolio
Standards and enacted the North Carolina Carbon Plan).
\228\ ACORE Initial Comments at 1-2 & n.2 (projecting that
``annual additions increasing from 15 GW of wind and 10 GW of
utility-scale solar PV in 2020 to an average of 39 GW/year of wind
additions in 2025-2026 (~2x the 2020 pace) and 49 GW/year of solar
(~5x the 2020 pace), with solar growth rates increasing
thereafter.'' (citing REPEAT Project, Preliminary Report: The
Climate and Energy Impacts of the Inflation Reduction Act of 2022,
at 15 (2022), https://repeatproject.org/docs/REPEAT_IRA_Prelminary_Report_2022-08-12.pdf)); CARE Coalition
Initial Comments at 17 (``Analysis suggests that the [Inflation
Reduction Act] could more than triple clean energy production in the
U.S. and lead to $600 billion in capital investment in clean energy
infrastructure.'' (citing American Clean Power Ass'n, It's a Big
Deal for Job Growth and for a Clean Energy Future (2022), https://cleanpower.org/blog/its-a-big-deal-for-job-growth-and-for-a-clean-energy-future)); Evergreen Action Initial Comments at 3-4
(discussing model showing that clean energy could comprise up to 81%
of all U.S. generation as a result of increased incentives in the
Inflation Reduction Act (citing John Larsen et al., Rhodium Group, A
Turning Point for US Climate Progress: Assessing the Climate and
Clean Energy Provisions in the Inflation Reduction Act (2022),
https://rhg.com/research/climate-clean-energy-inflation-reduction-act)); NextEra Reply Comments at 5 (``The signing of the Inflation
Reduction Act of 2022 . . . will only increase the demand for
renewables in the coming years and accelerate corresponding demands
on the transmission system.'').
---------------------------------------------------------------------------
97. Customers are also driving changes in the resource mix. In
addition to increasing their aggregate demand for electricity, the NOPR
explained that customers, including major corporations, in many regions
are increasingly demanding that load be served by renewable or non-
emitting resources.\229\ Substantial evidence in the record supports
the existence of this trend. Since 2014, for example, ``commercial and
industrial customers have contracted for more than 52 GW of clean
energy[.]'' \230\ Furthermore, this trend is accelerating. In 2021
alone, energy customers voluntarily contracted for ``11.06 GW of clean
energy.'' \231\ The record demonstrates that, going forward, this shift
is projected to continue, as forecasts show that Fortune 1000 companies
will have up to 85 GW of new demand for renewable energy to meet their
public sustainability commitments for 2030.\232\ As also noted in the
NOPR, utilities in many regions have made commitments to procure most
or all of their electricity from renewable or non-emitting resources.
For example, Exelon,\233\ Dominion,\234\ AEP,\235\ and Southern \236\
have all committed to achieve net-zero emissions by 2050, and each has
set an interim goal to significantly reduce emissions by 2030. And,
although utility commitments vary by utility and by region, the record
shows that many utilities have announced some future emissions
target.\237\
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\229\ NOPR, 179 FERC ] 61,028 at P 45.
\230\ Advanced Energy Buyers Initial Comments at 5 (citing Clean
Energy Buyers Alliance, State of the Market 2022, https://cebuyers.org/state-of-the-market/).
\231\ Clean Energy Buyers Initial Comments at 7.
\232\ Clean Energy Buyers Initial Comments at 7 n.13 (citing
Clean Energy Buyers ANOPR Initial Comments at 21-22).
\233\ Exelon Initial Comments at 2 (``Exelon has established
ambitious targets and aims to be a leader in clean energy by
continuing to reduce its own greenhouse gas emissions, including
reducing operations-driven emissions 50 percent by 2030, relative to
a 2015 baseline, and achieving net-zero operations by 2050.''
(citing Calvin Butler, Exelon Corporation, We're on the Path to
Clean (Apr. 2021), https://www.exeloncorp.com/grid/were-on-the-path-to-clean)).
\234\ Dominion Initial Comments at 3-4 (``Dominion Energy has
committed to achieve net zero greenhouse gas emissions by 2050 and
is investing in clean energy resources such as solar and wind.'').
\235\ AEP Initial Comments at 4 n.12 (``AEP's goal is to reduce
carbon emissions from directly owned generation by 80% by 2030
compared to 2000 levels and to achieve net-zero emissions by 2050.''
(citing AEP, 2022 Corporate Sustainability Report, at 48 (2022),
https://www.aep.com/news/releases/read/8520/AEP-Releases-2022-Corporate-Sustainability-Report)).
\236\ Southern Initial Comments at 14 (``By 2019, Southern
Companies had already achieved a 44% reduction in greenhouse gas
emissions in pursuit of its goals of a 50% reduction by 2030 and net
zero by 2050.'').
\237\ See, e.g., SREA Initial Comments at 41-42 (``Major
utilities in the South, including Entergy, Dominion Energy, Duke
Energy, NextEra, Tennessee Valley Authority, and Southern Company
have all announced some version of a net zero carbon emission plan
or commitment.'').
---------------------------------------------------------------------------
98. Furthermore, as noted in the NOPR,\238\ the resource mix is
also being affected by the changing economics of the resources that
comprise the resource mix.\239\
---------------------------------------------------------------------------
\238\ NOPR, 179 FERC ] 61,028 at P 45 & n.72 (noting the average
levelized cost of wind energy for commercial wind generation has
decreased from $90 per MWh in 2009, to $35 per MWh in 2019 (citing
Lawrence Berkeley National Laboratory, Wind Energy Technology Date
Update: 2020 Edition, at 66 (Nov. 2020))); id. (noting that the
average levelized power purchase agreement price for utility-scale
solar generation has decreased from approximately $160 per MWh in
2009, to approximately $40 MWh in 2020 (citing Lawrence Berkeley
National Laboratory, Utility-Scale Solar Data Update: 2020 Edition,
at 32 (Nov. 2020))).
\239\ See ACORE ANOPR Initial Comments at app. 1, p. 22 (ACEG
Jan. 2021 Planning Report) (``Wind and solar energy costs have
fallen 70 and 89 percent, respectively, in the last ten years, from
2009 through 2019.''); Dominion Initial Comments at 19 (noting how,
during the 2010s, the fracking revolution and advanced technology
for natural gas combined cycle generation lead to a shift away from
coal and nuclear as ``baseload'' fuels and how, today, renewable
energy resources are likewise undergoing a similar expansion);
Evergreen Action Initial Comments at 3 (``Rapid innovation has made
wind and solar power the lowest-cost resource in many areas of the
country[.]'' (citing Univ. of Tex. at Austin Energy Inst., Levelized
Cost of Electricity in the United States by County (2022), http://calculators.energy.utexas.edu/lcoe_map/#/county/tech); see also
ACORE Reply Comments at 2 (``In all scenarios, building transmission
that enables low-cost wind and other energy resources is often
cheaper than the alternatives, such as use of higher-cost but local
resources (and potentially additional storage).'' (citing Paul
Denholm, et al., National Renewable Energy Laboratory, Examining
Supply-Side Options to Achieve 100% Clean Electricity by 2035, at
47-78 (Sept. 2022))).
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99. Together, trends in economics, growing demand, and Federal,
federally-recognized Tribal, state, and local policies are already
resulting in significant changes in the resource mix. The record shows
that as of 2021, nearly 70% of capacity additions across the country
were from new, utility-scale wind and solar resources.\240\ Meanwhile,
most of the capacity retirements are, and are projected to continue to
be, coal resources.\241\ Based
[[Page 49301]]
on the record, those trends are projected to continue, with over 1,300
GW of wind, solar, and storage resources in interconnection queues
across the country as of 2021.\242\ With the passage of the Inflation
Reduction Act in 2022, many analysts are predicting that the shift
toward renewable resources will accelerate.\243\
---------------------------------------------------------------------------
\240\ SREA Initial Comments at 1-2 (citing US Energy Info.
Admin., Today in Energy (2021), https://www.eia.gov/todayinenergy/detail.php?id=46416#); see also AEE Initial Comments at 13 (noting
that between 2011 and 2021, ``renewable generation nearly doubled,
from 12.5% to more than 20%.'').
\241\ AEE Initial Comments at 12-13 (``From 2011 to 2021, the
proportion of U.S. electricity generated by coal plants dropped by
almost half, from 42% to under 22%'' (citing U.S. Energy Info.
Admin., U.S. Electricity Generation by Major Energy Source, 1950-
2021 (2022), https://www.eia.gov/energyexplained//electricity/charts/generation-major-source.csv)); California Commission Initial
Comments at 65 (citing FERC, State of the Markets 2020 (Mar. 2021);
Renewable Northwest Initial Comments at 36 (using IRP data to show
that utilities in NorthernGrid plan to retire 6,573 MW of coal,
1,476 MW of natural gas, 10 MW of wind, and 18 MW of solar, by
2040). FERC's State of the Markets 2020 report stated that 9.6 GW of
coal capacity retired in 2020, which had a noticeable effect on
coal's operating capacity share in most RTOs/ISOs. FERC, State of
the Markets 2020, at 10, 12 (Mar. 2021). FERC's State of the Markets
2023 indicates that this trend is continuing, with coal generation
declining 18.8% in 2023. FERC, State of the Markets 2023, at 4 (Mar.
2024). See also US DOE Initial Comments at App. B, pp. 8-9 (Rand et
al., Lawrence Berkeley National Laboratory, Queued Up:
Characteristics of Power Plants Seeking Transmission Interconnection
as of the End of 2021 (Apr. 2021)).
\242\ See US DOE Initial Comments app. B, at p. 26 (Lawrence
Berkeley National Laboratory, Queued Up: Characteristics of Power
Plants Seeking Transmission Interconnection As of the End of 2021
(Apr. 2022)) (noting that 676 GW of solar, 246 GW of wind, 213 GW of
standalone battery capacity, and ~208 GW of hybrid battery capacity
wait in interconnection queues across the U.S.). On the other hand,
the number of coal and, relatedly, natural gas resources waiting to
interconnect is limited. See id.; Colorado Consumer Advocates
Initial Comments attach. 7, at p. 21 (``No new coal plants have been
built for domestic utility electricity production since 2014[.]'');
NESCOE Initial Comments at 15-16 (noting that new natural gas
generation represented nearly 48% of the queue in 2017, but just 3%
by March of 2022). Moreover, the updated version of the report to
which US DOE cites indicates that the capacity of wind, solar, and
storage in interconnection queues is still increasing. Lawrence
Berkeley National Laboratory, Queued Up: Characteristics of Power
Plants Seeking Transmission Interconnection As of the End of 2022
(Apr. 2023) (noting that 947 GW of solar, 300 GW of wind, 325 GW of
standalone battery capacity, and ~358 GW of hybrid storage capacity,
totaling over 1900 GW, wait in interconnection queues across the
country).
\243\ ACORE Initial Comments at 1-2 & n.2 (``[P]rojecting annual
additions increasing from 15 GW of wind and 10 GW of utility-scale
solar PV in 2020 to an average of 39 GW/year of wind additions in
2025-2026 (~2x the 2020 pace) and 49 GW/year of solar (~5x the 2020
pace), with solar growth rates increasing thereafter.'' (quoting
REPEAT Project, Preliminary Report: The Climate and Energy Impacts
of the Inflation Reduction Act of 2022, at 15 (2022), https://repeatproject.org/docs/REPEAT_IRA_Prelminary_Report_2022-08-12.pdf)).
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100. In light of these changing demands on the transmission system,
the record also affirms what the Commission has long recognized:
regional transmission planning that identifies more efficient or cost-
effective transmission solutions to needs helps to ensure cost-
effective transmission development for customers and can yield better
returns for every dollar spent than localized or piecemeal transmission
solutions.\244\ Conversely, inadequate or poorly designed transmission
planning processes can lead to relatively inefficient or less cost-
effective transmission investment, with customers footing the bill for
piecemeal, inefficient, and less cost-effective transmission solutions
designed to meet short-term or small-scale transmission needs. Given
the magnitude of transmission investment needed to meet customers'
changing needs, it is essential that regional transmission planning be
of sufficient scope and duration to help to ensure customers' money is
well-spent on transmission infrastructure that can efficiently and
cost-effectively meet those needs. Unfortunately, we conclude that this
is not the case today and that existing regional transmission planning
processes are inadequate to address the emerging Long-Term Transmission
Needs that are expected to increasingly drive transmission investment
in the coming decades.
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\244\ Order No. 1000, 136 FERC ] 61,051 at P 55 (``[T]he narrow
focus of current planning requirements and shortcomings of current
cost allocation practices create an environment that fails to
promote the more efficient and cost-effective development of new
transmission facilities.''); id. P 68 (concluding that reforms that
require transmission providers to engage in regional transmission
planning and evaluate proposed alternatives that ``may resolve the
region's needs more efficiently or cost-effectively than solutions
identified in the local transmission plans . . . will provide
assurance that rates for transmission services on these systems will
reflect more efficient or cost-effective solutions for the
region.''); Order No. 890, 118 FERC ] 61,119 at P 524
(``[C]oordination of planning on a regional basis will also increase
efficiency through the coordination of transmission upgrades that
have region-wide benefits, as opposed to pursuing transmission
expansion on a piecemeal basis.''); see also ACORE Initial Comments
at 6 (demonstrating that effective regional transmission planning
could significantly reduce total electric system costs compared to
electric system costs that result from intrastate planning (citing
Brattle-Grid Strategies Oct. 2021 Report at 12)); R Street Initial
Comments at 8 (``[H]olistic transmission planning could improve
economic efficiencies and save billions of dollars . . . . For
example, MISO's 2022 long-range transmission plan results include
$10 billion in transmission projects that support interconnection of
53,000 megawatts of new renewable generation and reduces other costs
by $37-$68 billion. PJM similarly identified $3 billion in
transmission upgrades that would save billions compared to the
current practice of incremental upgrades through the interconnection
process.'' (citing Johannes Pfeifenberger, Brattle Group, Planning
for Generation Interconnection, at 5 (May 31, 2022), https://www.esig.energy/event/special-topic-webinar-interconnection-study-criteria (citation omitted))).
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101. Experience with the implementation of Order No. 1000 over the
last decade has highlighted a critical gap in the Commission's existing
transmission planning and cost allocation requirements. Notwithstanding
the broad recognition that additional transmission infrastructure is
needed to address the drivers noted above, regional transmission
planning processes across the country have yielded only limited
investments in regional transmission projects. As the Commission
observed in the NOPR, investment in regional transmission facilities in
some regions has declined compared to prior to Order No. 1000.\245\
Moreover, across all the non-RTO/ISO regions, there has not yet been a
single transmission facility selected since implementation of Order No.
1000.\246\ The record also demonstrates that within some RTO/ISO
regional transmission planning processes, even where investments
through the regional transmission planning process do occur, much of
that investment has been in transmission projects that only address
immediate reliability needs.\247\ We find that this evidence supports
our conclusion that existing regional transmission planning processes
are not of sufficient scope and duration to adequately or consistently
identify transmission needs and associated opportunities to more
comprehensively evaluate and select more efficient or cost-effective
transmission solutions to those needs.
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\245\ NOPR, 179 FERC ] 61,028 at P 39 (citing ACEG Jan. 2021
Planning Report at 25 & fig. 8); see also ACORE ANOPR Initial
Comments at 4 (``Despite the potential benefits, regional
transmission investment has not increased and in some regions even
has declined over the past decade.'') (citing ACEG Jan. 2021
Planning Report at 25)); State Agencies Initial Comments at 23
(``Regionally planned projects have [ ] declined in RTOs/ISOs . . .
.'' (citing John C. Gravan and Rob Gramlich, NRRI Insights, A New
State-Federal Cooperation Agenda for Regional and Interregional
Transmission, at 2 (Sept. 2021), https://pubs.naruc.org/pub/FF5D0E68-1866-DAAC-99FB-A31B360DC685)).
\246\ NOPR, 179 FERC ] 61,028 at P 39 (citing LS Power ANOPR
Initial Comments App. I at 18 & n.57); FERC, Staff Report, 2017
Transmission Metrics, at 19 (Oct. 6, 2017), https://www.ferc.gov/sites/default/files/2020-05/transmission-investment-metrics.pdf);
see also Western PIOs Initial Comments at 28 (``The Western Regional
Planning Groups, with the exception of the CAISO, have not developed
new projects from their current Order 1000 transmission planning
process.'').
\247\ Southwestern Power Group Initial Comments at 15; PIOs
ANOPR Initial Comments at 93 & n.276; see also Ari Peskoe, Is the
Utility Syndicate Forever?, 42 Energy L.J. 1, 56-57 (2021)
(explaining, for example, that in ISO-NE, all but one of the
transmission projects approved through the regional transmission
planning process were immediate-need reliability projects).
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102. Indeed, in the limited instances in which transmission
providers have followed processes that share many of the elements of
the long-term, forward-looking, and more comprehensive regional
transmission planning this
[[Page 49302]]
order requires, customers have seen clear and quantifiable benefits.
For example, as the Commission observed in the NOPR,\248\ MISO's Multi-
Value Project (MVP) transmission planning process proactively planned
over a 20-year period for two key drivers of transmission needs: the
impacts of changing state laws on the resource mix, and a large
increase in the number of generator interconnection requests. To
mitigate the uncertainties associated with such long-term projections
of transmission needs, MISO relied on scenarios to consider a range of
potential future conditions \249\ and disclosed the assumptions and
inputs underlying each scenario.\250\ The MVP process then identified a
portfolio of transmission projects that were projected to provide
multiple kinds of reliability and economic benefits under all the
alternate future scenarios studied.\251\ This process resulted in MISO
identifying, evaluating, and selecting transmission facilities that are
estimated to generate $2.20 to $3.40 of benefit per dollar
invested.\252\
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\248\ NOPR, 179 FERC ] 61,028 at PP 30-31 (citing Midcontinent
Indep. Sys. Operator, RGOS: Regional Generation Outlet Study, at 2
(Nov. 2020)).
\249\ Id. P 31 (citing MTEP2017 Review at 26-29).
\250\ Id. (citing MTEP2017 Review at 16).
\251\ Id. (citing MTEP2017 Review at 13).
\252\ Id. P 30 (citing MTEP2017 Review at 4).
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103. The benefits to transmission customers of long-term, forward-
looking, and more comprehensive regional transmission planning, which
we discuss further below, are thus well-documented but realized all too
infrequently under existing regional transmission planning processes.
Relatedly, the record demonstrates that a substantial amount of new
transmission investment is occurring outside of regional transmission
planning processes. Because these other processes--specifically,
generator interconnection processes and local transmission planning
processes--are generally designed to address discrete, shorter-term
needs, and do not comprehensively assess either broader transmission
needs or solutions to those needs, overreliance on those processes can
result in relatively inefficient or less cost-effective transmission
development for customers,\253\ which contributes to rates for
transmission that are unjust and unreasonable.
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\253\ ACORE Initial Comments at 4-5 (citing Brattle-Grid
Strategies Oct. 2021 Report at 3); Clean Energy Associations Initial
Comments at 5 (explaining that proactive, forward-looking
transmission planning processes can reduces costs by nearly half as
compared to incremental and reactive transmission planning
processes); [Oslash]rsted Initial Comments at 5 (explaining that
failure to proactively plan for offshore wind results in suboptimal
transmission development, which can increase costs to ratepayers);
Southeast PIOs Reply Comments at 2 (explaining that in the
Southeast, ``snowballing inefficiencies created by numerous small-
scale transmission band-aids, unfit to address broader generation
trends, translate into excessive, unjust, and unreasonable rates
borne by an already overburdened populace.'').
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104. The record demonstrates that significant expansion of the
transmission system is occurring through one-off, piecemeal,
interconnection-related network upgrades constructed in response to
individual generator interconnection requests.\254\ As the Commission
observed in the NOPR, the evidence shows a sharp growth in both the
total cost of interconnection-related network upgrades and in the cost
of such upgrades relative to generation project costs.\255\ The record
indicates that the average cost of interconnection-related network
upgrades is increasing over time as the transmission system is fully
subscribed and demand for interconnection service outpaces transmission
investment. As highlighted in the NOPR,\256\ in 2020, MISO identified
the need for nearly $2.5 billion in interconnection-related network
upgrades to interconnect just 9.2 GW of generation in MISO South, and
MISO expects to need over $3 billion in interconnection-related network
upgrades for interconnection in MISO West.\257\ Similarly, SPP
identified the need for $4.6 billion in interconnection-related network
upgrades to interconnect just 10.4 GW of new generation.\258\
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\254\ Pine Gate Initial Comments at 6, 8-10; PIOs Initial
Comments at 9 (noting how most transmission planning is done through
the generator interconnection process or local transmission
planning).
\255\ NOPR, 179 FERC ] 61,028 at P 37.
\256\ Id. PP 37-38.
\257\ ACORE ANOPR Initial Comments at 10 (citing ICF Sept. 2021
Interconnection Report at 2).
\258\ Id. (citing ICF Sept. 2021 Interconnection Report at 3-4).
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105. Record evidence also shows that increases in interconnection
costs are being driven, in many cases, by an expansion in the scope and
complexity of interconnection-related network upgrades.\259\ The
Commission noted in the NOPR, for example, that interconnection-related
network upgrade costs in MISO West went from approximately $300/kW in
2016 to nearly $1,000/kW in 2017.\260\ The trend is evident in other
parts of the country as well.\261\ The costs of interconnection-related
network upgrades are, in many cases, an ever-growing percentage of the
total capital costs of new generation projects. According to one
report, interconnection costs for new renewable resources were less
than 10% of total generation project costs until a few years ago, but
recently these costs have risen to as much as 50%-100% of the total
generation project costs.\262\ At the
[[Page 49303]]
same time, interconnection-related network upgrades have frequently
transitioned from primarily small transmission facilities that serve
the needs of a limited number of interconnection customers to the size
and scope of what have traditionally been considered high voltage
transmission facilities. For example, interconnection-related network
upgrades have recently included demolishing and rebuilding multiple 500
kV transmission lines \263\ and constructing long, double-circuit, 765
kV transmission lines,\264\ all at significant cost to the
interconnection customer initially--and ultimately to consumers.
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\259\ See, e.g., US DOE Initial Comments at 8 & n.20 (citing Jay
Caspary et al., ACEG, Disconnected: The Need for a New Generator
Interconnection Policy, at 13-16 (2021), https://cleanenergygrid.org/wp-content/uploads/2021/01/Disconnected-The-Need-for-a-New-Generator-Interconnection-Policy-1.pdf) (ACEG 2021
Interconnection Report); Will Gorman et al., Improving estimates of
transmission capital costs for utility-scale wind and solar projects
to inform renewable energy policy, 135 Energy Policy 110994 (2019),
https://www.sciencedirect.com/science/article/pii/S0301421519305816)); ACEG 2021 Interconnection Report at 13 (``[T]he
costs for integrating new resources in MISO are rising substantially
relative to previous years, indicating that the large-scale network
has reached its capacity and needs to expand to connect more
generation. In other words, much more than `driveway' type
facilities are need; larger roads and highways are required to
alleviate the traffic . . . . [H]istorically, interconnecting wind
projects have incurred interconnection costs of $0.85 per megawatt
hour (MWh) or $66 per kilowatt (kW). However, newly proposed wind
projects now face interconnection costs that are nearly five times
higher, at $4.05/MWh or $317/kW.''); id. at 14 (``New solar projects
in MISO South have much higher upgrade costs. The most recent 2019
system impact study for solar projects in MISO South estimated
upgrade costs to total $307/kW, with upgrade costs for individual
interconnection requests as high as $677/kW.''); id. (``The same
trend of rising network upgrade cost assignments is occurring in
PJM. Historically, the levelized costs for constructed wind and
solar projects were $0.25/MWh and $1.72/MWh, respectively, or $19.07
kW and $61.83/kW, respectively . . . costs for newly proposed wind
and solar projects, however, have now risen to $0.69/MWh and $3.66/
MWh, respectively or $0.54/kW and $131.90/kW, respectively--more
than a 100 percent increase.'').
\260\ NOPR, 179 FERC ] 61,028 at P 38 (citing ACEG Jan. 2021
Interconnection Report at 14; NextEra ANOPR Initial Comments at 16
(citing Midcontinent Indep. Sys. Operator, MISO 2020 Queue Outlook,
at 9 (2020), https://cdn.misoenergy.org/MISO2020InterconnectionQueueOutlook445829.pdf)).
\261\ NOPR, 179 FERC ] 61,028 at P 38 (showing that, as of 2019,
interconnection costs in PJM for constructed wind and solar projects
were $19.07/kW and 61.83/kW, respectively, as compared to a greater
than 100% increase to $54/kW and $131.90/kW, respectively, for
projects newly proposed today) (citing e.g., ACEG Jan. 2021
Interconnection Report at 14 & tbl.2)); NextEra ANOPR Initial
Comments at 16-17 (stating that interconnection-related network
upgrade cost estimates have nearly tripled for newly proposed wind
projects, and more than doubled for solar projects in PJM); see also
ACEG Jan. 2021 Interconnection Report at 16 (illustrating an
increase in average interconnection-related network upgrade costs in
NYISO from $67/kW in 2013 to $124/kW in 2019). Compare ACEG Jan.
2021 Interconnection Report at 15 (identifying interconnection-
related network upgrade costs in 2013 in SPP as $89/kW), with ICF
Sept. 2021 Interconnection Report at 2 (citing interconnection-
related network upgrade costs of $448/kW for interconnection
customers studied in SPP's system impact study published in April
2021)).
\262\ NOPR, 179 FERC ] 61,028 at P 38 (citing ACEG Jan. 2021
Interconnection Report at 6); id. (stating that the rising
interconnection costs of wind projects in MISO recently reached
approximately 23% of the capital cost of the project) (citing ACEG
Jan. 2021 Interconnection Report at 13)); id. (identifying the
increase in interconnection-related network upgrade costs in SPP
between 2013 and 2017 as representing an increase from around 8% to
over 43% of the capital cost of wind generation (citing ACEG Jan.
2021 Interconnection Report. at 15)); NextEra ANOPR Initial Comments
at 17 (similar)).
\263\ NOPR, 179 FERC ] 61,028 at P 38 (describing
interconnection-related network upgrades for a 120 MW solar plus
storage project in southern Virginia to interconnect to PJM that
cost as much as $12,086/kW (citing ACEG Jan. 2021 Interconnection
Report at 15)).
\264\ NOPR, 179 FERC ] 61,028 at P 38 (describing one
interconnection-related network upgrade in SPP identified in the
system impact study published in April 2021) (citing ACEG Jan. 2021
Interconnection Report at 15)); ICF Sept. 2021 Interconnection
Report at 3 (same); NextEra ANOPR Initial Comments at 17 (same). In
2017, for example, SPP included a 165-mile, $1.34 billion double
circuit 765 kV line in its Definitive Interconnection System Impact
Study. See ACORE ANOPR Initial Comments Ex. 5, ICF Sept. 2021
Interconnection Report at 4.
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106. Unlike regional transmission planning processes, however, the
generator interconnection process is not designed to consider how to
address transmission needs more efficiently or cost-effectively beyond
the discrete interconnection request (or requests) being studied.
Therefore, the generator interconnection process does not look at time
horizons beyond the specific interconnection request(s) being studied,
comprehensively assess any transmission needs beyond those created by
the specific interconnection request(s), or achieve the economies of
scale in transmission investment that long-term, forward-looking, and
more comprehensive regional transmission planning processes can
provide.\265\
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\265\ Anbaric Initial Comments at 5; Clean Energy Associations
Initial Comments at 15 (noting the reactive nature of generator
interconnection processes); Exelon Initial Comments at 5 (explaining
that the ``project-by-project approach of developing
[interconnection-related] network upgrades'' using the generator
interconnection processes will likely not result in efficient or
cost-effective outcomes given the ongoing changes in the resource
mix and demand); Pine Gate Initial Comments at 9 (explaining how
piecemeal approaches to transmission planning, like the generator
interconnection process, result in inefficiently small upgrades
(citing ACEG Jan. 2021 Interconnection Report at 7)); PIOs Initial
Comments at 10; SEIA Initial Comments at 2; Southeast PIOs Initial
Comments at 37 (``The lack of any regular, formal proceeding to
consider Alabama Power's comprehensive facility investment plan is
troubling and ensures that both generation and transmission are
considered on a project-by-project basis. This piecemeal approach to
addressing transmission needs for individual generation resource
decisions will cause sticker-shock every time and an institutional
aversion to broader transmission investment, especially when
transmission benefits are expressly ignored.'').
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107. We acknowledge that the Commission recently issued Order No.
2023, which requires transmission providers to reform their generator
interconnection processes. But while Order No. 2023 aims to improve the
efficient processing of interconnection queues, it does not attempt to
remedy the discrete deficiency addressed in this final order: that
existing regional transmission planning and cost allocation
requirements do not require transmission providers to plan on a
sufficiently long-term, forward-looking, and comprehensive basis.
Instead, Order No. 2023 seeks to ameliorate the fact that existing
generator interconnection procedures and agreements were ``insufficient
to ensure that interconnection customers are able to interconnect to
the transmission system in a reliable, efficient, transparent, and
timely manner[.]'' \266\ The interconnection queue backlogs and delays
that were the Commission's focus in Order No. 2023 have arisen, in
part, due to deficiencies in the existing transmission planning
requirements. But the Commission found issues regarding the
coordination between transmission planning and generator
interconnection processes were beyond the scope of Order No. 2023 and,
therefore, the Commission addressed only interconnection queue
processes rather than also addressing transmission planning
requirements.\267\ Consequently, this final order addresses a root
cause of interconnection backlogs and delays that Order No. 2023 did
not--the failure of transmission providers to plan on a sufficiently
long-term, forward-looking, and comprehensive basis. Accordingly, the
need to reform this deficiency persists despite the Commission's
reforms required by Order No. 2023.
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\266\ Order No. 2023, 184 FERC ] 61,054 at P 36.
\267\ Order No. 2023, 184 FERC ] 61,054 at PP 1741, 1743
(finding that, although ``several commenters argue in favor of
greater coordination between generator interconnection and
transmission planning or identify interconnection as a matter
requiring interregional planning,'' those comments were beyond the
scope of that rulemaking proceeding and noting that ``the Commission
proposed reforms related to coordination between regional
transmission planning and cost allocation and generator
interconnection in'' the docket for this final order).
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108. While some commenters argue that transmission providers do not
rely too heavily on the generator interconnection process to build
transmission facilities,\268\ we find that the record indicates
otherwise. Specifically, as discussed above, the increase in both the
total and average cost of interconnection demonstrates how much
transmission investment is occurring on a one-off, incremental basis
through generator interconnection processes.\269\ The Commission has
consistently and repeatedly found that interconnection-related network
upgrades provide systemwide benefits,\270\ a finding which courts have
upheld.\271\ In turn, we find that increasingly relying on
interconnection customers' interconnection-related network upgrades to
expand the capacity of the transmission system is inefficient and leads
to less cost-effective transmission development than would result from
long-term, forward-looking, and more comprehensive regional
transmission planning, to the detriment of customers.
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\268\ Mississippi Commission Initial Comments at 9; North
Carolina Commission and Staff Initial Comments at 5; Southern
Initial Comments at 38-40.
\269\ New Jersey Commission Initial Comments at 6-7 (noting that
interconnecting 87.1 GW of capacity, which is needed to meet the PJM
states' offshore wind and renewable portfolio standards goals,
through the interconnection queue process alone is projected to cost
$36 billion); US DOE Initial Comments at 8 (citing ACEG 2021
Interconnection Report at 13-16 (2021)).
\270\ See, e.g., Duke Energy Progress, LLC, 181 FERC ] 61,229,
at P 17 (2022) (rejecting Duke's claim that ``its customers reap no
benefits from network upgrades that must be constructed on Duke's
affected system'' because ``Duke's characterization disregards the
existence of any benefits to its customers from the network
upgrades''); ISO New England Inc., 150 FERC ] 61,209, at P 386
(2015) (noting that there ``is a presumption that transmission
system enhancements benefit all members of an integrated
transmission system''); Pac. Gas & Elec. Co., 106 FERC ] 61,144, at
P 22 (2004) (explaining that ``the integrated grid is a single
interconnected system serving and benefitting all transmission
customers''); Pub. Serv. Co. of Colo., 62 FERC ] 61,013, at 61,061
(1993) (``The Commission has reasoned that, even if a customer can
be said to have caused the addition of a grid facility, the addition
represents a system expansion used by and benefitting all users due
to the integrated nature of the grid.'' (emphasis in original)).
\271\ See, e.g., Nat'l. Ass'n of Regul. Util. Comm'rs v. FERC,
475 F.3d 1277, 1285 (D.C. Cir. 2007) (``We have endorsed the
approach of `assign[ing] the costs of system-wide benefits to all
customers on an integrated transmission grid.''); W. Mass. Elec. Co.
v. FERC, 165 F.3d 922, 927 (D.C. Cir. 1999) (``When a system is
integrated, any system enhancements are presumed to benefit the
entire system.''); City of Holyoke Gas & Elec. Dep't v. FERC, 954
F.2d 740, 742-43 (D.C. Cir. 1992); Me. Pub. Serv. Co. v. FERC, 964
F.2d 5, 8-9 (D.C. Cir. 1992).
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109. Separately, the record here also substantiates the NOPR's
preliminary
[[Page 49304]]
finding that the majority of investment in transmission facilities
since the issuance of Order No. 1000 has been in local transmission
facilities.\272\ Commenters explain that, in RTO/ISO regions, one half
of the nearly $70 billion in aggregate transmission investments by
Commission-jurisdictional transmission providers between 2013 and 2017
was approved outside of regional transmission planning processes.\273\
This investment trend is continuing and accelerating. For example, in
2019, PJM approved 383 transmission-owner planned supplemental projects
at a total cost of $3.75 billion, compared to only 80 regionally
planned baseline projects at a total cost of $1.27 billion. Then, in
2020, PJM approved 236 supplemental projects at a total cost of $4.7
billion, compared to only 43 regionally planned baseline projects at a
total cost of $413 million.\274\ In MISO, baseline reliability projects
and other local transmission projects have grown dramatically since
2010 and constituted 100% of approved transmission between 2018 and
2020 and 80% since 2010.\275\ From 2019 to 2021, 63% of transmission
investment by the three largest transmission owners in CAISO was in
local transmission projects, and Pacific Gas and Electric forecasts
that of the $13 billion it will spend on capital additions between 2022
and 2027, approximately 84% will be on local transmission
projects.\276\ In ISO-NE, spending on in-kind transmission
replacements, which are not part of the regional transmission planning
process, has been significant. Between 2016 and 2022, over $2.5 billion
has been spent on in-kind replacement projects that have entered
service and, as of 2022, an additional $3.122 billion of in-kind
replacement projects had been proposed, planned, or were under
construction.\277\
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\272\ NOPR, 179 FERC ] 61,028 at PP 39-40.
\273\ PIOs Initial Comments at 9.
\274\ PIOs ANOPR Initial Comments at 31-44; see also Ohio
Consumers Initial Comments at 5 (``Since 2017, in Ohio, less than
25% of the new investment in transmission has been associated with
large regional transmission projects needed for reliability or
economic efficiency.'').
\275\ See PIOs Initial Comments at 10 n.31 (citing PIOs ANOPR
Initial Comments at 49 (citing Brattle-Grid Strategies Oct. 2021
Report at iii, 2)).
\276\ See California Commission Initial Comments at 109-110.
\277\ NESCOE Reply Comments at 6.
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110. As with the growing reliance on the generator interconnection
process to identify needed transmission system improvements, local
transmission planning, with its focus on the needs of individual
utility footprints, does not necessarily provide sufficient,
comprehensive analysis of broader regional transmission needs.
Similarly, local transmission planning processes and in-kind
replacement processes do not generally assess transmission needs based
on a forward-looking multi-scenario assessment that more
comprehensively accounts for the benefits of transmission
infrastructure.\278\ Therefore, transmission expansion in this
incremental manner also misses the potential for transmission providers
to identify, evaluate, and select more efficient or cost-effective
transmission facilities to solve transmission needs, as well as to
afford system-wide benefits that may not be achieved through piecemeal,
one-off local transmission facilities. As stated above, the result is
relatively inefficient or less cost-effective transmission development
for customers, which contributes to rates for transmission that are
unjust and unreasonable.
---------------------------------------------------------------------------
\278\ PIOs ANOPR Initial Comments at 33-34 (citing ACEG Jan.
2021 Planning Report); ACEG Jan. 2021 Planning Report at 98-99.
---------------------------------------------------------------------------
111. To be clear, our findings here are not intended to call into
question the justness and reasonableness of either generator
interconnection processes or local transmission planning processes,
which each serve important roles in ensuring reliability and
integrating new resources onto the transmission system.\279\ Rather,
the trends regarding use of these processes, as well as in-kind
replacement processes, provide additional evidence to support our
finding that existing regional transmission planning and cost
allocation requirements are inadequate without reform. As discussed
further in the next section, we conclude that the record regarding the
current and projected transmission landscape--including the investment
trends and changing drivers of that investment detailed above--
highlights critical deficiencies in the Commission's current regional
transmission planning and cost allocation requirements. In this final
order, we address those deficiencies to help to ensure that customers
receive the benefits of long-term, forward-looking, and more
comprehensive regional transmission planning.
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\279\ As discussed below, we separately find that specific
existing requirements governing transparency in local transmission
planning processes and coordination between local and regional
transmission planning processes are unjust, unreasonable, and unduly
discriminatory or preferential. See infra Local Transmission
Planning Inputs in the Regional Transmission Planning Process
section.
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2. Unjust, Unreasonable, and Unduly Discriminatory or Preferential
Commission-Jurisdictional Transmission Planning and Cost Allocation
Processes
112. Based on the record, including comments submitted in response
to the NOPR, as discussed below, we find that there is substantial
evidence to support the determination that sufficiently long-term,
forward-looking, and comprehensive regional transmission planning and
cost allocation to meet Long-Term Transmission Needs is not occurring
on a consistent and sufficient basis. We find that the absence of
sufficiently long-term, forward-looking, and comprehensive regional
transmission planning processes is resulting in piecemeal transmission
expansion to address relatively near-term transmission needs. We find
that the status quo approach results in transmission providers
undertaking investments in relatively inefficient or less cost-
effective transmission infrastructure, the costs of which are
ultimately recovered through Commission-jurisdictional rates. This
dynamic results in, among other things, transmission customers paying
more than is necessary or appropriate to meet their transmission needs,
customers forgoing benefits that outweigh their costs, or some
combination thereof, which results in less efficient or cost-effective
transmission investments and, in turn, renders Commission-
jurisdictional regional transmission planning and cost allocation
processes unjust and unreasonable.
113. We therefore adopt, as modified by the discussion herein, the
preliminary findings of the NOPR concerning the need for reform \280\
and, pursuant to FPA section 206, conclude that revisions to the
Commission's regional transmission planning and cost allocation
requirements are necessary to ensure that Commission-jurisdictional
rates, terms, and conditions are just, reasonable, and not unduly
discriminatory or preferential. We find that, as stated in the
NOPR,\281\ absent the reforms instituted by this final order, regional
transmission planning processes will continue to fail to identify,
evaluate, and select regional transmission facilities that can more
efficiently or cost-effectively meet Long-Term Transmission Needs,
requiring customers to pay for relatively inefficient or less cost-
effective transmission development.
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\280\ NOPR, 179 FERC ] 61,028 at PP 28-55.
\281\ NOPR, 179 FERC ] 61,028 at P 33.
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[[Page 49305]]
114. Based on the record, including the comments submitted in
response to the NOPR, we find that there is substantial evidence to
support the conclusion that deficiencies in the Commission's existing
regional transmission planning and cost allocation requirements are
resulting in Commission-jurisdictional rates that are unjust,
unreasonable, and unduly discriminatory or preferential. Specifically,
we find that the Commission's regional transmission planning and cost
allocation requirements fail to require transmission providers to: (1)
perform a sufficiently long-term assessment of transmission needs that
identifies Long-Term Transmission Needs; (2) adequately account on a
forward-looking basis for known determinants of Long-Term Transmission
Needs; and (3) consider the broader set of benefits of regional
transmission facilities planned to meet those Long-Term Transmission
Needs. We find that these deficiencies render Commission-jurisdictional
regional transmission planning and cost allocation processes unjust and
unreasonable because they result in transmission providers failing to
identify Long-Term Transmission Needs, to evaluate and select more
efficient or cost-effective transmission solutions to meet those
transmission needs, and to allocate the costs of transmission
facilities selected to meet those transmission needs in a manner that
is at least roughly commensurate with benefits. Below, we address each
deficiency in turn.
115. The first deficiency is that the Commission's regional
transmission planning and cost allocation requirements fail to require
transmission providers to perform a sufficiently long-term assessment
of transmission needs. This deficiency is present in multiple aspects
of existing regional transmission planning processes, from the degree
to which planning studies that identify transmission needs are
sufficiently forward looking, to whether forward-looking assessments
actually inform the evaluation, selection, and eventual cost allocation
of regional transmission facilities. The record demonstrates that,
under existing regional transmission planning and cost allocation
processes, transmission providers typically identify and plan for
transmission needs using a relatively near-term transmission planning
horizon. Specifically, commenters have noted that most transmission
planning regions do not plan beyond a 10-year transmission planning
horizon. For example, commenters point out that ISO-NE, SERTP, and
NorthernGrid plan using a 10-year transmission planning horizon,\282\
while PJM notes that it plans using two different transmission planning
horizons: a 5-year transmission planning horizon for what it refers to
as its short-term transmission planning process and a 6-to-15-year
transmission planning horizon for what it refers to as its
intermediate-term transmission planning process.\283\ While it is
reasonable and necessary for regional transmission planning and cost
allocation processes to include a near-term study of the transmission
system, the absence of any consistent and sufficient longer-term
assessment of transmission needs prevents transmission providers from
identifying Long-Term Transmission Needs and considering regional
transmission facilities that may be more efficient or cost-effective
solutions to address those needs.\284\
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\282\ Massachusetts Attorney General Initial Comments at 25
(``For example, the Commission's proposal to increase the required
long-term transmission planning horizon to at least 20 years with 3-
year reassessments would double the current long-term planning
horizon for ISO-NE.''); Renewable Northwest Initial Comments at 12
(citing Brattle-Grid Strategies Oct. 2021 Report at 15); Southeast
PIOs Initial Comments at 12 (``The `independent reliability planning
studies . . . start with the combined local transmission plans of
participating utilities,' and the results comprise the ten-year
regional transmission plan.'' (citation omitted)); Western PIOs
Initial Comments at 8-9 (``NorthernGrid conducts transmission
reliability plans on a two-year cycle, with each plan covering a 10-
year time horizon.''); see also ITC Initial Comments at 9 (referring
to the ``broad use of a 10-year planning horizon in the existing
transmission planning processes of many major planning
regions[.]'').
\283\ PJM Initial Comments at 2 n.4.
\284\ See, e.g., MISO ANOPR Reply Comments at 5 (``[G]iven long-
term needs of an evolving system, additional transmission is
necessary to reliably serve customers now and into the future. These
challenges require immediate action and further delay only increases
the risk that system enhancements may not be in place in the
timeframe needed.''); PIOs Initial Comments at 13 (``[A] short-term
outlook under-forecasts longer-term transmission needs, preventing
the development of more cost-effective transmission facilities, and
fails to consider how the needs of the transmission system are
shifting[.]''); US DOE ANOPR Initial Comments at 10 (stating that
failure to plan transmission far enough ahead results in ``adverse
implications for system reliability, resilience, consumers'
electricity rates, and the achievement of clean energy goals.'').
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116. This lack of a longer-term assessment of transmission needs is
particularly problematic for a few reasons. First, shorter-term
transmission planning fails to take advantage of the potential for
efficiencies or economies of scale that regional transmission
facilities can provide by allowing fewer or better designed
transmission facilities to meet multiple transmission needs. For
example, shorter-term transmission planning fails to provide the
opportunity for transmission providers to identify, evaluate, and
select regional transmission facilities that could address multiple
transmission needs over various time horizons.\285\ Moreover, shorter-
term transmission planning fails to create opportunities to ``right
size'' the replacement of aging transmission facilities to address
multiple transmission needs over the longer term.\286\ Second,
constructing large (e.g., high voltage or long distance) transmission
facilities comes with long lead times: planning, permitting, and
building regional transmission facilities can often take more than ten
years.\287\ As an example, the MVP initiative in the MISO region took a
decade to move from approval by the MISO Board of Directors in 2011 to
completion of most of the projects by 2021, and this period of 10 years
does not even account for the significant transmission facility
development efforts that occurred prior to the MISO Board of Directors'
approval.\288\ Finally, the useful life of
[[Page 49306]]
transmission assets generally far exceeds even 20 years, so a 10-year
transmission planning horizon is much too short to capture all of the
benefits that regional transmission facilities can provide.\289\
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\285\ ACORE Initial Comments at 4 (``The narrowly focused
current approaches [to transmission planning] do not identify
opportunities to take advantage of the large economies of scale in
transmission that come from `up-sizing' reliability projects to
capture additional benefits, such as congestion relief, reduced
transmission losses, and facilitating the more cost-effective
interconnection of the renewable and storage resources needed to
meet public policy goals.'' (quoting Brattle-Grid Strategies Oct.
2021 Report at 3)); PIOs ANOPR Initial Comments at 10-11; SEIA ANOPR
Initial Comments at 14.
\286\ ACORE Initial Comments at 4 (``[I]n-kind replacement of
aging existing facilities misses opportunities to better utilize
scarce rights-of-way for upsized projects that can meet multiple
other needs and provide additional benefits, thus driving up costs
and inefficiencies.'' (quoting Brattle-Grid Strategies Oct. 2021
Report at 3)). PJM's long-term assessment of the transmission system
ostensibly uses a 15-year transmission planning horizon, for
example, but does not account for changes to the generation mix
beyond a 5-year period. See Concerned Scientists ANOPR Initial
Comments at 10 & n.11 (``Generation additions are unchanged in the
15-year study period, as the input assumption has no additional
information that would expand the set of generators included in the
forecast.''); PSEG ANOPR Initial Comments at 11 (stating that ``in
practice only new resources that are near the end of the
interconnection queue process and have signed an Interconnection
Service Agreement are considered in the RTEP base case.'').
\287\ AEP Initial Comments at 11; Nevada Commission Initial
Comments at 7 n.24 (noting that it took over seven years between the
request to include a transmission line in an Integrated Resource
Plan (IRP) and the in-service date, which did not include the lead
time for developing the underlying application) PIOs Initial
Comments at 14 (``[A] 20-year planning horizon was necessary given
the time needed to site, permit, and construct transmission
facilities or because states have longer-term public policy
goals.''); Renewable Northwest Initial Comments at 5; SEIA Initial
Comments at 6.
\288\ AESL Consulting, A Transmission Success Story: The MISO
MVP Transmission Portfolio, at 39 (2021).
\289\ SEIA Initial Comments at 6; US DOE Initial Comments at 33
(noting that transmission assets can have a useful life of at least
40 years).
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117. Thus, relying solely on shorter-term transmission planning and
studies fails to identify Long-Term Transmission Needs and,
consequently, undervalues or entirely ignores the benefits of
transmission investments to meet those needs. Moreover, the likelihood
that near-term assessments will fail to identify Long-Term Transmission
Needs and more efficient or cost-effective regional transmission
facilities to meet those needs is higher during periods of rapid
change, as the electric sector is now experiencing, during which the
need for transmission infrastructure is expected to grow
considerably.\290\ We find that continuing with the status quo approach
is resulting in transmission providers undertaking investments in
relatively inefficient or less cost-effective transmission
infrastructure, the costs of which are ultimately recovered through
Commission-jurisdictional rates.\291\ As a result, among other things,
customers are paying more than necessary or appropriate to meet their
transmission needs, forgoing benefits that outweigh their costs, or
some combination thereof, which results in less efficient or cost-
effective transmission investments and, in turn, renders Commission-
jurisdictional regional transmission planning and cost allocation
processes unjust and unreasonable.
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\290\ US DOE ANOPR Initial Comments at 10 (``Relying on
successive small transmission expansion projects to meet foreseeable
long-term needs may lead to the need for expensive retrofits (at
customers' expense) at a later date. Economies of scale and network
economies suggest that an initial larger-scale buildout will often
represent a lower-cost solution.''); Midcontinent Independent System
Operator, MTEP21 Report Addendum: Long Range Transmission Planning
Tranche 1 Portfolio Report, at 6 (July 28, 2022), https://cdn.misoenergy.org/MTEP21%20Addendum-LRTP%20Tranche%201%20Report%20with%20Executive%20Summary625790.pdf
(``While the Tranche 1 Portfolio is the result of MISO's long-range
planning process being executed for only the second time, the rapid
change within the industry will require that it become a more
routine aspect of the MISO planning process going forward.'').
\291\ See, e.g., S.C. Pub. Serv. Auth., 762 F.3d at 56-59
(explaining that transmission planning processes are practices
affecting rates pursuant to Section 206 of the FPA).
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118. The second deficiency is that the Commission's existing
regional transmission planning and cost allocation requirements fail to
require transmission providers to account adequately on a forward-
looking basis for known determinants of Long-Term Transmission Needs.
This deficiency is related to the first deficiency in the sense that
both relate to the failure of the existing transmission planning
requirements to require transmission providers to adequately plan for
the foreseeable future. We find that, even following Order Nos. 890 and
1000, transmission providers have adopted widely divergent approaches
to determining the factors that are relevant to identifying
transmission needs within regional transmission planning.\292\
Specifically, as commenters note, some existing regional transmission
planning processes ignore trends in future generation and the impact of
extreme weather.\293\ Other commenters note that certain regional
transmission planning processes ignore state laws or utility
goals.\294\ In addition to failing to adequately account for factors
that shape the resource mix, commenters also assert that current
regional transmission planning processes fail to account for factors
that will shape future load, particularly new loads associated with
electrification trends like, for example, electric vehicles \295\ and
data centers.\296\ Although transmission providers in some transmission
planning regions account for a wider range of the factors that drive
Long-Term Transmission Needs when performing regional transmission
planning studies than do others,\297\ we find that transmission
providers are not consistently or sufficiently accounting on a forward-
looking basis for the known determinants of Long-Term Transmission
Needs or accounting for such known determinants in a manner that
ensures the identification and evaluation of more efficient or cost-
effective regional transmission facilities to meet Long-Term
Transmission Needs.
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\292\ ELCON Initial Comments at 3 (``While regional differences
are important to consider, too much flexibility was provided to
transmission providers in Order No. 1000 that . . . created a
patchwork of planning processes further complicating planning and
fostering additional balkanization of the grid[.]''); NOPR, 179 FERC
] 61,028 at P 50.
\293\ GridLab Initial Comments at 4-5 (noting that SPP does not
consider extreme weather events in its transmission plan); Grid
Strategies July 2021 Extreme Weather Report at 5 (``[T]ransmission's
value for making the grid more resilient against severe weather and
other unexpected threats is not typically accounted for in
transmission planning and cost allocation analyses. Grid operator
transmission planning processes typically assume normal electricity
supply and demand patterns, and in most cases do not account for the
value of transmission for increasing resilience.''); Renewable
Northwest Initial Comments at 4, 8 (explaining that regional
transmission planning in the Pacific Northwest does not model
extreme weather events and generally does not reflect publicly
available data such as utility IRPs or carbon reduction goals); see
also Brattle-Grid Strategies Oct. 2021 Report at 36 (stating that
production cost simulations that are typically used to estimate the
economic benefit of regional transmission facilities assume no
extreme weather events); SPP Market Monitor ANOPR Initial Comments
at 3 & n.5 (describing that even SPP's more forward-looking scenario
analysis of an emerging technology case in its Integrated
Transmission Plan presently underestimates the actual growth of
renewables so much that ``[w]ind capacity in service today (29.8 GW)
already exceeds wind levels projected in both 2019 ITP futures that
go out to 2029'').
\294\ Acadia Center and CLF Initial Comments at 1 (``Order No.
1000 has failed to require public utility transmission providers to
align their transmission planning and funding processes with state
policies and objectives.'' (citing Regulatory Assistance Project,
FERC Transmission: The Highest-Yield Reforms, at 4 (July 2022),
https://www.raponline.org/wp-content/uploads/2023/09/rap-littell-prause-weston-FERC-transmission-highest-yield-reforms-2022-july.pdf)); Renewable Northwest Initial Comments at 12 (citing
Brattle-Grid Strategies Oct. 2021 Report at 15, which states that
WestConnect, for example, does not include planning inputs that
extend beyond generic, baseline projects nor ``knowable information
about enacted public policy mandates, publicly stated utility plans,
and/or consumer procurement targets[.]''); SREA Initial Comments at
25 (stating that ``SERTP relies entirely on member utilities to
self-nominate transmission study requests regarding public policy,
meaning if utilities do not provide recommendations or requests, no
SERTP study is completed. For instance, in 2021, SERTP stated,
`[t]he SERTP did not receive any input or proposals for possible
transmission needs driven by Public Policy Requirements for the 2021
planning cycle. Therefore, no possible transmission needs driven by
Public Policy Requirements have been identified for further
evaluation of potential transmission solutions in the 2021 SERTP
planning cycle.' '' (emphasis in original)).
\295\ See, e.g., Clean Energy Buyers Initial Comments at 7-8;
National Grid Initial Comments at 8; see also AEE ANOPR Initial
Comments at 18 (stating that MISO projects electrification effects
on load in its long-term regional transmission planning, but how
other transmission providers account for electrification trends is
not consistent or transparent).
\296\ See supra note 2166; Rocky Mountain Institute Supplemental
Comments at 1 (``Technology companies have begun requesting large
interconnections for data centers that require increased electricity
supply to power generative artificial intelligence.''); WIRES
Supplemental Comments at attach. 1, p. 36 (Rob Gramlich, et al.,
Fostering Collaboration Would Help Build Needed Transmission (Feb.
2024)) (``Load growth is rising in much of the country, and it is
happening in a way that is hard for any single entity to assess on
their own. It varies by local area due to factors such as
manufacturing plant and data center additions, plus expectations for
end-use electrification and penetration of electric vehicles.'').
\297\ See, e.g., Renewable Northwest Initial Comments at 11, 14-
15 (discussing how the MISO transmission planning process accounts
for the future resource mix); Western PIOs Initial Comments at 23-
24, 26-27 (explaining forward-looking aspects of the CAISO
transmission planning process).
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119. We recognize there is inherent uncertainty in
forecasting,\298\ and we
[[Page 49307]]
agree with Industrial Customers that current transmission planning is
based on known and measurable factors.\299\ However, we find, based on
this record, that the universe of known and measurable factors that
drive regional transmission needs extends beyond those that
transmission providers currently consider as part of their regional
transmission planning processes. Specifically, the record demonstrates
that a multitude of factors like reliability needs driven by the impact
of extreme weather, trends in future generation additions and
retirements, load growth, Federal, federally-recognized Tribal, state,
and local laws, and utility goals increasingly shape Long-Term
Transmission Needs, are known and identifiable, and have reasonably
predictable effects, especially in the aggregate.
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\298\ We acknowledge NRG's comment that forecasting is
inherently uncertain. NRG Initial Comments at 10-12. Sufficiently
long-term, forward-looking, and comprehensive regional transmission
planning and cost allocation, however, is better than a lack of
planning. The Commission may, by applying its expertise and
experience to the record, determine what type and amount of
transmission planning results in a just and reasonable rate. S.C.
Pub. Serv. Auth. v. FERC, 762 F.3d at 55 (``[I]n rate-related
matters, the court's review of the Commission's determination is
particularly deferential because such matters are either fairly
technical or `involve policy judgements that lie at the core of the
regulatory mission.' '' (citing Alcoa Inc. v. FERC, 564 F.3d 1342,
1347 (D.C. Cir. 2009))). ``The court owes the Commission `great
deference' in this realm because `[t]he statutory requirement that
rates be `just and reasonable' is obviously incapable of precise
judicial definition' and `the Commission must have considerable
latitude in developing a methodology responsive to its regulatory
challenge[.]' '' Id. (citing Morgan Stanley Cap. Grp. v. Pub. Util.
Dist. No. 1, 554 U.S. 527, 532 (2008); Am. Pub. Gas Ass'n v. FPC,
567 F.2d 1016, 1037 (D.C. Cir. 1977)).
\299\ Industrial Customers Initial Comments at 11.
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120. As noted above, the record shows that the increasing
frequency, duration, and intensity of extreme weather events are
driving changes in Long-Term Transmission Needs to maintain system
reliability.\300\ Additionally, demand growth is a major driver of
Long-Term Transmission Needs, and contrary to commenter
assertions,\301\ the record shows that evolving trends in load growth
due to data centers, electrification, and industrial growth are driving
Long-Term Transmission Needs.\302\ Similarly, state laws, utility
integrated resource plans and resource procurements, and other
regulatory actions necessarily affect Long-Term Transmission Needs for
Commission-jurisdictional transmission services.\303\ Several
commenters also support the broader consideration of anticipated
generation retirements and interconnection requests in regional
transmission planning processes because those factors shape the future
resource mix and, therefore, Long-Term Transmission Needs.\304\
Relatedly, many commenters highlight the impact of utility goals on the
resource mix because such goals will impact transmission needs.\305\
Yet, as described above, existing regional transmission planning
processes frequently undervalue or entirely omit consideration of some
or all of these factors. And while some existing regional transmission
planning processes do a better job than others of incorporating
different components of long-term, forward-looking, and more
comprehensive regional transmission planning, the Commission's existing
regional transmission planning requirements do not ensure that factors
influencing future transmission will be sufficiently accounted for in
that planning.
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\300\ ACEG Initial Comments at 63 (``[T]he need to improve
regional and interregional planning arises from the transformative
changes occurring with respect to resource diversity, energy market
efficiencies, technological changes, operational innovations and
resiliency to withstand severe weather events. If transmission
facilities are not constructed, these are all benefits that would
otherwise be forfeited.''); NERC Initial Comments at 6; Evergreen
Action Initial Comments at 2 (``[A]dditional transmission built
under improved planning procedures would [ ] create large
reliability benefits. With increasing extreme weather events due to
climate change--including wildfires, winter storms, hurricanes, and
more--additional transmission infrastructure and grid improvements
are increasingly necessary for resilience purposes.''); WE ACT
Initial Comments at 2 (``Requiring public utility transmission
providers to consider extreme weather events in Long-Term Regional
Transmission Planning is a positive step towards addressing grid
reliability in the face of more frequent and intensifying weather
events.'').
\301\ See, e.g., Industrial Customers Initial Comments at 8-10
(arguing that demand is growing more slowly than in previous
periods).
\302\ See, e.g., Northwest and Intermountain Initial Comments at
5 n.12 (``For example, Bonneville Power Administration (`BPA') owns
about 75 percent of the transmission lines in the Pacific Northwest.
In BPA's 2022 Transmission Service Expansion Plan cluster study,
customers submitted 153 separate transmission service requests
totaling 11,831 MW of transmission capacity. BPA was able to offer
service (without requiring detailed studies and transmission
upgrades) to only 275 MWs of those service requests.'' (citing BPA,
TSR Study and Expansion Process, at 12 (Dec. 7, 2021), https://www.bpa.gov/-/media/Aep/transmission/atc-methodology/2021-22tsep-overview.pdf.)); John Wilson and Zach Zimmerman, The Era of Flat
Demand is Over, Grid Strategies, at 3, 6 (Dec. 2023), https://gridstrategiesllc.com/wp-content/uploads/2023/12/National-Load-Growth-Report-2023.pdf (noting the 5-year load growth forecast has
nearly doubled from 2.6% to 4.7% and ``transmission investments need
to increase just to keep up with demand'').
\303\ See, e.g., Acadia Center and CLF Initial Comments at 8
(``State laws are . . . essential considerations in planning
transmission . . . as state laws drive substantial procurements of
energy resources along with the concomitant need for additional
transmission, as well as repurposed transmission and non-
transmission grid solutions.''); AEE Initial Comments at 10 (noting
that ``[a]s of September 2020, 38 states and the District of
Columbia had adopted renewable portfolio standards, and 21 states
(plus the District of Columbia and Puerto Rico)--representing more
than half of the U.S. population--include a target of 100% renewable
energy by 2050 or sooner. Many of these requirements have been
enacted in statute and are binding on utilities and retail energy
providers.'').
\304\ See, e.g., Pattern Energy Initial Comments at 26 (``[T]he
generation interconnection queues are indicative of the market and
should also be a major source for generation assumptions in scenario
planning (both near-term and long-term).''); SEIA Initial Comments
at 9.
\305\ See, e.g., Renewable Northwest Initial Comments at 6; SREA
Initial Comments at 41-46 (``The major utility announcements of
achieving net zero or some approximation affects the marketplace,
especially in the [S]outheast.'').
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121. The failure to adequately consider such factors delays
planning for the transmission system's changing operational needs until
shortly before those transmission needs manifest. As a result, existing
transmission planning processes are piecemeal and fail to take
advantage of economies of scale in transmission investment or
opportunities to address multiple transmission needs over multiple time
horizons.\306\ We find that engaging in regional transmission planning
without adequate consideration of such factors leads to transmission
investment that is not more efficient or cost-effective and renders
Commission-jurisdictional regional transmission planning and cost
allocation processes unjust and unreasonable.\307\
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\306\ PIOs Initial Comments at 10-11; Renewable Northwest
Initial Comments at 8 (citing Brattle-Grid Strategies Oct. 2021
Report at iii, iv).
\307\ See, e.g., AEE Initial Comments at 10 (``Failing to take
any of [the Commission-proposed factors] into consideration in
developing long-term scenarios would risk under investment in needed
regional transmission projects to meet transmission needs and
potential[ly] result in unjust and unreasonable rates for
transmission service.''); New Jersey Commission Initial Comments at
3-9 (arguing that ``[e]nsuring just and reasonable rates requires
mandating long-term, multi-value, and portfolio based transmission
planning.'').
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122. Third, the record demonstrates that the Commission's regional
transmission planning and cost allocation requirements fail to require
transmission providers to adequately consider the broader set of
benefits of regional transmission facilities planned to meet Long-Term
Transmission Needs.\308\ For example, commenters note that many
regional transmission planning processes focus too narrowly only on
some benefits.\309\ For instance,
[[Page 49308]]
the Brattle-Grid Strategies Report concludes that ``most of [the
Nation's recent transmission] investment addresses individual local
asset replacement needs, near-term reliability compliance, and
generation-interconnection-related reliability needs without
considering a comprehensive set of multiple regional needs and system-
wide benefits.'' \310\ As PIOs argue, the Commission's existing
regional transmission planning and cost allocation requirements do not
require that transmission providers assess ``opportunities to benefit
from economies of scale that come from `right-sizing' and strategic,
comprehensive planning of transmission portfolios and projects to
capture additional benefits . . . .'' \311\ Other regional transmission
planning processes fail entirely to consider cost savings associated
with certain transmission facilities.\312\
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\308\ See Order No. 1000, 136 FERC ] 61,051 at P 624 (declining
to prescribe ``a particular definition of `benefits' '').
\309\ Massachusetts Attorney General ANOPR Initial Comments at
22 (``New England's siloed approach to transmission planning
inhibits identification of multi-value solutions.'' As part of ISO-
NE's Boston 2028 Request for Proposals, ``[i]n focusing on cost-
effectively solving reliability needs alone, ISO-NE rejected all but
one of thirty-six proposals. While ISO-NE rejected some of these
proposals for technical reasons, it eliminated several due to cost
considerations alone.''); PIOs Initial Comments at 10 (``[T]he vast
majority of current transmission projects are focused solely either
on network reliability or connecting the next generator in the
interconnection queue and ignore any other potential benefits,
possible economies of scale or other efficiencies that might occur
by considering multiple future needs . . . . [M]ultiple quantifiable
benefits to transmission . . . are being ignored in the transmission
planning process.'').
\310\ Brattle-Grid Strategies Oct. 2021 Report at 2.
\311\ PIOs Initial Comments at 10-11. The benefits cited by PIOs
``include congestion relief, reduced transmission losses, resiliency
to extreme weather events, increased flexibility to respond to
changing market or system conditions, and facilitating larger
regional or interregional solutions for cost effective
interconnection of the renewable and storage resources needed to
meet public policy goals.'' Id. at 11.
\312\ SREA Initial Comments at 24 (``SERTP participants
explained that SERTP is unable to conduct adjusted production cost
savings, because none of the utilities involved in SERTP have the
software capable of doing so. In effect, the `Economic Planning
Studies' only evaluate the costs of potential upgrades to the
system, but none of the benefits.'').
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123. Based on the record, we find that, as with the universe of
known and measurable factors driving transmission needs, the benefits
that regional transmission facilities provide extend beyond those
benefits that transmission providers currently consider as part of
their regional transmission planning and cost allocation
processes.\313\ Failing to adequately identify and consider the
benefits of such transmission facilities may lead to relatively
inefficient or less cost-effective transmission development. In
particular, the cost-benefit analyses that transmission providers often
use as part of the evaluation process may fail to identify more
efficient or cost-effective regional transmission facilities for
selection because they provide an inaccurate portrayal of the
comparative benefits of different transmission facilities. Thus, the
failure to adequately consider the benefits of regional transmission
facilities results in, among other things, transmission customers
forgoing benefits that may significantly outweigh their costs, which
results in less efficient or cost-effective transmission investments
and, in turn, contributes to Commission-jurisdictional rates that are
unjust and unreasonable.
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\313\ We disagree with Potomac Economics' arguments that the
sole benefit of transmission is alleviating congestion and that
congestion is primarily an economic issue, so investment in
alleviating congestion should not exceed the benefit of doing so.
See Potomac Economics Initial Comments at 3-4. As discussed infra in
the Evaluation of the Benefits of Regional Transmission Facilities
section alleviating congestion is just one of many potential
benefits that transmission infrastructure provides, and transmission
benefits beyond solving congestion are considered by transmission
providers in regional transmission planning processes today.
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124. Given our findings above concerning the deficiencies in
existing transmission planning requirements, and our conclusion that
long-term, forward-looking, and more comprehensive regional
transmission planning is needed, we also conclude that existing cost
allocation requirements are deficient and must be modified to properly
account for Long-Term Regional Transmission Planning. The Commission
has long recognized the ``close relationship between transmission
planning, which identifies needed transmission facilities, and the
allocation of costs of the transmission facilities in the plan,'' \314\
and that cost allocation issues will often determine whether
transmission providers and customers support the construction of new
facilities.\315\ Furthermore, experience with Order No. 1000 has
reinforced the critical role that states play in the development of new
transmission infrastructure, particularly at the regional level, where
transmission projects may physically span, and their costs may be
allocated across, multiple states. As the Commission discussed in the
NOPR and we continue to find in this final order, facilitating state
regulatory involvement in the cost allocation process could minimize
delays and additional costs associated with state and local siting
proceedings.\316\
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\314\ Order No. 1000, 136 FERC ] 61,051 at P 496.
\315\ Order No. 890, 118 FERC ] 61,119 at P 557; see also Order
No. 1000, 136 FERC ] 61,051 at P 496.
\316\ NOPR, 179 FERC ] 61,028 at P 301; infra Regional
Transmission Cost Allocation section.
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125. Given the link between cost allocation and transmission
planning, it is essential that cost allocation requirements for Long-
Term Regional Transmission Facilities are appropriately tailored to the
new Long-Term Regional Transmission Planning requirements of this
order, particularly given the anticipated long-lead time for any
regional transmission facilities developed and regionally cost
allocated through this final order. Without proper alignment of the
regional transmission planning and cost allocation requirements, it is
less likely that transmission facilities selected in Long-Term Regional
Transmission Planning will be developed, which would undermine the
essential purpose of the regional transmission planning process,
namely, the development of more efficient or cost-effective regional
transmission facilities.
126. We find that the Commission's current cost allocation
requirements, which were designed and established in the context of
existing Order No. 1000 regional transmission planning processes, are
insufficient to appropriately allocate costs associated with regional
transmission facilities that are selected in accordance with the new
Long-Term Regional Transmission Planning requirements that we establish
in this final order. The Commission's existing Order No. 1000 cost
allocation requirements contemplate the application of differing cost
allocation methods to different types of transmission facilities. But
we find that Long-Term Regional Transmission Planning, which accounts
for multiple drivers of Long-Term Transmission Needs and results in
Long-Term Regional Transmission Facilities that produce a broader set
of benefits, warrants a different approach to cost allocation for such
transmission facilities. Likewise, existing Order No. 1000 regional
transmission planning processes do not mandate the consideration of
specific benefits that we believe are appropriately considered as part
of Long-Term Regional Transmission Planning. New information concerning
these benefits uncovered through the transmission planning process may
be relevant when allocating the costs of Long-Term Regional
Transmission Facilities in a manner that is at least roughly
commensurate with their benefits.\317\ Importantly, existing cost
allocation requirements do not provide a dedicated process through
which states have an opportunity to participate in the development of
regional cost allocation methods. We conclude such a role is
particularly relevant to Long-Term Regional Transmission Planning,
given: (1) the lengthy planning horizon over
[[Page 49309]]
which transmission projects might be identified, selected, and
ultimately constructed; (2) the resultant increased uncertainty for
Long-Term Regional Transmission Facilities; and (3) accordingly, the
increased importance for state engagement regarding cost allocation to
increase the likelihood such facilities obtain needed siting approvals
from the states and are thus timely and cost-effectively developed. We
therefore believe that it is both necessary and appropriate to
establish specific cost allocation requirements that are tailored to
the Long-Term Regional Transmission Planning reforms in this final
order.
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\317\ Ill. Commerce Comm'n v. FERC, 576 F.3d 470, 477 (7th Cir.
2009) (ICC v. FERC I); Order No. 1000, 136 FERC ] 61,051 at PP 622,
639 (requiring costs of regional transmission facilities to be
allocated in a manner that is at least roughly commensurate with
estimated benefits).
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127. Based on the record, including comments submitted in response
to the NOPR, we find that there is substantial evidence demonstrating
that Long-Term Regional Transmission Planning and cost allocation to
identify and plan for Long-Term Transmission Needs does not occur on a
consistent and sufficient basis.\318\ We find, in large part, that this
is because of the deficiencies that we have identified above in the
Commission's existing regional transmission planning and cost
allocation requirements. In addition, we find that, in the absence of
sufficiently long-term, forward-looking, and comprehensive regional
transmission planning and cost allocation processes, transmission
providers are meeting many transmission needs by identifying
transmission solutions and developing transmission facilities through
other processes, i.e., outside of the regional transmission planning
and cost allocation processes,\319\ or, as discussed above, in response
to near-term reliability needs,\320\ which may not identify the more-
efficient or cost-effective solution.
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\318\ See New Jersey Commission Initial Comments at 8
(explaining that, outside of limited circumstances, PJM, Florida,
ISO-NE, Southeastern Regional, South Carolina Regional, WestConnect,
NorthernGrid, NYISO, SPP, and CAISO do not conduct multi-driver or
portfolio transmission planning, which has required ratepayers to
pay for tens of billions of dollars in unnecessary transmission
projects); NextEra ANOPR Initial Comments at 71 (``While there are
examples of longer-term planning currently being utilized by some
regions, such as MISO's annual 15-year Futures assessment or SPP's
20-year Integrated Transmission Plan run every five years, there is
no standard as to what time horizon long-term planning must study,
nor how often this planning should be done. Further, no standards or
guidelines exist as to what should be included in such long-term
planning to ensure that customers are charged just and reasonable
rates for the most efficient and cost-effective investments given
the most comprehensive and up-to-date information available.'');
Western PIOs Initial Comments at 4-28 (arguing that in the Western
United States transmission planning outside of CAISO is not
developed and is ineffective); Brattle-Grid Strategies Oct. 2021
Report at 13-15 & tbl. 2 (documenting inconsistent ``use of
proactive, scenario-based, multi-value processes'' across various
planning authorities, including NYISO, CAISO, MISO, PJM, ISO-NE,
Florida, Southeast Regional, and South Carolina'').
\319\ See, e.g., LS Power Initial Comments at 46-50; PIOs
Initial Comments at 9-10 (explaining that about half of the
approximately $70 billion in aggregate transmission investment by
Commission-jurisdictional transmission owners in RTO/ISO regions was
approved outside of regional transmission planning processes).
\320\ Supra note 309.
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128. To reiterate, the fact that transmission facilities are being
identified and built outside of regional transmission planning
processes and in response to near-term reliability needs is not
inherently problematic. In many instances, as some commenters point
out,\321\ those processes may be well equipped to identify necessary
and appropriate transmission solutions. Rather, the problem is that
incremental and piecemeal expansion of the transmission system outside
of regional transmission planning process misses the potential for
transmission providers to identify, evaluate, and select more efficient
or cost-effective transmission solutions to solve Long-Term
Transmission Needs, as well as to afford system-wide benefits that may
not be achieved through one-off transmission system upgrades.\322\ To
the extent that transmission providers may not be identifying and
evaluating the more efficient or cost-effective transmission solutions
needed to meet underlying transmission needs, including Long-Term
Transmission Needs, over time, consumers will bear the costs of
relatively inefficient or less cost-effective piecemeal transmission
investment and expansion.\323\
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\321\ E.g., Duke Initial Comments at 7.
\322\ See, e.g., ACORE Initial Comments at 8 ((``For example,
two solutions to address a particular reliability need may offer
vastly different total system-wide benefits. Thus, the higher-cost
transmission solutions can actually result in significantly lower
net cost from a system-wide perspective.'') (quoting Brattle-Grid
Strategies Oct. 2021 Report at 30)); Clean Energy States Initial
Comments at 2 (``[T]he one-plant-at-a-time approach to transmission
upgrades results in a patchwork approach that drives up costs and
misses opportunities for improvements to the system as a whole.'');
Exelon Initial Comments at 5.
\323\ Michigan State Entities Initial Comments at 1-2
(explaining concerns that the lack of long-term transmission
planning has led to significantly higher residential rates and how
the problem will worsen if transmission investment does not reflect
changes in the resource mix and demand); New Jersey Commission
Initial Comments at 6-7 (noting PJM analysis showing transmission
upgrades to interconnect 87.1 GW of a variety of resources,
including offshore wind, would cost $3.2 billion if done through
holistic transmission planning whereas connecting only 15.4 GW of
offshore wind would cost $6.4 billion if done through the
interconnection queue process, and estimating that the
interconnection of 87.1 GW through the interconnection queue would
increase the cost to consumers by over $30 billion compared to
holistic transmission planning); PIOs Initial Comments at 8 (noting
how deficiencies in the Commission's regional transmission planning
processes have ``led to billions of dollars in excessive costs for
consumers.'' (citing Brattle-Grid Strategies Oct. 2021 Report at 1-
13 (Section 1)).
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129. We find that the concerns arising from the absence of
sufficiently long-term, forward-looking, and comprehensive regional
transmission planning and cost allocation processes and the
corresponding failure by transmission providers to identify and
evaluate more efficient or cost-effective transmission solutions to
Long-Term Transmission Needs are exacerbated by the fact that
transmission needs in most transmission planning regions are
drastically changing. Contrary to the claims of some commenters, we are
not promulgating this order in an attempt to steer the resource mix and
demand \324\ based on a preference for certain resources over
others.\325\ Instead, the Commission is reacting to well-documented
factors, which the record demonstrates are driven by exogenous forces
beyond the Commission's jurisdiction or control, including, but not
limited to, the increasing frequency of extreme weather events,
customer preferences, demand growth, economic and technological trends,
and Federal, federally-recognized Tribal, state, and local
policies.\326\
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\324\ Consumer Organizations Initial Comments at 1-2; ELCON
Initial Comments at 9; SERTP Sponsors Initial Comments at 16-20. But
see SEIA Reply Comments at 2-3 (``The NOPR does make `repeated
references' to the changing resource mix. But that is not because
the NOPR will `promote a transition to a more renewables-heavy
electric system.' The NOPR makes these references because the
resource mix is, in fact, changing. The question before the
Commission is not whether to promote or impede that change, but how
to address the needs of the grid as a result of that inevitable
change.'' (internal quotations omitted)); New Jersey Commission
Reply Comments at 2 (``The Commission is . . . trying to ensure the
electricity system can reliably and efficiently achieve the
generation mix that state policymakers and voluntary consumers--not
the Commission--have chosen. Ensuring that these customers are
served at the lowest possible cost while maintaining reliability is
entirely consistent with and indeed required in order to meet the
dictates of the FPA. In other words, the Commission is acting to
ensure transmission planning processes account for current realities
and meet evolving consumer needs at a total cost that is just and
reasonable.'' (internal citations omitted)).
\325\ See, e.g., Ohio Commission Federal Advocate Initial
Comments at 4-6 (arguing that the Commission's purpose in issuing
the NOPR was to promote an aspirational renewable future and achieve
narrow environmental objectives); Undersigned States Reply Comments
at 7 (arguing that the Commission is forcing ratepayers to subsidize
forms of energy by socializing the cost of a transmission build
out).
\326\ See New Jersey Commission Initial Comments at 3 (``The
Commission is not proposing to unduly favor, mandate, or subsidize
forms of generation but is rather seeking to ensure that the bulk
electricity system maintains reliability and satisfies evolving
consumer demand . . .'').
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[[Page 49310]]
130. In response to commenters, we acknowledge that integrated
resource planning processes, where they exist, shape the resource mix
and can often include forms of proactive transmission planning. As
stated in Order No. 1000, we reiterate that ``the regional transmission
planning process is not the vehicle by which integrated resource
planning is conducted.'' \327\ Indeed, this final order does not aim to
affect--either facilitate or hinder--any changes or decisions that
occur outside of the Commission's jurisdiction. Instead, because
practices directly affecting Commission-jurisdictional rates, terms,
and conditions of service for interstate transmission and wholesale
electricity are the exclusive jurisdiction of the Commission, we must
ensure that Commission-jurisdictional processes associated with
regional transmission planning and cost allocation result in rates that
are just and reasonable and not unduly discriminatory or preferential.
To this end, this final order is focused on ensuring that regional
transmission planning processes are adequately accounting for the
changes occurring outside of the Commission's jurisdiction, including
the resource decisions that are the exclusive jurisdiction of
states.\328\ Additionally, to the extent that integrated resource
planning processes include forms of transmission planning, such
planning can be complementary to Commission-jurisdictional regional
transmission planning processes but cannot take the place of such
processes. This is not to diminish the importance of integrated
resource planning processes, which serve a critical role in shaping the
generation mix and transmission infrastructure. In recognition of this
role, this final order requires transmission providers to consider
integrated resource planning as a factor when conducting Long-Term
Regional Transmission Planning. But, as discussed below, we conclude
that integrated resource planning is appropriately considered as one of
several categories of factors used to develop Long-Term Scenarios and
identify Long-Term Transmission Needs.
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\327\ Order No. 1000, 136 FERC ] 61,051 at P 154.
\328\ See PJM Power Providers Grp. v. FERC, 88 F.4th 250, 275
(3d Cir. 2023) (holding that the Commission is ``unambiguously
authorize[d] . . . to take state policies into account to the extent
that such policies affect [the Commission's] statutorily prescribed
area of focus . . . .''); see also Elec. Power Supply Ass'n v. Star,
904 F.3d 518, 524 (7th Cir. 2018) (approving of the Commission's
decision to take state zero-emissions credit systems like that in
Illinois ``as givens and set out to make the best of the situation
[these systems] produce'').
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131. In response to commenters that argue regional transmission
facilities may not address local transmission needs such that a local
transmission facility would still be needed,\329\ we acknowledge that
regional transmission facilities are not necessarily always a more
efficient or cost-effective solution to address local transmission
needs, and nothing in this final order requires transmission providers
to rely on regional transmission facilities to address exclusively
local transmission needs. Instead, this final order identifies
deficiencies in existing Commission-jurisdictional regional
transmission planning processes that lead transmission providers to
fail to identify Long-Term Transmission Needs and fail to identify,
evaluate, or select more efficient or cost-effective transmission
solutions to meet those transmission needs. As a result of these
deficiencies, transmission providers may undertake relatively
inefficient investments in transmission infrastructure by missing
opportunities to identify regional transmission facilities that bring
economies of scale or address multiple transmission needs over
different time horizons, including local transmission needs.
---------------------------------------------------------------------------
\329\ See, e.g., Duke Initial Comments at 9 (arguing that there
are instances in which larger regional transmission projects may not
resolve localized transmission needs).
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132. We disagree with arguments that the Commission cannot
promulgate this final order because we rely on general findings, rather
than individualized analyses of each, specific transmission planning
region.\330\ Relevant precedent, including regarding the Commission's
comparable action in Order No. 1000, is clear that the Commission has
discretion as to the procedural means through which it will apply its
substantive expertise, and we need not make findings that are region
specific in every case; rather, we are empowered to ``rely on `generic'
or `general' findings of a systemic problem to support imposition of an
industry-wide solution,'' \331\ and we do so here. The fact that
individual transmission planning regions may have different forms of
transmission planning processes, and may experience varying levels of
transmission investment, would be ``as unastonishing as it is
irrelevant.'' \332\ Moreover, although transmission planning practices
vary considerably between transmission planning regions and some
regions may engage in transmission planning that shares many of the
elements of the more long-term, forward-looking, comprehensive regional
transmission planning required in this order, the record demonstrates
that this final order identifies deficiencies that reach well beyond
``isolated pockets[.]'' \333\ Rather, the record demonstrates that
these deficiencies pervade large swaths of the country, which include
RTO/ISO and non-RTO/ISO transmission planning regions.\334\
Accordingly, this final order's remedy does not present an ``extreme
`disproportion of remedy to ailment[.]' '' \335\ The Commission may
reasonably rely on a rulemaking procedure to address the industry-wide
changes to the transmission landscape, notwithstanding regional
variation among regional transmission planning processes. As the
Commission stated in Order No. 1000, ``[i]t is well established that
the choice between rulemaking and case-by-case adjudication `lies
primarily in the informed discretion of the administrative agency.' ''
\336\ The Commission also stated that ``[i]t is within our discretion
to conclude that a generic rulemaking, not case-by-case adjudications,
is the most efficient approach to take to resolve the industry wide
problems facing us.'' \337\ Moreover, we agree with ACEG that pursuing
region-specific solutions will lead to ``siloed and disjunctive
transmission planning policies [that] will not solve the problems
facing the nation's electric grid.'' \338\
---------------------------------------------------------------------------
\330\ See, e.g., Louisiana Commission Reply Comments at 5-6;
NRECA Initial Comments at 14-16.
\331\ S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 67 (quoting
Interstate Nat. Gas v. FERC, 285 F.3d 18, 37 (D.C. Cir. 2002)).
\332\ Id. (quoting Wis. Gas v. FERC, 770 F.2d 1144, 1157 (D.C.
Cir. 1985)).
\333\ Id.
\334\ See, e.g., supra notes 283 and 284 (explaining that ISO-
NE, SERTP, Northern Grid, and PJM undergo transmission planning
using time horizons shorter than 20 years).
\335\ S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 67.
\336\ Order No. 1000, 136 FERC ] 61,051 at P 60.
\337\ Id.
\338\ ACEG Reply Comments at 17.
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133. Furthermore, although not every transmission planning region
is experiencing these changes in equal measure, the record shows that
significant changes are well underway nationwide, and that failing to
adequately account for Long-Term Transmission Needs poses a risk to
just and reasonable rates throughout the country.\339\ In fact, the
record raises a wide range of concerns, and the Commission need not,
and should not, wait for systemic problems to undermine regional
transmission
[[Page 49311]]
planning in every region before it acts.\340\ The record in this
proceeding confirms that significant investments in new transmission
facilities are expected to occur, with substantial impacts on the
Commission-jurisdictional rates that customers pay.\341\ It is
therefore critical, and it is the Commission's responsibility, to act
now to address deficiencies in its regional transmission planning and
cost allocation requirements to ensure that more efficient or cost-
effective transmission investments are made as the industry addresses
the changing landscape.\342\
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\339\ AEE Reply Comments at 3-4.
\340\ See Order No. 1000, 136 FERC ] 61,051 at P 50.
\341\ See supra P 93.
\342\ See Order No. 1000, 136 FERC ] 61,051 at P 46.
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3. Benefits of Long-Term Regional Transmission Planning and Cost
Allocation To Identify and Plan for Long-Term Transmission Needs
134. Upon consideration of the record, we find that the
requirements set forth in this final order will address deficiencies in
the existing regional transmission planning and cost allocation
requirements and will promote enhanced reliability and more efficient
or cost-effective transmission solutions, which will help to ensure
just and reasonable Commission-jurisdictional rates.
135. The record demonstrates that long-term, forward-looking, and
more comprehensive regional transmission planning that identifies Long-
Term Transmission Needs will help transmission providers to identify,
evaluate, and select more efficient or cost-effective transmission
solutions to those needs. For example, like the Commission in the
NOPR,\343\ commenters cite to the success of MISO's Long-Range
Transmission Plan in delivering more efficient or cost-effective
transmission solutions. By addressing public policy, economic, and
reliability transmission planning needs simultaneously through its MVP
category, MISO `` `eliminate[d] the need for $300 million in future
baseline reliability upgrades,' and provided production cost savings
that exceeded the entire cost of the portfolio by $10 billion.'' \344\
Brattle Group and Grid Strategies also found that ``building out
piecemeal network upgrades through the interconnection queue process to
integrate the same amount of generation would have cost over 80% more
than the cost of the MVP portfolio.'' \345\ Similarly, the New Jersey
Commission asserts that, by planning transmission facilities to address
a specific set of known and identified transmission needs through a
holistic portfolio, rather than piecemeal through the generator
interconnection process, PJM could save customers more than $30
billion.\346\
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\343\ See, e.g., NOPR, 179 FERC ] 61,028 at PP 31-32.
\344\ New Jersey Commission Initial Comments at 4 (citing
MTEP2017 Review at 6, 8) (emphasis in original).
\345\ Id. at 4-5 (citing Brattle-Grid Strategies Oct. 2021
Report at 7 & nn.13-14); see id. at 5 n.9 (noting that the cost of
the MVP portfolio divided by the amount of wind capacity it
interconnected came to $412 per kilowatt, while interconnection-
related network upgrades for new generation in MISO planned through
the interconnection queue cost $756 per kilowatt).
\346\ Id. at 6-7 (citing Brattle-Grid Strategies Oct. 2021
Report at 7); id. (explaining that the onshore network upgrades
required to interconnect 87.1 GW of resources meeting all of PJM
states' current offshore wind goals and total renewable portfolio
standards through ``piecemeal interconnection queue projects would
cost nearly $36 billion in total--more than eleven times the $3.2
billion cost of the integrated portfolio approach,'' or ``[p]ut
another way, proactive, portfolio-based planning in PJM could
ultimately save ratepayers over $30 billion compared to the status
quo.'').
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136. We note that the cost-saving results that MISO experienced
were the direct product of more comprehensive, longer-term regional
transmission planning. By expanding the transmission planning horizon
and considering factors affecting Long-Term Transmission Needs, as well
as considering a broader list of benefits, transmission providers will
be able to identify, evaluate, and select more efficient or cost-
effective transmission solutions to address Long-Term Transmission
Needs.\347\ Such Long-Term Regional Transmission Planning will: (1)
reduce reliance on transmission solutions that are relatively
inefficient or less cost-effective because they address only short-term
transmission needs; (2) unlock the benefits of economies of scale in
transmission investment; \348\ (3) enable opportunities to ``right
size'' replacement transmission facilities; \349\ (4) facilitate the
selection of regional transmission facilities that could address
multiple transmission needs over different time horizons; and (5)
provide states, utilities, customers, and other stakeholders with
greater insight and transparency into the costs and benefits of
particular transmission solutions to address Long-Term Transmission
Needs. We conclude that these regional transmission planning and cost
allocation reforms will benefit customers by leading to more efficient
or cost-effective transmission investment, thereby helping to ensure
just and reasonable rates.\350\
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\347\ PIOs Initial Comments at 35.
\348\ Id. at 10 (``[T]he vast majority of current transmission
projects are focused solely either on network reliability or
connecting the next generator in the interconnection queue and
ignore any other potential benefits, possible economies of scale or
other efficiencies that might occur by considering multiple future
needs.'').
\349\ ACEG Initial Comments at 53-56; Clean Energy Associations
Initial Comments at 25-27; SEIA Initial Comments at 25-26.
\350\ See, e.g., Exelon Initial Comments at 5 (``The project-by-
project approach of developing [interconnection-related] network
upgrades in response to generator interconnection requests does not
take into account broader, longer-term planning needs and
furthermore raises questions about whether it will lead to efficient
and cost-effective outcomes as the resource mix rapidly evolves.'');
PIOs Initial Comments at 8 (``[O]verwhelming evidence indicates that
transmission owners are largely able to evade the requirements of
Order No. 1000 and . . . have primarily invested in local projects.
This has led to . . . billions of dollars in excessive costs for
consumers.'' (citing Brattle-Grid Strategies Oct. 2021 Report at
Section 1)); Southeast PIOs Reply Comments at 2 (``All the while,
snowballing inefficiencies created by numerous small-scale
transmission band-aids, unfit to address broader generation trends,
translate into excessive, unjust, and unreasonable rates borne by an
already overburdened populace.'').
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137. In addition to potentially enhancing the efficiency and cost-
effectiveness of transmission investment, we find that sufficiently
long-term, forward-looking, and comprehensive regional transmission
planning and cost allocation processes will enhance reliability. In the
NOPR, the Commission found that a robust, well-planned transmission
system is foundational to ensuring an affordable, reliable supply of
electricity. The record supports this conclusion. Many commenters agree
that, especially in light of continuing changes in both supply and
demand, ongoing investment in regional transmission facilities is
necessary to ensure that the transmission system continues to serve
load in a reliable manner at reasonable cost.\351\ Commenters also
agree that regional transmission investments support enhanced
reliability because larger, more integrated transmission systems are
better equipped to accommodate a diversity of supply and demand
conditions and provide redundancy that allow the system to better
withstand unpredictable and extreme weather events, which are
[[Page 49312]]
occurring with increased frequency and severity.\352\
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\351\ ACORE ANOPR Initial Comments at 21-22 (explaining how
additional transmission investments can alleviate billions of
dollars in costs caused by extreme weather); EEI Initial Comments at
4 (``Transmission plays and will continue to play a vital role in
enabling the energy transition and in ensuring a reliable and
resilient energy grid. A robust transmission system will not only
enable electric utilities to integrate more renewable energy
resources and deliver more clean energy to customers but will also
enhance the reliability and resiliency of the grid and enable the
deployment of new technologies.'' (citing EEI, Planning and
Developing Electric Transmission Projects: The Path to the Grid of
the Future (2022)); NERC Initial Comments at 6 (explaining that
transmission will be key to managing a reliable transformation in
the resource mix).
\352\ NERC Initial Comments at 6 (explaining that regional
transmission planning is necessary to ensure sufficient transmission
capacity to move energy from areas with a surplus to areas that are
deficient).
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138. Moreover, commenters provide examples of how long-term,
forward-looking, and more comprehensive regional transmission planning
can better identify reliability needs and resolve these needs with more
efficient or cost-effective transmission solutions.\353\ For example,
as noted above, MISO's MVP Portfolio 4 eliminated the need for $300
million in future baseline reliability upgrades.\354\ By comparison,
the Reliability Must-Run Agreement for Indian River Unit 4, a 410 MW
coal-fired generation unit, highlights the costs of inadequate regional
transmission planning. As NARUC explains, the Indian River Unit 4 was
scheduled to retire, but PJM found that retirement would cause
reliability issues and would necessitate upgrades to transmission
facilities that, due to their age, were already due to be upgraded, and
that the Reliability Must-Run Agreement was needed because those
upgrades would take five years to complete.\355\ A long-term, forward-
looking, and more comprehensive regional transmission planning process
may have obviated the need for the Reliability Must-Run Agreement, the
individual transmission facility upgrades, or both.
---------------------------------------------------------------------------
\353\ ITC Initial Comments at 44 (``While local transmission
planning continues to serve a critically necessary, valuable
function in maintaining the reliability and efficiency of
transmission systems, it is nonetheless clear that holistic, long
range transmission planning is far more capable of identifying
optimal transmission solutions that serve the most needs and deliver
the most benefits.''); MISO Initial Comments at 88 (explaining that
in its Tranche 1 Long Range Transmission Plan, MISO recognizes
Avoided Transmission Investment benefits provided by Long Range
Transmission Plan facilities in addressing both avoided reliability
projects and avoided age and condition replacement projects with the
results being avoided costs in local transmission that would have
otherwise been incurred to replace existing facilities).
\354\ New Jersey Commission Initial Comments at 4.
\355\ NARUC Initial Comments at 14-15.
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4. Conclusion
139. In consideration of the record provided in this proceeding, as
well as the related conclusions stated above, we find that the
Commission's existing regional transmission planning and cost
allocation requirements are unjust, unreasonable, and unduly
discriminatory or preferential because they fail to require
transmission providers to adequately plan on a sufficiently long-term,
forward-looking, and comprehensive basis. Specifically, as discussed,
we find that the Commission's regional transmission planning and cost
allocation requirements fail to require transmission providers to: (1)
perform a sufficiently long-term assessment of transmission needs that
identifies Long-Term Transmission Needs; (2) adequately account on a
forward-looking basis for known determinants of Long-Term Transmission
Needs; and (3) consider the broader set of benefits of regional
transmission facilities planned to meet those Long-Term Transmission
Needs. We find that reforms to those requirements are thus necessary to
ensure that Commission-jurisdictional rates are just, reasonable, and
not unduly discriminatory or preferential. The failure to plan on a
sufficiently long-term, forward-looking, and comprehensive basis
results in the potential for relatively inefficient or less cost-
effective transmission development for which customers must pay. The
requirements set forth in this final order will help to ensure that
transmission providers plan to address Long-Term Transmission Needs, in
turn helping to ensure more efficient or cost-effective transmission
development and thus just and reasonable Commission-jurisdictional
rates.
III. Long-Term Regional Transmission Planning
A. Requirement To Participate in Long-Term Regional Transmission
Planning
1. NOPR Proposal
140. In the NOPR, the Commission proposed to require each
transmission provider to participate in a regional transmission
planning process that includes Long-Term Regional Transmission
Planning,\356\ meaning regional transmission planning on a sufficiently
long-term, forward-looking, and comprehensive basis to identify
transmission needs driven by changes in the resource mix and demand and
to identify and evaluate transmission facilities for potential
selection as the more efficient or cost-effective transmission
facilities to meet such needs.\357\
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\356\ The two features of Long-Term Regional Transmission
Planning that the Commission included in the proposed reforms were
the development of scenarios with a 20-year transmission planning
horizon to be reassessed and revised every three years, with each
such re-assessment providing the basis for identification and
evaluation of transmission facilities for potential selection. NOPR,
179 FERC ] 61,028 at P 68 n.128.
\357\ See id. PP 54, 64, 68.
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141. The Commission proposed that transmission providers may
continue to rely on their existing regional transmission planning and
cost allocation processes to comply with Order No. 1000's requirements
related to transmission needs driven by reliability concerns or
economic considerations.\358\
---------------------------------------------------------------------------
\358\ Id. P 72.
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142. The Commission proposed that transmission providers that
comply with the Long-Term Regional Transmission Planning requirements
will comply with the requirement in Order No. 1000 that they
participate in a regional transmission planning process that considers,
and has associated cost allocation provisions related to, transmission
needs driven by Public Policy Requirements.\359\ The Commission further
proposed to allow transmission providers to propose to continue using
some or all aspects of the existing regional transmission planning and
cost allocation processes they use to consider transmission needs
driven by Public Policy Requirements.\360\ The Commission stated,
however, that such continued use of existing regional transmission
planning and cost allocation processes would not supplant transmission
providers' obligations to comply with the Long-Term Regional
Transmission Planning requirements established in any final order in
this proceeding. Moreover, the Commission proposed that transmission
providers seeking to retain existing regional transmission planning and
cost allocation processes to consider transmission needs driven by
Public Policy Requirements would have to demonstrate that continued use
of any such processes does not interfere or otherwise undermine the
Long-Term Regional Transmission Planning proposed in the NOPR by
demonstrating that continued use of such processes is consistent with
or superior to any final order issued in this proceeding.\361\
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\359\ Id. P 73.
\360\ Id. P 74.
\361\ Id.
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143. The Commission preliminarily found that transmission providers
could propose a regional transmission planning process that plans for
reliability needs, economic needs, transmission needs driven by Public
Policy Requirements, and transmission needs driven by changes in the
resource mix and demand simultaneously through a combined approach. The
Commission stated that transmission providers proposing to address all
such transmission needs in a single regional transmission planning
process would bear the burden of demonstrating continued compliance
with Order No.
[[Page 49313]]
1000 in addition to compliance with the requirements of any final order
in this proceeding.\362\
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\362\ Id. P 75.
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144. Finally, the Commission proposed to require that Long-Term
Regional Transmission Planning comply with the following existing Order
Nos. 890 and 1000 transmission planning principles: (1) coordination;
(2) openness; (3) transparency; (4) information exchange; (5)
comparability; and (6) dispute resolution.\363\
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\363\ Id. P 76.
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2. Comments
a. General Comments
145. The majority of commenters support the Commission's
proposal,\364\ with multiple commenters claiming that Long-Term
Regional Transmission Planning is crucial to ensure that regional
transmission planning appropriately identifies transmission needs to
meet the changing resource mix and demand.\365\
---------------------------------------------------------------------------
\364\ Acadia Center and CLF Initial Comments at 2; ACEG Initial
Comments at 6, 22-23; ACORE Initial Comments at 2, 17; Advanced
Energy Buyers Initial Comments at 4; AEP Initial Comments at 5-7;
Amazon Initial Comments at 2; BP Initial Comments at 4-7;
Breakthrough Energy Initial Comments at 3; Breakthrough Energy
Supplemental Comments at 1; Business Council for Sustainable Energy
Initial Comments at 2-4; California Energy Commission Initial
Comments at 1; City of New Orleans Council Initial Comments at 4;
City of New York Initial Comments at 1, 3; Clean Energy Associations
Initial Comments at 10; Conservative Energy Network Supplemental
Comments at 1; Conservatives for Clean Energy--Florida Supplemental
Comments at 1; Conservatives for Clean Energy--South Carolina; CTC
Global Initial Comments at 1; US Senators Supplemental Comments at
1-2; EEI Initial Comments at 10; ELCON Initial Comments at 6-7; NERC
Initial Comments at 6-7; ENGIE Initial Comments at 2; Entergy
Initial Comments at 7; Environmental Groups Supplement Comments at
2; Evergreen Action Initial Comments at 3; Eversource Initial
Comments at 2; Exelon Initial Comments at 4-7; Form Energy Initial
Comments at 2-3; Governor of Kansas Laura Kelly Supplemental
Comments at 1; Handy Law Initial Comments at 7-8; US House
Republicans Supplemental Comments at 1; Indicated PJM TOs Initial
Comments at 7-8; Indicated US Senators and Representatives Initial
Comments at 1; Michigan Conservative Energy Forum Supplemental
Comments at 1; ISO-NE Initial Comments at 2, 8; ITC Initial Comments
at 5-9; Joint Consumer Advocates Initial Comments at 5-6; Minnesota
State Entities Initial Comments at 4; NARUC Initial Comments at 4;
National Grid Initial Comments at 9-11; NEMA Initial Comments at 1-
2; NESCOE Initial Comments at 14-16; New England for Offshore Wind
Initial Comments at 2; New York Commission and NYSERDA Initial
Comments at 8; New York TOs Initial Comments at 1; New York Transco
Initial Comments at 1; NextEra Initial Comments at 62; Northwest and
Intermountain Initial Comments at 7; Ohio Conservative Energy Forum
Supplemental Comments at 1; Pine Gate Initial Comments at 18-19;
PIOs Initial Comments at 12-14; Policy Integrity Initial Comments at
5; RMI Supplemental Comments at 2; Senator Schumer Supplemental
Comments at 1-2; Senator Whitehouse Supplemental Comments at 1-3;
SDG&E Initial Comments at 2; Southeast PIOs Initial Comments at 42-
49; State Officials Supplemental Comments at 1 (citing US Climate
Alliance Initial Comments); US Climate Alliance Initial Comments at
1-2; Vermont Electric and Vermont Transco Initial Comments at 3;
Virginia Commission Staff Initial Comments at 2-3; Western PIOs
Initial Comments at 28-30, 36; Western Way Colorado Supplemental
Comments at 1; Western Way Nevada Supplemental Comments at 1;
Western Way Utah Supplemental Comments at 1; Wisconsin Conservative
Energy Forum Supplemental Comments at 1.
\365\ Breakthrough Energy Initial Comments at 12; EEI
Supplemental Comments at 1; Exelon Initial Comments at 5; US House
Republicans Supplemental Comments at 1; ITC Initial Comments at 5.
---------------------------------------------------------------------------
146. AEP and [Oslash]rsted argue that the Commission's proposal
will address deficiencies in the current transmission planning
process.\366\ National Grid claims that existing long-term transmission
planning processes are sufficient for addressing reliability and
economic transmission needs in the near-term but are inadequate for
addressing the changing resource mix and demand, as well as for
addressing resilience challenges driven by climate change.\367\ ACEG
claims that Long-Term Regional Transmission Planning will allow right-
sizing of transmission facilities.\368\
---------------------------------------------------------------------------
\366\ AEP Initial Comments at 8; [Oslash]rsted Initial Comments
at 4-5.
\367\ National Grid Initial Comments at 10.
\368\ ACEG Initial Comments at 6.
---------------------------------------------------------------------------
147. Some commenters observe that this proposal may result in cost-
savings for consumers. For example, DC and MD Offices of People's
Counsel claim that this proposal could result in significant cost
savings to consumers by helping address severe weather events and
reduce the relative cost of decarbonizing the country's resource
fleet.\369\ AEP argues that the NOPR proposal will benefit consumers by
establishing a process that will identify more efficient or cost-
effective transmission facilities, capturing currently missed
opportunities and achieving economies of scale.\370\ North Carolina
Commission and Staff argue that Long-Term Regional Transmission
Planning can provide state utility commissions and consumer advocates
with useful information to promote a cost-effective and reliable
transmission grid.\371\
---------------------------------------------------------------------------
\369\ DC and MD Offices of People's Counsel Initial Comments at
8-10 (citing Patrick Brown & Audun Botterud, The Value of Inter-
Regional Coordination and Transmission in Decarbonizing the US
Electricity System, 5 Joule 115, 115-134 (2020), https://www.sciencedirect.com/science/article/pii/S2542435120305572?dgcid=author%20_blank); see also EEI Supplemental
Comments at 1 (arguing that robust transmission development will
provide cost savings from greater access to low-cost resources).
\370\ See AEP Initial Comments at 8-12.
\371\ North Carolina Commission and Staff Initial Comments at 4.
---------------------------------------------------------------------------
148. NextEra states that Long-Term Regional Transmission Planning
can minimize overall costs to consumers by enabling the lowest-cost
generation.\372\ Relatedly, Tabors Caramanis Rudkevich states that the
NOPR proposal would establish a transmission planning process that
coordinates across franchises, states, and regions, which will reduce
the production cost of delivery of energy to consumers.\373\
---------------------------------------------------------------------------
\372\ NextEra Initial Comments at 62.
\373\ Tabors Caramanis Rudkevich Initial Comments at 4-5.
---------------------------------------------------------------------------
149. PPL notes that Long-Term Regional Transmission Planning may
improve some of the limitations of criteria-based transmission
planning, which is currently employed in RTOs/ISOs.\374\ [Oslash]rsted
supports the proposed requirements regarding Long-Term Regional
Transmission Planning and argues that existing regional transmission
plans fail to anticipate the size and scale of future offshore wind
generation development, leading to inaccurate plans and insufficient
investment in infrastructure needed to integrate known future offshore
wind generation.\375\
---------------------------------------------------------------------------
\374\ PPL Initial Comments at 4. PPL claims that, while PJM may
perform long-term transmission planning on a 15-year time frame on
paper, its long-term transmission planning is effectively undertaken
over only 7 to 10 years. Id.
\375\ [Oslash]rsted Initial Comments at 4-5.
---------------------------------------------------------------------------
150. State Agencies assert that the Commission's various proposed
reforms in the NOPR collectively would enhance transparency, prevent
unnecessary investment in local transmission projects, and improve the
competitive landscape.\376\ US DOJ and FTC support reforms that address
obstacles to transmission development and that are implemented
consistent with principles for competition.\377\
---------------------------------------------------------------------------
\376\ State Agencies Reply Comments at 6.
\377\ US DOJ and FTC Initial Comments at 19.
---------------------------------------------------------------------------
b. Requests for Flexibility in Transmission Planning
151. A number of commenters support the Commission's proposal to
require Long-Term Regional Transmission Planning, but also express
reservations or objections regarding what they perceive as an overly
prescriptive approach that may disrupt existing processes that are
already working.\378\ For example, multiple
[[Page 49314]]
commenters express concerns that the NOPR's allegedly prescriptive
requirements for Long-Term Regional Transmission Planning will
significantly limit needed discretion to conduct such planning, and
that, without discretion to adjust the scenario modeling and
assumptions to regional circumstances, the final order could lead to
more delay and conflict.\379\ MISO TOs contend that the NOPR proposals
vary sufficiently from MISO's current approach that MISO and its
stakeholders will need to engage in complex and time-intensive
revisions in order to comply.\380\ Similarly, City of New Orleans
Council asks that the final order not hinder existing MISO
processes.\381\
---------------------------------------------------------------------------
\378\ See, e.g., Avangrid Initial Comments at 6, 9; CAISO
Initial Comments at 1-2, 7-10, 13; California Commission Initial
Comments at 6; Duke Initial Comments at 1-2; Indiana Commission
Initial Comments at 1, 3; ISO-NE Initial Comments at 20; ISO/RTO
Council Initial Comments at 4-5 (citing NOPR, 179 FERC ] 61,028 at
PP 66, 104); Massachusetts Attorney General Initial Comments at 10-
12; Michigan Commission Initial Comments at 4-5; MISO Initial
Comments at 23; NEPOOL Initial Comments at 7; NYISO Initial Comments
at 11; PG&E Initial Comments at 2; PJM Initial Comments at 54-55; US
Chamber of Commerce at 4-5.
\379\ Ameren Initial Comments at 8; ISO-NE Initial Comments at
20; ISO/RTO Council Initial Comments at 8-9; MISO TOs Reply Comments
at 10-12.
\380\ MISO TOs Reply Comments at 10-11.
\381\ City of New Orleans Initial Comments at 5-6.
---------------------------------------------------------------------------
152. Multiple commenters recommend that the Commission's final
order establish principles and objectives for long-term transmission
planning that address the Commission's concerns and provide
transmission providers with the flexibility to develop tailored long-
term transmission planning approaches and implementation details
accordingly.\382\ MISO recommends that each transmission provider
should give the Commission a report outlining the actions and processes
that support the Commission's principles and guidance, and then the
Commission could direct specific changes within each transmission
planning region as it deems necessary.\383\
---------------------------------------------------------------------------
\382\ ISO-NE Initial Comments at 20; ISO/RTO Council Initial
Comments at 4-5, 8-9; MISO Initial Comments at 22-23.
\383\ MISO Initial Comments at 22.
---------------------------------------------------------------------------
153. Multiple commenters argue for flexibility to accommodate local
and regional differences, including differences in public policy goals
that affect transmission planning.\384\ NYISO asks that the final order
give each transmission planning region discretion to determine, in
coordination with state entities and stakeholders, how best to
incorporate the Long-Term Regional Transmission Planning requirements
within its transmission planning framework.\385\ California Municipal
Utilities add that a significant amount of demand in the West is served
by publicly-owned utilities and electric cooperatives, which fall
outside of state commission regulation, highlighting the need for
flexibility in planning.\386\
---------------------------------------------------------------------------
\384\ APPA Reply Comments at 9-10; California Commission Initial
Comments at 5; California Municipal Utilities Reply Comments at 2-4;
Industrial Customers Reply Comments at 4; Louisiana Commission Reply
Comments at 4-5; Georgia Commission Initial Comments at 2; NARUC
Initial Comments at 3; New York Transco Initial Comments at 5; North
Dakota Commission Initial Comments at 3; New York Commission and
NYSERDA Initial Comments at 3; OMS Initial Comments at 3; PJM States
Initial Comments at 2.
\385\ NYISO Initial Comments at 13.
\386\ California Municipal Utilities Reply Comments at 2.
---------------------------------------------------------------------------
154. Dominion asserts that any reforms adopted in this proceeding
should align with the purpose of the transmission system, which is to
provide reliable, affordable electric service to customers rather than
to benefit generators.\387\
---------------------------------------------------------------------------
\387\ Dominion Initial Comments at 5.
---------------------------------------------------------------------------
155. APPA agrees with concerns expressed by Commissioner Christie
and former Commissioner Danly that overly prescriptive transmission
planning requirements have the potential to interfere with existing
regional transmission planning processes, and hence argues that
adequate flexibility is needed.\388\ Mississippi Commission states that
where an RTO/ISO or non-RTO/ISO transmission provider is already
engaged in long-term regional transmission planning, the Commission
should accept flexibility and regional variations on compliance to
address region-specific issues, including the delineation of regional
and local transmission facilities through, for example, a voltage
threshold (e.g., 100 kV).\389\
---------------------------------------------------------------------------
\388\ APPA Initial Comments at 23.
\389\ Mississippi Commission Reply Comments at 7-8 (citing
Entergy Initial Comments at 2-4; Louisiana Commission Initial
Comments at 35-36; Michigan State Entities Initial Comments at 2;
MISO Initial Comments at 2-3, 19; MISO TOs Initial Comments at 2, 4,
13-15).
---------------------------------------------------------------------------
156. CAISO maintains that the Commission should allow it to
continue evaluating transmission needs driven by Public Policy
Requirements in its transmission planning process, in addition to any
Long-Term Regional Transmission Planning process, and give CAISO the
flexibility to continue using resource portfolios and geographic zones
identified by state agencies and local regulatory authorities.\390\
Although ACORE urges the Commission not to grant requests for less
stringent transmission planning requirements in the final order, ACORE
agrees that there may be cases where an individual RTO's/ISO's existing
processes may be superior to the proposed reforms, such as in the case
of CAISO's treatment of public policy projects within its annual
transmission planning process.\391\ California Municipal Utilities note
that CAISO has already begun to implement some of the key reforms that
the Commission proposed in the NOPR, specifically by adopting a 20-year
outlook for transmission planning.\392\
---------------------------------------------------------------------------
\390\ CAISO Reply Comments at 17-18.
\391\ ACORE Reply Comments at 4.
\392\ California Municipal Utilities Initial Comments at 5.
---------------------------------------------------------------------------
157. MISO requests that a final order support, rather than detract
from, its demonstrated success in long-term transmission planning.\393\
MISO TOs request that the Commission revise the NOPR's required
parameters for Long-Term Regional Transmission Planning to accommodate
the robust long-term regional transmission planning that some
transmission planning regions, like MISO, have already developed.\394\
Similarly, Ameren contends that the Commission should find that MISO's
approved Long Range Transmission Planning process substantially
complies with the proposed reforms.\395\
---------------------------------------------------------------------------
\393\ MISO Reply Comments at 2-3.
\394\ MISO TOs Reply Comments at 11-12.
\395\ Ameren Initial Comments at 8.
---------------------------------------------------------------------------
158. New York TOs support allowing transmission planning regions
with already successful transmission planning processes to retain those
processes while making incremental enhancements and to demonstrate on
compliance that they meet the NOPR's objectives.\396\ New York Transco
asserts that the current NYISO public policy transmission planning
processes already address, at least in part, the proposed reforms and
believes that the Commission should permit regional flexibility.\397\
---------------------------------------------------------------------------
\396\ New York TOs Initial Comments at 8-9.
\397\ New York Transco Initial Comments at 5.
---------------------------------------------------------------------------
159. SPP states that its current transmission planning processes
are sufficient to meet the intent of the Commission's proposed Long-
Term Regional Transmission Planning reforms.\398\ Omaha Public Power
states that SPP and other RTOs/ISOs have already developed long-term
planning scenarios and suggests that transmission providers that
already have long-term planning scenarios should be provided with the
flexibility to continue using their previously established
processes.\399\
---------------------------------------------------------------------------
\398\ SPP Initial Comments at 3 (citing NOPR, 179 FERC ] 61,028
at P 3).
\399\ Omaha Public Power Initial Comments at 4.
---------------------------------------------------------------------------
160. In contrast, some commenters argue that the final order should
not provide too much flexibility to transmission providers because that
flexibility will undermine Long-Term
[[Page 49315]]
Regional Transmission Planning.\400\ Many commenters opposing greater
flexibility argue that the Commission should establish minimum
requirements for Long-Term Regional Transmission Planning.\401\
---------------------------------------------------------------------------
\400\ See, e.g., ACORE Reply Comments at 2-4 (citing New Jersey
Commission Initial Comments at 7); AEP Reply Comments at 2-5; Clean
Energy Associations Reply Comments at 4-6; DC and MD Offices of
People's Counsel Reply Comments at 2-3; Hannon Armstrong Reply
Comments at 1; Interwest Reply Comments at 3-4; Invenergy Reply
Comments at 8-10; PIOs Reply Comments at 5-6.
\401\ See, e.g., AEE Reply Comments at 9-13, 16-18, 21-22; AEP
Reply Comments at 2-5; Cypress Creek Reply Comments at 4-9;
Interwest Reply Comments at 3-4; Invenergy Initial Comments at 2;
Kentucky Commission Chair Chandler Reply Comments at 2; PIOs Reply
Comments at 2-3; SEIA Reply Comments at 1-3; Southeast PIOs Reply
Comments at 21-22; SREA Reply Comments at 26-27.
---------------------------------------------------------------------------
161. AEP argues that the Commission must resist requests for
excessive regional flexibility that could threaten the development of
long-term regional transmission and only permit it in limited instances
that exceed minimum requirements.\402\ Onward Energy states that, while
flexibility is reasonable, the Commission must clearly identify who
will drive regional transmission planning processes and how
transmission planners will coordinate, study, and implement Long-Term
Scenarios that represent realistic future resource portfolios.\403\
Clean Energy Associations state that without robust and proactive
transmission planning rules, the Commission cannot determine that rates
remain just and reasonable.\404\ DC and MD Offices of People's Counsel
state that, while regional flexibility is critical, long-term
transmission planning rules that provide carve-outs and opt-outs will
result in balkanized transmission development.\405\
---------------------------------------------------------------------------
\402\ AEP Reply Comments at 3.
\403\ Onward Energy Initial Comments at 4.
\404\ Clean Energy Associations Reply Comments at 4-5 (citing
CAISO Initial Comments at 3; California Commission Initial Comments
at 11; ISO-New England Initial Comments at 4; ISO/RTO Council
Initial Comments at 8; NYISO Initial Comments at 3; PG&E Initial
Comments at 4; PJM States Initial Comments at 4).
\405\ DC and MD Offices of People's Counsel Reply Comments at 2.
---------------------------------------------------------------------------
162. Hannon Armstrong states that by diluting the proposed
requirements or granting flexibility as some commenters request, the
Commission would allow existing deficiencies to persist, enabling the
continued reliance on either the generator interconnection process or
operational planning to resolve or mitigate constraints.\406\ Invenergy
rebuts commenters' claims that the NOPR is too prescriptive or that
some of the NOPR requirements should be optional, stating that optional
processes and deference to regional flexibility will not ensure needed
transmission is built and that a flexible approach has already been
tried and has failed to produce sufficient results.\407\
---------------------------------------------------------------------------
\406\ Hannon Armstrong Reply Comments at 1.
\407\ Invenergy Reply Comments at 9-10.
---------------------------------------------------------------------------
c. Comments Regarding More Comprehensive Transmission Planning
163. Several commenters contend that Long-Term Regional
Transmission Planning should not interfere with and should not supplant
existing shorter-term transmission planning processes.\408\ PJM asks
the Commission to confirm that it did not mean for the NOPR proposals
on Long-Term Regional Transmission Planning to modify the existing
reliability and market efficiency transmission planning processes.\409\
Transmission Dependent Utilities encourage the Commission to ensure
that transmission providers do not focus on long-term objectives to
satisfy state renewable energy portfolio requirements to the detriment
of near-term reliability needs, such as end-of-life transmission
planning.\410\ Large Public Power and NEPOOL state that any final order
should clearly state that the current near-term transmission planning
rules and processes, especially cost allocation, are not changed by the
final order's reforms, except where expressly indicated.\411\ Ameren
argues that the Commission was clear that changes to existing
reliability and economic transmission planning requirements are beyond
the scope of the NOPR and that the comments filed supporting holistic
planning have provided no compelling basis for the Commission to
address them.\412\
---------------------------------------------------------------------------
\408\ Ameren Reply Comments at 17; CAISO Initial Comments at 2-
3, 17-20; Chemistry Council Initial Comments at 5; Dominion Initial
Comments at 23; Exelon Initial Comments at 6-7; Indicated PJM TOs
Initial Comments at 12; ITC Initial Comments at 8-9; Large Public
Power Initial Comments at 14-16; NEPOOL Initial Comments at 8;
NESCOE Initial Comments at 21-23; PJM Initial Comments at 55-57; PPL
Initial Comments at 4-5; Transmission Dependent Utilities Initial
Comments at 4-6; WIRES Initial Comments at 6-7; Xcel Initial
Comments at 16.
\409\ PJM Initial Comments at 55-57.
\410\ Transmission Dependent Utilities Initial Comments at 4-6.
\411\ Large Public Power Initial Comments at 16-18; NEPOOL
Initial Comments at 7-8.
\412\ Ameren Reply Comments at 17.
---------------------------------------------------------------------------
164. Several commenters contend that Long-Term Regional
Transmission Planning should not interfere with and must not supplant
existing shorter-term transmission planning processes for transmission
needs driven by Public Policy Requirements.\413\ CAISO states that the
NOPR provides no guidance or criteria regarding how a transmission
provider can demonstrate that its existing process for addressing
transmission needs driven by Public Policy Requirements does not
interfere with or undermine Long-Term Regional Transmission Planning.
CAISO contends that it should not have to re-justify its existing
process or demonstrate that its existing process is consistent with or
superior to Long-Term Regional Transmission Planning.\414\
---------------------------------------------------------------------------
\413\ Anbaric Initial Comments at 22-27; CAISO Initial Comments
at 2-3, 9-20; Large Public Power Initial Comments at 14-16.
\414\ CAISO Initial Comments at 19.
---------------------------------------------------------------------------
165. AEP asserts that transmission providers should look at nearer-
term reliability and economic transmission planning processes to
determine whether there are needs that can be incorporated into Long-
Term Regional Transmission Planning and addressed by a Long-Term
Regional Transmission Facility.\415\ SEIA recommends that the
Commission require transmission providers to engage in portfolio-based
transmission planning that integrates all relevant factors, including
near-term needs, into Long-Term Regional Transmission Planning.\416\
Policy Integrity argues that inclusion of specific requirements for
transmission modeling are needed to fulfill the mandate of ensuring
wholesale electric rates are just and reasonable.\417\ Xcel recommends
that the Commission require that known or expected generation be
included in short-term regional transmission planning assumptions.\418\
---------------------------------------------------------------------------
\415\ AEP Initial Comments at 10.
\416\ SEIA Initial Comments at 20-21.
\417\ Policy Integrity Supplemental Comments at 3.
\418\ Xcel Initial Comments at 16.
---------------------------------------------------------------------------
166. PIOs state that, if the two processes continue to exist, the
Commission should mandate that the base cases used in Order No. 1000
regional transmission planning processes and Long-Term Scenarios in
Long-Term Regional Transmission Planning be defined in the same
process. Otherwise, PIOs contend, inconsistent assumptions between the
two processes could lead to redundant transmission projects and failure
to identify more efficient solutions. In particular, PIOs argue, if an
Order No. 1000 transmission planning process base case identifies
transmission needs that are not anticipated in the Long-Term Scenarios,
the opportunities for more efficient planning created by the long-term
process will be lost. In addition, PIOs suggest that there may be
opportunities for stakeholders to undermine Long-Term Regional
Transmission Planning if they believe Order No. 1000 transmission
planning
[[Page 49316]]
would produce more favorable results for them. PIOs further argue that
because uncertainty grows the further one looks into the future, there
should not be significant differences in the short-term results of
Long-Term Regional Transmission Planning and Order No. 1000 regional
transmission planning processes.\419\
---------------------------------------------------------------------------
\419\ PIOs Initial Comments at 44-46.
---------------------------------------------------------------------------
167. Several commenters support forward-looking, Long-Term Regional
Transmission Planning but argue for holistic planning using multiple
drivers of transmission needs.\420\ They argue that a holistic approach
is more efficient, better accounts for long-term benefits of new
transmission, addresses the needs of more stakeholders, and is more
likely to support development of regional transmission facilities,
among other benefits. Competition Advocates support a final order that
reflects the benefits of holistic modeling,\421\ while New Jersey
Commission contends that holistic transmission planning using a
competitive process provides significant benefits, including reducing
costs.\422\
---------------------------------------------------------------------------
\420\ See, e.g., Acadia Center and CLF Initial Comments at 4-7;
ACEG Initial Comments at 6-7, 30-31; ACORE Initial Comments at 5-7;
Anbaric Initial Comments at 5-10; AEE Reply Comments at 2; Business
Council for Sustainable Energy Initial Comments at 2; City of New
York Initial Comments at 4-6; Competition Coalition Initial Comments
at 15-16; Cypress Creek Reply Comments at 4-5; Enel Initial Comments
at 3; Pine Gate Initial Comments at 18-19; PIOs Reply Comments at
11; SEIA Reply Comments at 2, 7-8; see also Pattern Energy Initial
Comments at 16.
\421\ Competition Advocates Supplemental Comments at 1; see also
Policy Integrity Supplemental Comments at 2-3 (citing Jennifer Danis
et al., Inst. for Policy Integrity, Transmission Planning for the
Energy Transition: Rethinking Modeling Approaches (Dec. 2023),
https://policyintegrity.org/files/publications/Transmission_Report_2023.pdf).
\422\ New Jersey Commission Motion to Lodge at 4-5 (citing In re
Declaring Transmission to Support Offshore Wind a Pub. Policy of the
State of N.J., Order on the State Agreement Approach SAA Proposals,
N.J. BPU Docket No. QO20100630 (Oct. 26, 2022), https://publicaccess.bpu.state.nj.us/DocumentHandler.ashx?document_id=1279919; Johannes P. Pfeifenberger,
et al., Brattle Grp., New Jersey State Agreement Approach for
Offshore Wind Transmission: Evaluation Report, (Oct. 26, 2022),
https://publicaccess.bpu.state.nj.us/DocumentHandler.ashx?document_id=1279916; PJM, Economic Analysis
Report: 2021 SAA Proposal Window to Support NJ OSW (Nov. 4, 2022),
https://www.pjm.com/-/media/committees-groups/committees/teac/2022/
20221104-special/informationalonly_-njosw-economic-analysis-
report.ashx).
---------------------------------------------------------------------------
168. To ensure that reforms are not undermined by existing
processes, Clean Energy Buyers recommend that the Commission extend to
all existing regional transmission planning processes--not just
transmission planning processes to address transmission needs driven by
Public Policy Requirements, as proposed in the NOPR--the requirement
that, on compliance with any final order, transmission providers who
seek to retain existing regional transmission planning and cost
allocation processes must demonstrate that continued use of those
processes does not interfere with or undermine Long-Term Regional
Transmission Planning.\423\
---------------------------------------------------------------------------
\423\ Clean Energy Buyers Initial Comments at 9-10.
---------------------------------------------------------------------------
169. However, other commenters support the Commission's proposal in
the NOPR to not apply the proposed reforms to existing Order No. 1000
reliability and near-term economic regional transmission planning
processes.\424\ Ohio Consumers support the NOPR's proposal to mostly
retain the regional transmission planning processes outlined in Order
No. 1000, explaining that PJM stakeholders have reached an effective
settlement under that framework in which costs are allocated in a
manner that is roughly commensurate with the benefits received.\425\
---------------------------------------------------------------------------
\424\ Ameren Reply Comments at 17; Exelon Initial Comments at 6-
7; ITC Initial Comments at 8-9; WIRES Initial Comments at 6-7.
\425\ Ohio Consumers Initial Comments at 7 (citing NOPR, 179
FERC ] 61,028 at P 72).
---------------------------------------------------------------------------
170. Some commenters argue that the Commission should require that
local transmission projects be evaluated and approved as part of a
holistic planning approach.\426\ AEE asserts that, to ensure that
transmission providers consider the full range of needs in developing
long-term regional transmission plans, the final order should require
them to consider local transmission plans and to determine whether a
regional solution would be more efficient or cost-effective.\427\ OMS
suggests that the Commission require that all local transmission
projects be evaluated and approved as part of regional transmission
planning processes with the opportunity for meaningful input from
retail regulators, which it argues will enable participation by state
regulators while respecting transmission owners' abilities to maintain
their systems.\428\
---------------------------------------------------------------------------
\426\ AEE Initial Comments at 3, 38; OMS Initial Comments at 16-
17; LS Power and NRG Supplemental Comments at 34-37.
\427\ AEE Initial Comments at 3, 38.
\428\ OMS Initial Comments at 16-17.
---------------------------------------------------------------------------
171. By contrast, WIRES argues that the Commission should maintain
the distinction between regional transmission planning and local
transmission planning. WIRES argues that, while the regional
transmission planning process is directed toward addressing certain
reliability concerns, economic criteria, and public policy initiatives,
it is not geared toward addressing additional system needs related to
resilience, asset management, customer needs, customer impact, and
aging infrastructure replacement that is typically the focus of local
transmission planning.\429\ Similarly, AEP states that if an RTO/ISO
were to make all decisions regarding local transmission projects, they
would also need to assume the accompanying responsibility--and the
liability--for such decisions, which would entail physical inspection
and condition assessment of assets, as well as a determination of when
transmission facilities have reached their end of useful life.\430\ AEP
points out that both CAISO and PJM have expressly stated that they do
not wish to undertake these types of activities and assume such
obligations.\431\
---------------------------------------------------------------------------
\429\ WIRES Initial Comments at 9.
\430\ AEP Reply Comments at 7.
\431\ Id. (citing S. Cal. Edison Co., 164 FERC ] 61,160, at P 18
(2018); PJM Interconnection, L.L.C., Comments of PJM, Docket No.
ER20-2308-000, at attach. A (July 2, 2020) (citation omitted)).
---------------------------------------------------------------------------
d. Concerns Regarding Favoring Renewable Resources
172. ELCON argues that the Commission's proposal could require
customers to pay higher costs to connect distant renewables when a
lower-cost transmission project would provide the same reliability or
economic benefits.\432\ Utah Division of Public Utilities states that
Long-Term Scenario requirements favoring renewable generation burden
transmission providers while providing little to no benefit and that
developers and generation utilities should determine which renewable
generation should be developed at their respective zones or sites.\433\
Utah Commission further contends that nationwide mandates for
transmission planning add costs, produce confusion, and create
conflicts that could lead to higher utility prices for consumers.\434\
Kansas Ratepayer Advocates contend that Long-Term Regional Transmission
Planning would presume material additions of renewable energy to serve
consumers within a state, coupled with material additions of
transmission to interconnect those renewables to the electric
transmission grid, which do not reflect the unique circumstances of
Kansas.\435\
---------------------------------------------------------------------------
\432\ ELCON Initial Comments at 9-10.
\433\ Utah Division of Public Utilities Initial Comments at 7-8.
\434\ Utah Commission Initial Comments at 11, 13.
\435\ Kansas Ratepayers Advocates Reply Comments at 2.
---------------------------------------------------------------------------
173. Vistra asserts that the proposed reforms could devolve into
the subsidization of resources chosen to
[[Page 49317]]
achieve state policy goals, masking the true costs of those remotely
located resources that require extensive transmission development to
interconnect to the grid and leading to market distortions that
undermine the objectives of these reforms.\436\
---------------------------------------------------------------------------
\436\ Vistra Initial Comments at 11.
---------------------------------------------------------------------------
174. Louisiana Commission states that the NOPR would result in
subsidization of the costs of transmitting remote renewable energy,
spreading the costs out broadly based on an expanded ``nebulous concept
of `benefits' and perceived `public policy,' '' thus ensuring that
those transmission projects will pass any economic test.\437\ According
to Louisiana Commission, this subsidization would interfere with price
signals, thereby distorting the efficient functioning of the wholesale
market.\438\ Louisiana Commission states that any Commission policy
should be resource and technology neutral and should not impose costs
on states that do not benefit from distant renewable power.\439\
---------------------------------------------------------------------------
\437\ Louisiana Commission Reply Comments at 12 (citing NOPR,
179 FERC ] 61,028 (Christie, Comm'r, concurring at P 2)).
\438\ Louisiana Commission Initial Comments at 19-21.
\439\ Id. at 21-24.
---------------------------------------------------------------------------
175. Finally, Louisiana Commission contends that the NOPR's long-
term transmission planning requirements could threaten the reliability
of the transmission grid because the intermittent renewable resources
that the NOPR favors do not provide stable output and are not
dispatchable.\440\ Similarly, former Kansas Commission Chair Keen
argues that the NOPR fails to acknowledge the reliability concerns
associated with a generation mix that is too heavily weighted to
intermittent renewable generation resources.\441\
---------------------------------------------------------------------------
\440\ Id. at 21-23. But see Cypress Creek Reply Comments at 2-4
(disagreeing with Louisiana Commission and claiming that regionally
coordinated transmission planning should provide demonstrable system
reliability benefits).
\441\ Kansas Commission Chair Keen Initial Comments at 1.
---------------------------------------------------------------------------
e. Concerns Regarding Uncertainty, Over-Building, and Costs
176. A few commenters argue that long-term transmission planning
introduces uncertainty or incentivizes speculative transmission
development.\442\ While EPSA acknowledges that long-term forecasts can
provide valuable information about the potential scale of construction
necessary to achieve decarbonization, it argues that using such
forecasts to justify investment shifts the risks to consumers from
developers and facility owners.\443\ California Municipal Utilities
state that, as transmission planning horizons are extended, the changes
in resource mix, technology types, the location of resources, and
demand will likely change congestion patterns and therefore the need
for transmission upgrades needed to address them.\444\
---------------------------------------------------------------------------
\442\ EPSA Initial Comments at 7; New England Systems Initial
Comments at 22; see also NRECA Initial Comments at 28-29.
\443\ EPSA Initial Comments at 7.
\444\ California Municipal Utilities Initial Comments at 7.
---------------------------------------------------------------------------
177. Louisiana Commission states that it opposes the NOPR proposal
because it would lead to an inefficient and expensive build-out of the
transmission system and could be used to justify shifting the costs of
this build-out to load.\445\ ELCON states that it is concerned that the
Commission's proposal to prioritize Long-Term Regional Transmission
Planning to connect renewable generation over Long-Term Regional
Transmission Planning for economically necessary transmission may
exceed the Commission's authority if it increases transmission rates
for the benefit of a few stakeholders.\446\ Southern states that
transmission expansion predicated on hypothetical resources that might
not materialize would not satisfy the fundamental legal requirements of
being used and useful, prudent, and/or otherwise needed for the public
use, could harm reliability, and would violate the Commission's duty
under the FPA to facilitate transmission planning to meet load-serving
entities' obligations.\447\
---------------------------------------------------------------------------
\445\ Louisiana Commission Initial Comments at 4-5.
\446\ ELCON Initial Comments at 9 (citing NOPR, 179 FERC ]
61,028 (Danly, Comm'r, dissenting, at P 2 n.3); NOPR, 179 FERC ]
61,028 at P 47).
\447\ Southern Initial Comments at 32, 34.
---------------------------------------------------------------------------
178. Industrial Customers argue that the NOPR does not provide
evidence that extending the transmission planning horizon would exclude
modeling of speculative projects, which would likely result in the
over-building of transmission and unnecessary increases in rates.\448\
Industrial Customers cite the D.C. Circuit's finding in Old Dominion
Electric Cooperative v. FERC that ``[w]e are sensitive to the concern .
. . that individual utilities should not have free rein to impose
unjustified costs on an entire region by unilaterally adopting overly
ambitious planning criteria,'' and argue that the current NOPR proposal
would result in the same issues.\449\
---------------------------------------------------------------------------
\448\ Industrial Customers Initial Comments at 6, 15-16, 19-21.
\449\ Id. at 16 (citing Old Dominion Elec. Coop. v. FERC, 898
F.3d 1254, 1263 (D.C. Cir. 2018)).
---------------------------------------------------------------------------
179. NRG urges caution on over-reliance on any 20-year planning
study for making transmission investments due to the inherent
uncertainty of a study with such a long planning horizon.\450\ NRG
argues that the NOPR will increase delivery costs by reducing the value
of private investments and replacing such investments with a centrally
planned, cost-socialized approach that is founded on at least some
incorrect assumptions.\451\ NRG provides several examples of how
forecast errors have caused adverse consequences, including forecasts
of natural gas prices, load forecasts, and canceled planned
transmission facilities.\452\
---------------------------------------------------------------------------
\450\ NRG Initial Comments at 8.
\451\ Id. at 3.
\452\ Id. at 10-11.
---------------------------------------------------------------------------
180. Likewise, Ohio Consumers urge the Commission to avoid adopting
proposals based on long-term projections that justify massive charges
to consumers based on hypothetical scenarios.\453\ Ohio Consumers state
that Ohio customers have recently been saddled with rate increases in
part due to transmission investments and that long-term transmission
planning requirements would increase ratepayer burden, which is
especially troublesome if projections turn out to be inaccurate.\454\
---------------------------------------------------------------------------
\453\ Ohio Consumers Initial Comments at 5.
\454\ Id.
---------------------------------------------------------------------------
181. As an alternative to Long-Term Regional Transmission Planning,
Potomac Economics states that the Commission could require the
transmission planning process to incorporate a broader array of near-
term emerging trends that are less uncertain than the proposed longer-
term factors.\455\ Louisiana Commission states that it shares Potomac
Economics' concerns. Louisiana Commission urges the Commission to heed
testimony submitted by Potomac Economics arguing that: (1) there is
significant uncertainty about future technology and a significant risk
of investing in transmission projects that will not ultimately provide
value; (2) large transmission projects are often not the most economic,
whereas smaller, targeted projects are more beneficial; and (3) there
can and likely would be stranded transmission if transmission planning
processes attempt to identify and meet transmission needs 20 to 30
years in the future.\456\
---------------------------------------------------------------------------
\455\ Potomac Economics Initial Comments at 4.
\456\ Louisiana Commission Reply Comments at 13-14.
---------------------------------------------------------------------------
182. US Chamber of Commerce argues that the Commission should
ensure that any Long-Term Regional Transmission
[[Page 49318]]
Planning reforms do not perpetuate an irrational transmission buildout
that undermines competitive advantages of domestic electricity rates.
US Chamber of Commerce asserts that the loss of competitive advantage
would lead to lost jobs, lost economic growth, decreased electricity
use, and fixed system costs assessed to fewer customers.\457\
---------------------------------------------------------------------------
\457\ US Chamber of Commerce Initial Comments at 8.
---------------------------------------------------------------------------
183. Vistra states that the proposed reforms lean toward accounting
for regulatory and public policy initiatives that may shape changes in
the generation mix without sufficiently incorporating the commercial
and markets-related aspects of generation development.\458\ Vistra
states that, without a process to assess commercial interest and
financial commitment from generation developers, long-term regional
transmission plans may under- or over-build transmission facilities or
build them in the wrong locations.\459\ Relatedly, NRECA states that
planning a regional transmission network for generation resources or
changes in demand not identified by load-serving entities' forecasts,
and instead through unsupported top-down assumptions, may produce
uneconomic results from over-building and increase reliability
risks.\460\
---------------------------------------------------------------------------
\458\ Vistra Initial Comments at 7.
\459\ Id.
\460\ NRECA Initial Comments at 18-19.
---------------------------------------------------------------------------
184. NRG states that, in light of the uncertainty of variables such
as the amount of electrification and resulting load requirements,
technology costs for new resources, and viability and repurposing of
existing resources, it is not clear whether a ``no regrets'' option
genuinely exists. NRG also asserts that the centralized planning
envisioned in the NOPR sacrifices the ability of market participants to
use available information to assess whether their investments will be
viable in the future, which is a critical feature of competition. NRG
asserts that the Commission has not contemplated that trade-off or
quantified its costs, noting that past long-term transmission planning
studies have done a questionable job at forecasting future needs.\461\
---------------------------------------------------------------------------
\461\ NRG Initial Comments at 8.
---------------------------------------------------------------------------
185. Other commenters, however, note that the NOPR proposal
includes measures that mitigate the uncertainty inherent in longer-term
regional transmission planning.\462\ For example, New Jersey Commission
states that the proposed requirements to develop multiple scenarios and
perform reassessments mitigates the uncertainty inherently present in a
20-year transmission planning horizon.\463\ Additionally, several
commenters rebut opposition to Long-Term Regional Transmission Planning
based on concerns that it presents unreasonable levels of
uncertainty.\464\ For example, SREA and Clean Energy Buyers assert that
periodic updates of forecasts and scenarios will help to mitigate
uncertainty.\465\
---------------------------------------------------------------------------
\462\ New Jersey Commission Initial Comments at 10-11; PIOs
Initial Comments at 15-16.
\463\ New Jersey Commission Initial Comments at 10-11.
\464\ Clean Energy Buyers Reply Comments at 8; Policy Integrity
Reply Comments at 2; SREA Reply Comments at 21-24.
\465\ Clean Energy Buyers Reply Comments at 8; SREA Reply
Comments at 23.
---------------------------------------------------------------------------
186. Policy Integrity further explains that future uncertainty is
exactly why long-term scenario planning is necessary to ensure just and
reasonable rates. Policy Integrity states that the current transmission
planning process uses deterministic modeling that does not account for
the changing world, which will not lead to the development of efficient
or cost-effective transmission solutions. Policy Integrity asserts
that, in contrast, long-term scenario planning will allow transmission
planners to be prepared for changes.\466\ Policy Integrity argues that
any forward-looking decision will have a degree of uncertainty, but
that the risk posed by uncertainty can be mitigated and managed by
using a portfolio evaluation of costs and benefits.\467\ Policy
Integrity further argues that ignoring the uncertainty surrounding the
energy transition runs its own risk of failing to build transmission
that can be useful to meet needs in the short, medium, and long
term.\468\
---------------------------------------------------------------------------
\466\ Policy Integrity Reply Comments at 2.
\467\ Id. at 3-4.
\468\ Id. at 4.
---------------------------------------------------------------------------
f. Concerns Regarding Incentives for Resource Development
187. Vistra asserts that it is critical for Commission policy to
maintain interconnection cost signals to drive cost-effective
generation siting choices.\469\ Vistra also argues that a policy that
assigns all interconnection-related network upgrade costs, or even a
disproportionately high share, to load undermines the incentive that
generation developers currently have to site new projects in locations
that minimize the related transmission upgrade costs.\470\
---------------------------------------------------------------------------
\469\ Vistra Initial Comments at 7.
\470\ Id. at 7-8.
---------------------------------------------------------------------------
188. In contrast, New Jersey Commission argues that requiring
individual interconnecting generators to pay for piecemeal
interconnection-related network upgrades does not necessarily encourage
developers to make siting decisions that minimize the overall cost of
integrating large amounts of new generation.\471\ Likewise, Clean
Energy Associations state that robust, proactive regional transmission
planning will better incent efficient siting decisions, because
generators will evaluate the likely costs of interconnection facilities
that ensure deliverability to the grid, rather than more broadly
beneficial transmission facilities.\472\
---------------------------------------------------------------------------
\471\ New Jersey Commission Reply Comments at 7.
\472\ Clean Energy Associations Reply Comments at 9 (citing ACEG
2021 Interconnection Report at 15).
---------------------------------------------------------------------------
g. Comments Regarding Definition of Long-Term Regional Transmission
Facility
189. PJM states that the Commission should clarify certain details
of the NOPR proposal, including the meaning of the word ``identified''
in the proposed definition of Long-Term Regional Transmission
Facility.\473\ In addition, PJM requests that the Commission clarify
that if a transmission project shows up in several Long-Term Scenarios
but is not selected until it reaches one of the shorter-term
reliability and market efficiency transmission planning processes, that
project would not be considered a Long-Term Regional Transmission
Facility for selection and cost allocation purposes.\474\ Otherwise,
PJM contends, the rules for selection and cost allocation for
transmission projects selected in the shorter-term and intermediate-
term reliability and market efficiency transmission planning processes
will be unclear, leading to re-litigation.\475\
---------------------------------------------------------------------------
\473\ PJM Initial Comments at 8, 98.
\474\ Id. at 99.
\475\ Id. at 99, 101.
---------------------------------------------------------------------------
h. Challenges to Commission Jurisdiction or Authority
i. FPA Section 201
190. Some commenters argue that the NOPR proposals exceed the
Commission's jurisdiction or that the Commission otherwise lacks the
authority to adopt a final order in this proceeding. Of these
commenters, most contend that the NOPR proposal interferes with
authority reserved to the states under FPA section 201.\476\
---------------------------------------------------------------------------
\476\ Alabama Commission Initial Comments at 3-4, 7-8; Kansas
Ratepayer Advocates Reply Comments at 2-3; Louisiana Commission
Initial Comments at 5, 8-9, 27-28; Louisiana Commission Reply
Comments at 14-15; Mississippi Commission Initial Comments at 3, 5-
6; Mississippi Commission Reply Comments at 2; Nevada Commission
Initial Comments at 2-3, 6; SERTP Sponsors Initial Comments at 5,
15-19 & n.20; SERTP Sponsors Reply Comments at 12-13; Southern
Initial Comments at 3-8, 12-13, 15-24; Southern Reply Comments at 3,
6-7; Utah Commission Initial Comments at 7-9; Undersigned States
Reply Comments at 2, 4-5.
---------------------------------------------------------------------------
[[Page 49319]]
191. Some commenters argue that the NOPR proposal intrudes on the
authority reserved to the states under FPA section 201 over integrated
resource planning processes or resource mix decision making.\477\ For
example, Alabama Commission states that the NOPR proposal for Long-Term
Regional Transmission Planning would intrude on state integrated
resource planning to the extent that it dictates the construction of
facilities through a top-down regional process or seeks to influence or
mandate a substantive change to the generation resource mix.\478\
Similarly, Nevada Commission argues that the NOPR may impact states'
authority to determine their own mix of generating resources. Nevada
Commission contends that the NOPR may cross the line from regulating
interstate transmission to regulating intrastate processes--
particularly because the Commission has not asserted jurisdiction over
bundled retail transmission.\479\ Louisiana Commission argues that the
Commission should not override state jurisdiction on resource planning,
fuel type, and siting decisions, along with the regulation of retail
rates.\480\
---------------------------------------------------------------------------
\477\ Alabama Commission Initial Comments at 3-4, 7-8; Kansas
Ratepayer Advocates Reply Comments at 2; Louisiana Commission
Initial Comments at 8-9, 27-28; Louisiana Commission Reply Comments
at 14-15; Mississippi Commission Initial Comments at 3 (citing NOPR,
179 FERC ] 61,028 (Christie, Comm'r, concurring, at P 2)); Nevada
Commission Initial Comments at 2-3; SERTP Sponsors Initial Comments
at 5, 15-19 & n.20; SERTP Sponsors Reply Comments at 12-13; Southern
Initial Comments at 3-8, 12-13, 15-24; Southern Reply Comments at 3,
6-7; Utah Commission Initial Comments at 7-9; Undersigned States
Reply Comments at 2, 4-5.
\478\ Alabama Commission Initial Comments at 3-4, 7-8.
\479\ Nevada Commission Initial Comments at 2-3.
\480\ Louisiana Commission Initial Comments at 27-28; Louisiana
Commission Reply Comments at 14-15.
---------------------------------------------------------------------------
192. Mississippi Commission requests that the Commission
acknowledge that it cannot force regional planning entities to
indirectly act as a national integrated resource planner.\481\ SERTP
Sponsors and Southern argue that the NOPR essentially constitutes a
Commission-regulated integrated resource plan/request for proposal
process and that, to be workable, Long-Term Regional Transmission
Planning instead must be based on state commission-regulated integrated
resource planning/request for proposal decisions.\482\ SERTP Sponsors
and Southern contend that the NOPR proposed to require transmission
providers to make independent resource and load decisions because: (1)
state integrated resource plans are just one of many factors to be
considered in developing Long-Term Scenarios; and (2) state integrated
resource planning or request for proposal processes generally use a 10-
year planning horizon such that there are no state-approved resources
for the second half of the NOPR's proposed 20-year transmission
planning horizon.\483\ SERTP Sponsors and Southern further argue that,
in upholding Order No. 1000, the D.C. Circuit emphasized that the
Commission was regulating the transmission planning process and not
mandating any particular outcome, and that, if the Commission
prescribes a process that supplants state decision making, it will have
crossed the line into prescribing substantive outcomes and thus
exceeded its jurisdiction.\484\
---------------------------------------------------------------------------
\481\ Mississippi Commission Initial Comments at 3 (citing NOPR,
179 FERC ] 61,028 (Christie, Comm'r, concurring, at P 2)).
\482\ SERTP Sponsors Initial Comments at 15-16; SERTP Sponsors
Reply Comments at 12-13; Southern Initial Comments at 4-5, 7, 15-16;
Southern Reply Comments at 6-7.
\483\ SERTP Sponsors Initial Comments at 16; Southern Initial
Comments at 12-13.
\484\ SERTP Sponsors Initial Comments at 19; Southern Initial
Comments at 23-24 (citing Order No. 1000, 136 FERC ] 61,051 at P
154).
---------------------------------------------------------------------------
193. Ohio Commission Federal Advocate contends that the NOPR
appears designed to target the achievement of narrow environmental
policy objectives or the socialization of transmission costs, not to
ensure reliability or foster just and reasonable rates.\485\ Southern
and Utah Commission state that the Commission has consistently
recognized that the FPA does not allow the Commission to pick winners
and losers when it comes to generation and argue that the Commission
has no authority to favor one generation mix over another.\486\
Similarly, Louisiana Commission, Kansas Ratepayer Advocates, and
Undersigned States contend that the Commission lacks the statutory
authority to dictate states' generation resource decisions. They argue
instead that each state possesses such authority and is uniquely
qualified to choose the generation resources that are needed to
economically meet ratepayers' electric service needs within their
states.\487\
---------------------------------------------------------------------------
\485\ Ohio Commission Federal Advocate Initial Comments at 4-6.
\486\ Southern Initial Comments at 23 (citing ISO New England
Inc., 162 FERC ] 61,205, at P 26 (2018)); Utah Commission Initial
Comments at 7-9.
\487\ Louisiana Commission Initial Comments at 8-10 (citing
Monongahela Power Co., 40 FERC ] 61,256, at 61,861 (1987); Pac. Gas
& Elec. Co. v. State Energy Res. Conservation & Dev. Comm'n, 461
U.S. 190, 212 (1983)); Kansas Ratepayer Advocates Reply Comments at
2; Undersigned States Reply Comments at 2, 4-5 (citing Pac. Gas &
Elec. Co. v. State Energy Res. Conservation & Dev. Comm'n, 461 U.S.
at 205).
---------------------------------------------------------------------------
194. SERTP Sponsors and Southern argue that, even if assumptions
about the resource mix included in Long-Term Scenarios do not bind
states, requiring transmission providers to develop Long-Term Scenarios
that are predicated on particular resource assumptions effectively
makes a substantive resource decision because it favors the assumed
resource mix over others.\488\ SERTP Sponsors and Southern contend that
this is akin to the Commission attempting to accomplish indirectly what
it could not directly.\489\ SERTP Sponsors argue that the Commission
should support the exercise of traditional state resource and
infrastructure planning authority rather than supplant it.\490\ North
Carolina Commission and Staff argue that the use of the production cost
savings benefit in Long-Term Regional Transmission Planning ``could
conflict with state-jurisdictional resource decisions.'' \491\
---------------------------------------------------------------------------
\488\ SERTP Sponsors Initial Comments at 17 n.20; Southern
Initial Comments at 19.
\489\ SERTP Sponsors Initial Comments at 17 n.20; Southern
Initial Comments at 18.
\490\ SERTP Sponsors Initial Comments at 17, 19; see also
Undersigned States Reply Comments at 5, 8 (citing Am. Gas Ass'n v.
FERC, 912 F.2d 1496, 1510 (D.C. Cir. 1990)).
\491\ North Carolina Commission and Staff Initial Comments at 7.
---------------------------------------------------------------------------
195. Other commenters disagree with these contentions and argue
that the NOPR proposal would not intrude on states' reserved authority
over resource mix decision making or integrated resource plan
processes.\492\ Kentucky Commission Chair Chandler and SEIA argue that
the NOPR's stated aim of reforming regional and interregional
transmission planning processes does not foreclose states' decision
making on generation.\493\ ACEG contends that the NOPR does not propose
or purport to regulate the electric supply mix and that the Commission
is acting squarely within its authority under the FPA's cooperative
federalism structure.\494\ AEE notes that the Commission included
integrated resource planning and utility load-serving planning as a
factor driving transmission needs and argues that none of the
requirements proposed by the Commission directly conflict with
[[Page 49320]]
integrated resource planning processes, require that integrated
resource planning be conducted on a different timeline, or override
resource planning efforts.\495\ Likewise, Kentucky Commission Chair
Chandler reiterates that Kentucky's integrated resource plans are not
driving transmission planning processes in the state. He explains that
integrated resource plans/requests for proposals are not the basis for
generation investment decisions, but the state's requests for proposals
seek generation proposals after the integrated resource planning
process is complete and a need for generation is identified.\496\ In
response to Alabama Commission's arguments that the NOPR's proposed
rules have the potential to encroach on state-jurisdictional integrated
resource planning and resource procurement processes overseen by
Alabama Commission, SREA contends that Alabama Commission in fact does
not have a formal integrated resource planning process upon which the
Commission could encroach.\497\
---------------------------------------------------------------------------
\492\ ACEG Reply Comments at 15; AEE Reply Comments at 23; New
Jersey Commission Reply Comments at 2; Kentucky Commission Chair
Chandler Reply Comments at 3; SEIA Reply Comments at 2-3.
\493\ Kentucky Commission Chair Chandler Reply Comments at 3;
SEIA Reply Comments at 2-3.
\494\ ACEG Reply Comments at 15.
\495\ AEE Reply Comments at 23.
\496\ Kentucky Commission Chair Chandler Reply Comments at 6.
\497\ SREA Reply Comments at 2-3.
---------------------------------------------------------------------------
196. New Jersey Commission disagrees with commenters who argue that
the Commission intends to impose a preferred resource mix on the Nation
by overriding state choices and contends that such arguments are
``profoundly misconstruing'' the nature of the NOPR proposal and what
the Commission aims to achieve.\498\ Instead, New Jersey Commission
argues that Long-Term Regional Transmission Planning would address
transmission needs that are being driven by state policies, market
decisions, and technological changes, all of which reflect consumer-
driven demand for cleaner electricity.\499\ New Jersey Commission
contends that the NOPR proposal would ensure that transmission needs
are reliably met at a total cost that is just and reasonable, which New
Jersey Commission argues is required--not precluded--by the FPA.\500\
---------------------------------------------------------------------------
\498\ New Jersey Commission Reply Comments at 1-2.
\499\ Id. at 2.
\500\ Id.
---------------------------------------------------------------------------
197. Some commenters argue that the NOPR proposal would intrude on
authority over siting and construction of transmission facilities that
is reserved to the states under FPA section 201.\501\ For example,
Southern argues that the FPA reserves transmission siting authority to
the states and that the final order should not directly or indirectly
interfere with this authority.\502\ Alabama Commission argues that
Long-Term Regional Transmission Planning would interfere with state
authority to the extent it dictates the construction of facilities
through a top-down regional process.\503\ Kansas Ratepayer Advocates
state that the Commission would exceed its authority and violate
states' constitutional rights by ordering states to construct
interregional transmission facilities with construction costs paid by
retail ratepayers in Kansas.\504\
---------------------------------------------------------------------------
\501\ Alabama Commission Initial Comments at 7; Kansas Ratepayer
Advocates Reply Comments at 3; NARUC Initial Comments at 29; Nevada
Commission Initial Comments at 2-3; Southern Initial Comments at 21-
22.
\502\ Southern Initial Comments at 21-22.
\503\ Alabama Commission Initial Comments at 7.
\504\ Kansas Ratepayer Advocates Reply Comments at 3.
---------------------------------------------------------------------------
198. Nevada Commission explains that Nevada law governs the
issuance of permits to construct transmission facilities, and that such
facilities--even where their costs are not intended to be recovered
through retail rates--must go through and may not bypass that process
in favor of regional transmission planning processes.\505\ NARUC
contends that state participation in cost allocation for a portfolio of
Long-Term Regional Transmission Facilities does not require a state, in
its role as a transmission siting authority, to approve any projects
within the portfolio.\506\
---------------------------------------------------------------------------
\505\ Nevada Commission Initial Comments at 2-3.
\506\ NARUC Initial Comments at 29.
---------------------------------------------------------------------------
199. A few commenters argue that the NOPR proposal would intrude on
the authority over certain transmission planning allegedly reserved to
the states under FPA section 201. For example, Mississippi Commission
states that the final order must respect state jurisdictional authority
over planning and approval of transmission facilities used to serve
state load.\507\ Nevada Commission states that Nevada will continue to
plan for transmission through its integrated resource planning process
and that the Commission should allow ``bottom up'' transmission
planning, particularly in non-RTO/ISO transmission planning
regions.\508\
---------------------------------------------------------------------------
\507\ Mississippi Commission Initial Comments at 5 (citing
Mississippi Commission ANOPR Comments at 2, 17; NOPR, 179 FERC ]
61,028 (Christie, Comm'r, concurring at PP 2, 11-14)).
\508\ Nevada Commission Initial Comments at 6.
---------------------------------------------------------------------------
200. In contrast, other commenters express support for the
Commission's role in transmission planning. Ohio Consumers argue that
the Commission has authority over transmission planning, even in states
like Ohio that allow for retail consumer choice.\509\ SREA explains
that states and other jurisdictional regulators will continue to have
ultimate control over generation resource planning and transmission
planning, regardless of what a regional transmission body proposes.
SREA states that, even within RTO/ISO regions, ``transmission or
generation resource plans are subject to review, update or even
cancellation, and those decisions are always determined by the relevant
regulatory bodies.'' \510\ Vistra states that any final order should
recognize the legal and practical boundaries on the Commission's role
in transmission development and in shaping the generation sector.
According to Vistra, the Commission has successfully relied on its
general authority under FPA sections 205 and 206 to oversee rates,
terms, and conditions of jurisdictional service as the basis for its
policies on transmission planning.\511\
---------------------------------------------------------------------------
\509\ Ohio Consumers Initial Comments at 26 (citing New York v.
FERC, 535 U.S. at 23-24, 26-28).
\510\ SREA Reply Comments at 1-2.
\511\ Vistra Initial Comments at 4 & n.6.
---------------------------------------------------------------------------
201. Finally, Mississippi Commission argues that the NOPR proposal
may infringe upon states' reserved authority under FPA section 201 to
make resource adequacy decisions. Mississippi Commission explains that,
when an RTO/ISO approves construction to deliver generation output to
remote utilities that have failed to agree to purchase the energy, that
RTO/ISO infringes on the state's resource adequacy jurisdiction.\512\
Mississippi Commission contends that requiring State A to pay for
transmission upgrades to rely on energy generated in State B, despite
State A having constructed its own generation facilities, would usurp
State A's resource adequacy jurisdiction.\513\
---------------------------------------------------------------------------
\512\ Mississippi Commission Initial Comments at 5-6.
\513\ Id. at 13.
---------------------------------------------------------------------------
ii. ``Major Questions Doctrine''
202. Some commenters argue that the NOPR proposal would not
withstand judicial review under the major questions doctrine.\514\
---------------------------------------------------------------------------
\514\ Louisiana Commission Initial Comments at 6, 12-13; Ohio
Consumers Reply Comments at 14; SERTP Sponsors Initial Comments at
17-18; Southern Initial Comments at 20-21; Utah Commission Initial
Comments at 8-9; Undersigned States Reply Comments at 3-4.
---------------------------------------------------------------------------
203. Louisiana Commission claims that the NOPR proposal violates
principles of ``agency law'' and the separation of powers doctrine
because Congress has not clearly delegated to the Commission the
authority to enact far-reaching, nationwide policy changes favoring one
form of generation over another.\515\ Louisiana Commission
[[Page 49321]]
contends that the NOPR proposals exceed the limits of the FPA, which
does not provide clear delegated authority for the Commission to decide
types of generating resources. Louisiana Commission argues that the
Commission therefore lacks the authority to determine whether the
country should undergo a clean energy transition. Drawing parallels
between the NOPR proposal and the U.S. Supreme Court's decision in West
Virginia v. EPA, Louisiana Commission avers that the determination of
what type of generating resources should be transmitted from where in
the United States qualifies as a ``major question'' of public policy
that Congress should order.\516\
---------------------------------------------------------------------------
\515\ Louisiana Commission Initial Comments at 6.
\516\ Id. at 12 (citing 597 U.S. 697, 729-30, 735).
---------------------------------------------------------------------------
204. SERTP Sponsors argue that West Virginia v. EPA reinforces the
need for the Commission to exercise restraint in expanding its
jurisdiction without a clear Congressional delegation of
authority.\517\ According to SERTP Sponsors, West Virginia v. EPA makes
clear that the Nation's energy policy and generation mix is a ``major
question'' for which the Commission must have direct authorization from
Congress to assert jurisdiction.\518\ SERTP Sponsors contend that
Congress has not clearly provided the Commission with jurisdiction to
presuppose generation decisions and thereby effect particular
substantive transmission outcomes.\519\ Rather, SERTP Sponsors argue
that Congress instead expressly and unequivocally reserved generation
authority to the states.\520\
---------------------------------------------------------------------------
\517\ SERTP Sponsors Initial Comments at 17 (citing West
Virginia v. EPA, 597 U.S. at 723); see also EEI Initial Comments at
8 (urging the Commission to consider the overlap of the Commission's
and state commissions' respective jurisdictions).
\518\ SERTP Sponsors Initial Comments at 17-18.
\519\ Id. at 18.
\520\ Id.
---------------------------------------------------------------------------
205. Southern similarly argues that West Virginia v. EPA makes
clear that the Nation's energy policy and generation mix is a ``major
question'' that requires more than a ``merely plausible textual basis''
for a Federal agency to assert jurisdiction.\521\ Southern contends
that, as applied to the NOPR proposal's ``contemplated foray into
[integrated resource planning] and generation/resource matters,'' the
Commission does not rely upon a specific and clear grant of
congressional authorization but instead relies upon its ``general, gap-
filling authorization in FPA Section 206 to regulate a `practice'
affecting a rate or charge for transmission.'' \522\ Southern contends
that rather than provide clear congressional authorization, Congress
instead reserved authority over integrated resource plans and
generation to the states.\523\
---------------------------------------------------------------------------
\521\ Southern Initial Comments at 20-21 (citing West Virginia
v. EPA, 597 U.S. at 723).
\522\ Id.
\523\ Id. at 21.
---------------------------------------------------------------------------
206. Utah Commission argues that the Commission has no authority to
enact any rule for the purpose of influencing the resource generation
mix or expanding development of any type of generation. Utah Commission
states that the increased development and integration of renewable
generation is a ``highly charged political question and a matter of
significant political interest about which state legislatures have made
very different policy choices.'' As such, Utah Commission argues that,
although courts have given the Commission ``some latitude under FPA
Section 206,'' the U.S. Supreme Court will not uphold a final order
premised upon the Commission's ``claimed authority to prescribe a
single, onerous national regime for transmission planning specifically
intended to pressure transmission providers to select costly expansions
into remote areas for the purpose of realizing [the Commission's]
preferred generation mix, a matter specifically reserved to the
states.'' \524\ Utah Commission explains that the Supreme Court's
reasoning in West Virginia v. EPA is applicable to the Commission. Utah
Commission argues that ``imposing a single set of federally mandated,
highly prescriptive transmission planning and cost allocation
requirements for the purpose of privileging the selection of costly
transmission projects to serve remote and speculative renewable
generation is not a lawful exercise of [the Commission's] authority
under FPA Section 206.'' \525\
---------------------------------------------------------------------------
\524\ Utah Commission Initial Comments at 8.
\525\ Id. at 8-9 (citing West Virginia v. EPA, 597 U.S. at 729-
30).
---------------------------------------------------------------------------
207. Undersigned States argue that ``[n]ational-scale energy grid
regulation'' is a ``major question'' because of the ``massive economic
consequences'' involved and the implication of a ``unique and complex
jurisdictional divide between [s]tate and federal regulatory
authority.'' \526\ According to Undersigned States, the Commission
``has no statutory authority at all--much less `clear congressional
authorization'--to revamp the energy grid's mix of generation resources
writ large.'' \527\
---------------------------------------------------------------------------
\526\ Undersigned States Reply Comments at 3 (citing West
Virginia v. EPA, 597 U.S. 697; Ala. Ass'n of Realtors v. HHS, 594
U.S. 758, 764 (2021)).
\527\ Id. at 4 (quoting West Virginia v. EPA, 597 U.S. at 723).
---------------------------------------------------------------------------
208. Harvard ELI and Policy Integrity disagree with Undersigned
States. They argue that Undersigned States ``mischaracterize the NOPR''
because the NOPR would not revamp the energy grid's mix of generation
resources. Rather, according to Harvard ELI and Policy Integrity, the
NOPR would require utilities to amend their existing regional
transmission planning processes in response to changes in the resource
mix and demand that are occurring because of factors unrelated to the
NOPR.\528\
---------------------------------------------------------------------------
\528\ Harvard ELI and Policy Integrity Supplemental Comments at
2.
---------------------------------------------------------------------------
209. Harvard ELI and Policy Integrity also contend that Undersigned
States overlook the major questions doctrine's key requirements. They
assert that application of the major questions doctrine does not turn
on whether a regulation will have significant economic effects or
intrudes on areas traditionally regulated by states. Instead, Harvard
ELI and Policy Integrity assert that the major questions doctrine is
triggered only when an agency's action is both unheralded and
transformative.\529\
---------------------------------------------------------------------------
\529\ Id. at 2-3.
---------------------------------------------------------------------------
210. Harvard ELI and Policy Integrity argue that the NOPR is not
unheralded. They explain that Order No. 1000 similarly regulated
transmission planning and cost allocation in response to concerns about
the generation mix, and that the D.C. Circuit upheld Order No. 1000
while rejecting arguments similar to those that Undersigned States make
here.\530\ Moreover, Harvard ELI and Policy Integrity identify
provisions in existing tariffs that are similar to those that the NOPR
proposes and point to other antecedents for Commission regulation of
regional transmission planning.\531\
---------------------------------------------------------------------------
\530\ Id. at 4 (citing S.C. Pub. Serv. Auth. v. FERC, 762 F.3d
at 48-49; Order No. 1000, 136 FERC ] 61,051 at PP 45, 47).
\531\ Id. at 4-5; id. app. A.
---------------------------------------------------------------------------
211. Likewise, Harvard ELI and Policy Integrity argue that the NOPR
does not represent a transformative expansion in the Commission's
authority nor a ``fundamental change to the statutory scheme.'' \532\
Instead, they assert that the NOPR merely builds on existing regional
transmission planning processes to ensure that Commission-
jurisdictional rates remain just and reasonable, as the FPA
requires.\533\
---------------------------------------------------------------------------
\532\ Id. at 6-7 (quoting West Virginia v. EPA, 597 U.S. at 723
(internal quotations omitted)).
\533\ Id.
---------------------------------------------------------------------------
[[Page 49322]]
iii. ``Equal Sovereignty Doctrine''/Cross-Subsidization
212. Some commenters argue that the NOPR's cost allocation proposal
impermissibly requires states to subsidize other states' public
policies.\534\ Undersigned States argue that the NOPR would exceed the
Commission's jurisdiction because it violates the Constitution's equal
sovereignty doctrine, which provides constitutional equality among the
states.\535\ According to Undersigned States, the NOPR ``sets up a
scheme where one [s]tate can effectively require other [s]tates to
subsidize their own vision of what resources should be used in
electricity generation--a core, sovereign [s]tate function,'' which
risks ``undue discrimination'' among states.\536\ Mississippi
Commission argues that unanimous agreement, rather than majority
agreement, would be required for any ex ante default cost allocation
method, as each state has sole jurisdiction within its boundaries.\537\
---------------------------------------------------------------------------
\534\ Alabama Commission Initial Comments at 9; Louisiana
Commission Initial Comments at 29; Mississippi Commission Reply
Comments at 3; Ohio Commission Federal Advocate Initial Comments at
4-5; Ohio Consumers Reply Comments at 14.
\535\ Undersigned States Reply Comments at 5-6 (citing Coyle v.
Smith, 221 U.S. 559, 567 (1911)).
\536\ Id. at 6 (citing NOPR, 179 FERC ] 61,018, Danly, Comm'r,
dissenting, at PP 4-5).
\537\ Mississippi Commission Reply Comments at 2-3.
---------------------------------------------------------------------------
213. Louisiana Commission asserts that ``group state oversight'' is
not equivalent to ``state oversight,'' and that the Commission should
not adopt a rule that subjects one state's will to majority override.
Louisiana Commission further argues that the Commission should not
enact rules that would ``impose costs for projects selected under the
proposed long-term planning criteria on unwilling states that do not
benefit from those projects, even if those states are in the
minority.'' Louisiana Commission contends that the Commission should
not attempt to override state jurisdiction simply because a majority of
states in a region may support imposing costs on unwilling states that
do not benefit from transmission projects favored by the majority.\538\
Louisiana Commission argues that states should not be required to cede
their jurisdiction by engaging in any ``consulting'' committee
structure required with respect to Long-Term Regional Transmission
Planning,\539\ because granting each state one vote in a multi-state
body cannot replace the meaningful exercise of state jurisdiction
within a state's borders.\540\
---------------------------------------------------------------------------
\538\ Louisiana Commission Initial Comments at 27-28; Louisiana
Commission Reply Comments at 14-16.
\539\ Louisiana Commission Initial Comments at 28-29.
\540\ Louisiana Commission Reply Comments at 16.
---------------------------------------------------------------------------
214. Conversely, ACEG disputes these claims, which ACEG states are
``incorrect and misconstrue the NOPR.'' \541\ ACEG highlights the fact
that the NOPR does not include resource preferences in its proposed
planning criteria, factors, or benefits, nor does the NOPR exclude
consideration of non-renewable resources from transmission
planning.\542\ ACEG further notes that the NOPR proposes to direct
transmission planners to plan the system to ``meet transmission needs
driven by changes in the resource mix and demand,'' requiring
transmission planners to consider the resource mix as a whole, which
necessarily requires considering all types of resources.\543\ New
Jersey Commission agrees, stating that the Commission did not propose
in the NOPR ``to unduly favor, mandate, or subsidize forms of
generation,'' but rather ``to ensure that the bulk electricity system
maintains reliability and satisfies evolving consumer demands, whether
driven by public policy requirements or voluntary goals, at the lowest
reasonable cost.'' \544\ Moreover, New Jersey Commission argues,
allocating the cost of Long-Term Regional Transmission Facilities only
to those states with relevant public policy goals ``would allow the
remaining states to free ride, and effectively force the states with
public policy goals to subsidize the provision of normal electricity
service in other states in order to pursue their own policies.'' \545\
---------------------------------------------------------------------------
\541\ ACEG Reply Comments at 18.
\542\ Id. at 18-19.
\543\ Id. at 19.
\544\ New Jersey Commission Initial Comments at 3.
\545\ Id. at 20.
---------------------------------------------------------------------------
i. Other Issues
215. NRECA requests that the Commission clarify that the final
order, consistent with the Commission's obligation under FPA section
217(b)(4), ``is intended to facilitate and support `bottom-up'
transmission planning to meet the transmission needs of [load-serving
entities] to provide reliable and economical service to consumers.''
\546\
---------------------------------------------------------------------------
\546\ NRECA Initial Comments at 17-21.
---------------------------------------------------------------------------
216. Some commenters argue that the final order will not withstand
judicial scrutiny if it does not permit regional flexibility.\547\ For
example, US Chamber of Commerce explains that the interstate power grid
includes investor-owned utilities, publicly-owned utilities, and
electric cooperatives, which can be members of RTOs/ISOs, power pooling
arrangements, joint-ownership agreements, or subject to traditional
vertically-integrated structures.\548\ According to US Chamber of
Commerce, imposing a new regional transmission planning regime on all
these various entities would ignore the compromises and benefits that
led to the status quo.\549\ Relatedly, Southern and SERTP Sponsors
argue that the legal viability of the final order will be threatened if
the Commission fails to respect the FPA's fundamental jurisdictional
roles by not providing states and transmission providers with the
opportunity and flexibility to adapt their planning processes.\550\
---------------------------------------------------------------------------
\547\ SERTP Sponsors Initial Comments at 1; SERTP Sponsors Reply
Comments at 1-2; Southern Initial Comments at 1; Southern Reply
Comments at 3; US Chamber of Commerce Initial Comments at 4.
\548\ US Chamber of Commerce Initial Comments at 4.
\549\ Id.
\550\ Southern Initial Comments at 1; Southern Reply Comments at
3; SERTP Sponsors Initial Comments at 1; SERTP Sponsors Reply
Comments at 1-2.
---------------------------------------------------------------------------
j. Miscellaneous Concerns
217. MISO seeks clarification from the Commission that the term
``transmission planning region'' has the same meaning as in Order No.
1000, where MISO may comprise a single transmission planning region
despite including multiple transmission zones or local balancing
authorities.\551\
---------------------------------------------------------------------------
\551\ MISO Initial Comments at 24.
---------------------------------------------------------------------------
218. California Municipal Utilities state that transmission
planning should not be a vehicle to centralize resource choices, but
instead should reflect the choices made by state and local
authorities.\552\ Similarly, Mississippi Commission argues that Long-
Term Regional Transmission Planning should be driven by state-specific
concerns and needs and that regional priorities should be subordinated
to state priorities.\553\ Mississippi Commission asks that the
Commission not issue a final order but instead establish proceedings to
address specific concerns with certain regional transmission planning
processes on a more limited basis.\554\ Southern argues that Long-Term
Regional Transmission Facilities in non-RTO/ISO transmission planning
regions must have the support of affected states, as these facilities
stem from resource and load assumptions that are not the result of
those states' planning and procurement processes.\555\ Southern urges
the Commission to maintain the appropriate transmission
[[Page 49323]]
planning and state-driven supply- and demand-side relationships, which
Order No. 1000 preserved.\556\ SERTP Sponsors argue that the Commission
should avoid mandates that could largely result in transmission
expansion or infrastructure decisions that lead to investments borne,
largely, by retail electricity consumers that lack the consent and
support of the state authorities vested with the responsibility to
protect those consumers.\557\
---------------------------------------------------------------------------
\552\ California Municipal Utilities Reply Comments at 2.
\553\ Mississippi Commission Initial Comments at 3.
\554\ Id. at 9.
\555\ Southern Initial Comments at 8.
\556\ Id. at 12.
\557\ SERTP Sponsors Initial Comments at 6-7.
---------------------------------------------------------------------------
219. Several commenters agree with the Commission that any final
order should apply to transmission providers in both RTO/ISO and non-
RTO/ISO transmission planning regions.\558\ However, several commenters
disagree and argue that the final order, or certain specified
requirements in the final order, should apply only to RTO/ISO
transmission planning regions.\559\ Nevada Commission argues that the
RTOs/ISOs ``may be better suited'' than other regions for the
transmission planning that the NOPR proposes.\560\ Utah Division of
Public Utilities stresses the need for regional flexibility, noting
that transmission providers located outside of RTOs/ISOs already
coordinate on transmission planning with many non-Commission-
jurisdictional entities.\561\
---------------------------------------------------------------------------
\558\ See, e.g., AEE Reply Comments at 11; MISO Reply Comments
at 3; PIOs Reply Comments at 2-3; SEIA Reply Comments at 5; SREA
Initial Comments at 47; TAPS Initial Comments at 70.
\559\ See, e.g., Mississippi Commission Initial Comments at 16;
Utah Division of Public Utilities Reply Comments at 1-2.
\560\ Nevada Commission Initial Comments at 2-4.
\561\ Utah Division of Public Utilities Reply Comments at 1-2.
---------------------------------------------------------------------------
220. SEIA rebuts the claims of Southern and Louisiana, Utah,
Mississippi, and Alabama Commissions that state planning processes
already interact well with transmission planning and support customers'
transmission needs.\562\ SEIA and SREA assert that non-RTO/ISO
transmission planning regions do not engage in sufficient or
transparent transmission planning.\563\ Specifically, SEIA states, the
transmission planning processes in non-RTO/ISO regions are rife with
issues, including the use of inconsistent and inaccurate data and an
exclusionary and insufficiently transparent process.\564\ Further, SEIA
states that the end result of an integrated resource planning process
may be based on inconsistent and inaccurate data,\565\ the process is
``sometimes disjointed,'' \566\ and the process is a voluntary process
in which the planning authority must accept, and not verify, the
information provided.\567\
---------------------------------------------------------------------------
\562\ SEIA Reply Comments at 5.
\563\ Id.; SREA Reply Comments at 15-17.
\564\ SEIA Reply Comments at 5-6.
\565\ Id. at 5 (citing Western PIOs Initial Comments at 10).
\566\ Id. (citing PacifiCorp and NV Energy Initial Comments at
10).
\567\ Id. (citing PacifiCorp and NV Energy Initial Comments at
13; Western PIOs Initial Comments at 11).
---------------------------------------------------------------------------
221. SREA rebuts Southern's contention that Southern's transmission
planning processes are adequate, noting that Southern itself has
presented testimony to the Georgia Commission conceding that it is
unable to perform more robust transmission planning due to limitations
in its software and models.\568\ SREA argues that throughout the
Southeast, transmission planning is not a priority and that integrated
resource planning is not a substitute for robust transmission
planning.\569\ SREA explains that the NOPR borrows many of the
qualities of integrated resource planning and applies them to
transmission planning, including scenario-based evaluation and use of
20-year planning horizons, and that many states have integrated
resource planning rules and guidelines that recognize the value of
long-term planning.\570\
---------------------------------------------------------------------------
\568\ SREA Reply Comments at 7 (citing SREA Initial Comments,
attach. B (Testimony of Georgia Power Witness Robinson) at 282-283).
\569\ Id. at 5.
\570\ Id.
---------------------------------------------------------------------------
222. EPSA states that the Commission should focus not on
socializing transmission costs but on reducing transaction costs,
accelerating lagging processes, and adopting market-based solutions
like open seasons.\571\
---------------------------------------------------------------------------
\571\ EPSA Initial Comments at 7-8.
---------------------------------------------------------------------------
223. GridLab states that there is evidence to suggest that changes
in resource mix, demand, and weather will lead to significant changes
in the value of regional transmission facilities in the 2030s, though
GridLab asserts that these changes may increase or decrease the value
of regional transmission facilities. Accordingly, GridLab recommends
that the Commission and stakeholders resist evaluating the success of
this rulemaking based on arbitrary metrics related to each transmission
provider's expansion of regional transmission facilities.\572\
---------------------------------------------------------------------------
\572\ GridLab Initial Comments at 9-10.
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3. Commission Determination
a. Participation in Long-Term Regional Transmission Planning
224. We adopt the NOPR proposal to require transmission providers
in each transmission planning region to participate in a regional
transmission planning process that includes Long-Term Regional
Transmission Planning, meaning regional transmission planning on a
sufficiently long-term, forward-looking, and comprehensive basis to
identify Long-Term Transmission Needs, identify transmission facilities
that meet such needs, measure the benefits of those transmission
facilities, and evaluate those transmission facilities for potential
selection in the regional transmission plan for purposes of cost
allocation as the more efficient or cost-effective transmission
facilities to meet Long-Term Transmission Needs.\573\ We also adopt the
NOPR proposal to require that Long-Term Regional Transmission Planning
comply with the following existing Order Nos. 890 and 1000 transmission
planning principles: (1) coordination; (2) openness; (3) transparency;
(4) information exchange; (5) comparability; and (6) dispute
resolution.\574\ In developing their compliance filings, transmission
providers and stakeholders should review the requirements set forth in
Order No. 890 and Order No. 1000, and the Commission's orders on
compliance filings submitted by transmission providers, for guidance as
to what each of these transmission planning principles requires. For
example, as a starting point, a transmission provider should review the
orders addressing its own Order Nos. 890 and 1000 compliance filings
and the compliance filings for transmission providers in its
transmission planning region.
---------------------------------------------------------------------------
\573\ We note that, while we have modified this definition of
Long-Term Regional Transmission Planning from the NOPR proposal, the
modified definition does not substantively change the steps involved
in Long-Term Regional Transmission Planning from those proposed in
the NOPR. Rather, the revised definition merely clariies the steps
that transmission providers must take in conducting Long-Term
Regional Transmission Planning.
\574\ Order No. 1000, 136 FERC ] 61,051 at PP 146, 151. We do
not address these principles in detail here.
---------------------------------------------------------------------------
225. We also adopt specific requirements regarding how transmission
providers must conduct Long-Term Regional Transmission Planning.
Specifically, and as discussed further below, we require transmission
providers in each transmission planning region \575\ to: (1) identify
Long-Term
[[Page 49324]]
Transmission Needs and Long-Term Regional Transmission Facilities to
meet those needs through the development of Long-Term Scenarios \576\
that satisfy the requirements set forth in this final order; (2) use
and measure, at a minimum, a set of seven required benefits \577\ to
evaluate Long-Term Regional Transmission Facilities over a time horizon
that covers, at a minimum, 20 years starting from the estimated in-
service date of each transmission facility; and (3) evaluate Long-Term
Regional Transmission Facilities to determine whether they are more
efficient or cost-effective transmission solutions to meet Long-Term
Transmission Needs and use selection criteria (in collaboration with
states and other stakeholders) that provide the opportunity for
transmission providers to select such Long-Term Regional Transmission
Facilities.
---------------------------------------------------------------------------
\575\ In response to MISO's request, MISO Initial Comments at
24, we clarify that this final order does not alter the meaning of
``transmission planning region'' as used in Order No. 1000. A
transmission planning region is one in which transmission providers,
in consultation with stakeholders and affected states, have agreed
to participate for purposes of regional transmission planning and
development of a single regional transmission plan. Order No. 1000-
A, 139 FERC ] 61,132 at P 272; Order No. 1000, 136 FERC ] 61,051 at
P 160.
\576\ The requirements related to Long-Term Scenarios are
discussed below.
\577\ As discussed further below in the Evaluation of the
Benefits of Regional Transmission Facilities section, these seven
benefits are: (1) Benefit 1, Avoided or Deferred Reliability
Transmission Facilities and Aging Transmission Infrastructure
Replacement; (2) Benefit 2(a), Reduced Loss of Load Probability, or
Benefit 2(b), Reduced Planning Reserve Margin; (3) Benefit 3,
Production Cost Savings; (4) Benefit 4, Reduced Transmission Energy
Losses; (5) Benefit 5, Reduced Congestion Due to Transmission
Outages; (6) Mitigation of Extreme Weather Events and Unexpected
System Conditions; and (7) Capacity Cost Benefits from Reduced Peak
Energy Losses.
---------------------------------------------------------------------------
226. These requirements together establish a long-term, forward-
looking, and more comprehensive approach to regional transmission
planning, which will ensure that transmission providers identify,
evaluate, and select more efficient or cost-effective transmission
solutions to address Long-Term Transmission Needs. Long-Term Regional
Transmission Planning, as set forth in this final order, requires
regional transmission planning based on a multitude of drivers of Long-
Term Transmission Needs and provides the opportunity for transmission
providers to meet those needs by selecting more efficient or cost-
effective Long-Term Regional Transmission Facilities.
227. In considering the comments received on this proposal, we
strike a careful balance. On the one hand, we believe that there is an
inherent risk in transmission providers waiting for the near-term
certainty that some commenters appear to believe is necessary \578\
before planning to address transmission needs. As explained in the
Overall Need for Reform section above, doing so may result in
transmission providers relying on relatively inefficient and less cost-
effective piecemeal transmission solutions to address these needs
shortly before they manifest, to the detriment of customers. On the
other hand, we acknowledge the inherent uncertainty involved in
planning to meet Long-Term Transmission Needs and that this uncertainty
means that forward-looking regional transmission planning entails
certain risks, including the risk that transmission needs may change
over time. In this final order, we balance these risks, requiring
planning to meet Long-Term Transmission Needs, while imposing
requirements on how Long-Term Regional Transmission Planning is
conducted, as discussed further herein, to mitigate uncertainty. To
adequately prepare for the future, transmission providers need to make
decisions in the present that are grounded in a thorough, informed
analysis of the factors that drive Long-Term Transmission Needs.
---------------------------------------------------------------------------
\578\ See, e.g., NRG Initial Comments at 8 (arguing that there
are unliekly to be any ``no regrets'' options).
---------------------------------------------------------------------------
228. As discussed in the Overall Need for Reform section, these
factors are together driving rapid changes in the Long-Term
Transmission Needs that transmission providers must plan to meet to
continue to provide an affordable, reliable supply of electricity to
customers, but neither transmission infrastructure nor regional
transmission planning processes are keeping pace. Consequently, the
Commission's existing regional transmission planning requirements are
no longer just and reasonable, as they increasingly result in
transmission investment decisions occurring outside of regional
transmission planning processes and instead through generator
interconnection processes and local transmission planning processes
that typically plan to meet discrete, nearer-term transmission needs.
In addition, the record demonstrates that transmission providers have
made substantial investments in in-kind replacement transmission
facilities, which generally are not identified through more long-term,
forward-looking, or comprehensive transmission planning. This final
order aims to ensure that transmission providers, through their
regional transmission planning processes, identify, evaluate, and
select Long-Term Regional Transmission Facilities that more efficiently
or cost-effectively address Long-Term Transmission Needs, helping to
ensure just and reasonable rates.
229. We disagree with arguments that the Commission should not
require Long-Term Regional Transmission Planning because, certain
commenters claim, doing so will introduce excessive uncertainty into
regional transmission planning, transmission providers will make
forecasting errors, or the final order will result in regional
transmission planning that is speculative.\579\ To the contrary, we
believe that the reforms adopted in this final order account for and
seek to reduce the inherent uncertainty in forward-looking regional
transmission planning, while ensuring that transmission providers,
through their regional transmission planning processes, identify,
evaluate, and select Long-Term Regional Transmission Facilities that
more efficiently or cost-effectively address Long-Term Transmission
Needs, thus helping to ensure just and reasonable rates.\580\ In fact,
by requiring transmission providers to use Long-Term Scenarios in Long-
Term Regional Transmission Planning, this final order provides
transmission providers with a critical tool for managing uncertainty,
facilitating regional transmission planning that accounts for a range
of potential futures, as well as an assessment of the likelihood of
each scenario manifesting, when identifying, evaluating, and selecting
Long-Term Regional Transmission Facilities. Further, as discussed in
the Evaluation and Selection of Long-Term Regional Transmission
Facilities section below, we require transmission providers to
reevaluate Long-Term Regional Transmission Facilities in certain
circumstances, which will provide transmission providers with yet
another such tool.
---------------------------------------------------------------------------
\579\ Louisiana Commission Initial Comments at 4-5; NRG Initial
Comments at 3-4; Ohio Consumers Initial Comments at 5.
\580\ See Policy Integrity Initial Comments at 6 (arguing that
future uncertainty requires scenario planning).
---------------------------------------------------------------------------
230. Moreover, notwithstanding allegations to the contrary, we
believe that Long-Term Regional Transmission Planning is a logical and
reasonable extension of current regional transmission planning
processes, which also manage uncertainty and plan for future regional
transmission needs. The key difference, which we address through this
final order, is that these existing regional transmission planning
processes are conducted in a manner that is not sufficiently long-term,
forward-looking, or comprehensive such that transmission providers are
not identifying Long-Term Transmission Needs. As a result, transmission
providers are failing to identify or evaluate regional transmission
facilities that would more efficiently or cost-effectively address
those Long-Term Transmission Needs, and consequently,
[[Page 49325]]
are missing the opportunity to select such regional transmission
facilities. Our reforms in this final order remedy these deficiencies.
231. Further, we believe that Long-Term Regional Transmission
Planning as set forth in this final order provides adequate safeguards
against excessive transmission development in response to speculative
transmission needs. For example, this final order requires transmission
providers to develop multiple plausible and diverse Long-Term Scenarios
based upon best available data, which will allow transmission providers
to better understand how certain categories of factors will give rise
to Long-Term Transmission Needs, and requires transmission providers to
update their assumptions periodically, as discussed further below.\581\
In developing these Long-Term Scenarios, transmission providers are
required to treat more certain drivers of Long-Term Transmission Needs
differently than less certain drivers, and must provide opportunities
for stakeholder engagement. Further, the final order grants substantial
flexibility to transmission providers to develop an evaluation process
and selection criteria that will provide them with the opportunity to
select Long-Term Regional Transmission Facilities in a way that
maximizes benefits accounting for costs over time without over-building
transmission facilities. Consistent with the existing Order No. 1000
regional transmission planning processes, the final order does not
require transmission providers to select any regional transmission
facilities as part of Long-Term Regional Transmission Planning.
Finally, we require transmission providers to reevaluate previously
selected Long-Term Regional Transmission Facilities in certain
circumstances, as discussed further below in the Reevaluation section.
---------------------------------------------------------------------------
\581\ See New Jersey Commission Initial Comments at 10-11.
---------------------------------------------------------------------------
232. The regional transmission planning and cost allocation
requirements in this final order, like those of Order Nos. 890 and
1000, are focused on the transmission planning process, and do not
require any substantive outcomes from this process.\582\ We disagree
with certain commenters' assertions that this final order favors,
promotes, or subsidizes particular types of generation resources over
others, or otherwise engages in generation planning.\583\ Instead, this
final order requires transmission providers to participate in Long-Term
Regional Transmission Planning through their regional transmission
planning process that identifies Long-Term Transmission Needs,
evaluates the benefits of Long-Term Regional Transmission Facilities to
meet those needs, and provides the opportunity for transmission
providers to select Long-Term Regional Transmission Facilities that are
more efficient or cost-effective transmission solutions to those needs.
We reiterate that, as discussed below in the Evaluation and Selection
of Long-Term Regional Transmission Facilities section, any selected
Long-Term Regional Transmission Facilities must satisfy transmission
provider-developed selection criteria that maximize benefits accounting
for costs over time without over-building transmission facilities,
which ensures that the costs of such transmission facilities are
outweighed by the benefits they deliver to customers.
---------------------------------------------------------------------------
\582\ See, e.g., Order No. 1000, 136 FERC ] 61,051 at P 12.
\583\ Alabama Commission Initial Comments at 7-8; Louisiana
Commission Initial Comments at 12, 19-21; Potomac Economics Initial
Comments at 3-4; Utah Division of Public Utilities Initial Comments
at 2; Vistra Initial Comments at 11.
---------------------------------------------------------------------------
233. We disagree with commenters that argue that the factors giving
rise to Long-Term Transmission Needs, such as state laws dictating
specific generation resource mixes, are irreconcilable with effective
transmission planning.\584\ These changes are occurring independent of
any action that we take in this final order, and they are being driven
by a wide variety of factors. This final order provides transmission
providers with the tools that they need to respond to these factors,
requiring that they conduct Long-Term Regional Transmission Planning to
identify, evaluate, and select Long-Term Regional Transmission
Facilities that are more efficient or cost-effective regional
transmission solutions to the Long-Term Transmission Needs that these
factors drive.
---------------------------------------------------------------------------
\584\ See ELCON Initial Comments at 9 (``ELCON has always
believed that planning for disparate state energy priorities is at
odds with market-driven, efficient, and cost-effective transmission
planning.'').
---------------------------------------------------------------------------
234. We disagree with Louisiana Commission and former Kansas
Commission Chairman Keen's claims that Long-Term Regional Transmission
Planning will threaten the reliability of the transmission system. We
acknowledge that reliability needs are evolving; for example, the
increasing frequency and severity of high-impact extreme weather events
threatens grid reliability. We believe that Long-Term Regional
Transmission Planning--in addition to existing Order No. 1000 regional
transmission planning and cost allocation requirements--is needed to
support the reliable operation of transmission systems, given these
changes. As the Commission and the North American Electric Reliability
Corporation have noted, the transmission system may not be adequately
prepared for extreme weather events and the increasing frequency of
these events must be planned for to ensure system reliability.\585\ We
thus view our action in this final order as complementary to other
steps that the Commission has taken in recent years to bolster system
reliability.\586\
---------------------------------------------------------------------------
\585\ FERC, North American Electric Reliability Corporation,
Winter Storm Elliot Report: Inquiry into Bulk-Power System
Operations During December 2022 (Nov. 2023), https://www.ferc.gov/media/winter-storm-elliott-report-inquiry-bulk-power-system-operations-during-december-2022; FERC, North American Electric
Reliability Corporation, The February 2021 Cold Weather Outages in
Texas and the South Central United States (Nov. 2021), https://www.ferc.gov/media/february-2021-cold-weather-outages-texas-and-south-central-united-states-ferc-nerc-and.
\586\ See, e.g., Transmission Sys. Planning Performance
Requirements for Extreme Weather, Order No. 896, 88 FR 41262 (June
23, 2023), 183 FERC ] 61,191 (2023); One-Time Info. Reports on
Extreme Weather Vulnerability Assessments, Order No. 897, 88 FR
41447 (June 27, 2023), 183 FERC ] 61,192 (2023).
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235. Further, we disagree with the contention of Louisiana
Commission and Vistra that Long-Term Regional Transmission Planning
will distort the efficient functioning of Commission-jurisdictional
wholesale markets by subsidizing uneconomic generation or by distorting
price signals. As discussed further below, we require transmission
providers, as part of Long-Term Regional Transmission Planning, to
assess the costs and measure the benefits of regional transmission
facilities that address Long-Term Transmission Needs and to develop
evaluation processes and selection criteria that provide the
opportunity to select those transmission facilities as more efficient
or cost-effective regional transmission solutions to those Needs. While
the addition of any new transmission facility necessarily affects
Commission-jurisdictional wholesale markets, the requirements set forth
in this final order ensure that transmission providers will have the
opportunity to select more efficient or cost-effective Long-Term
Regional Transmission Facilities that provide value to transmission
customers and support the efficient functioning of wholesale markets by
addressing Long-Term Transmission Needs.
[[Page 49326]]
236. We also disagree with Vistra's contention that Long-Term
Regional Transmission Planning somehow will assign all, or a
disproportionately high share, of interconnection-related network
upgrade costs to load or undermine the incentives for generation
developers to site new generation resources in ways that minimize
transmission system upgrade costs. Rather, because transmission
providers will now engage in Long-Term Regional Transmission Planning
to identify, evaluate, and select more efficient or cost-effective
regional transmission facilities to address Long-Term Transmission
Needs, Long-Term Regional Transmission Facilities will be planned in a
more efficient and cost-effective manner than if transmission
facilities meeting a narrower set of transmission needs were left to be
identified through the generator interconnection process. Indeed,
numerous commenters explain that the piecemeal expansion of the
transmission system is highly inefficient and results in higher costs
for transmission customers,\587\ in part because the costs of
interconnection-related network upgrades ultimately are passed on to
consumers.
---------------------------------------------------------------------------
\587\ See, e.g., NYISO Initial Comments at 30; PIOs Initial
Comments at 9-10.
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237. We strike another careful balance in this final order. On the
one hand, we recognize transmission providers' need for sufficient
flexibility to implement Long-Term Regional Transmission Planning in
their transmission planning regions to reflect regional differences,
such as different market structures.\588\ On the other hand, we must
ensure that transmission providers' regional transmission planning
processes result in just and reasonable rates, which, as discussed
above in the Overall Need for Reform section, necessitates that they
plan on a sufficiently long-term, forward-looking, and comprehensive
basis such that transmission providers are identifying, evaluating, and
selecting more efficient or cost-effective regional transmission
facilities to address Long-Term Transmission Needs. We believe that the
balance struck in the final order will ensure that Commission-
jurisdictional rates are just and reasonable and not unduly
discriminatory or preferential and, thus, we reject requests for
flexibility that exceeds that provided in this final order.
---------------------------------------------------------------------------
\588\ The Commission also recognized the need for sufficient
flexibility in regional transmission planning to reflect regional
differences in Order No. 1000. See Order No. 1000, 136 FERC ] 61,051
at P 61.
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238. In particular, we reject requests that, instead of requiring
transmission providers to implement Long-Term Regional Transmission
Planning in accordance with the requirements adopted in this final
order, we set forth principles and objectives articulating our concerns
with existing regional transmission planning processes and give
transmission providers the flexibility to propose revisions to their
processes to address those concerns.\589\ Having found existing
regional transmission planning and cost allocation requirements to be
unjust and unreasonable, we have an obligation under FPA section 206 to
adopt reforms that remedy the deficiencies identified in this final
order. We also believe that such an approach would fail to adequately
address the deficiencies described above in the Overall Need for Reform
section, namely that transmission providers are not currently required
to: (1) perform a sufficiently long-term assessment of transmission
needs that identifies Long-Term Transmission Needs; (2) adequately
account on a forward-looking basis for known determinants of Long-Term
Transmission Needs; and (3) consider the broader set of benefits of
regional transmission facilities planned to meet those Long-Term
Transmission Needs. We further believe that establishing requirements
rather than principles will ensure a sufficiently robust process for
Long-Term Regional Transmission Planning while providing sufficient
clarity about that process to avert conflict among stakeholders, as
noted by AEP.\590\
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\589\ ISO-NE Initial Comments at 20; ISO RTO Council Initial
Comments at 4-5, 8-9; MISO Initial Comments at 22-23.
\590\ AEP Reply Comments at 2-4.
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239. We also disagree with commenters that argue that this final
order should apply to only RTO/ISO transmission planning regions. The
Commission's existing regional transmission planning requirements,
which, as described above in the Overall Need for Reform section, we
find to be deficient, apply in RTO/ISO and non-RTO/ISO transmission
planning regions alike; without the Long-Term Regional Transmission
Planning Requirements adopted herein, transmission providers in both
RTO/ISO and non-RTO/ISO transmission planning regions will continue to
be at risk of undertaking investments in relatively inefficient or less
cost-effective transmission infrastructure, the costs of which are
ultimately recovered through Commission-jurisdictional rates.
Accordingly, while we acknowledge differences between RTO/ISO and non-
RTO/ISO transmission planning regions, we find that transmission
providers in all transmission planning regions must implement Long-Term
Regional Transmission Planning as required in this final order to
ensure that Commission-jurisdictional rates are just and reasonable and
not unduly discriminatory or preferential. Additionally, we note that
many of the requirements established in this final order provide for
regional flexibility, including, but not limited to, the requirements
to develop Long-Term Scenarios, determine which factors in each
required category of factors do not affect Long-Term Transmission Needs
and need not be considered, develop methods to measure the benefits of
Long-Term Regional Transmission Facilities, design an evaluation
process and selection criteria, and establish a Long-Term Regional
Transmission Cost Allocation Method.
240. We acknowledge that certain transmission planning regions
already conduct some regional transmission planning on a relatively
forward-looking, proactive basis. We do not intend to undermine
progress made in these transmission planning regions, and our goal is
to set a floor, not a ceiling. We decline to prejudge whether any
existing regional transmission planning process meets the requirements
set forth in this final order and accordingly reject requests that we
do so.\591\ We note that, if a transmission provider believes that it
participates in a regional transmission planning process that fulfills
the requirements adopted in this final order, it may describe in its
compliance filing how its process meets these requirements.
---------------------------------------------------------------------------
\591\ See, e.g., Ameren Initial Comments at 8.
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241. We expect Long-Term Regional Transmission Planning to enhance
the existing regional transmission planning and cost allocation
processes required by Order No. 1000. Except as set forth in this final
order, we do not require that any transmission provider replace or
otherwise make changes to its existing Order No. 1000-compliant
regional transmission planning processes that plan for reliability or
economic transmission needs, or the associated Order No. 1000-compliant
regional cost allocation method(s). Transmission providers may continue
to rely on their existing regional transmission planning and cost
allocation processes to comply with Order No. 1000's requirements
related to transmission needs driven by reliability concerns or
economic considerations.
[[Page 49327]]
242. We also do not alter the existing Order No. 1000 requirement
to consider transmission needs driven by Public Policy Requirements in
the regional transmission planning process. Instead, we clarify that we
will deem transmission providers to be in compliance with this existing
requirement by conducting Long-Term Regional Transmission Planning in
accordance with the requirements set forth in this final order. As
discussed below, we require transmission providers to incorporate a
variety of factors into the development of Long-Term Scenarios, which
include, among others, certain Federal, state, and local laws and
regulations. Therefore, we find that transmission providers that
implement Long-Term Regional Transmission Planning and satisfy the
requirements set forth in this final order will comply with the
requirement in Order No. 1000 to participate in a regional transmission
planning process that considers, and has associated cost allocation
provisions related to, transmission needs driven by Public Policy
Requirements.
243. We understand--and acknowledge comments submitted in this
proceeding explaining--that transmission providers in some transmission
planning regions have developed processes to consider transmission
needs driven by Public Policy Requirements through their regional
transmission planning processes that they wish to retain.\592\ In their
filings made to comply with this final order, transmission providers
may propose to continue using some or all aspects of the existing
regional transmission planning and cost allocation processes that they
use to consider transmission needs driven by Public Policy
Requirements. Transmission providers must nevertheless comply with the
Long-Term Regional Transmission Planning requirements set forth in this
final order, such that continued use of existing regional transmission
planning and cost allocation processes related to transmission needs
driven by Public Policy Requirements will not supplant transmission
providers' obligation to comply with this final order. In their filing
to comply with this final order, transmission providers that wish to
continue to use some or all of their existing regional transmission
planning and cost allocation processes to consider transmission needs
driven by Public Policy Requirements must demonstrate that continued
use of any such processes does not interfere with or otherwise
undermine Long-Term Regional Transmission Planning as set forth in this
final order.
---------------------------------------------------------------------------
\592\ CAISO Reply Comments at 17-18; New York Transco Initial
Comments at 5.
---------------------------------------------------------------------------
244. Similarly, we allow transmission providers to propose a
regional transmission planning process that simultaneously plans for
shorter-term reliability and economic transmission needs, as well as
Long-Term Transmission Needs, as outlined in this final order, through
a combined process. Transmission providers proposing to address all of
these transmission needs in a single regional transmission planning
process must demonstrate that the unified regional transmission
planning process continues to comply with Order No. 1000, as well as
with the Long-Term Regional Transmission Planning requirements set
forth in this final order, by demonstrating that such a combined
process is consistent with or superior to the requirements of both
Order No. 1000 and this final order. However, in the case that the
requirements of Order No. 1000 and this final order conflict, the
requirements of this final order prevail, and transmission providers
must demonstrate that their proposed regional transmission planning
process is consistent with or superior to the applicable requirements
in this final order.
245. We reject requests to require transmission providers to
simultaneously plan for all such transmission needs through a single
regional transmission planning process, however.\593\ We recognize that
such a combined process has potential benefits and do not prohibit such
an approach, but at this time we believe that the benefits of requiring
such a combined process on a generic basis may be outweighed by the
difficulty of transitioning to such a process from existing regional
transmission planning processes. Therefore, we do not require in this
final order that transmission providers plan for all reliability and
economic transmission needs and Long-Term Transmission Needs through a
single regional transmission planning process. Further, we believe that
Long-Term Regional Transmission Planning, as set forth in this final
order, meets many of the same objectives as would such a combined
regional transmission planning process because, by identifying Long-
Term Transmission Needs and considering a broad set of benefits when
evaluating Long-Term Regional Transmission Facilities, the existing
regional transmission planning processes for economic and reliability
needs may ultimately come to address only residual needs not already
addressed through Long-Term Regional Transmission Planning.
---------------------------------------------------------------------------
\593\ See, e.g., ACEG Initial Comments at 30-31.
---------------------------------------------------------------------------
246. With respect to the request by PIOs to mandate that the base
cases used in Order No. 1000 regional transmission planning processes
and Long-Term Scenarios in Long-Term Regional Transmission Planning be
defined in the same process,\594\ we decline to adopt this proposal.
The record is inadequate to assess the impact that such a requirement
would have on existing Order No. 1000 regional transmission planning
processes, and whether this proposal would work across the differing
transmission planning processes in each transmission planning region.
With respect to the proposals by Clean Energy Buyers, Cypress Creek,
and Policy Integrity,\595\ these proposals were not among the proposals
included in the NOPR and are beyond the scope of this proceeding, and
therefore we decline to adopt them.
---------------------------------------------------------------------------
\594\ PIOs Initial Comments at 44-46.
\595\ Clean Energy Buyers Initial Comments at 9-10; Cypress
Creek Reply Comments at 10-12; Policy Integrity Supplemental
Comments at 3.
---------------------------------------------------------------------------
247. We also reject requests to incorporate local transmission
planning into Long-Term Regional Transmission Planning specifically or
regional transmission planning more generally,\596\ as well as requests
to require transmission providers to evaluate and approve local
transmission facilities in regional transmission planning.\597\ This
final order sets forth requirements that will enhance the transparency
of local transmission planning and examine opportunities for right-
sizing in-kind replacements of existing transmission facilities,
including local transmission facilities, but the Commission in the NOPR
did not propose other changes to local transmission planning processes
and therefore these requests are beyond the scope of this final order.
---------------------------------------------------------------------------
\596\ AEE Initial Comments at 3, 38.
\597\ OMS Initial Comments at 16-17.
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248. As discussed in detail below, we require transmission
providers to satisfy specific requirements in implementing Long-Term
Regional Transmission Planning, including requirements to: (1) use a
transmission planning horizon of no less than 20 years into the future
in developing Long-Term Scenarios; (2) reassess and revise those
scenarios at least once every five years; (3) incorporate into the
Long-Term Scenarios a set of Commission-identified categories of
factors that give rise to Long-Term Transmission Needs;
[[Page 49328]]
(4) develop a plausible and diverse set of at least three Long-Term
Scenarios; (5) perform sensitivity analyses of uncertain operational
outcomes during multiple concurrent and sustained generation and/or
transmission outages due to an extreme weather event across a wide
area; and (6) use ``best available data'' in developing Long-Term
Scenarios.
249. Before turning to these topics, however, we address two
preliminary matters: the definition of Long-Term Regional Transmission
Facility; and our jurisdiction to adopt these reforms.
b. Definition of Long-Term Regional Transmission Facility
250. We modify the NOPR proposal and define Long-Term Regional
Transmission Facility for purposes of this final order as a regional
transmission facility, as defined in Order No. 1000, that is identified
as part of Long-Term Regional Transmission Planning to address Long-
Term Transmission Needs.\598\ In so doing, we clarify that some Long-
Term Regional Transmission Facilities may be selected in a regional
transmission plan for purposes of cost allocation, while others may be
considered for selection but not be selected.
---------------------------------------------------------------------------
\598\ In the NOPR, the Commission proposed to define a Long-Term
Regional Transmission Facility as a transmission facility identified
as part of Long-Term Regional Transmission Planning and selected in
the regional transmission plan for purposes of cost allocation to
address transmission needs driven by changes in the resource mix and
demand. NOPR, 179 FERC ] 61,028 at P 252 n.398.
---------------------------------------------------------------------------
251. This modification also clarifies that Long-Term Regional
Transmission Facilities are a subset of regional transmission
facilities as defined in Order No. 1000. Further, consistent with Order
No. 1000,\599\ a selected Long-Term Regional Transmission Facility is a
regional transmission facility that has been selected pursuant to a
Commission-approved Long-Term Regional Transmission Planning process in
a regional transmission plan for purposes of cost allocation because it
is a more efficient or cost-effective solution to Long-Term
Transmission Needs.
---------------------------------------------------------------------------
\599\ Order No. 1000, 136 FERC ] 61,051 at P 63.
---------------------------------------------------------------------------
252. We disagree with PJM that Order No. 1000's requirements
related to regional transmission planning processes addressing
transmission needs driven by reliability concerns or economic
considerations will be unclear given the definition of Long-Term
Regional Transmission Facility, and we find unpersuasive PJM's
contention that Long-Term Regional Transmission Planning will
inadvertently cause the re-litigation of aspects of those existing
processes. If a regional transmission facility is selected in an
existing Order No. 1000 regional transmission planning process, the
rules of, as well as the regional cost allocation method for, that
existing process apply to the selected regional transmission facility.
If a Long-Term Regional Transmission Facility is selected in Long-Term
Regional Transmission Planning, then the rules of, and the Long-Term
Regional Cost Allocation Method for, Long-Term Regional Transmission
Planning apply to that Long-Term Regional Transmission Facility.
c. Legal Authority To Adopt Reforms for Long-Term Regional Transmission
Planning
253. We reaffirm our conclusion in the NOPR that we are acting
within the Commission's legal authority under FPA section 206 by
requiring transmission providers to participate in a regional
transmission planning process that includes Long-Term Regional
Transmission Planning. The FPA grants the Commission authority over the
transmission of electric energy in interstate commerce, which includes
transmission on the interconnected national grids.\600\ FPA section 205
requires that the rates charged by any public utility in connection
with such transmission--as well as the rules and regulations affecting
such rates--be just and reasonable, and further requires that public
utilities file with the Commission the practices affecting such
rates.\601\ Under FPA section 206, when the Commission determines that
any rate or any practice affecting such rate is unjust, unreasonable,
or unduly discriminatory or preferential--as we find above with respect
to transmission planning practices--the Commission must determine the
just and reasonable rate or practice to be followed.\602\ Transmission
planning and cost allocation processes are practices affecting the
rates charged by public utilities in connection with the Commission-
jurisdictional transmission of electric energy in interstate
commerce.\603\ No commenter has claimed otherwise.
---------------------------------------------------------------------------
\600\ New York v. FERC, 535 U.S. at 16-17 (citing 16 U.S.C.
824(b)).
\601\ 16 U.S.C. 824d.
\602\ 16 U.S.C. 824e.
\603\ See S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 55-59;
accord Emera Me. v. FERC, 854 F.3d at 673-74.
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254. Despite this, a number of commenters claim that the specific
transmission planning requirements we adopt in this final order
infringe on the authority reserved to the states by FPA section 201 or
are otherwise barred by certain prudential or constitutional
principles. As a threshold matter, we believe that commenters' concerns
with respect to our jurisdiction or authority to adopt this final order
mainly arise from factual misunderstandings or mischaracterizations
about what Long-Term Regional Transmission Planning will and will not
require transmission providers to do. As explained above, this final
order requires transmission providers in each transmission planning
region to participate in a regional transmission planning process that
includes Long-Term Regional Transmission Planning and to conduct Long-
Term Regional Transmission Planning in accordance with the requirements
set forth in this final order. Transmission providers are required to
identify Long-Term Transmission Needs, identify Long-Term Regional
Transmission Facilities that meet such needs, measure the benefits of
these Long-Term Regional Transmission Facilities, and evaluate these
Long-Term Regional Transmission Facilities for potential selection. As
such, this final order does not regulate, aim at, or otherwise attempt
to influence integrated resource planning, the generation mix,
decisions related to the siting and construction of transmission
facilities or generation resources, or any other matters reserved to
states under FPA section 201.
255. As discussed in the Introduction and Background section above,
the requirements of this final order build upon more than a quarter
century of significant actions taken by the Commission on transmission
planning and cost allocation, beginning with the Commission's initial
open access reforms in Order No. 888. In 2007, the Commission issued
Order No. 890 to address identified deficiencies in the pro forma OATT
based on more than 10 years of experience since the issuance of Order
No. 888. Most recently, in 2011, the Commission issued Order No. 1000,
which required transmission providers to develop a regional
transmission plan after evaluating whether regional transmission
facilities may be more efficient or cost-effective than transmission
facilities identified in local transmission planning processes and to
consider transmission needs driven by Public Policy Requirements. These
practices serve as the foundation for regional transmission planning,
and this final order leaves them in place.
256. As described above, however, we have identified specific gaps
in the Order No. 1000 framework--namely, that regional transmission
planning practices do not perform a sufficiently
[[Page 49329]]
long-term assessment of transmission needs, adequately account on a
forward-looking basis for known determinants of Long-Term Transmission
Needs, or consider the broader set of benefits of regional transmission
facilities. In this final order, we direct reforms to close these gaps
without otherwise disturbing the regional transmission planning
structure required by Order No. 1000, which was fully affirmed on
appeal in the face of similar objections to those raised here.\604\
---------------------------------------------------------------------------
\604\ See S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 55-64
(rejecting arguments that the requirement to engage in regional
transmission planning, as prescribed in Order No. 1000, exceeded the
Commission's jurisdiction under FPA section 206, interfered with
traditional state authority reserved under FPA section 201, or
improperly interpreted and applied FPA section 202(a)).
---------------------------------------------------------------------------
257. Critically, as in Order No. 1000, our focus continues to be on
ensuring that Commission-jurisdictional regional transmission planning
processes are just and reasonable and that, as a result of improvements
to the regional transmission planning and cost allocation processes,
Commission-jurisdictional rates remain just and reasonable.\605\ And,
as in Order No. 1000, while the improvements to the regional
transmission planning and cost allocation processes will ensure that
potentially more efficient or cost-effective regional transmission
facilities are evaluated for potential selection and have a cost
allocation method available if they are selected, this order does not
mandate development of any particular transmission facility.
---------------------------------------------------------------------------
\605\ See id. at 63-64 (affirming that the Commission was acting
within its jurisdiction because its planning mandate ``relates
wholly to electricity transmission, as opposed to electricity
sales'' and ``is directed at ensuring the proper functioning of the
interconnected grid spanning state lines'').
---------------------------------------------------------------------------
258. Consistent with the regional transmission planning and cost
allocation reforms adopted in Order No. 1000, and in response to
commenters arguing otherwise,\606\ we affirm that this final order does
not authorize or require any entity to adopt a particular siting plan
for Long-Term Regional Transmission Facilities that transmission
providers select; or to forego state-jurisdictional siting proceedings
where they are necessary; or to begin construction on such Long-Term
Regional Transmission Facilities. Even where transmission providers
select a Long-Term Regional Transmission Facility, the relevant
transmission developer typically must secure a variety of other permits
and authorizations before beginning to construct the facility,
including those that are subject to state jurisdiction. Nothing in this
final order changes otherwise applicable siting laws or requirements.
---------------------------------------------------------------------------
\606\ Alabama Commission Initial Comments at 7; Kansas Ratepayer
Advocates Reply Comments at 3; NARUC Initial Comments at 29; Nevada
Commission Initial Comments at 2-3; Southern Initial Comments at 3-
4, 7, 15-17; Southern Reply Comments at 6-7.
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259. Similarly, this final order does not change existing
mechanisms for cost-recovery through retail rates; authorize or require
states or state commissions to change the laws or regulations that
govern the conduct of integrated resource planning or request for
proposal processes; authorize or require transmission providers or
transmission developers to bypass any applicable state-regulated
integrated resource planning or request for proposal processes; or
authorize or require states or public utilities to adopt a different
mix of generation resources than would otherwise be the case. Comments
suggesting otherwise do not accurately represent the Commission's
proposed requirements in the NOPR or the requirements adopted in this
final order,\607\ which seeks to ensure that transmission providers
plan for Long-Term Transmission Needs, however those needs arise.\608\
---------------------------------------------------------------------------
\607\ Alabama Commission Initial Comments at 3-4, 7-9; Kansas
Ratepayer Advocates Reply Comments at 2; Louisiana Commission
Initial Comments at 8-10, 27-28; Louisiana Commission Reply Comments
at 14-15; Mississippi Commission Initial Comments at 3 (citing NOPR,
179 FERC ] 61,028 (Christie, Comm'r, concurring, at P 2); Nevada
Commission Initial Comments at 2-3; SERTP Sponsors Initial Comments
at 5, 16, 17 n.20, 19-20; SERTP Sponsors Reply Comments at 12-13;
Southern Initial Comments at 3-4, 7-8, 12-13, 15-17, 23-24; Southern
Reply Comments at 3, 6-7; Undersigned States Reply Comments at 2, 4-
5, 8; Utah Commission Initial Comments at 7-9.
\608\ New Jersey Commission Reply Comments at 1-2.
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260. We disagree with Southern and SERTP Sponsors' characterization
of Long-Term Regional Transmission Planning as a Commission-regulated
integrated resource planning/request for proposal process.\609\
Similarly, comments that suggest that this final order intends to
``revamp the energy grid's mix of generation resources writ large''
\610\ are incorrect. We understand these comments to argue that the
Commission seeks reforms to regional transmission planning and cost
allocation processes so that it can direct or influence investments
toward particular resources, as would an entity engaged in integrated
resource planning. In this final order, the Commission neither aims to
influence the resource mix, nor, as a practical matter, could the final
order achieve such an outcome.
---------------------------------------------------------------------------
\609\ SERTP Sponsors Initial Comments at 16-17; Southern Initial
Comments at 3-4, 7, 15-17.
\610\ Undersigned States Reply Comments at 4; see also Louisiana
Commission Initial Comments at 6, 12-13 (arguing that the FPA does
not allow the Commission to ``enact[ ] sweeping energy policy
changes that would have far-reaching, nation-wide effects'' or to
favor one form of generation over another).
---------------------------------------------------------------------------
261. Instead, the final order merely requires transmission
providers to account for observable changes affecting the transmission
system. The final order neither directs those changes, nor does it
require any entity, including a state, to approve changes to any
subject within its jurisdiction. As with Order Nos. 890 and 1000, which
built on the Commission's open access reforms in Order No. 888, this
final order responds to changes in the electric industry that have
arisen in the years since the Commission's last regulatory action
related to transmission planning. As discussed above in the Overall
Need for Reform section, this final order responds to evolving
reliability concerns, including the increasing frequency of high-impact
extreme weather events; changes in electricity demand, including
significant load growth that is projected to increase in coming years;
changes in supply, including Federal, federally-recognized Tribal,
state, and local laws and policies that affect the future resource mix;
changes in the economics of generation, transmission, and storage
technologies; corporate, governmental, and utility commitments to rely
on certain generation resources; and other factors as discussed in this
final order.
262. We emphasize that these changes, which are affecting and will
continue to drive transmission needs, are not within the Commission's
control and, in many cases, are beyond the Commission's jurisdiction.
We do not aim to influence these drivers of transmission needs through
the requirements in this final order.\611\ However, the Commission has
an obligation under the FPA to ensure that Commission-jurisdictional
transmission rates remain just and reasonable, and we affirm--
consistent with the Commission's actions in Order Nos. 890 and 1000--
that the Commission has the requisite authority to account for the
effects of these changes driving transmission needs in Commission-
jurisdictional transmission planning processes.\612\
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\611\ See EPSA, 577 U.S. 260 at 282 (citing Oneok, Inc. v.
Learjet, Inc., 575 U.S. 373, 385 (2015)).
\612\ Cf. EPSA, 577 U.S. at 281-82 (``When FERC regulates what
takes place on the wholesale market, as part of carrying out its
charge to improve how that market runs, then no matter the effect on
retail rates, 824(b) imposes no bar.'').
---------------------------------------------------------------------------
263. We also emphasize, and no commenter contests, that this final
order directly regulates transmission planning
[[Page 49330]]
and cost allocation processes, which are practices that affect the
rates for the transmission of electric energy in interstate commerce.
Importantly, it directly regulates only those practices, and it does
not directly regulate any matter reserved to the states by FPA section
201. Moreover, in doing so, this final order is not aiming to
indirectly regulate any matter reserved to the states by FPA section
201. Instead, our aim here is to improve on the Commission's existing
transmission planning and cost allocation processes for the express
purpose of addressing identified deficiencies with those processes.
264. As the U.S. Supreme Court has recognized, it is true that
almost any action that the Commission takes with respect to regulating
the practices affecting the rates for the transmission of or the
wholesale sale of electric energy in interstate commerce will have
``some effect, in either the short or long term'' on matters reserved
to the states' jurisdiction.\613\ But those effects, inevitable as they
may be, are ``of no legal consequence'' to determining whether this
final order infringes on the states' authority under FPA section
201.\614\ Instead, such effects are a ``fact of economic life'' for the
electric industry, given Congress's decision in the FPA to divide
jurisdiction over the industry, including both generation and
transmission, into spheres of Commission and state jurisdiction that
are not ``hermetically sealed'' from one another.\615\ Accordingly,
Commission regulation of Commission-jurisdictional practices affecting
transmission may ``have natural consequences'' for generation.\616\
But, even where that happens, that does not defeat Federal
jurisdiction.
---------------------------------------------------------------------------
\613\ Id. at 281 (emphasis added).
\614\ Id.
\615\ Id.
\616\ Id.
---------------------------------------------------------------------------
265. Rather, as in EPSA, what matters is that this final order aims
to regulate and, in fact, does regulate only practices that affect the
transmission of electric energy in interstate commerce, which are
squarely within the Commission's jurisdiction under the FPA. As in
Order Nos. 890 \617\ and 1000,\618\ this final order aims to improve
Commission-regulated transmission planning processes, in this instance
by ensuring that they are sufficiently long-term, forward-looking, and
comprehensive such that they are capable of identifying and meeting
Long-Term Transmission Needs.\619\ Thus, this final order ensures just
and reasonable Commission-jurisdictional rates and practices by
ensuring that transmission providers have adequate processes to
identify Long-Term Transmission Needs and to identify, evaluate, and
select Long-Term Regional Transmission Facilities that more efficiently
or cost-effectively address those needs.
---------------------------------------------------------------------------
\617\ Order No. 890, 118 FERC ] 61,119 at P 3.
\618\ Order No. 1000, 136 FERC ] 61,051 at P 12.
\619\ EPSA, 577 U.S. at 281-83.
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266. Moreover, as in EPSA, what also matters is that ``every aspect
of the [final order] happens exclusively'' as part of a process that is
subject to the Commission's jurisdiction and governs exclusively how
those processes work.\620\ In aiming to improve transmission planning
processes, this final order does not require that transmission
providers achieve any particular substantive outcome of those
processes, including either the selection or construction of any
specific transmission facilities. The final order patently does not aim
to alter states' or the Nation's generation mix or otherwise regulate
matters that are within state jurisdiction. Indeed, to the contrary,
our rationale in this final order is ``all about, and only about,
improving'' the relevant matters under the Commission's
jurisdiction.\621\ Nor is it clear how, under commenters' theory, the
final order could be argued to regulate matters under states'
jurisdiction, given that the final order does not require investment in
any particular transmission facilities, and could not, even indirectly,
ensure investments in any particular set of generating facilities that
may rely on such transmission facilities.
---------------------------------------------------------------------------
\620\ Id. at 282.
\621\ Id. (citing Oneok, Inc. v. Learjet, Inc., 575 U.S. at
385).
---------------------------------------------------------------------------
267. Despite some commenters' claims,\622\ nothing in this final
order requires states to subsidize other states' public policies and,
indeed, this final order requires, consistent with long-established
Commission and court precedent, that transmission customers within a
transmission planning region need only pay costs that are ``roughly
commensurate'' with the benefits that transmission providers estimate
they will receive from a regional transmission facility.\623\ Thus, the
final order ensures that transmission customers nationwide are not
required to pay for Long-Term Regional Transmission Facilities from
which they do not benefit.
---------------------------------------------------------------------------
\622\ Alabama Commission Initial Comments at 8-9; Louisiana
Commission Initial Comments at 6, 9-10; Mississippi Commission Reply
Comments at 2-3; Ohio Commission Federal Advocate Initial Comments
at 4-6; Ohio Consumers Reply Comments at 14.
\623\ See Ill. Com. Comm'n v. FERC, 756 F.3d 556, 562 (7th Cir.
2014) (ICC v. FERC III); ICC v. FERC I, 576 F.3d at 477; Sw. Power
Pool, Inc., 182 FERC ] 61,141, at P 12 (2023).
---------------------------------------------------------------------------
268. The reforms in the final order require greater transparency
regarding the benefits that would result from the development of Long-
Term Regional Transmission Facilities, but these reforms also continue
to allow flexibility, as under Order No. 1000, for the transmission
providers in each transmission planning region to determine the
appropriate method for allocating to transmission customers the costs
of any selected Long-Term Regional Transmission Facility. Rather than
force transmission providers to adopt a particular cost allocation
method that would necessarily result in customers in one state
subsidizing the costs of customers in another state, as these
commenters allege, the final order affords significant new
opportunities for Relevant State Entities to inform the evaluation
process, selection criteria, and cost allocation method adopted by the
transmission providers in a transmission planning region. We believe
that the requirements for greater transparency regarding the benefits
of proposed transmission facilities, the increased opportunities for
state engagement in evaluation, selection, and cost allocation, the
flexibility for transmission providers in each transmission planning
region to determine their own cost allocation methods, and the
requirement that any cost allocation method must ensure costs are
allocated in a manner that is at least roughly commensurate with
estimated benefits provide robust assurance that the cost allocation
methods ultimately proposed under the final order will not result in
improper cost subsidization. Ultimately, the Commission must review and
accept each cost allocation method proposed under the final order to
ensure that it is just and reasonable and consistent with the final
order's requirements.
269. As discussed in the Evaluation of the Benefits of Regional
Transmission Facilities section below, this final order requires
transmission providers to use and measure a set of seven required
benefits to evaluate Long-Term Regional Transmission Facilities. The
measurement of these benefits represents the value that the
transmission providers expect a particular Long-Term Regional
Transmission Facility to provide to transmission customers in the
transmission planning region. As further discussed in the Regional
Transmission Planning Cost Allocation section below, this final order
requires transmission providers to provide a forum for
[[Page 49331]]
Relevant State Entities to negotiate a cost allocation method and/or a
process for determining future cost allocation methods for Long-Term
Regional Transmission Facilities, which enables robust participation by
those entities. Moreover, the cost allocation methods required by this
final order are intended to ensure that costs are allocated in a manner
that is at least roughly commensurate with the estimated benefits that
a Long-Term Regional Transmission Facility provides to transmission
customers.
270. The benefits this order requires to be used and measured--
which provide an important source of transparency regarding any
resulting allocation of costs to transmission customers--reflect
objective, measurable changes in transmission system conditions, rather
than achievement of state public policies. For example, even if a
state's public policy is one driver of a Long-Term Transmission Need,
these benefits of a Long-Term Regional Transmission Facility resolving
that need are well understood and measurable, including, for example,
reducing the cost of generating electricity by allowing for the
increased dispatch of suppliers that have lower incremental costs of
production, minimizing energy losses incurred in transmitting
electricity, and lowering the number or duration of loss of load
events. Transmission providers will evaluate Long-Term Regional
Transmission Facilities for selection considering these benefits that
these facilities would provide, and these benefits accrue to the
transmission customers that fund their construction. In other words,
under this final order, customers pay for a more reliable and economic
transmission system as identified through open and transparent Long-
Term Regional Transmission Planning, and any state's ratepayers only
fund the construction of Long-Term Regional Transmission Facilities
that provide them with such benefits that are at least roughly
commensurate with the costs of those facilities.
271. We turn now to commenters' specific jurisdiction arguments. As
an initial matter, we acknowledge that, in addition to granting
authority to the Commission over the transmission of electric energy in
interstate commerce, FPA section 201 also reserves certain authority to
the states.\624\ As such, we agree with Southern that Congress sought
in enacting the FPA to ensure the ``continued exercise of state power''
\625\ over certain matters. However, the requirements in this final
order respect and do not unlawfully infringe on state authority.
Rather, as discussed above, the Commission is acting in an area
squarely within its jurisdiction--transmission planning and cost
allocation--by requiring transmission providers to engage in Long-Term
Regional Transmission Planning to remedy deficiencies in the current
transmission planning and cost allocation processes, which we conclude
are unjust and unreasonable.
---------------------------------------------------------------------------
\624\ See 16 U.S.C. 824(a)-(b)(1); New York v. FERC, 535 U.S. at
20-21 (``It is, however, perfectly clear that the original FPA did a
good deal more than close the gap in state power identified in [Pub.
Utils. Comm'n of R.I. v. Attleboro Steam & Elec. Co., 273 U.S. 83
(1927) (Attleboro)]. The FPA authorized Federal regulation not only
of wholesale sales that had been beyond the reach of state power,
but also the regulation of wholesale sales that had been previously
subject to state regulation. More importantly, as discussed above,
the FPA authorized Federal regulation of interstate transmissions as
well as of interstate wholesale sales, and such transmissions were
not of concern in Attleboro.'' (emphasis in original) (internal
citations omitted)).
\625\ Southern Initial Comments at 16 (quoting Oneok, Inc. v.
Learjet, Inc., 575 U.S. at 385).
---------------------------------------------------------------------------
272. We acknowledge that Long-Term Regional Transmission Planning
will affect matters that are within the states' jurisdiction. As
stated, this is inevitable. Effective transmission planning necessarily
involves taking into account assumptions about the generation resources
that will be available, because transmission needs arise from the
relative amounts, locations, and timing of supply (i.e., generation)
and of demand (i.e., load); indeed, existing transmission planning
processes also take into account these assumptions.\626\ Our action in
this final order simply modifies the scope and duration of these
assumptions to ensure that regional transmission planning processes are
conducted on a sufficiently long-term, forward-looking, and
comprehensive basis by requiring transmission providers to evaluate
factors that give rise to Long-Term Transmission Needs.
---------------------------------------------------------------------------
\626\ See, e.g., Xcel Initial Comments at 13, 16 & n.26
(discussing generation resource assumptions made in existing Order
No. 1000 regional transmission planning and cost allocation
processes).
---------------------------------------------------------------------------
273. Southern and SERTP Sponsors acknowledge that the NOPR proposed
to require transmission providers to incorporate the results of state-
sanctioned integrated resource planning as factors in developing Long-
Term Scenarios, but they insist that Long-Term Regional Transmission
Planning will intrude upon state authority if we do not require Long-
Term Scenarios to be limited to those state-sanctioned resources.\627\
This assertion is incorrect for at least three reasons. First, the
public utilities whose integrated resource plans are approved by state
commissions are not the only entities whose decisions may influence the
development of generation resources within a particular transmission
planning region. For example, a wide variety of private enterprises,
publicly-owned utilities, and electric cooperatives have made
commitments to fund the development of certain generation resources,
and transmission providers may reasonably determine that these
procurement decisions give rise to Long-Term Transmission Needs.
Second, making generation resource assumptions for the purpose of
performing transmission planning does not result in any legally-binding
determination on a matter within a state's jurisdiction, let alone
undermine a state's ability to ultimately decide what generation
resources to build, and on what timetable.\628\ Third, as Southern and
SERTP Sponsors concede,\629\ many existing integrated resource planning
processes do not identify specific generation resources beyond a
particular point in time. Other integrated resource planning processes
may not result in a set of state-sanctioned generation resources and
may instead serve merely as a guide for the relevant public
utility.\630\ As a result, relying on such integrated resource planning
processes exclusively to identify Long-Term Transmission Needs would
fail to ensure that regional transmission planning processes are
conducted on a sufficiently long-term, forward-looking, and
comprehensive basis and therefore would fail to ensure just and
reasonable Commission
[[Page 49332]]
jurisdictional-rates. To be clear, we are not in this final order
attempting to denigrate or diminish the importance of integrated
resource planning. Rather, in the context of Long-Term Regional
Transmission Planning, integrated resource planning is reasonably
considered one of several categories of factors used to develop Long-
Term Scenarios and identify Long-Term Transmission Needs.
---------------------------------------------------------------------------
\627\ SERTP Sponsors Initial Comments at 15-17; Southern Initial
Comments at 18-19.
\628\ We disagree with Southern's and SERTP Sponsors' contention
that the inclusion of such non-binding assumptions about generation
resources in transmission planning will ``bias'' subsequent state
resource decisions. See Southern Initial Comments at 19; SERTP
Sponsors Initial Comments at 17 n.20. As Kentucky Commission Chair
Chandler argues, the NOPR's reforms do not foreclose states'
decision making on generation. Kentucky Commission Chair Chandler
Reply Comments at 3. We also disagree with North Carolina Commission
and Staff's contention that merely requiring transmission providers
to use and measure production cost savings in evaluating Long-Term
Regional Transmission Facilities ``could conflict with state-
jurisdictional resource decisions.'' North Carolina Commission and
Staff Initial Comments at 7. If nothing else, Long-Term Regional
Transmission Planning will provide public utilities and state
commissions the opportunity to develop longer-term, forward-looking,
robust assessments that can inform future decision making.
\629\ SERTP Sponsors Initial Comments at 16; Southern Initial
Comments at 19.
\630\ See, e.g., SREA Reply Comments at 2-3 (arguing, in
response to Alabama Commission, that Alabama has no formal
integrated resource plan process upon which the Commission could
encroach).
---------------------------------------------------------------------------
274. In that light, Southern's and SERTP Sponsors' argument--that
we should limit transmission providers to state-approved resources and
prohibit non-binding assumptions about the resource mix and demand--
does not safeguard but in fact subverts the FPA's division between
Federal and state authority. As stated above, were we to require that
transmission providers limit their assumptions to only state-sanctioned
generation resources, we would be requiring transmission providers to
ignore many of the factors that, as demonstrated by this record,
transmission providers must reasonably consider to plan on a
sufficiently long-term, forward-looking, and comprehensive basis.
Instead, it is within our jurisdiction to determine the factors that
transmission providers must incorporate in order to identify Long-Term
Transmission Needs.
275. Commenters' arguments that the final order would not withstand
judicial scrutiny under the ``major questions doctrine'' are similarly
unfounded. For example, some commenters appear to misinterpret West
Virginia v. EPA as standing for the proposition that ``the nation's
energy policy and generation mix is a `major question' and that an
agency must have direct authorization from Congress to assert
jurisdiction'' over these matters.\631\ As an initial matter, as noted
above, the aim of this final order is not to influence the generation
mix or energy policy more broadly, but to ensure that Commission-
jurisdictional transmission providers are planning for Long-Term
Transmission Needs in a manner that is just and reasonable and results
in just and reasonable Commission-jurisdictional rates.
---------------------------------------------------------------------------
\631\ SERTP Sponsors Initial Comments at 17-18; Southern Initial
Comments at 20; see also Undersigned States Reply Comments at 3
(``National-scale energy grid regulation is a `major question'
because of the massive economic consequences involved in such
regulation.'').
---------------------------------------------------------------------------
276. In any case, the Court did not determine that energy policy
and the mix of generation resources are in every instance a major
question. Instead, in West Virginia v. EPA, the U.S. Supreme Court
considered a specific agency action in light of a specific statutory
provision and concluded that the Environmental Protection Agency's
(EPA) exercise of authority was a ``major question'' based on a variety
of factors specific to that context--including whether the EPA's
administrative action was a ``transformative'' expansion of its power,
whether the EPA had relevant technical and policy expertise, whether
the relevant statutory provision was ``ancillary'' to the broader
statutory construct, and whether the EPA's administrative action
implicated significant economic and political questions.\632\
---------------------------------------------------------------------------
\632\ West Virginia v. EPA, 597 U.S. at 710, 724-725, 729, 731-
32; see also Biden v. Nebraska, 143 S. Ct. 2355, 2372-2374 (2023)
(applying West Virginia v. EPA's mode of analysis).
---------------------------------------------------------------------------
277. Commenters have not attempted a similar analysis of whether
courts should construe this final order as a ``major question,'' \633\
and we find that their contentions that courts ought to do so are based
on the factual mischaracterizations discussed above. In any event, this
final order neither transforms nor expands the Commission's authority;
it merely applies existing authority, based on the Commission's
expertise and experience, to identify and remedy deficiencies in
existing regional transmission planning and cost allocation
processes.\634\ As with Order Nos. 890 and 1000, the Commission is
promulgating a final order pursuant to FPA section 206 to address those
deficiencies in order to ensure that transmission planning practices, a
subject long-regulated by the Commission and well within its area of
expertise, remain just and reasonable and not unduly discriminatory or
preferential. To that end, this final order requires further reforms to
regional transmission planning and cost allocation processes so that
they are sufficiently long-term, forward-looking, and comprehensive.
And while the transmission planning required in this final order may be
more forward-looking, long-term, and comprehensive than the status quo,
as a matter of the Commission's jurisdiction, it is fundamentally no
different than the regional transmission planning already required by
the Commission and upheld by appellate courts.\635\ In short, the
differences in transmission planning required by this final order
represent differences in degree, not kind, from the Commission's
longstanding regulations. As such, they are a far cry from the
``transformative expansion'' of the EPA's authority on which the Court
relied in West Virginia v. EPA to find that the issue presented therein
represented a major question not delegated to the agency to decide.
---------------------------------------------------------------------------
\633\ See Harvard ELI and Policy Integrity Supplemental Comments
at 2 (arguing that Undersigned States, for example, ``overlook key
requirements of the major questions doctrine'').
\634\ See, e.g., S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 68-
69. Cf. PJM Power Providers Grp. v. FERC, 88 F.4th at 274.
\635\ See, e.g., S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 48-
49; see also Harvard ELI and Policy Integrity Supplemental Comments
at 4-7.
---------------------------------------------------------------------------
278. Just as it is clear that incremental improvements to practices
that the courts have already determined fall squarely within the
Commission's jurisdiction do not constitute a ``transformative
expansion'' or ``extraordinary grant'' of regulatory authority to which
the major questions doctrine may apply, so too is it clear that the
other ancillary factors cited by the Court are similarly inapplicable.
The final order's incremental process improvements, while necessary to
ensure just and reasonable Commission-jurisdictional rates, do not have
the ``vast economic and political significance'' that would implicate
the major questions doctrine.\636\ The Commission's regulation of
interstate transmission rates will have an effect on billions of
dollars in customer charges and, in that generic sense, is of political
interest to many. The incremental process improvements required by the
final order, however, do not fundamentally change the economic or
political stakes of ensuring that Commission-jurisdictional rates
remain just and reasonable.
---------------------------------------------------------------------------
\636\ West Virginia v. EPA, 597 U.S. at 735 (J. Gorsuch,
concurring).
---------------------------------------------------------------------------
279. Likewise, the Commission's continued assertion of authority
over regional transmission planning and cost allocation processes does
not resemble the EPA's assertion of authority related to the electric
system that the Court found to be beyond that agency's expertise.\637\
Here, the Commission undisputedly bears the relevant expertise over the
interstate transmission system.\638\ Nor does the Commission rely on a
``backwater'' statutory provision to achieve its reforms.\639\ The
Commission relies on FPA sections 205 and 206, which the Court has held
``unambiguously authorize[ ]'' the Commission to assert jurisdiction
over interstate
[[Page 49333]]
transmission\640\ and extends an authority--indeed, a duty--to ensure
that the practices directly affecting such rates are just and
reasonable.\641\ This provision was not ancillary to the statutory
scheme but, rather, central to Congress' aim to ensure that the
Commission possessed adequate authority to regulate interstate
transmission beyond the reach of state power.\642\ Finally, commenters
do not point to Congress's ``conspicuous[ ] and repeated[ ]'' rejection
of legislation that would enact reforms similar to those adopted in the
final order.\643\
---------------------------------------------------------------------------
\637\ West Virginia v. EPA, 597 U.S. at 729 (finding relevant
that EPA itself admitted it lacked expertise to project ``system-
wide trends in areas such as electricity transmission, distribution,
and storage'').
\638\ Cf. Amerada Hess Pipeline Corp. v. FERC, 117 F.3d 596,
600-01 (D.C. Cir. 1997) (``[The Federal Energy Regulatory
Commission] is entrusted with administering the regulations relating
to oil pipelines and has an expertise in the field based on that
jurisdiction.'' (emphasis added)).
\639\ West Virginia v. EPA, 597 U.S. at 729.
\640\ New York v. FERC, 535 U.S. at 19.
\641\ EPSA, 577 U.S. at 277.
\642\ New York v. FERC, 535 U.S. at 20-21 (discussing enactment
of FPA in 1935 as a response to Attleboro).
\643\ West Virginia v. EPA, 597 U.S. at 745 (J. Gorsuch,
concurring).
---------------------------------------------------------------------------
280. We also disagree with Undersigned States' legal claim that
allowing ``one [s]tate [to] effectively require other [s]tates to
subsidize their own vision of what resources should be used in
electricity generation'' would violate the Constitution's ``equal
sovereignty doctrine.'' \644\ As discussed above, the final order
categorically does not require states to subsidize other states' public
policies or generation decisions. To the contrary, consistent with the
cost causation principle, this final order requires customers to pay
for a share of the costs of new Long-Term Regional Transmission
Facilities only to the extent that they benefit from those facilities
and, even then, any share they pay for must be roughly commensurate
with the benefits they receive.\645\
---------------------------------------------------------------------------
\644\ Undersigned States Reply Comments at 5-6.
\645\ See supra note 623 and accompanying discussion.
---------------------------------------------------------------------------
281. Moreover, according to Undersigned States, the equal
sovereignty doctrine dictates that the Nation ``is a union of [s]tates,
equal in power, dignity and authority, each competent to exert that
residuum of sovereignty not delegated to the United States by the
Constitution itself.'' \646\ But, ``neither the Supreme Court nor any
other court has ever applied that principle as a limit on the Commerce
Clause or other Article I powers.'' \647\ Instead, Courts have found
that ``the Constitution does not contain any textual provision
suggesting an equal sovereignty limit on Congress's Article I powers
generally or on the Commerce Clause in particular.'' \648\ As relevant
here, pursuant to the Constitution's Commerce Clause,\649\ Congress
duly enacted the FPA, which in turn empowers the Commission to regulate
the rates and practices affecting rates for the transmission of
electricity in interstate commerce.\650\ Under the FPA, the Commission
is ``unambiguously authorize[d] . . . to take state policies into
account to the extent that such policies affect [the Commission's]
statutorily prescribed area of focus . . . .'' \651\
---------------------------------------------------------------------------
\646\ Undersigned States Reply Comments at 5 (citing Coyle v.
Smith, 221 U.S. at 567). But see Ohio v. EPA, 2024 WL 1515001, at
*15 (D.C. Cir. Apr. 9, 2024) (holding that ``[t]he equal footing
cases,'' like Coyle v. Smith, ``do not directly apply either outside
of the admission context or to Article I powers like the Commerce
Clause.'').
\647\ Ohio v. EPA, 2024 WL 1515001 at *13.
\648\ Id. at *16.
\649\ U.S. Const. art. 1, 8.
\650\ 16 U.S.C. 824d.
\651\ PJM Power Providers Grp. v. FERC, 88 F.4th at 275; see
also Elec. Power Supply Ass'n v. Star, 904 F.3d at 524 (approving of
the Commission's decision to take state zero-emissions credit
systems like that in Illinois ``as givens and set out to make the
best of the situation [these systems] produce'').
---------------------------------------------------------------------------
282. The nature of the interconnected transmission system is such
that states naturally affect one another in pursuing policies available
to them while exercising the authority reserved to them under FPA
section 201.\652\ For the reasons explained in this final order, we
conclude that transmission providers must participate in a regional
transmission planning process that includes Long-Term Regional
Transmission Planning, and we find that transmission providers must
have the opportunity to select Long-Term Regional Transmission
Facilities that more efficiently or cost-effectively address Long-Term
Transmission Needs. Our role within our Federal system is not to
``unreasonably interfere with'' nor to ``pass judgement on state and
local policies and objectives,'' \653\ including where such policies
and objectives have incidental interstate effects.\654\ Nor need we,
because even if one state's public policy is a driver of a Long-Term
Transmission Need, the costs of a Long-Term Regional Transmission
Facility that transmission providers select will be allocated to
transmission customers only to the extent that they benefit from that
facility and only to a degree that is at least roughly commensurate
with the benefits that facility provides to them. That approach is
consistent with Commission precedent and commenters have not
demonstrated that this framework results in impermissible cross-
subsidization among states.\655\
---------------------------------------------------------------------------
\652\ See Elec. Power Supply Ass'n v. Star, 904 F.3d at 524
(describing the effects on interstate sales resulting from states'
exercise of powers reserved to them under FPA section 201 as ``an
inevitable consequence of a system in which power is shared between
state and national governments'' (citing Hughes v. Talen Energy
Mktg., LLC, 578 U.S. 150, 164 (2016)).
\653\ N.J. Bd. Pub. Utils. v. FERC, 744 F.3d 74, 98 n.24 (3rd
Cir. 2014) (quoting PJM Interconnection, L.L.C., 137 FERC ] 61,145,
at P 3 (2011)); see also PJM Interconnection, L.L.C., 186 FERC ]
61,080, at P 186 (2024) (rejecting an argument that the Commission
was required to determine whether state-sponsored resources were
providing disproportionate benefits to other states in the form of
lower capacity market prices).
\654\ See Coal. for Competitive Elec. v. Zibelman, 906 F.3d 41,
56 (2d Cir. 2018) (collecting Commission orders sanctioning state-
jurisdictional programs incidentally affecting wholesale markets).
\655\ For example, PJM incorporates transmission needs driven by
Public Policy Requirements into the assumptions stage of its
regional transmission planning process to identify needed
reliability and economic regional transmission facilities for
potential selection and cost allocation, rather than through a
separate and distinct process to identify and allocate the costs of
transmission facilities selected to address transmission needs
driven by Public Policy Requirements. The Commission found PJM's
approach complied with the requirement in Order No. 1000 to consider
transmission needs driven by Public Policy Requirements in regional
transmission planning and cost allocation processes. PJM
Interconnection, L.L.C., 142 FERC ] 61,214, at PP 109-120 (2013),
order on reh'g and compliance, 147 FERC ] 61,128, at PP 66-71
(2014).
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283. Finally, in response to NRECA's request, we confirm that the
final order is consistent with the Commission's obligation under FPA
section 217(b)(4). As articulated in South Carolina Public Service
Authority v. FERC, FPA section 217(b)(4) requires the Commission to
``facilitate the planning of a reliable grid,'' and we do so by
``seek[ing] to ensure that adequate transmission capacity is built to
allow load-serving entities to meet their service obligations.'' \656\
This final order seeks to ensure precisely the same goal, and it
therefore satisfies the Commission's obligation under FPA section
217(b)(4).
---------------------------------------------------------------------------
\656\ 762 F.3d at 90.
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B. Development of Long-Term Scenarios
1. NOPR Proposal
284. In the NOPR, the Commission proposed to require transmission
providers to develop Long-Term Scenarios as part of Long-Term Regional
Transmission Planning. The Commission proposed to define Long-Term
Scenarios as a tool to identify the transmission planning region's
needs driven by changes in the resource mix and demand--and enable the
evaluation of transmission facilities to meet such transmission needs--
across multiple scenarios that incorporate different assumptions about
the future electric power system over a sufficiently long-term,
forward-looking transmission planning horizon. The Commission explained
that a scenario is a hypothetical sequence of events that includes
assumptions used to forecast transmission needs. The Commission also
stated that assumptions used to forecast transmission needs driven by
[[Page 49334]]
changes in the resource mix and demand include: forecasts of the level
and pattern (i.e., hourly and seasonal variability) of future
electricity demand; the quantity, location, and type of resource
additions and retirements; and other relevant forecasts about the
electric power system that are used as inputs to the transmission model
and determine the need for new transmission facilities over the
transmission planning horizon. In addition, the Commission noted that
other relevant assumptions might include forecasts for natural gas
prices, increasing outage trends due to extreme weather and climatic
trends, and other future events.
285. The Commission also proposed in the NOPR to require that
transmission providers use Long-Term Scenarios to evaluate potential
regional transmission facilities needed to meet transmission needs
driven by changes in the resource mix and demand to identify the more
efficient or cost-effective regional transmission facilities.\657\
---------------------------------------------------------------------------
\657\ NOPR, 179 FERC ] 61,028 at P 84.
---------------------------------------------------------------------------
2. Comments
a. General Comments
286. Of the commenters specifically addressing the proposal to
require Long-Term Scenarios in Long-Term Regional Transmission
Planning, the majority support scenario-based planning.\658\ Clean
Energy Buyers state that Long-Term Scenarios are critical to Long-Term
Regional Transmission Planning because its success will depend on the
quality of forecasting.\659\ Form Energy states that long-term scenario
review will ensure that transmission upgrades address future needs in a
cost-effective and environmentally friendly manner.\660\ LADWP asserts
that Long-Term Scenarios are critical to developing an effective
transmission system that ensures reliability, while also providing
flexibility to support the delivery of renewable energy.\661\ NARUC
states that Long-Term Scenarios are a flexible planning tool for
addressing the uncertainty involved in identifying transmission needs
driven by changes in the resource mix and demand and that using them
will ensure that transmission providers adequately assess the potential
benefits of regional transmission facilities.\662\
---------------------------------------------------------------------------
\658\ See ACEG Initial Comments at 6; AEP Initial Comments at 7-
8; Amazon Initial Comments at 2-3; BP Initial Comments at 4;
California Commission Initial Comments at 1-2, 5-6, 21; California
Energy Commission Initial Comments at 1-2; City of New York Initial
Comments at 7; Clean Energy Associations Initial Comments at 10;
Clean Energy Buyers Initial Comments at 11; Duke Initial Comments at
10; Eversource Initial Comments at 10; Exelon Initial Comments at 5;
Form Energy Initial Comments at 2-3; GridLab Initial Comments at 10;
Handy Law Initial Comments at 9-10; Indicated PJM TOs Initial
Comments at 7-8; LADWP Initial Comments at 2; NARUC Initial Comments
at 4; National Grid Initial Comments at 10-11; PIOs Initial Comments
at 14; PPL Initial Comments at 4; SEIA Initial Comments at 4-5;
Southeast PIOs Initial Comments at 42; SREA Initial Comments at 39;
State Agencies Initial Comments at 14; State Officials Supplemental
Comments at 1 (citing US Climate Alliance Initial Comments); US
Climate Alliance Initial Comments at 2; WE ACT Initial Comments at
3; WIRES Initial Comments at 6.
\659\ Clean Energy Buyers Initial Comments at 11.
\660\ Form Energy Initial Comments at 3.
\661\ LADWP Initial Comments at 2.
\662\ NARUC Initial Comments at 4.
---------------------------------------------------------------------------
287. Southeast PIOs claim that Long-Term Scenarios are essential to
improving current transmission planning processes in the
Southeast.\663\ SREA argues that Long-Term Regional Transmission
Planning is not occurring in MISO South and states that scenario
planning is contentious but necessary.\664\
---------------------------------------------------------------------------
\663\ Southeast PIOs Initial Comments at 42, 46.
\664\ SREA Initial Comments at 39-41.
---------------------------------------------------------------------------
288. California Energy Commission requests that the Commission
clarify that transmission providers may rely on scenarios developed by
other agencies, as currently CAISO relies on analyses conducted by
California Energy Commission and California Commission.\665\ Relatedly,
New York Commission and NYSERDA and ISO-NE highlight the importance of
state-led identification of public policy needs and their impact on
scenario assumptions.\666\ New York Commission and NYSERDA state that,
especially in a single-state RTO/ISO like NYISO, the state should be
afforded a central role in determining the scenarios to be
studied.\667\ ISO-NE also believes that reliance on states is
consistent with prior Commission orders permitting transmission
providers to rely on a committee of state regulators to identify
transmission needs driven by Public Policy Requirements.\668\
---------------------------------------------------------------------------
\665\ California Energy Commission Initial Comments at 2.
\666\ New York Commission and NYSERDA Initial Comments at 7;
ISO-NE Initial Comments at 25-26.
\667\ New York Commission and NYSERDA Initial Comments at 8.
\668\ ISO-NE Initial Comments at 25 (citing ISO New England
Inc., 143 FERC ] 61,150, at P 108 (2013)).
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289. PJM States suggest that the Commission's proposal for state
involvement in the development of Long-Term Scenarios could be
interpreted as more limited than its proposal for state involvement
with respect to Long-Term Regional Cost Allocation and ask that the
Commission clarify that retail regulators have a primary role in both.
PJM States warn that, if a retail regulator disagrees with the
scenarios or benefits metrics used to select a transmission project, it
is unlikely to receive regulatory approval.\669\
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\669\ PJM States Initial Comments at 3-4 (citing NOPR, 179 FERC
] 61,028 at P 245).
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290. Cypress Creek asserts that the Commission should require the
use of a defined and standardized set of baseline assumptions to ensure
that scenario projections are realistic, and that deviation should only
be allowed if the proposal is consistent with or superior to the pro
forma.\670\
---------------------------------------------------------------------------
\670\ Cypress Creek Reply Comments at 5-8.
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291. Concerned Scientists state that the Commission should reject
comments arguing that uncertainty prohibits scenario-based planning,
and instead endeavor to create a transmission planning process that
properly acknowledges and addresses that uncertainty. Concerned
Scientists state that uncertainty does not prohibit long-term
transmission planning but rather necessitates the evaluation of
multiple plausible scenarios to identify investments that will perform
well over a variety of possible future conditions. Concerned Scientists
explain that, just as utilities and generator developers do not shy
away from an uncertain future when building new generation resources,
transmission investments should also be informed by, but not avoided
due to, future uncertainty. Concerned Scientists state that the
Commission's proposed Long-Term Scenarios requirements are a reasonable
minimum for responsible transmission planning.\671\
---------------------------------------------------------------------------
\671\ Concerned Scientists Reply Comments at 18-19.
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292. Other commenters support the NOPR proposal to require Long-
Term Scenarios in transmission planning but have reservations.\672\
Many of these commenters argue that the NOPR is too prescriptive and
ask for greater flexibility so that the Long-Term Scenario planning
already occurring in their respective transmission planning region will
comply with any final order.\673\ For example, OMS points to such
flexibility as key to the success of MISO's long-term transmission
planning
[[Page 49335]]
processes.\674\ SERTP Sponsors argue that the Commission should not
make Long-Term Scenarios even more prescriptive because such an
approach would likely result in litigation and delay.\675\
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\672\ Ameren Initial Comments at 7-8; American Municipal Power
Initial Comments at 7; APPA Initial Comments at 25; CAISO Initial
Comments at 21; Chemistry Council Initial Comments at 5; Michigan
Commission Initial Comments at 4-5; MISO TOs Initial Comments at 15-
17; Omaha Public Power Initial Comments at 3-4; OMS Initial Comments
at 3-5; PJM Initial Comments at 54.
\673\ CAISO Initial Comments at 21; Michigan Commission Initial
Comments at 4-5; MISO TOs Initial Comments at 15-16; OMS Initial
Comments at 3-4.
\674\ OMS Initial Comments at 4-5.
\675\ SERTP Sponsors Reply Comments at 13-14.
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293. American Municipal Power believes that transmission providers
should conduct Long-Term Scenarios in a highly collaborative way with
the full and active participation of all stakeholders.\676\ Similarly,
Six Cities recommend that Long-Term Scenarios be coordinated between
state and local regulatory authorities to reflect varying policies. Six
Cities recommend that, in CAISO, Long-Term Scenarios should consider
the procurement choices of non-jurisdictional utilities, such as Six
Cities, as well as policy portfolios provided by California
Commission.\677\
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\676\ American Municipal Power Initial Comments at 7.
\677\ Six Cities Initial Comments at 4.
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294. Some commenters oppose the NOPR proposal to require Long-Term
Scenarios in Long-Term Regional Transmission Planning.\678\ Dominion
argues for maximum flexibility for planning assumptions to support
reliable and affordable transmission service for customers.\679\ Idaho
Commission states that any prescription for scenario analysis should be
supported by clear evidence of a deficiency.\680\ Instead of specific
scenario planning requirements, Nebraska Commission states that the
Commission should provide general guidelines and as much flexibility as
possible to transmission providers, who--along with state regulatory
officials--are best situated to evaluate the needs of each transmission
planning region.\681\
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\678\ Dominion Initial Comments at 10; Idaho Commission Initial
Comments at 3; Nebraska Commission Initial Comments at 3; Ohio
Consumers Initial Comments at 2, 5; Potomac Economics Initial
Comments at 2.
\679\ Dominion Initial Comments at 10-12.
\680\ Idaho Commission Initial Comments at 3.
\681\ Nebraska Commission Initial Comments at 3.
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295. Potomac Economics questions the NOPR's proposal to require
Long-Term Scenarios, stating that it will force RTOs/ISOs to plan and
commit to sizable transmission investment costs based on uncertain
factors and unreasonable speculation on factors such as the location of
future generation, retirements, grid enhancing technologies, and
transmission reconfiguration options.\682\ Potomac Economics also
questions the usefulness of Long-Term Scenarios, asserting that future
congestion patterns will be increasingly uncertain given that the
higher penetration of intermittent resources will cause larger
fluctuations in transmission flows, making it more difficult to
accurately estimate the benefits of transmission upgrades.\683\ Potomac
Economics argues that many of the most beneficial transmission upgrades
address very specific constraints, are smaller in size, can be
difficult to identify in advance, and can be very sensitive to modest
changes in generation and load.\684\
---------------------------------------------------------------------------
\682\ Potomac Economics Initial Comments at 2, 4.
\683\ Id. at 2.
\684\ Id. at 3.
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b. Applying Scenario Planning to Reliability and Economic Planning
296. California Commission and City of New York assert that the
Commission should require the use of Long-Term Scenarios in all
transmission planning processes--not just Long-Term Regional
Transmission Planning.\685\ City of New York argues that such a
requirement would enable consideration of a broad range of potential
future system conditions across multiple planning categories.\686\
Similarly, NYISO states that the final order should authorize, but not
require, the use of multiple alternative scenarios in existing
transmission planning processes. NYISO states that doing so would
enhance its ability to anticipate and solicit more efficient, holistic
transmission solutions, which would support system reliability and
resilience.\687\
---------------------------------------------------------------------------
\685\ California Commission Initial Comments at 22-24; City of
New York Initial Comments at 7.
\686\ City of New York Initial Comments at 7.
\687\ NYISO Initial Comments at 14-15.
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297. In contrast, certain commenters oppose requiring transmission
providers to incorporate some form of scenario analysis into their
existing reliability and economic regional transmission planning
processes.\688\ Duke contends that the Commission should avoid
disrupting existing regional transmission planning processes that work
well.\689\ MISO notes that, while this type of scenario-based planning
has been applied to economic transmission planning processes and could
be applied to existing reliability transmission planning processes,
such application should be flexible and tailored to the unique needs of
each transmission provider, adding that scenario-based planning
requires considerable time and resources.\690\
---------------------------------------------------------------------------
\688\ Duke Initial Comments at 2, 10-11; Eversource Initial
Comments at 19; MISO Initial Comments at 32; NESCOE Initial Comments
at 23; PJM Initial Comments at 54-56.
\689\ Duke Initial Comments at 2, 10-11.
\690\ MISO Initial Comments at 32.
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3. Commission Determination
298. We adopt, with modification, the NOPR proposals to require
transmission providers in each transmission planning region to (1)
develop and use Long-Term Scenarios as part of Long-Term Regional
Transmission Planning and (2) use those Long-Term Scenarios to identify
and evaluate Long-Term Regional Transmission Facilities needed to meet
Long-Term Transmission Needs. As further explained in subsequent
sections of this final order, we find that these requirements regarding
the development and use of Long-Term Scenarios in Long-Term Regional
Transmission Planning strike a reasonable balance between ensuring that
Long-Term Regional Transmission Planning reasonably identifies Long-
Term Transmission Needs over a sufficiently long-term, forward-looking
transmission planning horizon and providing sufficient flexibility for
transmission providers to develop and use Long-Term Scenarios in a way
that reflects the unique characteristics of their respective
transmission planning regions.
299. We first address the definition of Long-Term Transmission
Needs. For purposes of this final order, Long-Term Transmission Needs
are transmission needs identified through Long-Term Regional
Transmission Planning by, among other things and as discussed in this
final order, running scenarios and considering the enumerated
categories of factors. As explained in the NOPR, the drivers of
transmission needs are diverse and include, but are not limited to,
evolving reliability concerns, changes in the resource mix, and changes
in demand. For example, as identified in the NOPR, reliability concerns
giving rise to Long-Term Transmission Needs include, among other
things, the increasing frequency of high-impact extreme weather events,
the increasing reliance by transmission system operators on regional
integration and coordination to reliably serve load, the operational
challenges created by the increasing share of variable resources
entering the resource mix, and changes in electric demand patterns such
as shifts in load profiles caused by, for example, the emergence of
large loads associated with evolving industrial and commercial needs
such as the growth in data centers, and increased electrification of
energy end uses.\691\
---------------------------------------------------------------------------
\691\ See NOPR, 179 FERC ] 61,028 at PP 45, 51.
---------------------------------------------------------------------------
300. In the NOPR, the Commission referred to transmission needs
identified through Long-Term Regional Transmission Planning largely as
needs
[[Page 49336]]
driven by changes in the resource mix and demand.\692\ Nevertheless, we
agree with commenters who correctly note that there are additional
drivers of Long-Term Transmission Needs,\693\ and, as noted above, the
Commission itself contemplated in the NOPR that Long-Term Regional
Transmission Planning would consider drivers beyond those tied directly
to changes in supply and demand. We therefore clarify that, although
changes in the resource mix and demand are important drivers of Long-
Term Transmission Needs, they represent only a subset of such drivers.
In addition, we note that Long-Term Transmission Needs are similar in
kind to transmission needs identified through existing regional
transmission planning processes established under Order No. 1000. Where
Long-Term Transmission Needs differ is their identification through the
long-term, forward-looking, and more comprehensive regional
transmission planning and cost allocation processes established in this
final order. Accordingly, in this final order, we refer to the
transmission needs that are identified through Long-Term Regional
Transmission Planning as Long-Term Transmission Needs. The
identification of Long-Term Transmission Needs and Long-Term Regional
Transmission Facilities to potentially meet those needs is accomplished
through the use of Long-Term Scenarios in Long-Term Regional
Transmission Planning.
---------------------------------------------------------------------------
\692\ Id.
\693\ See, e.g., AEE Initial Comments at 7-8 (noting that
reforms are needed to meet transmission needs driven by ``market
forces, state policies, and new reliability and resilience
imperatives''); ELCON Initial Comments at 4 (``[L]ong term scenario
planning should not be limited to anticipated resource mix but also
take into consideration impacts on reliability and congestion
management.''); New Jersey Commission Initial Comments at 2 (``[T]he
Board stresses that most of the reforms the Commission is proposing
would be necessary even in the absence of `changes in the resource
mix and demand.' '') (citing NOPR, 179 FERC ] 61,028 at P 24);
Renewable Northwest Initial Comments at 8 (noting how current
transmission planning processes ignore both ``trends in future
generation and the impact of extreme weather events'') (citing NOPR,
179 FERC ] 61,028 at P 51); Southeast PIOs Initial Comments at 7-8
(noting that both intensifying ``changes in the generation mix'' and
``increasingly common extreme weather and high-intensity, low
frequency events'' burden the existing transmission system).
---------------------------------------------------------------------------
301. As discussed in the Requirement for Transmission Providers to
Use a Set of Seven Required Benefits section of this final order, we
require transmission providers to measure and use a set of seven
required benefits in Long-Term Regional Transmission Planning.
Transmission providers must use this same set of benefits to help to
inform their identification of Long-Term Transmission Needs. For
example, in this final order we require transmission providers to
measure and use production cost savings in Long-Term Regional
Transmission Planning. As such, when transmission providers are working
to identify Long-Term Transmission Needs, areas of significant
congestion on the transmission system--where Long-Term Regional
Transmission Facilities could reduce congestion and in turn facilitate
production cost savings--may indicate a Long-Term Transmission Need.
302. We adopt the definition of Long-Term Scenarios proposed in the
NOPR,\694\ with modification. We define Long-Term Scenarios as
scenarios that incorporate various assumptions using best available
data inputs about the future electric power system over a sufficiently
long-term, forward-looking transmission planning horizon to identify
Long-Term Transmission Needs and enable the identification and
evaluation of transmission facilities to meet such transmission needs.
We make this modification to clarify the intent of the definition
proposed in the NOPR, rather than modify the definition in substance.
---------------------------------------------------------------------------
\694\ In the NOPR, the Commission proposed to define Long-Term
Scenarios as a tool to identify transmission needs driven by changes
in the resource mix and demand--and enable the evaluation of
transmission facilities to meet such transmission needs--across
multiple scenarios that incorporate different assumptions about the
future electric power system over a sufficiently long-term, forward-
looking transmission planning horizon. NOPR, 179 FERC ] 61,028 at P
84.
---------------------------------------------------------------------------
303. Certain commenters assert that the Commission should not
require transmission providers to develop Long-Term Scenarios due to
the inherent uncertainty of forecasting future transmission needs over
a long transmission planning horizon. We acknowledge the inherent
uncertainty involved in planning to meet Long-Term Transmission Needs.
However, we believe that such uncertainty is mitigated by using Long-
Term Scenarios themselves, as noted by Concerned Scientists and
NARUC.\695\ Scenario planning allows transmission providers to evaluate
whether Long-Term Regional Transmission Facilities are beneficial in
more than one scenario. Transmission providers may also examine whether
Long-Term Transmission Needs appear in one or more scenarios. Scenario
planning also allows transmission providers to consider a broader range
of future circumstances and be better prepared for changes in the
electric power system.\696\ Finally, transmission providers may use
scenario planning to determine whether identified Long-Term Regional
Transmission Facilities provide sufficient benefits across more than
one scenario when considering whether to select such facilities, as
also noted by NARUC.\697\ Moreover, we adopt requirements for Long-Term
Scenarios, as discussed further below, to ensure they are based on
reasonable assumptions and better reflect future transmission system
conditions and uncertainties in those future circumstances. In sum,
incorporating Long-Term Scenarios into Long-Term Regional Transmission
Planning provides an appropriate approach to ensure just and reasonable
rates by accounting for the increasing uncertainty in the accuracy of
assumptions over longer (i.e., over 10 years) transmission planning
horizons and mitigating the risks of under-building or over-building
Long-Term Regional Transmission Facilities.
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\695\ Concerned Scientists Reply Comments at 18-19; NARUC
Initial Comments at 4 (citing NOPR, 179 FERC ] 61,028 at PP 86, 88).
\696\ See Policy Integrity Reply Comments at 2.
\697\ NARUC Initial Comments at 4.
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304. Further, we disagree with commenters that suggest that the
Commission should not establish specific Long-Term Scenario
requirements and that imposing general principles is sufficient to
ensure just and reasonable rates. We find that Long-Term Regional
Transmission Planning that does not incorporate Long-Term Scenarios
that meet the requirements of this final order would fail to ensure
that transmission providers identify Long-Term Transmission Needs, as
well as identify and evaluate Long-Term Regional Transmission
Facilities to address those needs. For example, relying on a single
forecast of future transmission system conditions may limit
transmission providers' and stakeholders' confidence in identified
Long-Term Transmission Needs, and accordingly the evaluation of Long-
Term Regional Transmission Facilities to address those needs. Further,
failure to incorporate Long-Term Scenarios would increase the
likelihood of piecemeal and relatively inefficient or less cost-
effective transmission development. Accordingly, we find that requiring
transmission providers to develop and use Long-Term Scenarios that meet
the requirements established in this final order as part of Long-Term
Regional Transmission Planning will ensure that Commission-
jurisdictional rates are just and reasonable and not unduly
discriminatory or preferential.
305. Additionally, as stated above and in response to commenters
that emphasize the importance of
[[Page 49337]]
collaboration in developing Long-Term Scenarios, this final order
retains the requirements for an open, coordinated, and transparent
local transmission planning process established in Order No. 890 and
further required for regional transmission planning in Order No.
1000.\698\ For example, consistent with the transparency transmission
planning principle,\699\ transmission providers must make transparent
the methodology, criteria, assumptions, and data used to develop each
Long-Term Scenario. Moreover, as described below, this final order
requires that transmission providers provide meaningful opportunity for
stakeholder input, including from state and local regulators, as well
as non-jurisdictional entities, into the factors used to develop Long-
Term Scenarios.
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\698\ Order No. 1000, 136 FERC ] 61,051 at PP 150-152; Order No.
890, 118 FERC ] 61,119 at P 435.
\699\ Order No. 890, 118 FERC ] 61,119 at P 471.
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306. In response to PJM's request that the Commission clarify that
the role of the state regulator is primary in developing Long-Term
Scenarios, we note that, as described in the Stakeholder Process and
Transparency determination within the Categories of Factors section,
transmission providers retain the ultimate responsibility for
transmission planning.\700\ As such, transmission providers have
discretion, subject to the limits imposed in this final order, to weigh
more heavily one source of information over another, such as weighing
information related to a factor provided by a state regulator more
heavily than information provided by other stakeholders. In response to
California Energy Commission, we find that the final order does not
preclude transmission providers from relying on scenarios developed by
state agencies, provided that the Commission finds that the OATT
provisions governing those Long-Term Scenarios' development comply with
the Long-Term Scenarios requirements of this final order (e.g.,
transmission planning horizon and stakeholder input requirements). We
decline to require the use of Long-Term Scenarios in all transmission
planning processes, as requested by California Commission and City of
New York. The record in this proceeding does not demonstrate that the
incorporation of Long-Term Scenarios in existing Order No. 1000
regional transmission planning processes is necessary to ensure that
Long-Term Regional Transmission Planning is just and reasonable. In
response to NYISO's request that transmission providers be allowed to
use scenario planning in their existing Order No. 1000 regional
transmission planning processes, while we agree that such a practice
may offer benefits, we find that any such request amending existing
transmission planning processes must be submitted in an FPA section 205
filing separate from their compliance filings to this final order.\701\
---------------------------------------------------------------------------
\700\ Id. P 454. There, we stated in response to the suggestion
by some commenters that we require transmission providers to allow
customers to collaboratively develop transmission plans with
transmission providers on a co-equal basis that transmission
planning is the tariff obligation of each transmission provider, and
the pro forma OATT planning process adopted in the final rule is the
means to see that it is carried out in a coordinated, open, and
transparent manner, in order to ensure that customers are treated
comparably. Therefore, the ultimate responsibility for planning
remains with transmission providers.
\701\ We note that an exception to the requirement to file a
separate FPA section 205 filing applies if transmission providers
were to propose a unified transmission planning process, as
discussed above. See supra Participation in Long-Term Regional
Transmission Planning section.
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C. Long-Term Scenarios Requirements
1. Transmission Planning Horizon
a. NOPR Proposal
307. In the NOPR, the Commission proposed to require transmission
providers to develop Long-Term Scenarios as part of Long-Term Regional
Transmission Planning using no less than a 20-year transmission
planning horizon.\702\
---------------------------------------------------------------------------
\702\ NOPR, 179 FERC ] 61,028 at PP 97-100.
---------------------------------------------------------------------------
308. The Commission preliminarily found that a 20-year transmission
planning horizon requirement strikes a reasonable balance between the
current transmission planning horizons used in many transmission
planning regions and the 30-year or longer transmission planning
horizon proposed by some ANOPR commenters. The Commission noted that
the 30-year or longer transmission planning horizon was criticized by
other commenters as speculative or too uncertain. The Commission also
stated that a 20-year transmission planning horizon requirement may be
reasonable because some transmission providers use a 20-year
transmission planning horizon in existing regional transmission
planning processes. In addition, the Commission stated that a 20-year
transmission planning horizon would allow for sufficient time to
identify, plan, and obtain siting and permitting approval for and to
construct regional transmission facilities to meet long-term regional
transmission needs, including those that may take longer than the
average amount of time to go from the planning stage to in-service.
Finally, the Commission stated that a 20-year transmission planning
horizon would allow transmission providers to better leverage economies
of scale by sizing transmission facilities to meet not only nearer-term
transmission needs, but also longer-term transmission needs driven by
changes in the resource mix and demand over time. The Commission
preliminarily found that by assessing transmission needs over a longer
time horizon--for example, starting in year six \703\ through year 20
of the transmission planning horizon--Long-Term Regional Transmission
Planning should be able to identify more efficient or cost-effective
regional transmission facilities to address these needs.\704\
---------------------------------------------------------------------------
\703\ The Commission noted that the North American Electric
Reliability Corporation defines the long-term transmission planning
horizon as covering year six through year 10 and beyond. Id. P 94
n.160.
\704\ Id. PP 97-99 (footnotes omitted).
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b. Comments
i. Support for 20-Year Transmission Planning Horizon
309. Many commenters support the Commission's proposal to require
transmission providers to develop Long-Term Scenarios as part of Long-
Term Regional Transmission Planning using no less than a 20-year
transmission planning horizon.\705\ Several
[[Page 49338]]
commenters generally consider a 20-year transmission planning horizon
to be reasonable, acceptable, or appropriate.\706\ Some commenters
argue that a 20-year transmission planning horizon provides a
reasonable balance between shorter- and longer-term transmission
planning horizons.\707\ National Grid states that a 20-year
transmission planning horizon balances the benefits of prospective
transmission planning with the greater uncertainty that comes with
forecasting system needs over a longer period.\708\ Numerous commenters
argue that a 20-year transmission planning horizon will help to improve
the efficiency and cost of developing transmission and to assess future
transmission needs.\709\
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\705\ ACORE Initial Comments at 1; Advanced Energy Buyers
Initial Comments at 7; AEE Initial Comments at 8; AEP Initial
Comments at 5, 8-12; Amazon Initial Comments at 2-3; BP Initial
Comments at 4-5; Breakthrough Energy Initial Comments at 12-13;
Breakthrough Energy Supplemental Comments at 1; California Water
Initial Comments at 14-15; Certain TDUs Initial Comments at 3, 19;
Clean Energy Associations Initial Comments at 10; Clean Energy
Buyers Initial Comments at 12; Clean Energy States Initial Comments
at 2; Concerned Scientists Reply Comments at 18-19; Cypress Creek
Reply Comments at 4; DC and MD Offices of People's Counsel Initial
Comments at 8; Environmental Groups Supplemental Comments at 2;
Eversource Initial Comments at 14; Form Energy Initial Comments at
2; Georgia Commission Initial Comments at 2-3; GridLab Initial
Comments at 5; Idaho Power Initial Comments at 4; Illinois
Commission Initial Comments at 6; Indicated US Senators and
Representatives Initial Comments at 1; Interwest Initial Comments at
4-5; ITC Initial Comments at 9-11; LADWP Initial Comments at 2;
Minnesota State Entities Initial Comments at 4; National and State
Conservation Organizations Initial Comments at 1; National Grid
Initial Comments at 12-13; Nevada Commission Initial Comments at 7;
New England for Offshore Wind Initial Comments at 2; New Jersey
Commission Initial Comments at 9-10; NextEra Initial Comments at 62;
NYISO Initial Comments at 2; Pacific Northwest State Agencies
Initial Comments at 2; PG&E Initial Comments at 2; Policy Integrity
Initial Comments at 10; PIOs Initial Comments at 15; R Street
Initial Comments at 6; SEIA Initial Comments at 6; SoCal Edison
Initial Comments at 11-12; Southeast PIOs Initial Comments at 43;
SPP Initial Comments at 5-6; SPP Market Monitor Initial Comments at
4-5; State Officials Supplemental Comments at 1 (citing US Climate
Alliance Initial Comments at 2); US Climate Alliance Initial
Comments at 2; US DOE Initial Comments at 10; Vermont Electric and
Vermont Transco Initial Comments at 2; Vermont State Entities
Initial Comments at 5; WE ACT Initial Comments at 3.
\706\ CAISO Initial Comments at 21; EEI Initial Comments at 11;
Entergy Initial Comments at 9; NARUC Initial Comments at 5; New York
TOs Initial Comments at 10; Pine Gate Initial Comments at 19-20; PPL
Initial Comments at 6; WIRES Initial Comments at 7.
\707\ DC and MD Offices of People's Counsel Initial Comments at
8-9; LADWP Initial Comments at 2-3; National Grid Initial Comments
at 12-13.
\708\ National Grid Initial Comments at 12-13.
\709\ AEP Reply Comments at 4-5 (citing MTEP2017 Review at 33-
34); Amazon Initial Comments at 2-3; BP Initial Comments at 5;
Certain TDUs Reply Comments at 5; PIOs Initial Comments at 15.
---------------------------------------------------------------------------
310. New Jersey Commission argues that a 20-year transmission
planning horizon should help to make long-term multi-driver
transmission projects viable by identifying needs and opportunities in
a timeframe that allows states to have a meaningful conversation about
voluntarily funding such projects.\710\ Policy Integrity argues that it
is crucial to model what is going to be needed over the next 20 years
to ensure that short- and medium-term transmission projects are built
efficiently, stating that a longer transmission planning horizon is
reasonable in the context of long-lived transmission assets with long
lead times.\711\
---------------------------------------------------------------------------
\710\ New Jersey Commission Initial Comments at 9-10, 28.
\711\ Policy Integrity Initial Comments at 10.
---------------------------------------------------------------------------
311. US DOE asserts that there is sufficient evidence to extend the
transmission planning horizon to a minimum of 20 years for Long-Term
Regional Transmission Planning to capture power sector changes that
occur during transmission development.\712\ PIOs note that panelists at
the November 2021 Technical Conference suggested a 20-year transmission
planning horizon is necessary, in part, due to long-term public policy
goals.\713\ Acadia Center and CLF similarly argue that transmission
planners should plan over long-term horizons to factor in predictable
trends, such as timelines required under state laws and policies.\714\
---------------------------------------------------------------------------
\712\ US DOE Initial Comments at 10.
\713\ PIOs Initial Comments at 15 (citing Tr. 129-137 (multiple
witnesses)).
\714\ Acadia Center and CLF Initial Comments at 4.
---------------------------------------------------------------------------
312. Several commenters emphasize that a transmission planning
horizon of 20 years is sufficient to account for the amount of time
needed to develop transmission projects, considering the complexity and
challenges of major transmission development.\715\ Eversource states
that a long-term perspective is necessary to take advantage of the
economies of scale that large transmission projects can enable, as well
as to incorporate anticipated changes in generation and load beyond the
traditional transmission planning horizon.\716\ Illinois Commission
states that a 20-year transmission planning horizon is necessary to
properly plan and build transmission and generation resources.\717\
LADWP states that a 20-year transmission planning horizon provides
enough time for transmission projects to be developed and placed in
service when such projects require new rights-of-way without becoming
too speculative.\718\ NextEra contends that a 20-year transmission
planning horizon will ensure that transmission planners anticipate and
plan transmission facilities for needs driven by changes in the
resource mix and demand.\719\
---------------------------------------------------------------------------
\715\ Eversource Initial Comments at 14; Illinois Commission
Initial Comments at 6; LADWP Initial Comments at 2; NextEra Initial
Comments at 62-63; PG&E Initial Comments at 2; PIOs Initial Comments
at 15.
\716\ Eversource Initial Comments at 14.
\717\ Illinois Commission Initial Comments at 6.
\718\ LADWP Initial Comments at 2.
\719\ NextEra Initial Comments at 62-63.
---------------------------------------------------------------------------
313. PIOs state that a 20-year transmission planning horizon should
be the minimum timeframe, explaining that because transmission
facilities can take 15 years to plan, permit, and construct, a 20-year
transmission planning horizon can result in just-in-time planning,
where the transmission plan is developed shortly before the process for
siting and permitting must begin.\720\ GridLab asserts that a 20-year
transmission planning horizon might identify regional transmission
needs that occur after year 10, as well as transmission projects that
would be selected and approved in later transmission planning
cycles.\721\
---------------------------------------------------------------------------
\720\ PIOs Initial Comments at 15.
\721\ GridLab Initial Comments at 8-9.
---------------------------------------------------------------------------
314. Clean Energy States support quick adoption of at least a 20-
year planning horizon because many of their member states have
established 100% clean energy power sector or zero-carbon goals for
their state economies by 2040 or 2050.\722\ California Municipal
Utilities, on the other hand, support a 20-year transmission planning
horizon, but caution that transmission costs identified can be
significant and could rely upon speculative resources that may not come
to fruition, namely off-shore wind development.\723\
---------------------------------------------------------------------------
\722\ Clean Energy States Initial Comments at 2.
\723\ California Municipal Utilities Initial Comments at 6-7.
---------------------------------------------------------------------------
315. Many commenters highlight transmission planning regions with
existing long-term transmission planning that either does or will
conform to the 20-year transmission planning horizon proposed in the
NOPR.\724\ MISO commits to continue using its 20-year forecast period
under this proposed reform.\725\ SPP states that it currently performs
a 20-year assessment that incorporates Long-Term Scenarios at least
once every five years.\726\ New York Transco notes that NYISO's
transmission planning process utilizes multiple cases and scenarios
over a 20-year evaluation horizon.\727\ Acadia Center and CLF note that
ISO-NE recently gained Commission approval for longer-term transmission
studies to undertake long-term transmission planning to 2050.\728\
---------------------------------------------------------------------------
\724\ Acadia and CLF Initial Comments at 3; CAISO Initial
Comments at 15; California Municipal Utilities Initial Comments at
5-6; Clean Energy States Initial Comments at 2; ISO/RTO Council
Initial Comments at 3-4; MISO Initial Comments at 33; MISO TOs
Initial Comments at 17; New York TOs Initial Comments at 2; New York
Transco Initial Comments at 5; NextEra Initial Comments at 63-64
(discussing efforts at CAISO, SPP, and MISO); Omaha Public Power
Initial Comments at 4; PIOs Initial Comments at 14 (pointing to
NYISO and MISO as examples of transmission planning regions already
successfully using a 20-year transmission planning horizon); SPP
Initial Comments at 5-6.
\725\ MISO Initial Comments at 33.
\726\ SPP Initial Comments at 5-6.
\727\ New York Transco Initial Comments at 5 (citing NYISO,
NYISO Tariffs, NYISO OATT, attach. Y section 31.4a (Public Policy
Requirements Planning Process) (23.0.0), section 31.4.6.1).
\728\ Acadia Center and CLF Initial Comments at 3.
---------------------------------------------------------------------------
316. CAISO states that it currently approves transmission projects
in its annual transmission planning process based on a 10-year outlook,
although the CAISO OATT allows for a longer 20-year transmission
horizon outlook to reliably and cost-effectively account for
California's greenhouse gas and renewable energy objectives.\729\ CAISO
explains that its 20-year outlook does not include a process for
approving specific transmission projects, but rather allows
considerations beyond 10 years to inform decisions in its annual
[[Page 49339]]
transmission planning process.\730\ California Municipal Utilities also
highlight CAISO's existing transmission planning processes, noting that
its 20-year transmission outlook calls for an estimated combined
capital cost of $30.5 billion.\731\ NextEra notes that, while many
transmission planning regions use or will use a 20-year transmission
planning horizon, no requirements exist to ensure that these practices
persist.\732\
---------------------------------------------------------------------------
\729\ CAISO Initial Comments at 15.
\730\ Id. at 15-16.
\731\ California Municipal Utilities Initial Comments at 5-6
(citing CAISO, 20-Year Transmission Outlook, Table ES-1: Cost
estimate of transmission development to integrate resources of SB100
Starting Point scenario (Jan. 31, 2022), http://www.caiso.com/InitiativeDocuments/Draft20-YearTransmissionOutlook.pdf).
\732\ NextEra Initial Comments at 64-65.
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317. Several commenters reference existing long-term planning
processes as support for the Commission's proposed 20-year transmission
planning horizon.\733\ NextEra and ACEG explain that longer time
horizons are embedded into existing integrated resource plans, through
law or common practice, and extend into and beyond 2040 to meet
ambitious resource goals.\734\ R Street argues that, for benchmarking
purposes, 20- to 25-year planning horizons have been a best practice
for integrated resource planning for decades.\735\
---------------------------------------------------------------------------
\733\ BP Initial Comments at 5 (citing CAISO's transmission
planning process); Idaho Power Initial Comments at 4 (noting
NorthernGrid's 20-year transmission planning horizon); Interwest
Initial Comments at 5 (noting existing state resource planning
processes); Nevada Commission Initial Comments at 7 (noting its
integrated resource planning process requiring a minimum of eight
years); PIOs Initial Comments at 14 (noting 20-year horizons used by
NYISO, MISO, and other transmission planning regions); SPP Market
Monitor Initial Comments at 4-5 (noting SPP's existing transmission
planning process); Western PIOs Initial Comments at 28-29 (noting
Western Electricity Coordinating Council's planning scenarios and
the integrated resource planning timelines of western vertically-
integrated utilities).
\734\ ACEG Reply Comments at 4-5; NextEra Initial Comments at
62-63.
\735\ R Street Initial Comments at 6.
---------------------------------------------------------------------------
318. LADWP asserts that the proposed 20-year transmission planning
horizon is likely the least disruptive horizon because of its current
use by many transmission providers. LADWP further argues that a
consistent transmission planning horizon will optimize asset investment
and minimize public impacts; facilitate planning, coordination, and
development of large-scale regional transmission projects; and ensure
that transmission providers consider the same end point assessments of
the evolving resource mix, environmental requirements that develop
beyond a typical 10-year period, and significant maintenance and
retirement issues.\736\
---------------------------------------------------------------------------
\736\ LADWP Initial Comments at 2.
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ii. Requests for Flexibility
319. Several commenters recommend that the Commission provide
transmission providers in each transmission planning region with the
flexibility to propose other transmission planning horizons that may be
appropriate and beneficial based on their planning processes.\737\ APS
states that it is not convinced that a prescriptive approach will yield
the benefits that the Commission seeks.\738\
---------------------------------------------------------------------------
\737\ Ameren Initial Comments at 13; APPA Initial Comments at 5;
California Water Initial Comments at 14-15; EEI Initial Comments at
11; Indicated PJM TOs Initial Comments at 10; ISO-NE Initial
Comments at 22-23; MISO TOs Initial Comments at 17; NARUC Initial
Comments at 5-6; NESCOE Initial Comments at 25; New York State
Department Initial Comments at 3; New York TOs Initial Comments at
10; Pennsylvania Commission Initial Comments at 5; TANC Initial
Comments at 10; WIRES Initial Comments at 7; Xcel Initial Comments
at 9.
\738\ APS Initial Comments at 3.
---------------------------------------------------------------------------
320. NESCOE states that there is not one ``right'' transmission
planning horizon and that it does not support a one-size-fits-all
transmission planning horizon requirement.\739\ NESCOE requests that
the Commission allow transmission providers in each transmission
planning region to demonstrate that existing tariff provisions are
consistent with or superior to a final order mandating a minimum
transmission planning horizon, explaining--along with ISO-NE--that ISO-
NE's Tariff does not provide a prescribed timeframe to request
transmission analyses based on state-provided scenarios.\740\
Relatedly, California Commission suggests that, instead of mandating a
20-year transmission planning horizon, the Commission should adopt
NYISO's recommendation to provide transmission providers with the
discretion, up to 20 years, to plan for their needs.\741\
---------------------------------------------------------------------------
\739\ NESCOE Initial Comments at 23-24.
\740\ ISO-NE Initial Comments at 22-23; NESCOE Initial Comments
at 24-25.
\741\ California Commission Initial Comments at 11-12 (citing
NYISO ANOPR Initial Comments at 37).
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321. PG&E understands that not every transmission need identified
in the latter years of a 20-year transmission planning horizon will
require immediate selection resolution, and it therefore asks the
Commission to give individual transmission planning regions the
flexibility to determine how to allow for monitoring and updating
planning assumptions for transmission projects that meet transmission
needs beyond 10 years.\742\ ISO-NE argues that the Commission should
permit an approach that allows (but does not require) a transmission
planning horizon beyond 10 years because the 20-year transmission
planning horizon could potentially limit the identification of system
issues during interim years, inhibit adaptation to evolving policies,
and preclude the transmission planning process from considering public
policies that may include shorter timeframes, which may limit the
ability to adapt to emerging needs or changing laws.\743\ NESCOE
contends that a rigid 20-year transmission planning horizon may be
counterproductive and could divert resources focused on meeting
requests under ISO-NE's longer-term transmission planning process to
study a time horizon that states, stakeholders, and ISO-NE may not find
useful.\744\
---------------------------------------------------------------------------
\742\ PG&E Initial Comments at 4-6.
\743\ ISO-NE Initial Comments at 22-23.
\744\ NESCOE Initial Comments at 24-25.
---------------------------------------------------------------------------
322. OMS argues that the final order should permit flexibility in
transmission planning horizons and enable transmission planning regions
to meet objectives through routine scenario-based planning within an
appropriate study window.\745\ Industrial Customers assert that
transmission planning horizons should consider the time to identify,
plan, and obtain siting and permitting approval to construct regional
transmission facilities, and that timing can vary dramatically by
region. Industrial Customers believe a stringent 20-year transmission
planning horizon could create more uncertainty, resulting in stranded
transmission investments and increased transmission rates because it is
difficult, if not impossible, to forecast transmission needs and
requirements 20 years into the future.\746\
---------------------------------------------------------------------------
\745\ OMS Initial Comments at 4-5.
\746\ Industrial Customers Reply Comments at 4-5.
---------------------------------------------------------------------------
323. PJM States recommend, and Clean Energy Associations agree,
that instead of requiring a transmission planning horizon of a
particular length, the Commission should require each transmission
provider to demonstrate that the transmission planning horizon it
chooses is adequate to achieve the goals of Long-Term Regional
Transmission Planning.\747\
---------------------------------------------------------------------------
\747\ Clean Energy Associations Reply Comments at 5-6; PJM
States Initial Comments at 4.
---------------------------------------------------------------------------
324. New York State Department recommends that the final order
allow states to determine the appropriate transmission planning horizon
since New York Public Service Commission has already issued orders
directing long-term transmission and distribution
[[Page 49340]]
planning with undefined terms.\748\ EEI and US Chamber of Commerce
explain that state regulators may not appreciate a rigid 20-year
transmission planning horizon requirement given that some state
resource procurement processes use a 10-year outlook, and the proposed
transmission planning process may thus make resource decisions that are
not state-sanctioned.\749\ Consistent with their Coordinated Grid
Planning Process, New York Commission and NYSERDA assert that the
Commission should allow state regulators to help determine the
appropriate transmission planning horizon, especially in a single-state
RTO/ISO such as NYISO.\750\
---------------------------------------------------------------------------
\748\ New York State Department Initial Comments at 3.
\749\ EEI Initial Comments at 11; US Chamber of Commerce Initial
Comments at 6.
\750\ New York Commission and NYSERDA Initial Comments at 10-12.
---------------------------------------------------------------------------
325. Louisiana Commission states that a 20-year transmission
planning horizon may be longer than the planning horizon utilized in
state integrated resource planning, explaining that its integrated
resource planning rules allow for a 20-year default planning period,
but also for alternative periods, and more importantly, require 5-year
action plans.\751\
---------------------------------------------------------------------------
\751\ Louisiana Commission Reply Comments at 8 (citing Corrected
General Order Docket No R-30021 (LPSC 3/12/2012)).
---------------------------------------------------------------------------
326. APPA argues, and TANC concurs, that the Commission should
allow transmission planning regions to incorporate cost and benefit-
tracking mechanisms to reduce the risk of speculative transmission
projects.\752\
---------------------------------------------------------------------------
\752\ APPA Initial Comments at 26, 36; TANC Initial Comments at
10.
---------------------------------------------------------------------------
iii. Requests for a Different Transmission Planning Horizon
327. Several commenters argue that a 20-year transmission planning
horizon is too long.\753\ Indicated PJM TOs contend that the Commission
should ensure that transmission planning horizons result in the
identification of transmission facilities that can be realistically
planned and developed, and that 20 years may be too long given rapidly
changing technology, generation mix, and demand patterns.\754\
Mississippi Commission also favors a shorter transmission planning
horizon, arguing that there is too much uncertainty to plan 20 to 40
years into the future.\755\ NRECA argues that a 20-year transmission
planning horizon may allow more alternatives to be considered, but cost
efficacy is not guaranteed. Further, NRECA argues that planning beyond
10 years will by necessity devolve into a top-down process that would,
at best, relegate actual load-serving entity resource plans and demand
forecasts to a secondary status or, at worst, ignore them altogether,
violating FPA section 217(b)(4).\756\
---------------------------------------------------------------------------
\753\ Exelon Initial Comments at 4, 7-8; Indicated PJM TOs
Initial Comments at 10; Industrial Customers Initial Comments at 18;
Louisiana Commission Reply Comments at 13; Mississippi Commission
Initial Comments at 12; Nebraska Commission Initial Comments at 3-4;
NRECA Initial Comments at 27-28; NRG Initial Comments at 6-9, 14;
Ohio Consumers Initial Comments at 20; Omaha Public Power Initial
Comments at 3-4; PJM Initial Comments at 5, 58-62; US Chamber of
Commerce Initial Comments at 5-6; Utah Commission Initial Comments
at 13.
\754\ Indicated PJM TOs Initial Comments at 10.
\755\ Mississippi Commission Initial Comments at 12; see also
Louisiana Commission Reply Comments at 13 (citing Mississippi
Commission Initial Comments at 12).
\756\ NRECA Initial Comments at 27-28.
---------------------------------------------------------------------------
328. PJM Market Monitor states that uncertainty increases
significantly as the transmission planning horizon is extended, and the
transmission planning process should be both long-term and flexible,
allowing transmission planners to change plans as reality changes.\757\
Similarly, US Chamber of Commerce asserts that, as the length of the
transmission planning horizon increases, the number of assumptions
increases and the quality of assumptions decreases, rendering costs and
benefits less certain. US Chamber of Commerce states that today's
transmission grid was not forecasted at the turn of the century, and,
thus, forecasts made today for a similar period are likely to under or
over-shoot transmission needs due to new and advancing generation
technologies with commercial operation timeframes not yet known.\758\
Nebraska Commission states that a 20-year transmission planning horizon
may reduce the transmission planning process to an academic exercise
due to the amount of speculation necessarily involved.\759\
---------------------------------------------------------------------------
\757\ PJM Market Monitor Initial Comments at 3.
\758\ US Chamber of Commerce Initial Comments at 6.
\759\ Nebraska Commission Initial Comments at 3.
---------------------------------------------------------------------------
329. Industrial Customers state that the Commission has not ruled
against transmission planning horizons under 15 years and has
acknowledged that the average time needed to develop and build a
transmission project is 10 years.\760\ Industrial Customers assert
that, contrary to the Commission's view, most transmission planners use
10-year transmission planning horizons, and transmission investment
should be driven by shorter timeframes to plan for economic and
reliability needs.\761\ Ohio Consumers note that the 5-year timeframe
used by PJM's DFAX method is characterized by high uncertainty, so a
longer timeframe would exacerbate inaccuracies.\762\
---------------------------------------------------------------------------
\760\ Industrial Customers Initial Comments at 18.
\761\ Industrial Customers Initial Comments at 16-19
(referencing NYISO and the Eastern Interconnection Planning
Collaborative planning processes).
\762\ Ohio Consumers Initial Comments at 20.
---------------------------------------------------------------------------
330. Several commenters argue that a 10-year transmission planning
horizon could reduce speculation, such as with respect to the changing
resource mix.\763\ NRG states that a shorter, 10-year transmission
planning horizon would fit within the time horizon necessary to make
transmission investment decisions and still reflect regional policy
goals.\764\ Utah Commission notes that NorthernGrid's members in 2020
adopted a 10-year transmission planning horizon and objects to being
compelled to abandon that planning horizon in favor of a one-size-fits-
all mandate.\765\
---------------------------------------------------------------------------
\763\ Nebraska Commission Initial Comments at 3-4; NRG Initial
Comments at 6-9, 14; Omaha Public Power Initial Comments at 3-4.
\764\ NRG Initial Comments at 6-9, 14.
\765\ Utah Commission Initial Comments at 13.
---------------------------------------------------------------------------
331. PJM and Exelon advocate for a 15-year transmission planning
horizon to reduce uncertainty and enhance reliability.\766\ Exelon
argues that a 15-year transmission planning horizon may yield less
uncertain forecasts that are more likely to be actionable and better
align with target dates in public policies.\767\ PJM argues that its
current 15-year transmission planning horizon is sufficient to plan and
develop needed transmission, and that forecasts of fuel prices, load
trends, generation retirement, and other relevant parameters become
more uncertain the further one looks out. Moreover, PJM asserts, a
longer transmission planning horizon leads to a greater probability
that a transmission provider will commit to a transmission project that
will look unfortunate in hindsight.\768\
---------------------------------------------------------------------------
\766\ Exelon Initial Comments at 4, 7-8; PJM Initial Comments at
5, 58-62.
\767\ Exelon Initial Comments at 4, 7-8.
\768\ PJM Initial Comments at 59-62 (citing Promoting Regional
Transmission Planning and Expansion to Facilitate Fuel Diversity
Including Expanded Uses of Coal-fired Resources, Notice of Technical
Conference, Docket No. AD05-3-000, at 1 (issued Feb. 16, 2005)).
---------------------------------------------------------------------------
332. Some commenters argue that a transmission planning horizon
longer than 20 years may be warranted to capture the longer-term
benefits of transmission facilities.\769\ ACEG recommends that the
Commission
[[Page 49341]]
consider up to a 40-year transmission planning horizon to match the
expected life of most transmission assets.\770\ CARE Coalition argues
that a 40-year transmission planning horizon would be consistent with
standard practice in economics and public policy of evaluating benefits
over the life of the asset, and that the long lead time to develop
transmission facilities justifies a longer planning horizon.\771\
---------------------------------------------------------------------------
\769\ ACEG Initial Comments at 6-7, 24; CARE Coalition Initial
Comments at 40-41; Interwest Initial Comments at 5; National and
State Conservation Organizations Initial Comments at 1; Pine Gate
Initial Comments at 19-20; PIOs Initial Comments at 15; SEIA Initial
Comments at 6.
\770\ ACEG Initial Comments at 6, 24.
\771\ CARE Coalition Initial Comments at 40-41.
---------------------------------------------------------------------------
iv. Opposition to Requests for a Different Transmission Planning
Horizon
333. Several commenters dispute claims that a 20-year transmission
planning horizon introduces risks from uncertainty and that a shorter
planning horizon is more appropriate.\772\ Southeast PIOs claim that
the risk of unaddressed transmission needs grows over time because of
long lead times needed for transmission development, and that SERTP's
10-year transmission planning horizon prevented Georgia Power from
using that process to plan for its long-term North Georgia Reliability
& Resilience Plan and its goal to integrate 6,000 MW of renewable
resources by 2035.\773\ Southeast PIOs assert that a longer
transmission planning horizon will put future transmission needs on the
radar for transmission planners and, if updated frequently, allow
transmission providers to select transmission facilities conditional on
subsequent transmission planning cycles, which affords planners
flexibility to determine the need for the facility and whether there
are more cost-effective alternatives.\774\ ACORE notes that the NOPR
addresses the uncertainty about the future by requiring the use of
multiple Long-Term Scenarios that are revised every three years.\775\
---------------------------------------------------------------------------
\772\ ACORE Reply Comments at 5 (citing EPSA Initial Comments at
7; ITC Initial Comments at 9; Mississippi Commission Initial
Comments at 12; PJM Initial Comments at 58-62); Concerned Scientists
Reply Comments at 18-19; PJM Initial Comments at 58-62; Southeast
PIOs Reply Comments at 23-25 (citing Dominion Initial Comments at
19; Southern Initial Comments at 19, 32-33).
\773\ Southeast PIOs Reply Comments at 24 (citing Southeast PIOs
Initial Comments at 27-28).
\774\ Id. at 23-25.
\775\ ACORE Reply Comments at 5.
---------------------------------------------------------------------------
334. Several commenters state that the transmission planning
horizon should not extend beyond 20 years to avoid overly speculative
long-term forecasts.\776\ Entergy asserts that looking beyond 20 years
would increase the likelihood of errors, risk billions of dollars in
investments that may prove to be misguided, and amplify the risk of
planning a transmission system that poorly aligns with actual future
needs.\777\ Illinois Commission states that a transmission planning
horizon longer than 20 years would make it difficult to accurately
predict the factors relevant to transmission planning.\778\ Clean
Energy Buyers propose that transmission providers seeking to adopt a
transmission planning horizon beyond 20 years should be required to
demonstrate the justness and reasonableness of that transmission
planning horizon.\779\
---------------------------------------------------------------------------
\776\ Arizona Commission Initial Comments at 3-4; California
Commission Initial Comments at 11-13; Entergy Initial Comments at 9-
11; Georgia Commission Initial Comments at 2-3; Pennsylvania
Commission Initial Comments at 5; US Chamber of Commerce Initial
Comments at 4, 6.
\777\ Entergy Initial Comments at 9-11.
\778\ Illinois Commission Initial Comments at 6.
\779\ Clean Energy Buyers Initial Comments at 12-13.
---------------------------------------------------------------------------
335. Certain TDUs and Louisiana Commission oppose a 40-year
transmission planning horizon.\780\ Certain TDUs emphasize that, as
evidenced by the Michigan Thumb Loop transmission project, assumptions
such as the resource mix can change in as few as seven years.\781\
Louisiana Commission argues that longer periods, such as the 40-year
transmission planning horizon proposed by some commenters, will greatly
increase the risk for errors and wasted investments. According to
Louisiana Commission, transmission planning horizons should neither
exceed the availability of reasonable data and assumptions nor create
unnecessary risks that ratepayers will be required to fund transmission
facilities that do not deliver expected benefits.\782\
---------------------------------------------------------------------------
\780\ Certain TDUs Reply Comments at 3-6 (citing ACEG Initial
Comments at 24); Louisiana Commission Reply Comments at 8.
\781\ Certain TDUs Reply Comments at 3-6.
\782\ Louisiana Commission Reply Comments at 8.
---------------------------------------------------------------------------
v. Meaning and Scope of Transmission Planning Horizon
336. Several commenters request that the Commission define the 20-
year transmission planning horizon as a simple 20-year period, and not
a 20-year period starting from the estimated in-service date of the
transmission facilities, which would result in forecasting transmission
needs beyond 20 years.\783\ Kentucky Commission Chair Chandler states
that the usefulness of Long-Term Regional Transmission Planning and
measuring benefits 20 years after a transmission project's in-service
date will decrease if each project's relative benefits cannot be
adequately measured and identified.\784\ PPL argues that tying the
transmission planning horizon to the study date rather than the
solution in-service date will facilitate a more realistic, certain, and
simple transmission planning process and reduce the need for additional
analysis.\785\ US Chamber of Commerce adds that beginning at the in-
service date of the transmission facilities would extend the effective
transmission planning horizon to 25-30 years, thereby further
increasing the uncertainty of Long-Term Regional Transmission Planning;
thus, US Chamber of Commerce argues the Commission should use the 20-
year transmission planning horizon as a ceiling, rather than a floor,
consistent with the far end of most state planning horizons, which
would protect transmission planners from being forced to plan beyond
the requirements of applicable state law.\786\
---------------------------------------------------------------------------
\783\ Kentucky Commission Chair Chandler Reply Comments at 2;
National Grid Initial Comments at 12-13; PJM States Initial Comments
at 3; PPL Initial Comments at 6; US Chamber of Commerce Initial
Comments at 6.
\784\ Kentucky Commission Chair Chandler Reply Comments at 2.
\785\ PPL Initial Comments at 6.
\786\ US Chamber of Commerce Initial Comments at 6.
---------------------------------------------------------------------------
337. Policy Integrity requests that the Commission clarify the
details of the 20-year time horizon, stating that it is unclear whether
the Commission intended the 20-year time horizon for Long-Term Regional
Transmission Planning to be tied to construction commencing in year
20.\787\ ISO-NE and Policy Integrity seek clarification that, if the
Commission requires that transmission providers must study what is
needed over the next 20 years, transmission providers are not precluded
from evaluating what needs to be built in the short and medium
terms.\788\ Industrial Customers assert that the proposed 20-year
transmission planning horizon is unclear because some commenters
interpret the Commission's proposal as requiring a 20-year transmission
planning horizon for Long-Term Regional Transmission Planning,\789\
while others argue it requires a 20-year transmission planning horizon
in existing regional transmission planning processes.\790\
---------------------------------------------------------------------------
\787\ Policy Integrity Initial Comments at 5.
\788\ ISO-NE Initial Comments at 23; Policy Integrity Initial
Comments at 5.
\789\ Industrial Customers Reply Comments at 5-6 (citing NARUC
Initial Comments at 5).
\790\ Industrial Customers Reply Comments at 5-6 (citing
California Commission Initial Comments at 11).
---------------------------------------------------------------------------
338. Several commenters support a 20-year transmission planning
horizon if Long-Term Scenarios are used to inform the development of
transmission
[[Page 49342]]
facilities but not used to select transmission facilities or to dictate
construction.\791\ TANC does not believe that a 20-year transmission
planning horizon should be used for local transmission planning
processes or selection.\792\ Nebraska Commission states that using a
20-year transmission planning horizon for only research, study, and
projections will avoid speculation, increased costs, and unjust and
unreasonable rates.\793\ NRECA asserts that using a 20-year
transmission planning horizon in Long-Term Regional Transmission
Planning to select transmission projects will not produce the
granularity and certainty needed to assign costs to beneficiaries.\794\
Similarly, Ohio Consumers argue that too little is known about the
location of future loads and resources and the direction of power flows
over 20 years to use a 20-year transmission planning horizon for cost
allocation purposes.\795\ NRG argues that use of a 20-year transmission
planning horizon to allocate costs will lead to unjust and unreasonable
outcomes, and instead, a 10-year transmission planning horizon is
appropriate.\796\ New England Systems state that the Commission should
adjust the NOPR's focus on transmission planning horizons toward an
evolutionary and evidence-based transmission planning process aimed at
mitigating avoidable costs for operating generation out of economic
merit order and at improving the utilization of renewable resources
that experience curtailment due to congestion.\797\
---------------------------------------------------------------------------
\791\ NARUC Initial Comments at 5; Nebraska Commission Initial
Comments at 3; Northwest and Intermountain Initial Comments at 7,
13; NRECA Initial Comments at 23, 29; NRG Initial Comments at 6-9,
14; Ohio Consumers Initial Comments at 20; see also Dominion Reply
Comments at 4-5 (citing NARUC Initial Comments at 5); PJM States
Reply Comments at 9 (citing NARUC Initial Comments at 5).
\792\ TANC Initial Comments at 10.
\793\ Nebraska Commission Initial Comments at 3.
\794\ NRECA Initial Comments at 23-24 (citing GDS Assocs., Inc.,
Report, at 10 (Aug. 17, 2022)).
\795\ Ohio Consumers Initial Comments at 1, 20.
\796\ NRG Initial Comments at 6-9, 14.
\797\ New England Systems Initial Comments at 21-22.
---------------------------------------------------------------------------
339. Some commenters support a 20-year transmission planning
horizon only if the latter portion of the planning horizon is not used
to direct the development of transmission facilities.\798\ SERTP
Sponsors state that the Commission should not require that regional
transmission expansion be based on transmission planning horizons that
are incompatible with the planning horizons used for integrated
resource planning or supply-side resource plan development, or that
involve a degree of speculation that the states comprising a
transmission planning region are not willing to accept.\799\ SPP Market
Monitor contends that if the Commission requires all RTOs/ISOs to
perform a 20-year study, the final order should also provide guidance
on how information determined in that long-term study will be used. SPP
Market Monitor supports a secondary, shorter-term transmission planning
horizon of 10 years that could be based on the results of the longer-
term 20-year studies.\800\
---------------------------------------------------------------------------
\798\ APS Initial Comments at 3-4; Kansas Commission Initial
Comments at 13-14; Maryland Energy Administration Initial Comments
at 3; SERTP Sponsors Initial Comments at 20; Shell Initial Comments
at 21; SPP Market Monitor Initial Comments at 5-6.
\799\ SERTP Sponsors Initial Comments at 20.
\800\ SPP Market Monitor Initial Comments at 5-6.
---------------------------------------------------------------------------
340. Shell suggests that the 20-year transmission planning horizon
include a developmental ``Actionable Period'' for the first 10 years,
during which developers may be willing to invest in generation
projects, or the RTOs/ISOs or utilities may be willing to commit to and
authorize the construction of new transmission. Shell proposes that
there would be an ``Indicative Period'' for the following 10 years,
which would be used to drive the Actionable Period so that the
Commission establishes a process that converges and integrates short,
medium, and long-term planning. Shell asserts that its proposal could
foster more comprehensive and efficient Long-Term Regional Transmission
Planning and inform existing regional transmission planning
processes.\801\ To remove speculative assumptions from Long-Term
Regional Transmission Planning, Arizona Commission similarly suggests
that the Commission divide the 20-year transmission planning horizon
into two equal parts: a ``more certain'' forecast and a ``flexible''
forecast.\802\ Likewise, APS recommends that the Commission adopt a 20-
year transmission planning horizon for ``potential projects'' and a 10-
year planning horizon for ``planned projects'' to provide greater
regional flexibility.\803\
---------------------------------------------------------------------------
\801\ Shell Initial Comments at 19-23.
\802\ Arizona Commission Initial Comments at 3-4.
\803\ APS Initial Comments at 3-4.
---------------------------------------------------------------------------
341. Kansas Commission, Mississippi Commission, and NRECA state
that the results of Long-Term Regional Transmission Planning should be
considered informational only.\804\ Kansas Commission requests that the
Commission establish solid evidentiary and policy bases to support a
20-year transmission planning horizon before imposing such a
requirement.\805\ Mississippi Commission believes that transmission
construction decisions should use a 10-year transmission planning
horizon.\806\
---------------------------------------------------------------------------
\804\ Kansas Commission Initial Comments at 13-14; Mississippi
Commission Reply Comments at 6; NRECA Initial Comments at 23.
\805\ Kansas Commission Initial Comments at 13.
\806\ Mississippi Commission Reply Comments at 6.
---------------------------------------------------------------------------
342. Some commenters rebut arguments that Long-Term Regional
Transmission Planning should be performed for informational purposes
only.\807\ ACEG contends that adopting the proposed transmission
planning methods is essential to accomplishing the Commission's
responsibilities and that less stringent requirements have not led to
much-needed development of high-capacity transmission throughout the
country. ACEG further states that providing informational reports will
do little to remedy undue discrimination and achieve actual
transmission plans.\808\ DC and MD Offices of People's Counsel state
that the potential benefits to ratepayers and other stakeholders of a
20-year transmission planning horizon is significantly diminished if
transmission planning is simply an academic exercise, without actual
impact on future transmission development.\809\ SEIA argues that the
Commission should mandate that scenarios developed under the final
order be used in transmission planning rather than for informational
purposes only or contingent on the approval of state regulators.\810\
---------------------------------------------------------------------------
\807\ ACEG Reply Comments at 10; DC and MD Offices of People's
Counsel Reply Comments at 5; SEIA Reply Comments at 2.
\808\ ACEG Reply Comments at 10.
\809\ DC and MD Offices of People's Counsel Reply Comments at 5.
\810\ SEIA Reply Comments at 2.
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343. Business Council for Sustainable Energy states that
transmission planning should consider the length of time that it takes
for transmission assets to be built and the estimated useful life of
those facilities.\811\ California Municipal Utilities argue, and TANC
concurs, that any lengthening of the transmission planning horizon must
be accompanied by consumer protections that guard against speculative
siting of generation and a rigorous re-evaluation of planning
assumptions and other relevant factors, such as commercial viability of
transmission projects and the associated resources.\812\
---------------------------------------------------------------------------
\811\ Business Council for Sustainable Energy Initial Comments
at 4.
\812\ California Municipal Utilities Initial Comments at 3; TANC
Initial Comments at 10.
---------------------------------------------------------------------------
c. Commission Determination
344. We adopt the NOPR proposal to require transmission providers
in each transmission planning region to develop
[[Page 49343]]
Long-Term Scenarios as part of Long-Term Regional Transmission Planning
using no less than a 20-year transmission planning horizon. We further
clarify that using a transmission planning horizon of no less than 20
years means that transmission providers must develop Long-Term
Scenarios to identify Long-Term Transmission Needs that will
materialize in the 20 years or more following the commencement of the
Long-Term Regional Transmission Planning cycle.
345. In requiring a transmission planning horizon of not less than
20 years, we strike a balance. On the one hand, a 20-year transmission
planning horizon extends far enough into the future that transmission
providers can proactively identify Long-Term Transmission Needs that
could be met with more efficient or cost-effective Long-Term Regional
Transmission Facilities; in contrast, as discussed below, a
transmission planning horizon less than 20 years may limit transmission
providers' ability to adequately plan for Long-Term Transmission Needs.
Specifically, as described in the NOPR, a 20-year transmission planning
horizon allows for more time between when a transmission facility is
identified to meet a future transmission need, and when the
transmission need materializes, allowing for sufficient time to
identify, plan, obtain siting and permitting approval for, and
construct Long-Term Regional Transmission Facilities. Moreover, as some
commenters observe, several transmission providers, including MISO,
SPP, and NYISO, already use a 20-year transmission planning horizon. On
the other hand, based on the record before us, we find that there may
be sufficient uncertainty with regard to system conditions and
transmission needs beyond a 20-year horizon such that it may be
challenging for transmission providers to forecast Long-Term
Transmission Needs across that time period, especially for those
transmission providers that do not presently conduct, and thus do not
have experience with, long-term regional transmission planning.
Accordingly, we decline to adopt a requirement to use a transmission
planning horizon that exceeds 20 years. However, this does not preclude
transmission providers from proposing to use a transmission planning
horizon of more than 20 years.
346. We clarify that transmission providers must plan for the
entire duration of the 20-year transmission planning horizon.
Specifically, transmission providers must, among other requirements
established in this final order, develop and use Long-Term Scenarios to
identify Long-Term Transmission Needs occurring in any period of the
20-year transmission planning horizon and to evaluate potential
transmission solutions to those needs.
347. Certain commenters either misstate aspects of the proposed 20-
year transmission planning horizon or request clarification regarding
the horizon.\813\ We specify that the transmission planning horizon
starts at the beginning of the Long-Term Regional Transmission Planning
cycle and ends 20 years from that date. The transmission planning
horizon is not tied to the in-service date of any identified
transmission solution; rather, potential transmission solutions are
identified after identifying Long-Term Transmission Needs that manifest
during the 20-year transmission planning horizon.
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\813\ Kentucky Commission Chair Chandler Reply Comments at 2;
National Grid Initial Comments at 12-13; PJM States Initial Comments
at 3; PPL Initial Comments at 6; US Chamber of Commerce Initial
Comments at 6.
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348. We disagree with commenters that assert that a 20-year
transmission planning horizon could result in Long-Term Regional
Transmission Planning based on speculative transmission needs \814\ or,
relatedly, that a 20-year transmission planning horizon is only
appropriate if Long-Term Scenarios are not used to select Long-Term
Regional Transmission Facilities.\815\ We find these assertions to be
unfounded. In fact, the Long-Term Regional Transmission Planning
requirements adopted in this final order are designed to avoid over-
building transmission in response to speculative transmission needs
through a series of tools and safeguards, discussed at length
above.\816\ To highlight just one of these safeguards, as discussed in
the Evaluation and Selection of Long-Term Regional Transmission
Facilities section of this final order, we require transmission
providers to reevaluate certain previously selected Long-Term Regional
Transmission Facilities in some circumstances to confirm that the Long-
Term Regional Transmission Facility continues to meet the transmission
providers' selection criteria. This reevaluation process will help
ensure that the continued selection of Long-Term Regional Transmission
Facilities is based on the use of updated information regarding the
existence of a Long-Term Transmission Need and the benefits that
transmission providers expect a Long-Term Regional Transmission
Facility to provide.
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\814\ E.g., TANC Initial Comments at 10.
\815\ NARUC Initial Comments at 5; Nebraska Commission Initial
Comments at 3; Northwest and Intermountain Initial Comments at 7,
13; NRECA Initial Comments at 23, 29; NRG Initial Comments at 6-9,
14; Ohio Consumers Initial Comments at 20; see also PJM States Reply
Comments at 9 (citing NARUC Initial Comments at 5).
\816\ See supra Participation in Long-Term Regional Transmission
Planning section.
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349. We disagree with commenters that assert that the Commission
should adopt a shorter transmission planning horizon.\817\ A
transmission planning horizon of less than 20 years would fail to
sufficiently capture Long-Term Transmission Needs given that at least
some of the drivers of such needs extend up to 20 years into the future
(e.g., many state laws include requirements to be met 15 to 20 years in
the future). Additionally, a shorter minimum transmission planning
horizon may not allow for sufficient time to develop Long-Term Regional
Transmission Facilities with long lead-time requirements or to compare
alternative transmission solutions to identify more efficient or cost-
effective transmission solutions to meet Long-Term Transmission Needs.
---------------------------------------------------------------------------
\817\ Exelon Initial Comments at 4, 7-8; Industrial Customers
Initial Comments at 18; Mississippi Commission Initial Comments at
34; Nebraska Commission Initial Comments at 3-4; NRECA Initial
Comments at 27-28; NRG Initial Comments at 6-9, 14; Omaha Public
Power Initial Comments at 3-4; PJM Initial Comments at 5, 58-62; US
Chamber of Commerce Initial Comments at 6; Utah Commission Initial
Comments at 13.
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350. We disagree with commenters that assert requiring a 20-year
transmission planning horizon is incompatible with planning horizons
used with state integrated resource planning.\818\ In addition to the
discussions in the Overall Need for Reform and Legal Authority to Adopt
Reforms for Long-Term Regional Transmission Planning sections regarding
state integrated resource planning, we note that regardless of the
planning horizon used in a state integrated resource planning process,
the results of that process can be incorporated into Long-Term Regional
Transmission Planning to identify Long-Term Transmission Needs. In
fact, as explained in State-Approved Utility Integrated Resource Plans
and Expected Supply Obligations for Load-Serving Entities (Factor
Category Three) section below, integrated resource plans are part of
the Categories of Factors and thus, transmission providers must
incorporate information on the load-serving entities' projected loads
and resources over the planning horizon. The fact that a state
integrated resource plan does not extend out a full 20 years--or
extends further
[[Page 49344]]
into the future--does not change the obligation for transmission
providers to incorporate the information that is available over the 20-
year transmission planning horizon.
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\818\ SERTP Sponsors Initial Comments at 21.
---------------------------------------------------------------------------
351. In response to ISO-NE, and Policy Integrity,\819\ the 20-year
transmission planning horizon is distinct from the requirement to
calculate benefits of an identified Long-Term Regional Transmission
Facility over a minimum of 20 years from the estimated in-service date,
as discussed in the Required Benefits section.
---------------------------------------------------------------------------
\819\ ISO-NE Initial Comments at 23; Policy Integrity Initial
Comments at 5.
---------------------------------------------------------------------------
2. Frequency of Long-Term Scenario Revisions
a. NOPR Proposal
352. In the NOPR, the Commission proposed to require each
transmission provider to develop Long-Term Scenarios at least every
three years, by reassessing whether the data inputs and factors
incorporated in the previously developed Long-Term Scenarios need to be
updated and then revising the Long-Term Scenarios as needed to reflect
updated data inputs and factors. The Commission also proposed to
require that the development of Long-Term Scenarios be completed within
three years, before the next three-year assessment commences.\820\
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\820\ NOPR, 179 FERC ] 61,028 at P 97.
---------------------------------------------------------------------------
353. The Commission preliminarily found that a three-year frequency
requirement balances the need of transmission providers to reassess
changes in the resource mix and demand, as technology, markets, and
policies have the potential to rapidly change, against the burden of
developing Long-Term Scenarios that can take a year or longer to
produce. The Commission stated that this three-year frequency
requirement would allow transmission providers to identify new
transmission needs driven by changes in the resource mix and demand
during the interim years of the transmission planning period, and
update previously identified transmission needs, if warranted.\821\
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\821\ NOPR, 179 FERC ] 61,208 at P 99.
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b. Comments
i. Support for Frequency of Long-Term Scenario Revisions
354. Many commenters support the Commission's proposal to require
transmission providers in each transmission planning region to develop
Long-Term Scenarios at least every three years, by reassessing whether
the data inputs and factors incorporated in their previously developed
Long-Term Scenarios need to be updated and then revising the Long-Term
Scenarios as needed to reflect updated data inputs and factors.\822\
Arizona Commission and Interwest state that the proposed three-year
process aligns with their existing regional transmission planning
processes.\823\ Several commenters assert that this proposal allows for
Long-Term Scenarios to remain accurate and account for material
technological, political, environmental, and operational developments
in the energy industry,\824\ with some commenters indicating that past
experience demonstrates that the energy industry is rapidly
changing.\825\ For example, PIOs share that MISO recently recognized
assumptions in its MISO Transmission Expansion Plan did not capture the
rate of change for the region's fuel mix.\826\
---------------------------------------------------------------------------
\822\ ACORE Initial Comments at 10; Advanced Energy Buyers
Initial Comments at 7; AEE Initial Comments at 8-9; AEP Initial
Comments at 5, 8, 13-14; Amazon Initial Comments at 3; Arizona
Commission Initial Comments at 4; BP Initial Comments at 4;
Breakthrough Energy Supplemental Comments at 1; CAISO Initial
Comments at 21; California Water Initial Comments at 15; Clean
Energy Associations Initial Comments at 10; Clean Energy Buyers
Initial Comments at 13; DC and MD Offices of People's Counsel
Initial Comments at 8; Entergy Initial Comments at 11; Idaho Power
Initial Comments at 4; Interwest Initial Comments at 6-8; Joint
Consumer Advocates Initial Comments at 8; Nevada Commission Initial
Comments at 7; New England Offshore Wind Initial Comments at 2; New
Jersey Commission Initial Comments at 11; NYISO Initial Comments at
18; Pacific Northwest State Agencies Initial Comments at 13-14;
Pennsylvania Commission Initial Comments at 5; PG&E Initial Comments
at 6; PIOs Initial Comments at 16; PJM Initial Comments at 5-6, 63;
SEIA Initial Comments at 6; SPP Market Monitor Initial Comments at
6; US DOE Initial Comments at 11; Vermont State Entities Initial
Comments at 5; WE ACT Initial Comments at 3.
\823\ Arizona Commission Initial Comments at 3; Interwest
Initial Comments at 6-8.
\824\ Advanced Energy Buyers Initial Comments at 7; California
Water Initial Comments at 15; ELCON Initial Comments at 11; Joint
Consumer Advocates at 8; PIOs Initial Comments at 17; SPP Market
Monitor Initial Comments at 6; US DOE Initial Comments at 11.
\825\ Advanced Energy Buyers Initial Comments at 7; ELCON
Initial Comments at 11.
\826\ PIOs Initial Comments at 16-17 (stating that MISO's
prediction for changes in its fuel mix 15 years out in the MISO
Transmission Expansion Plan 2020 Report had already materialized
before that final report was published).
---------------------------------------------------------------------------
355. Pennsylvania Commission states that routine reviews could
update information and data, justify modifications to transmission
plans, and reduce the risk of uneconomic transmission investments.\827\
ELCON notes that the proposed three-year reassessment provides the
opportunity to consult recent data and update the probability of each
scenario, which will produce better outcomes in the transmission
planning process.\828\ Joint Consumer Advocates state that long-term
transmission plans must be revisited regularly and with sufficient
frequency to ensure that they remain accurate and account for material
developments.\829\ AEE states that triennial updates will provide a
suitable amount of time for stakeholders to complete comprehensive
studies while also ensuring that scenarios do not become stale as
advanced energy technology deployment scales more rapidly and policy
changes disrupt existing assumptions.\830\
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\827\ Pennsylvania Commission Initial Comments at 5.
\828\ ELCON Initial Comments at 11.
\829\ Joint Consumer Advocates Initial Comments at 8.
\830\ AEE Initial Comments at 8-9.
---------------------------------------------------------------------------
356. Louisiana Commission avers that the proposed three-year
reassessment will prevent transmission providers from ignoring changes
that might better reflect future assumptions.\831\ PIOs state that a
three-year update will also help address issues that could occur if a
transmission provider is too aggressive or conservative when defining
scenarios.\832\ DC and MD Offices of People's Counsel recommend that
plans be updated every three years.\833\
---------------------------------------------------------------------------
\831\ Louisiana Commission Reply Comments at 9.
\832\ PIOs Initial Comments at 17.
\833\ DC and MD Offices of People's Counsel Reply Comments at 2.
---------------------------------------------------------------------------
357. Entergy and Interwest state that a three-year reassessment
cycle balances the need for recent data and the time and resources
needed to develop the updates.\834\ LADWP states that a rolling near-
term planning horizon provides the long-term transmission planning
process with up-to-date information without being too frequent.\835\
New Jersey Commission notes that reassessments more frequent than every
three years would be overly burdensome.\836\ Similarly, Nebraska
Commission states that a frequency shorter than every three years would
require almost constant updates from transmission providers, which
would drive up costs, while a frequency longer than three to five years
could risk the underlying information becoming stale between
revisions.\837\
---------------------------------------------------------------------------
\834\ Entergy Initial Comments at 11; Interwest Initial Comments
at 6.
\835\ LADWP Initial Comments at 3.
\836\ New Jersey Commission Initial Comments at 11.
\837\ Nebraska Commission Initial Comments at 4.
---------------------------------------------------------------------------
358. Certain TDUs suggest that the Commission address concerns that
a three-year review period would put significant strain on transmission
provider resources by clarifying that three-year assessments would
review the key drivers and assumptions behind
[[Page 49345]]
a transmission plan with updates as needed for material changes rather
than a rerun of the full transmission planning process. In addition,
Certain TDUs state that a three-year reassessment of initial
transmission plans would result in more transparency and consideration
of alternatives in the transmission planning process.\838\ In contrast,
PJM requests that the Commission clarify that Long-Term Scenarios would
be completely updated with new data, updated factors, and the best
information available at least every three years, not merely partially
reassessed. PJM also requests that the Commission clarify that scenario
evaluations will not overlap, as re-runs are expensive, and a
predictable three-year clock will make the process run smoothly.\839\
---------------------------------------------------------------------------
\838\ Certain TDUs Reply Comments at 7.
\839\ PJM Initial Comments at 6, 63-64.
---------------------------------------------------------------------------
359. AEP requests that the Commission require all transmission
planning regions to continuously follow the same, consistent three-year
transmission planning cycles to align future efforts and ease burdens
on transmission providers and developers operating in multiple
transmission planning regions and to promote better coordination among
regions concerning potential interregional transmission solutions.\840\
---------------------------------------------------------------------------
\840\ AEP Initial Comments at 5, 8, 13-14; AEP Reply Comments at
5.
---------------------------------------------------------------------------
360. Southeast PIOs support the NOPR proposal to require
transmission providers to reassess and revise Long-Term Scenarios every
three years, arguing that it would synchronize with existing state
processes and ensure that long-term regional transmission plans remain
an up-to-date resource for state planning.\841\ Similarly, Certain TDUs
argue that a five-year transmission planning cycle is too long and that
a three-year transmission planning cycle would be more likely to
account for unforeseen changes, helping to prevent inefficient
transmission development and balance planning for future needs with the
need to quickly identify material changes to planning assumptions.\842\
---------------------------------------------------------------------------
\841\ Southeast PIOs Reply Comments at 25.
\842\ Certain TDUs Reply Comments at 5-6.
---------------------------------------------------------------------------
ii. Concerns About Frequency of Long-Term Scenario Revisions
361. Some commenters urge the Commission to provide flexibility for
transmission providers to determine the frequency at which they must
develop Long-Term Scenarios by reassessing whether the data inputs and
factors incorporated in their previously developed Long-Term Scenarios
need to be updated and then revising the Long-Term Scenarios as needed
to reflect updated data inputs and factors.\843\ EEI requests that the
Commission allow transmission providers in each transmission planning
region to initiate a new Long-Term Scenario process in lieu of a
refresh of old Long-Term Scenarios.\844\ California Commission and
Omaha Public Power argue that requiring transmission providers to
reassess and revise Long-Term Scenarios at least every three years will
create a significant compliance burden without improving planning
outcomes, such as forecast accuracy.\845\
---------------------------------------------------------------------------
\843\ Ameren Initial Comments at 12-13; American Municipal Power
Initial Comments at 33; California Commission Initial Comments at
16; Duke Initial Comments at 11; ISO-NE Initial Comments at 24; MISO
Initial Comments at 28-29; MISO TOs Initial Comments at 17; NARUC
Initial Comments at 6-7; NESCOE Initial Comments at 25-26; OMS
Initial Comments at 4-5; Pacific Northwest State Agencies Initial
Comments at 15; Vermont State Entities Initial Comments at 5; WIRES
Initial Comments at 7.
\844\ EEI Initial Comments at 12.
\845\ California Commission Initial Comments at 16; Omaha Public
Power Initial Comments at 3.
---------------------------------------------------------------------------
362. MISO TOs argue that flexibility is warranted because MISO is
already implementing Long-Term Regional Transmission Planning, as well
as reassessing its data as needed.\846\ MISO states that the NOPR
proposal is overly prescriptive, may not reflect stakeholder and
regional needs, and could result in a compliance exercise without the
prospect of transmission expansion.\847\ NESCOE and OMS suggest that
the Commission require transmission providers to reassess Long-Term
Scenarios at regular intervals but leave the timing of that
reassessment to the transmission planning region.\848\ MISO also
recommends that the Commission allow transmission providers to reuse
Long-Term Scenarios as long as they update the relevant input data to
reflect the latest available information.\849\
---------------------------------------------------------------------------
\846\ MISO TOs Initial Comments at 17.
\847\ MISO Initial Comments at 28.
\848\ NESCOE Initial Comments at 25-26; OMS Initial Comments at
4-5.
\849\ MISO Initial Comments at 29.
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363. Duke asserts that the Commission should allow transmission
planning regions to propose their own cycles to reassess and revise
Long-Term Scenarios to meet the needs of the region, keep pace with
markets and policies across the country, and align their processes with
state integrated resource planning processes.\850\ Similarly, WIRES
requests a variance to the proposed three-year scenario reassessment
requirement because three years may be too short and could potentially
be disruptive or increase costs. WIRES further asks that the Commission
clarify that transmission providers are not required to reassess
previously approved transmission projects as part of their triennial
review process.\851\
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\850\ Duke Initial Comments at 12.
\851\ WIRES Initial Comments at 7.
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364. Pacific Northwest State Agencies state that the Commission
should set three years as a minimum and provide transmission planning
regions with the flexibility to work with states to determine the
appropriate schedule for developing Long-Term Scenarios.\852\
Similarly, Vermont State Entities and Pennsylvania Commission argue
that transmission planning regions should have the flexibility to
conduct reassessments at intervals shorter than every three years.\853\
---------------------------------------------------------------------------
\852\ Pacific Northwest State Agencies Initial Comments at 15.
\853\ Pennsylvania Commission Initial Comments at 5; Vermont
State Entities Initial Comments at 5.
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365. NYISO recommends that the final order should allow
transmission planning regions to modify or add to their Long-Term
Scenarios to account for changes that would significantly affect their
analysis when they occur instead of waiting for the next transmission
planning cycle. NYISO further requests that the Commission clarify
that, if a transmission planning region requires more than three years
to complete a given transmission planning cycle, it may extend the
three-year time period. In addition, NYISO requests that the Commission
permit transmission providers in each transmission planning region to
commence the next Long-Term Regional Transmission Planning cycle using
current information even if the prior transmission planning cycle is
running in parallel. NYISO adds that the Commission should allow
transmission planning regions to use their existing Long-Term Scenarios
for the duration of a Long-Term Regional Transmission Planning cycle,
even if it runs beyond three years, to avoid stopping and re-starting
that cycle due to changes in circumstances.\854\
---------------------------------------------------------------------------
\854\ NYISO Initial Comments at 19.
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366. Some commenters raise concerns that the proposal to require
development of Long-Term Scenarios at least every three years may
create overlapping planning assessments and suggest ways to avoid that
situation.\855\ ISO-NE states that the timeframe for Long-Term Regional
Transmission Planning should account for all the elements of the
process, such as implementing the process for selecting
[[Page 49346]]
transmission solutions, before the next long-term study begins. ISO-NE
indicates that this will allow subsequent Long-Term Regional
Transmission Planning studies to account for the outcomes of the
preceding transmission planning cycle and avoid unnecessary study
overlap between cycles.\856\
---------------------------------------------------------------------------
\855\ Eversource Initial Comments at 15; ISO-NE Initial Comments
at 24; NESCOE Initial Comments at 26; PJM Initial Comments at 63.
\856\ ISO-NE Initial Comments at 24.
---------------------------------------------------------------------------
367. Eversource suggests that the Commission require completion of
project selection before the development of the next set of Long-Term
Scenarios, arguing that it would undermine the project selection
process if the current three-year Long-Term Scenario cycle fails to
include selected transmission facilities from the prior three-year
cycle.\857\
---------------------------------------------------------------------------
\857\ Eversource Initial Comments at 15.
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368. Similarly, NESCOE is concerned that the three-year Long-Term
Scenario cycle requirement is inflexible and could interfere with
existing procedures in New England. NESCOE states that ISO-NE's longer-
term transmission planning process requires that a planning process be
concluded before a new one can begin, and that a request for a longer-
term transmission study may be submitted to ISO-NE no earlier than six
months after the conclusion of the prior study.\858\
---------------------------------------------------------------------------
\858\ NESCOE Initial Comments at 26.
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369. Some commenters argue that requiring transmission providers to
reassess and revise their Long-Term Scenarios every three years may be
too frequent and costly, asserting that between every three and five
years may be more appropriate.\859\ ITC avers that a three-year
transmission planning cycle for Long-Term Regional Transmission
Planning would exceed the capabilities of the transmission providers
administering the process.\860\ Likewise, NRECA asserts that developing
multiple Long-Term Scenarios and updating them every three years will
require significant time and resources, as well as substantial changes
in transmission planning throughout the country. NRECA asserts that
existing power supply and transmission planning models employ different
assumptions that cannot be used to prepare 20-year Long-Term Scenarios,
much less update them every three years.\861\
---------------------------------------------------------------------------
\859\ ACEG Initial Comments at 7, 25; Breakthrough Energy
Initial Comments at 12-13; EEI Initial Comments at 12; Indicated PJM
TOs Initial Comments at 11-12; ITC Initial Comments at 5, 9-11; Pine
Gate Initial Comments at 19-20.
\860\ ITC Initial Comments at 10.
\861\ NRECA Initial Comments at 23 (citing GDS Assocs., Report,
at 8-10 (Aug. 17, 2022)).
---------------------------------------------------------------------------
iii. Support for Different Frequency of Long-Term Scenario Revisions
370. Western PIOs support mandating a two-year timeframe for
revision, as three years may be too long and therefore may miss
important updated data inputs.\862\
---------------------------------------------------------------------------
\862\ Western PIOs Initial Comments at 30.
---------------------------------------------------------------------------
371. Shell argues that the Commission should require transmission
providers to reassess and revise their Long-Term Scenarios every five
years, asserting that the proposal to use three years could create too
much uncertainty and delay the development of renewable generation
being developed to comply with state climate objectives and resource
adequacy requirements in forward-looking capacity markets.\863\
Indicated PJM TOs argue that three years may be insufficient to perform
relevant studies and recommend that the Commission provide transmission
providers with the flexibility to adopt four- or five-year transmission
planning cycles.\864\
---------------------------------------------------------------------------
\863\ Shell Initial Comments at 18-19.
\864\ Indicated PJM TOs Initial Comments at 11-12.
---------------------------------------------------------------------------
372. Exelon argues that a three-year transmission planning cycle is
too short, as it is unlikely that transmission needs will surface
within three years, and that conducting a study so soon could create
uncertainty that recently selected transmission projects will be
revisited. Exelon instead recommends that the final order adopt a five-
year transmission planning cycle requirement with a provision that
requires transmission providers to initiate a new cycle sooner, with
good reason, to better align with the time needed to permit and
construct new transmission infrastructure.\865\
---------------------------------------------------------------------------
\865\ Exelon Initial Comments at 9.
---------------------------------------------------------------------------
373. Similarly, PPL argues that a five-year transmission planning
cycle will allow sufficient time for one transmission planning cycle to
be completed before the subsequent cycle commences.\866\ Pine Gate
states that a five-year transmission planning cycle is warranted given
the size and complexity of transmission planning regions and the time
needed to receive and incorporate stakeholder feedback and to achieve
consensus on cost allocation. Pine Gate further notes that a five-year
transmission planning cycle would more closely align the results of
Long-Term Regional Transmission Planning with the time horizons for
reliability planning and other transmission planning processes.\867\
---------------------------------------------------------------------------
\866\ PPL Initial Comments at 6.
\867\ Pine Gate Initial Comments at 20-21.
---------------------------------------------------------------------------
374. SPP argues in favor of the update procedures in its current
transmission planning processes rather than the three-year schedule for
updating Long-Term Scenarios proposed in the NOPR. SPP states that it
performs a 20-year assessment that incorporates Long-Term Scenarios at
least once every five years and that, on an annual basis, SPP assesses
data inputs and factors incorporated into the assessment.\868\
---------------------------------------------------------------------------
\868\ SPP Initial Comments at 5-6.
---------------------------------------------------------------------------
iv. Miscellaneous Comments
375. Several commenters state that the Commission should regularly
review transmission planning processes and assumptions to account for
new developments.\869\ Pattern Energy states that the best way to make
20-year transmission plans useful is for their outputs to be fed into
near-term (i.e., five-to-seven-year horizon) transmission planning
activities.\870\
---------------------------------------------------------------------------
\869\ Clean Energy Buyers Initial Comments at 13; SREA Reply
Comments at 26-27.
\870\ Pattern Energy Initial Comments at 22.
---------------------------------------------------------------------------
376. ELCON recommends that the Commission hold a technical
conference after the first three-year reassessment period for Long-Term
Scenarios to allow transmission providers to offer their experiences
with and best practices for Long-Term Regional Transmission
Planning.\871\
---------------------------------------------------------------------------
\871\ ELCON Initial Comments at 11.
---------------------------------------------------------------------------
c. Commission Determination
377. We modify the NOPR proposal to require transmission providers
in each transmission planning region to reassess and revise the Long-
Term Scenarios that they use in Long-Term Regional Transmission
Planning at least once every five years. In implementing this
requirement, transmission providers in each transmission planning
region must reassess whether the data inputs and factors incorporated
in previously developed Long-Term Scenarios need to be updated and then
revise those Long-Term Scenarios, as needed, to reflect updated data
inputs and factors. At the outset of a Long-Term Regional Transmission
Planning cycle, transmission providers may develop the new Long-Term
Scenarios either by crafting entirely new Long-Term Scenarios, or by
updating the data inputs and factors of previously developed Long-Term
Scenarios.
378. To assist transmission providers in implementing the
requirement to reassess and revise Long-Term Scenarios used in Long-
Term Regional Transmission Planning at least once every five years, we
clarify that the process, which begins with the development of Long-
Term Scenarios using best available data inputs, and
[[Page 49347]]
proceeds to identifying Long-Term Transmission Needs, measuring the
benefits of Long-Term Regional Transmission Facilities to address those
needs, and evaluating and deciding whether to select Long-Term Regional
Transmission Facilities (collectively, the Long-Term Regional
Transmission Planning cycle),\872\ must conclude at a date that is no
later than five years after the date that it began.
---------------------------------------------------------------------------
\872\ The Long-Term Regional Transmission Planning cycle
encompasses all components of Long-Term Regional Transmission
Planning, including each of these foundational steps.
---------------------------------------------------------------------------
379. While we find that the record supports a five-year interval
before new Long-Term Scenarios must be developed, we also conclude that
transmission providers should not need the full five-year period to
reach the point in Long-Term Regional Transmission Planning at which
they decide whether to select Long-Term Regional Transmission
Facilities that they have evaluated. Accordingly, we require
transmission providers to complete the steps of the Long-Term Regional
Transmission Planning cycle and determine whether to select Long-Term
Regional Transmission Facilities no later than three years from the
date when the Long-Term Regional Transmission Planning cycle
began.\873\ Specifically, we find the record demonstrates that three
years provides sufficient time for transmission providers to develop
Long-Term Scenarios, identify Long-Term Transmission Needs, measure the
benefits of Long-Term Regional Transmission Facilities to address those
needs, and evaluate and decide whether to select Long-Term Regional
Transmission Facilities.\874\ At the same time, we are persuaded by
commenters' concerns that requiring the Long-Term Regional Transmission
Planning cycle to repeat at three-year intervals could be
administratively burdensome, and that the benefit of updating Long-Term
Scenarios every three years may not outweigh those additional
burdens.\875\ We therefore find that requiring selection decisions to
occur within three years of commencing a Long-Term Regional
Transmission Planning cycle, while allowing as long as five years
between the commencement of each planning cycle, strikes an appropriate
balance by ensuring timely identification, evaluation, and selection of
more efficient or cost-effective Long-Term Regional Transmission
Facilities, while balancing the administrative burden associated with
updating the Long-Term Scenarios that form the basis for Long-Term
Regional Transmission Planning during each planning cycle.\876\
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\873\ To be clear, nothing in this final order prevents
transmission providers from evaluating and selecting additional
Long-Term Regional Transmission Facilities after year three of the
Long-Term Regional Transmission Planning cycle and before the next
five-year Long-Term Regional Transmission Planning cycle begins.
However, if Long-Term Regional Transmission Facilities are selected
at year three of the Long-Term Regional Transmission Planning cycle,
those same Long-Term Regional Transmission Facilities cannot be de-
selected during the remainder of the current five-year planning
cycle.
\874\ See ACORE Initial Comments at 10; Advanced Energy Buyers
Initial Comments at 7; AEE Initial Comments at 8-9; AEP Initial
Comments at 5, 8, 13-14; Amazon Initial Comments at 3; Arizona
Commission Initial Comments at 4; BP Initial Comments at 4;
Breakthrough Energy Supplemental Comments at 1; CAISO Initial
Comments at 21; California Water Initial Comments at 15; Clean
Energy Associations Initial Comments at 10; Clean Energy Buyers
Initial Comments at 13; DC and MD Offices of People's Counsel
Initial Comments at 8; Entergy Initial Comments at 11; Idaho Power
Initial Comments at 4; Interwest Initial Comments at 6-8; Joint
Consumer Advocates Initial Comments at 8; Nevada Commission Initial
Comments at 7; New England Offshore Wind Initial Comments at 2; New
Jersey Commission Initial Comments at 11; NYISO Initial Comments at
18; Pacific Northwest State Agencies Initial Comments at 13-14;
Pennsylvania Commission Initial Comments at 5; PG&E Initial Comments
at 6; PIOs Initial Comments at 16; PJM Initial Comments at 5-6, 63;
SEIA Initial Comments at 6; SPP Market Monitor Initial Comments at
6; US DOE Initial Comments at 11; Vermont State Entities Initial
Comments at 5; WE ACT Initial Comments at 3.
\875\ See Ameren Initial Comments at 12-13; American Municipal
Power Initial Comments at 33; California Commission Initial Comments
at 16; Duke Initial Comments at 11; ISO-NE Initial Comments at 24;
MISO Initial Comments at 28-29; MISO TOs Initial Comments at 17;
NARUC Initial Comments at 6-7; NESCOE Initial Comments at 25-26; OMS
Initial Comments at 4-5; Pacific Northwest State Agencies Initial
Comments at 15; Vermont State Entities Initial Comments at 5; WIRES
Initial Comments at 7.
\876\ Accordingly, we decline NYISO's request to clarify that
the transmission provider may extend the transmission planning
cycle. As explained, we find that three years provides sufficient
time to complete the actions necessary to make selection decisions.
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380. We find that requiring transmission providers to reassess and
revise Long-Term Scenarios used in Long-Term Regional Transmission
Planning at least once every five years is necessary to ensure that the
Long-Term Scenarios accurately reflect factors that may change over the
five-year time span, such as changes in technology, load forecasts, or
Federal, federally-recognized Tribal, state, or local laws.
Furthermore, regular scenario reassessment and revision may also
address some of the uncertainty associated with Long-Term Regional
Transmission Planning over a 20-year transmission planning horizon that
some commenters assert may result in under-building or over-building
transmission facilities.\877\ As discussed below in the Specificity of
Data Inputs section, nothing in this final order prohibits transmission
providers from updating the inputs used to inform Long-Term Scenarios
during a Long-Term Regional Transmission Planning cycle.
---------------------------------------------------------------------------
\877\ Industrial Customers Initial Comments at 15-16, 19-21;
NRECA Initial Comments at 18-19, 28; Vistra Initial Comments at 7.
---------------------------------------------------------------------------
381. As discussed in the Evaluation and Selection of Long-Term
Regional Transmission Facilities section of this final order,
transmission providers must designate a point in the evaluation process
at which they will make a decision to either select or not select the
relevant Long-Term Regional Transmission Facility (or portfolio of such
Facilities). Further, we clarify that transmission providers must
conclude a Long-Term Regional Transmission Planning cycle before
developing Long-Term Scenarios at the beginning of the next Long-Term
Regional Transmission Planning cycle. Given that, as we state directly
above, nothing in this final order prevents transmission providers from
evaluating and selecting additional Long-Term Regional Transmission
Facilities after year three of the Long-Term Regional Transmission
Planning cycle and before the next five-year Long-Term Regional
Transmission Planning cycle begins, we further find that transmission
providers must designate the point in time or action that concludes a
Long-Term Regional Transmission Planning cycle. Such designation will
ensure transparency regarding whether the transmission providers are
engaging in the evaluation and selection of additional Long-Term
Regional Transmission Facilities after year three of the Long-Term
Regional Transmission Planning cycle.
382. Some commenters express concern that the proposal to reassess
Long-Term Scenarios in concurrent Long-Term Regional Transmission
Planning cycles would create uncertainty as to which cycle produced the
controlling outcome and would burden stakeholders (e.g., requiring them
to provide input on the development of Long-Term Scenarios for the next
Long-Term Regional Transmission Planning cycle while also requiring
them to provide input on Long-Term Regional Transmission Facilities
being considered for selection from the previous Long-Term Regional
Transmission Planning cycle).\878\ By providing for a period of up to
two years between the date by which transmission
[[Page 49348]]
providers are required to make a decision to select or not select Long-
Term Regional Transmission Facilities and the date by which the next
Long-Term Regional Transmission Planning cycle must commence, and by
clarifying that transmission providers must conclude one Long-Term
Regional Transmission Planning cycle before another begins, this final
order will appropriately minimize confusion regarding overlap between
planning assessments. Specifically, this clarification will allow
transmission providers to use in subsequent Long-Term Regional
Transmission Planning cycles updated base or reference cases that
include all Long-Term Regional Transmission Facilities that were
selected in a previous Long-Term Regional Transmission Planning cycle,
including those not yet in service. We find that including the selected
Long-Term Regional Transmission Facilities in subsequent Long-Term
Regional Transmission Planning cycles will improve the accuracy of
Long-Term Regional Transmission Planning.
---------------------------------------------------------------------------
\878\ Eversource Initial Comments at 15; ISO-NE Initial Comments
at 24; NESCOE Initial Comments at 26.
---------------------------------------------------------------------------
383. In response to WIRES's request,\879\ we clarify that
transmission providers need not routinely reevaluate selected Long-Term
Regional Transmission Facilities. However, we note that, as discussed
further in the Evaluation and Selection of Long-Term Regional
Transmission Facilities section below, we require transmission
providers to reevaluate previously selected Long-Term Regional
Transmission Facilities in certain specified circumstances.
---------------------------------------------------------------------------
\879\ WIRES Initial Comments at 7.
---------------------------------------------------------------------------
384. Given that we are requiring transmission providers in each
transmission planning region to reassess and revise Long-Term Scenarios
used in Long-Term Regional Transmission Planning at least once every
five years, thus establishing the maximum length of the Long-Term
Regional Transmission Planning cycle, we affirm that to the extent that
transmission providers believe that a shorter Long-Term Regional
Transmission Planning cycle is appropriate for their transmission
planning region and circumstances, they may propose on compliance to
conduct Long-Term Regional Transmission Planning more frequently than
every five years.
385. We find AEP's request to require all transmission planning
regions to follow the same-length transmission planning cycles is
beyond the scope of this proceeding.\880\ In the NOPR, we proposed
frequency requirements related to the Long-Term Regional Transmission
Planning cycles but did not propose a requirement for transmission
providers to align their regional transmission planning cycles with
those of the transmission providers in neighboring transmission
planning regions.
---------------------------------------------------------------------------
\880\ AEP Initial Comments at 5, 8, 14; AEP Reply Comments at 5.
---------------------------------------------------------------------------
386. While we do not establish a technical conference after the
first Long-Term Regional Transmission Planning cycle, as ELCON
requests,\881\ the Commission has discretion to conduct additional
proceedings at a future date if it finds they are warranted.
---------------------------------------------------------------------------
\881\ ELCON Initial Comments at 11.
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3. Categories of Factors
a. Requirement To Incorporate Categories of Factors
i. NOPR Proposal
387. In the NOPR, the Commission proposed to require transmission
providers to incorporate specific categories of factors in the
development of Long-Term Scenarios as part of Long-Term Regional
Transmission Planning.\882\ Specifically, the Commission proposed to
require transmission providers to incorporate, at a minimum, the
following categories of factors in the development of Long-Term
Scenarios: (1) Federal, state, and local laws and regulations that
affect the future resource mix and demand; \883\ (2) Federal, state,
and local laws and regulations on decarbonization and electrification;
(3) state-approved utility integrated resource plans and expected
supply obligations for load-serving entities; (4) trends in technology
and fuel costs within and outside of the electricity supply industry,
including shifts toward electrification of buildings and
transportation; (5) resource retirements; (6) generator interconnection
requests and withdrawals; and (7) utility and corporate commitments and
Federal, state, and local goals \884\ that affect the future resource
mix and demand.\885\
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\882\ NOPR, 179 FERC ] 61,028 at PP 104-112.
\883\ Id. P 104 n.189. The Commission explained that ``state or
federal laws or regulations'' meant ``enacted statutes (i.e., passed
by the legislature and signed by the executive) and regulations
promulgated by a relevant jurisdiction, whether within a state,
municipality, or at the federal level.''
\884\ Id. P 104 n.195. The Commission explained that ``goal''
meant ``any commitment or statement expressed in writing that is not
a law or regulation.''
\885\ Id. P 104.
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388. The Commission preliminarily found that incorporating, at a
minimum, these categories of factors in the development of Long-Term
Scenarios is appropriate because these categories of factors affect the
future resource mix and demand, and their incorporation in Long-Term
Scenarios is therefore essential to identifying transmission needs
driven by changes in the resource mix and demand through Long-Term
Regional Transmission Planning.\886\ To the extent that transmission
providers in a transmission planning region would like to incorporate
additional categories of factors in the development of Long-Term
Scenarios, the Commission proposed to require that they demonstrate on
compliance with any final order that the incorporation of more than the
minimum categories is consistent with or superior to any final order in
this proceeding.\887\
---------------------------------------------------------------------------
\886\ Id. P 105.
\887\ Id.
---------------------------------------------------------------------------
389. Also, as discussed in the Coordination of Regional
Transmission Planning and Generator Interconnection Processes section
of the NOPR,\888\ the Commission proposed to require that transmission
providers consider in their Long-Term Regional Transmission Planning
regional transmission facilities that address interconnection-related
transmission needs that the transmission provider has identified
multiple times in the generator interconnection process but that have
never been constructed due to the withdrawal of the underlying
interconnection request(s). The Commission proposed to require that
transmission providers incorporate the specific interconnection-related
needs identified through that proposed reform, in addition to one or
more factors that more generally characterize generator interconnection
withdrawals, as a factor in the generator interconnection requests and
withdrawals category of factors in their development of Long-Term
Scenarios.\889\
---------------------------------------------------------------------------
\888\ Id. PP 166-174.
\889\ Id. P 107.
---------------------------------------------------------------------------
390. The Commission explained that incorporation of the categories
of factors set forth above in developing Long-Term Scenarios would help
facilitate the identification of transmission needs driven by changes
in the resource mix and demand, which the Commission preliminarily
found was necessary to ensure just and reasonable and not unduly
discriminatory or preferential Commission-jurisdictional rates. The
Commission explained that absent a requirement to incorporate these
categories of factors in the development of Long-Term Scenarios,
transmission providers may not incorporate known inputs that likely
will affect the future resource mix and demand. Additionally, the
Commission explained that transmission providers may not adequately
identify transmission needs
[[Page 49349]]
driven by changes in the resource mix and demand and evaluate the
potential benefits of regional transmission facilities that may more
efficiently or cost-effectively meet such needs. The Commission stated
that, as an additional benefit, this requirement would provide clarity
to transmission providers and stakeholders regarding which factors must
be considered in scenario development.\890\
---------------------------------------------------------------------------
\890\ Id. P 111.
---------------------------------------------------------------------------
ii. Comments
(a) Requirement To Incorporate Categories of Factors
391. A number of commenters support the proposal to require
transmission providers to incorporate in their development of Long-Term
Scenarios the seven specific categories of factors identified in the
NOPR.\891\ Georgia Commission asserts that these categories of factors
adequately capture the factors expected to drive changes in the
resource mix and demand,\892\ and APPA states that they reflect
potential drivers of the need for new transmission.\893\
---------------------------------------------------------------------------
\891\ ACEG Initial Comments at 7; Advanced Energy Buyers Initial
Comments at 5; AEE Initial Comments at 9-10; Breakthrough Energy
Initial Comments at 14; Breakthrough Energy Supplemental Comments at
1; City of New York Initial Comments at 7; Clean Energy Associations
Initial Comments at 10-11; Clean Energy Buyers Initial Comments at
14-15; ELCON Initial Comments at 12; Eversource Initial Comments at
16-17; Illinois Commission Initial Comments at 4-5; Kansas
Commission Initial Comments at 14-15; Nevada Commission Initial
Comments at 8; Northwest and Intermountain Initial Comments at 13;
NRECA Initial Comments at 30; OMS Initial Comments at 6;
[Oslash]rsted Initial Comments at 6; Pacific Northwest State
Agencies Initial Comments at 14; PG&E Initial Comments at 6; Pine
Gate Initial Comments at 22; PIOs Initial Comments at 17-18; PJM
Initial Comments at 6, 64; SEIA Initial Comments at 7; Southeast
PIOs Initial Comments at 44-45; US DOE Initial Comments at 11-12.
\892\ Georgia Commission Initial Comments at 4.
\893\ APPA Initial Comments at 27-28.
---------------------------------------------------------------------------
392. AEE asks that the Commission clarify that consideration of
each factor is mandatory, arguing that failing to take into account any
of the seven listed categories of factors would risk under-investment
in regional transmission facilities, which could result in unjust and
unreasonable rates.\894\ Evergreen Action and Pine Gate assert that the
Commission should require that the seven factors are ``incorporated''
instead of ``considered'' in order to make clear that incorporation is
not optional.\895\ Otherwise, Pine Gate states, transmission providers
may ignore certain categories relevant and critical to identifying
needed transmission infrastructure.\896\
---------------------------------------------------------------------------
\894\ AEE Initial Comments at 10.
\895\ Evergreen Action Initial Comments at 4; Pine Gate Initial
Comments at 22-23.
\896\ Pine Gate Initial Comments at 22.
---------------------------------------------------------------------------
393. DC and MD Offices of People's Counsel also urge the Commission
to require that all seven factor categories listed in the NOPR be
included in Long-Term Scenarios.\897\ DC and MD Offices of People's
Counsel and ACEG state that the flexibility proposed in the NOPR could
give transmission providers the option of not considering the last four
factor categories.\898\ SEIA recommends that the Commission establish
guidelines on the information used to determine factors in the last
four factor categories to ensure some level of certainty in how they
are reflected in Long-Term Scenarios.\899\
---------------------------------------------------------------------------
\897\ DC and MD Offices of People's Counsel Initial Comments at
11-12.
\898\ ACEG Initial Comments at 28; DC and MD Offices of People's
Counsel Initial Comments at 11.
\899\ SEIA Initial Comments at 9-10.
---------------------------------------------------------------------------
394. Clean Energy Buyers support the NOPR proposal, arguing that
requiring uniform categories of factors across transmission planning
regions could promote efficiency and interregional coordination.\900\
Southeast PIOs argue that broader consideration of resource trends and
other transmission drivers through comprehensive scenarios will inform
the decision-making of state authorities tasked with approving
transmission facilities.\901\ Indicated US Senators and Representatives
express general support for proactive transmission planning that
considers a broad range of factors.\902\
---------------------------------------------------------------------------
\900\ Clean Energy Buyers Initial Comments at 14-15.
\901\ Southeast PIOs Reply Comments at 26.
\902\ Indicated US Senators and Representatives Initial Comments
at 1.
---------------------------------------------------------------------------
395. MISO TOs, MISO, and OMS state that existing MISO processes
already identify and consider the proposed categories of factors to
develop scenarios for transmission planning.\903\ MISO TOs further
claim that there is no need to require that MISO consider additional
factors.\904\ OMS supports the NOPR's proposed requirements as to the
minimum categories of factors and asserts that the categories of
factors proposed in the NOPR are all included in MISO's existing
transmission planning processes.\905\
---------------------------------------------------------------------------
\903\ MISO Initial Comments at 34-35; MISO TOs Initial Comments
at 18; OMS Initial Comments at 6.
\904\ MISO TOs Initial Comments at 18.
\905\ OMS Initial Comments at 6.
---------------------------------------------------------------------------
396. Some commenters support the NOPR proposal because they note
that it provides transmission providers with flexibility as to the
specific factors they incorporate into their development of Long-Term
Scenarios, as well as how they incorporate those factors.\906\
---------------------------------------------------------------------------
\906\ Exelon Initial Comments at 10-11; Georgia Commission
Initial Comments at 4; Illinois Commission Initial Comments at 7;
NEPOOL Initial Comments at 7.
---------------------------------------------------------------------------
397. A few commenters support the NOPR proposal to allow
transmission providers to incorporate additional categories of factors
if they can demonstrate that doing so is consistent with or superior to
the final order.\907\ Specifically, AEE states that the Commission
should clarify that transmission providers can propose to consider
other categories of factors.\908\
---------------------------------------------------------------------------
\907\ Acadia Center and CLF Initial Comments at 9; Clean Energy
Buyers Initial Comments at 14-15; ELCON Initial Comments at 12;
NESCOE Initial Comments at 27; US DOE Initial Comments at 11-12.
\908\ AEE Initial Comments at 10.
---------------------------------------------------------------------------
398. Pattern Energy states that the Commission should provide
examples of how the categories of factors and their associated
sensitivities may be modeled to ensure that each Long-Term Scenario is
useful for Long-Term Regional Transmission Planning. For example,
Pattern Energy asks whether the different scenarios alter the various
assumptions for each (or some) of the factors. Alternatively, Pattern
Energy asks whether the assumptions remained fixed across scenarios and
different scenarios are designed to evaluate different transmission
solutions.\909\
---------------------------------------------------------------------------
\909\ Pattern Energy Initial Comments at 24.
---------------------------------------------------------------------------
(b) Requests for Flexibility
399. Some commenters argue that the Commission should give
transmission providers more flexibility to determine the appropriate
categories of factors or individual factors to include in their
development of Long-Term Scenarios.\910\ NESCOE contends that providing
flexibility would be consistent with the Commission's approach in Order
No. 1000, where it did not require the identification of transmission
needs driven by any particular Public Policy Requirements.\911\ PG&E
argues that the Commission should allow transmission providers to
experiment with how they define scenarios and factors to best reflect
the policy and planning environments of their transmission
[[Page 49350]]
planning regions.\912\ EEI notes that not all of the factors listed in
the NOPR may be relevant for all transmission planning regions during
every long-term assessment and explains that private sector, Federal,
state, and local public policy goals may diverge or conflict,
especially in multi-state regions.\913\
---------------------------------------------------------------------------
\910\ Alabama Commission Initial Comments at 7; APPA Initial
Comments at 27-28; Dominion Initial Comments at 25; Indicated PJM
TOs Initial Comments at 8-9; MISO Initial Comments at 29; NARUC
Initial Comments at 8-9; New York TOs Initial Comments at 11-12;
NYISO Initial Comments at 8, 20; Pennsylvania Commission Initial
Comments at 5-6; PG&E Initial Comments at 7.
\911\ NESCOE Initial Comments at 27-28 (citing Order No. 1000,
136 FERC ] 61,051 at P 207).
\912\ PG&E Initial Comments at 7.
\913\ EEI Initial Comments at 12-13.
---------------------------------------------------------------------------
400. ISO-NE requests that the Commission provide transmission
providers with flexibility in the consideration of factors for
inclusion in each scenario, noting that the factors may vary from study
to study depending on the study objectives. Specifically, ISO-NE argues
that the Commission should not require that each Long-Term Scenario
account for and consistently reflect the first three categories of
factors: Federal, state, and local laws and regulations on the future
resource mix, decarbonization and electrification, and state-approved
integrated resource plans. ISO-NE emphasizes that the Commission should
not require local laws to be consistently reflected in and accounted
for in Long-Term Scenarios. ISO-NE argues that, in addition to being
too prescriptive, such a requirement would introduce unnecessary and
substantial administrative burdens and compliance risks with the
possibility for inadvertent exclusion of a required law, regulation, or
integrated resource plan. Moreover, ISO-NE contends, it would
unnecessarily prevent testing of variations with these categories of
factors, limiting the usefulness of scenario analysis.\914\
---------------------------------------------------------------------------
\914\ ISO-NE Initial Comments at 26-27.
---------------------------------------------------------------------------
401. Idaho Commission and Idaho Power argue that the NOPR proposal
is too prescriptive.\915\ PJM advises the Commission not to include too
many inflexible details in the implementation of the factors.\916\
However, PJM generally supports the NOPR proposal to create seven
factors that should guide the development of scenarios with some
additions and revisions.\917\
---------------------------------------------------------------------------
\915\ Idaho Commission Initial Comments at 3; Idaho Power
Initial Comments at 5.
\916\ PJM Initial Comments at 67.
\917\ Id. at 6, 64.
---------------------------------------------------------------------------
402. NYISO states that the Commission should not prescribe specific
categories of factors that transmission providers must use and instead
should allow each transmission planning region, in coordination with
state entities and stakeholders, to determine to what extent and how
the seven categories of factors should be applied.\918\ SEIA disagrees,
asserting that each proposed category of factors is broad enough to
reflect regional differences within the category, but suggests that the
Commission provide flexibility on implementation details. SEIA explains
that the categories of factors do not set forth specific requirements
on how much weight each factor should have in each Long-Term Scenario,
what generation mix will result from the mix of factors, or what models
to use. SEIA states that the Commission should allow transmission
providers to include these implementation details in their
manuals.\919\
---------------------------------------------------------------------------
\918\ NYISO Initial Comments at 8, 20.
\919\ SEIA Reply Comments at 3-4.
---------------------------------------------------------------------------
403. Some commenters express support for some or all of the
proposed categories of factors but request that the Commission provide
transmission providers with flexibility in how they incorporate the
factors into their development of Long-Term Scenarios.\920\ For
example, TANC requests that the Commission allow transmission planning
regions, in consultation with stakeholders, to exclude some of the
proposed factors (i.e., regulatory and corporate goals or technology
trends) from their development of Long-Term Scenarios.\921\ TANC also
advocates that the Commission should allow transmission planning
regions to determine the manner in which other factors, namely trends,
resource requirements, generator interconnection requests, and
withdrawals, are incorporated in regional transmission planning
studies. Although SPP states that most of the categories of factors are
appropriate, it contends that requiring the listed factors to be
incorporated, rather than considered, in development of Long-Term
Scenarios could overburden the process.\922\
---------------------------------------------------------------------------
\920\ Ameren Initial Comments at 9-12; APPA Initial Comments at
27-28; Arizona Commission Initial Comments at 5; Eversource Initial
Comments at 16-17; ISO-NE Initial Comments at 26; LADWP Initial
Comments at 3; TANC Initial Comments at 9-10.
\921\ TANC Initial Comments at 9-10.
\922\ SPP Initial Comments at 7-8.
---------------------------------------------------------------------------
404. NEPOOL states that the categories of factors identified in the
NOPR seem generic enough to allow implementation despite regional
differences or changes in circumstances over time but contends that the
Commission should carefully consider different market structures and
potential changes to state policies to ensure that any requirement
accommodates regional differences.\923\ Pine Gate further requests
clarification as to the degree of flexibility that the Commission will
grant to transmission providers in how they incorporate each factor
into Long-Term Scenarios.\924\
---------------------------------------------------------------------------
\923\ NEPOOL Initial Comments at 7.
\924\ Pine Gate Initial Comments at 22-23.
---------------------------------------------------------------------------
(c) Concerns With the Requirement To Incorporate Categories of Factors
405. Large Public Power argues that the NOPR proposal ignores the
Commission's fundamental responsibility to facilitate planning to meet
the needs of load-serving entities, as well as Congress' recognition
that load-serving entities themselves have a fundamental obligation to
build transmission to meet their load.\925\ Large Public Power asserts
that the NOPR proposal to establish factors that look more broadly than
the Commission's core obligations under the FPA threatens to undermine
the needs of load-serving entities and their customers.\926\ Further,
Large Public Power contends that the Commission has no authority to
direct the development of transmission facilities.\927\ Similarly, some
commenters voice concerns with the use of categories of factors to
direct transmission investment.\928\ Louisiana Commission states that
the incorporation of speculative factors would result in a large-scale
transmission build-out to accommodate the policy preference of some, at
the cost of all.\929\
---------------------------------------------------------------------------
\925\ Large Public Power Initial Comments at 19-20 (citing 16
U.S.C. 824q, (e)); see also NRECA Initial Comments at 17-18 (quoting
16 U.S.C. 824q(b)(4)), 19-20).
\926\ Large Public Power Initial Comments at 20-21.
\927\ Id. at 11 (citing 16 U.S.C. 824o(i)(2)).
\928\ Industrial Customers Initial Comments at 11; Louisiana
Commission Initial Comments at 17-19
\929\ Louisiana Commission Initial Comments at 17-19.
---------------------------------------------------------------------------
406. Undersigned States claim that the proposed requirement that
each Long-Term Scenario ``incorporate and be consistent'' with certain
factors does not address potentially irresolvable conflicts over how
certain factors affect the future resource mix and demand.\930\ PPL
criticizes the NOPR for failing to explain how to translate the
proposed factors into usable assumptions that can feed into
transmission planning models, leading to increased uncertainty for
transmission developers and greater difficultly in financing
transmission projects or gaining siting approval.\931\
---------------------------------------------------------------------------
\930\ Undersigned States Initial Comments at 3.
\931\ PPL Initial Comments at 8.
---------------------------------------------------------------------------
(d) Alternative Frameworks
407. Other commenters propose alternative frameworks for
incorporating factors in the development of Long-Term Scenarios. PPL
believes that the Commission's proposed categories of factors are
largely overlapping and can
[[Page 49351]]
be summarized and replaced by a single factor: reasonable expectations
regarding the future resource mix and demand.\932\ ENGIE suggests that,
because the Commission's proposed factors may be too numerous for
transmission providers to model, certain factors (i.e., laws,
regulations, and announced retirements) should be fixed while others
are varied or studied as sensitivities (i.e., costs, demand, and
resource development trends).\933\ PIOs state that the Commission must
set minimum requirements for some factors, asserting that there is
broad support for minimum requirements.\934\
---------------------------------------------------------------------------
\932\ Id. at 7.
\933\ ENGIE Initial Comments at 3.
\934\ PIOs Reply Comments at 10.
---------------------------------------------------------------------------
408. GridLab contends that the Commission's proposal to require
that transmission providers incorporate specific categories of factors
in the development of Long-Term Scenarios cannot be enforced and that
such broad factors will not change investment outcomes. GridLab states
that the proposed list of factors are a helpful minimum standard and
recommends that the Commission focus on whether transmission providers
have meaningfully incorporated them into Long-Term Regional
Transmission Planning.\935\ Further, GridLab avers that local laws and
regulations and corporate commitments are difficult to incorporate into
Long-Term Regional Transmission Planning in a bottom-up, meaningful
way.\936\ As an alternative, GridLab suggests that transmission
providers could use aggregate assumptions and indicative scenario
design and allow state and local agencies, as well as other
stakeholders, to provide inputs into scenario development, and then
evaluate whether the resulting scenarios are consistent with state,
local, and corporate commitments.\937\
---------------------------------------------------------------------------
\935\ GridLab Initial Comments at 21-22.
\936\ Id. at 22.
\937\ Id.
---------------------------------------------------------------------------
iii. Commission Determination
409. We adopt the NOPR proposal to require transmission providers
in each transmission planning region to incorporate the seven specific
categories of factors proposed in the NOPR, as modified in this final
order, in the development of Long-Term Scenarios. Specifically, as
discussed in more detail below, transmission providers must incorporate
in the development of Long-Term Scenarios: (1) Federal, federally-
recognized Tribal,\938\ state, and local laws and regulations affecting
the resource mix and demand; (2) Federal, federally-recognized Tribal,
state, and local laws and regulations on decarbonization and
electrification; (3) state-approved integrated resource plans and
expected supply obligations for load-serving entities; (4) trends in
fuel costs and in the cost, performance, and availability of
generation, electric storage resources, and building and transportation
electrification technologies; (5) resource retirements; (6) generator
interconnection requests and withdrawals; and (7) utility and corporate
commitments and Federal, federally-recognized Tribal, state, and local
policy goals that affect Long-Term Transmission Needs.\939\ We address
each of these categories of factors in the Specific Categories of
Factors determination section below.
---------------------------------------------------------------------------
\938\ We emphasize that we are requiring transmission providers
to incorporate laws and regulations into Long-Term Scenario
development. As noted earlier, while we are providing this
opportunity for federally-recognized Tribes to voluntarily
participate, we are not imposing any requirements on them to
participate.
\939\ Modifications to the title of Factor Categories One, Two,
Four, and Seven are discussed in the Specific Categories of Factors
determination section.
---------------------------------------------------------------------------
410. We find that existing regional transmission planning
requirements fail to ensure that transmission providers adequately
account on a forward-looking basis for known determinants of Long-Term
Transmission Needs.\940\ Many commenters in this proceeding, even some
that may oppose the prescriptiveness of the requirement or otherwise
request more flexibility in how transmission providers account for
factors affecting Long-Term Transmission Needs,\941\ generally agree
that the categories of factors outlined in the NOPR account for many of
the known determinants of such needs. We find that incorporating the
seven categories of factors in the development of Long-Term Scenarios
is necessary because these categories of factors are essential to
identifying Long-Term Transmission Needs. Further, we find that
requiring transmission providers to incorporate the enumerated
categories of factors in Long-Term Regional Transmission Planning will
help to ensure that transmission providers are accounting for known and
identifiable drivers of Long-Term Transmission Needs.
---------------------------------------------------------------------------
\940\ NOPR, 179 FERC ] 61,028 at PP 50-51.
\941\ See, e.g., EEI Initial Comments at 12-13; PJM Initial
Comments at 64-67.
---------------------------------------------------------------------------
411. We are not persuaded by commenters' arguments that certain of
the categories of factors may not be relevant in certain transmission
planning regions and therefore that transmission providers should not
be required to incorporate those categories of factors in the
development of Long-Term Scenarios.\942\ We decline to allow
transmission providers to exclude some of the proposed categories of
factors from being incorporated in the development of Long-Term
Scenarios, as certain commenters request, because we conclude that each
category of factors includes important determinants of Long-Term
Transmission Needs. We are concerned that not requiring incorporation
of all of the proposed categories of factors in Long-Term Scenarios
would increase the likelihood that transmission providers will continue
to underestimate--or omit entirely--certain known determinants of Long-
Term Transmission Needs in their regional transmission planning
processes.
---------------------------------------------------------------------------
\942\ See, e.g., EEI Initial Comments at 12-13; SPP Initial
Comments at 7-8.
---------------------------------------------------------------------------
412. In response to AEE's request, we affirm that the seven
categories of factors adopted in this final order are the minimum set
of known determinants of Long-Term Transmission Needs that transmission
providers must incorporate into the development of their Long-Term
Scenarios, and we decline to adopt the NOPR proposal to require
transmission providers to demonstrate on compliance that the
incorporation of additional categories of factors is consistent with or
superior to any final order in this proceeding.\943\ Transmission
providers may be aware of additional categories of factors beyond those
adopted in this final order that drive Long-Term Transmission Needs
and, thus, should be incorporated into the development of Long-Term
Scenarios. While transmission providers may incorporate additional
categories of factors into the development of Long-Term Scenarios, we
require in this final order that each Long-Term Scenario remains
plausible, as discussed further below.
---------------------------------------------------------------------------
\943\ AEE Initial Comments at 10.
---------------------------------------------------------------------------
413. We clarify that incorporating each category of factors into
the development of Long-Term Scenarios means more than merely
considering each category of factors in the development of Long-Term
Scenarios.\944\ Incorporating a category of factors in the development
of Long-Term Scenarios means that transmission providers must use
factors in the category, for each factor individually or collectively,
to determine the assumptions that will be used in the development of
Long-Term Scenarios. Incorporating a category of factors into the
development of Long-Term
[[Page 49352]]
Scenarios does not require exacting precision; transmission providers
may generalize how all of the discrete factors in a category of factors
will, in the aggregate, affect the development of Long-Term
Scenarios.\945\ However, we expect that similar factors (or groups of
factors) affecting a single assumption used in the development of Long-
Term Scenarios will have an additive effect on that assumption.\946\ We
also expect that incorporating a category of factors into the
development of Long-Term Scenarios will result in scenarios that differ
from scenarios lacking that specific category of factors; that is, the
incorporation of a category of factors should have a measurable impact
on the Long-Term Scenario, compared to that same Long-Term Scenario,
all else equal, if it had not incorporated that category of factors.
---------------------------------------------------------------------------
\944\ Evergreen Action Initial Comments at 4; Pine Gate Initial
Comments at 22-23.
\945\ For example, transmission providers could aggregate the
effect of corporate goals by leveraging publicly available surveys
of corporations' clean energy and electrification goals and then
using those surveys to inform the assumptions used to develop Long-
Term Scenarios (e.g., 10% more clean energy resources and 10% higher
load growth for a Long-Term Scenario that assumes full achievement
of those goals than in a Long-Term Scenario that does not consider
such goals).
\946\ For example, two independent factors that increase the
likelihood of future electric storage resource development (e.g.,
(1) a state law requiring the deployment of at least 5 gigawatts of
electric storage resources by 2030 and (2) a Federal investment tax
credit for the deployment of electric storage resources) would have
a combined effect that exceeds the effect of either factor alone.
---------------------------------------------------------------------------
414. We believe that the best-available data requirement, which we
adopt and discuss further below, should mitigate concerns that
transmission providers may undermine Long-Term Regional Transmission
Planning by not incorporating categories of factors in a meaningful
way.\947\ The best-available data requirement will ensure that the data
inputs that transmission providers use to incorporate categories of
factors are timely, developed using best practices, and diverse and
expert perspectives. We also clarify that, as a consequence of the
requirement that all Long-Term Scenarios must be plausible, as well as
the requirement that all Long-Term Scenarios must be diverse, both of
which we adopt and discuss below, transmission providers must
incorporate the categories of factors in the development of Long-Term
Scenarios in a way that results in plausible and diverse Long-Term
Scenarios.
---------------------------------------------------------------------------
\947\ E.g., ACEG Initial Comments at 28.
---------------------------------------------------------------------------
415. As to the factors within each category that transmission
providers must account for when they incorporate each category of
factors in the development of Long-Term Scenarios, we require
transmission providers to account for the factors that they have
determined are likely to affect Long-Term Transmission Needs. As
explained above, these Long-Term Transmission Needs include, but are
not limited to, evolving reliability concerns and changes in the
resource mix, and changes in demand. For each factor (or group of
similar factors) within each category of factors that transmission
providers identify, in coordination with stakeholders through an open
and transparent process as described below, transmission providers must
make a determination as to how that factor (or group of similar
factors) is likely to affect Long-Term Transmission Needs. Transmission
providers must then account for the factors that they have determined
are likely to affect Long-Term Transmission Needs in the development of
the Long-Term Scenarios used in Long-Term Regional Transmission
Planning. We clarify, however, that transmission providers in a
transmission planning region need not account for a factor,
stakeholder-identified or otherwise, if they determine that factor is
unlikely to affect Long-Term Transmission Needs.
416. We also clarify that a category of factors (e.g., Factor
Category Two: Federal, federally-recognized Tribal, state, and local
laws and regulations on decarbonization and electrification) differs
from a specific factor (e.g., a specific state law with a
decarbonization requirement). We make this distinction because some
commenters use only the word ``factors'' when describing the categories
of factors proposed in the NOPR.\948\
---------------------------------------------------------------------------
\948\ E.g., AEE Initial Comments at 9; Evergreen Action Initial
Comments at 4.
---------------------------------------------------------------------------
417. We disagree with commenters that the categories of factors
requirements are too prescriptive,\949\ and we believe that the
framework adopted in this final order requiring transmission providers
to incorporate categories of factors into the development of Long-Term
Scenarios strikes the right balance between prescriptive requirements
and flexibility. Transmission providers have discretion to determine
whether specific factors must be accounted for within each category
(i.e., if the specific factor will likely affect Long-Term Transmission
Needs), how to account for specific factors in the development of Long-
Term Scenarios (e.g., the method and data used to forecast resource
retirements), and how to vary the treatment of each category of factors
across Long-Term Scenarios (e.g., assume all forecasted resource
retirements materialize in some but not all Long-Term Scenarios), so
long as transmission providers assume that the laws, regulations,
state-approved integrated resource plans, and expected supply
obligations for load-serving entities identified in the first three
categories of factors--that transmission providers have determined are
likely to affect Long-Term Transmission Needs--are fully met (as
discussed below). We believe that each proposed category of factors is
broad enough to allow the transmission providers in each transmission
planning region to reflect regional differences within the category, as
noted by SEIA and NEPOOL.\950\ In response to PG&E's request that we
allow flexibility for transmission providers to use Long-Term Scenarios
that best reflect the individual policy and planning environments in
their specific transmission planning regions, and to Pattern Energy's
questions about how categories of factors may be modeled,\951\ we
clarify that transmission providers have the flexibility to develop
different Long-Term Scenarios specific to their transmission planning
region and develop using assumptions based on the categories of
factors.
---------------------------------------------------------------------------
\949\ ISO-NE Initial Comments at 26; NYISO Initial Comments at
8, 20; PJM Initial Comments at 67.
\950\ NEPOOL Initial Comments at 7; SEIA Reply Comments at 3-4.
\951\ Pattern Energy Initial Comments at 24; PG&E Initial
Comments at 7.
---------------------------------------------------------------------------
418. In response to NESCOE, we decline to give transmission
providers the flexibility to choose which of the proposed categories of
factors to incorporate into Long-Term Scenarios, which NESCOE states
would be consistent with the flexibility that the Commission provided
to transmission providers in Order No. 1000, where it did ``not . . .
require the identification of any particular transmission need driven
by any particular Public Policy Requirements.'' \952\ As noted in The
Overall Need for Reform section, there are deficiencies in the
Commission's existing regional transmission planning requirements,
including that they fail to ensure that transmission providers
adequately account on a forward-looking basis for known determinants of
Long-Term Transmission Needs. We are concerned that, if transmission
providers have flexibility to choose which of the proposed categories
of factors to incorporate into the development of Long-Term Scenarios,
they will continue to underestimate--or omit entirely--certain known
determinants of Long-Term Transmission Needs in their regional
[[Page 49353]]
transmission planning processes. Additionally, we note that
transmission needs are distinct from categories of factors: as
explained above, categories of factors, and specific factors therein,
form the basis for assumptions that will be used in the development of
Long-Term Scenarios that transmission providers will then use to
identify Long-Term Transmission Needs.
---------------------------------------------------------------------------
\952\ NESCOE Initial Comments at 27-28 (citing Order No. 1000,
136 FERC ] 61,051 at P 207).
---------------------------------------------------------------------------
419. We also disagree with arguments that we are directing the
development of specific transmission facilities.\953\ As an initial
matter, transmission providers retain discretion to determine how
specific factors will affect Long-Term Transmission Needs. Moreover,
the categories of factors requirements adopted in this final order do
not create new transmission needs that did not previously exist, but
rather, they improve regional transmission planning processes by
requiring transmission providers to identify Long-Term Transmission
Needs across a plausible and diverse range of future scenarios and to
identify, evaluate, and select Long-Term Regional Transmission
Facilities to address those needs. If transmission providers do not
account in Long-Term Regional Transmission Planning for known
determinants of Long-Term Transmission Needs, then those needs would
still exist and would likely be resolved, if at all, in a relatively
inefficient or less cost-effective manner (e.g., in a piecemeal fashion
through local transmission planning processes and/or generator
interconnection processes). We are not requiring that transmission
providers select any particular Long-Term Regional Transmission
Facility and therefore are not directing the development of any
particular transmission facilities. Finally, we clarify that while the
requirement for transmission providers to incorporate the seven
categories of factors adopted in this final order into the development
of Long-Term Scenarios is intended to ensure that Long-Term Regional
Transmission Facilities are identified for selection to more
efficiently or cost-effectively address Long-Term Transmission Needs,
we do not believe that concerns over whether a transmission provider
appropriately implemented this requirement represent an appropriate
basis on which to challenge the cost allocation for one or more
individual Long-Term Regional Transmission Facilities. Rather, whether
the allocation of costs is just and reasonable and not unduly
discriminatory is governed by the requirement that costs be roughly
commensurate with benefits, as discussed in the Regional Transmission
Cost Allocation section below.
---------------------------------------------------------------------------
\953\ E.g., Large Public Power Initial Comments at 20-21; see
also Alabama Commission Initial Comments at 4; Industrial Customers
Initial Comments at 10; Louisiana Commission Initial Comments at 17-
19; Pennsylvania Commission Initial Comments at 6.
---------------------------------------------------------------------------
420. We disagree with Large Public Power's argument that we are
ignoring the Commission's fundamental responsibility to facilitate
planning to meet the needs of load-serving entities.\954\ As described
below, we are requiring all Long-Term Scenarios to be consistent with
and fully account for factors in Factor Category Three, which includes
state-approved integrated resource plans and the expected supply
obligations of load-serving entities. Therefore, transmission providers
are required to plan to meet the needs of load-serving entities.
---------------------------------------------------------------------------
\954\ Large Public Power Initial Comments at 19-20 (citing 16
U.S.C. 824q, (e)); see also NRECA Initial Comments at 17-18 (quoting
16 U.S.C. 824q(b)(4)), 19-20.
---------------------------------------------------------------------------
421. We decline to adopt more specific minimum requirements than
those described herein for incorporating categories of factors in the
development of Long-Term Scenarios, as requested by some
commenters.\955\ We believe that the requirements adopted herein,
coupled with the other Long-Term Scenarios requirements, including the
plausible and diverse and best available data requirements, are
sufficiently detailed to address the need for reform without limiting
regional flexibility.
---------------------------------------------------------------------------
\955\ E.g., PIOs Reply Comments at 10.
---------------------------------------------------------------------------
b. Specific Categories of Factors
i. NOPR Proposal
422. In the NOPR, the Commission proposed to require transmission
providers to incorporate, at a minimum, the following categories of
factors in the development of Long-Term Scenarios: (1) Federal, state,
and local laws and regulations that affect the future resource mix and
demand; \956\ (2) Federal, state, and local laws and regulations on
decarbonization and electrification; (3) state-approved utility
integrated resource plans and expected supply obligations for load-
serving entities; (4) trends in technology and fuel costs within and
outside of the electricity supply industry, including shifts toward
electrification of buildings and transportation; (5) resource
retirements; (6) generator interconnection requests and withdrawals;
and (7) utility and corporate commitments and Federal, state, and local
goals that affect the future resource mix and demand.\957\
---------------------------------------------------------------------------
\956\ NOPR, 179 FERC ] 61,028 at P 104 n.189. The Commission
explained that ``state or federal laws or regulations'' meant
``enacted statutes (i.e., passed by the legislature and signed by
the executive) and regulations promulgated by a relevant
jurisdiction, whether within a state or municipality, or at the
federal level.''
\957\ Id. P 104.
---------------------------------------------------------------------------
(a) Federal, Federally-Recognized Tribal, State, and Local Laws and
Regulations That Affect the Future Resource Mix and Demand (Factor
Category One)
(1) Comments
423. Many commenters support the proposed requirement that each
Long-Term Scenario incorporate and be consistent with the Federal,
state, and local laws and regulations that affect the future resource
mix and demand.\958\ AEE, Clean Energy States, and Acadia Center and
CLF argue that laws and regulations implementing clean energy and
decarbonization policies will be key drivers in changes to the resource
mix and demand.\959\ Moreover, AEE notes, 38 states and the District of
Columbia have adopted renewable portfolio standards, many of which have
been enacted in statute and constitute binding commitments on utilities
and retail energy providers.\960\ Clean Energy States similarly assert
that the 21 states (plus the District of Columbia and Puerto Rico) with
100% clean energy policies account for 42.3% of United States power
sales as of 2020, 49.4% of United States customer accounts, and 51% of
United States population.\961\ Clean Energy States argue that
altogether, these states could see an aggregated demand for 800 TWh of
new energy generation to meet their targets.
---------------------------------------------------------------------------
\958\ Acadia Center and CLF Initial Comments at 8; AEE Initial
Comments at 9-10; Breakthrough Energy Initial Comments at 14;
California Commission Initial Comments at 17; Clean Energy
Associations Initial Comments at 10-11; Clean Energy States Initial
Comments at 3; Environmental Groups Supplemental Comments at 2;
Exelon Initial Comments at 10-11; New England for Offshore Wind
Initial Comments at 2; OMS Initial Comments at 6; Pacific Northwest
State Agencies at Initial Comments at 14; Pine Gate Initial Comments
at 23; PIOs Initial Comments at 17-18; WE ACT Initial Comments at 4-
5.
\959\ Acadia Center and CLF Initial Comments at 8; AEE Initial
Comments at 10; Clean Energy States Initial Comments at 3.
\960\ AEE Initial Comments at 10 (citing Energy Info. Admin.,
Renewable Energy Explained, Portfolio Standards (June 29, 2021),
https://www.eia.gov/energyexplained/renewable-sources/portfolio-standards.php).
\961\ Clean Energy States Initial Comments at 3 (citing Clean
Energy States Alliance, 100% Energy Collaborative, https://www.cesa.org/projects/100-clean-energy-collaborative/).
---------------------------------------------------------------------------
424. AEE, DC and MD Offices of People's Counsel, and SEIA agree
that transmission providers should incorporate the effects of Federal,
state, and local laws and regulations on
[[Page 49354]]
renewable energy development into development of Long-Term
Scenarios.\962\ City of New York states that government action that
bears the force of law should be reflected in baseline transmission
planning studies and not considered as merely one of multiple factors
used to develop Long-Term Scenarios.\963\
---------------------------------------------------------------------------
\962\ AEE Initial Comments at 17-18, 22; DC and MD Offices of
People's Counsel Reply Comments at 5-6; SEIA Initial Comments at 7-
8.
\963\ City of New York Initial Comments at 7.
---------------------------------------------------------------------------
425. Southeast PIOs argue that concerns that requiring the
incorporation of local laws and regulations in the development of Long-
Term Scenarios is unduly burdensome are misplaced at this stage because
the details of how it will be done will be established during
compliance proceedings.\964\
---------------------------------------------------------------------------
\964\ Southeast PIOs Reply Comments at 26.
---------------------------------------------------------------------------
426. PIOs argue that the Commission should require the same level
of engagement with Tribal governments as it does with states and that
the Commission should clarify that Long-Term Scenarios must incorporate
relevant aspects of Tribal policies.\965\
---------------------------------------------------------------------------
\965\ PIOs Reply Comments at 15.
---------------------------------------------------------------------------
427. Acadia Center and CLF claim that the Commission should clarify
that state laws and regulations that affect the future resource mix and
demand include state laws and regulations that affect demand
management, such as energy efficiency, distributed generation, flexible
load, and demand response because laws and initiatives in this area
will also affect transmission needs while providing grid
solutions.\966\
---------------------------------------------------------------------------
\966\ Acadia Center and CLF Initial Comments at 9.
---------------------------------------------------------------------------
428. Center for Biological Diversity states that the Commission
must include all Executive Actions, not just laws and regulations, as
factors in Long-Term Regional Transmission Planning. Center for
Biological Diversity states that allowing transmission providers to
decide whether to consider Executive Orders fails to provide
stakeholders with the type of clarity that is a goal of the NOPR.\967\
---------------------------------------------------------------------------
\967\ Center for Biological Diversity Initial Comments at 3, 9-
12.
---------------------------------------------------------------------------
429. As noted above, some commenters oppose the overall categories
of factors requirement in this final order and argue that requiring
transmission providers to incorporate certain factors, such as laws and
regulations that affect the resource mix, will force transmission
providers to settle irresolvable conflicts among state policies and
conduct transmission planning that accommodates the policy preferences
of some, at the cost of all.\968\
---------------------------------------------------------------------------
\968\ Louisiana Commission Initial Comments at 17-18;
Undersigned States Initial Comments at 3.
---------------------------------------------------------------------------
430. Some commenters acknowledge that state laws and regulations
may affect the future resource mix and demand but argue against
mandatory inclusion such that they cannot discount certain Federal,
state, and local laws and regulations.\969\ Idaho Power states that the
NOPR proposal does not provide transmission providers with the
flexibility necessary to create transmission planning regions that span
multiple states and could cause non-jurisdictional entities to opt out
of regional transmission planning.\970\ NYISO states that the final
order should not require transmission providers to assume across all
scenarios the full achievement of all Federal, state, and local laws
and regulations that could drive the need for transmission. NYISO also
does not think that the final order should require the identification
of all Federal, state, and local laws and regulations that may drive
the need for transmission over the 20-year transmission planning
horizon, but instead should provide each transmission planning region
with flexibility.\971\
---------------------------------------------------------------------------
\969\ Ameren Initial Comments at 9-10; NESCOE Initial Comments
at 27-28; NYISO Initial Comments at 8, 20.
\970\ Idaho Power Initial Comments at 7.
\971\ NYISO Initial Comments at 8.
---------------------------------------------------------------------------
431. Although Duke agrees that many of the categories of factors
identified in the NOPR capture a minimum list of factors that are
expected to drive changes in the resource mix and demand, it does not
support the inclusion of local laws and regulations.\972\
---------------------------------------------------------------------------
\972\ Duke Initial Comments at 13-14.
---------------------------------------------------------------------------
(2) Commission Determination
432. We adopt the NOPR proposal, with modification, to require
transmission providers in each transmission planning region to
incorporate Factor Category One: Federal, federally-recognized Tribal,
state, and local laws and regulations affecting the resource mix and
demand, in the development of Long-Term Scenarios. We find that the
factors in this category have been, and will continue to be, key
drivers of Long-Term Transmission Needs and therefore must be accounted
for in Long-Term Regional Transmission Planning. Accordingly, we find
that failing to account for factors in Factor Category One would hamper
the identification, evaluation, and selection of Long-Term Regional
Transmission Facilities that are potentially more efficient or cost-
effective solutions to Long-Term Transmission Needs.
433. We clarify that factors in Factor Category One include, among
other things, legally binding obligations, incentives (e.g., tax
credits), and/or restrictions promulgated by policymakers that will
affect new or existing generators, or demand. Further, as discussed in
the Additional Categories of Factors section below, we recognize that
energy equity and justice laws and regulations are also potential
factors within Factor Category One to the extent that they are likely
to affect Long-Term Transmission Needs.
434. As discussed in further detail below in the Additional
Categories of Factors section, we modify the NOPR proposal for Factor
Category One to include federally-recognized Tribal laws and
regulations affecting the resource mix and demand because we are
persuaded by commenters that contend that such factors have a similar
potential to affect Long-Term Transmission Needs as Federal, state, and
local laws and regulations. Federally-recognized Tribal laws and
regulations mean the legally binding obligations, incentives, and/or
restrictions promulgated by federally-recognized Tribes that will
affect new or existing generators, or demand. We make similar
modifications to Factor Category Two and Factor Category Seven, as
discussed in the Factor Category Two and Factor Category Seven sections
below.
435. We are not persuaded by Louisiana Commission's argument that
requiring transmission providers to incorporate certain factors, such
as Federal, federally-recognized Tribal, state, and local laws and
regulations affecting the resource mix and demand, would result in a
transmission buildout that only accommodates the policy preferences of
some stakeholders, at the cost of all transmission customers.\973\
Similarly, we are not persuaded by Undersigned States' contention that
policy differences among states may be irresolvable, and therefore the
Commission should not require transmission providers to account for
laws and regulations in their Long-Term Scenarios.\974\ First, every
policy choice--from Federal tax incentives and state regulation of
generation, down to local economic development policies--that changes
the quantity and location of generation and load contributes to changes
in transmission needs. Accordingly, all transmission buildout--whether
it occurs through a
[[Page 49355]]
local or regional transmission plan, or through a near-term
transmission planning process or a more forward-looking one--is a
reflection, at least in part, of Federal, federally-recognized Tribal,
state, and local laws and regulations that drive transmission needs.
Rather than a unique feature of Long-Term Regional Transmission
Planning, transmission planning of any kind will inherently reflect the
policy choices of multiple decisionmakers, because the quantity and
location of generation and load are shaped by multiple decisionmakers.
---------------------------------------------------------------------------
\973\ Louisiana Commission Initial Comments at 17.
\974\ Undersigned States Initial Comments at 3.
---------------------------------------------------------------------------
436. Second, we find that requiring transmission providers to
properly account for known determinants of Long-Term Transmission Needs
is necessary to ensure just and reasonable rates. Specifically,
because, as described above, Long-Term Transmission Needs driven by
disparate policy decisions would continue to exist, regardless of
whether they were identified in Long-Term Regional Transmission
Planning, failing to identify, evaluate, and select Long-Term Regional
Transmission Facilities to address those needs will result in unjust
and unreasonable rates. We note that some policy decisions are
reflected in laws and regulations, which can affect load-serving
entities' supply obligations, and in transmission planning regions with
vertically integrated utilities, some policy decisions are reflected in
the integrated resource plans approved by retail regulators.
437. We are not endorsing the merits of any specific Federal,
federally-recognized Tribal, state, or local laws and regulations or of
any specific state-approved integrated resource plans. We emphasize
that the Commission's policies are technology neutral, and we are not
establishing a preference for certain types of generation or energy end
uses. We acknowledge that, in some instances, a policy choice in one
jurisdiction may reduce or negate the effect of a policy choice in
another jurisdiction. However, the fact that certain factors may have
conflicting effects on Long-Term Transmission Needs is not a basis to
conclude that the effects of laws and regulations or state-approved
integrated resource plans should be ignored or discounted.
(b) Federal, Federally-Recognized Tribal, State, and Local Laws and
Regulations on Decarbonization and Electrification (Factor Category
Two)
(1) Comments
438. Several commenters support the proposed requirement that Long-
Term Scenarios incorporate Federal, state, and local laws and
regulations on decarbonization and electrification.\975\ Illinois
Commission notes that, in Illinois, the Climate and Equitable Jobs Act
of 2021 will affect future demand and the supply mix and that Long-Term
Regional Transmission Planning will be critical to meeting Illinois'
policy goals.\976\ New England for Offshore Wind states that
electrification to meet New England states' greenhouse gas emissions
mandates will dramatically increase electricity load and require
massive amounts of clean energy.\977\ Pattern Energy states that
Federal and state legislative efforts to promote decarbonization should
be the basis of scenario modeling for generation and demand.\978\
Center for Biological Diversity states that the Commission should
identify decarbonization as an objective in Long-Term Regional
Transmission Planning because it has the authority and responsibility
to prioritize decarbonization in the transmission planning process
since these policies bear directly on the provision of transmission
service.\979\
---------------------------------------------------------------------------
\975\ Acadia and CLF Initial Comments at 9; Center for
Biological Diversity Initial Comments at 7-9; Clean Energy
Associations Initial Comments at 10-11; DC and MD Offices of
People's Counsel Reply Comments at 6; Illinois Commission Initial
Comments at 4-5; New England for Offshore Wind Initial Comments at
2-3; Pacific Northwest State Agencies at Initial Comments at 14;
Pattern Energy Initial Comments at 26; Pine Gate Initial Comments at
23; PIOs Initial Comments at 17-18; Renewable Northwest Initial
Comments at 19-22.
\976\ Illinois Commission Initial Comments at 4-5.
\977\ New England for Offshore Wind Initial Comments at 2-3.
\978\ Pattern Energy Initial Comments at 26.
\979\ Center for Biological Diversity Initial Comments at 7-9
(citing S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 89-93).
---------------------------------------------------------------------------
439. Nevada Commission acknowledges that other state policies and
its own integrated resource planning process should be considered in
Long-Term Regional Transmission Planning even though it does not
support other state policies affecting Nevada ratepayers.\980\ Utah
Division of Public Utilities states that the impact of state policies
should be part of the Long-Term Regional Transmission Planning scenario
analysis.\981\ Cypress Creek asserts that the Commission should include
state policy requirements in a uniform set of assumptions that are
applicable across all Long-Term Scenarios.\982\
---------------------------------------------------------------------------
\980\ Nevada Commission Initial Comments at 8.
\981\ Utah Division of Public Utilities Reply Comments at 4.
\982\ Cypress Creek Reply Comments at 5-6.
---------------------------------------------------------------------------
(2) Commission Determination
440. We adopt the NOPR proposal, with modification, to require
transmission providers in each transmission planning region to
incorporate Factor Category Two: Federal, federally-recognized Tribal,
state, and local laws and regulations on decarbonization and
electrification, in the development of Long-Term Scenarios. Similar to
Factor Category One, we find that the factors in this category have
been, and will continue to be, key drivers of Long-Term Transmission
Needs and therefore must be accounted for in Long-Term Regional
Transmission Planning. We clarify that this category of factors
includes legally binding obligations, incentives, and/or restrictions
that affect Long-Term Transmission Needs in different ways than Factor
Category One, for example, by limiting the carbon intensity of
electricity generation or electrifying energy end uses and thereby
significantly increasing electricity use in certain sectors of the
economy, such as transportation and building heating and cooling. We
acknowledge that there could be overlap between Factor Categories One
and Two because a certain law or regulation could reasonably be
considered to fit into both categories. In such a circumstance,
transmission providers must account for the law or regulation in one of
the two categories, not both, to avoid double-counting of that factor's
anticipated effect on Long-Term Transmission Needs. Since transmission
providers must account for and be consistent with, and not discount,
factors in the first three categories of factors equally once the
transmission providers have determined that such a factor is likely to
affect Long-Term Transmission Needs, we do not believe it is necessary
to ensure that a certain factor is considered as part of Factor
Category One instead of Factor Category Two (or vice versa), but rather
it is only necessary to ensure that these factors are accounted for in
the development of Long-Term Scenarios.
441. In addition, based on the record before us, we modify the NOPR
proposal for Factor Category Two to include federally-recognized Tribal
laws and regulations on decarbonization and electrification because we
are persuaded by commenters that argue that such factors have the same
potential to affect Long-Term Transmission Needs as Federal, state, and
local laws and regulations on decarbonization and electrification.
442. Similar to our response in the Factor Category One section to
commenters arguing that categories of factors involving Federal,
federally-recognized Tribal, state, and local laws and regulations
would provide
[[Page 49356]]
preference to some at the cost of all or result in irresolvable
conflict,\983\ we find that differences in if and how government
entities promulgate laws and regulations concerning decarbonization and
electrification (i.e., factors in Factor Category Two) do not diminish
the effect of such laws and regulations. As such, Long-Term Scenarios
must account for these key drivers of Long-Term Transmission Needs so
that transmission providers can identify such needs through Long-Term
Regional Transmission Planning and can identify, evaluate, and select
Long-Term Regional Transmission Facilities to address those needs.
---------------------------------------------------------------------------
\983\ Louisiana Commission Initial Comments at 17-19;
Undersigned States Initial Comments at 3. Comments originally
summarized in PP 404-405.
---------------------------------------------------------------------------
(c) State-Approved Utility Integrated Resource Plans and Expected
Supply Obligations for Load-Serving Entities (Factor Category Three)
(1) Comments
443. Several commenters support the proposed requirement that each
Long-Term Scenario incorporate state-approved integrated resource plans
and expected supply obligations for load-serving entities.\984\ NRECA
and TAPS state that using Long-Term Scenarios that satisfy expected
load-serving entity supply obligations is consistent with FPA section
217(b)(4)'s directive to facilitate the planning and expansion of
transmission to meet the reasonable needs of load-serving entities to
satisfy their service obligations.\985\ NRECA asserts that this
category should be moved to the top of the list of categories of
factors because state-approved integrated resource plans and load-
serving entity supply obligations will incorporate state laws and
regulations affecting resource mix, demand, decarbonization, and
electrification. Additionally, NRECA contends that the changing
characteristics of the distribution grid, such as distributed energy
resources, storage, demand response, energy efficiency, and
electrification of demand, will affect load-serving entity needs and
should be incorporated in this category of factors.\986\ Clean Energy
Associations and ACEG agree.\987\
---------------------------------------------------------------------------
\984\ California Commission Initial Comments at 17; NRECA
Initial Comments at 30; Pine Gate Initial Comments at 23; PIOs
Initial Comments at 17-18; US Chamber of Commerce Initial Comments
at 6-7.
\985\ NRECA Initial Comments at 30-31; TAPS Initial Comments at
2, 7-8 (citing NOPR, 179 FERC ] 61,028 at P 106); see also APPA
Initial Comments at 28.
\986\ NRECA Initial Comments at 30-31 n.85.
\987\ ACEG Reply Comments at 22; Clean Energy Associations Reply
Comments at 6-7.
---------------------------------------------------------------------------
444. APPA and ACEG argue that the final order should focus on the
resource plans of load-serving entities and include a requirement for
transmission providers to include in their Long-Term Regional
Transmission Planning process a requirement to coordinate with load-
serving entities.\988\ ACEG argues that such a requirement is necessary
because not all load-serving entities either own generation or are
overseen by a state regulator, meaning that they must rely on the
Commission to ensure that transmission planning meets their needs.\989\
---------------------------------------------------------------------------
\988\ ACEG Reply Comments at 22; APPA Initial Comments at 27-28.
\989\ ACEG Reply Comments at 22-23.
---------------------------------------------------------------------------
445. Several commenters clarify that they support the inclusion of
load-serving entity demand as a factor in Long-Term Scenarios.\990\ In
addition, some commenters support the inclusion of load-serving entity
generation resource planning as a factor in Long-Term Scenarios.\991\
PIOs argue that the Commission should require load-serving entities to
provide their generation and demand forecasts to transmission planning
entities.\992\ ACEG agrees and argues that PIOs' recommendation will
decrease the burden on transmission planning entities and provide them
with the information they need to determine the future resource
mix.\993\
---------------------------------------------------------------------------
\990\ ACEG Reply Comments at 22-23; Clean Energy Associations
Reply Comments at 7; DC and MD Offices of People's Counsel Reply
Comments at 4; PIOs Initial Comments at 18; PIOs Reply Comments at
10.
\991\ ACEG Reply Comments at 22-23; Clean Energy Associations
Reply Comments at 7; DC and MD Offices of People's Counsel Reply
Comments at 4.
\992\ PIOs Initial Comments at 19.
\993\ ACEG Reply Comments at 23.
---------------------------------------------------------------------------
446. Entergy asserts that the Commission has identified the
appropriate factors but explains that not all states conduct commission
proceedings related to integrated resource plans and, for those states
that do, the timelines are not necessarily the same. Thus, Entergy
requests that the Commission clarify that the term ``state-approved
utility integrated resource plans'' will be construed broadly to
include any resource plan developed and reviewed through a retail
commission proceeding and submitted to the relevant transmission
provider for use in Long-Term Regional Transmission Planning. Entergy
asserts that such clarification would result in a range of benefits
such as consistency of data with current local, state, and Federal laws
and expected retirements, additions, and corporate goals.\994\
---------------------------------------------------------------------------
\994\ Entergy Initial Comments at 15-16.
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(2) Commission Determination
447. We adopt the NOPR proposal to require transmission providers
in each transmission planning region to incorporate Factor Category
Three: state-approved integrated resource plans and expected supply
obligations for load-serving entities, in the development of Long-Term
Scenarios. We find it appropriate to require transmission providers to
incorporate Factor Category Three because it reflects the outcomes of
retail-level regulatory proceedings that will affect Long-Term
Transmission Needs. Further, incorporation of Factor Category Three
into Long-Term Scenarios will ensure that transmission providers
properly account for resource planning and anticipated changes to
demand, including increased integration of distributed energy
resources. We note that the Commission shares concurrent jurisdiction
over the bulk power system with retail regulators,\995\ and we agree
with commenters that note that FPA section 217(b)(4) directs the
Commission to facilitate the planning and expansion of transmission to
meet the reasonable needs of load-serving entities to satisfy their
service obligations.\996\
---------------------------------------------------------------------------
\995\ Compare 16 U.S.C. 824d(a) (providing the Commission
authority to regulate the rates charged by public utilities in
connection with the transmission or wholesale sale of electric
energy), with id. 824(a) (reserving certain state authorities).
\996\ 16 U.S.C. 824q(b)(4) (``The Commission shall exercise the
authority of the Commission under this chapter in a manner that
facilitates the planning and expansion of transmission facilities to
meet the reasonable needs of load-serving entities to satisfy the
service obligations of the load-serving entities, and enables load-
serving entities to secure firm transmission rights (or equivalent
tradable or financial rights) on a long-term basis for long-term
power supply arrangements made, or planned, to meet such needs.'').
---------------------------------------------------------------------------
448. In response to commenters that note some retail regulators may
review but not formally approve integrated resource plans, we clarify
that, for this category of factors, state-approved integrated resource
plans includes resource plans that are developed and reviewed through a
retail proceeding in jurisdictions where the retail regulator does not
formally approve such plans.\997\ We grant Entergy's clarification
request that the term ``state-approved utility integrated resource
plans'' be construed broadly to include any resource plan developed and
reviewed through a retail commission proceeding and submitted to the
relevant transmission provider for use in Long-Term Regional
Transmission Planning because it would enable a more complete
consideration of state-approved integrated resource plans and
[[Page 49357]]
expected supply obligations for load-serving entities.
---------------------------------------------------------------------------
\997\ Entergy Initial Comments at 15-16.
---------------------------------------------------------------------------
449. In response to APPA and ACEG's request for the Commission to
require transmission providers to coordinate with load-serving
entities,\998\ we note that we require transmission providers, as
described in further detail below, to provide an open and transparent
process in their OATT that provides stakeholders, including load-
serving entities, with a meaningful opportunity to propose potential
factors and to provide input on how to account for specific factors in
the development of Long-Term Scenarios.\999\ However, in response to
PIOs' request that the Commission require load-serving entities to
provide their generation and demand forecast to transmission providers,
we agree that such information will assist transmission providers in
developing Long-Term Scenarios. Therefore, consistent with the
information exchange transmission planning principle established in
Order No. 890,\1000\ we require load-serving entities that are taking
transmission service pursuant to an OATT to provide transmission
providers with information on the load-serving entities' projected
loads and resources over the planning horizon.
---------------------------------------------------------------------------
\998\ ACEG Reply Comments at 22; APPA Initial Comments at 27-28.
\999\ See infra Stakeholder Process and Transparency section.
\1000\ The information exchange transmission planning principle
requires network transmission customers to submit information on
their projected loads and resources on a comparable basis (e.g.,
planning horizon and format) as used by transmission providers in
planning for their native load. Point-to-point transmission
customers are required to submit their projections for need of
service over the planning horizon and at what receipt and delivery
points. To the extent applicable, transmission customers should also
provide information on existing and planned demand resources and
their impact on demand and peak demand. Transmission providers, in
consultation with their customers and other stakeholders, must
develop guidelines and a schedule for the submittal of such customer
information. Order No. 890, 118 FERC ] 61,119 at PP 486-487.
---------------------------------------------------------------------------
(d) Trends in Technology and Fuel Costs Within and Outside of the
Electricity Supply Industry, Including Shifts Toward Electrification of
Buildings and Transportation (Factor Category Four)
(1) Comments
450. Several commenters emphasize the importance of incorporating
assumptions regarding shifts towards electrification in Long-Term
Scenarios.\1001\ Clean Energy Buyers assert that regional flexibility
should not be used to diminish the representation in Long-Term
Scenarios of significant load growth from the commercial and industrial
sectors and electrification of transportation.\1002\ Likewise, DC and
MD Offices of People's Counsel assert that regional flexibility should
be reflected in the actual inputs for these factors, rather than their
inclusion in or exclusion from Long-Term Scenarios, noting, for
example, that electrification forecasts in some areas are increasing
load growth estimates by 30%.\1003\ Clean Energy Associations argue
that, to keep pace with changes in supply and demand, Long-Term
Scenarios should incorporate aging infrastructure and planned
replacements, along with load and generation trends informed by both
historical data and applicable policy drivers.\1004\
---------------------------------------------------------------------------
\1001\ Clean Energy Associations Initial Comments at 11; Clean
Energy Buyers Initial Comments at 15-16; DC and MD Offices of
People's Counsel Initial Comments at 11-12; ENGIE Initial Comments
at 3; PJM Market Monitor Initial Comments at 3.
\1002\ Clean Energy Buyers Initial Comments at 15-16.
\1003\ DC and MD Offices of People's Counsel Initial Comments at
11-12.
\1004\ Clean Energy Associations Initial Comments at 12.
---------------------------------------------------------------------------
451. Other commenters emphasize the trends in specific technology
costs, such as long-duration storage. ENGIE states that advances in
longer-duration storage and advancing photovoltaic technologies may
affect the ability to develop resources in areas previously considered
to be uneconomic, which could affect the resource and demand mix.\1005\
Form Energy argues that the inclusion of diverse, long-duration
electric storage technologies would require significantly fewer new
transmission needs.\1006\
---------------------------------------------------------------------------
\1005\ ENGIE Initial Comments at 3.
\1006\ Form Energy Initial Comments at 2-3.
---------------------------------------------------------------------------
452. Pine Gate supports the inclusion of trends in technology and
fuel costs in Long-Term Scenarios; however, Pine Gate requests that the
Commission clarify what type of data would constitute a ``trend'' and
how it expects transmission providers to assure that trend-related
input is objective and representative of the ``best available data.''
\1007\ Similarly, US DOE recommends that the Commission clarify whether
the term ``trends in technology and fuel costs'' refers to trends in
fuel cost and trends in technology, or rather trends in the cost of
fuel and trends in the cost of technology. If the Commission is
referring to the former, US DOE recommends that the Commission consider
the phrase ``trends in fuel costs and in the cost, performance, and
availability of generation, storage, and transmission technologies.''
US DOE further recommends that the Commission provide a non-exhaustive
list of examples of cost and technology trends that transmission
planners could consider.\1008\
---------------------------------------------------------------------------
\1007\ Pine Gate Initial Comments at 24.
\1008\ US DOE Initial Comments at 12-13.
---------------------------------------------------------------------------
453. SEIA recommends that the Commission direct transmission
providers to use the data and models used in NREL's Electrification
Futures Study, Solar Futures Study, Storage Futures Study, and
Transportation Futures Study.\1009\ PIOs disagree with granting
discretion to transmission providers to define trends in technology and
fuel costs because PIOs state that it could empower them to distort the
modeling process and create Long-Term Scenarios that are
meaningless.\1010\
---------------------------------------------------------------------------
\1009\ SEIA Initial Comments at 10.
\1010\ PIOs Initial Comments at 19.
---------------------------------------------------------------------------
454. PIOs argue that the Commission should require transmission
providers to use certain values for trends in technology and fuel costs
within and outside of the electricity supply industry.\1011\
---------------------------------------------------------------------------
\1011\ Id. at 17-19.
---------------------------------------------------------------------------
455. New York TOs argue that trends in technology costs are
amorphous and therefore should not be prescribed as a required factor
for transmission providers to consider.\1012\ Similarly, PPL criticizes
the Commission's proposed requirement that transmission providers
forecast trends in technology without providing concrete assumptions to
use, or without a guarantee for cost recovery for investments that are
based on those uncertain forecasts.\1013\
---------------------------------------------------------------------------
\1012\ New York TOs Initial Comments at 11-12.
\1013\ PPL Initial Comments at 8.
---------------------------------------------------------------------------
(2) Commission Determination
456. We adopt the NOPR proposal, with modification, to require
transmission providers in each transmission planning region to
incorporate Factor Category Four: trends in fuel costs and in the cost,
performance, and availability of generation, electric storage
resources, and building and transportation electrification
technologies, in the development of Long-Term Scenarios. We find it
appropriate to require transmission providers to incorporate Factor
Category Four into the development of Long-Term Scenarios because the
relative cost of constructing and operating different types of
generation or storage resources and the relative cost of electrifying
certain energy end uses will affect Long-Term Transmission Needs. We
further find that this requirement is necessary to ensure that
transmission providers
[[Page 49358]]
develop plausible Long-Term Scenarios that account for technological
changes expected over the transmission planning horizon, facilitating
transmission providers' identification of Long-Term Transmission Needs.
457. As requested by commenters, including US DOE, we modify this
category of factors in the final order to clarify that this category of
factors is meant to capture changes in the cost, as well as the
performance and availability, of certain technologies relevant to the
electric industry.\1014\ In response to commenters arguing that trends
in technology costs are amorphous and should not be included in the
final order as a required category of factors, we disagree. However, as
discussed above, we grant transmission providers discretion to
determine whether specific trends identified in Factor Category Four
are likely to affect Long-Term Transmission Needs and how to account
for those specific trends in Long-Term Scenarios.\1015\ As discussed in
further detail below, transmission providers also have some discretion
to discount or place more weight on the anticipated effects on Long-
Term Transmission Needs due to factors in this category.
---------------------------------------------------------------------------
\1014\ Pine Gate Initial Comments at 24; US DOE Initial Comments
at 12.
\1015\ See New York TOs Initial Comments at 11-12; PPL Initial
Comments at 8.
---------------------------------------------------------------------------
458. In response to comments from US DOE,\1016\ we clarify that
trends in fuel costs and in the cost, performance, and availability of
generation, storage, and building and transportation electrification
technologies may include, but are not limited to, cost and technology
trends for: utility-scale generation construction costs for different
generating technologies; distributed energy resources; storage
technologies with differing duration limitations; carbon capture and
sequestration; small modular nuclear; light-, medium-, and heavy-duty
electric vehicles and electric vehicle supply equipment; and ground-
and air-source heat pumps. While we agree with US DOE that transmission
providers should consider trends in the cost, performance, and
availability of transmission technologies as part of their evaluation
of potential solutions to Long-Term Transmission Needs, we do not
believe that these trends should be included as factors in this
category because trends in the cost, performance, and availability of
transmission technologies do not drive Long-Term Transmission Needs. We
also agree with commenters that note that the effects of the factors in
this category may vary significantly, such as shifts towards
electrification leading to significant load growth, or cost reductions
for emerging technologies, like long-duration electric storage
resources, mitigating some new transmission needs.
---------------------------------------------------------------------------
\1016\ US DOE Initial Comments at 12-13.
---------------------------------------------------------------------------
(e) Resource Retirements (Factor Category Five)
(1) Comments
459. Several commenters support the proposed requirement that each
Long-Term Scenario incorporate resource retirements as a category of
factors.\1017\ PJM Market Monitor states that PJM faces the potential
for the retirement of large coal resources and that the PJM capacity
market design and the transmission planning process need to identify
these specific resources well in advance and ensure an efficient
response to obviate the need for nonmarket cost-of-service contracts to
retain generation while transmission is constructed.\1018\
---------------------------------------------------------------------------
\1017\ Breakthrough Energy Initial Comments at 14; NRECA Initial
Comments at 31; NYISO Initial Comments at 24; PIOs Initial Comments
at 21; SPP Market Monitor Initial Comments at 9; see also PJM Market
Monitor at 3 (``PJM faces the potential retirement . . . of a
significant amount of coal resources in the next five years. Both
the PJM capacity market and design and the transmission planning
process need to identify these specific resources well in advance
and plan for their retirement in order to ensure an efficient
response and to obviate the need for nonmarket cost of service
contracts to retain the generation while transmission is
constructed.'').
\1018\ PJM Market Monitor Initial Comments at 3.
---------------------------------------------------------------------------
460. PIOs and NYISO both argue that the Commission should further
specify that transmission providers must incorporate expected trends in
resource retirements rather than just announced retirements into Long-
Term Scenarios.\1019\ PIOs state the Commission should require
transmission providers to (1) specify how they will use generator age
and condition data to predict retirements, (2) include announced
retirements, and (3) specify how they will reflect trends and
incentives for distributed energy resources, as well as how they will
quantify these trends.\1020\
---------------------------------------------------------------------------
\1019\ NYISO Initial Comments at 24; PIOs Initial Comments at
21.
\1020\ PIOs Initial Comments at 21.
---------------------------------------------------------------------------
461. NYISO states that the final order should confirm that each
transmission planning region has the authority and flexibility to
account for likely resource retirements that have not been announced by
the resource based on factors that include the facility's age, its
emission profile, applicable laws and regulations, and other
factors.\1021\ Similarly, Pine Gate asserts that resource retirements
should be included at the earliest opportunity as there is often a
significant gap of time between when a public announcement is made and
when the official notice of deactivation is communicated to the
transmission provider.\1022\
---------------------------------------------------------------------------
\1021\ NYISO Initial Comments at 24.
\1022\ Pine Gate Initial Comments at 24.
---------------------------------------------------------------------------
462. SEIA states that transmission providers should only be
required to include the retirement of resources that have provided
notice of pending retirement pursuant to the applicable tariff
provisions.\1023\ PJM supports engaging in transparent economic impact
analyses of generation resource retirements but asserts that such
analyses might disclose confidential information about specific
generators. Therefore, PJM contends that the Commission will need to
provide clear direction on how it wishes to address these issues,
especially since masking of data is not a practical solution once the
transmission case is released.\1024\
---------------------------------------------------------------------------
\1023\ SEIA Initial Comments at 10.
\1024\ PJM Initial Comments at 6, 69.
---------------------------------------------------------------------------
(2) Commission Determination
463. We adopt the NOPR proposal to require transmission providers
in each transmission planning region to incorporate Factor Category
Five: resource retirements, in the development of Long-Term Scenarios.
We find it appropriate to require transmission providers to incorporate
Factor Category Five because resource retirements expected over the
transmission planning horizon will affect Long-Term Transmission Needs.
Commenters generally support requiring this category of factors, but
commenters disagree as to how transmission providers should account for
projected resource retirements that have not been publicly
announced.\1025\
---------------------------------------------------------------------------
\1025\ NYISO Initial Comments at 24; Pine Gate Initial Comments
at 24; PIOs Initial Comments at 21.
---------------------------------------------------------------------------
464. In response to those commenters, we clarify that, to develop
plausible Long-Term Scenarios, transmission providers must, in
incorporating Factor Category Five into the development of Long-Term
Scenarios, account for likely resource retirements beyond those that
have been publicly announced. The record indicates that resource
retirements have significantly influenced the supply of electricity in
the past and are expected to do so in the coming decades.\1026\ The
North
[[Page 49359]]
American Electric Reliability Corporation's 2021 Long-Term Reliability
Assessment reports nearly 50 GW of confirmed thermal generation
resource retirements by 2026 and acknowledges that many more are yet to
be announced.\1027\ In addition, the record reflects that publicly
announced resource retirements are only a fraction of the resource
retirements expected over the required 20-year transmission planning
horizon.\1028\ Given the significance of resource retirements, and the
limited scope of publicly announced resource retirements, we find that
transmission providers must account for expected retirements that have
not been publicly announced to meet this final order's requirement that
transmission providers develop a plausible set of Long-Term
Scenarios.\1029\
---------------------------------------------------------------------------
\1026\ See supra note 241; Colorado Consumer Advocate Initial
Comments, attach. 7 (US DOE, Staff Report to the Secretary on
Electricity Markets and Reliability (Aug. 2017)) at 13-14 (stating
that 132 GW of generation capacity retired between 2002 and 2016--
approximately 15% of the installed capacity in 2002--due to the
advantaged economics of natural gas-fired generation, low
electricity demand growth, the deployment of variable energy
resources, and regulatory requirements); see also, e.g., AEP Initial
Comments at 4 n.12.
\1027\ SEIA Initial Comments at 9 (citing North American
Electric Reliability Corporation, 2021 Long-Term Reliability
Assessment, at 30, 35 (Dec. 2021)). The North American Electric
Reliability Corporation states that long-range retirement projects
based on confirmed retirements could be ``significantly
understated'' because generator retirement announcements can be made
as late as 90 days prior to planned deactivation in some areas. The
North American Electric Reliability Corporation 's 2021 reported
retirements through 2026 increased 126% compared to the North
American Electric Reliability Corporation's 2020 estimates; and the
North American Electric Reliability Corporation's 2022 reported
retirements through 2026 increased compared to the North American
Electric Reliability Corporation 's 2021 retirements. See North
American Electric Reliability Corporation, 2021 Long-Term
Reliability Assessment, at 35 (Dec. 2021); NERC, 2022 Long-Term
Reliability Assessment, at 17 (Dec. 2022).
\1028\ For example, announced retirements account for less than
half of MISO's projected retirements over a 20-year transmission
planning horizon. See MISO Initial Comments at 35 (citing MISO, MISO
Futures Report, at 14-19, (Dec. 2021), https://cdn.misoenergy.org/MISO%20Futures%20Report538224.pdf).
\1029\ See infra Types of Long-Term Scenarios section.
---------------------------------------------------------------------------
465. We provide flexibility to transmission providers to propose on
compliance with this final order how to account for resource
retirements that might take place over the transmission planning
horizon, in addition to those that have been publicly announced. We
note, for example, that transmission providers could propose to account
for expected retirements by considering factors such as a generating
facility's age, its emissions profile, its projected costs and
revenues, and any applicable laws and regulations that may affect a
generating facility's continued operation over the transmission
planning horizon.\1030\ To the extent that certain laws and regulations
identified by stakeholders in Factor Categories One and Two will
necessitate the retirement of certain resources, we reiterate that
transmission providers must develop Long-Term Scenarios that are
consistent with such laws and regulations.
---------------------------------------------------------------------------
\1030\ For example, MISO assumes age-based resource retirements
which vary by resource type and scenario, over a 20-year
transmission planning horizon. In a 2021 study, MISO assumes coal-
fired resources will retire at age 46 in one scenario, and age 36 in
another. MISO assumes utility-scale solar resources will retire at
age 25 in every scenario. MISO also incorporates resource
retirements announced by the resource owner, stated in an integrated
resource plan, or filed in MISO's Attachment Y. See MISO Initial
Comments at 35 (citing MISO, MISO Futures Report, at 14-19, (Dec.
2021), https://cdn.misoenergy.org/MISO%20Futures%20Report538224.pdf).
---------------------------------------------------------------------------
466. In response to PJM's concerns that conducting transparent
economic impact analyses of generation resource retirements could lead
to the disclosure of confidential information about specific
generators, we note that the Commission has previously acknowledged
that tension exists between ensuring transparency in transmission
planning processes and protecting confidential information, including
commercially sensitive information.\1031\ We note that we are not
specifying how transmission providers must estimate resource
retirements, and we clarify that transmission providers may include
what they believe to be appropriate confidentiality protections in
their proposals to account for resource retirements that might take
place over the transmission planning horizon. The Commission will
evaluate those proposals by using the established principles in Order
No. 890,\1032\ as well as precedent on existing confidentiality
protections with respect to transmission planning that the Commission
has previously found comply with the Order No. 890 principles, to guide
its findings on whether such protections are appropriate.
---------------------------------------------------------------------------
\1031\ Sw. Power Pool, Inc., 137 FERC ] 61,227, at P 20 (2011).
\1032\ Order No. 890, 118 FERC ] 61,119 at PP 471-476.
---------------------------------------------------------------------------
(f) Generator Interconnection Requests and Withdrawals (Factor Category
Six)
(1) Comments
467. Several commenters support the proposed requirement that each
Long-Term Scenario incorporate generator interconnection requests and
withdrawals.\1033\ Pattern Energy argues that generation
interconnection queues are indicative of the market for generation
capacity additions and should also be a major source for generation
assumptions in both near-term and long-term scenario planning.\1034\
SEIA supports the proposed requirement with the caveat that
transmission providers should only include interconnection customers
that have signed a facilities study agreement, or other applicable
study agreement.\1035\ Cypress Creek asserts that the Commission should
require transmission providers to include the proposed generator
interconnection requests in the queue that have completed a system
impact study as part of a uniform set of assumptions applicable across
all scenarios.\1036\
---------------------------------------------------------------------------
\1033\ Breakthrough Energy Initial Comments at 14; Cypress Creek
Reply Comments at 5-7.
\1034\ Pattern Energy Initial Comments at 26.
\1035\ SEIA Initial Comments at 10.
\1036\ Cypress Creek Reply Comments at 5-7.
---------------------------------------------------------------------------
468. CAISO and MISO state that their regional transmission planning
processes already include projects in the generator interconnection
queue.\1037\ MISO further explains that it considers the generator
interconnection queue when determining the location where future
generation will interconnect, but MISO also states that transmission
providers and their stakeholders need to have flexibility, including
how to consider trends in interconnection queue requests.\1038\
Further, MISO argues that ``generation interconnection requests and
withdrawals'' as stated in the NOPR is unclear regarding how the
transmission provider must weigh withdrawals differently than requests.
Therefore, MISO requests that the Commission revise the NOPR proposal
to require transmission providers to ``consider activity in the
generation interconnection queue.'' \1039\
---------------------------------------------------------------------------
\1037\ CAISO Initial Comments at 34; MISO Initial Comments at
35.
\1038\ MISO Initial Comments at 35-36.
\1039\ Id. at 36.
---------------------------------------------------------------------------
469. Nebraska Commission asserts that the Commission should not
include interconnection request withdrawals as a factor because it does
not follow the Commission's cost causation principles and would
incentivize additional interconnection requests. For example, Nebraska
Commission states, most interconnection requests in SPP are
duplicative, and entities compare costs among their requests once they
are analyzed. Nebraska Commission asserts that such requests could be
used to game the transmission planning process, create additional
backlogs in the interconnection queue, and shift costs from
interconnection customers to transmission customers.\1040\
---------------------------------------------------------------------------
\1040\ Nebraska Commission Initial Comments at 4-5.
---------------------------------------------------------------------------
470. Likewise, Omaha Public Power claims that, until generator
interconnection reform is enacted, the use of interconnection queues
and withdrawals as factors will lead to
[[Page 49360]]
scenario inaccuracy due to the size of interconnection backlogs and
speculative nature of many queued projects.\1041\ Dominion also opposes
using the number and size of interconnection requests as a basis for
transmission planning because speculative interconnection requests
could stimulate transmission development in areas slated for
development by private interests.\1042\
---------------------------------------------------------------------------
\1041\ Omaha Public Power Initial Comments at 3.
\1042\ Dominion Reply Comments at 7-8.
---------------------------------------------------------------------------
471. PJM Market Monitor states that, while there are many comments
on the significant renewable resources PJM will connect to its grid,
based on historic completion rates and effective load carry capability
derate factors, only 5.6% of renewable resources are expected to go
into service.\1043\
---------------------------------------------------------------------------
\1043\ PJM Market Monitor Initial Comments at 4.
---------------------------------------------------------------------------
(2) Commission Determination
472. We adopt the NOPR proposal to require transmission providers
in each transmission planning region to incorporate Factor Category
Six: generator interconnection requests and withdrawals, in the
development of Long-Term Scenarios. We find it appropriate to require
transmission providers to incorporate Factor Category Six because
generation interconnection queues provide important information about
future generation development over the transmission planning horizon
and therefore affect Long-Term Transmission Needs. Multiple RTOs/ISOs
explain that their regional transmission planning processes already
account for generation projects in the interconnection queue, but MISO
notes that transmission providers need flexibility in how to
incorporate that data into the development of Long-Term
Scenarios.\1044\ In response to MISO's concerns, we reiterate that
transmission providers have discretion to determine how to account for
all factors, including interconnection requests and withdrawals, in
Long-Term Scenarios.
---------------------------------------------------------------------------
\1044\ MISO Initial Comments at 35-36.
---------------------------------------------------------------------------
473. We disagree with commenters that argue that, because many
interconnection requests are speculative and/or duplicative, requiring
transmission providers to incorporate Factor Category Six into the
development of Long-Term Scenarios will compromise the accuracy of
Long-Term Scenarios, shift costs to transmission customers that should
be borne by interconnection customers, or create an incentive for
additional interconnection requests that could slow down
interconnection queue processing.\1045\ We note that over the years,
and recently with Order No. 2023, transmission providers and the
Commission have adopted changes to generator interconnection procedures
to reduce the submission of speculative interconnection requests in the
interconnection queue. For example, interconnection requests require
significant financial commitments from the interconnection customer
(e.g., application fees, study deposits, and site control
requirements), which the Commission made more stringent in Order No.
2023.\1046\ Noting that, as discussed above, transmission providers
will have discretion as to how they account for factors in Long-Term
Scenarios and may determine whether certain generator interconnection
requests are speculative and/or duplicative, such that the requests are
unlikely to affect Long-Term Transmission Needs, and then make
corresponding adjustments to their Long-Term Scenarios. As discussed in
further detail below, transmission providers can also account for
uncertainty by discounting or putting more weight on the anticipated
effects on Long-Term Transmission Needs due to factors in this
category. Additionally, we believe that the existence of a large number
of interconnection requests in a certain area, even if some of those
requests are speculative, indicates that generation developers have an
interest in interconnecting resources in that area, which Long-Term
Scenarios should take into account.
---------------------------------------------------------------------------
\1045\ Dominion Reply Comments at 7-8; Nebraska Commission
Initial Comments at 4-5; Omaha Public Power Initial Comments at 3.
\1046\ Order No. 2023, 184 FERC ] 61,054 at P 490.
---------------------------------------------------------------------------
(g) Utility and Corporate Commitments and Federal, Federally-Recognized
Tribal, State, and Local Policy Goals That Affect Long-Term
Transmission Needs (Factor Category Seven)
(1) Comments
474. Some commenters generally support the proposed requirement to
incorporate in Long-Term Scenarios utility and corporate commitments
and Federal, state, and local goals that affect the future resource mix
and demand.\1047\ ACEG contends that FPA section 217(b)(4) supports the
Commission's proposed requirement to include public policies and
utility and corporate renewable procurement goals within Long-Term
Scenarios because load-serving entities' service obligations will
depend upon both public policies and the resource preferences of their
customers.\1048\ AEE highlights the role of local goals by noting that
29 of the 50 most populous cities in the United States have set clean
or renewable energy targets.\1049\
---------------------------------------------------------------------------
\1047\ ACEG Initial Comments at 26-29; AEE Initial Comments at
10-11; Advanced Energy Buyers Initial Comments at 5-6; Amazon
Initial Comments at 3-4; Center for Biological Diversity Initial
Comments at 9-12; Environmental Groups Supplemental Comments at 2;
[Oslash]rsted Initial Comments at 7; Pacific Northwest State
Agencies at Initial Comments at 14; PIOs Initial Comments at 18-19;
SEIA Initial Comments at 10; SREA Initial Comments at 41-46; see
also Environmental Groups Supplemental Comments at 2 (``The electric
industry is undergoing a major transformation driven by consumer,
utility, and corporate preferences, state public policies, and the
cost competitiveness of renewable energy. The Commission's
transmission planning and cost allocation standards must be up to
the challenge of enabling this transition while ensuring the
continued provision of reliable and affordable electricity at just
and reasonable rates.'').
\1048\ ACEG Initial Comments at 26-29.
\1049\ AEE Initial Comments at 10-11 (citing Third Way,
Utilities, Cities, and States with Clean Energy Targets (July 30,
2021), https://www.thirdway.org/graphic/utilities-cities-and-states-with-clean-energy-targets).
---------------------------------------------------------------------------
475. Advanced Energy Buyers argue that private efforts to use more
low- and zero-carbon electricity are significantly affecting the
resource mix and in turn transmission needs, noting that since 2014,
commercial and industrial customers have contracted for more than 52 GW
of clean energy in the United States, with annual increases every year
since 2016.\1050\ Moreover, Advanced Energy Buyers state, corporate and
industrial customer demand for renewable energy in the United States is
expected to reach about 85 GW by 2030.\1051\ Advanced Energy Buyers
state that, in some markets, corporate demand is already a dominant
driver of renewable energy deployment, as in Illinois, where corporate
procurement accounted for roughly one-third of total renewable
deployment.\1052\ SEIA states that, for corporate commitments,
transmission providers should include data from the Clean Energy Buyers
Association Deal Tracker, and for utility commitments, transmission
providers should include
[[Page 49361]]
data from state resource plans and regulatory filings.\1053\
---------------------------------------------------------------------------
\1050\ Advanced Energy Buyers Initial Comments at 5 (citing
Clean Energy Buyers Alliance, State of the Market 2022, https://cebuyers.org/state-of-the-market/).
\1051\ Id. at 5-6 (citing Wood Mackenzie, Corporates Usher in
New Wave of US Wind and Solar Growth (Aug. 2019), https://www.woodmac.com/our-expertise/focus/Power--Renewables/corporates-usher-in-new-wave-of-u.s.-wind-and-solar-growth/).
\1052\ Id. at 6 (citing Advanced Energy Economy, Adding it All
Up for Voluntary Buyers of Renewable Energy (Jan. 2021), https://blog.advancedenergyunited.org/adding-it-all-up-for-voluntary-buyers-of-renewable-energy; Microsoft, Greener datacenters for a brighter
future: Microsoft's commitment to renewable energy (May 2016),
https://blogs.microsoft.com/on-the-issues/2016/05/19/greener-datacenters-brighter-future-microsofts-commitment-renewable-energy/
).
\1053\ SEIA Initial Comments at 10 (citing Clean Energy Buyer
Association, CEBA Deal Tracker, https://cebuyers.org/deal-tracker/;
Sierra Club, Check Out Where We Are Ready For 100%, https://www.sierraclub.org/climate-and-energy/map).
---------------------------------------------------------------------------
476. SREA and ACEG argue that the Commission should require
transmission providers to incorporate utilities' generation planning
announcements associated with net zero commitments and publicized
utility resource plans, including SEC filings and public statements,
into the development of Long-Term Scenarios.\1054\ SREA contends that
such a requirement would protect the interests of customers and
generation developers because these announcements affect the
marketplace.\1055\ Breakthrough Energy suggests that utility targets
and expected consumer demand should also be incorporated into the
development of Long-Term Scenarios because actual demand is often
higher than reflected in utility plans, which do not sufficiently
incorporate corporate demand, including corporate buyer
commitments.\1056\
---------------------------------------------------------------------------
\1054\ ACEG Initial Comments at 28-29; SREA Initial Comments at
41-46.
\1055\ SREA Initial Comments at 41-46.
\1056\ Breakthrough Energy Initial Comments at 14-15.
---------------------------------------------------------------------------
477. LADWP, MISO, and NRECA support the inclusion of this category
of factors as long as transmission providers are allowed to discount
these factors in their analysis by assuming the goals or commitments
may not be fully met.\1057\ NRECA is concerned that factor category
seven (utility and corporate commitments) carries a distinct risk of
stranded transmission costs and therefore supports it being
discounted.\1058\ NRECA further states that it is concerned that
stakeholders may try to use Long-Term Regional Transmission Planning to
impose goals and commitments that lack the force of law.\1059\ LADWP
argues that the Commission should allow transmission planners to use
discretion when identifying utility commitments and local goals.\1060\
MISO is concerned about the inherent difficulty of modeling corporate
commitments given the ambiguous nature of corporate footprints.\1061\
---------------------------------------------------------------------------
\1057\ LADWP Initial Comments at 3; MISO Initial Comments at 36;
NRECA Initial Comments at 32-33.
\1058\ NRECA Initial Comments at 32 (citing GDS Assocs., Report,
at 12 (Aug. 17, 2022)).
\1059\ Id. at 32-33.
\1060\ LADWP Initial Comments at 3.
\1061\ MISO Initial Comments at 36.
---------------------------------------------------------------------------
478. Several commenters oppose including utility and corporate
commitments and/or Federal, state, and local goals as a category of
factors in Long-Term Scenarios.\1062\ For example, California
Commission states that it is not clear what purpose would be served by
requiring transmission providers to incorporate these commitments or
goals into Long-Term Scenarios yet, at the same time, allowing them to
discount such commitments or goals to account for their inherent
uncertainty.\1063\ New York TOs argue that corporate commitments are
amorphous and therefore should not be prescribed as a required factor
for transmission providers to consider. Moreover, New York TOs state
that, if a goal is not codified as a law, it is not clear that it is
sufficiently solidified and supported to be included as a factor.\1064\
---------------------------------------------------------------------------
\1062\ Alabama Commission Initial Comments at 6; California
Commission Initial Comments at 20; Duke Initial Comments at 13; New
York TOs Initial Comments at 11-12; Pennsylvania Commission Initial
Comments at 6.
\1063\ California Commission Initial Comments at 20.
\1064\ New York TOs Initial Comments at 11-12.
---------------------------------------------------------------------------
479. PJM argues that the NOPR proposal to include corporate
commitments as a factor in Long-Term Scenarios is vague, inappropriate,
and impractical, because even if PJM is able to develop a record of
information in the expansive PJM footprint, this information will
likely be incomplete. PJM argues that the burden to ensure that a
transmission provider is aware of corporate commitments and goals
should be on the corporation or another interested party.\1065\
---------------------------------------------------------------------------
\1065\ PJM Reply Comments at 37-38 (citing PJM Initial Comments
at 68).
---------------------------------------------------------------------------
480. Illinois Commission states that transmission planning criteria
should not include vague terms such as ``corporate goals,'' which could
mean multiple things and may already be accounted for.\1066\ Alabama
Commission states that corporate commitments and goals are not a
sufficient basis for planning decisions as they are not law and
accountability for achieving them is limited.\1067\ Similarly,
Pennsylvania Commission states that determinants for Long-Term
Scenarios should not be based on speculative factors, arguing that
factors that include Federal, state, and local laws and regulations
that affect the future resource mix and demand are preferable to
factors that include utility, corporate, Federal, state, and local
goals or policies that have no enforcement mechanisms.\1068\ PPL states
that utility and corporate commitments are unlikely to be sufficiently
firm or definitive to pass state siting review.\1069\
---------------------------------------------------------------------------
\1066\ Illinois Commission Initial Comments at 7.
\1067\ Alabama Commission Initial Comments at 6.
\1068\ Pennsylvania Commission Initial Comments at 5-6.
\1069\ PPL Initial Comments at 8.
---------------------------------------------------------------------------
(2) Commission Determination
481. We adopt the NOPR proposal, with modification, to require
transmission providers in each transmission planning region to
incorporate Factor Category Seven: utility and corporate commitments
and Federal, federally-recognized Tribal, state, and local policy goals
that affect Long-Term Transmission Needs, in the development of Long-
Term Scenarios. We find it appropriate to require transmission
providers to incorporate Factor Category Seven into the development of
Long-Term Scenarios because the relevant commitments and goals
represent known consumer preferences that have been, and will continue
to be, key drivers of Long-Term Transmission Needs. We agree with
commenters that argue that corporate demand for clean energy resources,
as demonstrated by the volume of bilateral corporate contracts with
renewable energy resources, is already a major driver of changes in the
resource mix and demand and that corporate and industrial customer
demand for clean energy is projected to increase. We believe that it is
necessary for transmission providers to incorporate publicly announced
utility commitments in the development of Long-Term Scenarios. Such
commitments may be ignored or overlooked in retail-level regulatory
proceedings, but they nevertheless may have an impact on future changes
in the resource mix and demand that must be accounted for to ensure the
development of plausible Long-Term Scenarios.
482. We modify the NOPR proposal for Factor Category Seven to
include federally-recognized Tribal goals that affect the resource mix
and demand because we are persuaded by commenters that argue that such
factors have the same potential to affect Long-Term Transmission Needs
as Federal, state, and local goals. We believe that federally-
recognized Tribal goals should include publicly announced policy
recommendations, such as energy vision reports.\1070\ Further, as
discussed under Additional Categories of Factors below, we recognize
that energy equity and justice goals are potential factors within
Factor Category Seven.
---------------------------------------------------------------------------
\1070\ See, e.g., Columbia River Inter-Tribal Fish Comm'n,
Energy Vision for the Columbia River Basin (Sept. 2022), https://critfc.org/wp-content/uploads/2022/09/CRITFC-Energy-Vision-Full-Report.pdf.
---------------------------------------------------------------------------
[[Page 49362]]
483. While Federal, federally-recognized Tribal, state, and local
goals may not have the same durability and binding impact of laws and
regulations, we believe that it is appropriate for transmission
providers to account for such goals in Long-Term Scenarios because
these goals represent known preferences of governmental entities that
affect Long-Term Transmission Needs. Such goals may improve or diminish
the prospects of deploying certain technologies. For example, as AEE
explains, local governments representing some of the most populous
cities in the United States have established goals to have their
cities' loads served by clean or renewable energy.\1071\
---------------------------------------------------------------------------
\1071\ AEE Initial Comments at 10-11 (citing Third Way,
Utilities, Cities, and States with Clean Energy Targets (July 30,
2021), https://www.thirdway.org/graphic/utilities-cities-and-states-with-clean-energy-targets).
---------------------------------------------------------------------------
484. We disagree with commenters that argue that transmission
providers should not be required to incorporate utility and corporate
commitments into the development of Long-Term Scenarios because they
may not be significant enough to drive Long-Term Transmission Needs or
that accountability for achieving commitments and goals is too limited
for these factors to be considered sufficiently firm.\1072\ We
acknowledge that utility and corporate commitments and governmental
goals may be more likely to change over the transmission planning
horizon than factors in other required factor categories; however, we
are not persuaded that these commitments and goals are so speculative,
amorphous, or unreliable that they should not be incorporated into
Long-Term Scenarios at all. We emphasize that transmission providers
have discretion, as discussed above, in how to account for these
factors in the development of Long-Term Scenarios, and we note, as
discussed in further detail below, that transmission providers can
account for the uncertainty associated with the achievement of these
commitments and goals by using discounting or putting more weight on
the effects of these factors on Long-Term Transmission Needs in each of
the required Long-Term Scenarios. Similarly, transmission providers
have discretion to determine how to account for commitments and goals
in Long-Term Scenarios if the effects of particular commitments or
goals conflict with, negate, or duplicate the effects of other factors.
---------------------------------------------------------------------------
\1072\ Alabama Commission Initial Comments at 6; California
Commission Initial Comments at 20; Illinois Commission Initial
Comments at 7; New York TOs Initial Comments at 11-12; Pennsylvania
Commission Initial Comments at 5-6; PJM Reply Comments at 37-38
(citing PJM Initial Comments at 68); PPL Initial Comments at 8.
---------------------------------------------------------------------------
(h) Additional Categories of Factors
(1) Comments on Energy Equity and Justice
485. Some commenters argue that the Commission should include
equity and energy justice considerations in Long-Term Regional
Transmission Planning.\1073\ Grand Rapids NAACP, agreeing with NASEO,
urges the Commission to expand factors considered in Long-Term Regional
Transmission Planning to include energy equity and justice.\1074\ Grand
Rapids NAACP also states that transmission providers should be required
to follow Federal, state, and local laws addressing the need for energy
equity and justice.\1075\ In concordance with PIOs, Grand Rapids NAACP
urges the Commission to address equity in the transmission planning
process because doing so would encourage competition and lower consumer
costs.\1076\ Finally, Grand Rapids NAACP urges the Commission to
encourage transmission providers to develop metrics that advance
economic equity and environmental justice by facilitating consideration
of the impact of transmission infrastructure on disadvantaged
communities.\1077\
---------------------------------------------------------------------------
\1073\ See, e.g., California Energy Commission Initial Comments
at 2; City of New York Initial Comments at 9; Clean Energy Buyers
Initial Comments at 8-9; Grand Rapids NAACP Initial Comments at 12,
15, 21, 23; Grand Rapids NAACP Reply Comments at 2-3, 5; Montclair
Congregation Supplemental Comments at 1; NARUC Initial Comments at
3-4; NASEO Initial Comments at 5; PIOs Initial Comments at 35-36;
PIOs Reply Comments at 15; Policy Integrity Initial Comments at 28;
WE ACT Initial Comments at 4-6.
\1074\ Grand Rapids NAACP Reply Comments at 2 (citing NASEO
Initial Comments at 5).
\1075\ Id.
\1076\ Id. (citing PIOs Initial Comments at 35, 36).
\1077\ Id. at 2-3 (citing NARUC Initial Comments at 3-4).
---------------------------------------------------------------------------
486. US DOE asserts that energy justice considerations will form an
integral part of transmission planning. Specifically, US DOE states
that transmission planning can identify potential sources, sinks, and
locations of transmission expansion facilities and that identifying
locations where frontline communities and historically underserved
communities have faced long-standing impacts may affect the future
resource mix.\1078\ NESCOE agrees with US DOE and argues that regional
transmission planning processes should accommodate state efforts to
advance equity and environmental justice concerns.\1079\ New England
for Offshore Wind argues that without a transparent and inclusive
transmission planning process, regional transmission planning efforts
will be at odds with state policy on environmental justice.\1080\
---------------------------------------------------------------------------
\1078\ US DOE Initial Comments at 9.
\1079\ NESCOE Reply Comments at 8-9.
\1080\ New England for Offshore Wind Initial Comments at 5.
---------------------------------------------------------------------------
487. PIOs state that the Commission should be clear that Long-Term
Regional Transmission Planning complies with and incorporates relevant
aspects of applicable Federal, federally-recognized Tribal, state, and
local environmental and energy justice policies--including future
resource mix impacts, assignment of transmission benefits toward
disadvantaged communities, and project selection.\1081\
---------------------------------------------------------------------------
\1081\ PIOs Reply Comments at 15 (citing Grand Rapids NAACP
Initial Comments at 12-15, 21-23 (listing notable Federal, state,
and local public policies requiring that equity and energy justice
inform decision making processes); WE ACT Initial Comments at 6).
---------------------------------------------------------------------------
488. CARE Coalition states that the Commission should consider
issues of siting and the granting of permits that cause significant
delays in construction of new transmission facilities.\1082\ CARE
Coalition emphasizes WE ACT's argument that a final order should ensure
that transmission planners and states ``are cognizant about siting and
the potential harms of transmission development to environmental
justice communities.'' \1083\ Relatedly, CARE Coalition highlights
NRECA's argument that rural and poorer areas are disproportionately
burdened under the current regime because ``siting decisions are
primarily driven by technical and economic factors.'' \1084\
---------------------------------------------------------------------------
\1082\ CARE Coalition Reply Comments at 3.
\1083\ Id. at 4 (citing WE ACT Initial Comments at 6).
\1084\ Id. (citing NRECA Initial Comments at 39 n.111).
---------------------------------------------------------------------------
(2) Comments on Efficiency and Technology
489. NASEO argues that the Commission should expand its list of
factors that transmission providers should include in Long-Term
Regional Transmission Planning and Long-Term Scenarios to include
increased energy efficiency of existing transmission lines, and the
efficient use of existing rights of way.\1085\ Invenergy suggests that
the Commission expressly require consideration of advanced-stage
merchant HVDC transmission as a factor in regional transmission
planning scenarios.\1086\ Invenergy highlights US DOE's proposal that
transmission providers consider trends in the development of HVDC
network technology, arguing, however, that such
[[Page 49363]]
consideration should include incorporating and accounting for HVDC
transmission facilities in transmission planning models and
scenarios.\1087\
---------------------------------------------------------------------------
\1085\ NASEO Initial Comments at 5.
\1086\ Invenergy Initial Comments at 6-7.
\1087\ Invenergy Reply Comments at 11 (citing US DOE Initial
Comments at 13).
---------------------------------------------------------------------------
(3) Comments Regarding Enhanced Reliability and Interregional Transfer
Capability
490. PJM recommends that the Commission require enhanced
reliability and Interregional Transfer Capability as two additional
categories of factors that transmission providers must incorporate into
the development of Long-Term Scenarios.\1088\ PJM envisions enhanced
reliability to include, but not be limited to, storm hardening of
critical facilities, reducing the number of critical CIP-014 facilities
through transmission upgrades, coordination of infrastructure
development with natural gas pipelines serving generation in the
region, and ensuring redundancy of facilities, where appropriate, to
address the threat of physical or cyber attacks.\1089\ PJM envisions
Interregional Transfer Capability to be established in accordance with
the methodology that the Commission adopts in a subsequent order.\1090\
---------------------------------------------------------------------------
\1088\ PJM Initial Comments at 6, 13, 65-67.
\1089\ Id. at 66.
\1090\ Id. at 66-67.
---------------------------------------------------------------------------
491. Invenergy agrees with the additional categories of factors
that PJM proposes.\1091\ ELCON supports the consideration of transfer
capability between seams, which it asserts would provide transmission
providers with the ability to develop and consider solutions that may
solve for multiple drivers and offer greater benefits to more
consumers.\1092\ In contrast, AEE states that it disagrees with the
additional categories of factors that PJM proposes, although it agrees
with PJM that enhanced reliability planning is an important
consideration.\1093\
---------------------------------------------------------------------------
\1091\ Invenergy Reply Comments at 11.
\1092\ ELCON Initial Comments at 8.
\1093\ AEE Reply Comments at 20.
---------------------------------------------------------------------------
(4) Commission Determination
492. We recognize that some commenters ask the Commission to
require transmission providers to incorporate several categories of
factors in addition to those proposed in the NOPR in the development of
Long-Term Scenarios. We decline to include energy equity and justice as
a distinct and additional category of factors because we believe that
these important energy equity and justice laws and regulations, or
goals, that are likely to affect Long-Term Transmission Needs, are
accounted for in Factor Category One: Federal, federally-recognized
Tribal, state, and local laws and regulations affecting the resource
mix and demand, or Seven: utility and corporate commitments and
Federal, federally-recognized Tribal, state, and local policy goals
that affect Long-Term Transmission Needs.\1094\ Stakeholders will have
a meaningful opportunity to identify any such factors as part of the
open and transparent stakeholder process described below in the
Stakeholder Process and Transparency section.
---------------------------------------------------------------------------
\1094\ Grand Rapids NAACP Reply Comments at 2 (citing NASEO
Initial Comments at 5).
---------------------------------------------------------------------------
493. We decline to adopt Invenergy's recommendation that the
Commission require transmission providers to include advanced-stage
merchant HVDC transmission as an additional category of factors. The
Commission did not propose specific requirements in the NOPR regarding
merchant HVDC transmission facilities under development, and we are not
persuaded by the evidence in the record that the Commission should
include advanced-stage HVDC transmission facilities in the minimum set
of known determinants of Long-Term Transmission Needs. We reiterate
that transmission providers may be aware of additional categories of
factors beyond those adopted in this final order that drive Long-Term
Transmission Needs and may incorporate additional categories of factors
in the development of Long-Term Scenarios provided that each Long-Term
Scenario remains plausible.
494. In response to PJM's request for the Commission to require
enhanced reliability and Interregional Transfer Capability \1095\ as
additional categories of factors,\1096\ we find that the record in this
proceeding is insufficient to adequately consider whether to require
transmission providers to adopt such categories of factors in this
final order. As noted in our response to Invenergy just above,
transmission providers may incorporate additional categories of factors
in the development of Long-Term Scenarios provided that each Long-Term
Scenario remains plausible. We note that, in this final order, we
provide transmission providers with flexibility in how they develop
Long-Term Scenarios to identify Long-Term Transmission Needs. We
believe that other parts of this final order enable transmission
providers to account for enhanced reliability and Interregional
Transfer Capability by modeling sensitivities and using certain
transmission benefits. As discussed below, we require transmission
providers to develop at least one sensitivity analysis, applied to each
Long-Term Scenario, to account for uncertain operational outcomes
during multiple concurrent and sustained generation and/or transmission
outages due to an extreme weather event across a wide area that
determine the benefits of or need for Long-Term Regional Transmission
Facilities. As discussed in the Evaluation of the Benefits of Regional
Transmission Facilities section below, we require transmission
providers to measure, and consider as part of Benefit 6, the benefits
associated with any increase in Interregional Transfer Capability that
a Long-Term Regional Transmission Facility would provide.
---------------------------------------------------------------------------
\1095\ We define Interregional Transfer Capability for purposes
of this final order consistent with the definition of total transfer
capability in the Commission's regulations as: ``the amount of
electric power that can be moved or transferred reliably from one
area to another area of the interconnected transmission systems by
way of all transmission lines (or paths) between those areas under
specified system conditions, or such definition as contained in
Commission-approved Reliability Standards.'' 18 CFR 37.6(b)(1)(vi).
In the context of Interregional Transfer Capability, an ``area'' in
the above definition would be a transmission planning region
composed of transmission providers.
\1096\ PJM Initial Comments at 6, 13, 65-67.
---------------------------------------------------------------------------
c. Treatment of Specific Categories of Factors
i. NOPR Proposal
495. The Commission proposed to require that each Long-Term
Scenario that transmission providers use in Long-Term Regional
Transmission Planning incorporate and be consistent with Federal,
state, and local laws and regulations that affect the future resource
mix and demand; Federal, state, and local laws and regulations on
decarbonization and electrification; and state-approved integrated
resource plans and expected supply obligations for load-serving
entities. The Commission preliminarily found that it is reasonable to
require transmission providers to assume that legally binding
obligations and state utility regulator-approved plans will be followed
and that expected supply obligations for load-serving entities will be
fully met. As a result, the Commission explained that, under the
proposal, transmission providers cannot discount the factors included
in the categories of Federal, state, and local laws and regulations
that affect the future resource mix; Federal, state, and local laws and
regulations on decarbonization and electrification; and state-approved
integrated resource plans and expected
[[Page 49364]]
supply obligations for load-serving entities.\1097\
---------------------------------------------------------------------------
\1097\ NOPR, 179 FERC ] 61,028 at P 106.
---------------------------------------------------------------------------
496. In addition, the Commission proposed to require that each
Long-Term Scenario that transmission providers use in Long-Term
Regional Transmission Planning include trends in technology and fuel
costs within and outside the electricity supply industry, including
shifts toward electrification of buildings and transportation; resource
retirements; and generator interconnection requests and withdrawals.
For these particular categories of factors, the Commission proposed to
provide transmission providers with flexibility in how they incorporate
each factor into Long-Term Scenarios as long as transmission providers
identify and publish specific factors for each of these categories, as
further described below.\1098\
---------------------------------------------------------------------------
\1098\ Id. P 107.
---------------------------------------------------------------------------
497. Further, the Commission proposed to require that each Long-
Term Scenario incorporate utility and corporate goals and Federal,
state, and local goals that affect the future resource mix and demand.
However, the Commission acknowledged that these categories of factors
are less binding and more likely to change over time, and therefore
their impact on the future resource mix and demand are less certain,
than other categories of factors. For this reason, the Commission
preliminarily found that it may be appropriate for transmission
providers to discount such goals to account for this uncertainty. The
Commission explained that transmission providers would not be required
to assume that utility and corporate goals and Federal, state, and
local goals that affect the future resource mix will be fully
met.\1099\
---------------------------------------------------------------------------
\1099\ Id. P 108.
---------------------------------------------------------------------------
ii. Comments
498. Several commenters, that generally support the NOPR proposal,
support discounting and rebut arguments opposing discounting.\1100\
NRECA, Exelon, and TAPS argue that the NOPR proposal to allow
transmission providers to discount some categories of factors while
weighing factors in other categories more heavily strikes an
appropriate balance.\1101\ Specifically, Exelon supports the NOPR
proposal to allow for variation in the treatment of different
categories of factors such as legislated energy policy, which it states
should not vary by scenario, and non-binding targets, which it states
may be discounted yet are important to consider.\1102\ TAPS also
supports the proposed flexibility in how transmission providers
incorporate factors that are not Federal, state, and local laws and
regulations, state-approved integrated resource plans, and expected
supply obligations for load-serving entities.\1103\
---------------------------------------------------------------------------
\1100\ Exelon Initial Comments at 10-11; Georgia Commission
Initial Comments at 4; Illinois Commission Initial Comments at 7;
NEPOOL Initial Comments at 7; NRECA Initial Comments at 32; TAPS
Initial Comments at 2-3, 8.
\1101\ Exelon Initial Comments at 10-11; NRECA Initial Comments
at 32; TAPS Initial Comments at 2-3, 8.
\1102\ Exelon Initial Comments at 10-11.
\1103\ TAPS Initial Comments at 2-3, 8.
---------------------------------------------------------------------------
499. Some commenters express concerns that the NOPR proposal would
allow transmission providers in each transmission planning region to
discount, or not fully incorporate, some factors when developing Long-
Term Scenarios.\1104\ Clean Energy Associations state that certain
factors (i.e., Federal, state, and local policies, utility integrated
resource plans, generator retirements, interconnection requests,
corporate commitments, and trends in technology and fuel costs) can be
quantified and should be reflected in Long-Term Scenarios without
discounting.\1105\ Clean Energy Buyers are concerned that the
flexibility proposed in the NOPR for transmission providers to
incorporate into their Long-Term Scenarios the categories of factors
that include trends in fuel costs and technologies both inside and
outside the electricity supply industry, including regarding shifts in
electrification of transport and buildings, resource retirements, and
generator interconnection requests and withdrawals, could delay the
transmission build-out.\1106\ ACEG recommends that the Commission
presume that all factors are required to be incorporated (and not
discounted or only considered) unless the Commission approves a request
from the transmission providers in a transmission planning region not
to include a factor.\1107\ In response, California Municipal Utilities
argue that mandating the use of specific factors would not account for
the cost consequences of such mandates, which must be considered for
any transmission planning requirements to be just and reasonable.\1108\
---------------------------------------------------------------------------
\1104\ ACEG Initial Comments at 27-28; Amazon Initial Comments
at 4; Clean Energy Associations Initial Comments at 10-11; Pine Gate
Initial Comments at 23-25; PIOs Initial Comments at 18-19; SEIA
Initial Comments at 8-10.
\1105\ Clean Energy Associations Initial Comments at 10-11.
\1106\ Clean Energy Buyers Initial Comments at 15-16.
\1107\ ACEG Initial Comments at 27.
\1108\ California Municipal Utilities Reply Comments at 5-6.
---------------------------------------------------------------------------
500. Several commenters object to the Commission's proposal to
provide transmission providers with the flexibility to discount utility
and corporate and Federal, state, and local goals that affect the
future resource mix and demand.\1109\ Amazon states that transmission
providers should not be allowed to discount clean energy goals in their
development of Long-Term Scenarios without proving such discounting is
just and reasonable by showing evidence that such goals have been
unfulfilled in the past, or that those goals have been altered or
abandoned.\1110\
---------------------------------------------------------------------------
\1109\ Amazon Initial Comments at 4; Clean Energy Associations
Initial Comments at 10-11; Pine Gate Initial Comments at 24-25; PIOs
Initial Comments at 18-19; SEIA Initial Comments at 8.
\1110\ Amazon Initial Comments at 4.
---------------------------------------------------------------------------
501. PIOs state that the NOPR proposal to discount Factor Category
Seven would allow transmission providers to game the results if their
incentives are contrary to consumers' goals.\1111\ SEIA urges the
Commission to limit the flexibility given to transmission providers
regarding this factor because SEIA believes that they would ignore
certain factors if consideration is not mandatory.\1112\ Further, Clean
Energy Associations argue that utility, corporate, and Federal, state,
and local goals should be fully incorporated, without discounting
targets not enshrined in law or regulation. If necessary, Clean Energy
Associations contend, changes in non-binding obligations could be
treated as a sensitivity or probabilistic change in one or more
scenarios to determine how they might affect transmission
development.\1113\
---------------------------------------------------------------------------
\1111\ PIOs Initial Comments at 18-19.
\1112\ SEIA Initial Comments at 8.
\1113\ Clean Energy Associations Initial Comments at 10-11.
---------------------------------------------------------------------------
502. PIOs state that, when utilities make commitments affecting the
future resource mix and consumer demand, they should be held to them
and that granting transmission providers complete discretion to
discount such factors could undermine the goals of the NOPR proposal.
Thus, PIOs state, the Commission should set minimum requirements for
some factors, including for incorporating corporate commitments into
future resource mix estimates.\1114\ PIOs assert that widespread
support exists for these
[[Page 49365]]
recommendations, citing ELCON as an example.\1115\
---------------------------------------------------------------------------
\1114\ PIOs Initial Comments at 17-18.
\1115\ PIOs Reply Comments at 10-11 (citing ELCON Initial
Comments at 4).
---------------------------------------------------------------------------
503. Pine Gate argues that transmission providers should be
required to assume that utility and corporate and Federal, state, and
local goals that affect the future resource mix will be fully met in at
least one of their Long-Term Scenarios.\1116\
---------------------------------------------------------------------------
\1116\ Pine Gate Initial Comments at 25.
---------------------------------------------------------------------------
504. In addition, Pattern Energy argues that the Commission should
distinguish between generation assumptions and demand assumptions for
purposes of 20-year transmission planning so that there is no
ambiguity. For example, Pattern Energy states that transmission
providers should not be permitted to utilize their planning for load
growth to satisfy the requirement to plan for changing resources and
demand. Pattern Energy asserts that transmission providers should be
required to distinguish between modeling a changing resource mix and,
separately, a changing demand profile, arguing that both are important
and should be considerations in near-term and long-term transmission
planning.\1117\
---------------------------------------------------------------------------
\1117\ Pattern Energy Initial Comments at 26.
---------------------------------------------------------------------------
505. NYISO argues that the final order should permit transmission
providers to appropriately account for, in coordination with state and
local entities and stakeholders, the likely effect of applicable laws
and regulations on the need for transmission and to realistically
appraise achievement of such laws and regulations.\1118\
---------------------------------------------------------------------------
\1118\ NYISO Initial Comments at 23.
---------------------------------------------------------------------------
506. Some commenters oppose the NOPR proposal to require that
transmission providers incorporate applicable local laws and
regulations in their development of Long-Term Scenarios.\1119\ Duke
explains that although local laws and regulations for decarbonization
and electrification may affect the resource mix and demand at the local
level, it is unclear how such laws would have a material effect on
regional transmission planning that warrants the additional burden of
tracking and incorporating them into Long-Term Scenarios.\1120\ Alabama
Commission argues that local laws, regulations, and goals might change
or conflict with the policy perspectives of other states.\1121\ PPL
claims that the NOPR proposal is impractical and will significantly
increase uncertainty, which in turn will invite disagreement and
litigation.\1122\ PJM recommends that the Commission require
transmission providers to only consider local laws, local regulations,
and local goals to the extent that such laws, regulations, and goals
are brought to their attention by states, other local regulators, or
stakeholders.\1123\
---------------------------------------------------------------------------
\1119\ Alabama Commission Initial Comments at 5-6; Ameren
Initial Comments at 9-10; Duke Initial Comments at 13-14, 16; ISO-NE
Initial Comments at 26-27; ISO/RTO Council Initial Comments at 4-5;
NYISO Initial Comments at 21-23.
\1120\ Duke Initial Comments at 13.
\1121\ Alabama Commission Initial Comments at 5-6.
\1122\ PPL Initial Comments at 7-8.
\1123\ PJM Reply Comments at 38 (citing PJM Initial Comments at
68).
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iii. Commission Determination
(a) Treatment of Factors in the First Three Categories
507. With regard to the first three categories of factors,\1124\ we
require transmission providers in each transmission planning region to
assume that legally binding obligations (i.e., Federal, federally-
recognized Tribal, state, and local laws and regulations) are followed,
state-approved integrated resource plans are followed, and expected
supply obligations for load-serving entities are fully met. Therefore,
we require that each Long-Term Scenario account for and be consistent
with, and not discount, factors in the first three categories of
factors once the transmission providers have determined that such a
factor is likely to affect Long-Term Transmission Needs. We believe it
is necessary to prohibit discounting of factors in the first three
categories of factors because they are more certain drivers of Long-
Term Transmission Needs, relative to factors in other factor
categories.
---------------------------------------------------------------------------
\1124\ As explained above, the first three categories of factors
are: (1) Federal, federally-recognized Tribal, state, and local laws
and regulations affecting the resource mix and demand; (2) Federal,
federally-recognized Tribal, state, and local laws and regulations
on decarbonization and electrification; and (3) state-approved
integrated resource plans and expected supply obligations for load-
serving entities.
---------------------------------------------------------------------------
508. We clarify that transmission providers may rely on the open
and transparent stakeholder process discussed below to identify the
factors in the first three required categories of factors. More
specifically, this final order does not obligate transmission providers
to independently identify all of the factors in the first three
categories of factors. We believe that it would be unduly burdensome
and potentially impractical for transmission providers to independently
identify all of the potential factors in the first three categories of
factors, which will include numerous Federal, federally-recognized
Tribal, state, and local laws and regulations, as well as integrated
resource plans and expected supply obligations for load-serving
entities.\1125\ However, transmission providers may, if they choose,
independently identify factors in the first three categories of factors
as part of the stakeholder process, discussed further in the
Stakeholder Process and Transparency section below.
---------------------------------------------------------------------------
\1125\ The Commission has previously found that transmission
providers ``cannot later be faulted'' for failing to consider
projections of a need for service from a point-to-point transmission
customer if such projections are not provided by the transmission
customer. Order No. 890, 118 FERC ] 61,119 at P 487; id. (``We also
believe that it is appropriate to require point-to-point customers
to submit any projections they have of a need for service over the
planning horizon and at what receipt and delivery points . . . . If
the point-to-point customers do not submit such projections, then
the transmission provider cannot later be faulted for failing to
consider planning scenarios that might have taken into account
reasonable projections of future system uses that were not the
subject of specific service requests.'').
---------------------------------------------------------------------------
509. We believe that this clarification addresses PJM's request
that we clarify that the burden of making the transmission provider
aware of laws, regulations, and goals rests with stakeholders and not
with the transmission provider itself.\1126\ We also believe that this
clarification mitigates the potential administrative burdens and
compliance risks identified by ISO-NE, as well as the burden of
incorporating factors identified by SPP.\1127\
---------------------------------------------------------------------------
\1126\ PJM Initial Comments at 68.
\1127\ ISO-NE Initial Comments at 26-27; SPP Initial Comments at
7-8.
---------------------------------------------------------------------------
510. In addition, as clarified above, transmission providers retain
the discretion to determine whether particular factors, including those
in the first three categories of factors, that stakeholders identify
are likely to affect Long-Term Transmission Needs. Thus, transmission
providers may determine, for example, that some stakeholder-identified
local laws and regulations that fall within Factor Categories One and
Two are unlikely to affect Long-Term Transmission Needs and therefore
need not be accounted for in the development of Long-Term Scenarios. We
believe that this clarification addresses concerns about the additional
burden some commenters identified of tracking and incorporating local
laws and regulations into the development of Long-Term Scenarios, as
well as concerns that the inclusion of local laws and regulations in
the first two categories of factors creates a burden for transmission
providers to account for factors that are unlikely to affect Long-Term
Transmission Needs.\1128\
---------------------------------------------------------------------------
\1128\ Duke Initial Comments at 13.
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511. We believe that the open and transparent stakeholder process
[[Page 49366]]
discussed below in the Stakeholder Process and Transparency section
will help transmission providers to ensure that each Long-Term Scenario
accounts for factors in the first three categories of factors without
discounting the effects of those factors on Long-Term Transmission
Needs. We expect that transmission providers will rely, at least in
part, on information that relevant Federal, state, and local government
entities, federally-recognized Tribes, utilities, and load-serving
entities provide during the required open and transparent stakeholder
process to determine if specific factors are likely to affect Long-Term
Transmission Needs and how to account for those specific factors in
Long-Term Scenarios. We agree with NYISO regarding the value of
coordination and clarify that transmission providers may work in
coordination with government entities and stakeholders to determine how
applicable laws and regulations may affect Long-Term Transmission
Needs.\1129\
---------------------------------------------------------------------------
\1129\ NYISO Initial Comments at 23.
---------------------------------------------------------------------------
512. We recognize that some commenters raise concerns as to whether
factors in the first three categories of factors can be fully achieved
(e.g., a legislative requirement is met) or may have various levels of
impact on Long-Term Transmission Needs.\1130\ At the outset, we find it
appropriate to assume legally binding obligations are met, unless and
until there is a change in law. Government entities have an interest
and ability to ensure that the requirements of laws and regulations are
fully achieved. Similarly, utilities and load-serving entities, as well
as the relevant retail regulator, have an interest in developing
accurate integrated resource plans and expected supply obligations that
can be fully achieved. Even in the limited circumstances in which these
factors are not fully achieved, we expect the targets or requirements
associated with these factors will be informative for purposes of
identifying Long-Term Transmission Needs. We acknowledge that, for
certain factors, there may be insufficient information for transmission
providers to determine, or stakeholder disagreement about, how the
factor will affect Long-Term Transmission Needs. In such instances, we
clarify that transmission providers have discretion over how to account
for a factor in the first three categories of factors in their Long-
Term Scenarios as long as the assumptions in each Long-Term Scenario
are consistent with legally binding obligations, state-approved
integrated resource plans, and expected supply obligations of load-
serving entities.
---------------------------------------------------------------------------
\1130\ Id.
---------------------------------------------------------------------------
513. For example, when a legally binding obligation sets a minimum
requirement or threshold (e.g., a state law requiring the deployment of
at least 5 gigawatts of electric storage resources by 2030),
transmission providers may develop Long-Term Scenarios assuming either
the minimum amount of the requirement or more than the minimum amount
of the requirement (e.g., modeling 10 gigawatts of electric storage
resources deployed by 2030 instead of the minimum 5 gigawatts) but may
not develop any Long-Term Scenarios that are inconsistent with that
minimum (e.g., modeling only 2 gigawatts of electric storage resources
deployed by 2030). We believe that these clarifications sufficiently
address PPL's concerns regarding the uncertainty associated with how
transmission providers are expected to translate factors, including
local laws and regulations, into Long-Term Scenarios.\1131\ We note
that the requirement, discussed further below, that Long-Term Scenarios
be plausible and diverse also clarifies how transmission providers must
account for factors in the Long-Term Scenarios. That is, while
transmission providers can model assumptions that exceed the minimum
requirements of factors in the first three categories in developing
Long-Term Scenarios, they can only exceed those minimum requirements
such that each Long-Term Scenario remains plausible.\1132\ Similarly,
the requirement that Long-Term Scenarios be diverse ensures that
transmission providers will model the effect of factors on Long Term
Transmission Needs in different ways, and thus that Long-Term Scenarios
help to manage uncertainty over how factors will affect Long-Term
Transmission Needs.
---------------------------------------------------------------------------
\1131\ PPL Initial Comments at 8.
\1132\ Likewise, as discussed in the Treatment of Factors in the
Last Four Categories section, transmission providers may only
discount the effect of factors in the last four categories on Long-
Term Transmission Needs such that each Long-Term Scenario remains
plausible.
---------------------------------------------------------------------------
514. We disagree with ISO-NE's claim that requiring that each Long-
Term Scenario account for and consistently reflect the first three
categories of factors would unnecessarily prevent testing of variations
with these categories of factors. Where a factor's effect is not clear
on its face, transmission providers have discretion, within reason, to
determine the likely effect of full achievement of the factor and
reflect that into development of the Long-Term Scenarios. Transmission
providers also are not limited to assuming only the minimum
requirements of a factor are fully achieved in developing the Long-Term
Scenarios.
515. We also are unpersuaded by commenter claims that local laws
and regulations might conflict with state laws and regulations and,
therefore, we should not include local laws and regulations in the
first two categories of factors.\1133\ However, we acknowledge that
there may be limited circumstances when two legally binding factors
have conflicting or opposite implications for Long-Term Transmission
Needs. We clarify that, in such circumstances, transmission providers
shall reconcile this information while giving full effect to the
maximum extent possible to all legally binding factors. For example,
where two laws have equal and opposite effect, transmission providers
may need to incorporate them as negating each other, as necessary to
comply with the requirement to produce plausible Long-Term Scenarios.
In circumstances when that is not possible because the legally binding
factors support alternatives to the same assumption used to develop
Long-Term Scenarios, transmission providers could use two or more of
the three required Long-Term Scenarios, or develop additional Long-Term
Scenarios, to capture the differences implied by each of the
conflicting factors.
---------------------------------------------------------------------------
\1133\ Alabama Commission Initial Comments at 5-6; PJM Initial
Comments at 68.
---------------------------------------------------------------------------
(b) Treatment of Factors in the Last Four Categories
516. We affirm that transmission providers have additional
discretion in how they account for each factor in the last four
categories of factors compared to how they account for each factor in
the first three categories.\1134\ After transmission providers have
determined that a specific factor, stakeholder-identified or otherwise,
is likely to affect Long-Term Transmission Needs over the transmission
planning horizon, transmission providers must then assess the extent to
which the anticipated effects on Long-Term Transmission Needs due to
that factor are likely to be realized in full, in part, or exceeded,
for purposes of developing a plausible and diverse set of Long-Term
Scenarios. For example, for a corporate commitment
[[Page 49367]]
identified in Factor Category Seven, transmission providers can make a
determination that only a fraction of that corporate commitment will
actually be met, and the transmission providers can subsequently model
more limited effects on Long-Term Transmission Needs due to that
factor, in some or all Long-Term Scenarios. Likewise, transmission
providers may put more weight on the factor by modeling more than the
projected change in some or all Long-Term Scenarios to reflect the
transmission providers' view regarding the likelihood that the
anticipated effects on Long-Term Transmission Needs due to that factor
will occur. Transmission providers may choose to discount or put more
weight on the effects on Long-Term Transmission Needs due to factors in
Factor Categories Four through Seven to account for uncertainty when
developing plausible and diverse Long-Term Scenarios.
---------------------------------------------------------------------------
\1134\ As explained above, the last four categories of factors
are: (4) trends in fuel costs and in the cost, performance, and
availability of generation, electric storage resources and building
and transportation electrification technologies; (5) resource
retirements; (6) generator interconnection requests and withdrawals;
(7) utility and corporate commitments and Federal, federally-
recognized Tribal, state, and local policy goals that affect Long-
Term Transmission Needs.
---------------------------------------------------------------------------
517. Several commenters generally support this flexibility to treat
the last four categories of factors differently from the first
three.\1135\ We believe that requiring transmission providers to
incorporate the last four categories of factors, but allowing
transmission providers to discount the effects of factors within these
categories, strikes an appropriate balance between requiring factors in
these categories be given full weight, and allowing them to be excluded
entirely in developing Long-Term Scenarios. We believe that these
categories of factors affect Long-Term Transmission Needs, and absent a
requirement to incorporate them, transmission providers may fail to
identify, evaluate, and select more efficient or cost-effective Long-
Term Regional Transmission Facilities to address those Long-Term
Transmission Needs. On the other hand, these categories of factors are
less certain than the first three categories and should not necessarily
be given the same weight in developing Long-Term Scenarios as factors
that are legally binding.
---------------------------------------------------------------------------
\1135\ APPA Initial Comments at 27-28; Exelon Initial Comments
at 10-11 (citing NOPR, 179 FERC ] 61,028 at P 121); NRECA Initial
Comments at 29-32; TAPS Initial Comments at 2-3, 8.
---------------------------------------------------------------------------
518. We disagree with the concern that this flexibility could allow
transmission providers to ignore the last four factor categories \1136\
because the final order requires transmission providers to incorporate
all categories of factors in each Long-Term Scenario, even if they
discount specific factors within the category, and requires that all
Long-Term Scenarios be plausible.\1137\ We reiterate that transmission
providers may only discount the effects of factors in these categories
on Long-Term Transmission Needs such that each Long-Term Scenario
remains plausible.
---------------------------------------------------------------------------
\1136\ E.g., ACEG Initial Comments at 27-28; Amazon Initial
Comments at 4; Clean Energy Associations Initial Comments at 10-11;
Pine Gate Initial Comments at 23-25; PIOs Initial Comments at 18-19;
SEIA Initial Comments at 8-10.
\1137\ ACEG Initial Comments at 28; DC and MD Offices of
People's Counsel Initial Comments at 11.
---------------------------------------------------------------------------
d. Stakeholder Process and Transparency
i. NOPR Proposal
519. The Commission proposed to require that transmission providers
identify and publish on an Open Access Same-Time Information System
(OASIS) or other public website a list of the factors that fall into
each of the required categories of factors that they will incorporate
in their development of Long-Term Scenarios. The Commission explained
that transmission providers would be responsible for identifying all
the factors they know of and are considering incorporating in the
development of Long-Term Scenarios as part of Long-Term Regional
Transmission Planning. The Commission also proposed to require
transmission providers to revise the regional transmission planning
processes in their OATTs to outline an open and transparent process
that provides stakeholders, including states, with a meaningful
opportunity to propose potential factors that transmission providers
must incorporate in their development of Long-Term Scenarios, such as
specific laws, regulations, goals, and commitments, and to provide
input on how to appropriately discount factors that are less
certain.\1138\
---------------------------------------------------------------------------
\1138\ NOPR, 179 FERC ] 61,028 at P 109.
---------------------------------------------------------------------------
520. The Commission noted that, under Order No. 1000, transmission
providers must already have procedures in their OATTs that give
stakeholders a meaningful opportunity to submit proposed transmission
needs driven by Public Policy Requirements and that allow transmission
providers to identify, out of the larger set of potential transmission
needs driven by Public Policy Requirements that stakeholders propose,
those needs for which transmission facilities will be evaluated.\1139\
Therefore, the Commission explained that transmission providers may be
able to modify and expand these existing procedures for identifying
transmission needs driven by Public Policy Requirements to meet these
proposed requirements regarding the identification of factors for
incorporation into Long-Term Scenarios.\1140\
---------------------------------------------------------------------------
\1139\ Id. P 110 (citing Order No. 1000, 136 FERC ] 61,051 at PP
206-207; Order No. 1000-A, 139 FERC ] 61,132 at P 335).
\1140\ Id.
---------------------------------------------------------------------------
ii. Comments
(a) State Input
521. Several commenters emphasize the important role of
stakeholders, including states, in identifying or commenting on the
factors to be included in the development of Long-Term Scenarios.\1141\
In addition, Southeast PIOs note that states do not currently engage in
regional transmission planning processes to any meaningful degree, and
therefore, the Commission should encourage their participation in
shaping and conducting Long-Term Regional Transmission Planning.\1142\
---------------------------------------------------------------------------
\1141\ APPA Initial Comments at 27-29; PIOs Initial Comments at
22; PJM Initial Comments at 70; Southeast PIOs Initial Comments at
45, 46-47.
\1142\ Southeast PIOs Initial Comments at 45-46; State Officials
Supplemental Comments at 1.
---------------------------------------------------------------------------
522. Some commenters discuss the important role of states in
identifying factors within specific category of factors.\1143\ DC and
MD Offices of People's Counsel assert that the final order should
explicitly require information on the factors to be provided by
appropriate authorities, such as state agencies.\1144\ New Jersey
Commission supports the Commission's proposal to require that states
have a meaningful opportunity to propose potential factors to be
incorporated into the development of Long-Term Scenarios and to provide
input on appropriately discounting less certain factors.\1145\ NESCOE
asserts that, if states do not play a central role in determining the
factors, the proposed reforms will likely run into the problem that
underlies the Order No. 1000 public policy transmission planning
process in New England, where states do not have a decision-making role
over project selection even though state laws or policies could be the
driver for the project.\1146\
---------------------------------------------------------------------------
\1143\ DC and MD Offices of People's Counsel Initial Comments at
12; New Jersey Commission Initial Comments at 14-15.
\1144\ DC and MD Offices of People's Counsel Initial Comments at
12.
\1145\ New Jersey Commission Initial Comments at 14-15.
\1146\ NESCOE Initial Comments at 28-29.
---------------------------------------------------------------------------
523. However, other commenters state that their existing processes
are adequate for determining the relevant factors to include in Long-
Term
[[Page 49368]]
Regional Transmission Planning.\1147\ PJM states that it currently has
processes and standing committees that allow states and stakeholders to
participate in discussions of factors to use in its transmission
planning processes. For example, PJM asserts that its Independent State
Agencies Committee is set up to receive feedback on transmission
planning from states, and it discusses, among other things, assumptions
used in the models, relevant regulatory initiatives and their impact,
and alternative sensitivities, as well as what was discussed at other
committee meetings. In addition, PJM states, it vets all proposed
transmission solutions with its Transmission Expansion Advisory
Committee before submitting them to the PJM board for approval.\1148\
---------------------------------------------------------------------------
\1147\ MISO Initial Comments at 34-35; MISO TOs Initial Comments
at 18; OMS Initial Comments at 6; PJM Initial Comments at 6, 64, 70-
71.
\1148\ PJM Initial Comments at 70-71.
---------------------------------------------------------------------------
(b) Transparency, Enforcement, and Accuracy
524. Cross Sector Representatives state that Long-Term Regional
Transmission Planning processes should provide transparency for
impacted stakeholders.\1149\ SEIA argues that the Commission should
adopt clear, uniform language that sets forth the specific goals and
deliverables from the proposed Long-Term Regional Transmission Planning
process for transmission providers to include in their tariffs,
including language that mirrors the proposed list of categories of
factors the Commission included in the NOPR.\1150\
---------------------------------------------------------------------------
\1149\ Cross Sector Representatives Supplemental Comments at 1.
\1150\ SEIA Reply Comments at 3-4 (citing PJM Initial Comments
at 27-28).
---------------------------------------------------------------------------
525. Several commenters support the NOPR proposal to require
transmission providers to post the list of factors that they will
incorporate into their Long-Term Scenarios on a public website for
stakeholder comment.\1151\ Pine Gate recommends that the Commission
further require that transmission providers identify and publish all
factors that were considered but not incorporated.\1152\
---------------------------------------------------------------------------
\1151\ Ameren Initial Comments at 11-12; APPA Initial Comments
at 28; NESCOE Initial Comments at 28; Pine Gate Initial Comments at
25; PIOs Initial Comments at 22.
\1152\ Pine Gate Initial Comments at 25.
---------------------------------------------------------------------------
526. Clean Energy Buyers state that, to ensure transparency and
just and reasonable rates, the Commission should require that
transmission providers post the details regarding any proposed or
adopted discounting of factors on OASIS, including: (1) which factors
are to be discounted; (2) the extent of the discounting; and (3) the
justification for and derivation of the amount of discounting deemed
appropriate.\1153\
---------------------------------------------------------------------------
\1153\ Clean Energy Buyers Initial Comments at 16-17.
---------------------------------------------------------------------------
527. GridLab and R Street propose modifications to the NOPR
proposal regarding the role of stakeholders.\1154\ GridLab proposes
that state agencies, other stakeholders, and independent experts could
play a dominant role in enforcing the Commission's requirement to
incorporate specific categories of factors, and that the Commission
would provide a common framework establishing guidelines on the kinds
of factors that transmission providers should consider, at a minimum,
in developing Long-Term Scenarios.\1155\ In addition, R Street argues
that governance mechanisms should drive the selection of data sets,
methods, and assumptions behind these factors to promote objective
accuracy.\1156\
---------------------------------------------------------------------------
\1154\ GridLab Initial Comments at 20-21; R Street Initial
Comments at 7.
\1155\ GridLab Initial Comments at 21.
\1156\ R Street Initial Comments at 7.
---------------------------------------------------------------------------
iii. Commission Determination
528. We adopt the NOPR proposal, with modification, to require
transmission providers in each transmission planning region to revise
the regional transmission planning processes in their OATTs to outline
an open and transparent process that provides stakeholders, including
federally-recognized Tribes and states, with a meaningful opportunity
to propose potential factors and to provide timely input on how to
account for specific factors in the development of Long-Term
Scenarios.\1157\ As discussed below, we also adopt the NOPR proposal,
with modification, to require transmission providers to publish on the
public portion of an OASIS or other public website: (1) the list of the
factors in each of the seven required categories of factors that they
will account for in their Long-Term Scenarios; (2) a description of
each factor that they will account for in their Long-Term Scenarios;
(3) a general statement explaining how they will account for each of
those factors in their Long-Term Scenarios; (4) a description of the
extent to which they will discount any factors in Factor Categories
Four through Seven in each Long-Term Scenario; and (5) a list of the
factors that they considered but did not incorporate in their Long-Term
Scenarios.
---------------------------------------------------------------------------
\1157\ As an example, transmission providers would provide
stakeholders with an opportunity to describe how a specific state
law in the first category of factors will result in the development
of new resources of a certain type, the retirement of existing
resources, or changes in demand patterns due to increased
electrification.
---------------------------------------------------------------------------
529. We believe that a robust stakeholder process will ensure that
transmission providers can identify which, and how, specific factors
might influence Long-Term Transmission Needs over the transmission
planning horizon. For this reason, consistent with Order No. 890's
transmission planning principles,\1158\ we require transmission
providers to give stakeholders a meaningful opportunity to provide
timely input on how and what information to incorporate in Long-Term
Scenarios, including how to account for a specific factor in terms of
how the factor may affect Long-Term Transmission Needs. We clarify that
this meaningful opportunity for stakeholders to provide timely input
includes the opportunity to propose factors, provide information and
identify sources of best available data, propose how a factor may
affect Long-Term Transmission Needs, and explain how that factor could
be reflected in the development of Long-Term Scenarios, including the
extent to which it is appropriate to discount the effects of certain
factors on Long-Term Transmission Needs. We note that some transmission
providers have existing processes in place that allow states and
stakeholders to participate in discussions of factors, which
transmission providers can propose, with any necessary modifications,
to comply with this final order.\1159\
---------------------------------------------------------------------------
\1158\ See, e.g., Order No. 890, 118 FERC ] 61,119 at P 454.
\1159\ MISO Initial Comments at 34-35; PJM Initial Comments at
6, 64, 70-71.
---------------------------------------------------------------------------
530. We believe that affording stakeholders a meaningful
opportunity to propose potential factors and to provide input on how to
account for specific factors in the development of Long-Term Scenarios
will help transmission providers to develop more accurate assumptions
to serve as the basis for their Long-Term Scenarios. Specifically, with
stakeholder input, transmission providers will be in a better position
to determine which specific factors within each category of factors
they should account for in the development of Long-Term Scenarios, as
well as how best to incorporate them. Stakeholder input is particularly
important for factors in the first three categories of factors because
Federal, state, and local government entities, federally-recognized
Tribes, and utilities, load-serving entities, and their retail
regulators that participate in the stakeholder process are distinctly
[[Page 49369]]
positioned to provide transmission providers with vital information on
how the factors over which they have authority or govern are likely to
influence Long-Term Transmission Needs over the transmission planning
horizon. Similarly, utilities, corporations, and governments that
participate in the stakeholder process are distinctly positioned to
provide transmission providers with vital information regarding factors
in Factor Category Seven: utility and corporate commitments and
Federal, federally-recognized Tribal, state, and local policy goals
that affect Long-Term Transmission Needs. The required stakeholder
process ensures that all stakeholders, including states, can provide
important and useful information concerning factors that they believe
will affect Long-Term Transmission Needs.
531. We recognize that different stakeholders may provide
information about the same factor that is contradictory--an issue
identified by some commenters.\1160\ Different stakeholders may also
provide different analyses showing, for example, how a specific factor
will affect resource additions and retirements. However, as we explain
earlier, transmission providers have discretion regarding how to
account for specific factors in their development of Long-Term
Scenarios. In reviewing the information provided by stakeholders in the
open and transparent stakeholder process, transmission providers may
weigh more heavily one source of information over another. To maintain
transparency for stakeholders, transmission providers must include a
general statement explaining how they will account for each factor in
their Long-Term Scenarios on the public portion of an OASIS or other
public website, as further described below.
---------------------------------------------------------------------------
\1160\ E.g., Undersigned States Initial Comments at 3 (citing
NOPR, 179 FERC ] 61,028 at P 106).
---------------------------------------------------------------------------
532. We also believe that the information provided in the open and
transparent stakeholder process will reduce the burden placed on
transmission providers to identify and assess the impact of relevant
factors for each category. For example, transmission providers can rely
on the open and transparent stakeholder process to identify the
multiple relevant local laws and regulations that are likely to
influence Long-Term Transmission Needs over the transmission planning
horizon. The same is true for the utility and corporate commitments and
Federal, federally-recognized Tribal, state, and local policy goals
that affect Long-Term Transmission Needs in Factor Category Seven.
During the stakeholder process, government entities, utilities, and
corporate entities can identify their publicly announced goals and
provide feedback on how the transmission providers can account for
these publicly announced goals in Long-Term Scenarios. These entities
will have an opportunity to provide information to help the
transmission providers determine the likelihood that they will achieve
their stated goals, which the transmission providers can then use to
discount the specific factors in Factor Category Seven, if necessary.
533. With regard to the information about factors and categories of
factors that transmission providers must publish on the public portion
of an OASIS or other public website, we modify the proposal in the
NOPR. We require transmission providers to publish on the public
portion of an OASIS or other public website: (1) the list of the
factors in each of the seven required categories of factors that they
will account for in their Long-Term Scenarios; (2) a description of
each factor that they will account for in their Long-Term Scenarios;
(3) a general statement explaining how they will account for each of
these factors in their Long-Term Scenarios; (4) a description of the
extent to which they will discount any factors in Factor Categories
Four through Seven in each Long-Term Scenario; and (5) a list of the
factors that they considered but did not incorporate in their Long-Term
Scenarios.\1161\ Transmission providers must post this information
after stakeholders, including states, have had the meaningful
opportunity to propose potential factors and to provide input on how to
account for specific factors in the development of Long-Term Scenarios.
---------------------------------------------------------------------------
\1161\ As discussed above, transmission providers may not
discount factors in Factor Categories One through Three.
---------------------------------------------------------------------------
534. We believe that this transparency is necessary to make clear
to stakeholders which specific factors transmission providers
incorporate into Long-Term Scenarios and how they incorporate those
factors. We believe the posting requirement will also provide greater
transparency into how transmission providers develop Long-Term
Scenarios (discussed below), as some commenters requested, while still
providing transmission providers with flexibility regarding whether,
and if so, how they choose to incorporate relevant factors.
535. In response to commenters requesting additional
transparency,\1162\ we require transmission providers to publish on the
public portion of an OASIS or other public website the factors that
were considered but not accounted for in the development of Long-Term
Scenarios. We believe this requirement will help stakeholders
understand which factors, either identified in the stakeholder process
or independently identified by a transmission provider, the
transmission providers in a transmission planning region have
determined are unlikely to affect Long-Term Transmission Needs. This
transparency also ensures that stakeholder-proposed factors are
reviewed in a fair and non-discriminatory manner.
---------------------------------------------------------------------------
\1162\ E.g., Pine Gate Initial Comments at 25.
---------------------------------------------------------------------------
536. We decline to require transmission providers to publicly
publish the justification for and derivation of the amount of
discounting deemed appropriate, as requested by Clean Energy
Buyers.\1163\ We believe such a requirement to detail the rationale for
the treatment of each factor in Factor Categories Four through Seven,
across all Long-Term Scenarios, would create a time-consuming
administrative burden for transmission providers that is not justified
by the value of the additional information provided to stakeholders.
---------------------------------------------------------------------------
\1163\ Clean Energy Buyers Initial Comments at 16-17.
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537. We decline to adopt modifications to the NOPR proposal that
would diminish the role of the transmission providers in developing
Long-Term Scenarios.\1164\ Transmission providers must provide
stakeholders with a meaningful opportunity to propose potential factors
and to provide input on how to incorporate specific factors in the
development of Long-Term Scenarios, as described above. However, we
reiterate that transmission providers are not required to incorporate
stakeholder-identified factors into their development of Long-Term
Scenarios merely because stakeholders propose them, if transmission
providers determine that the factor is unlikely to influence Long-Term
Transmission Needs over the transmission planning horizon. Consistent
with Order No. 890, the ultimate responsibility for transmission
planning remains with the transmission provider.\1165\
---------------------------------------------------------------------------
\1164\ E.g., GridLab Initial Comments at 20-21; R Street Initial
Comments at 7.
\1165\ Order No. 890, 118 FERC ] 61,119 at P 454. There, in
response to the suggestion by some commenters that we require
transmission providers to allow customers to collaboratively develop
transmission plans with transmission providers on a co-equal basis,
we clarified that transmission planning is the tariff obligation of
each transmission provider, and the pro forma OATT planning process
adopted in this final rule is the means to see that it is carried
out in a coordinated, open, and transparent manner, in order to
ensure that customers are treated comparably. Therefore, the
ultimate responsibility for planning remains with transmission
providers.
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[[Page 49370]]
4. Number and Development of Long-Term Scenarios
a. NOPR Proposal
538. In the NOPR, the Commission proposed to require transmission
providers to develop at least four distinct Long-Term Scenarios as part
of Long-Term Regional Transmission Planning at least once during a
transmission planning cycle.\1166\ The Commission explained that it
preliminarily found that using at least four distinct Long-Term
Scenarios is a reasonable lower bound for the number of Long-Term
Scenarios that transmission providers must evaluate in Long-Term
Regional Transmission Planning. The Commission explained that this
minimum number of Long-Term Scenarios would help to ensure that
transmission providers conduct Long-Term Regional Transmission Planning
that identifies more efficient or cost-effective regional transmission
facilities to meet transmission needs driven by changes in the resource
mix and demand. The Commission explained that to satisfy this
requirement, transmission providers could develop a base case and three
alternatives, or a low-, medium-, and high-level assumption for the
factors that transmission providers (and their stakeholders) believe to
be important to conduct Long-Term Regional Transmission Planning to
more efficiently or cost-effectively meet transmission needs driven by
changes in the resource mix and demand, along with a scenario that
accounts for a high-impact, low-frequency event (as discussed
below).\1167\
---------------------------------------------------------------------------
\1166\ NOPR, 179 FERC ] 61,028 at PP 121-126.
\1167\ Id. P 122.
---------------------------------------------------------------------------
539. Consistent with the Order No. 890 transparency transmission
planning principle,\1168\ the Commission proposed to require
transmission providers in each transmission planning region to publicly
disclose (subject to any applicable confidentiality protections)
information and data inputs they use to create each Long-Term Scenario.
The Commission explained that this transparency requirement will allow
stakeholders to understand how each scenario differs.
---------------------------------------------------------------------------
\1168\ The transparency transmission planning principle requires
transmission providers to reduce to writing and make available the
basic methodology, criteria, and processes used to develop
transmission plans. Transmission providers must make sufficient
information available to enable customers and other stakeholders to
replicate the results of transmission planning studies. Order No.
890, 118 FERC ] 61,119 at P 471. Order No. 1000 applied this and
other Order No. 890 transmission planning principles to regional
transmission planning processes. Order No. 1000, 136 FERC ] 61,051
at P 151.
---------------------------------------------------------------------------
540. Similarly, consistent with the coordination transmission
planning principle established in Order No. 890,\1169\ the Commission
proposed to require that transmission providers in each transmission
planning region give stakeholders the opportunity to provide timely and
meaningful input into the identification of which Long-Term Scenarios
are developed. The Commission proposed to require transmission
providers to revise the regional transmission planning processes in
their OATTs to outline an open and transparent process that provides
stakeholders, including states, with a meaningful opportunity to
propose which future outcomes are probable and can be captured through
assumptions made in the development of Long-Term Scenarios.
Furthermore, the Commission proposed to require transmission providers
to explain on compliance how their process will identify a plausible
and diverse set of Long-Term Scenarios.\1170\
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\1169\ The coordination transmission planning principle requires
transmission providers to provide customers and other stakeholders
with the opportunity to participate fully in the transmission
planning process. The transmission planning process must provide for
the timely and meaningful input and participation of customers and
other stakeholders regarding the development of transmission plans,
allowing customers and other stakeholders to participate in the
early stages of development. Order No. 890, 118 FERC ] 61,119 at PP
451-454.
\1170\ NOPR, 179 FERC ] 61,028 at P 123.
---------------------------------------------------------------------------
b. Comments
541. Many commenters support requiring transmission providers in
each transmission planning region to develop at least four distinct
Long-Term Scenarios as part of Long-Term Regional Transmission
Planning.\1171\ GridLab and R Street state that this proposed
requirement appropriately balances the need to address uncertainty and
risk factors associated with long-term transmission planning while
limiting the complexity of the transmission planning process.\1172\ PJM
says that employing multiple scenarios will ensure that transmission
providers' plans reflect changing needs while avoiding the risk of
over-building.\1173\ SEIA states that requiring four distinct Long-Term
Scenarios will allow transmission providers to reflect the uncertainty
inherent in long-term planning.\1174\ AEE states that the Commission
should establish a minimum number of scenarios as a baseline for
compliance with any final order.\1175\ New York TOs support requiring
the use of multiple scenarios for Long-Term Regional Transmission
Planning, noting that NYISO already incorporates multiple scenarios
into its transmission planning processes.\1176\ Nevada Commission notes
that information from four scenarios could provide inputs into Nevada's
integrated regional planning process and identify both local and
regional needs.\1177\
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\1171\ ACORE Initial Comments at 10; Advanced Energy Buyers
Initial Comments at 8; AEE Initial Comments at 8, 18; APPA Initial
Comments at 29; Arizona Commission Initial Comments at 6; Concerned
Scientists Reply Comments at 18-19; ELCON Initial Comments at 12;
ENGIE Initial Comments at 4; Evergreen Action Initial Comments at 3;
Georgia Commission Initial Comments at 4-5; GridLab Initial Comments
at 12; ITC Initial Comments at 12; Nevada Commission Initial
Comments at 8-9; New England for Offshore Wind Initial Comments at
2; NextEra Initial Comments at 65; Northwest and Intermountain
Initial Comments at 12; NYISO Initial Comments at 25; [Oslash]rsted
Initial Comments at 7; Southeast PIOs Initial Comments at 46; SPP
Market Monitor Initial Comments at 6-7; US Chamber of Commerce
Initial Comments at 7; US DOE Initial Comments at 14; Vermont
Electric and Vermont Transco Initial Comments at 2.
\1172\ GridLab Initial Comments at 12; R Street Initial Comments
at 6.
\1173\ PJM Initial Comments at 74.
\1174\ SEIA Initial Comments at 11.
\1175\ AEE Reply Comments at 18.
\1176\ New York TOs Initial Comments at 2.
\1177\ Nevada Commission Initial Comments at 8-9.
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542. Policy Integrity argues that the Commission should require
more than four Long-Term Scenarios.\1178\ Policy Integrity identifies
planning efforts that have used more than four scenarios to illustrate
that best practice counsels against reducing the number of required
Long-Term Scenarios.\1179\ Northwest and Intermountain state that,
depending upon the size and characteristics of the transmission
planning region, additional scenarios may be necessary to identify the
transmission facilities that are most likely to ensure just and
[[Page 49371]]
reasonable rates.\1180\ LADWP states that while developing more than
four scenarios will likely be prudent in some instances such as special
studies, four scenarios should be adequate for most Long-Term Regional
Transmission Planning given the 20-year planning horizon and
uncertainties.\1181\
---------------------------------------------------------------------------
\1178\ Policy Integrity Initial Comments at 14-16.
\1179\ Id. at 15 (citing US DOE et al., Presentation on National
Transmission Planning Study at the Modeling Subcommittee Meeting, at
slide 21 (June 7, 2022), https://perma.cc/MEJ5-9JE6 (study will use
approximately 100 scenarios); ERCOT, Report On Existing and
Potential Electric System Constrains and Needs 10 (Dec. 2020),
https://perma.cc/JGS4-9VH7 (ERCOT has previously used five
scenarios); Mohamed Labib Awad et al., Using Market Simulations for
Economic Assessment of Transmission Upgrades: Application of the
California ISO Approach, in Restructured Electric Power Systems:
Analysis Of Electricity Markets With Equilibrium Models 241, 255
(Xiao-Ping Zhang ed. 2010) (economists evaluating CAISO have used
seventeen scenarios)).
\1180\ Northwest and Intermountain Initial Comments at 12.
\1181\ LADWP Initial Comments at 4.
---------------------------------------------------------------------------
543. Some commenters stress the importance of considering multiple
Long-Term Scenarios and the uncertainty associated with future
conditions.\1182\ ACORE suggests that uncertainties in data can be
addressed with multiple Long-Term Scenarios that are continuously
revised instead of granting flexibility or encouraging discounting of
certain factors.\1183\ ENGIE states that a single base-case scenario is
not effective at capturing trends in the resource mix and demand.\1184\
New York Commission and NYSERDA state that Long-Term Scenarios should
reflect a range of plausible long-term futures that are relevant to the
state (or transmission planning region) and should account for the
uncertainty associated with looking out over longer time
horizons.\1185\ On the other hand, R Street posits that whether
scenario planning sufficiently captures information on the resource mix
and demand depends more on the quality of inputs and scenario
construction elements than the total number of scenarios.\1186\
---------------------------------------------------------------------------
\1182\ ACORE Initial Comments at 10; ENGIE Initial Comments at
3-4; New York Commission and NYSERDA Initial Comments at 8; R Street
Initial Comments at 6.
\1183\ ACORE Initial Comments at 10.
\1184\ ENGIE Initial Comments at 4.
\1185\ New York Commission and NYSERDA Initial Comments at 8.
\1186\ R Street Initial Comments at 6.
---------------------------------------------------------------------------
544. Some commenters generally support requiring Long-Term
Scenarios \1187\ including scenarios examining the effects of high
energy demand,\1188\ and penetration of renewable resources.\1189\
---------------------------------------------------------------------------
\1187\ Breakthrough Energy Supplemental Comments at 1; Clean
Energy Associations Initial Comments at 11-12; Cross Sector
Representatives Supplemental Comments at 1; PJM Initial Comments at
6, 71-72; RMI Supplemental Comments at 2; US Climate Alliance
Initial Comments at 2; Western PIOs Initial Comments at 29.
\1188\ ACORE Supplemental Comments at 1; Environmental Groups
Supplemental Comments at 2.
\1189\ ACORE Supplemental Comments at 1; Environmental Groups
Supplemental Comments at 2.
---------------------------------------------------------------------------
545. Other commenters do not oppose this requirement.\1190\
---------------------------------------------------------------------------
\1190\ Clean Energy Buyers Initial Comments at 17; Dominion
Initial Comments at 25; Pine Gate Initial Comments at 26; Utah
Division of Public Utilities Initial Comments at 5.
---------------------------------------------------------------------------
546. Some commenters support requiring transmission providers to
establish Long-Term Scenarios, but would modify the NOPR proposal to
require a lower minimum number. AEP, Entergy, NRECA, Pine Gate, and
Western PIOs support requiring at least three Long-Term
Scenarios.\1191\ CAISO argues that the Commission should not require
transmission providers to develop a minimum of four Long-Term Scenarios
because there is no evidence, rationale, or justification for why four
is the appropriate number of scenarios to develop.\1192\ Instead, CAISO
asserts that the Commission should grant transmission planners the
flexibility to determine the minimum number of Long-Term Scenarios that
are appropriate given the specific circumstances in their region and
planning cycle. However, CAISO states that if Commission were to adopt
a minimum number of Long-Term Scenarios, three Long-Term Scenarios is
appropriate because it allows for a base case scenario and two
sensitivity scenarios.\1193\ Entergy and NRECA claim that three Long-
Term Scenarios would better balance the burden with the benefit of
developing an additional scenario.\1194\ Pine Gate recommends that,
instead of requiring a fourth scenario, the Commission should permit
transmission providers in each transmission planning region to develop
and use no less than three Long-Term Scenarios, and then to conduct
either a fourth scenario or a sensitivity analysis on the most likely
Long-Term Scenario to ``account for uncertain operational outcomes that
determine the benefits of or need for transmission facilities during
high-impact, low frequency events'' as proposed in the NOPR.\1195\
---------------------------------------------------------------------------
\1191\ AEP Initial Comments at 5, 8, 12; Entergy Initial
Comments at 13; NRECA Initial Comments 35; Pine Gate Initial
Comments at 26-27; Western PIOs Initial Comments at 33.
\1192\ CAISO Initial Comments at 23-24.
\1193\ Id. at 25-26.
\1194\ Entergy Initial Comments at 13; NRECA Initial Comments
35.
\1195\ Pine Gate Initial Comments at 26 (citing NOPR, 179 FERC ]
61,028 at P 124).
---------------------------------------------------------------------------
547. National Grid argues that there is an inherent trade-off
between the number of Long-Term Scenarios, the quality of the data
underpinning the assessment, and the frequency of reassessments.
National Grid concludes that a transmission provider should not be
required to plan for a scenario that is impossible or not supported by
its stakeholders solely to meet the requirement that four distinct
Long-Term Scenarios be developed and studied.\1196\ Xcel supports the
use of scenarios but states that the proposed requirement to use at
least four Long-Term Scenarios is too prescriptive.\1197\ Relatedly,
LADWP states that developing more than four Long-Term Scenarios may be
prudent in some instances but that it would be inefficient and a waste
of resources to require all transmission providers in each transmission
planning region to do so.\1198\
---------------------------------------------------------------------------
\1196\ National Grid Initial Comments at 14-15.
\1197\ Xcel Initial Comments at 10.
\1198\ LADWP Initial Comments at 4.
---------------------------------------------------------------------------
548. Some commenters broadly oppose the NOPR proposal to require
transmission providers in each transmission planning region to develop
at least a minimum number or specific number of Long-Term
Scenarios.\1199\ California Commission argues that the NOPR's approach
would interfere with regional transmission planning processes, such as
CAISO's, that are closely coordinated with state resource planning and
load forecasting and already effectively identify transmission
necessary to accommodate changes in the resource mix and demand.\1200\
Duke argues that requiring a minimum number of Long-Term Scenarios,
while also requiring one capture high-impact, low-frequency events,
places greater importance on developing scenarios purely to satisfy the
requirement than on gaining consensus about what scenarios are in fact
plausible or most likely.\1201\ MISO states that a prescriptive number
of Long-Term Scenarios with specific factors included may introduce a
level of granularity and complexity into Long-Term Regional
Transmission Planning that impedes progress.\1202\
---------------------------------------------------------------------------
\1199\ California Commission Initial Comments at 21-24; Duke
Initial Comments at 15; Indicated PJM TOs Initial Comments at 9-10;
ISO-NE Initial Comments at 28; ISO/RTO Council Initial Comments at
9; MISO Initial Comments at 20; NESCOE Initial Comments at 30; OMS
Initial Comments at 5; PG&E Initial Comments at 6-7; SPP Initial
Comments at 9-10; State Agencies Initial Comments at 14.
\1200\ California Commission Initial Comments at 23.
\1201\ Duke Initial Comments at 15.
\1202\ MISO Initial Comments at 20.
---------------------------------------------------------------------------
549. Some commenters request that the Commission provide
transmission providers in each transmission planning region with the
flexibility to determine how many Long-Term Scenarios to develop.\1203\
US DOE supports a
[[Page 49372]]
requirement to identify four scenarios as a reasonable lower bound, and
supports the analysis of additional scenarios, including sensitivities,
but asserts that the development of Long-Term Scenarios should not be
prescriptive but, rather, the Commission should provide guidelines and
give transmission planning regions flexibility to work within those
guidelines to capture reasonable sets of scenarios.\1204\
---------------------------------------------------------------------------
\1203\ Ameren Initial Comments at 13-14; Avangrid Initial
Comments at 9-10; CAISO Initial Comments at 25; California Energy
Commission Initial Comments at 2; Clean Energy Associations Initial
Comments at 11-12; Dominion Initial Comments at 25; Entergy Initial
Comments at 13; MISO Initial Comments at 16, 20; MISO TOs Initial
Comments at 16-17; National Grid Initial Comments at 14; Nebraska
Commission Initial Comments at 5; PG&E Initial Comments at 7; PJM
Initial Comments at 72; SPP Initial Comments at 9; US DOE Initial
Comments at 14; Xcel Initial Comments at 10.
\1204\ US DOE Initial Comments at 14.
---------------------------------------------------------------------------
550. Some commenters propose that, if the Commission does not
require a minimum number of Long-Term Scenarios, the Commission should
instead require that transmission providers in each transmission
planning region demonstrate, on compliance, why their proposed number
of Long-Term Scenarios is appropriate.\1205\ Duke asserts that the
Commission should direct transmission providers to offer on compliance
a process for Long-Term Scenario development that will capture enough
sufficiently plausible scenarios with distinct sets of assumptions to
adequately capture a consensus view of the most likely future state(s)
to occur.\1206\
---------------------------------------------------------------------------
\1205\ CAISO Initial Comments at 25; Duke Initial Comments at
15; Eversource Initial Comments at 17-18; NESCOE Initial Comments at
30-31.
\1206\ Duke Initial Comments at 15.
---------------------------------------------------------------------------
551. Other commenters call for the Commission to permit discretion
on how transmission providers determine the number of Long-Term
Scenarios to use.\1207\ ISO-NE and ISO/RTO Council argue that the
number of Long-Term Scenarios is an implementation detail that each
transmission planning region should decide.\1208\ NYISO states that the
final order should permit each transmission planning region to conduct
Long-Term Regional Transmission Planning using multiple Long-Term
Scenarios that account for varying levels of achievement of local laws
and regulations.\1209\
---------------------------------------------------------------------------
\1207\ Indicated PJM TOs Initial Comments at 9-10; ISO-NE
Initial Comments at 28; ISO/RTO Council Initial Comments at 9; MISO
Initial Comments at 20; NESCOE Initial Comments at 30-31; OMS
Initial Comments at 5.
\1208\ ISO-NE Initial Comments at 28; ISO/RTO Council Initial
Comments at 9.
\1209\ NYISO Initial Comments at 23.
---------------------------------------------------------------------------
552. MISO opposes requiring transmission providers to evaluate a
specific number of Long-Term Scenarios and proposes, instead, that the
Commission require that future scenarios be developed and implemented
for purposes of long-term regional transmission planning, leaving each
transmission planning region to determine what and how many scenarios
are appropriate. According to MISO, this approach would ensure
consistency across the transmission planning regions in what is
required while allowing for any needed variation within each
region.\1210\ Additionally, MISO notes that it developed the futures
that it uses in its Long-Range Transmission Plan through extensive
stakeholder processes and that these futures reflect the specific
realities of its member utilities. MISO contends that allowing
transmission providers to develop the number of Long-Term Scenarios
they need, and at intervals appropriate for them, encourages
stakeholder buy-in and more efficient allocation of planning
resources.\1211\
---------------------------------------------------------------------------
\1210\ MISO Initial Comments at 16, 20.
\1211\ MISO Reply Comments at 9-10.
---------------------------------------------------------------------------
553. California Municipal Utilities disagree with comments that
urge prescriptive uniformity, arguing that uniformity involves high
costs and lacks consumer protection measures against speculative
transmission projects.\1212\ For example, California Municipal
Utilities argue against the proposal from Western PIOs for the
development of three common scenarios to be synchronized across the
Western Interconnection because this proposal amounts to central
resource planning, which is not consistent with the existing process in
which state and local choices drive the planning process.\1213\
---------------------------------------------------------------------------
\1212\ California Municipal Utilities Reply Comments at 5.
\1213\ Id. (citing Western PIOs Initial Comments at 32-33).
---------------------------------------------------------------------------
554. Louisiana Commission states that the Commission's proposal is
overly prescriptive and that the Commission should provide for a more
flexible approach that allows transmission providers, retail
regulators, and other stakeholders to develop scenarios with
appropriate, realistic, and reasonable assumptions. Louisiana
Commission states that Long-Term Scenarios should be based on
reasonable ranges of assumptions for load, and generation type and
location. Louisiana Commission argues that the number of scenarios
required is far less important than the quality of the data and
assumptions used to develop them.\1214\ MISO TOs agree that the NOPR
proposal is overly prescriptive, stating that the Commission should not
create unnecessary obstacles, but rather create a rule broad enough to
incorporate existing processes.\1215\
---------------------------------------------------------------------------
\1214\ Louisiana Commission Reply Comments at 6-7.
\1215\ MISO TOs Reply Comments at 13.
---------------------------------------------------------------------------
555. Some commenters emphasize the need for an open and transparent
process that provides stakeholders, including states, with a meaningful
opportunity to provide timely and meaningful input into which Long-Term
Scenarios are developed.\1216\ For example, California Commission,
NRECA, Concerned Scientists, and US Climate Alliance support the NOPR
proposal to require transmission providers to disclose--subject to any
applicable confidentiality protections--information and data inputs
that they use to create each Long-Term Scenario.\1217\ ELCON states
that the Commission should require each transmission provider to post
all methodologies and inputs used in determining Long-Term Scenarios
and factors to its OASIS.\1218\ NRG claims that the NOPR proposes a
central determination of particular actions based on collectively
determined assumptions, which gives up a major advantage of
competition--the requirement that market participants take an
individual view based on available information of the future viability
of any investment they might make.\1219\
---------------------------------------------------------------------------
\1216\ California Commission Initial Comments at 25; Clean
Energy Associations Initial Comments at 12; DC and MD Offices of
People's Counsel Initial Comments at 14; ELCON Initial Comments at
12; NRECA Initial Comments at 35; Pacific Northwest State Agencies
at 14-15; US Climate Alliance Initial Comments at 2.
\1217\ California Commission Initial Comments at 25; NRECA
Initial Comments at 35; Concerned Scientists Reply Comments at 15-
16; US Climate Alliance Initial Comments at 2.
\1218\ ELCON Initial Comments at 12.
\1219\ NRG Initial Comments at 8.
---------------------------------------------------------------------------
556. NESCOE argues that states must play a central role in Long-
Term Regional Transmission Planning. Specifically, NESCOE agrees with
ISO-NE, which calls for the Commission to explicitly authorize states
to have a central decision-making role at all aspects of Long-Term
Regional Transmission Planning, including ``scenario analysis
development,'' to ensure necessary additional investment for a
reliable, clean energy future.\1220\ Similarly, Nebraska Commission
adds that state regulatory commissions should have a significant role
in defining Long-Term Scenarios.\1221\
---------------------------------------------------------------------------
\1220\ NESCOE Reply Comments at 2 (citing ISO-NE Initial
Comments at 2-4).
\1221\ Nebraska Commission Initial Comments at 5-6.
---------------------------------------------------------------------------
557. AEE requests that the Commission clarify the role of states in
providing input to the development of Long-Term Scenarios.\1222\
---------------------------------------------------------------------------
\1222\ AEE Initial Comments at 19.
---------------------------------------------------------------------------
558. GridLab states that the Commission should be prepared to act
[[Page 49373]]
as the arbiter of stakeholder concerns about Long-Term Scenario design,
similar to the role that state public utility commissions play in the
integrated resource planning process, and that this may require new
staff, resources, and the development of new expertise at the
Commission.\1223\
---------------------------------------------------------------------------
\1223\ GridLab Initial Comments at 11-12.
---------------------------------------------------------------------------
c. Commission Determination
559. We adopt the NOPR proposal, with modification, to require
transmission providers in each transmission planning region to develop
at least three distinct Long-Term Scenarios as part of Long-Term
Regional Transmission Planning. In implementing this requirement,
transmission providers must develop, at least once during the five-year
Long-Term Regional Transmission Planning cycle, at least three distinct
Long-Term Scenarios that, at a minimum, incorporate the seven
categories of factors listed in the Categories of Factors section
above. We find that requiring transmission providers to develop at
least three distinct Long-Term Scenarios as part of Long-Term Regional
Transmission Planning strikes the appropriate balance between
establishing a sufficient number of Long-Term Scenarios and the
associated burden of developing and using Long-Term Scenarios in Long-
Term Regional Transmission Planning. We also find that requiring
transmission providers to develop at least three distinct Long-Term
Scenarios instead of four, as proposed in the NOPR, is more consistent
with the manner in which some transmission providers currently employ
scenarios in their existing regional transmission planning
process.\1224\ We also reiterate, as stated in the NOPR, that if
transmission providers produce a base-case Long-Term Scenario in Long-
Term Regional Transmission Planning, that base case should be
consistent with what the transmission provider determines is the most
likely scenario to occur.\1225\
---------------------------------------------------------------------------
\1224\ See, e.g., CAISO Initial Comments at 26 (explaining that
``CAISO typically has utilized three scenarios in its public policy
planning process, a base case scenario and two sensitivity
scenarios''); Entergy Initial Comments at 13-14 (explaining that
MISO currently uses three scenarios in its transmission planning
process and arguing that the use of three scenarios enables
``transmission providers to `bookend' plausible outcomes to plan no-
regrets additions to meet the grid, and then develop a scenario
between those two to better inform the decision making''); NRECA
Initial Comments at 35 n.100 (highlighting that MISO uses three
scenarios in its transmission planning process).
\1225\ NOPR, 179 FERC ] 61,028 at P 123.
---------------------------------------------------------------------------
560. In addition, we adopt the NOPR proposal to require, consistent
with Order No. 890's transparency transmission planning principle,
transmission providers in each transmission planning region to publicly
disclose (subject to any applicable confidentiality protections)
information and data inputs that they use to create each Long-Term
Scenario.\1226\ We also adopt the NOPR proposal to require transmission
providers in each transmission planning region, consistent with Order
No. 890's coordination transmission planning principle, to provide
stakeholders an opportunity to provide timely and meaningful input into
how Long-Term Scenarios are developed.\1227\ Consistent with Order No.
890 and Order No. 1000's coordination transmission planning principle,
we require transmission providers, with the input of their customers
and other stakeholders, to craft coordination requirements that work
for those transmission providers and their customers and other
stakeholders. Furthermore, we adopt the NOPR proposal to require
transmission providers to revise the regional transmission planning
process in their OATTs to outline an open and transparent process that
provides stakeholders, including states, with a meaningful opportunity
to propose which future outcomes are probable and can be captured
through assumptions made in the development of Long-Term Scenarios. We
conclude that these requirements will help ensure that transmission
providers will have the necessary information to identify Long-Term
Transmission Needs and identify, evaluate, and select Long-Term
Regional Transmission Facilities to address those needs. Furthermore,
by requiring transmission providers to afford stakeholders a meaningful
opportunity to propose future outcomes that are probable, we believe
that this requirement helps to ensure that Long-Term Transmission Needs
are being addressed in a more efficient or cost-effective manner.\1228\
---------------------------------------------------------------------------
\1226\ The transparency transmission planning principle requires
transmission providers to reduce to writing and make available the
basic methodology, criteria, and processes used to develop
transmission plans. Transmission providers must make sufficient
information available to enable customers and other stakeholders to
replicate the results of transmission planning studies. Order No.
890, 118 FERC ] 61,119 at P 471. Order No. 1000 applied this and
other Order No. 890 transmission planning principles to regional
transmission planning processes. Order No. 1000, 136 FERC ] 61,051
at P 151.
\1227\ The coordination transmission planning principle requires
transmission providers to provide customers and other stakeholders
with the opportunity to participate fully in the transmission
planning process. The transmission planning process must provide for
the timely and meaningful input and participation of customers and
other stakeholders regarding the development of transmission plans,
allowing customers and other stakeholders to participate in the
early stages of development. Order No. 890, 118 FERC ] 61,119 at P
454.
\1228\ Order No. 1000, 136 FERC ] 61,051 at P 150.
---------------------------------------------------------------------------
561. We also note the important role of states in developing Long-
Term Scenarios. As the Commission stated in Order No. 890 and Order No.
1000, and we reiterate here, our expectation is that ``all transmission
providers will respect states' concerns'' when engaging in the regional
transmission planning process.\1229\ We strongly encourage states to
participate actively in the development of Long-Term Scenarios, as well
as in all other aspects of Long-Term Regional Transmission Planning. In
response to NESCOE's and AEE's concerns about the role of state
regulators in the development of Long-Term Scenarios and their use in
Long-Term Regional Transmission Planning,\1230\ we find that,
consistent with Order No. 890,\1231\ transmission planning must be
coordinated with interested stakeholders, including relevant state
regulators that wish to participate in the Long-Term Regional
Transmission Planning process. As reflected throughout this final
order, we recognize that states have a particularly important role to
play in the development of Long-Term Regional Transmission Facilities
and encourage transmission providers to work with states in a way that
reflects that role in addition to complying with the relevant
requirements established herein.
---------------------------------------------------------------------------
\1229\ Id. P 212; Order No. 890, 118 FERC ] 61,119 at P 574.
\1230\ AEE Initial Comments at 8; NESCOE Reply Comments at 2
(citing ISO-NE Initial Comments at 2-4).
\1231\ Order No. 890, 118 FERC ] 61,119 at P 574.
---------------------------------------------------------------------------
562. In response to commenters that argue that the Commission
should require four or more Long-Term Scenarios,\1232\ we affirm that
nothing in this final order precludes or prevents transmission
providers from proposing
[[Page 49374]]
to use more than three Long-Term Scenarios in Long-Term Regional
Transmission Planning. To the extent that transmission providers, in
consultation with stakeholders, conclude that using more than three
Long-Term Scenarios is appropriate for Long-Term Regional Transmission
Planning in their transmission planning region, those transmission
providers may propose to use more than three Long-Term Scenarios in
their compliance filings.
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\1232\ ACORE Initial Comments at 10; Advanced Energy Buyers
Initial Comments at 8; AEE Initial Comments at 8; APPA Initial
Comments at 29; Arizona Commission Initial Comments at 6; Concerned
Scientists Reply Comments at 18-19; ELCON Initial Comments at 12;
ENGIE Initial Comments at 4; Evergreen Action Initial Comments at 3;
Georgia Commission Initial Comments at 4-5; GridLab Initial Comments
at 12; ITC Initial Comments at 12; Nevada Commission Initial
Comments at 8-9; New England for Offshore Wind Initial Comments at
2; NextEra Initial Comments at 65; Northwest and Intermountain
Initial Comments at 12; NYISO Initial Comments at 25; [Oslash]rsted
Initial Comments at 7; Southeast PIOs Initial Comments at 46; SPP
Market Monitor Initial Comments at 7; US Chamber of Commerce Initial
Comments at 7; US DOE Initial Comments at 14-15; Vermont Electric
and Vermont Transco Initial Comments at 2.
---------------------------------------------------------------------------
563. In response to California Commission's comments about the
interaction between the development of Long-Term Scenarios and existing
regional transmission planning processes,\1233\ we believe the final
order, as modified from the NOPR proposal, addresses this concern and
provides transmission providers with sufficient flexibility to tailor
the development of Long-Term Scenarios to their transmission planning
regions' specific needs or existing practices, as discussed elsewhere
in this final order.\1234\
---------------------------------------------------------------------------
\1233\ California Commission Initial Comments at 23.
\1234\ See supra Categories of Factors, Requirement to
Incorporate Categories of Factors section; Categories of Factors,
Stakeholder Process and Transparency section.
---------------------------------------------------------------------------
5. Types of Long-Term Scenarios
a. NOPR Proposal
564. In the NOPR, the Commission proposed to require that each
Long-Term Scenario incorporate, at a minimum, the categories of factors
listed in the requirement above. As discussed in the Factors section of
the NOPR,\1235\ the Commission proposed that each Long-Term Scenario
must be consistent with Federal, state, and local laws and regulations
that affect the future resource mix; Federal, state, and local laws and
regulations on decarbonization and electrification; and state-approved
integrated resource plans. However, the Commission explained that each
Long-Term Scenario may vary according to assumptions about the
remaining categories of factors described in the NOPR, as well as with
respect to other characteristics of the future electric power system.
The Commission explained that it neither proposed to require the
development of a specific Long-Term Scenario or specific set of Long-
Term Scenarios, nor did it propose to require that transmission
providers identify the relative likelihood of different Long-Term
Scenarios except where transmission providers develop a base case
scenario, as described more fully below.\1236\
---------------------------------------------------------------------------
\1235\ NOPR, 179 FERC ] 61,028 at PP 104-112.
\1236\ Id. P 121.
---------------------------------------------------------------------------
565. The Commission proposed to require transmission providers in
each transmission planning region to develop a plausible and diverse
set of Long-Term Scenarios.\1237\ The Commission explained that the set
of at least four Long-Term Scenarios must be: (1) plausible, that is
they must reasonably capture probable future outcomes, and (2) diverse
in the sense that transmission providers must be able to distinguish
distinct transmission facilities or distinct benefits of similar
transmission facilities in each scenario. The Commission proposed to
require that if the transmission providers in a transmission planning
region use a base case scenario, that scenario should be consistent
with the scenario that the transmission providers determine to be the
most likely scenario to occur.
---------------------------------------------------------------------------
\1237\ The Commission noted that different assumptions about the
factors and data inputs used to develop Long-Term Scenarios and
other characteristics of the future electric power system determine
whether the set of Long-Term Scenarios are plausible and diverse.
---------------------------------------------------------------------------
b. Comments
566. Some commenters support the Commission's proposal to require
transmission providers in each transmission planning region to develop
a plausible and diverse set of Long-Term Scenarios.\1238\ For example,
GridLab agrees that the Commission should require that transmission
providers demonstrate that their Long-Term Scenarios capture a
reasonable range of possible futures. GridLab argues that scenarios
that are too conservative will lead to similar load-resource and
transmission portfolio scenarios, which limits the value of scenario
planning in managing uncertainty and risk.\1239\ Illinois Commission
argues that the NOPR's proposed requirement for diverse and plausible
scenarios is important, and that Long-Term Scenarios must consider a
wide array of conditions.\1240\
---------------------------------------------------------------------------
\1238\ APPA Initial Comments at 29; Clean Energy Buyers Initial
Comments at 17; DC and MD Offices of People's Counsel Initial
Comments at 13; GridLab Initial Comments at 11 & n.12; Illinois
Commission Initial Comments at 7; Mississippi Commission Reply
Comments at 9; NARUC Initial Comments at 10; NESCOE Initial Comments
at 32; New York Commission and NYSERDA Initial Comments at 8; SPP
Market Monitor Initial Comments at 7.
\1239\ GridLab Initial Comments at 11.
\1240\ Illinois Commission Initial Comments at 7.
---------------------------------------------------------------------------
567. Some commenters discuss the need for certain types of Long-
Term Scenarios.\1241\ Certain TDUs and PIOs argue that, although Long-
Term Scenarios should include anticipated levels of generation, they
should also include ``book end'' scenarios of high- and low-load
growth.\1242\ Clean Energy Associations argue that, because the
Inflation Reduction Act provides for significant funding for
electrification, at least some scenarios should evaluate transmission
needs under higher-than-anticipated load growth.\1243\
---------------------------------------------------------------------------
\1241\ ACORE Initial Comments at 10-11; AEE Initial Comments at
8; APPA Initial Comments at 29; Certain TDUs Initial Comments at 18;
Clean Energy Associations Initial Comments at 10-11; Evergreen
Action Initial Comments at 3; Eversource Initial Comments at 18-19;
Georgia Commission Initial Comments at 4-5; NESCOE Initial Comments
at 32; NextEra Initial Comments at 65; PIOs Initial Comments at 22-
23; PJM Initial Comments at 73-74; US Climate Alliance Initial
Comments at 2; US DOE Initial Comments at 15; Utah Division of
Public Utilities Initial Comments at 5-6; Western PIOs Initial
Comments at 33.
\1242\ Certain TDUs Initial Comments at 18; PIOs Initial
Comments at 22-23.
\1243\ Clean Energy Associations Initial Comments at 11 (citing
Inflation Reduction Act, Public Law 117-169 (2022)).
---------------------------------------------------------------------------
568. PJM describes four scenarios that it might use: (1) a low
uncertainty scenario with known inputs, such as legislative and
regulatory laws and announced deactivations and load forecasts; (2) a
medium uncertainty scenario that includes state and local goals and
economic retirement analysis; (3) a higher uncertainty scenario that
adds more speculative and aspirational goals; and (4) a high-impact-
low-frequency resilience evaluation scenario that includes low-
probability, high-impact events. PJM states that the scenarios should
be: (1) based on a clearly defined, robust set of factor development
criteria grounded in customer needs; (2) capable of adapting to an
evolving set of future system conditions; and (3) crafted to produce
the appropriate level of transmission.\1244\
---------------------------------------------------------------------------
\1244\ PJM Initial Comments at 73-74.
---------------------------------------------------------------------------
569. Western PIOs state that one scenario should be based on
existing policy and assumptions about generation retirements and
electrification that are likely to occur. Western PIOs state that a
second scenario would build on that base case scenario by assuming
Public Policy Requirements and utility and corporate goals are met or
exceeded, as well as high levels of electrification and generation
retirements. Western PIOs state that a third scenario should address
high-impact, low-frequency extreme weather events. Western PIOs state
that the fourth scenario could be reserved for a scenario unique to
each of the non-RTO/ISO transmission planning regions.\1245\
---------------------------------------------------------------------------
\1245\ Western PIOs Initial Comments at 33.
---------------------------------------------------------------------------
570. ACORE argues that uncertainties in data do not require
granting
[[Page 49375]]
flexibility or encouraging discounting, but instead can be addressed
with multiple scenarios that are continuously revised as recommended in
the NOPR. For example, one Long-Term Scenario can include a discounted
set of goals, while another can add contingency factors for when demand
exceeds those goals; and a range of scenarios could be incorporated for
the extent of electrification of buildings and transportation. ACORE
states that scenario analysis should incorporate a probabilistic-based
range of future weather and extreme events which, ACORE asserts, will
support the analyses of the benefits of mitigation of those extreme
events and system contingencies and mitigation of weather and load
uncertainty.\1246\
---------------------------------------------------------------------------
\1246\ ACORE Initial Comments at 10-11.
---------------------------------------------------------------------------
571. AEE recommends that the Commission require Long-Term Scenarios
that consider anticipated distributed energy resource
deployments.\1247\ Evergreen Action urges the Commission to require
that at least one Long-Term Scenario contemplate a 100% clean-energy
grid by 2035, to reflect the Biden Administration's target of 100%
carbon-free electricity by 2035.\1248\ Similarly, NextEra argues that
the Commission should require that one of the Long-Term Scenarios be
based on an economy-wide, net-zero emissions scenario or at least a
Federal net-zero emissions mandate limited to the power sector.\1249\
In contrast, Utah Division of Public Utilities states that one of the
Long-Term Scenarios should consider little or no state renewable energy
or decarbonization goals or requirements to assist in determining
transmission costs for states that have less onerous goals.\1250\
---------------------------------------------------------------------------
\1247\ AEE Initial Comments at 8.
\1248\ Evergreen Action Initial Comments at 3.
\1249\ NextEra Initial Comments at 65.
\1250\ Utah Division of Public Utilities Initial Comments at 5-
6.
---------------------------------------------------------------------------
572. APPA requests that one of the Long-Term Scenarios represent a
base case of business as usual.\1251\ Eversource supports the NOPR
proposal to use the ``most likely scenario to occur'' as the base case
for analysis of Long-Term Scenarios.\1252\ Georgia Commission argues
that a base case scenario should reflect the expected long-term mix of
generating capacity, with additional scenarios reflecting alternative
carbon emission constraints, fuel prices, and growth in distributed
energy resources.\1253\ US Climate Alliance states that business-as-
usual cases should be consistent with state and Federal policy and used
in addition to alternative scenarios that demonstrate a range of
factors influencing the changing grid.\1254\
---------------------------------------------------------------------------
\1251\ APPA Initial Comments at 29.
\1252\ Eversource Initial Comments at 19.
\1253\ Georgia Commission Initial Comments at 4-5.
\1254\ US Climate Alliance Initial Comments at 2.
---------------------------------------------------------------------------
573. However, PIOs state that the Commission should not use the
phrase ``business as usual'' as it is misleading in a rapidly changing
electric industry.\1255\ US DOE argues against identifying the
likelihood of any one Long-Term Scenario, including a base case
scenario, because identifying a single such scenario as most likely is
challenging and discourages the analysis of more scenarios and
sensitivities, undermining the value of scenario analysis. Instead, US
DOE argues that transmission facilities that provide high value in
multiple scenarios should be identified as more likely to provide value
to the future transmission system, because expansion options that
provide high value in many future scenarios are flexible, and that
flexibility to accommodate multiple future scenarios is more important
than trying to characterize the likelihood of any one scenario.\1256\
---------------------------------------------------------------------------
\1255\ PIOs Initial Comments at 22.
\1256\ US DOE Initial Comments at 15.
---------------------------------------------------------------------------
574. Senator Schumer supports requiring a high variable energy
resource penetration scenario.\1257\
---------------------------------------------------------------------------
\1257\ Senator Schumer Supplemental Comments at 2.
---------------------------------------------------------------------------
c. Commission Determination
575. We adopt the NOPR proposal to require transmission providers
in each transmission planning region to develop a plausible and diverse
set of at least three Long-Term Scenarios. Specifically, we find that
the set of at least three Long-Term Scenarios must be: (1) plausible,
meaning that each scenario must itself be reasonably probable, and
collectively that the set of plausible scenarios must reasonably
capture probable future outcomes, and (2) diverse, in the sense that
transmission providers can distinguish distinct transmission facilities
or distinct benefits of similar transmission facilities in each Long-
Term Scenario. We find that requiring Long-Term Scenarios to be both
plausible and diverse prevents the development of Long-Term Scenarios
that may otherwise be too conservative, speculative, or similar for
transmission providers to identify Long-Term Transmission Needs and
identify, evaluate, and select Long-Term Regional Transmission
Facilities to more efficiently or cost-effectively address those needs.
Absent a requirement that Long-Term Scenarios be both plausible and
diverse, transmission providers could develop Long-Term Scenarios in a
manner that undercuts one of the primary benefits of using scenario-
based planning practices, which is to help ensure that transmission
providers can account for the uncertainty about future conditions when
conducting Long-Term Regional Transmission Planning.
576. Moreover, we also require that each individual Long-Term
Scenario be plausible (i.e., individually the scenario must be
reasonably probable) because, absent such a requirement, we are
concerned that the set of Long-Term Scenarios may include a Long-Term
Scenario that rests on assumptions about the factors and data inputs
that do not reasonably capture possible future outcomes. Additionally,
we also clarify the term ``diverse'' to mean that the set of Long-Term
Scenarios must represent a reasonable range of probable future outcomes
consistent with the requirement for plausibility, based on assumptions
about the factors and data inputs.
577. We disagree with commenters that argue that the Commission
should modify the NOPR proposal and prescribe specific types of Long-
Term Scenarios for transmission providers to use in Long-Term Regional
Transmission Planning.\1258\ We are not persuaded that we should
require transmission providers to develop either a specific Long-Term
Scenario or a specific set of Long-Term Scenarios because we believe
that transmission providers, with an opportunity for timely and
meaningful input from stakeholders, are in the best position to
determine which plausible Long-Term Scenarios are applicable to their
transmission planning region. Further, we do not find it necessary to
require transmission providers to develop low-, medium-, and high-level
assumptions for the factors that transmission providers believe to be
important except where transmission providers develop a base case
scenario, as discussed above.\1259\
---------------------------------------------------------------------------
\1258\ ACORE Initial Comments at 10-11; AEE Initial Comments at
8; APPA Initial Comments at 29; Certain TDUs Initial Comments at 18,
22; Clean Energy Associations Initial Comments at 11; Evergreen
Action Initial Comments at 3; Eversource Initial Comments at 19;
Georgia Commission Initial Comments at 4-5; NESCOE Initial Comments
at 32; NextEra Initial Comments at 65; PIOs Initial Comments at 22-
23; PJM Initial Comments at 73-74; US Climate Alliance Initial
Comments at 2; US DOE Initial Comments at 15; Utah Division of
Public Utilities Initial Comments at 5-6; Western PIOs Initial
Comments at 33.
\1259\ See supra Types of Long-Term Scenarios section.
---------------------------------------------------------------------------
[[Page 49376]]
6. Sensitivities for High-Impact, Low-Frequency Events
a. NOPR Proposal
578. In the NOPR, the Commission proposed to require that at least
one of the four distinct Long-Term Scenarios that transmission
providers in each transmission planning region use in Long-Term
Regional Transmission Planning account for uncertain operational
outcomes that determine the benefits of or need for transmission
facilities during high-impact, low-frequency events. The Commission
proposed to allow transmission providers the flexibility to determine
which high-impact, low-frequency event should be modeled in this Long-
Term Scenario as part of Long-Term Regional Transmission Planning based
on the Commission's understanding that each transmission planning
region may see a need to evaluate a different type of high-impact, low-
frequency event. The Commission stated that high-impact, low-frequency
events may include extreme weather events or events associated with
potential cyber-attacks. The Commission explained that this Long-Term
Scenario accounting for a high-impact, low-frequency event can be
developed, for example, by assuming greater-than-expected electricity
demand and greater-than-expected generation or transmission outages.
The Commission proposed that the use of either probabilistic
transmission planning \1260\ or stochastic techniques would be
sufficient to satisfy this requirement, but it did not propose to
require either approach at this time.\1261\
---------------------------------------------------------------------------
\1260\ NOPR, 179 FERC ] 61,028 at P 124. The Commission stated
that it considers probabilistic transmission planning approaches to
include any transmission planning approach that uses a probability
distribution to assign probabilities to one or more inputs to the
transmission model. The Commission stated that these inputs can
include shorter-term operational inputs (like wind generation or
generation outages). The Commission described stochastic techniques
as including adaptive transmission planning techniques that identify
transmission facilities that optimize transmission net-benefits over
a time horizon under market and regulatory uncertainty about the
future. Id. P 124 n.228.
\1261\ Id. P 124.
---------------------------------------------------------------------------
579. The Commission noted that transmission providers can develop
sensitivities for every Long-Term Scenario to assess how outcomes
modeled in Long-Term Scenarios may depend on an assumption about
electric power system model inputs that does not vary across scenarios
(e.g., higher natural gas prices). The Commission explained that such
sensitivities can provide valuable information about the need for and
benefits of potential transmission facilities, but also noted that they
can be burdensome to develop if applied to every scenario.\1262\
---------------------------------------------------------------------------
\1262\ Id. P 125.
---------------------------------------------------------------------------
b. Comments
580. Some commenters support the NOPR proposal to require one Long-
Term Scenario to account for uncertain operational outcomes that
determine the benefits of or need for transmission facilities during
high-impact, low-frequency events as part of Long-Term Regional
Transmission Planning.\1263\ Ameren states that the inclusion of such
events in Long-Term Regional Transmission Planning would provide
additional information for transmission providers, stakeholders, state
regulators, and others to consider when determining the need for
regional transmission facilities.\1264\ According to Arizona
Commission, including such a scenario, and giving the transmission
provider the discretion to determine what this should be for its
region, may provide the added benefit of allowing state involvement in
identifying the appropriate ``high-impact'' event to be analyzed.
Arizona Commission additionally asserts that the Commission should
require transmission providers to develop sensitivities for each Long-
Term Scenario to better understand the range of benefits under each
scenario.\1265\
---------------------------------------------------------------------------
\1263\ Ameren Initial Comments at 13; Arizona Commission Initial
Comments at 6; California Commission Initial Comments at 24;
Evergreen Action Initial Comments at 4; Eversource Initial Comments
at 18; Grid United Initial Comments at 4; New England for Offshore
Wind Initial Comments at 2; Pacific Northwest State Agencies Initial
Comments at 14; US DOE Initial Comments at 15.
\1264\ Ameren Initial Comments at 13-14.
\1265\ Arizona Commission Initial Comments at 6-7.
---------------------------------------------------------------------------
581. Eversource supports the NOPR proposal given the increasing
threat of extreme weather events and potential cyber-attacks.\1266\
Similarly, Illinois Commission states that the inclusion of high-
impact, low-frequency events in the transmission planning process is
reasonable and should include cyber-security attacks and extreme
weather events to strengthen the system's resilience.\1267\ New England
for Offshore Wind argues that it is prudent for the Commission to
require transmission providers to develop at least one high-impact,
low-frequency scenario due to the increased likelihood of extreme
weather events due to climate change.\1268\ SoCal Edison states that
incorporating probabilistic assumptions about extreme weather in Long-
Term Scenarios would be a reasonable, proactive approach to mitigate
the impacts of extreme weather when it occurs.\1269\
---------------------------------------------------------------------------
\1266\ Eversource Initial Comments at 18.
\1267\ Illinois Commission Initial Comments at 6.
\1268\ New England for Offshore Wind Initial Comments at 2.
\1269\ SoCal Edison Initial Comments at 12.
---------------------------------------------------------------------------
582. Likewise, Cypress Creek, City of New Orleans Council, DC and
MD Offices of People's Counsel, and PIOs support the inclusion of
extreme weather events in Long-Term Scenarios.\1270\ Business Council
for Sustainable Energy contends that Long-Term Scenarios must account
for the increase in significant climate events, acknowledging that the
most salient events to assess may vary regionally.\1271\ US DOE asserts
that regional transmission planning should consider the effects of
extreme events, including extreme weather events, on the availability
and reliability of the transmission system.\1272\ WE ACT comments that
requiring transmission providers to consider extreme weather events in
Long-Term Regional Transmission Planning is a positive step towards
addressing grid reliability in the face of more frequent and
intensifying weather events brought on by the climate crisis.\1273\
---------------------------------------------------------------------------
\1270\ City of New Orleans Council Initial Comments at 8;
Cypress Creek Reply Comments at 5-6; DC and MD Offices of People's
Counsel Reply Comments at 6; PIOs Reply Comments at 10; see also RMI
Supplemental Comments at 2; Senator Whitehouse Supplemental Comments
at 2-3.
\1271\ Business Council for Sustainable Energy Initial Comments
at 4.
\1272\ US DOE Initial Comments at 5.
\1273\ WE ACT Initial Comments at 2.
---------------------------------------------------------------------------
583. Other commenters express more general support for the study of
high-impact, low-frequency events in Long-Term Regional Transmission
Planning.\1274\ Clean Energy Associations emphasize that no scenario or
sensitivity should assume that historical operating conditions will
persist given the unpredictable and increasing impact of climate
change.\1275\ Grid United states that high-impact, low-frequency
scenarios should not be considered ``black swan'' events since they
occur on a regular, but low-frequency, basis. Moreover, Grid United
asks that the Commission define or provide examples of high-impact,
low-frequency events that transmission providers could incorporate into
Long-Term Scenarios to
[[Page 49377]]
provide clarity and consistency across transmission planning
regions.\1276\
---------------------------------------------------------------------------
\1274\ See Business Council for Sustainable Energy Initial
Comments at 4; Clean Energy Associations Initial Comments at 12;
Evergreen Action Initial Comments at 3-4; Grid United Initial
Comments at 4-5; NARUC Initial Comments at 11-12; NASUCA Initial
Comments at 4-5; NESCOE Initial Comments at 32-33; NRECA Initial
Comments at 35-36; Pattern Energy Initial Comments at 25; SoCal
Edison Initial Comments at 12.
\1275\ Clean Energy Associations Initial Comments at 12.
\1276\ Grid United Initial Comments at 5.
---------------------------------------------------------------------------
584. NARUC does not oppose the requirement that one of the Long-
Term Scenarios account for high-impact, low-frequency events but notes
that states' input is important when developing such scenarios.\1277\
Pattern Energy states that, with respect to low-probability, high-risk
event scenarios, the Commission should: (1) require the North American
Electric Reliability Corporation and the Regional Entities to develop
the scope of low-probability, high-risk events for each region of the
country and then (2) require transmission providers to model at least
one of the events in a rotation of the three-year review of the 20-year
plans to identify vulnerabilities that can be addressed through
transmission solutions that increase resilience.\1278\ Vermont Electric
and Vermont Transco request clarity on what scenarios the Commission
would consider sufficiently high-impact to be analyzed but not so high-
impact as to be unable to be mitigated by effective Long-Term Regional
Transmission Planning.\1279\
---------------------------------------------------------------------------
\1277\ NARUC Initial Comments at 11-12.
\1278\ Pattern Energy Initial Comments at 25.
\1279\ Vermont Electric and Vermont Transco Initial Comments at
3.
---------------------------------------------------------------------------
585. Some commenters support the Commission's proposal to permit
transmission providers to model high-impact, low-frequency events via
probabilistic or stochastic methods.\1280\ PJM states that it will
sometimes use probabilistically-derived parameters and sometimes use
deterministically-derived parameters in its Long-Term Scenarios,
depending on which is more appropriate.\1281\ Policy Integrity asserts
that the Commission should ensure the use of modeling techniques that
address uncertainty, such as stochastic programming and robust
optimization models.\1282\ Policy Integrity argues that modeling that
fails to consider uncertainties that arise from various factors could
reduce the cost-efficacy and efficiency of results and, ultimately,
result in unjust and unreasonable rates.\1283\ Policy Integrity cites
the European Network of Transmission System Operators' consideration of
the interactions between gas and electric systems as an example of best
practices for choosing scenarios.\1284\
---------------------------------------------------------------------------
\1280\ California Commission Initial Comments at 24-25;
Eversource Initial Comments at 18; PJM Initial Comments at 74-75.
\1281\ PJM Initial Comments at 75.
\1282\ Policy Integrity Initial Comments at 7.
\1283\ Id. at 6.
\1284\ Id. at 9 (citing European Commission, Key Cross Border
Infrastructure Projects, https://perma.cc/4U6X-Q2WN (last visited
Aug. 9, 2022)).
---------------------------------------------------------------------------
586. Some commenters provided views on the Commission's proposal to
require transmission providers to develop sensitivities for each Long-
Term Scenario.\1285\ Business Council for Sustainable Energy states
that it is important that scenario planning cover a range of
sensitivities, and that the long-term needs of the transmission system
as well as long-term policy goals should be incorporated.\1286\ NERC
states that studies could more adequately study various sensitivities
and extreme conditions (e.g., extreme weather) to ensure a reliable,
resilient, and secure bulk power system on a longer time horizon, which
could, in turn, help inform transmission expansion plans particularly
related to the changing resource mix.\1287\
---------------------------------------------------------------------------
\1285\ Business Council for Sustainable Energy Initial Comments
at 4; NERC Initial Comments at 7; Exelon Initial Comments 7 & n.7;
GridLab Initial Comments at 17-19; Idaho Power Initial Comments at
5; Minnesota State Entities Initial Comments at 5; NYISO Initial
Comments at 26; PIOs Initial Comments at 23-24; Policy Integrity
Initial Comments at 14-16; PPL Initial Comments at 9; R Street
Initial Comments at 6; US DOE Initial Comments at 15-16.
\1286\ Business Council for Sustainable Energy Initial Comments
at 4.
\1287\ NERC Initial Comments at 7.
---------------------------------------------------------------------------
587. GridLab recommends that the Commission provide a high-level
requirement and guidance on what kinds of factors are more effectively
considered in scenario versus sensitivity analysis and how sensitivity
analysis might be used in tandem with scenario analysis.\1288\ Policy
Integrity states that, instead of mandating only a minimum number of
Long-Term Scenarios, the Commission should also require sensitivity
analysis of critical drivers of transmission needs.\1289\ In addition,
Policy Integrity recommends that the Commission require transmission
providers to run a sensitivity for each Long-Term Scenario using a 30-
year transmission planning horizon and compare the results with those
from the analysis of each Long-Term Scenario using a 20-year
transmission planning horizon.\1290\ PIOs state that the Commission
should specify that, if any critical variable (e.g., natural gas
prices, capital costs of wind and solar, short and long duration
storage, and carbon capture and sequestration) is the same in more than
two Long-Term Scenarios, then transmission providers must conduct
sensitivities that use different values for that variable.\1291\
---------------------------------------------------------------------------
\1288\ GridLab Initial Comments at 17-18.
\1289\ Policy Integrity Initial Comments at 15.
\1290\ Id. at 10-11.
\1291\ PIOs Initial Comments at 23-24.
---------------------------------------------------------------------------
588. Although NRECA does not oppose the proposal that at least one
Long-Term Scenario account for high-impact, low-frequency events from
extreme weather, NRECA states that the Commission should not require
any Long-Term Scenarios to account for possible cyber-attacks. NRECA
asserts that modeling cyber-attacks and their effects would be
extraordinarily complex and risk disclosure of non-public Critical
Electric Infrastructure Information (CEII) and that such risks are
better addressed in North American Electric Reliability Corporation
standards development, noting that cyber-attacks may already be
evaluated under North American Electric Reliability Corporation
Transmission Planning Reliability Standard TPL-001-4.\1292\
---------------------------------------------------------------------------
\1292\ NRECA Initial Comments at 35-36 (citing GDS Associates,
Report, at 13 (Aug. 17, 2022); NERC Reliability Standard TPL-001-4,
Table 1--Steady State, https://www.nerc.com/pa/Stand/Reliability%20Standards/TPL-001-4.pdf).
---------------------------------------------------------------------------
589. Some commenters oppose requiring one Long-Term Scenario for
uncertain operational outcomes that determine the benefits of or need
for transmission facilities during high-impact, low-frequency
events.\1293\ LADWP asserts that a more meaningful measure of benefits
or needs associated with high-impact, low-frequency events may be a
periodic examination of the impacts of large-scale single points of
failures.\1294\ US Chamber of Commerce argues against requiring a Long-
Term Scenario for high-impact, low-frequency events because, it
asserts, the scope and impacts of such events on the transmission
system can be infinite in number.\1295\
---------------------------------------------------------------------------
\1293\ LADWP Initial Comments at 3; MISO Initial Comments at 27-
28, 38-39; Mississippi Commission Reply Comments at 6; OMS Initial
Comments at 6; US Chamber of Commerce Initial Comments at 7.
\1294\ LADWP Initial Comments at 3.
\1295\ US Chamber of Commerce Initial Comments at 7.
---------------------------------------------------------------------------
590. MISO argues that, although the impacts of large-scale
generation loss events associated with extreme weather events should be
considered in Long-Term Regional Transmission Planning, the Commission
should consider requiring analysis or sensitivities of extreme events
that are focused on the times or snapshots when the system is
potentially impacted by those events instead of requiring a separate
extreme event scenario.\1296\ MISO further argues that the Commission
should not require a specific number or type of sensitivities, which
can vary over time, but instead transmission providers should have
flexibility to assess the appropriate sensitivities needed to test
scenarios and results at the time those
[[Page 49378]]
are being developed.\1297\ Similarly, OMS argues that analyzing system
performance during extreme weather for all Long-Term Scenarios would
result in a better understanding of the benefits of transmission and
ensure reliability regardless of future changes in generation and/or
load.\1298\ PIOs likewise recommend that the Commission require that
transmission providers model extreme weather events as sensitivities in
each Long-Term Scenario and, specifically, that they model at least
extreme heat or cold over geographic areas that are experiencing these
extremes.\1299\
---------------------------------------------------------------------------
\1296\ MISO Initial Comments at 27-28.
\1297\ Id. at 39.
\1298\ OMS Initial Comments at 6.
\1299\ PIOs Initial Comments at 21.
---------------------------------------------------------------------------
591. NESCOE states that it supports the study of high-impact, low-
frequency events; however, NESCOE argues that the proposal raises
questions about whether codifying such a requirement blurs the line
between public policy planning and reliability planning, contrary to
the NOPR's contention that none of the proposals seek to alter the
reliability planning process. NESCOE contends that making the study of
high-impact, low-frequency events discretionary instead of mandatory
under Long-Term Regional Transmission Planning would avoid such
tension.\1300\ Mississippi Commission states that the Commission should
not mandate that transmission planning attempt to predict extreme
weather events and over-build the system, because ``predicting where
the next hurricane or tornado will land is speculative.'' Mississippi
Commission argues that a better approach is to incorporate construction
standards (e.g., North American Electric Reliability Corporation, IEEE,
local reliability criteria) designed to withstand such events.\1301\
---------------------------------------------------------------------------
\1300\ NESCOE Initial Comments at 32-33.
\1301\ Mississippi Commission Reply Comments at 6.
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592. Idaho Power raises concerns that developing multiple
sensitivities for multiple Long-Term Scenarios over a long-term
transmission planning horizon introduces too many variables.\1302\
Minnesota State Entities state that defining specific methods in the
final order--such as the difference between a ``sensitivity'' and what
is included in a ``scenario''--can be unnecessarily confusing and
complex.\1303\ US DOE encourages transmission providers to perform
sensitivity analyses but states that the Commission should only require
that one Long-Term Scenario analyze high-impact, low-frequency
events.\1304\
---------------------------------------------------------------------------
\1302\ Idaho Power Initial Comments at 5.
\1303\ Minnesota State Entities Initial Comments at 5.
\1304\ US DOE Initial Comments at 16.
---------------------------------------------------------------------------
c. Commission Determination
593. We modify the NOPR proposal to require transmission providers
in each transmission planning region to develop at least one
sensitivity, applied to each Long-Term Scenario, to account for
uncertain operational outcomes that determine the benefits of and/or
need for transmission facilities during multiple concurrent and
sustained generation and/or transmission outages due to an extreme
weather event across a wide area.\1305\ As discussed below, we
acknowledge support in the record for studying high-impact, low-
frequency events as proposed in the NOPR \1306\ but also recognize that
requiring a fourth Long-Term Scenario might be a burdensome way to
study such events as compared to a sensitivity.\1307\ We find that more
clearly defining the type of system conditions that transmission
providers must model to account for uncertain operational outcomes--in
particular, multiple concurrent and sustained generation and/or
transmission outages due to an extreme weather event across a wide
area--compared to the NOPR proposal, will enable transmission providers
to better account for periods when regional transmission facilities may
have particularly high value by decreasing the risk of loss of load
and/or decreasing the cost to reliably serve load.
---------------------------------------------------------------------------
\1305\ The Commission proposed in the NOPR to require that at
least one of four Long-Term Scenarios account for uncertain
operational outcomes that determine the benefits of or need for
transmission facilities during high-impact, low-frequency events.
NOPR, 179 FERC ] 61,028 at P 124.
\1306\ See, e.g., New England for Offshore Wind Initial Comments
at 2; see also Arizona Commission Initial Comments at 6-7. We also
note that the Commission has previously discussed that ``[e]xtreme
heat and cold weather events have occurred with greater frequency in
recent years, and are projected to occur with even greater frequency
in the future.'' Order No. 896, 183 FERC ] 61,191 at P 2.
\1307\ See, e.g., MISO Initial comments at 27.
---------------------------------------------------------------------------
594. Therefore, we require that, after developing at least three
Long-Term Scenarios, transmission providers develop a sensitivity for
each of the Long-Term Scenarios.\1308\ We provide transmission
providers with flexibility to conduct this sensitivity either before or
after identifying potential regional transmission solutions to the
Long-Term Transmission Needs identified using those Long-Term
Scenarios. Conducting this sensitivity before identifying potential
regional transmission solutions can be useful because it may help
transmission providers to identify such solutions. On the other hand,
conducting this sensitivity after identifying potential regional
transmission solutions to Long-Term Transmission Needs would allow
transmission providers to engage in efforts to develop additional or
alternative regional transmission solutions to address such conditions.
---------------------------------------------------------------------------
\1308\ See NOPR, 179 FERC ] 61,028 at P 125 n.229. A sensitivity
represents a single assumption about a short-term input or factor
(some input with a value that may change throughout a day or year).
A scenario represents an assumption about a longer-term input or
factor (e.g., resource retirements and additions or public
policies).
---------------------------------------------------------------------------
595. In conducting this sensitivity, transmission providers change
the data inputs of the underlying Long-Term Scenarios--in terms of
load, generation, generator outages, and transmission outages--to
account for uncertain operational outcomes that determine the benefits
of or need for regional transmission facilities during multiple
concurrent and sustained generation and/or transmission outages due to
an extreme weather event across a wide area, while maintaining the
underlying longer-term determinants of the Long-Term Scenario (e.g.,
the installed capacity of each generation resource). The sensitivity
can be thought of as a ``stress test'' for all Long-Term Scenarios.
596. We find it necessary to require the consideration of a more
narrowly defined set of conditions, as compared to the broader high-
impact, low-frequency event conditions described in the NOPR, to
include multiple concurrent and sustained generation and/or
transmission outages due to an extreme weather event across a wide
area.\1309\ Extreme weather events have occurred more frequently in
recent years,\1310\ are periods when regional transmission facilities
have particularly high value,\1311\ and create system conditions that
transmission providers can readily specify compared to contingencies
with an unknown root cause.\1312\ During these extreme weather
[[Page 49379]]
events, generation and transmission outages can be widespread, occur at
the same time, and persist due to a common cause like freezing
temperatures or limited fuel availability. This more narrowly defined
set of conditions also gives transmission providers more direct
guidance on how to comply with the requirements of this final
order.\1313\
---------------------------------------------------------------------------
\1309\ See, e.g., Grid United Initial Comments at 4-5 (stating
that ``the Commission should define or provide examples of the low-
frequency, high impact events that it would like to be considered
for planning purposes'').
\1310\ See supra The Overall Need for Reform section; see also
NOPR, 179 FERC ] 61,028 at P 45; Breakthrough Energy Initial
Comments at 8.
\1311\ See ACEG Initial Comments at 5; PIOs Initial Comments at
21; US DOE Initial Comments at 5-6.
\1312\ In terms of specifying the system conditions during
extreme weather events, transmission providers can, for example,
look at previous severe cold weather events to identify how load
might increase, how load and generation forecasts might be
incorrect, and how generation and transmission outages might occur
during a future extreme weather event.
\1313\ See, e.g., Grid United Initial Comments at 4-5.
---------------------------------------------------------------------------
597. Although we are only requiring that one sensitivity analysis
specific to extreme weather events be applied to each Long-Term
Scenario to comply with this final order, we do not preclude
transmission providers from considering additional sensitivities. We
recognize that transmission providers may consider several other
sensitivities as important and helpful in evaluating the benefits of
and need for Long-Term Regional Transmission Facilities. For example,
transmission providers can develop sensitivities to account for a
cyber-attack, significant forecast error, or fuel price volatility. We
encourage transmission providers to assess the need to develop other
sensitivities as part of Long-Term Regional Transmission Planning.
598. We find that modeling extreme weather events as sensitivities
is appropriate for Long-Term Regional Transmission Planning. We first
note that extreme weather events can occur under any assumed future
scenario but do not, by themselves, represent changes in the way that
factors are used in Long-Term Scenarios to determine Long-Term
Transmission Needs.\1314\ Therefore, we believe that applying a
sensitivity to each Long-Term Scenario is a more accurate way to
evaluate the effects of high-impact, low-frequency events than
considering such events in a distinct Long-Term Scenario. Second,
although there is a burden associated with conducting sensitivities,
the overall burden of conducting a sensitivity analysis is
comparatively lower than that of developing a new, separate Long-Term
Scenario. This is because sensitivities will be conducted using the
existing Long-Term Scenarios, where most inputs, and the factors and
assumptions used to develop the scenarios, have already been
established and mapped. Adjusting a set of existing inputs to test the
impact of the changes on a Long-Term Scenario through a sensitivity
analysis is therefore less burdensome than developing an entirely new
Long-Term Scenario.
---------------------------------------------------------------------------
\1314\ See MISO Initial Comments at 27-28; OMS Initial Comments
at 6.
---------------------------------------------------------------------------
599. In addition, we highlight that transmission providers can use
the required sensitivity analyses to evaluate the need for, or benefits
of, increased Interregional Transfer Capability provided by candidate
Long-Term Regional Transmission Facilities. We recognize that certain
Long-Term Regional Transmission Facilities could increase Interregional
Transfer Capability by changing the topology of the transmission
system, even if the specific transmission facility is not directly
connected to a neighboring transmission planning region's transmission
system. We believe that an increase in Interregional Transfer
Capability could provide significant benefits during extreme weather
events that result in multiple concurrent and sustained generation and/
or transmission outages.\1315\ We note that several commenters discuss
the need for greater Interregional Transfer Capability because of
extreme weather events\1316\ and the importance of modeling extreme
weather event conditions to capture the benefits of regional
transmission facilities.\1317\ As discussed in the Evaluation of the
Benefits of Regional Transmission Facilities section below, we require
transmission providers to consider increased Interregional Transfer
Capability provided by a Long-Term Regional Transmission Facility when
measuring Benefit 6.\1318\ We believe that transmission providers can
evaluate Benefit 6, including reduced loss of load and reduced
production costs during extreme weather events that result in multiple
concurrent and sustained generation and/or transmission outages, using
this required sensitivity, among other sensitivities that transmission
providers may develop to capture extreme events and system
contingencies.
---------------------------------------------------------------------------
\1315\ See, e.g., Order No. 896, 183 FERC ] 61,191 at PP 85-88.
\1316\ BP Initial Comments at 10; Breakthrough Energy Initial
Comments at 2; Kansas Commission Initial Comments at 8-9; NARUC
Initial Comments at 23; US DOE Initial Comments at 39-42; see also
ELCON Initial Comments at 8 (arguing Interregional Transfer
Capability should be a driver of transmission needs); PJM Initial
Comments at 66-67.
\1317\ See ACEG Initial Comments at 5; PIOs Initial Comments at
21; US DOE Initial Comments at 5-6.
\1318\ See infra Evaluation of the Benefits of Regional
Transmission Facilities, Required Benefits, Benefit 6: Mitigation of
Extreme Weather Events and Unexpected System Conditions section.
---------------------------------------------------------------------------
600. We disagree with NESCOE's concern that a requirement to study
the impact of high-impact, low-frequency events might ``blur[] the line
between public policy planning and reliability planning.'' \1319\
Rather, as discussed below in the Evaluation of the Benefits of
Regional Transmission Facilities section, we believe that the
requirement complements Benefit 6 (Mitigation of Extreme Weather Events
and Unexpected System Conditions) given the high probability that
extreme weather events will cause unplanned transmission outages and
the likelihood that such events will continue to occur at regular
intervals.\1320\ Although this final order requires a more
comprehensive consideration of benefits, it does not alter Order No.
1000's requirements for transmission providers to create a regional
transmission plan that will identify transmission facilities that more
efficiently or cost-effectively meet the transmission planning region's
reliability and economic requirements.
---------------------------------------------------------------------------
\1319\ NESCOE Initial Comments at 33.
\1320\ See infra Evaluation of the Benefits of Regional
Transmission Facilities, Required Benefits, Benefit 6: Mitigation of
Extreme Weather Events and Unexpected System Conditions section.
---------------------------------------------------------------------------
601. We also acknowledge LADWP's concern that a more meaningful
measure of benefits or needs associated with high-impact, low-frequency
events may be a periodic examination of the impacts of large-scale
single point failure.\1321\ Although we do not preclude transmission
providers from conducting such a study, such a study would not meet the
final order's requirement to conduct a sensitivity, applied to each
Long-Term Scenario, to account for uncertain operational outcomes that
determine the benefits of and/or need for transmission facilities
during multiple concurrent and sustained generation and/or transmission
outages due to an extreme weather event across a wide area.
---------------------------------------------------------------------------
\1321\ LADWP Initial Comments at 3.
---------------------------------------------------------------------------
7. Specificity of Data Inputs
a. NOPR Proposal
602. In the NOPR, the Commission proposed to require transmission
providers in each transmission planning region to use ``best available
data inputs'' when developing Long-Term Scenarios.\1322\ The Commission
stated that, by ``best available,'' the Commission did not imply that
there is a single ``best'' value for each data input that transmission
providers must use, but rather that best practices are used to develop
that data input.\1323\
---------------------------------------------------------------------------
\1322\ NOPR, 179 FERC ] 61,028 at PP 130-134.
\1323\ Id. P 130.
---------------------------------------------------------------------------
603. The Commission proposed to define ``best available data
inputs'' as data inputs that are timely and developed using diverse and
expert perspectives, adopted via a process that satisfies the Order
Nos. 890 and 1000 transparency transmission planning principles
described above, and reflect
[[Page 49380]]
the list of factors that transmission providers must incorporate into
Long-Term Scenarios.\1324\ The Commission explained that an example of
data inputs that could meet this requirement are the long-term load
forecasts of demand that RTOs/ISOs currently use for predicting long-
term resource adequacy. The Commission stated that another example of
data inputs that could meet this requirement are the most recent data
on renewable energy potential and distributed energy resources
developed by national labs.\1325\
---------------------------------------------------------------------------
\1324\ Id. P 131.
\1325\ Id. P 131 n.247.
---------------------------------------------------------------------------
604. The Commission proposed to require transmission providers in
each transmission planning region to update all data inputs each time
they reassess and revise, as necessary, their Long-Term Scenarios,
which, as explained in the NOPR, the Commission proposed to require
that they do at least every three years. As indicated in the Long-Term
Regional Transmission Planning section of the NOPR,\1326\ the
Commission also proposed to require that the Order Nos. 890 and 1000
transmission planning principles apply to the process through which
transmission providers determine which data inputs to use in their
Long-Term Scenarios. For example, consistent with the coordination
transmission planning principle established in Order No. 890, the
Commission proposed to require that transmission providers in each
transmission planning region give stakeholders the opportunity to
provide timely and meaningful input concerning which data inputs to use
in Long-Term Scenarios.\1327\
---------------------------------------------------------------------------
\1326\ Id. PP 64-67.
\1327\ Id. P 132.
---------------------------------------------------------------------------
605. The Commission preliminarily found that a requirement to use
the best available data inputs was necessary to ensure that
transmission providers are regularly updating data inputs and then
using timely and accurate data inputs to inform Long-Term Scenarios.
The Commission stated that data inputs can drive the results of Long-
Term Regional Transmission Planning. As a result, the Commission
explained that data inputs can directly affect which transmission
facilities may be selected and, in turn, Commission-jurisdictional
rates.\1328\
---------------------------------------------------------------------------
\1328\ Id. P 133.
---------------------------------------------------------------------------
b. Comments
i. Interest in Best Available Data Requirement
606. Many commenters generally support the NOPR proposal for ``best
available data,'' but some recommend that the Commission monitor data
inputs.\1329\ AEE states that it is not practical to make a more
prescriptive requirement for data inputs than the NOPR proposal and
recommends that the Commission be vigilant in monitoring data
inputs.\1330\ Policy Integrity states that the NOPR proposal is crucial
in protecting against strategic modeling behavior.\1331\ WATT Coalition
adds that ``best available data'' on future generation must be used
because demand and energy profiles are inherently uncertain.\1332\
---------------------------------------------------------------------------
\1329\ AEE Initial Comments at 23; Certain TDUs Initial Comments
at 16; Clean Energy Buyers Initial Comments at 17-18; DC and MD
Offices of People's Counsel Initial Comments at 14; Duke Initial
Comments at 16-17; Eversource Initial Comments at 20; Georgia
Commission Initial Comments at 5; ITC Initial Comments at 12; NARUC
Initial Comments at 13-15; NRECA Initial Comments at 35-36; OMS
Initial Comments at 5; [Oslash]rsted Initial Comments at 7; Pacific
Northwest State Agencies Initial Comments at 13-14; PJM Initial
Comments at 7, 76; Policy Integrity Initial Comments at 6; US DOE
Initial Comments at 16-17; WATT Coalition Initial Comments at 7.
\1330\ AEE Initial Comments at 23.
\1331\ Policy Integrity Initial Comments at 17.
\1332\ WATT Coalition Initial Comments at 7.
---------------------------------------------------------------------------
607. ACEG claims that the FPA supports the Commission's proposed
requirement to plan based on the best available data, noting that
section 217(b)(4) requires the Commission to exercise its authority
``in a manner that facilitates the planning and expansion of
transmission facilities to meet the reasonable needs of load-serving
entities to satisfy the service obligation of load-serving entities.''
\1333\ ACEG argues that load-serving entities' service obligations will
be more accurately predicted by the best available forecasting
methodologies.\1334\
---------------------------------------------------------------------------
\1333\ ACEG Initial Comments at 26-27 (citing 16 U.S.C.
824q(b)(4)).
\1334\ Id. at 27.
---------------------------------------------------------------------------
608. Clean Energy Buyers state that it is important to get
stakeholder input on data inputs, as has been done through MISO's Long-
Range Transmission Planning effort.\1335\ Breakthrough Energy states
that Long-Term Scenarios should use ``best available data.'' \1336\
---------------------------------------------------------------------------
\1335\ Clean Energy Buyers Initial Comments at 18.
\1336\ Breakthrough Energy Supplemental Comments at 1.
---------------------------------------------------------------------------
ii. Reservations with the Best Available Data Requirement
609. Several commenters support the NOPR proposal but nevertheless
have suggestions about how to modify the proposal.\1337\ For example,
several commenters request that the Commission create a common dataset,
publish a database of best available sources of data, or otherwise
standardize data inputs.\1338\ Southeast PIOs state that the Commission
should publish a regularly updated database of best available data
sources and require transmission providers to justify any decision not
to use that database, arguing that flexibility in project selection can
only work if the selection process utilizes reliable and standardized
inputs.\1339\ SEIA urges the Commission to issue standards or
guidelines that define what constitutes ``best available data inputs''
for each of the seven categories of factors.\1340\ R Street contends
that intraregional standardization could support internal consistency
and transparency and focus scarce stakeholder capital.\1341\
---------------------------------------------------------------------------
\1337\ ACEG Initial Comments at 7; ACORE Initial Comments at 8-
9; Eversource Initial Comments at 20-21; GridLab Initial Comments at
23; OMS Initial Comments at 5; Pine Gate Initial Comments at 27-29;
PIOs Initial Comments at 19-20; Policy Integrity Initial Comments at
6, 16-18; Southeast PIOs Initial Comments at 47-48.
\1338\ ACEG Initial Comments at 7; ACORE Initial Comments at 8-
9; GridLab Initial Comments at 23; PIOs Initial Comments at 19-20;
Southeast PIOs Initial Comments at 47-48.
\1339\ Southeast PIOs Initial Comments at 47.
\1340\ SEIA Initial Comments at 11; SEIA Reply Comments at 4.
\1341\ R Street Initial Comments at 7.
---------------------------------------------------------------------------
610. ELCON notes that, as part of the three-year reassessment of
Long-Term Scenarios, the Commission may decide that identifying or
standardizing data inputs and sources may help to ensure that
transmission providers are consistently using timely and widely
accepted data.\1342\ Interwest endorses US DOE's proposal in its
comments to the ANOPR to standardize data inputs.\1343\ ACORE states
that an identification of certain common data sets and modeling best
practices will reduce uncertainty, improve transparency, and achieve
greater consistency among transmission planning regions.\1344\
---------------------------------------------------------------------------
\1342\ ELCON Initial Comments at 13.
\1343\ Interwest Initial Comments at 8 (citing US DOE ANOPR
Initial Comments at 12-15).
\1344\ ACORE Reply Comments at 5.
---------------------------------------------------------------------------
611. ENGIE states that data inputs should be sourced from Federal
and state agencies whenever possible.\1345\ Renewable Northwest states
that determining a future resource mix for NorthernGrid is possible
with publicly available data.\1346\ GridLab states that the Commission
should consider whether to require that transmission providers either
use unadjusted, publicly available data in Long-Term Regional
Transmission Planning or justify why using proprietary data would
provide superior results.
---------------------------------------------------------------------------
\1345\ ENGIE Initial Comments at 3.
\1346\ Renewable Northwest Initial Comments at 17.
---------------------------------------------------------------------------
612. Several commenters state that it is not necessary for the
Commission to facilitate the development of data or
[[Page 49381]]
standardize inputs.\1347\ PPL, for example, asserts that the task of
developing data inputs should be left to transmission providers, with
the caveat that the entire process should avoid hindsight bias or an
inappropriate shift in burden or responsibility to the transmission
provider.\1348\ SPP states that the development of data inputs
facilitated by the Commission could provide value if implemented in a
way that does not create additional burden to the assessment. SPP
suggests that allowing access to recommended data sources or standard
information would provide an additional reference for transmission
providers to validate their own data, incorporate portions of the data,
or utilize all of the data, as appropriate.\1349\
---------------------------------------------------------------------------
\1347\ Ameren Initial Comments at 14-15; Idaho Power Initial
Comments at 5; NESCOE Initial Comments at 35-36; New York State
Department Initial Comments at 8-9; PPL Initial Comments at 10.
\1348\ PPL Initial Comments at 10.
\1349\ SPP Initial Comments at 11-12.
---------------------------------------------------------------------------
613. US Climate Alliance and US DOE support transparency
requirements for data inputs.\1350\ Similarly, California Commission
and NRECA support transparency requirements for data inputs, subject to
appropriate confidentiality considerations.\1351\ Colorado Consumer
Advocate contends that greater transparency and opportunities for
meaningful stakeholder input regarding data inputs for Long-Term
Regional Transmission Planning will improve the regional transmission
planning process and help to ensure that Order No. 890 transmission
planning principles are met.\1352\
---------------------------------------------------------------------------
\1350\ US Climate Alliance Initial Comments at 2; US DOE Initial
Comments at 17.
\1351\ California Commission Initial Comments at 25; NRECA
Initial Comments at 35-37 (citing GDS Associates, Report, at 13
(Aug. 17, 2022)).
\1352\ Colorado Consumer Advocate Initial Comments at 26.
---------------------------------------------------------------------------
614. Concerned Scientists state that the final order should require
transmission providers and load-serving entities to submit to the
relevant transmission planner an account of planned investments and
retirements over the transmission planning horizon because not doing so
ensures a transmission planning process that is less informed than it
can and should be. Concerned Scientists state that excluding these
minimum requirements from the final order will inevitably lead to the
exclusion of information needed by regulators, stakeholders, and the
transmission providers themselves to make informed investment
decisions.\1353\ PJM, which supports the NOPR proposal, states that,
while it is important to consider resource retirements when developing
planning assumptions, generation retirement forecasts may be
interpreted by stakeholders as sending economic signals concerning the
viability of existing generating units. Thus, PJM urges the Commission
to provide clear direction on how to balance the heightened
transparency and public processes proposed in the NOPR with appropriate
safeguards against releasing data that could preempt unit owner
economic decisions, as well as decisions by market participants.\1354\
---------------------------------------------------------------------------
\1353\ Concerned Scientists Reply Comments at 17.
\1354\ PJM Reply Comments at 22.
---------------------------------------------------------------------------
615. ITC, PJM, and SEIA support the NOPR proposal, and ITC and SEIA
agree with PJM's suggestion that the Commission hold regular forums,
workshops, or technical conferences to determine best practices in
developing best available data.\1355\
---------------------------------------------------------------------------
\1355\ ITC Initial Comments at 12; PJM Initial Comments at 76-
77; SEIA Initial Comments at 11; SEIA Reply Comments at 4-5.
---------------------------------------------------------------------------
616. SPP Market Monitor contends that the Commission should further
provide guidance in the form of parameters by which transmission
providers should define the phrase ``best available data,'' which SPP
Market Monitor argues would aid in ensuring that the Long-Term
Scenarios studied and transmission projects or facilities planned are
consistent and reasonable.\1356\ Relatedly, Pine Gate states that the
NOPR's failure to address source accuracy in the definition of best
available date inputs may introduce subjectivity into Long-Term
Regional Transmission Planning, obscure sources, and inhibit the
ability of stakeholders to meaningfully engage in the Long-Term
Regional Transmission Planning process. To remedy these concerns, Pine
Gate suggests that the Commission define ``best available data inputs''
as data inputs that: (1) are current and developed using diverse and
expert perspectives expressed during a stakeholder process; (2) have
identified sources; (3) are adopted via a process that satisfies Order
No. 890's transparency planning principle; and (4) reflect the list of
factors that transmission providers must incorporate into Long-Term
Scenarios.\1357\ Policy Integrity states that the Commission should
require external vetting of data inputs used by a party without a stake
in the outcomes.\1358\
---------------------------------------------------------------------------
\1356\ SPP Market Monitor Initial Comments at 8.
\1357\ Pine Gate Initial Comments at 28.
\1358\ Policy Integrity Initial Comments at 17-18.
---------------------------------------------------------------------------
617. Several commenters state that the final order should add a
requirement that data must be accurate.\1359\ ELCON notes that
utilities should consider whether a data source's historical
projections ultimately proved to be accurate when identifying ``best
available'' inputs, and Vermont Electric and Vermont Transco
agree.\1360\ Arizona Commission supports the use of relevant, timely,
and accurate data.\1361\
---------------------------------------------------------------------------
\1359\ ELCON Initial Comments at 13; LADWP Initial Comments at
4; Vermont Electric and Vermont Transco Initial Comments at 3.
\1360\ ELCON Initial Comments at 13; Vermont Electric and
Vermont Transco Initial Comments at 3.
\1361\ Arizona Commission Initial Comments at 7.
---------------------------------------------------------------------------
618. LADWP asserts that the determination of ``best available
data'' should be changed to ``the most accurate data inputs available''
at the time of study because ``best'' is subjective but ``most
accurate'' is clear and objective. LADWP states that, if data is
interpreted differently, as may be the case under the ``best
available'' standard, then results will be inconsistent. For example,
LADWP states that the ``most accurate data inputs available'' for load
inputs for near-term planning and for data for generation and energy
storage capacities would be data derived from projections based on
actual field measurements, and from in-service equipment (instead of
from manufacturing brochures or articles), respectively. LADWP states
that for new technologies, the projected availability and performance
parameters should be based on actual data when possible. For example,
LADWP states that data derived from field operating experience with
prototypes should be considered ``most accurate'' as compared to lab
test data. LADWP contends that transmission providers should be careful
not to take ``expert perspectives'' at face value, but should seek to
use data inputs that show a strong correlation to scientifically
verifiable facts. Furthermore, LADWP states, projected data based on
administrative law or executed interconnection agreements should be
considered more certain, and hence more accurate, than data based on
corporate or government goals.\1362\
---------------------------------------------------------------------------
\1362\ LADWP Initial Comments at 4.
---------------------------------------------------------------------------
619. GridLab recommends that the Commission request that the
national laboratories and other public agencies work with transmission
providers, resource developers, and others to evaluate the historical
accuracy of publicly available data sources.\1363\ However, Ameren sees
no reason to expand the definition of best available data inputs to
include an evaluation of data source entities' historical accuracy
identifying and projecting trends
[[Page 49382]]
because the open and transparent planning process of diverse
stakeholders will identify any questionable or non-reliable data
sources.\1364\
---------------------------------------------------------------------------
\1363\ GridLab Initial Comments at 24.
\1364\ Ameren Initial Comments at 15.
---------------------------------------------------------------------------
620. ELCON states that the Commission may need to clarify what data
is considered ``timely'' and argues, for example, that the Commission
should not establish a mandate in favor of using historical data (e.g.,
actual data from the previous 12 months) because such data may not
reflect current and future operational needs.\1365\ Pine Gate is
concerned that the use of the term ``timely'' in the definition of
``best available data inputs'' may lead to confusion and inconsistency
amongst transmission providers.\1366\
---------------------------------------------------------------------------
\1365\ ELCON Initial Comments at 13.
\1366\ Pine Gate Initial Comments at 28.
---------------------------------------------------------------------------
621. PJM Market Monitor states that both aggregate and very
specific locational data on future demand and the future resource mix
will be critical for efficient and cost-effective transmission
planning.\1367\
---------------------------------------------------------------------------
\1367\ PJM Market Monitor Initial Comments at 4.
---------------------------------------------------------------------------
iii. Concerns With Best Available Data
622. Several commenters either oppose the NOPR proposal or object
to specific aspects of the NOPR proposal.\1368\ Ameren, EEI, and PPL
state that the NOPR proposal is unnecessary and too prescriptive.\1369\
Idaho Commission agrees that it is too prescriptive.\1370\ EEI states
that, while using the best available data inputs when preparing the
Long-Term Scenarios is appropriate, a pro forma definition may not be
necessary.\1371\
---------------------------------------------------------------------------
\1368\ Ameren Initial Comments at 14-15; Dominion Initial
Comments at 26-28; EEI Initial Comments at 14; ELCON Initial
Comments at 13; Idaho Power Initial Comments at 5; LADWP Initial
Comments at 4; MISO Initial Comments at 40-41; MISO TOs Initial
Comments at 18-19; National Grid Initial Comments at 14; Nebraska
Commission Initial Comments at 6; NESCOE Initial Comments at 35-36;
PPL Initial Comments at 9-10; R Street Initial Comments at 7;
Vermont Electric and Vermont Transco Initial Comments at 3; Xcel
Initial Comments at 10.
\1369\ Ameren Initial Comments at 14-15; EEI Initial Comments at
14; PPL Initial Comments at 9.
\1370\ Idaho Commission Initial Comments at 3.
\1371\ EEI Initial Comments at 14.
---------------------------------------------------------------------------
623. PPL expresses concern that the proposed requirement for data
inputs will unnecessarily burden transmission providers by effectively
shifting a burden from data owners (who are in the best position to
control and ensure data accuracy) to the transmission provider and
instead recommends that the Commission strengthen the requirements
applicable to the data owners or data source entities.\1372\ Dominion
states that using best available data inputs should not be a
requirement because transmission providers should be permitted to
select the data inputs that are most appropriate for their own
situation, as they know their transmission systems best. Dominion
additionally does not support defining ``best available data inputs''
as proposed because it would limit transmission providers' flexibility
to conduct transmission planning that is most appropriate to their
unique system needs.\1373\
---------------------------------------------------------------------------
\1372\ PPL Initial Comments at 9-10.
\1373\ Dominion Initial Comments at 26-27.
---------------------------------------------------------------------------
624. MISO, Utah Division of Public Utilities, and Xcel state that
the NOPR proposal on data inputs is a potential source of
conflict.\1374\ MISO is concerned that parties opposing particular
long-range transmission planning outcomes could seize on the proposed
language and argue that some other data was the best available data,
thereby delaying the process; and the resulting disputes could
potentially slow down the transmission planning process and ultimately
delay much needed transmission.\1375\ Xcel agrees.\1376\ Utah Division
of Public Utilities attests that requiring transmission providers to
use the best data available is not based on evidence showing that data
inputs currently used by transmission providers have led to unjust or
discriminatory rates, and may produce unnecessary and time-consuming
disagreements among stakeholders regarding which data inputs to
use.\1377\ National Grid asserts that the term ``best available'' data
is vague and subjective, which introduces development, regulatory and
implementation inefficiencies.\1378\ Clean Energy Associations argue
that transmission providers should be required to explain the number
and the basis for including each input they choose to include.\1379\
---------------------------------------------------------------------------
\1374\ MISO Initial Comments at 29; Utah Division of Public
Utilities Initial Comments at 6; Xcel Initial Comments at 10.
\1375\ MISO Initial Comments at 40.
\1376\ Xcel Initial Comments at 10.
\1377\ Utah Division of Public Utilities Initial Comments at 6.
\1378\ National Grid Initial Comments at 14.
\1379\ Clean Energy Associations Initial Comments at 13.
---------------------------------------------------------------------------
iv. Flexibility Issues
625. Several commenters, some that support the NOPR proposal and
some that do not, call for flexibility in allowing transmission
providers to determine what constitutes best available data. ISO-NE and
NYISO support the NOPR proposal but request that the Commission provide
transmission providers with some flexibility about how to satisfy this
requirement.\1380\ ISO-NE asserts that the Commission should allow
flexibility for ISO-NE to rely on the states to determine the data
inputs, with its technical support and stakeholder input, and NESCOE,
which opposes the NOPR proposal, agrees.\1381\ NESCOE is concerned
about the prescriptive nature of the NOPR proposal and contends that
data inputs should be determined on a region-by-region basis by
transmission providers with input from states and stakeholders.\1382\
MISO agrees on both points.\1383\ Duke, which generally supports the
NOPR proposal to define best available data inputs and requirement to
follow a transparent process to develop the data inputs, states that
because there is not a single ``best'' value for each input, the
emphasis should be on best practices to develop the data inputs, which
should be left to the regions to develop with their specific
stakeholders.\1384\
---------------------------------------------------------------------------
\1380\ ISO-NE Initial Comments at 28; NYISO Initial Comments at
28.
\1381\ ISO-NE Initial Comments at 28; NESCOE Initial Comments at
35-36.
\1382\ NESCOE Initial Comments at 36.
\1383\ MISO Initial Comments at 40.
\1384\ Duke Initial Comments at 16-17.
---------------------------------------------------------------------------
626. In addition, NYISO requests that the Commission revise the
definition of best available data to permit flexibility on how it
reflects factors considered in the scenarios. Specifically, NYISO
requests that the language in the NOPR specifying that the data inputs
must ``reflect the list of factors that transmission providers must
incorporate into Long-Term Scenarios'' should be modified to ``reflect
the factors that the transmission provider considers in the scenarios''
to reflect the authority of transmission planning regions to identify
which factors should be used in Long-Term Scenarios. NYISO adds that
transmission providers should have authority over how to interpolate
and employ their data sets.\1385\
---------------------------------------------------------------------------
\1385\ NYISO Initial Comments at 28.
---------------------------------------------------------------------------
627. MISO, which opposes the NOPR proposal, contends that the
Commission should allow transmission providers to determine, in
consultation with its stakeholders, what data is most appropriate, but
require transmission providers to use the most up-to-date data from the
source that they select.\1386\ MISO recommends that, if the final order
includes the NOPR proposal for best available data, then the Commission
should clarify that transmission providers may satisfy the requirement
by using the most up-to-date data that they have selected and that
reflects practical limitations
[[Page 49383]]
regarding the precision and scope of the data.\1387\ MISO TOs suggest
that the Commission consider articulating principles and guidelines and
let transmission planning regions develop their own conception of
``best available data'' in the interest of flexibility.\1388\ Nevada
Commission states that the definition of ``best available data'' may
need further comment and will likely evolve as the Long-Term Regional
Transmission Planning process is implemented.\1389\
---------------------------------------------------------------------------
\1386\ MISO Initial Comments at 40.
\1387\ Id. at 29.
\1388\ MISO TOs Initial Comments at 19.
\1389\ Nevada Commission Initial Comments at 9.
---------------------------------------------------------------------------
628. National Grid requests that the Commission clarify that
transmission providers have final and sole responsibility and
discretion to determine what is ``best available data'' as transmission
providers are best situated to make these determinations in
consultation with their stakeholders. National Grid also seeks clarity
from the Commission as to what ``diverse'' means as it describes best
available data inputs. National Grid further asserts that the
Commission should distinguish between Long-Term Scenarios based on
diverse inputs in each scenario.\1390\
---------------------------------------------------------------------------
\1390\ National Grid Initial Comments at 14.
---------------------------------------------------------------------------
v. Best Sources of Data Issues
629. Several commenters, some that support the NOPR proposal and
some that do not, make suggestions about the best sources of data.
Several commenters state that transmission providers already have the
best available data.\1391\ Nebraska Commission further states that the
current methods used by RTOs/ISOs would meet the NOPR's proposed
requirements.\1392\ PPL states that transmission providers already use
a ``best available data inputs'' standard in transmission planning but
must rely on other entities' data.\1393\ EEI states that, if the
Commission adopts a definition for best available data, it should
acknowledge that transmission providers and load-serving entities often
may possess this data.\1394\
---------------------------------------------------------------------------
\1391\ EEI Initial Comments at 14; Nebraska Commission Initial
Comments at 6; PJM Initial Comments at 76; PPL Initial Comments at
9-10.
\1392\ Nebraska Commission Initial Comments at 6.
\1393\ PPL Initial Comments at 9-10.
\1394\ EEI Initial Comments at 14.
---------------------------------------------------------------------------
630. Several commenters state that load-serving entities have the
best available data.\1395\ Eversource recommends that the Commission
require the RTOs/ISOs to collaborate with the transmission owners
regarding transmission owners' forecast of load localized peak
times.\1396\ PIOs state that the Commission should require load-serving
entities to provide their generation and load forecasts to transmission
providers so that they have reasonable information to use and do not
have to perform their own estimates.\1397\ ACEG and Clean Energy
Associations agree.\1398\
---------------------------------------------------------------------------
\1395\ Id.; Eversource Initial Comments at 20; Xcel Initial
Comments at 10.
\1396\ Eversource Initial Comments at 20.
\1397\ PIOs Initial Comments at 19.
\1398\ ACEG Reply Comments at 23; Clean Energy Associations
Reply Comments at 7.
---------------------------------------------------------------------------
631. Western PIOs state that the Western Electricity Coordinating
Council databases on load and generation forecasts and the Western
Electricity Coordinating Council Anchor dataset constitute best
available data.\1399\ NARUC argues that any reasonable, credible source
of data should be allowed to supplement more traditional sources like
the national laboratories and RTO/ISO-generated data.\1400\ SREA
recommends that, to the extent possible, the Commission should
recognize the National Renewable Energy Lab's Annual Technology
Baseline (NREL ATB) as the Nation's preferred data set.\1401\ Policy
Integrity states that the Commission should urge transmission providers
to engage independent researchers in the process to ensure inclusion of
the latest modeling and computational developments.\1402\ PIOs state
that the Commission could publish a regularly updated list of databases
that meet the ``best available data requirement,'' such as the
following current databases: NREL ATB data, US DOE's Annual Energy
Outlook for fuel costs, and NREL's Electrification Futures Study for
electrification trends. PIOs suggests that the Commission could
additionally partner with the US DOE and National Laboratories to
develop appropriate databases.\1403\
---------------------------------------------------------------------------
\1399\ Western PIOs Initial Comments at 31.
\1400\ NARUC Initial Comments at 13.
\1401\ SREA Reply Comments at 26.
\1402\ Policy Integrity Initial Comments at 17.
\1403\ PIOs Initial Comments at 19.
---------------------------------------------------------------------------
632. Entergy asserts that integrated resource plans approved by
retail commissions should be considered the best available data, and
Louisiana Commission and Mississippi Commission agree.\1404\ However,
Kentucky Commission Chair Chandler disagrees with the propositions that
local data provided by a utility in an integrated resource plan is
superior to other data and that RTOs/ISOs should be required to rely on
such data.\1405\
---------------------------------------------------------------------------
\1404\ Entergy Initial Comments at 18; Louisiana Commission
Reply Comments at 7; Mississippi Commission Reply Comments at 9.
\1405\ Kentucky Commission Chair Chandler Reply Comments at 3.
---------------------------------------------------------------------------
c. Commission Determination
633. We adopt the NOPR proposal, with modification, to require
transmission providers in each transmission planning region to use
``best available data inputs'' when developing Long-Term Scenarios. As
the Commission explained in the NOPR, by ``best available,'' we do not
imply that there is a single ``best'' value for each data input that
transmission providers must use, but rather that best practices will be
used to develop each data input. We adopt, with modification, the NOPR
proposal to define ``best available data inputs'' as data inputs that
are timely, developed using best practices and diverse and expert
perspectives,\1406\ and adopted via a process that satisfies the
transmission planning principles of Order Nos. 890 and 1000.\1407\ We
further adopt the NOPR proposal to require that best available data
inputs also reflect the list of factors that transmission providers
account for in their Long-Term Scenarios.\1408\ By ``reflect the list
of factors,'' we mean the data inputs that correspond to the list of
factors that transmission providers have determined might affect Long-
Term Transmission Needs.\1409\ We also adopt the NOPR proposal to
require transmission providers to update, as necessary, all data inputs
each time they reassess and revise their Long-Term Scenarios.
---------------------------------------------------------------------------
\1406\ While we largely adopt the definition of ``best available
data inputs'' proposed in the NOPR, we modify it to reflect the
requirement that ``best available data inputs'' are developed using
best practices.
\1407\ For example, the transparency transmission planning
principle requires transmission providers to reduce to writing and
make available the basic methodology, criteria, and processes used
to develop transmission plans. Transmission providers must make
sufficient information available to enable customers and other
stakeholders to replicate the results of transmission planning
studies. Order No. 890, 118 FERC ] 61,119 at P 471. Order No. 1000
applied this and other Order No. 890 transmission planning
principles to regional transmission planning processes. Order No.
1000, 136 FERC ] 61,051 at P 151.
\1408\ One example of a data input dataset that would meet the
requirement for best available data are the long-term load forecasts
of demand that RTOs/ISOs currently use for predicting long-term
resource adequacy. Another example of a data input dataset that
would meet the requirement for best available data is the most
recent data on renewable energy potential and distributed energy
resources developed by national labs.
\1409\ For example, a transmission provider might determine that
corporate goals for corporations less than $20 million are too small
to affect Long-Term Transmission Needs and not include these
corporate goals in its Long-Term Scenarios. This transmission
provider does not have any obligation to develop data inputs
corresponding to these omitted corporate goals.
---------------------------------------------------------------------------
634. Finally, in addition, we adopt the NOPR proposal to require
that the Order Nos. 890 and 1000 transmission planning principles apply
to the process
[[Page 49384]]
through which transmission providers determine which data inputs to use
in their Long-Term Scenarios. Consistent with the coordination
transmission planning principle established in Order No. 890, we also
adopt the NOPR proposal to require transmission providers in each
transmission planning region to give stakeholders an opportunity to
provide timely and meaningful input during each Long-Term Regional
Transmission Planning cycle concerning which data inputs to use in
Long-Term Scenarios.\1410\ Also, we clarify that the right to challenge
data inputs via dispute resolution as discussed in Order No. 890 is
available for interested parties with respect to data inputs that
transmission providers develop for Long-Term Regional Transmission
Planning.\1411\
---------------------------------------------------------------------------
\1410\ NOPR, 179 FERC ] 61,028 at P 132.
\1411\ Order No. 890, 118 FERC ] 61,119 at PP 501-503.
---------------------------------------------------------------------------
635. We agree, in part, with NYISO's suggestion to revise the
wording of the NOPR proposal that required best available data to
reflect ``the list of factors that transmission providers must
incorporate into Long-Term Scenarios.'' \1412\ NYISO states that the
NOPR language should be modified to ``reflect the factors that the
public utility transmission provider considers in the scenarios.''
\1413\ As discussed in the Categories of Factors section of this final
order, we explain that transmission providers need not account for a
factor, stakeholder-identified or otherwise, if they determine that
factor is unlikely to affect Long-Term Transmission Needs. We find that
transmission providers must use best available data when determining
whether each factor is likely to affect Long-Term Transmission Needs.
Once transmission providers have determined that a factor is likely to
affect Long-Term Transmission Needs, they must use the best available
data when they then account for that factor in the development of Long-
Term Scenarios.
---------------------------------------------------------------------------
\1412\ NYISO Initial Comments at 28 (citing NOPR, 179 FERC ]
61,028 at P 131).
\1413\ Id.
---------------------------------------------------------------------------
636. We find that a requirement to use the best available data
inputs is warranted to ensure that transmission providers are regularly
updating data inputs and using timely and accurate data inputs to
inform Long-Term Scenarios. We further find that data inputs can drive
the results of Long-Term Regional Transmission Planning. As a result,
we find that data inputs affect transmission providers' ability to
identify Long-Term Transmission Needs and thus affect the ability to
identify, evaluate, and select Long-Term Regional Transmission
Facilities to more efficiently or cost-effectively address those needs.
We note that many commenters share this view and support the NOPR
proposal.\1414\
---------------------------------------------------------------------------
\1414\ ACORE Initial Comments at 8; AEE Initial Comments at 22;
Certain TDUs Initial Comments at 16; Clean Energy Buyers Initial
Comments at 17-18; DC and MD Offices of People's Counsel Initial
Comments at 14; Eversource Initial Comments at 20; Georgia
Commission Initial Comments at 5; ISO-NE Initial Comments at 28; ITC
Initial Comments at 12; Mississippi Commission Initial Comments at
34-35; NARUC Initial Comments at 13-15; NRECA Initial Comments at
36; OMS Initial Comments at 5; [Oslash]rsted Initial Comments at 7;
Pacific Northwest State Agencies Initial Comments at 13-14; PJM
Initial Comments at 7, 76; Policy Integrity Initial Comments at 16-
17; US DOE Initial Comments at 16-18; WATT Coalition Initial
Comments at 7.
---------------------------------------------------------------------------
637. We disagree with commenters asserting that the requirements
for data inputs would be overly burdensome to transmission
providers.\1415\ We believe that, because most transmission providers
already endeavor to use best available data inputs to ensure credible
results in regional transmission planning, this final order's
requirements for data inputs will not impose an unreasonable burden
beyond existing practices today. Further, as many commenters
note,\1416\ any increase in transmission providers' burden from such
requirements is outweighed by the benefits of establishing reasonable
safeguards for accuracy and confidence in Long-Term Regional
Transmission Planning.
---------------------------------------------------------------------------
\1415\ Ameren Initial Comments at 14; MISO Initial Comments at
29; PPL Initial Comments at 9-10; Utah Division of Public Utilities
Initial Comments at 7; Xcel Initial Comments at 10.
\1416\ See ACORE Initial Comments at 8; AEE Initial Comments at
23; Certain TDUs Initial Comments at 16; Clean Energy Buyers Initial
Comments at 17-18; DC and MD Offices of People's Counsel Initial
Comments at 14; Eversource Initial Comments at 20; Georgia
Commission Initial Comments at 5; ISO-NE Initial Comments at 28; ITC
Initial Comments at 12; Mississippi Commission Initial Comments at
34-35; NARUC Initial Comments at 13-15; NRECA Initial Comments at
36; OMS Initial Comments at 5; [Oslash]rsted Initial Comments at 7;
Pacific Northwest State Agencies Initial Comments at 13-14; PJM
Initial Comments at 7, 76; Policy Integrity Initial Comments at 16-
17; US DOE Initial Comments at 16-18; WATT Coalition Initial
Comments at 7.
---------------------------------------------------------------------------
638. We disagree with commenters' arguments that the final order
requirements for data inputs would lead to problems because
stakeholders will delay Long-Term Regional Transmission Planning by
contesting the data used by transmission providers.\1417\ Similarly, we
disagree with commenters' arguments that the requirements for data
inputs unnecessarily limit transmission providers' flexibility in
producing data inputs.\1418\ As discussed above, this final order
establishes requirements for data inputs used in Long-Term Scenarios
and requires that stakeholders have an opportunity to provide timely
and meaningful input during each Long-Term Regional Transmission
Planning cycle concerning those data inputs. However, transmission
providers have significant flexibility about which data inputs they use
in Long-Term Scenarios, and no commenters have provided us with
convincing or specific arguments that stakeholder input will undermine
that flexibility or cause consequential delays to the Long-Term
Regional Transmission Planning process.
---------------------------------------------------------------------------
\1417\ MISO Initial Comments at 29; Utah Division of Public
Utilities Initial Comments at 6; Xcel Initial Comments at 10.
\1418\ Dominion Initial Comments at 26-27; Duke Initial Comments
at 16-17; MISO Initial Comments at 40; MISO TOs Initial Comments at
19; NESCOE Initial Comments at 35-36.
---------------------------------------------------------------------------
639. We decline to adopt the suggestion of commenters to
standardize data inputs used by transmission providers in Long-Term
Regional Transmission Planning.\1419\ Imposing further requirements to
enforce uniformity in data is challenging given regional variation in
transmission planning approaches. Further, it might stifle innovation
that would improve Long-Term Regional Transmission Planning.
---------------------------------------------------------------------------
\1419\ ACEG Initial Comments at 7; ACORE Initial Comments at 8-
9; GridLab Initial Comments at 23; PIOs Initial Comments at 19-20;
Southeast PIOs Initial Comments at 47-48.
---------------------------------------------------------------------------
640. We decline to adopt the modifications of the NOPR proposal
suggested by certain commenters to establish specific accuracy
standards in addition to requiring that transmission providers use best
available data inputs.\1420\ While we agree that transmission providers
should strive for data accuracy, including by assessing the historical
accuracy of different data sources where appropriate, a specific
accuracy standard would be difficult to develop and administer given
the diversity of different data inputs.\1421\ As we explain above,
transmission providers must use best available data inputs, which
include forecasted data, and must develop such inputs using diverse and
expert perspectives. They must use best practices to develop data
inputs, and must do so in an open and transparent stakeholder process.
Taken together, we believe that these
[[Page 49385]]
requirements will help ensure that data inputs are as accurate as
possible, while also providing transmission providers with the
flexibility to use best practices to develop data inputs that are
appropriate for their transmission planning regions and to recognize
the inherent uncertainty involved in planning transmission on a
forward-looking basis.
---------------------------------------------------------------------------
\1420\ ELCON Initial Comments at 13; LADWP Initial Comments at
4; Pine Gate Initial Comments at 27-29; Vermont Electric and Vermont
Transco Initial Comments at 3.
\1421\ In addition, while we decline to adopt a specific
accuracy standard that data must meet in order to be ``best
available data,'' we note that a demonstration that a data source
has historically proven to be relatively inaccurate would likely
constitute evidence that such data is not best available data.
---------------------------------------------------------------------------
641. With respect to the issue raised by PJM about revealing
potentially confidential data to improve accuracy,\1422\ we reiterate,
as discussed above, that consistent with Order No. 890's transparency
transmission planning principle, transmission providers in each
transmission planning region are required to disclose (subject to
appropriate confidentiality protections) information and data inputs
they use to create each Long-Term Scenario.\1423\ The Commission has
recognized that tension exists between ensuring transparency in
transmission planning processes and protecting confidential
information, including commercially sensitive information.\1424\ The
Commission has also noted that using resource-specific data that best
reflect actual operations on the transmission system leads to more
precise and effective transmission study results. In addition, the
Commission has recognized that market participants who provide that
information need to be assured that the confidential information they
provide will be used for its intended purpose in planning the
transmission system and will not be disclosed in a manner that harms
them commercially. However, the Commission has found that, at the same
time, the requirement in Order No. 890 for transmission providers to
disclose to all customers and other stakeholders the basic methodology,
criteria, assumptions, and data that underlie their transmission system
plans to enable customers, other stakeholders, or an independent third-
party to replicate the results of planning studies is essential to an
open and transparent transmission planning process.\1425\ Thus, the
Commission has found that, without certain generator dispatch and
economic information, for example, it becomes difficult or impossible
to conduct meaningful load flow studies for some transmission planning
purposes,\1426\ and the competitive playing field is tilted toward
those who have this information and away from those who do not.\1427\
---------------------------------------------------------------------------
\1422\ PJM Reply Comments at 22.
\1423\ See supra Number and Development of Long-Term Scenarios
section.
\1424\ Sw. Power Pool, Inc., 137 FERC ] 61,227 at P 20.
\1425\ Order No. 890, 118 FERC ] 61,119 at P 471.
\1426\ Id. P 478.
\1427\ Sw. Power Pool, Inc., 137 FERC ] 61,227 at P 20.
---------------------------------------------------------------------------
642. The Commission therefore required in Order No. 890, and we
apply that requirement to Long-Term Regional Transmission Planning in
this final order, disclosure of the methodology, criteria, assumptions,
data and other information that underlie transmission plans, including
Long-Term Scenarios. We recognize that no bright line rule exists to
determine the appropriate balance between ensuring transparency in the
transmission planning processes and ensuring that confidential
information is not disclosed inappropriately. Transmission providers
may propose what they believe are appropriate confidentiality
protections in their filings to comply with this final order, and the
Commission will evaluate those proposals by using the established
principles in Order No. 890, as well as precedent on existing
confidentiality protections with respect to transmission planning that
the Commission has previously found comply with the Order No. 890
principles, to guide its findings on whether such protections are
appropriate.
643. With respect to the issue raised by ELCON and Pine Gate about
timely data,\1428\ we decline to adopt their suggestion to define
precisely what ``timely'' means with respect to best available data
because we believe flexibility is warranted given the diverse regional
transmission planning processes to which this reform will apply. That
is, we believe that updating data inputs may require different
timelines depending on the transmission planning region and the
specific data input, where each input may change on a different
timeline. However, given the five-year duration of the Long-Term
Regional Transmission Planning cycle, and the risk of data becoming
stale, we require transmission providers to update their data inputs at
least once at the outset of each Long-Term Regional Transmission
Planning cycle.
---------------------------------------------------------------------------
\1428\ ELCON Initial Comments at 13; Pine Gate Initial Comments
at 28-29.
---------------------------------------------------------------------------
644. With respect to National Grid's request to clarify the
definition of ``diverse'' in the context of the requirement that data
inputs must be developed using diverse and expert perspectives,\1429\
we clarify that the term ``diverse'' specifically used in the context
of data inputs indicates that the data inputs must represent a range of
data within the bounds of plausibility. We believe that this
requirement will ensure that the set of Long-Term Scenarios that are
developed from these data inputs will represent a reasonable range of
probable future outcomes consistent with the requirement for
plausibility.
---------------------------------------------------------------------------
\1429\ National Grid Initial Comments at 14.
---------------------------------------------------------------------------
8. Identification of Geographic Zones
a. NOPR Proposal
645. In the NOPR, the Commission proposed to require that each
transmission provider, as part of its regional transmission planning
process, consider whether to establish geographic zones within the
transmission planning region that have the potential for development of
large amounts of new generation. If transmission providers within a
transmission planning region choose to establish geographic zones, then
the Commission proposed to require the transmission provider to: (1)
identify, with stakeholder input, specific geographic zones within the
transmission planning region that have the potential for development of
large amounts of new generation; (2) assess generation developers'
commercial interest in developing generation within the identified
geographic zones; and (3) incorporate designated zones, and the
identified commercial interest in each zone, into Long-Term
Scenarios.\1430\
---------------------------------------------------------------------------
\1430\ NOPR, 179 FERC ] 61,028 at P 145.
---------------------------------------------------------------------------
646. The Commission preliminarily found that requiring the
consideration and potential identification of geographic zones within
Long-Term Scenarios assists transmission providers, transmission
developers, and generation developers in coordinating their activities.
The Commission stated that transmission providers would be able to
better identify transmission needs driven by changes in the resource
mix and demand by considering geographic zones that have the potential
for the development of large amounts of new generation and where
developers have already shown commercial interest. Further, the
Commission stated that, using the information gained through the
process described below to identify such geographic zones, transmission
providers in each transmission planning region could then plan
transmission facilities that would serve large concentrations of new
generation in a more efficient or cost-effective manner.\1431\
---------------------------------------------------------------------------
\1431\ Id. P 146.
---------------------------------------------------------------------------
647. The Commission proposed to require, as step one of the three-
step geographic zone process, that transmission providers consider
[[Page 49386]]
whether to establish and include in the regional transmission planning
process outlined in their OATTs the method that they will use to
identify geographic zones within the transmission planning region. The
Commission also proposed to require that transmission providers in each
transmission planning region use this information to create a set of
draft geographic zones, and that they post on their OASIS or other
public website maps of the draft geographic zones, as well as the
information used to create the draft geographic zones, for
stakeholders' input.\1432\
---------------------------------------------------------------------------
\1432\ Id. PP 147-148.
---------------------------------------------------------------------------
648. In addition, the Commission proposed to require transmission
providers in each transmission planning region to consider this
stakeholder feedback and modify the draft geographic zones as
appropriate to produce a final list of designated geographic zones
within the transmission planning region.\1433\
---------------------------------------------------------------------------
\1433\ The Commission noted that, while it referred to multiple
``zones,'' subsequent to stakeholder feedback, the final list may
contain only one designated geographic zone. Id. P 149.
---------------------------------------------------------------------------
649. The Commission proposed to require, in step two of the three-
step geographic zone process, that transmission providers in each
transmission planning region assess generation developers' commercial
interest in developing generation within each designated geographic
zone.\1434\ The Commission proposed to require, in the final step of
the three-step geographic zone process, that transmission providers in
each transmission planning region incorporate the information from step
one and step two regarding the designated geographic zones into their
Long-Term Scenarios.\1435\
---------------------------------------------------------------------------
\1434\ Id. P 150.
\1435\ Id. P 151.
---------------------------------------------------------------------------
b. Comments
650. Many commenters support the Commission's proposal to require
each transmission provider, as part of its regional transmission
planning process, to consider whether to: (1) identify, with
stakeholder input, specific geographic zones within the transmission
planning region that have the potential for development of large
amounts of new generation; (2) assess generation developers' commercial
interest in developing generation within the identified geographic
zones; and (3) incorporate designated zones, and the identified
commercial interest in each zone, into Long-Term Scenarios.\1436\
Commenters assert that, compared to interconnection-related network
upgrades identified on a case-by-case basis in the interconnection
process, identifying and incorporating geographic zones into Long-Term
Scenarios would save consumers money by identifying more efficient or
cost-effective transmission facilities to connect areas with the
potential for low cost generation to load centers and reduce congestion
and generator curtailment.\1437\ Further, commenters note the success
of previous planning efforts in ERCOT, MISO, CAISO, and ISO-NE to
incorporate geographic zones into their transmission planning
efforts.\1438\
---------------------------------------------------------------------------
\1436\ Ameren Initial Comments at 15; American Municipal Power
Initial Comments at 35; Clean Energy Associations Initial Comments
at 13; EEI Initial Comments at 15; ENGIE Initial Comments at 4;
Eversource Initial Comments at 21-22; Interwest Reply Comments at 4;
ISO-NE Initial Comments at 30; ITC Initial Comments at 5, 13-17;
Middle River Power Initial Comments at 3; MISO Initial Comments at
30; NARUC Initial Comments at 16; Nebraska Commission Initial
Comments at 6-7; NESCOE Initial Comments at 37; New Jersey
Commission Initial Comments at 15; New York TOs Initial Comments at
12; New York Transco Initial Comments at 5-6; Northwest and
Intermountain Initial Comments at 5-6; NRECA Initial Comments at 37;
New York Commission and NYSERDA Initial Comments at 14-15; NYISO
Initial Comments at 29-30; [Oslash]rsted Initial Comments at 7; US
DOE Initial Comments at 18; Western PIOs Initial Comments at 31-32.
\1437\ See, e.g., ENGIE Initial Comments at 4; Eversource
Initial Comments at 21-22; ITC Initial Comments at 13-17; Northwest
and Intermountain Initial Comments at 5-6; NYISO Initial Comments at
29-30.
\1438\ See, e.g., ENGIE Initial Comments at 4; Eversource
Initial Comments at 21-22.
---------------------------------------------------------------------------
651. Some commenters highlight the importance of this proposed
reform for remotely located renewable resources generally, and more
specifically for offshore wind, which is constrained to lease areas
auctioned by the Bureau of Ocean Energy Management.\1439\ For example,
[Oslash]rsted argues that the location and approximate resource
potential of offshore wind is well understood and the failure to
proactively plan the necessary transmission would result in higher
costs to ratepayers.\1440\ BP further contends that the geographic
zones in which National Interest Electric Transmission Corridors are
likely to be established also merit inclusion in transmission
planning.\1441\
---------------------------------------------------------------------------
\1439\ See, e.g., BP Initial Comments at 4, 7-8; Clean Energy
Buyers Initial Comments at 18; New York Transco Initial Comments at
5-6; [Oslash]rsted Initial Comments at 7-8.
\1440\ See, e.g., [Oslash]rsted Initial Comments at 7-8.
\1441\ BP Initial Comments at 7 (citing 16 U.S.C. 824p).
---------------------------------------------------------------------------
652. Some commenters support the proposal but urge the Commission
to require the identification of geographic zones and planning
transmission to integrate generation in those zones rather than just
requiring transmission providers to consider whether to identify
geographic zones.\1442\ Acadia Center and CLF argue that the Commission
should require the identification and creation of geographic zones in
areas where the majority of states have binding greenhouse gas emission
reduction or renewables mandates, which could result in fewer
transmission corridors being built, thereby reducing costs, siting
challenges, and benthic environmental impacts.\1443\ Acadia Center and
CLF assert that, without mandatory identification and establishment of
geographic zones, there is a significant risk that adequate
transmission will not be built to accommodate state emission reduction
and renewables mandates in a cost-effective or efficient way.\1444\
---------------------------------------------------------------------------
\1442\ Acadia Center and CLF Initial Comments at 13-15; Amazon
Initial Comments at 6-7; California Water Initial Comments at 16;
Center for Biological Diversity Initial Comments at 13-15; City of
New York Initial Comments at 7-8; Handy Law Initial Comments at 12;
Invenergy Reply Comments at 9-10; SEIA Initial Comments at 11-12;
Shell Initial Comments at 23.
\1443\ Acadia Center and CLF Initial Comments at 13-14.
\1444\ Id. at 13.
---------------------------------------------------------------------------
653. In contrast, other commenters emphasize that they support the
proposal to require transmission providers to consider identifying
geographic zones rather than to actually identify such geographic
zones.\1445\ Such commenters assert that providing the option to
identify geographic zones would allow transmission providers to
determine, with their stakeholders, what is right for their
transmission planning region.\1446\
---------------------------------------------------------------------------
\1445\ See, e.g., Ameren Initial Comments at 15-16; American
Municipal Power Initial Comments at 34-35; Clean Energy Associations
Initial Comments at 13; EEI Initial Comments at 15; ISO-NE Initial
Comments at 30; ITC Initial Comments at 5, 13-17; MISO Initial
Comments at 30; Nebraska Commission Initial Comments at 6-7; NESCOE
Initial Comments at 37; NRECA Initial Comments at 37; New York
Commission and NYSERDA Initial Comments at 14-15; NYISO Initial
Comments at 32; PPL Initial Comments at 11; US Chamber of Commerce
Initial Comments at 7.
\1446\ See, e.g., EEI Initial Comments at 15; ISO-NE Initial
Comments at 30; MISO Initial Comments at 30; New York Commission and
NYSERDA Initial Comments at 14-15; NYISO Initial Comments at 32.
---------------------------------------------------------------------------
654. Other commenters express concerns with the idea of
incorporating geographic zones with the potential for large amounts of
generation into regional transmission planning, but do not oppose the
proposal so long as it is optional.\1447\ For example, NESCOE and
[[Page 49387]]
National Grid assert that the proposed requirements for each of the
three steps is overly prescriptive and could be included in a final
order as guidance, but not as a mandate.\1448\
---------------------------------------------------------------------------
\1447\ APPA Initial Comments at 29-30; Dominion Initial Comments
at 28-29; Georgia Commission Initial Comments at 6; Large Public
Power Initial Comments at 22; National Grid Initial Comments at 16-
17; NESCOE Initial Comments at 38; SERTP Sponsors Initial Comments
at 27; SPP Market Monitor Initial Comments at 11-12; TANC Initial
Comments at 10.
\1448\ NESCOE Initial Comments at 38; National Grid Initial
Comments at 16.
---------------------------------------------------------------------------
655. Several commenters urge the Commission to provide flexibility
in any process for considering and potentially identifying geographic
zones.\1449\ For example, Michigan Commission states that the proposed
three-step process in the NOPR is highly prescriptive and overly
burdensome, and instead the Commission should provide greater
flexibility to ensure that generation siting assumptions included in
Long-Term Scenarios are developed transparently in collaboration with
state regulators, generation utilities, and resource planners.\1450\
---------------------------------------------------------------------------
\1449\ See, e.g., APS Initial Comments at 5; ISO-NE Initial
Comments at 30; Michigan Commission Initial Comments at 6; MISO
Initial Comments at 42; MISO TOs Initial Comments at 32; NARUC
Initial Comments at 17; New Jersey Commission Initial Comments at
15; NYISO Initial Comments at 3-4.
\1450\ Michigan Commission Initial Comments at 6.
---------------------------------------------------------------------------
656. Several commenters suggest modifications to the NOPR
proposal.\1451\ For example, Vistra contends that the NOPR proposal
could be improved through the use of open seasons or other comparable
tools to elicit concrete commitments from generator developers.\1452\
Other commenters argue that the NOPR proposal should be modified to
involve a subscription model in which prospective generation resources
within the zone indicate their willingness to pay for transmission to
the zone.\1453\ Although PJM opposes the NOPR proposal, PJM argues that
these alternative proposals offered by Vistra and New Jersey Commission
have merit and are worthy of further dialogue.\1454\
---------------------------------------------------------------------------
\1451\ Acadia Center and CLF Initial Comments at 15-16;
California Energy Commission Initial Comments at 2-3; Center for
Biological Diversity Initial Comments at 13-16; Clean Energy
Associations Initial Comments at 24-25; Illinois Commission Initial
Comments at 9-11; Large Public Power Initial Comments at 26;
Microgrid Resources Coalition Initial Comments at 4-6; New Jersey
Commission Initial Comments at 16-17; Vistra Initial Comments at 24.
\1452\ Vistra Initial Comments at 24.
\1453\ Clean Energy Associations Initial Comments at 24-25;
Large Public Power Initial Comments at 26; New Jersey Commission
Initial Comments at 16-17.
\1454\ PJM Reply Comments at 29-30, 31-32.
---------------------------------------------------------------------------
657. Regarding the specific steps in the NOPR proposal for
identifying geographic zones, several commenters support the proposal
to provide all stakeholders, including relevant Federal and state
siting authorities, with a meaningful opportunity to provide input on
the draft geographic zones.\1455\ Other commenters, however, assert
that the Commission should provide a clearer role for states and other
stakeholders to participate earlier in the process of identifying
geographic zones.\1456\
---------------------------------------------------------------------------
\1455\ ISO/RTO Council Initial Comments at 8; NARUC Initial
Comments at 16-17; National Grid Initial Comments at 17; Nebraska
Commission Initial Comments at 7; SEIA Initial Comments at 12-13;
Shell Initial Comments at 25.
\1456\ Acadia Center and CLF Initial Comments at 12-13; AEE
Initial Comments at 24-25; Amazon Initial Comments at 7; CAISO
Initial Comments at 4-5, 28-29, 31; DC and MD Offices of People's
Counsel Initial Comments at 15-16; Interwest Initial Comments at 9;
ISO-NE Initial Comments at 29; National Grid Initial Comments at 17-
18; NESCOE Initial Comments at 38-39; Nevada Commission Initial
Comments at 9-10; SERTP Sponsors Initial Comments at 27.
---------------------------------------------------------------------------
658. Some commenters argue that the NOPR proposal regarding what
information transmission providers should use to gauge commercial
interest in geographic zones is overly prescriptive and that the
information would be too speculative to be an accurate indicator of
commercial interest.\1457\ Several commenters urge the Commission to
increase the transparency of the NOPR proposal.\1458\ For example, US
DOE recommends that the Commission specify minimum standards for
reporting the attributes of each geographic zone.\1459\
---------------------------------------------------------------------------
\1457\ See, e.g., Middle River Power Initial Comments at 3; MISO
Initial Comments at 43; PJM Initial Comments at 84.
\1458\ Amazon Initial Comments at 8; Shell Initial Comments at
23-24; US DOE Initial Comments at 24-25
\1459\ US DOE Initial Comments at 20.
---------------------------------------------------------------------------
659. Several commenters oppose the proposal to require transmission
providers to consider whether to identify geographic zones with the
potential for large amounts of generation.\1460\ For example, APS
argues that the proposal may not be appropriate due to the speculative
nature of the identification of geographic zones and the long-term
nature of planning and building transmission infrastructure.\1461\
Idaho Power is concerned that the NOPR proposal will create a
significant level of work for transmission providers that would
outweigh the minor benefits developers would receive from the
data.\1462\
---------------------------------------------------------------------------
\1460\ APS Initial Comments at 5-7; Arizona Commission Initial
Comments at 8; CAISO Initial Comments at 27-28; Consumer
Organizations Initial Comments at 3-7; Duke Initial Comments at 4,
18-19; Idaho Power Initial Comments at 5; Indicated PJM TOs Initial
Comments at 3-4, 12-13; ISO/RTO Council Initial Comments at 7; LADWP
Initial Comments at 4; Louisiana Commission Initial Comments at 24-
25; Michigan Commission Initial Comments at 5-6; Microgrid Resources
Initial Comments at 5; North Carolina Commission and Staff Initial
Comments at 8-10; North Dakota Commission Initial Comments at 4-5;
Ohio Commission Federal Advocate Initial Comments at 7-8.
\1461\ APS Initial Comments at 6-7.
\1462\ Idaho Power Initial Comments at 5.
---------------------------------------------------------------------------
660. PJM opposes the NOPR proposal, which it describes as an
arbitrary and inflexible process that fails to account for regional
differences and that will require transmission providers to draw lines
on a map and commit to these areas for 20 years.\1463\ PJM states that
the information from the geographic zones will be poor compared to
information in the marketplace, including nearer term decisions of
interconnection customers.\1464\ PJM states that an alternative, more
case-specific flexible approach that builds on and is better
synchronized with the transmission provider's interconnection queue
process and market developments, and accommodates topologies as diverse
as those in PJM, is a better solution.\1465\ For example, PJM suggests
that the PJM State Agreement Approach is a better way to facilitate
clusters of renewable energy interconnections by finding states that
are willing to sponsor the new transmission to help fulfill a renewable
energy policy.\1466\
---------------------------------------------------------------------------
\1463\ PJM Initial Comments at 77-78.
\1464\ Id. at 77.
\1465\ Id. at 7.
\1466\ Id. at 79-82 (citing PJM Operating Agreement, Schedule 6,
section 1.5.9).
---------------------------------------------------------------------------
661. Several state commissions express concerns that the NOPR
proposal would give undue preference to certain kinds of
resources.\1467\ For example, North Dakota Commission argues that the
NOPR proposal would bias transmission planning towards one type of
generation, encourage speculative build-out of transmission, and
prevent visibility into the cost of other generation/transmission
combinations, which will result in under-utilized transmission and
additional costs to ratepayers with little benefit.\1468\
---------------------------------------------------------------------------
\1467\ Arizona Commission Initial Comments at 8; Louisiana
Commission Initial Comments at 24-25; Louisiana Commission Reply
Comments at 11-12; Michigan Commission Initial Comments at 5-6;
North Carolina Commission and Staff Initial Comments at 10-13; North
Dakota Commission Initial Comments at 4; Ohio Commission Federal
Advocate Initial Comments at 7-8; Pennsylvania Commission Initial
Comments at 7-8.
\1468\ North Dakota Commission Initial Comments at 4.
---------------------------------------------------------------------------
662. North Carolina Commission and Staff assert that the NOPR
proposal is an unwarranted intrusion into state jurisdiction over
generation and fails to acknowledge state authority over utility
generation, resource portfolios, and
[[Page 49388]]
integrated resource planning.\1469\ Similarly, Ohio Commission Federal
Advocate asserts that the NOPR proposal exceeds the Commission's
authority and interferes with Ohio's ability to maintain its
competitive retail electric service law.\1470\ Mississippi Commission
states that decisions to develop such zones within a state should be
left to the state.\1471\ Pennsylvania Commission argues that the
geographic zones used for Long-Term Scenarios could frustrate a state's
legitimate policy choices in establishing, for example, economic
development zones designed to encourage developers to site generation
in specific areas, by favoring another state's policy choices.\1472\
TAPS opposes any requirement to undertake a process to consider and
identify remote geographic zones where state or local laws require
local generating resources rather than remote resources.\1473\
---------------------------------------------------------------------------
\1469\ North Carolina Commission and Staff Initial Comments at
8.
\1470\ Ohio Commission Federal Advocate Initial Comments at 7
(quoting Ohio Commission Federal Advocate ANOPR Comments at 8).
\1471\ Mississippi Commission Reply Comments at 10.
\1472\ Pennsylvania Commission Initial Comments at 7-8.
\1473\ TAPS Initial Comments 9-10.
---------------------------------------------------------------------------
663. Many commenters argue that the NOPR proposal would be
duplicative of, or would interfere with, existing processes.\1474\ AEE
states that the consideration of geography in developing long-term
regional transmission plans should occur as a natural outgrowth of more
effective regional transmission planning and that a specific
requirement to identify geographic zones could have unintended
consequences.\1475\ AEE further asserts that some of the factors that
the NOPR proposes to require transmission providers to incorporate in
their Long-Term Scenarios inherently require them to consider what
geographic areas are ripe for low-cost generation development but are
isolated or otherwise transmission constrained.\1476\ Similarly,
Indicated PJM TOs argue that it is unnecessary to require the
identification of geographic zones in Long-Term Regional Transmission
Planning because transmission providers necessarily will rely on
driving factors (e.g., public policy goals) that will determine where
renewable resources will be developed.\1477\ According to Duke, the
categories of factors proposed in the NOPR already capture generator
interconnections, so it is unclear what this additional process will
add.\1478\
---------------------------------------------------------------------------
\1474\ AEE Initial Comments at 8; APS Initial Comments at 5;
CAISO Initial Comments at 4-5; Duke Initial Comments at 18-19;
Illinois Commission Initial Comments at 9-11; Indicated PJM TOs
Initial Comments at 12; ISO-NE Initial Comments at 30; ISO/RTO
Council Initial Comments at 7; MISO TOs Initial Comments at 32;
Mississippi Commission Reply Comments at 10; Nebraska Commission
Initial Comments at 6; NESCOE Initial Comments at 37; Nevada
Commission Initial Comments at 10; New York TOs Initial Comments at
12; NYISO Initial Comments at 33; SPP Initial Comments at 12-13;
TAPS Initial Comments 8-10; Xcel Initial Comments at 10-11.
\1475\ AEE Initial Comments at 8.
\1476\ Id. at 23-24.
\1477\ Indicated PJM TOs Initial Comments at 12.
\1478\ Duke Initial Comments at 18.
---------------------------------------------------------------------------
664. Several commenters argue that some transmission planning
processes already incorporate the identification of geographic zones,
and those existing processes should be allowed to continue.\1479\ ISO-
NE claims that transmission providers' planning constructs may already
include rules that allow for assessing and identifying geographic zones
with potential for high renewable development, rendering a separate
process redundant or unnecessary.\1480\ SPP states that the NOPR
proposal would duplicate SPP's current process to some extent and that
it would not be practical to do both.\1481\ Similarly, CAISO argues
that the NOPR proposal is overly prescriptive and would interfere with
California's existing processes, which are working effectively.\1482\
New York TOs note that New York's transmission planning processes
already include the evaluation of geographic zones expected to see
significant growth in generation or changes in load and incorporate
state involvement.\1483\ Mississippi Commission asserts that MISO
already considers geographic zones for new generation.\1484\
---------------------------------------------------------------------------
\1479\ See, e.g., CAISO Initial Comments at 27-33; ISO-NE
Initial Comments at 30; MISO TOs Initial Comments at 32; Nebraska
Commission Initial Comments at 6; NESCOE Initial Comments at 37;
Nevada Commission Initial Comments at 10; New York TOs Initial
Comments at 12; NYISO Initial Comments at 33; SPP Initial Comments
at 12-13.
\1480\ ISO-NE Initial Comments at 30.
\1481\ SPP Initial Comments at 12-13.
\1482\ CAISO Initial Comments at 4-5, 27-33.
\1483\ New York TOs Initial Comments at 12.
\1484\ Mississippi Commission Reply Comments at 10.
---------------------------------------------------------------------------
c. Commission Determination
665. We decline to adopt the proposed requirement that each
transmission provider, as part of its regional transmission planning
process, consider whether to establish geographic zones within the
transmission planning region that have the potential for development of
large amounts of new generation. We are persuaded by commenters that
finalizing and requiring the NOPR proposal is not warranted at this
time. Further, given the other requirements in this final order, such
as the requirement for transmission providers to plan for factors
affecting supply and demand, we agree with commenters that adopting
this proposed requirement is not necessary at this time to ensure that
Long-Term Regional Transmission Planning ensures just and reasonable
rates. We also agree with commenters that the prescriptive nature of
the proposed three-step process could unintentionally impede existing
efforts to incorporate geographic zones into regional transmission
planning.
666. Although we are not adopting the NOPR proposal, we encourage
transmission providers to consider geographic zones that have the
potential for development of large amounts of new generation as part of
their regional transmission planning process. As such, transmission
providers in a transmission planning region may propose to identify
geographic zones as part of Long-Term Regional Transmission Planning on
compliance with this final order, provided that they demonstrate that
their process for identifying such geographic zones is consistent with
or superior to the Long-Term Regional Transmission Planning
requirements established herein.
D. Evaluation of the Benefits of Regional Transmission Facilities
667. In this final order, we require transmission providers, as
part of Long-Term Regional Transmission Planning, to measure seven
specified benefits that were enumerated in the NOPR (``set of seven
required benefits'' or ``required benefits'') in each Long-Term
Scenario. We also allow transmission providers to propose on compliance
to measure additional benefits as part of Long-Term Regional
Transmission Planning. In addition, we require transmission providers
to use those measured benefits when evaluating Long-Term Regional
Transmission Facilities to determine whether they more efficiently or
cost-effectively address Long-Term Transmission Needs.\1485\
---------------------------------------------------------------------------
\1485\ As discussed in the Development of Long-Term Scenarios
section supra, transmission providers must also use these benefits
to inform their identification of Long-Term Transmission Needs.
---------------------------------------------------------------------------
668. This section of the final order discusses the requirements
that we adopt governing transmission providers' measurement and use of
benefits in Long-Term Regional Transmission Planning. Specifically, we
discuss: (1) the requirement to use a set of seven required benefits;
(2) the required benefits, themselves; (3) the requirement
[[Page 49389]]
to include a general description of how transmission providers will
measure each of the benefits that the final order requires, as well as
any additional benefits that they may propose, in their OATTs; (4) the
requirements related to the minimum time horizon over which
transmission providers must calculate the benefits of Long-Term
Regional Transmission Facilities; (5) the evaluation of the benefits of
portfolios of Long-Term Regional Transmission Facilities; and (6) other
issues related to benefits.
1. Requirement for Transmission Providers To Use a Set of Seven
Required Benefits
a. NOPR Proposal
669. In the NOPR, the Commission proposed a list of benefits that
transmission providers in each transmission planning region may
consider in Long-Term Regional Transmission Planning and cost
allocation processes, which included: (1) avoided or deferred
reliability transmission projects and aging infrastructure replacement;
(2) either reduced loss of load probability or reduced planning reserve
margin; (3) production cost savings; (4) reduced transmission energy
losses; (5) reduced congestion due to transmission outages; (6)
mitigation of extreme events and system contingencies; (7) mitigation
of weather and load uncertainty; (8) capacity cost benefits from
reduced peak energy losses; (9) deferred generation capacity
investments; (10) access to lower-cost generation; (11) increased
competition; and (12) increased market liquidity.\1486\ The NOPR
provided a description of each of these benefits categories as well as
a method to calculate benefits in each category.\1487\
---------------------------------------------------------------------------
\1486\ NOPR, 179 FERC ] 61,028 at P 185. As more fully described
below, the Commission is making modifications to the list of
benefits in this final order. Therefore, we clarify for the reader
how we refer to each of those benefits in this section. We refer to
benefits 1-6 as ``Benefit 1,'' ``Benefit 2,'' etc. We refer to
Benefit 7, ``mitigation of weather and load uncertainty'' as NOPR
Benefit 7. We refer to ``(8) capacity cost benefits from reduced
peak energy losses'' as ``NOPR Benefit 8'', ``Final Order Benefit
7'', and ``Benefit 7''. We refer to benefits 9-12 as ``Benefit 9,''
Benefit 10,'' etc.
\1487\ Id. PP 189-225.
---------------------------------------------------------------------------
670. The Commission explained that it was not proposing to make the
list of potential benefits mandatory or exhaustive and that
transmission providers would have flexibility to propose which benefits
to use as part of their Long-Term Regional Transmission Planning.\1488\
---------------------------------------------------------------------------
\1488\ Id. P 184.
---------------------------------------------------------------------------
671. The 12 potential benefits described in the NOPR are:
------------------------------------------------------------------------
Number Benefit Description
------------------------------------------------------------------------
1................. Avoided or deferred Reduced costs of avoided or
reliability delayed transmission
transmission investment otherwise required
facilities and to address reliability needs
aging transmission or replace aging transmission
infrastructure facilities.
replacement.
2a................ Reduced loss of load Reduced frequency of loss of
probability [OR load events by providing
next benefit]. additional pathways for
connecting generation
resources with load (if
planning reserve margin is
constant), resulting in
benefit of reduced expected
unserved energy by customer
value of lost load.
2b................ Reduced planning While holding loss of load
reserve margin [OR probabilities constant,
prior benefit]. system operators can reduce
their resource adequacy
requirements (i.e., planning
reserve margins), resulting
in a benefit of reduced
capital cost of generation
needed to meet resource
adequacy requirements.
3................. Production cost Reduction in production costs,
savings. including savings in fuel and
other variable operating
costs of power generation,
that are realized when
transmission facilities allow
for the increased dispatch of
suppliers that have lower
incremental costs of
production, displacing higher-
cost supplies; also,
reduction in market prices as
lower-cost suppliers set
market clearing prices; when
adjusted to account for
purchases and sales outside
the region, called adjusted
production cost savings.
4................. Reduced transmission Reduced energy losses incurred
energy losses. in transmittal of power from
generation to loads, thereby
reducing total energy
necessary to meet demand.
5................. Reduced congestion Reduced production costs
due to transmission during transmission outages
outages. that significantly increase
transmission congestion.
6................. Mitigation of Reduced production costs
extreme events and during extreme events, such
system as unusual weather
contingencies. conditions, fuel shortages,
and multiple or sustained
generation and transmission
outages, through more robust
transmission system reducing
high-cost generation and
emergency procurements
necessary to support the
system.
7................. Mitigation of Reduced production costs
weather and load during higher than normal
uncertainty. load conditions or
significant shifts in
regional weather patterns.
8................. Capacity cost Reduced energy losses during
benefits from peak load reduces generation
reduced peak energy capacity investment needed to
losses. meet the peak load and
transmission losses.
9................. Deferred generation Reduced costs of needed
capacity generation capacity
investments. investments through expanded
import capability into
resource-constrained areas.
10................ Access to lower-cost Reduced total cost of
generation. generation due to ability to
locate units in a more
economically efficient
location (e.g., low
permitting costs, low-cost
sites on which plants can be
built, access to existing
infrastructure, low labor
costs, low fuel costs, access
to valuable natural
resources, locations with
high-quality renewable energy
resources).
11................ Increased Reduced bid prices in
competition. wholesale electricity markets
due to increased competition
among generators and reduced
overall market concentration/
market power.
12................ Increased market Reduced transaction costs
liquidity. (e.g., bid-ask spreads) of
bilateral transactions,
increased price transparency,
increased efficiency of risk
management, improved
contracting, and better
clarity for Long-Term
Regional Transmission
Planning and investment
decisions through increased
number of buyers and sellers
able to transact with each
other as a result of
transmission expansion.
------------------------------------------------------------------------
[[Page 49390]]
672. While the Commission did not propose to require use of any
specific benefits in the NOPR, it sought comment on whether
transmission providers should be required to use some or all of the
potential benefits described in the NOPR as a minimum set of benefits
for their Long-Term Regional Transmission Planning process.\1489\
---------------------------------------------------------------------------
\1489\ Id. P 188.
---------------------------------------------------------------------------
b. Comments
673. Many commenters support the NOPR approach of providing
illustrative benefits rather than mandating the use of certain
benefits.\1490\ Indicated PJM TOs contend that the NOPR proposal would
advance the Commission's goals better than a more prescriptive
proposal.\1491\ SERTP Sponsors and Southern argue that the Commission
should not impose a minimum set of benefits because existing state-
regulated integrated resource planning processes adequately examine
some of the proposed benefits, and that some of the proposed benefits
would harm existing integrated resource planning processes or are only
appropriate for RTO/ISO regions.\1492\ LADWP asserts that some or all
of the identified benefits will be considered as part of the normal
transmission planning process without a requirement.\1493\ Dominion
asserts that the question arises of who will judge whether a
transmission project addresses the NOPR's proposed list of benefits and
that such debates could be time-consuming and further delay projects
and drive up costs.\1494\ Dominion states that transmission providers
should be permitted to identify the benefits that they will consider in
conducting Long-Term Regional Transmission Planning but retain
flexibility to apply the specific benefits that are most appropriate
given each transmission provider's individual circumstances.\1495\
---------------------------------------------------------------------------
\1490\ Ameren Initial Comments at 19; APPA Initial Comments at
31; APS Initial Comments at 9; Dominion Initial Comments at 34; Duke
Initial Comments at 22-23; EEI Initial Comments at 19-20; Eversource
Initial Comments at 25; Georgia Commission Initial Comments at 6-7;
Idaho Commission Initial Comments at 4; Idaho Power Initial Comments
at 7-8; Illinois Commission Initial Comments at 13-14; Indiana
Commission Initial Comments at 6; Indicated PJM TOs Initial Comments
at 17; ISO-NE Initial Comments at 5, 33-34; LADWP Initial Comments
at 5; Louisiana Commission Reply Comments at 9-10; Michigan
Commission Initial Comments at 6; MISO Initial Comments at 9, 51-52;
Mississippi Commission Initial Comments at 36; NARUC Initial
Comments at 20-21; National Grid Initial Comments at 26; North
Carolina Commission and Staff Initial Comments at 7; Nebraska
Commission Initial Comments at 7; New York TOs Initial Comments at
15; NRECA Initial Comments at 43-45; NYISO Initial Comments at 9,
37-38; OMS Initial Comments at 7-8; Pacific Northwest Utilities
Initial Comments at 8; Pennsylvania Commission Initial Comments at
9; SERTP Sponsors Initial Comments 29-30; Southern Initial Comments
at 24; TANC Initial Comments at 16; TAPS Initial Comments at 3, 14;
US Chamber of Commerce Initial Comments at 7; Vermont State Entities
Initial Comments at 7; Virginia Commission Staff Initial Comments at
5; Vistra Initial Comments at 15; Xcel Initial Comments at 12.
\1491\ Indicated PJM TOs Initial Comments at 17.
\1492\ SERTP Sponsors Initial Comments 29-30; Southern Initial
Comments at 25-27.
\1493\ LADWP Initial Comments at 5.
\1494\ Dominion Initial Comments at 34.
\1495\ Id.
---------------------------------------------------------------------------
674. TAPS supports requiring transmission providers to evaluate
production cost modeling but opposes requiring transmission providers
to consider any other benefits in order to allow for regional
flexibility.\1496\ Northwest and Intermountain and NYISO ask that the
final order confirm that the 12 illustrative benefits are neither
mandatory nor exhaustive.\1497\ California Municipal Utilities state
that requiring the consideration of all 12 benefits proposed in the
NOPR would misapprehend the state and local nature of resource
portfolio planning and fail to account for the costs of such
prescriptive measures and the need for consumer protection measures to
guard against speculative transmission projects.\1498\
---------------------------------------------------------------------------
\1496\ TAPS Initial Comments at 3, 14.
\1497\ Northwest and Intermountain Initial Comments at 16; NYISO
Initial Comments at 39.
\1498\ California Municipal Utilities Reply Comments at 5-6.
---------------------------------------------------------------------------
675. OMS urges the Commission to clarify that transmission
providers will have sufficient flexibility to use different sets of
benefit metrics in different transmission planning cycles.\1499\
Relatedly, Xcel states that for any specific study, portfolio, or
transmission project, all benefits do not need to be calculated and, in
some cases, calculating additional benefits may be costly, time
consuming, and contentious and provide little added value.\1500\
---------------------------------------------------------------------------
\1499\ OMS Initial Comments at 8.
\1500\ Xcel Initial Comments at 12.
---------------------------------------------------------------------------
676. Many of the commenters that support an illustrative approach
emphasize the importance of regional flexibility.\1501\ US Chamber of
Commerce states that flexibility will allow transmission planning
regions to consider benefits that best align with their respective
market structures.\1502\ MISO states that, without flexibility, it may
not be able to move forward with the transmission projects of the
greatest benefit and value to MISO and its stakeholders, noting that
benefits used to meet criteria for its recent Long-Range Transmission
Planning projects are not specified in its OATT.\1503\ MISO, NYISO, and
SPP argue that transmission providers and their stakeholders ought to
determine what the benefits evaluated for specific transmission
projects or sets of projects should be.\1504\ NARUC, New York TOs, and
Pennsylvania Commission agree, emphasizing consultation with
states.\1505\
---------------------------------------------------------------------------
\1501\ Ameren Reply Comments at 16-17 (citing MISO Initial
Comments at 9); APS Initial Comments at 9; Dominion Initial Comments
at 34; Duke Initial Comments at 22-23; EEI Initial Comments at 19-
20; Eversource Initial Comments at 25; Entergy Reply Comments at 3;
Idaho Commission Initial Comments at 4; Idaho Power Initial Comments
at 7-8; Illinois Commission Initial Comments at 13-14; Indiana
Commission Initial Comments at 6-7; Large Public Power Initial
Comments at 28; ISO-NE Initial Comments at 33-34; Massachusetts
Attorney General Initial Comments at 12, 15; MISO Initial Comments
at 9; Mississippi Commission Initial Comments at 35-36; NARUC
Initial Comments at 20-21; National Grid Initial Comments at 26;
Nebraska Commission Initial Comments at 7; New York TOs Initial
Comments at 15; Pennsylvania Commission Initial Comments at 9; SPP
Initial Comments at 18; US Chamber of Commerce Initial Comments at
7; Vistra Initial Comments at 15; Xcel Initial Comments at 12.
\1502\ US Chamber of Commerce Initial Comments at 7.
\1503\ MISO Initial Comments at 9.
\1504\ MISO Initial Comments at 9-10; NYISO Initial Comments at
39; SPP Initial Comments at 18.
\1505\ NARUC Initial Comments at 21-22; New York TOs Initial
Comments at 15; Pennsylvania Commission Initial Comments at 9.
---------------------------------------------------------------------------
677. Entergy urges the Commission to affirm its commitment to
providing transmission planning regions with flexibility in terms of
how they identify, consider, and calculate benefits. Entergy further
urges the Commission to adopt guiding principles to aid transmission
providers in identifying their own benefits.\1506\ Entergy argues that
the Commission should recognize that not all benefits are appropriate
in all jurisdictions and that some states will want to prioritize
transmission projects that reduce customer bills.\1507\
---------------------------------------------------------------------------
\1506\ Entergy Initial Comments at 21.
\1507\ Id.
---------------------------------------------------------------------------
678. SPP argues that how and when transmission benefits are
calculated and incorporated in any regional transmission planning
assessment should be at the discretion of each transmission provider
and its stakeholders. Specifically, SPP argues that the effort required
to incorporate additional benefit metrics into its current transmission
planning process cannot be accommodated within its current process
timeline.\1508\
---------------------------------------------------------------------------
\1508\ SPP Initial Comments at 18.
---------------------------------------------------------------------------
679. Mississippi Commission argues that any required benefits would
be arbitrary and some metrics may not be applicable at times.\1509\
National Grid
[[Page 49391]]
argues that flexibility will allow transmission providers to adapt more
readily to changes in state policy drivers, prevent the requirements of
Long-Term Regional Transmission Planning from becoming dated, and allow
benefits and cost allocation discussions to be synchronized.\1510\ Duke
contends that allowing regional flexibility may help to mitigate some
disputes within transmission planning regions over what benefits to
measure and how to measure them. Moreover, Duke argues that regional
flexibility is critical to ensuring that each benefit metric used is
relevant and calculable for each transmission planning region,
particularly given differences between RTO/ISO and non-RTO/ISO regions.
Duke contends that regions must not be forced into accepting and
implementing benefits metrics that they have not vetted or on which
they do not have consensus.\1511\
---------------------------------------------------------------------------
\1509\ Mississippi Commission Initial Comments at 35-36.
\1510\ National Grid Initial Comments at 26-27.
\1511\ Duke Initial Comments at 22-23.
---------------------------------------------------------------------------
680. MISO, while stating its preference for flexibility in
identifying benefits, also states that it would support identifying and
using a general set of benefit metrics that capture key areas of
transmission value, such as reliability and resilience, production cost
savings, and avoided resource and/or transmission investment, assuming
that each transmission planning region may determine how to calculate
each metric and how each applies during a transmission assessment, as
well as allowing for different benefit metrics not part of that
``general set'' to be applied when warranted.\1512\
---------------------------------------------------------------------------
\1512\ MISO Initial Comments at 9.
---------------------------------------------------------------------------
681. Some commenters offer support for the illustrative benefits
without suggesting that they be required.\1513\ PG&E states that
CAISO's transmission planning process currently evaluates several of
the same benefits, either routinely or on a case-specific basis, and
that PG&E supports the continued flexibility the NOPR envisions for
RTO/ISOs.\1514\
---------------------------------------------------------------------------
\1513\ Nevada Commission Initial Comments at 10-11; Pattern
Energy Initial Comments at 14; PG&E Initial Comments at 7.
\1514\ PG&E Initial Comments at 7.
---------------------------------------------------------------------------
682. In contrast, many commenters support the Commission requiring
that transmission providers consider a minimum list of benefits for
Long-Term Regional Transmission Planning.\1515\ PIOs argue that most of
the benefits outlined in the NOPR have broad support, even among those
commenters that do not support a Commission requirement to consider a
minimum set of benefits.\1516\
---------------------------------------------------------------------------
\1515\ ACORE Initial Comments at 12; ACORE Reply Comments at 6;
ACORE Supplemental Comments at 1; AEE Initial Comments at 8, 25; AEP
Initial Comments at 6, 23-25; Breakthrough Energy Initial Comments
at 4, 21-22; Business Council for Sustainable Energy Initial
Comments at 2, 5; Certain TDUs Initial Comments at 11-12; Clean
Energy Buyers Reply Comments at 8-9; Concerned Scientists Reply
Comments at 7-10; Cypress Creek Reply Comments at 7-8; DC and MD
Offices of People's Counsels Reply Comments at 3, 7-8; ELCON Initial
Comments at 15; Enel Initial Comments at 3; Environmental Groups
Supplemental Comments at 2; Environmental Legislators Caucus
Supplemental Comments at 1; Exelon Initial Comments at 16: Grid
United Initial Comments at 2; Handy Law Initial Comments at 8; US
House Republicans Supplemental Comments at 1; Indicated US Senators
and Representatives Initial Comments at 2; ITC Initial Comments at
5, 18-22; Interwest Initial Comments at 12; Interwest Reply Comments
at 6-7; Joint Consumer Advocates Initial Comments at 11; Kentucky
Commission Chair Chandler Reply Comments at 7; Minnesota State
Entities Initial Comments at 6; New England for Offshore Wind
Initial Comments at 5; New Jersey Commission Initial Comments at 11-
14; Pacific Northwest State Agencies Initial Comments at 16-17; PIOs
Initial Comments at 27-28; PIOs Reply Comments at 7-8; Policy
Integrity Initial Comments at 27; Policy Integrity Supplemental
Comments at 4; R Street Initial Comments at 9; RMI Initial Comments
at 1; RMI Supplemental Comments at 2; SEIA Initial Comments at 16-
17; Southeast PIOs Initial Comments at 50; Southeast PIOs Reply
Comments at 27-28; US DOE Initial Comments at 30-33; US Senator
Schumer Supplemental Comments at 1-2; US Senator Whitehouse
Supplemental Comments at 2; US Senators Supplemental Comments at 2;
WATT Coalition Initial Comments at 7.
\1516\ PIOs Initial Comments at 26, 41; PIOs Reply Comments at
7-8.
---------------------------------------------------------------------------
683. Clean Energy Associations and US Senator Schumer assert that
the failure to adopt a minimum list of benefits risks skewing benefit-
to-cost ratios against developing necessary transmission because all
costs would be included in an evaluation but not all benefits would
also be included.\1517\ Clean Energy Associations further state that
failing to require the adoption of a minimum list of benefits could
lead to higher costs in the long-term, as larger transmission projects
with net benefits would not be selected.\1518\ Finally, Clean Energy
Associations argue that, without a minimum list of benefits,
significant disparities in regional identification of potential Long-
Term Regional Transmission Facilities could have harmful spillover
effects on coordinated activities such as interregional transmission
coordination and affected systems studies.\1519\
---------------------------------------------------------------------------
\1517\ Clean Energy Associations Initial Comments at 19; US
Senator Schumer Supplemental Comments at 1-2.
\1518\ Clean Energy Associations Initial Comments at 19-20
(citing The Brattle Group, Transmission Planning and Benefit-Cost
Analyses, at 26 (Apr. 2021)).
\1519\ Clean Energy Associations Initial Comments at 19.
---------------------------------------------------------------------------
684. Michigan State Entities argue that there must be some
prescribed list of benefits, asserting that it would not force
differently situated transmission providers to implement any specific
policy, but instead would ensure that they take a ``fair look'' at
transmission planning policies, including those using storage, that
could produce substantial savings for customers.\1520\ Interwest
contends that a standard and comprehensive framework for evaluating
benefits is necessary because an ad hoc approach could result in
inconsistencies and an incomplete picture of a transmission project's
potential benefits.\1521\
---------------------------------------------------------------------------
\1520\ Michigan State Entities Reply Comments at 2.
\1521\ Interwest Reply Comments at 7.
---------------------------------------------------------------------------
685. Southeast PIOs urge the Commission to prescribe a set of
benefits for use in benefit-cost analyses, starting with the entire
list of benefits in the NOPR. Southeast PIOs argue that the
transmission providers in the Southeast exploited the flexibility in
establishing and assessing benefits that the Commission provided in
Order No. 1000 to implement a straight cost comparison.\1522\ Southeast
PIOs further state that minimum standards are necessary to produce
actionable results; otherwise, Long-Term Regional Transmission Planning
will devolve into a ``box-checking exercise.'' \1523\ SREA argues that
the Commission needs to set clear guidelines around benefit metrics to
avoid opponents to the NOPR finding easy work-arounds.\1524\
---------------------------------------------------------------------------
\1522\ Southeast PIOs Initial Comments at 50.
\1523\ Southeast PIOs Reply Comments at 23, 27.
\1524\ SREA Reply Comments at 26 (citing Louisiana Commission
Initial Comments at 17; Mississippi Commission Initial Comments at
11; Southern Initial Comments at 12).
---------------------------------------------------------------------------
686. Similarly, R Street states that transmission providers should
be required to use a minimum set of benefits because they lack the
incentive to account for all system-wide benefits. R Street argues that
proposing a benefits list for transmission providers to consider is the
status quo and the Commission should expect little change without a
benefits requirement.\1525\ Concerned Scientists agree, claiming that
the experience with Order No. 1000 implementation and the descriptions
in the comments in response to the NOPR illustrate how transmission
planning processes are resistant to changes when the Commission
provides latitude for discretion.\1526\ Concerned Scientists further
contend that the discretion provided in the NOPR will allow a pattern
of undue discrimination and unjust and unreasonable rates to persist
[[Page 49392]]
that initially motivated the Commission to act.\1527\
---------------------------------------------------------------------------
\1525\ R Street Initial Comments at 9.
\1526\ Concerned Scientists Reply Comments at 7.
\1527\ Id. at 8-9.
---------------------------------------------------------------------------
687. Some commenters assert that requiring the same benefits in
different transmission planning regions will help increase
interregional transmission coordination.\1528\ Clean Energy
Associations argue that it is important for transmission planning
regions to have a common starting point in terms of which benefits they
evaluate to facilitate greater interregional transmission
coordination.\1529\ Breakthrough Energy notes that load diversity--and
its effect on reducing very expensive generation capacity costs--is a
major and under-appreciated benefit of large-scale interregional
transmission facilities.\1530\ Grid United states that, without a
minimum set of benefits criteria, disparate benefits in neighboring
transmission planning regions could balkanize the grid and disrupt
effective interregional transmission planning, emphasizing the need for
a set of principles that outline benefits that are universal and
necessary for effective long-term transmission planning.\1531\ Policy
Integrity asserts that defining a uniform set of minimum benefits would
facilitate better identification and selection of efficient and cost-
effective transmission solutions and would ensure comparability of
transmission expansion projects across different RTOs/ISOs, which will
be particularly useful given the need to improve Interregional Transfer
Capability.\1532\
---------------------------------------------------------------------------
\1528\ Breakthrough Energy Initial Comments at 22-23; California
Commission Initial Comments at 33; Grid United Initial Comments at
3; Policy Integrity Initial Comments at 27-28; US DOE Initial
Comments at 31-32.
\1529\ Clean Energy Associations Initial Comments at 19.
\1530\ Breakthrough Energy Initial Comments at 22.
\1531\ Grid United Initial Comments at 3.
\1532\ Policy Integrity Initial Comments at 3, 27-28.
---------------------------------------------------------------------------
688. Relatedly, PJM states that, while it agrees that transmission
providers should have flexibility to propose which benefits make sense
to consider for their own transmission planning regions, the Commission
should adopt a core set of benefits to be considered nationwide to
ensure consistency.\1533\ SREA notes that, in RTOs/ISOs, seams are
perpetually a problem due to a lack of common national standards on
benefits metrics and data inputs and asserts that the Commission should
set minimum standards.\1534\
---------------------------------------------------------------------------
\1533\ PJM Initial Comments at 93 (citing NOPR, 179 FERC ]
61,028 at P 186).
\1534\ SREA Reply Comments at 26-27.
---------------------------------------------------------------------------
689. Some commenters assert that a failure to consider sufficient
benefits could result in higher costs and/or unjust and unreasonable
rates.\1535\ According to Enel, without considering a larger number of
benefits, transmission projects that would have large net benefits will
not be selected if no benefits or even only a small number of potential
benefits were compared against the upfront costs.\1536\
---------------------------------------------------------------------------
\1535\ Enel Initial Comments at 3; Clean Energy Association
Initial Comments at 20; Conservative Energy Network Supplemental
Comments at 1; Conservatives for Clean Energy--Florida Supplemental
Comments at 1; Conservatives for Clean Energy--South Carolina
Supplemental Comments at 1; Indicated US Senators and
Representatives Initial Comments at 2; Michigan Conservative Energy
Forum Supplemental Comments at 1; Ohio Conservative Energy Forum
Supplemental Comments at 1; Western Way Colorado Supplemental
Comments at 1; Western Way Nevada Supplemental Comments at 1;
Western Way Utah Supplemental Comments at 1; Wisconsin Conservative
Energy Forum Supplemental Comments at 1.
\1536\ Enel Initial Comments at 3.
---------------------------------------------------------------------------
690. Some commenters assert that a failure to require consideration
of specific benefits will undermine other aspects of the NOPR's
proposed reforms.\1537\ Anbaric, for instance, argues that the NOPR
falls far short of requiring comprehensive transmission planning,
because it does not propose to mandate the use of any specific set of
benefits.\1538\ RMI contends that there is overwhelming evidence that
transmission infrastructure provides multiple, diverse benefits, as
well as established precedent that transmission costs should be
allocated roughly commensurate with benefits. Therefore, RMI states, it
would be illogical to allow transmission providers to ignore any
benefits that transmission infrastructure offers, as it would lead to
flawed investment decisions and defective cost allocation. RMI asserts
that transmission providers should be required to quantify the full
suite of known benefits of transmission infrastructure in Long-Term
Regional Transmission Planning and that the list of 12 benefits in the
NOPR is conservative and does not double-count benefits.\1539\
---------------------------------------------------------------------------
\1537\ Anbaric Initial Comments at 6-7; RMI Initial Comments at
2.
\1538\ Anbaric Initial Comments at 6-7.
\1539\ RMI Initial Comments at 2.
---------------------------------------------------------------------------
691. AEE argues that several of the listed benefits are
indisputably relevant to all transmission planners and that these
benefits should form a core group of minimum considerations.\1540\ AEE
states that the Commission may wish to conduct additional fact-finding
in this docket to consider whether additional benefits cut across all
markets and transmission planning regions or whether it is necessary to
require each region to identify region-specific benefits for
inclusion.\1541\ Hannon Armstrong states that the Commission indicated
that each of the 12 benefits listed in the NOPR has the potential to
provide a meaningful contribution to offset the cost of transmission
and recommends that, absent any double-counting in this list, the
Commission should require each of these benefits to be evaluated.\1542\
ITC argues that the Commission should adopt as minimum benefit criteria
for project evaluation those used in the recently approved MISO Long-
Range Transmission Plan process.\1543\
---------------------------------------------------------------------------
\1540\ AEE Initial Comments at 26.
\1541\ Id.
\1542\ Hannon Armstrong Initial Comments at 2-3.
\1543\ ITC Initial Comments at 5, 18-22.
---------------------------------------------------------------------------
692. Southeast PIOs claim that the Commission must establish a set
of minimum benefits for transmission providers to incorporate in their
assessment of regional transmission facilities to ensure that regional
transmission facilities are accurately represented in the transmission
planning process.\1544\ Southeast PIOs contend that a regional
transmission planning process that quantifies and fully accounts for
benefits of regional transmission alternatives would provide a measure
of assurance to regulators and stakeholders that such alternatives were
evaluated appropriately.\1545\ In response to Southern and SERTP,
Southeast PIOs argue that quantifying the listed benefits does not
itself make resource decisions; the benefits are meant to determine the
value proposition of alternative regional transmission
facilities.\1546\
---------------------------------------------------------------------------
\1544\ Southeast PIOs Initial Comments at 50.
\1545\ Id. at 53.
\1546\ Southeast PIOs Reply Comments at 28 (citing Southern
Initial Comments at 25-26; SERTP Sponsors Initial Comments at 30).
---------------------------------------------------------------------------
693. GridLab states that the Commission should require transmission
providers to justify why their transmission solution evaluation
frameworks omit any categories of benefits in relation to a standard
list of benefits like those proposed in the NOPR.\1547\ Pattern Energy
agrees and notes that a ``common starting point'' would lower barriers
to entry for market participants that do business in multiple
transmission planning regions. Moreover, Pattern Energy argues that a
required set of standardized benefits would facilitate a more
transparent transmission planning process, as developers would have a
baseline knowledge of any single transmission provider's transmission
planning
[[Page 49393]]
process regardless of where they are located.\1548\
---------------------------------------------------------------------------
\1547\ GridLab Initial Comments at 25.
\1548\ Pattern Energy Reply Comments at 6-8 (citing ACEG Initial
Comments at 32; Clean Energy Associations Initial Comments at 21).
---------------------------------------------------------------------------
694. Tabors Caramanis Rudkevich states that when transmission
planning analyses account for the benefits of capital cost savings,
resource adequacy, and resilience, the total benefits of transmission
infrastructure well exceed the cost.\1549\ Tabors Caramanis Rudkevich
provides an example of multi-value benefit stacking for the
transmission line connecting ERCOT and Southern Company and states that
the results show total benefits of $390 million, compared to $33
million when considering production cost savings alone.\1550\
---------------------------------------------------------------------------
\1549\ Tabors Caramanis Rudkevich Initial Comments at 6.
\1550\ Id.
---------------------------------------------------------------------------
695. Certain TDUs and NESCOE support or are amenable to a
requirement for minimum benefits that also allows for flexibility in
determination of additional benefits.\1551\ Specifically, NESCOE
recommends that the Commission establish a list of benefits that must
be considered for a regional discussion on transmission cost allocation
and that the benefits list in the NOPR is an appropriate starting
point. However, NESCOE contends, after consulting with the states,
transmission providers should have the flexibility to include
additional benefits or remove benefits from the list, asserting that
such an approach would help facilitate collaboration in determining the
appropriate set of benefits for a transmission planning region.\1552\
NESCOE also argues that, because benefits and the methods of measuring
them may change over time, the Commission should clarify in any final
order that transmission providers may modify or add benefits in future
FPA section 205 filings.\1553\
---------------------------------------------------------------------------
\1551\ Certain TDUs Initial Comments at 2-3, 9-12; NESCOE
Initial Comments at 43-44.
\1552\ NESCOE Initial Comments at 44.
\1553\ Id. at 43-44.
---------------------------------------------------------------------------
696. Certain TDUs also urge the Commission to allow for regional
flexibility and state involvement in determining other measurable and
quantifiable benefits to use in evaluating Long-Term Regional
Transmission Facilities.\1554\ While arguing for requiring certain
benefits, Cypress Creek states that it agrees with Brattle Group that
requiring evaluation of all 12 benefits in every scenario would detract
from necessary regional flexibility.\1555\ Cypress Creek asserts that
the Commission should require two additional project/region-specific
benefits in evaluating multi-value projects but does not explain what
they should be.\1556\
---------------------------------------------------------------------------
\1554\ Certain TDUs Initial Comments at 9.
\1555\ Cypress Creek Reply Comments at 7-8 (citing PIOs Initial
Comments Ex. A, ]] 8-9).
\1556\ Id. at 8.
---------------------------------------------------------------------------
697. Exelon supports the Commission's proposal to provide
flexibility to each transmission planning region to identify which
benefits they will use in Long-Term Regional Transmission Planning. For
instance, Exelon suggests that congestion reduction is more applicable
to regions with Locational Marginal Price pricing, while it may be
impossible to calculate the benefits of deferred generation capacity
investments in a region like PJM where generation capacity is largely
market-driven.\1557\ Similarly, the New Jersey Commission recommends
providing regional flexibility to include additional benefits that may
be harder to quantify and/or do not reduce customers' bills (e.g.,
resilience benefits and the value of meeting state public
policies).\1558\
---------------------------------------------------------------------------
\1557\ Exelon Initial Comments at 15.
\1558\ New Jersey Commission Initial Comments at 14.
---------------------------------------------------------------------------
698. Clean Energy Buyers state that the proposed set of benefits is
generally appropriate and that a common set of benefits would allow for
the proper identification of benefits in Long-Term Regional
Transmission Planning, accounting for changes in the resource mix and
demand, and facilitating stakeholder participation. Therefore, Clean
Energy Buyers argue, the Commission should require transmission
providers to adopt a set of Commission-identified benefits that are
consistent with the just and reasonable standard or demonstrate on
compliance why they should not have to do so. That said, Clean Energy
Buyers state that the Commission should permit transmission providers
to propose processes for weighing benefits in accordance with their
relative importance in each specific transmission planning
region.\1559\
---------------------------------------------------------------------------
\1559\ Clean Energy Buyers Initial Comments at 19-21.
---------------------------------------------------------------------------
699. Several commenters recognize that benefits analysis can be
resource intensive and therefore recommend that the Commission allow
transmission providers to use a screening approach that initially
screens benefit categories for significance before investing staff
resources and modeling work to provide a detailed quantification.\1560\
Clean Energy Buyers argue that, at a minimum, the Commission should
require that transmission providers screen for all 12 benefits listed
in the NOPR and quantify them accordingly.\1561\ Hannon Armstrong
states that while certain benefits may have a zero or de minimis
contribution for certain candidate transmission projects, the
Commission should require transmission providers to document each
potential benefit by using a high-level screening analysis or detailed
modeling as applicable.\1562\ PIOs assert that screening tools can be
used to reduce analytical burdens, allowing transmission providers to
self-certify compliance and/or provide justifications for when benefits
do not apply.\1563\
---------------------------------------------------------------------------
\1560\ ACEG Initial Comments at 7, 33; ACORE Initial Comments at
12; Breakthrough Energy Initial Comments at 22; CTC Global Initial
Comments at 9; Interwest Initial Comments at 12-13; WATT Coalition
Initial Comments at 7.
\1561\ Clean Energy Buyers Initial Comments at 20-21.
\1562\ Hannon Armstrong Initial Comments at 2-3.
\1563\ PIOs Initial Comments at 41.
---------------------------------------------------------------------------
i. List of Benefits Proposed in the NOPR
700. Some commenters support requiring transmission providers to
consider all 12 illustrative benefits enumerated in the NOPR.\1564\
ACORE contends that these categories represent a best practice and
track closely with recommended multi-benefit planning approaches.\1565\
Breakthrough Energy notes that some of the Commission-listed benefits
can be very significant but are typically ignored in today's
transmission planning processes.\1566\ SEIA and Fervo assert that the
final order should account for the full range of transmission benefits
and use multi-value planning to comprehensively identify investments
that address all categories of needs and benefits.\1567\
---------------------------------------------------------------------------
\1564\ Acadia Center and CLF Initial Comments at 21-22; ACEG
Initial Comments at 32; ACORE Initial Comments at 12; AEE Reply
Comments at 25: Amazon Initial Comments at 5; Breakthrough Energy
Initial Comments at 21-22; Clean Energy Associations Initial
Comments at 19-20; DC and MD Offices of People's Counsel Initial
Comments at 19-20; ENGIE Reply Comments at 3; Hannon Armstrong
Initial Comments at 3; Interwest Initial Comments at 12-14; National
and State Conservation Organizations Initial Comments at 1; Pine
Gate Initial Comments at 34-37; PIOs Initial Comments at 38-41; RMI
Initial Comments at 1; SEIA Initial Comments at 16; Southeast PIOs
Initial Comments at 50.
\1565\ ACORE Initial Comments at 12 (citing Rob Gramlich, Grid
Strategies LLC, Enabling Low-Cost Clean Energy and Reliable Service
Through Better Transmission Benefits Analysis, at 9 (Aug. 9, 2022)).
\1566\ Breakthrough Energy Initial Comments at 22.
\1567\ Fervo Reply Comments at 2; SEIA Initial Comments at 16.
---------------------------------------------------------------------------
701. PIOs state that there is strong evidence in the record to
support the proposed list of benefits, including extensive testimony
provided by the Brattle Group and others. PIOs state that these
benefits all correlate with needs
[[Page 49394]]
and goals associated with Long-Term Regional Transmission Planning and,
as such, the Commission should require transmission providers to
consider them for most, if not all, regional transmission projects.
Finally, PIOs encourage the Commission to make clear that these
benefits should be assessed as part of any transmission planning
process--even those conducted for economic purposes.\1568\
---------------------------------------------------------------------------
\1568\ PIOs Initial Comments at 37-38, 41.
---------------------------------------------------------------------------
702. Amazon supports the list of benefits set forth in the NOPR and
urges the Commission to make consideration of those benefits mandatory
except insofar as a transmission provider files for waiver and
overcomes a strong presumption of their relevance to transmission
planning and cost allocation.\1569\ To facilitate the responsible
construction of transmission facilities, ENGIE recommends that the
Commission incorporate the 12 listed benefits as a minimum set of
benefits for analysis but permit flexibility in how transmission
providers conduct their analysis.\1570\
---------------------------------------------------------------------------
\1569\ Amazon Initial Comments at 5.
\1570\ ENGIE Reply Comments at 3.
---------------------------------------------------------------------------
ii. Application of the Benefits of Long-Term Regional Transmission
Facilities in Non-RTO/ISO Regions
703. Certain commenters state that all or most of the Commission's
proposed benefits are applicable and appropriate in non-RTO/ISO
transmission planning regions.\1571\ For example, ACEG states the
minimum set of benefits should be implemented as universally as
possible across RTOs/ISOs and non-RTO/ISO regions.\1572\ PIOs state
that the Brattle-Grid Strategies Oct. 2021 Report shows the numerous
benefits not currently quantified in RTO/ISO regions to consumers'
detriment and that the problem is more dire in non-RTO/ISO
regions.\1573\ Relatedly, MISO states that benefits could be applied in
non-RTO/ISO regions but may be limited or not fully realized due to
less coordinated congestion management and transmission planning.\1574\
---------------------------------------------------------------------------
\1571\ ACEG Initial Comments at 32, 48, 61; PIOs Initial
Comments at 42; SEIA Initial Comments at 17.
\1572\ ACEG Initial Comments at 32.
\1573\ PIOs Initial Comments at 42.
\1574\ MISO Initial Comments at 51.
---------------------------------------------------------------------------
704. SEIA comments that the Commission should mandate the
consideration of benefits of Long-Term Regional Transmission Facilities
in non-RTO/ISO transmission planning regions. Otherwise, SEIA states,
transmission providers could rely on state integrated resource planning
processes, which do not incorporate lower cost transmission
alternatives to generation procurement, potentially leading to
transmission expansion to accommodate higher-cost generation than is
needed. According to SEIA, there is no basis to apply different
benefits in non-RTO/ISO transmission planning regions, because many of
the proposed benefits of Long-Term Regional Transmission Facilities
have already been calculated in non-RTO/ISO regions.\1575\
---------------------------------------------------------------------------
\1575\ SEIA Initial Comments at 17-18.
---------------------------------------------------------------------------
705. Southeast PIOs claim that Southeastern transmission providers
should not be exempt from quantifying benefits, even if some benefits
do not apply in the same manner to non-RTO/ISO transmission planning
regions as they do to RTO/ISO regions.\1576\ Southeast PIOs advocate
for the Commission to establish standardized metrics for both RTO/ISO
regions and non-RTO/ISO regions to capture similar benefits.\1577\
Otherwise, Southeast PIOs argue, transmission providers will continue
to focus only on costs, thereby depriving states and stakeholders of a
fuller picture of transmission planning options.\1578\ TAPS contends
that no transmission facilities have been selected in a regional
transmission plan for purposes of cost allocation since the
implementation of Order No. 1000 in non-RTO/ISO transmission planning
regions partly because of the narrow factors that most non-RTO/ISO
regions consider in evaluating the benefits of potential transmission
projects.\1579\
---------------------------------------------------------------------------
\1576\ Southeast PIOs Initial Comments at 51.
\1577\ Id. at 52.
\1578\ Id. at 52-53.
\1579\ TAPS Initial Comments at 15.
---------------------------------------------------------------------------
706. Other commenters express concern that certain NOPR benefits
would be inapplicable or problematic to apply to non-RTO/ISO
transmission planning regions or argue that the same types of benefits
should not be applied to both sets of regions.\1580\ California
Municipal Utilities oppose applying the list of benefits to non-RTO/ISO
transmission planning regions, stating that doing so would misapprehend
the state and local nature of resource portfolio planning and would
fail to account for the costs of such prescriptive measures and to
provide consumer protection measures to guard against speculative
transmission projects.\1581\ Dominion states that a one-size-fits-all
approach to benefits may be inappropriate, for instance, in locations
where some transmission providers operate outside of an RTO/ISO while
others function within an RTO/ISO.\1582\
---------------------------------------------------------------------------
\1580\ California Municipal Utilities Reply Comments at 5-6;
Dominion Reply Comments at 2; Duke Initial Comments at 23; EEI
Initial Comments at 19; Idaho Power Initial Comments at 8; North
Carolina Commission and Staff Initial Comments at 7; Southern
Initial Comments at 25-27.
\1581\ California Municipal Utilities Reply Comments at 5-6.
\1582\ Dominion Reply Comments at 2.
---------------------------------------------------------------------------
707. EEI and Idaho Power state that non-RTO/ISO transmission
planning regions may not be able to calculate reduced congestion or
increased market liquidity.\1583\ Likewise, North Carolina Commission
and Staff state that some of the benefits proposed for consideration
are only applicable in RTOs/ISOs (e.g., increased market liquidity) and
argue that some benefits could conflict with state-jurisdictional
resource decisions (e.g., production cost savings, access to lower-cost
generation).\1584\
---------------------------------------------------------------------------
\1583\ EEI Initial Comments at 19; Idaho Power Initial Comments
at 8.
\1584\ North Carolina Commission and Staff Initial Comments at
7.
---------------------------------------------------------------------------
708. Southern states that, while certain benefits identified in the
NOPR could work for Southern's non-RTO/ISO footprint, others could harm
underlying state integrated resource planning/request for proposal
processes or are suited only for RTO/ISO markets, such as increased
market liquidity.\1585\ For example, Southern states that considering
production cost savings effectively would make generation resource-
related decisions that would intrude into integrated resource plan/
request for proposal planning, which considers the total costs
(including both generation and transmission costs) of available
alternatives to customers.\1586\ Similarly, SERTP Sponsors state that,
because SERTP Sponsors continue to use integrated resource plan/request
for proposal planning to make their resource and load determinations,
some of the benefits that are appropriate for consideration in RTOs/
ISOs are inapplicable for transmission planning or cost allocation
purposes in the Southeast.\1587\ SERTP Sponsors further state that, as
the states have exclusive jurisdiction over such integrated resource
plan/generation matters, requiring consideration of ``[integrated
resource plan/request for proposal]-related benefits,'' including
production cost savings, capacity costs benefits, reduced planning
reserve margins, and reduced peak energy losses, could exceed the
Commission's jurisdiction by infringing on such state processes.\1588\
---------------------------------------------------------------------------
\1585\ Southern Initial Comments at 25-27.
\1586\ Id. at 26.
\1587\ SERTP Sponsors Initial Comments at 30.
\1588\ SERTP Sponsors Initial Comments at 30.
---------------------------------------------------------------------------
709. Kentucky Commission Chair Chandler argues against SERTP
Sponsors' comments that suggest that integrated resource plan/request
for proposal processes already consider four of the proposed categories
of
[[Page 49395]]
benefits included in the NOPR. Kentucky Commission Chair Chandler
contends that the integrated resource planning/request for proposal
process can only address these four categories on a utility-by-utility
basis and, thus, is unable to plan for transmission facilities across
utilities or transmission planning regions by nature.\1589\
---------------------------------------------------------------------------
\1589\ Kentucky Commission Chair Chandler Reply Comments at 7.
---------------------------------------------------------------------------
710. Some commenters advocate for or against requiring transmission
providers to consider other specific lists, categories, or combinations
of benefits, arguing that such approaches reduce possible duplication
of benefits, increase flexibility, and/or focus on benefits they
believe are most important.\1590\ PIOs, for example, assert that some
commenters who are opposed to the list of benefits in the NOPR
nonetheless agree that transmission planners should quantify broad
categories of benefits to plan effectively.\1591\ AEP states that some
benefits are more difficult to calculate than others and argues that
the minimum set of benefits it recommends appropriately balances the
significance of each type of benefit with the difficulty of quantifying
that benefit.\1592\
---------------------------------------------------------------------------
\1590\ ACEG Reply Comments at 6-7; AEE Reply Comments at 25-26;
AEP Initial Comments at 6, 23-25; California Commission Initial
Comments at 31-34; Certain TDUs Reply Comments at 1-2; Entergy
Initial Comments at 21; GridLab Initial Comments at 27; Joint
Consumer Advocates Initial Comments at 11; PIOs Reply Comments at 7-
9; PJM Initial Comments at 94-96; PPL Initial Comments at 14.
\1591\ PIOs Reply Comments at 7-8 (citing Entergy Initial
Comments at 21; Exelon Initial Comments at 15).
\1592\ AEP Initial Comments at 23.
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711. AEP and GridLab argue that many of the benefits listed in the
NOPR measure or identify the same type of benefit and therefore argue
that the Commission should group similar benefits together into
categories to avoid double-counting.\1593\ Specifically, AEP and
GridLab propose that the production cost savings and access to lower-
cost generation benefits be grouped into a required category.\1594\ In
addition, AEP states that the reduced loss of load probability, reduced
planning reserve margin, capacity cost benefits from reduced peak
energy losses, and deferred capacity investments benefits should be
combined into one required category.\1595\
---------------------------------------------------------------------------
\1593\ AEP Initial Comments at 23-24; GridLab Initial Comments
at 27.
\1594\ AEP Initial Comments at 25; GridLab Initial Comments at
27.
\1595\ AEP Initial Comments at 25.
---------------------------------------------------------------------------
712. GridLab and PJM contend that the Commission should combine the
benefits of reduced loss of load probability and deferred generation
capacity investment into a single category of benefits.\1596\ PJM
further argues that the Commission should combine the benefits of
mitigation of extreme events and mitigation of weather and load
uncertainty.\1597\
---------------------------------------------------------------------------
\1596\ GridLab Initial Comments at 27; PJM Initial Comments at
95.
\1597\ PJM Initial Comments at 94.
---------------------------------------------------------------------------
713. California Commission recommends that to capture the benefits
of transmission infrastructure, the Commission should require
transmission providers to assess benefits within the following six
benefit categories: (1) production cost benefits; (2) emissions
reductions benefits; (3) generation capital cost benefits; (4) risk
mitigation benefits; (5) resource adequacy benefits; and (6) resilience
benefits. California Commission states that such a requirement would
promote greater uniformity in how the benefits of regional (and
interregional) transmission projects are evaluated, reducing potential
disputes over cost allocation.\1598\ However, California Commission
argues, the Commission should allow transmission providers, in
consultation with Relevant State Entities, to define each identified
benefit and determine how to quantify it.\1599\ To ensure that
customers are protected from speculative transmission development and
unreasonably high costs, California Commission concludes that the
Commission should require transmission providers to demonstrate on
compliance that they identified and defined benefits within each of the
required benefit categories and determined appropriate quantification
methods through a transparent public process.\1600\
---------------------------------------------------------------------------
\1598\ California Commission Initial Comments at 33.
\1599\ Id. at 28-29.
\1600\ Id. at 34-35.
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714. Joint Consumer Advocates state that the following categories
of benefits should be included in Long-Term Regional Transmission
Planning: (1) production cost savings; (2) avoided or deferred
reliability transmission facilities; and (3) aging transmission
infrastructure replacement.\1601\
---------------------------------------------------------------------------
\1601\ Joint Consumer Advocates Initial Comments at 11.
---------------------------------------------------------------------------
715. AEE notes that some commenters propose that the Commission
adopt a smaller set of benefit categories.\1602\ AEE states that while
there may be value in considering these proposals, they miss important
benefits such as increased competition, market liquidity, and increased
resilience from mitigation of extreme weather events effects and system
contingencies.\1603\ Thus, AEE recommends that the Commission adopt as
mandatory the full set of 12 benefits listed in the NOPR but allow a
transmission provider to demonstrate that an alternative set of
benefits captures all the benefits of transmission in its transmission
planning region.
---------------------------------------------------------------------------
\1602\ AEE Reply Comments at 25-26 (citing PJM Initial Comments
at 93-96; California Commission Initial Comments at 32; New Jersey
Commission Initial Comments at 13-14).
\1603\ Id.
---------------------------------------------------------------------------
716. A few commenters offer categories of benefits while noting the
importance of regional flexibility.\1604\ ACEG notes widespread support
for the Commission to require certain categories of minimum benefits
and requests flexibility for transmission providers to address these
categories in accordance with regional needs. ACEG states that
considering categories of benefits will reduce the risk of double-
counting or miscalculating benefits and allow flexibility to apply
specific benefits best suited to each transmission planning
region.\1605\
---------------------------------------------------------------------------
\1604\ ACEG Reply Comments at 6-7; Entergy Initial Comments at
21.
\1605\ ACEG Reply Comments at 6-7 (citing Entergy Initial
Comments at 21; AEP Initial Comments at 23-27; Exelon Initial
Comments at 15-16).
---------------------------------------------------------------------------
717. In addition to concerns expressed by commenters in the context
of the combinations of benefits proposed above, other commenters
express concern regarding the potential for double-counting of benefits
if transmission providers are required to consider certain
benefits.\1606\ For example, NRECA asserts that accounting for
increased competition and increased market liquidity would risk double-
counting benefits,\1607\ and Utah Division of Public Utilities argues
that accounting for both reduction in loss of load probability and
mitigation of extreme events and system contingencies would result in
double-counting.\1608\ Clean Energy Buyers ask that the Commission
require transmission providers to explain how they will avoid double-
counting issues,\1609\ while ISO-NE seeks more information from the
Commission regarding which benefits the Commission believes are
redundant.\1610\
---------------------------------------------------------------------------
\1606\ See, e.g., APPA Initial Comments at 32; City of New
Orleans Council Initial Comments at 10-11; Louisiana Commission
Reply Comments at 10; Michigan Commission Initial Comments at 6;
Nevada Commission Initial Comments at 10-11; Utah Division of Public
Utilities Initial Comments at 8; Vistra Initial Comments at 16-17.
\1607\ NRECA Initial Comments at 45 (citing NRECA Initial
Comments, attach. at 16-17).
\1608\ Utah Division of Public Utilities Initial Comments at 8.
\1609\ Clean Energy Buyers Initial Comments at 20-21.
\1610\ ISO-NE Initial Comments at 34.
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[[Page 49396]]
718. A few commenters state that the list of 12 benefits in the
NOPR does not risk double-counting.\1611\ DC and MD Offices of People's
Counsel concludes that each benefit in this list is mutually exclusive,
noting that some transmission providers may wish to mix and match these
benefits because their modeling tools may not disaggregate them in
exactly the way described in the NOPR.\1612\ MISO notes that there are
instances where one benefit can enable other benefits and that adopting
a calculation method that recognizes that complementary behavior can
yield incremental value.\1613\ For example, MISO states, a calculation
approach that distinguishes between the benefit of enabling resource
expansion and the benefit of increased transmission capability provided
by regional transmission projects would produce unique benefits.\1614\
---------------------------------------------------------------------------
\1611\ DC and MD Offices of People's Counsel Initial Comments at
20; MISO Initial Comments at 50.
\1612\ DC and MD Offices of People's Counsel Initial Comments at
20.
\1613\ MISO Initial Comments at 50.
\1614\ Id.
---------------------------------------------------------------------------
c. Commission Determination
719. We adopt the NOPR proposal, with modification, to require
transmission providers in each transmission planning region to measure
a set of seven required benefits (required benefits) for Long-Term
Regional Transmission Facilities under each Long-Term Scenario as part
of Long-Term Regional Transmission Planning. Furthermore, we adopt the
NOPR proposal, with modification, to require transmission providers in
each transmission planning region to use these measured benefits to
evaluate Long-Term Regional Transmission Facilities, as discussed below
in the Evaluation and Selection of Regional Transmission Facilities
section. This Evaluation of the Benefits of Regional Transmission
Facilities section discusses this final order's requirements with
regard to transmission providers' measurement and use of benefits in
evaluating Long-Term Regional Transmission Facilities; however, as
discussed in the Development of Long-Term Scenarios section, these same
benefits should help to inform transmission providers' identification
of Long-Term Transmission Needs.\1615\
---------------------------------------------------------------------------
\1615\ See supra Long-Term Regional Transmission Planning,
Development of Long-Term Scenarios section.
---------------------------------------------------------------------------
720. The seven required benefits that we require transmission
providers to measure and use in Long-Term Regional Transmission
Planning, which we describe in greater detail in the discussion of the
individual benefits below, are: (1) avoided or deferred reliability
transmission facilities and aging infrastructure replacement; (2) a
benefit that can be characterized and measured as either reduced loss
of load probability or reduced planning reserve margin; (3) production
cost savings; (4) reduced transmission energy losses; (5) reduced
congestion due to transmission outages; (6) mitigation of extreme
weather events and unexpected system conditions; and (7) capacity cost
benefits from reduced peak energy losses.\1616\
---------------------------------------------------------------------------
\1616\ We discuss modifications to Benefit 6 from its
description in the NOPR in the Benefit 6 determination section.
---------------------------------------------------------------------------
721. We find that these requirements are necessary to ensure that
transmission providers can evaluate Long-Term Regional Transmission
Facilities to determine whether they more efficiently or cost-
effectively address Long-Term Transmission Needs. Specifically, we find
that transmission providers must measure these seven required benefits
in each Long-Term Scenario because, as discussed further in the
Evaluation and Selection of Regional Transmission Facilities section,
evaluating Long-Term Regional Transmission Facilities for potential
selection necessarily involves the consideration of the benefits
measured in each Long-Term Scenario and sensitivity to help address
uncertainty over the 20-year transmission planning horizon and to
maximize benefits accounting for costs over time. As such, we find
that, to ensure just and reasonable Commission-jurisdictional rates,
transmission providers must measure, at minimum, the set of seven
required benefits in Long-Term Regional Transmission Planning and then
use them to evaluate Long-Term Regional Transmission Facilities for
selection.
722. Although the Commission did not propose to require the use of
any specific benefits in the NOPR, the Commission sought comment on
whether it should require transmission providers to use some or all of
the potential benefits described in the NOPR as a minimum set of
benefits in Long-Term Regional Transmission Planning. The record in
this proceeding shows that, in order to ensure just and reasonable
Commission-jurisdictional transmission rates, it is necessary to
require transmission providers to measure and use in Long-Term Regional
Transmission Planning a set of particular benefits so that they may
identify, evaluate, and select regional transmission facilities that
are more efficient or cost-effective transmission solutions to Long-
Term Transmission Needs. We find that the benefits that Long-Term
Regional Transmission Facilities generally provide extend beyond the
benefits that transmission providers currently consider as part of
their regional transmission planning and cost allocation processes, and
without consideration of such benefits, Long-Term Regional Transmission
Planning cannot be reasonably expected to identify, evaluate, and
select more efficient or cost-effective regional transmission solutions
to address Long-Term Transmission Needs.
723. By requiring the measurement and use of the seven enumerated
benefits in Long-Term Regional Transmission Planning, we ensure that
transmission providers will consider a sufficiently broad range of
benefits when determining whether to select a Long-Term Regional
Transmission Facility as a more efficient or cost-effective regional
transmission solution to Long-Term Transmission Needs. In contrast,
adopting the more flexible approach proposed in the NOPR would not
address the identified deficiencies in existing regional transmission
planning and cost allocation processes because such an approach would
fail to ensure that transmission providers consider the broader set of
benefits provided by, and the beneficiaries receiving the benefits of,
Long-Term Regional Transmission Facilities, and thus, may fail to
identify the potentially more efficient or cost-effective regional
transmission solution. We find that failing to use the set of benefits
that we require in this final order to evaluate Long-Term Regional
Transmission Facilities for potential selection could render resulting
Commission-jurisdictional rates unjust and unreasonable. We find that
not requiring transmission providers to use certain benefits to
evaluate Long-Term Regional Transmission Facilities would be expected
to lead to relatively inefficient and less cost-effective transmission
development, as Long-Term Regional Transmission Facilities that provide
significant net benefits may not be selected.\1617\ In addition, we
find that the transparency provided by requiring consideration of a
sufficiently broad and common set of benefits will help to ensure the
costs of Long-Term Regional Transmission Facilities are allocated to
beneficiaries in a manner that is at least
[[Page 49397]]
roughly commensurate with the benefits they derive from them.\1618\
---------------------------------------------------------------------------
\1617\ See Clean Energy Associations Initial Comments at 20
(citing The Brattle Group, Transmission Planning and Benefit-Cost
Analyses, at 26 (Apr. 2021)).
\1618\ ICC v. FERC I, 576 F.3d at 477; Order No. 1000, 136 FERC
] 61,051 at PP 622, 639 (requiring costs of regional transmission
facilities to be allocated in a manner that is at least roughly
commensurate with estimated benefits).
---------------------------------------------------------------------------
724. We appreciate arguments made by certain commenters that
failure to incorporate identifiable benefits risks skewing the
evaluation process against developing needed and beneficial Long-Term
Regional Transmission Facilities because transmission providers would
consider all of the costs of such transmission facilities without
similarly considering many important benefits that they may
provide.\1619\ However, we are also cognizant of concerns about
duplication of benefits and difficulty of measuring certain benefits.
In this final order, rather than requiring transmission providers to
measure and use all 12 benefits enumerated in the NOPR, we only require
transmission providers to measure and use seven specific benefits that
have a proven track record, can be discretely measured, and are
unlikely to cause duplication. We find that the modification to the
NOPR proposal to require the measurement and use of these seven
benefits to evaluate Long-Term Regional Transmission Facilities, as
discussed above, resolves concerns about important benefits being
omitted from Long-Term Regional Transmission Planning, as well as
challenges raised concerning duplication and measurement of certain
benefits.
---------------------------------------------------------------------------
\1619\ See Enel Initial Comments at 3.
---------------------------------------------------------------------------
725. We acknowledge that many commenters do not favor requiring the
use of particular benefits. In response, we emphasize that a set of
common benefits and a requirement to measure and use those benefits in
Long-Term Regional Transmission Planning will ensure just and
reasonable rates, as discussed above.\1620\ Specifically, unless
transmission providers consider a sufficiently broad range of benefits
when determining whether to select a Long-Term Regional Transmission
Facility as a more efficient or cost-effective regional transmission
solution to Long-Term Transmission Needs, they may fail to identify the
more efficient or cost-effective regional transmission solution,
resulting in relatively inefficient or less cost-effective transmission
development.
---------------------------------------------------------------------------
\1620\ See ACORE Initial Comments at 12; ACORE Reply Comments at
6; ACORE Supplemental Comments at 1; AEE Initial Comments at 8, 25;
AEP Initial Comments at 6, 23-25; Breakthrough Energy Initial
Comments at 4, 21-22; Business Council for Sustainable Energy
Initial Comments at 2, 5; Certain TDUs Initial Comments at 11-12;
Clean Energy Buyers Reply Comments at 8-9; Concerned Scientists
Reply Comments at 7-10; Cypress Creek Reply Comments at 7-8; DC and
MD Offices of People's Counsels Reply Comments at 3, 7-8; ELCON
Initial Comments at 15; Enel Initial Comments at 3; Environmental
Groups Supplemental Comments at 2; Environmental Legislators Caucus
Supplemental Comments at 1; Exelon Initial Comments at 16: Grid
United Initial Comments at 2; Handy Law Initial Comments at 8; US
House Republicans Supplemental Comments at 1; Indicated US Senators
and Representatives Initial Comments at 2; ITC Initial Comments at
5, 18-22; Interwest Initial Comments at 12; Interwest Reply Comments
at 6-7; Joint Consumer Advocates Initial Comments at 11; Kentucky
Commission Chair Chandler Reply Comments at 7; Minnesota State
Entities Initial Comments at 6; New England for Offshore Wind
Initial Comments at 5; New Jersey Commission Initial Comments at 11-
14; Pacific Northwest State Agencies Initial Comments at 16-17; PIOs
Initial Comments at 27-28; PIOs Reply Comments at 7-8; Policy
Integrity Initial Comments at 27; Policy Integrity Supplemental
Comments at 4; R Street Initial Comments at 9; RMI Initial Comments
at 1; RMI Supplemental Comments at 2; SEIA Initial Comments at 16-
17; Southeast PIOs Initial Comments at 50; Southeast PIOs Reply
Comments at 27-28; ; US DOE Initial Comments at 30-33; US Senator
Schumer Supplemental Comments at 1-2; US Senator Whitehouse
Supplemental Comments at 2; US Senators Supplemental Comments at 2;
WATT Coalition Initial Comments at 7.
---------------------------------------------------------------------------
726. We note that some commenters request flexibility to use
different benefits, such as SPP, which states that the effort required
to incorporate additional benefit metrics into its current regional
transmission planning process cannot be accommodated within its current
process timeline.\1621\ As discussed in the Implementation and
Compliance sections of this final order, we require transmission
providers to propose on compliance a date, no later than one year from
the date on which initial filings to comply with this final order are
due, on which they will commence the first Long-Term Regional
Transmission Planning cycle (unless additional time is needed to align
the first Long-Term Regional Transmission Planning cycle with existing
transmission planning cycles), and thus transmission providers will not
be required to immediately implement this reform.
---------------------------------------------------------------------------
\1621\ SPP Initial Comments at 18.
---------------------------------------------------------------------------
727. Some commenters argue that the requirement to measure and use
these benefits will increase costs and require additional effort, and
that the Commission has presented insufficient evidence that this
requirement will produce the desired benefits.\1622\ Commenters who
express such concerns did not provide persuasive evidence to suggest
that requiring the measurement and use of a required set of benefits
would be unduly burdensome. While measuring these benefits may impose a
degree of burden on some transmission providers, the requirement for
transmission providers to measure and use the seven required benefits
in Long-Term Regional Transmission Planning is necessary to ensure that
rates are just and reasonable. Specifically, absent a requirement that
transmission providers measure and use a sufficiently broad range of
benefits of Long-Term Regional Transmission Facilities when evaluating
them for potential selection, transmission providers may not identify,
evaluate, and select more efficient or cost-effective regional
transmission solutions to Long-Term Transmission Needs, which may lead
to relatively inefficient or less cost-effective transmission
development. Further, we believe that experience gained by transmission
providers will over time allow them to perform the necessary
measurements more efficiently. Moreover, in our discussion of each
required benefit below, we provide a description, for several of the
required benefits, of at least one manner in which transmission
providers could measure each required benefit. Finally, commenters also
did not provide persuasive evidence that the burdens of measuring and
using a required set of benefits outweigh the benefits of using these
benefits in Long-Term Regional Transmission Planning. We therefore find
that any burdens of measuring and using the seven required benefits in
Long-Term Regional Transmission Planning are outweighed by the
identification, evaluation, and selection of more efficient or cost-
effective Long-Term Regional Transmission Facilities to address Long-
Term Transmission Needs.\1623\
---------------------------------------------------------------------------
\1622\ E.g., Dominion Initial Comments at 34-35.
\1623\ See Clean Energy Associations Initial Comments at 20
(``Not requiring benefits to be evaluated could lead to higher costs
in the long-term, and, thus, unjust and unreasonable rates.'').
---------------------------------------------------------------------------
728. Another common concern expressed by some commenters is that
requiring a minimum set of benefits would undermine regional
flexibility.\1624\ We conclude that it would be inappropriate to
provide flexibility not to consider this required set of benefits in
Long-Term Regional Transmission Planning because, as described above,
requiring the measurement and use of these benefits ensures that
transmission providers are able to identify, evaluate, and select
regional transmission solutions to more efficiently or cost-effectively
address Long-Term Transmission Needs, and thereby ensures just and
reasonable rates. We therefore disagree with Dominion that transmission
providers should be permitted to identify initial benefits that they
will consider in
[[Page 49398]]
conducting Long-Term Regional Transmission Planning but retain
flexibility in applying such benefits to each transmission provider's
individual circumstances.\1625\ However, as we discuss further below,
we are providing flexibility to transmission providers regarding how
they will measure each of the required benefits.
---------------------------------------------------------------------------
\1624\ E.g., Entergy Initial Comments at 21.
\1625\ Dominion Initial Comments at 34.
---------------------------------------------------------------------------
729. Transmission providers may also propose to measure and use
additional benefits in Long-Term Regional Transmission Planning, as
discussed below in the Other Benefits section. This approach provides
flexibility to transmission providers in how they implement the
requirement to measure and use the required set of benefits in Long-
Term Regional Transmission Planning, while maintaining the baseline
requirement that they measure and use all seven benefits included in
that required set of benefits, in order to ensure that rates remain
just and reasonable. Requiring all transmission providers to measure
and use a required set of benefits will help to improve interregional
transmission coordination among different transmission planning
regions, as noted by commenters.\1626\
---------------------------------------------------------------------------
\1626\ Breakthrough Energy Initial Comments at 22-23; California
Commission Initial Comments at 33; Grid United Initial Comments at
3; Policy Integrity Initial Comments at 27-28; US DOE Initial
Comments at 31-32.
---------------------------------------------------------------------------
730. In addition, as more fully described below, we also find that
the seven benefits we require are not overly burdensome to calculate.
We address such concerns for individual benefits in more detail within
the determination section on each benefit below.
731. Some commenters assert that some benefits are only appropriate
for use in RTO/ISO transmission planning regions.\1627\ We believe that
all seven required benefits can be calculated in both RTO/ISO and non-
RTO/ISO transmission planning regions, as noted by ACEG.\1628\ In
particular, we note that all seven required benefits have either been
approved for use in regional transmission planning in at least one non-
RTO/ISO transmission planning region or may be implemented by building
upon the modeling or techniques used to measure benefits in RTO/ISO or
non-RTO/ISO regions, or both.
---------------------------------------------------------------------------
\1627\ Pacific Northwest Utilities Initial Comments at 8-10;
SERTP Sponsors Initial Comments 29-30; Southern Initial Comments at
25-27.
\1628\ ACEG Initial Comments at 48.
---------------------------------------------------------------------------
732. As described below, in the NOPR, the Commission noted that it
approved the use of production cost savings (i.e., Benefit 3) to
evaluate Order No. 1000 economic transmission projects in a non-RTO/ISO
transmission planning region.\1629\ We note that, as measurements of
reduced production costs outside of normal conditions, the measurement
methods for Benefit 5, Reduced Congestion Due to Transmission Outages,
and Benefit 6, Mitigation of Extreme Weather Events and Unexpected
System Conditions, may be built upon the modeling used to measure
Benefit 3. Separately, the Commission has accepted use of benefits in
evaluating regional transmission facilities in Order No. 1000 regional
transmission planning processes akin to Benefit 2(a), Reduced Loss of
Load Probability,\1630\ and Benefit 4, Reduced Transmission Energy
Losses, in non-RTO/ISO transmission planning regions.\1631\ In the
NOPR, the Commission likewise noted that it has accepted accounting for
the avoided costs (i.e., Benefit 1) as part of a method for identifying
beneficiaries and allocating costs in almost all the regional cost
allocation methods in non-RTO/ISO transmission planning regions.\1632\
With respect to Final Order Benefit 7 (i.e., capacity cost benefits
from reduced peak energy losses), the avoided costs associated with
this benefit are comparable across RTO/ISO and non-RTO/ISO transmission
planning regions. Transmission providers in all transmission planning
regions incur capital costs to meet installed generation requirements
and to maintain reliable operations. Transmission expansions may help
reduce peak energy losses, and under this benefit, result in capital
cost savings associated with the reduction in installed generation
requirements.
---------------------------------------------------------------------------
\1629\ NOPR, 179 FERC ] 61,028 at P 201 (citing Pub. Serv. Co.
of Colo., 142 FERC ] 61,206, at P 314 (2013)).
\1630\ PacifiCorp, 147 FERC ] 61,057, at PP 133-134, 141-143
(2014); Pub. Serv. Co. of Colo., 142 FERC ] 61,206 at P 314.
\1631\ PacifiCorp, 147 FERC ] 61,057 at PP 132, 134, 141-143.
\1632\ NOPR, 179 FERC ] 61,028 at PP 189-190 & n.326 (citing
Order No. 1000, 136 FERC ] 61,051 at P 81).
---------------------------------------------------------------------------
733. We disagree with commenters that express concerns that
required benefits would conflict with state-regulated integrated
resource planning processes.\1633\ As discussed in the Legal Authority
to Adopt Reforms for Long-Term Regional Transmission Planning section,
nothing in this final order infringes on the states' reserved authority
under FPA section 201.
---------------------------------------------------------------------------
\1633\ SERTP Sponsors Initial Comments at 30; Southern Initial
Comments at 24-26.
---------------------------------------------------------------------------
734. Entergy argues that the Commission should recognize that not
all benefits are created equal for all jurisdictions and that some
states will want transmission projects that actually reduce customer
bills to have clear priority.\1634\ We believe that the required
measurement and use of the required set of benefits can accommodate
such preferences. Our requirements ensure that all benefits are
measured transparently and considered in selection decisions. In
addition, our required set of benefits captures considerations such as
production cost savings that can flow through to customer bills. PJM,
for example, notes that lower production costs will generally also
reduce market prices for electricity as lower-cost suppliers will set
market clearing prices more frequently than without the transmission
project.\1635\ We note that while this final order requires the
measurement and use of the required set of benefits, it is the
evaluation process, including selection criteria, that transmission
providers propose on compliance that will inform which Long-Term
Regional Transmission Facilities are selected. Transmission providers
may propose an evaluation process, including selection criteria, that
reflect regional preferences as long as those criteria meet the
requirements set forth below in the Evaluation and Selection of Long-
Term Regional Transmission Facilities section.
---------------------------------------------------------------------------
\1634\ Entergy Initial Comments at 21.
\1635\ PJM Initial Comments at 95.
---------------------------------------------------------------------------
735. ISO-NE notes that the Commission sought information on
potential double-counting of benefits and requests that the Commission
clarify which benefits the Commission believes are redundant.\1636\ We
believe that the seven benefits that we include in the required set of
benefits that transmission providers must measure and use in Long-Term
Regional Transmission Planning are distinct enough that they will not
overlap in a way that results in double-counting. Nonetheless, to the
extent that transmission providers are concerned that any possibility
of double-counting remains, we provide transmission providers with
flexibility on the measurement of such benefits and expect that
transmission providers can use such flexibility to develop methods for
measuring each required benefit that address those concerns.
---------------------------------------------------------------------------
\1636\ ISO-NE Initial Comments at 34.
---------------------------------------------------------------------------
736. Some commenters urge the Commission to adopt a combination or
categorical approach toward benefits, under which required benefits
would be grouped under certain categories or combinations.\1637\ We
decline to adopt
[[Page 49399]]
this approach, largely because our analysis and review of the record
suggests that such an approach could reduce transparency regarding the
benefits that we are requiring. For example, in some cases adopting a
combination or categories approach could obfuscate individual benefit
calculations within a category, making it less clear to interested
parties what specific benefits a Long-Term Regional Transmission
Facility may provide. Additionally, we find that these seven benefits
merit individual measurement and evaluation.
---------------------------------------------------------------------------
\1637\ ACEG Reply Comments at 6-7; AEP Initial Comments at 23-
25; California Commission Initial Comments at 33; Entergy Initial
Comments at 21; GridLab Initial Comments at 27; Joint Consumer
Advocates Initial Comments at 11; PJM Initial Comments at 94-96.
---------------------------------------------------------------------------
737. Northwest and Intermountain and NYISO ask that the final order
confirm that the 12 illustrative benefits described in the NOPR are not
exhaustive.\1638\ First, we confirm that the list of 12 illustrative
benefits described in the NOPR is not an exhaustive list of the
potential benefits of Long-Term Regional Transmission Facilities.
Second, we reiterate that the required set of benefits adopted in this
final order is a subset of the benefits listed in the NOPR, as modified
in the discussions below. Transmission providers may be aware of
additional benefits beyond those included in the required set of
benefits, or the 12 illustrative benefits described in the NOPR, and we
provide them with the flexibility to propose to measure and use
additional benefits in Long-Term Regional Transmission Planning so long
as they do so in a manner that is consistent with transmission
providers' obligations under Order No. 890 and Order No. 1000
transmission planning principles to be open and transparent as to their
transmission planning processes. In particular, the evaluation process
must result in a determination that is sufficiently detailed for
stakeholders to understand why a particular Long-Term Regional
Transmission Facility (or portfolio of such Facilities) was selected or
not selected to address Long-Term Transmission Needs.\1639\ This
necessarily means that stakeholders must understand which benefits
transmission providers considered in the evaluation process, including
any beyond the seven benefits that we require transmission providers to
include in their OATTs. We find that this transparency strikes an
appropriate balance between ensuring that transmission providers
measure and use the seven required benefits in Long-Term Regional
Transmission Planning and allowing flexibility for transmission
providers to use additional benefits that they believe will reasonably
reflect the benefits of a Long-Term Regional Transmission Facility or
Facilities in their transmission planning regions.
---------------------------------------------------------------------------
\1638\ Northwest and Intermountain Initial Comments at 16; NYISO
Initial Comments at 39.
\1639\ See infra Evaluation and Selection of Long-Term Regional
Transmission Facilities section.
---------------------------------------------------------------------------
738. OMS urges the Commission to clarify that transmission
providers will have sufficient flexibility to use different sets of
benefit metrics in different transmission planning cycles.\1640\ We
clarify that transmission providers must use the required set of
benefits to evaluate Long-Term Regional Transmission Facilities in
every Long-Term Regional Transmission Planning cycle, and we discuss
the use of other benefits to evaluate Long-Term Regional Transmission
Facilities in the Other Benefits section of this final order.
---------------------------------------------------------------------------
\1640\ OMS Initial Comments at 8.
---------------------------------------------------------------------------
739. Some commenters suggest that the Commission allow transmission
providers to use a screening approach that initially screens benefit
categories for significance before investing staff resources and
modeling work to provide a detailed quantification.\1641\ Clean Energy
Buyers similarly argue that, at a minimum, the Commission should
require that transmission providers screen for all 12 benefits
described in the NOPR and quantify them accordingly.\1642\ We find such
screening approaches, as advocated by some commenters, to be
inconsistent with the approach we adopt in this final order, which
requires measurement and use of each of the seven required benefits in
Long-Term Regional Transmission Planning, and we are concerned that
permitting the use of screens could undermine this requirement. We
therefore do not allow transmission providers to use a screening
approach when measuring the seven required benefits.
---------------------------------------------------------------------------
\1641\ ACEG Initial Comments at 7, 33; ACORE Initial Comments at
12; Breakthrough Energy Initial Comments at 22; CTC Global Initial
Comments at 9; Interwest Initial Comments at 12-13; WATT Coalition
Initial Comments at 7.
\1642\ Clean Energy Buyers Initial Comments at 20-21.
---------------------------------------------------------------------------
2. Required Benefits
a. The Seven Required Benefits
i. Benefit 1: Avoided or Deferred Reliability Transmission Facilities
and Aging Transmission Infrastructure Replacement
(a) NOPR Description
740. The Commission described this benefit in the NOPR as the
reduced costs of avoided or delayed transmission investment otherwise
required to address reliability needs or replace aging transmission
facilities. The Commission stated that, recognizing that regional
transmission planning could lead to the development of transmission
facilities that span the service territories of multiple transmission
providers, which in turn would obviate the need for transmission
facilities that would otherwise be identified in multiple local
transmission plans, the Commission has accepted accounting for such
``avoided costs'' as part of a method for identifying beneficiaries and
allocating costs in almost all the regional cost allocation methods in
non-RTO/ISO regions.\1643\ The Commission noted that, in using this
method, transmission providers in a transmission planning region
determine the beneficiaries of a regional transmission facility or
portfolio of facilities by identifying the local and regional
transmission facilities that a new proposed regional transmission
facility or portfolio of facilities would displace. The Commission
described the method as defining the benefits of the regional
transmission facility or facilities as the costs that transmission
providers in the transmission planning region ``avoid'' because they no
longer need to build the displaced local and regional transmission
facilities. Further, the Commission stated that the method allocates
costs among transmission providers whose local or regional transmission
facilities the new proposed regional transmission facility or
facilities would displace in proportion to their share of the total
benefits (i.e., the total avoided costs). If the new proposed regional
transmission facility or facilities do not displace any local or
regional transmission facilities in existing local or regional
transmission plans, the Commission discussed that the avoided cost
method determines the benefits of the applicable facilities by
considering the costs of local or regional transmission facilities that
would otherwise be needed to meet the same need that the new proposed
regional transmission facility will meet.\1644\ The Commission noted
that, in calculating this benefit, transmission providers in each
transmission planning region could first identify transmission
facilities that could defer or replace an identified reliability
transmission solution. Avoided cost benefits could be calculated by
comparing the cost of
[[Page 49400]]
transmission facilities required to address the reliability need
without the proposed regional transmission facility to the cost of
transmission facilities needed to address the reliability need assuming
the regional transmission solution were in place.\1645\
---------------------------------------------------------------------------
\1643\ NOPR, 179 FERC ] 61,028 at PP 189-190 (citing Order No.
1000, 136 FERC ] 61,051 at P 81).
\1644\ NOPR, 179 FERC ] 61,028 at P 190 (citing S.C. Elec. & Gas
Co., 143 FERC ] 61,058, at P 232 (2013)).
\1645\ Id. P 191 (citing Brattle-Grid Strategies Oct. 2021
Report at 37).
---------------------------------------------------------------------------
741. The Commission noted that Benefit 1 could also include the
separate benefits stream caused by a deferral of replacement of other
transmission facilities through identification and selection of a
transmission facility or facilities. This could be measured through
calculation of the present value savings for the period of deferral of
additional replacement transmission facilities multiplied by their
estimated capital cost.\1646\ The Commission also noted that a number
of transmission providers already evaluate the avoided or deferred
costs of reliability transmission projects. For example, SPP uses a
power flow model to analyze the ability of potential economic and
Public Policy Requirements transmission facilities to meet the same
thermal reliability needs addressed by a potential reliability
transmission facility. The costs of these avoided or delayed
reliability transmission facilities are used to determine the
reliability benefit of the potential economic or Public Policy
Requirements transmission facilities.\1647\ The Commission stated that
transmission providers could also use avoided costs to calculate the
benefits of replacing aging transmission facilities. The Commission
provided NYISO as an example, which estimates the benefits associated
with the replacement of aging transmission facilities by quantifying
the savings of not having to refurbish the facilities in the
future.\1648\
---------------------------------------------------------------------------
\1646\ Id. P 192.
\1647\ Id. P 193 (citing SPP, SPP Benefit Metrics Manual, SPP
Engineering, at 15 (Nov. 6, 2020)).
\1648\ Id. P 193 (citing The Brattle Group, Benefit-Cost
Analysis of Proposed New York AC Transmission Upgrades, at 114
(Sept. 15, 2015)).
---------------------------------------------------------------------------
(b) Comments
742. A number of commenters support mandating consideration of
Benefit 1.\1649\ ACEG, for example, supports inclusion of this benefit,
asserting that reliability considerations and replacing aging assets
are responsible for almost all current transmission spending.\1650\
However, MISO states that, when capturing avoided transmission
investment benefits, care must be exercised to avoid the counting of
benefits associated with facility overloads that are identified in
reliability studies and directly addressed by regional transmission
projects. MISO indicates that this approach is necessary because the
adjusted production cost savings benefits already reflect the
congestion associated with these facility overloads.\1651\ Southern
states that this benefit would likely prove workable under its non-RTO/
ISO construct because SERTP Sponsors' regional and interregional
transmission planning and cost allocation processes already incorporate
the benefit of ``avoided costs.'' \1652\
---------------------------------------------------------------------------
\1649\ Acadia Center and CLF Initial Comments at 21-22; ACEG
Initial Comments at 32; ACORE Initial Comments at 12; AEE Reply
Comments at 25; AEP Initial Comments at 25 (including Benefit 1 in
its recommended minimum set of benefit categories); Amazon Initial
Comments at 5; Breakthrough Energy Initial Comments at 21-22;
Certain TDUs Reply Comments at 1-2; Clean Energy Associations
Initial Comments at 19-20; DC and MD Offices of People's Counsel
Initial Comments at 19-20; ENGIE Reply Comments at 3; Hannon
Armstrong Initial Comments at 3; Interwest Initial Comments at 12-
14; National and State Conservation Organizations Initial Comments
at 1; New Jersey Commission Initial Comments at 11-13; Pine Gate
Initial Comments at 34-37; PIOs Initial Comments at 38-41; PJM
Initial Comments at 96; RMI Initial Comments at 1; SEIA Initial
Comments at 16; Southeast PIOs Initial Comments at 50; US DOE
Initial Comments at 31-32.
\1650\ ACEG Initial Comments at 34-35.
\1651\ MISO Initial Comments at 50.
\1652\ Southern Initial Comments at 25.
---------------------------------------------------------------------------
743. Several commenters oppose or express concerns with mandating
consideration of Benefit 1.\1653\ West Virginia Commission argues that
calculation of this benefit requires evidence based on assumptions that
are difficult, if not impossible, to quantify in advance.\1654\ Xcel
states that benefit calculations can be different between the short-
term regional transmission planning process and Long-Term Regional
Transmission Planning and that, for example, it would likely be
unreasonable to determine reliability benefits in Long-Term Regional
Transmission Planning using the avoided cost of local reliability
solutions.\1655\
---------------------------------------------------------------------------
\1653\ Joint Consumer Advocates Initial Comments at 11; NARUC
Initial Comments at 22; West Virginia Commission Supplemental
Comments at 4; Xcel Initial Comments at 13.
\1654\ West Virginia Commission Supplemental Comments at 4.
\1655\ Xcel Initial Comments at 13.
---------------------------------------------------------------------------
744. NARUC states that, while Benefit 1 seems capable of
calculation, it carries with it a degree of risk if aging transmission
infrastructure continues to be operated. For instance, NARUC indicates
that some wildfires have been linked to deferred transmission
maintenance of aging infrastructure.\1656\ AEE responds by stating that
the Commission should clarify: (1) its expectations regarding its
calculation; and (2) that regional transmission built for inherently
economic or public policy purposes has, when installed, avoided
reliability cost benefits.\1657\ AEE argues that calculating the
benefits of avoided investment in reliability or replacement facilities
should not create an environment for continuously putting ``band aid''
fixes on aging systems that should instead be replaced to ensure
reliability and resilience.\1658\
---------------------------------------------------------------------------
\1656\ NARUC Initial Comments at 22.
\1657\ AEE Reply Comments at 26 (citing NARUC Initial Comments
at 22).
\1658\ Id.
---------------------------------------------------------------------------
(c) Commission Determination
745. We adopt the NOPR proposal, with modification, to require
transmission providers in each transmission planning region to measure
and use Benefit 1, Avoided or Deferred Reliability Transmission
Facilities and Aging Transmission Infrastructure Replacement, in Long-
Term Regional Transmission Planning. We adopt the NOPR's proposed
description of Benefit 1 as the reduced costs due to avoided or delayed
transmission investment otherwise required to address reliability needs
or replace aging transmission facilities. We find that requiring the
measurement and use of Benefit 1, as described, is necessary because
Long-Term Regional Transmission Facilities may obviate or delay the
need for reliability transmission facilities identified in the near
term, or the need for later replacements of aging transmission
infrastructure. Requiring transmission providers to measure and use the
benefits associated with avoiding or delaying such transmission needs
will help to ensure that, when conducting Long-Term Regional
Transmission Planning, transmission providers identify, evaluate, and
select Long-Term Regional Transmission Facilities that more efficiently
or cost-effectively address Long-Term Transmission Needs.
746. We note that a number of transmission providers already
evaluate avoided or deferred costs of reliability transmission
facilities. ACEG states that Benefit 1 reflects that reliability
considerations and replacing aging assets drive significant investment
in transmission and account for almost all current transmission
spending.\1659\ SPP employs a power flow model to analyze the ability
of potential economic and Public Policy Requirements transmission
facilities to meet the same thermal reliability needs addressed by a
[[Page 49401]]
potential reliability transmission facility, using the costs of these
avoided or delayed reliability transmission facilities to determine the
reliability benefit of the potential economic or Public Policy
Requirements transmission facilities.\1660\ Additionally, NYISO
estimates the benefits associated with the replacement of aging
transmission facilities by quantifying the savings of not having to
refurbish the facilities in the future.\1661\ We find that widespread
use of this benefit contradicts West Virginia Commission's assertion
that calculation of this benefit requires evidence based on assumptions
that are difficult, if not impossible, to quantify in advance, as well
as similar assertions by Xcel.\1662\
---------------------------------------------------------------------------
\1659\ ACEG Initial Comments at 34-35.
\1660\ NOPR, 179 FERC ] 61,028 at P 193 (citing SPP, SPP Benefit
Metrics Manual, SPP Engineering, at 15 (Nov. 6, 2020)).
\1661\ Id. (citing The Brattle Group, Benefit-Cost Analysis of
Proposed New York AC Transmission Upgrades, at 114 (Sept. 15,
2015)).
\1662\ West Virginia Commission Supplemental Comments at 4; Xcel
Initial Comments at 13.
---------------------------------------------------------------------------
747. We agree with NARUC and AEE that continued operation of aging
infrastructure can carry risks if it is not properly maintained.\1663\
We note that nothing in this final order restricts an incumbent
transmission provider from developing a local transmission facility to
meet its reliability needs or service obligations in its own retail
distribution service territory or footprint.\1664\ Such a solution
would not be subject to approval at the regional or interregional level
where the transmission provider does not seek to have it selected as a
regional transmission facility for purposes of cost allocation.\1665\
Moreover, nothing in this final order requires transmission providers
to keep transmission facilities in operation beyond their useful life.
We emphasize that transmission providers can use Benefit 1 to calculate
the costs that are avoided because replacements of local or regional
transmission facilities are no longer needed, or may be deferred, when
they are displaced by proposed new Long-Term Regional Transmission
Facilities.
---------------------------------------------------------------------------
\1663\ AEE Reply Comments at 26 (citing NARUC Initial Comments
at 22); NARUC Initial Comments at 22.
\1664\ Order No. 1000, 136 FERC ] 61,051 at PP 262, 329.
\1665\ Id. P 384.
---------------------------------------------------------------------------
ii. Benefit 2(a): Reduced Loss of Load Probability or Benefit 2(b):
Reduced Planning Reserve Margin
(a) NOPR Description
748. The Commission described this benefit in the NOPR as being
measured in one of two ways: (a) using reduced loss of load probability
or (b) reduced planning reserve margin. The Commission noted that,
because there is an overlap between reduced loss of load probability
benefits and reduced planning reserve margin benefits, a single
transmission facility can either reduce loss of load events if the
planning reserve margin is unchanged or allow for the reduction in
planning reserve margins if loss of load events remain constant, but
not both simultaneously.\1666\
---------------------------------------------------------------------------
\1666\ NOPR, 179 FERC ] 61,028 at P 194.
---------------------------------------------------------------------------
749. The Commission described Benefit 2(a) in the NOPR as reduced
frequency of loss of load events by providing additional pathways for
connecting generation resources with load in regions that can be
constrained by weather events and unplanned outages (if the planning
reserve margin is not changed despite lower loss of load events), as
well as improved physical reliability benefits by reducing the
likelihood of load shed events.\1667\ The Commission noted that
transmission investments, even those not made to satisfy a reliability
need, generally enhance the reliability of the transmission system by
increasing transfer capability, which, in turn, reduces the likelihood
that a transmission provider will be unable to serve its load due to a
shortage of generation over a given period. This enhancement in
reliability can be measured as a reduction in loss of load probability,
or the likelihood of system demand exceeding generation over a given
period. The Commission noted that one example of how a reduction of
loss of load probability benefit could be calculated can be found in a
report by SPP's Metrics Task Force. The report proposes quantifying the
incremental increase in system reliability by determining the reduction
in expected unserved energy between the base case and the change case,
obtaining the value of lost load, and multiplying these two values to
obtain the monetary benefit of enhanced reliability associated with a
transmission expansion.\1668\
---------------------------------------------------------------------------
\1667\ Id.
\1668\ Id. P 195 & n.331 (citing SPP, Benefits for the 2013
Regional Cost Allocation Review, at 25 (Sept. 13, 2012)).
---------------------------------------------------------------------------
750. The Commission described Benefit 2(b) in the NOPR as reduced
planning reserve margin, or ``the reduction in capital costs of
generation needed to meet resource adequacy requirements (i.e.,
planning reserve margins) while holding loss of load probability
constant.'' \1669\ The Commission stated that investments in
transmission capacity can reduce the system-wide planning reserve
margin requirement or the reserve margin requirement within individual
resource adequacy zones of a transmission planning region, which can
reduce the need for generation capital expenditures.\1670\ The
Commission also stated that it is important to note that, due to the
overlap between the benefit obtained from a reduction in reserve margin
requirements and the benefit associated with loss of load probability,
only one of these benefits should be calculated for a transmission
investment, but not both simultaneously.\1671\ The Commission noted
that RTOs/ISOs have calculated the transmission benefits of reduced
planning reserve margins. MISO, for example, calculated a reduction in
planning reserves associated with its Multi-Value Projects portfolio,
which reduced the need for future generation buildout to meet reserve
requirements, by using loss of load expectation reliability
simulations. MISO estimated that its Multi-Value Projects portfolio was
expected to reduce the required planning reserve margin by up to one
percentage point, which translated into a projected savings of $1.0 to
$5.1 billion in benefits over 10 years.\1672\
---------------------------------------------------------------------------
\1669\ Id. P 194.
\1670\ Id. P 196.
\1671\ Id.
\1672\ Id. P 197 (citing Midcontinent Independent System
Operator, Inc., Proposed Multi Value Project Portfolio: Business
Case Workshop, at 36-38 (Sept. 19 & 29, 2011)).
---------------------------------------------------------------------------
(b) Comments
751. A number of commenters support mandating consideration of
Benefit 2(a).\1673\ Some commenters discuss the manner in which this
benefit should be calculated.\1674\ ACEG and DC and MD Offices of
People's Counsel note the importance of geographic diversity between
transmission planning regions as an important consideration in
evaluating this benefit.\1675\ Specifically, ACEG states that it can be
estimated using the
[[Page 49402]]
value of lost load and generation capital cost savings due to lower
needed planning reserve margins.\1676\
---------------------------------------------------------------------------
\1673\ Acadia Center and CLF Initial Comments at 21-22; ACEG
Initial Comments at 32; ACORE Initial Comments at 12; AEE Reply
Comments at 25: AEP Initial Comments at 25; Amazon Initial Comments
at 5; Breakthrough Energy Initial Comments at 21-22; Clean Energy
Associations Initial Comments at 19-20; DC and MD Offices of
People's Counsel Initial Comments at 19-20; ENGIE Reply Comments at
3; Hannon Armstrong Initial Comments at 3; Interwest Initial
Comments at 12-14; National and State Conservation Organizations
Initial Comments at 1; Pine Gate Initial Comments at 34-37; PIOs
Initial Comments at 38-41; RMI Initial Comments at 1; SEIA Initial
Comments at 16; Southeast PIOs Initial Comments at 50; US DOE
Initial Comments at 31-32.
\1674\ E.g., ACEG Initial Comments at 38-39.
\1675\ ACEG Initial Comments at 35-38; DC and MD Offices of
People's Counsel Initial Comments at 21-24.
\1676\ ACEG Initial Comments at 38.
---------------------------------------------------------------------------
752. However, some commenters oppose or express concerns regarding
mandating consideration of Benefit 2(a).\1677\ NARUC states that
transmission planners are likely already considering loss of load
events in their evaluations of system expansions and that whether such
benefit, in isolation, is sufficient to recommend construction of a
particular transmission project is a question best left to them and
their states.\1678\ West Virginia Commission argues that calculation of
benefits from reduced loss of load probability requires evidence based
on assumptions that are difficult, if not impossible, to quantify in
advance.\1679\ R Street states that Benefit 2(a) should be refined to
the avoided value of lost load so that it is compatible with an
economic assessment, while Illinois Commission asserts that the
Commission should consider a more expansive definition of reduced loss
of load probability composed of more than one metric, such as value of
lost load, expected unserved energy, or a hybrid measure, that can
serve as a supplement to loss of load expectation.\1680\
---------------------------------------------------------------------------
\1677\ NARUC Initial Comments at 23; Pacific Northwest Utilities
Initial Comments at 9; West Virginia Commission Supplemental
Comments at 4.
\1678\ NARUC Initial Comments at 23.
\1679\ West Virginia Commission Supplemental Comments at 4.
\1680\ Illinois Commission Initial Comments at 14; R Street
Initial Comments at 9.
---------------------------------------------------------------------------
753. With respect to Benefit 2(b), a number of commenters support
mandating consideration of this benefit.\1681\ AEP recommends including
Benefit 2(b) as a part of a combination of benefits.\1682\ Pine Gate
states that this proposed benefit is critical to address resource
adequacy concerns, particularly where a transmission planning region
relies heavily on a single generation type.\1683\
---------------------------------------------------------------------------
\1681\ Acadia Center and CLF Initial Comments at 21-22; ACEG
Initial Comments at 32; ACORE Initial Comments at 12; AEE Reply
Comments at 25; AEP Initial Comments at 25; Amazon Initial Comments
at 5; Breakthrough Energy Initial Comments at 21-22; Clean Energy
Associations Initial Comments at 19-20; DC and MD Offices of
People's Counsel Initial Comments at 20; ENGIE Reply Comments at 3;
Hannon Armstrong Initial Comments at 3; Interwest Initial Comments
at 12-14; National and State Conservation Organizations Initial
Comments at 1; Pine Gate Initial Comments at 34-37; PIOs Initial
Comments at 38; RMI Initial Comments at 1; SEIA Initial Comments at
16; Southeast PIOs Initial Comments at 50.
\1682\ AEP Initial Comments at 25.
\1683\ Pine Gate Initial Comments at 37.
---------------------------------------------------------------------------
754. With respect to comments in opposition to Benefit 2(b),
similar to its comments on Benefit 2(a) above, West Virginia Commission
argues that calculation of benefits from reduced planning reserve
margin requires evidence based on assumptions that are difficult, if
not impossible, to quantify in advance.\1684\
---------------------------------------------------------------------------
\1684\ West Virginia Commission Supplemental Comments at 4.
---------------------------------------------------------------------------
(c) Commission Determination
755. We adopt the NOPR proposal, with modification, to require
transmission providers in each transmission planning region to measure
and use Benefit 2, in Long-Term Regional Transmission Planning. This
benefit can be characterized and measured as Benefit 2(a), Reduced Loss
of Load Probability, or as Benefit 2(b), Reduced Planning Reserve
Margin, and we clarify that these are different methods for measuring
the same underlying benefit. We find that requiring the measurement and
use of this benefit is necessary because it reflects an important
category of reliability benefits of Long-Term Regional Transmission
Facilities. Because there is an overlap between reduced loss of load
probability benefits and reduced planning reserve margin benefits, for
purposes of Long-Term Regional Transmission Planning, transmission
providers must either measure reduced loss of load events by holding
the planning reserve margin constant or measure the reduction in
planning reserve margins by holding loss of load events constant but
may not measure both simultaneously for purposes of using and measuring
Benefit 2(a) or 2(b).
756. We adopt the NOPR's proposed description of Benefit 2(a) that
describes Benefit 2(a), Reduced Loss of Load Probability, as the
reduced frequency of loss of load events by providing additional
pathways for connecting generation resources with load in regions that
can be constrained by weather events and unplanned outages (if the
planning reserve margin is not changed despite lower loss of load
events), as well as improved physical reliability benefits by reducing
the likelihood of load shed events. Benefit 2(a) measures reduced loss
of load probability for resource adequacy planning, which typically
includes the consideration of normal system conditions. One method of
measuring a reduction in loss of load probability benefit is to
quantify the incremental increase in system reliability by determining
the reduction in expected unserved energy between the base case and the
change case, determining the value of lost load, and multiplying these
two values to obtain the monetary benefit of enhanced reliability
associated with a Long-Term Regional Transmission Facility or a
portfolio of Long-Term Regional Transmission Facilities.\1685\
---------------------------------------------------------------------------
\1685\ NOPR, 179 FERC ] 61,028 at P 195 & n.331 (citing SPP,
Benefits for the 2013 Regional Cost Allocation Review, at 25 (Sept.
13, 2012)).
---------------------------------------------------------------------------
757. Numerous commenters support mandating Benefit 2(a).\1686\ We
recognize commenter suggestions regarding the method for calculating
this benefit, with some recommending consideration of geographic
diversity between transmission planning regions \1687\ and others
recommending that the benefit be expressed in terms of the value of
lost load.\1688\ We agree that geographic diversity is an important
consideration in evaluating the reduced loss of load probability method
of calculating this benefit and find that the flexibility in measuring
benefits that we provide to transmission providers under this final
order allows for this consideration. As to the suggestion by Illinois
Commission and R Street that Benefit 2(a) should be expressed in terms
of the value of lost load so that it can be expressed in terms of cost,
we believe that either Benefit 2(a) or Benefit 2(b) are reasonable
methods to calculate Benefit 2 and we reiterate that transmission
providers can choose either method to calculate this benefit. We
encourage transmission providers to consider whether Benefit 2(a) or
Benefit 2(b) is the most effective way to accurately reflect the
benefits of a proposed Long-Term Regional Transmission Facility in
their individual regions. As to NARUC's contention that the benefit of
reducing the probability of loss of load events, in isolation, may be
insufficient to support the development of a particular
[[Page 49403]]
transmission project, while we are requiring transmission providers to
use Benefit 2(a) or Benefit 2(b) to evaluate Long-Term Regional
Transmission Facilities, we are not requiring transmission providers to
base their evaluation on this single benefit--or any single benefit,
for that matter--but rather on at least the range of benefits included
in the required set of benefits that we adopt herein. Moreover, we are
not requiring that transmission providers select any Long-Term Regional
Transmission Facility.
---------------------------------------------------------------------------
\1686\ Acadia Center and CLF Initial Comments at 21-22; ACEG
Initial Comments at 32; ACORE Initial Comments at 12; AEE Reply
Comments at 25: AEP Initial Comments at 25; Amazon Initial Comments
at 5; Breakthrough Energy Initial Comments at 21-22; Clean Energy
Associations Initial Comments at 19-20; DC and MD Offices of
People's Counsel Initial Comments at 19-20; ENGIE Reply Comments at
3; Hannon Armstrong Initial Comments at 3; Interwest Initial
Comments at 12-14; National and State Conservation Organizations
Initial Comments at 1; Pine Gate Initial Comments at 34-37; PIOs
Initial Comments at 38-41; RMI Initial Comments at 1; SEIA Initial
Comments at 16; Southeast PIOs Initial Comments at 50; US DOE
Initial Comments at 31-32.
\1687\ ACEG Initial Comments at 35-38; DC and MD Offices of
People's Counsel Initial Comments at 21-24.
\1688\ Illinois Commission Initial Comments at 14 (suggesting
alternatively that Benefit 2(a) be expressed in terms of expected
unserved energy, or a hybrid measurement composed of more than one
metric); R Street Initial Comments at 9 (stating that using value of
lost load is compatible with an economic assessment).
---------------------------------------------------------------------------
758. As noted above, the NOPR proposed the following description of
Benefit 2(b), ``the reduction in capital costs of generation needed to
meet resource adequacy requirements (i.e., planning reserve margins)
while holding loss of load probability constant.'' \1689\ We adopt the
NOPR description in this final order. We find that a lower planning
reserve margin is another way to demonstrate a resource adequacy
benefit. As we indicate above, due to the relationship between the
benefit obtained from a reduction in reserve margin requirements and
the benefit associated with reduced loss of load probability, only one
of these methods for calculating the benefit for a transmission
investment can be used, but not both simultaneously. We find that
Benefit 2(b) is one of two ways to calculate reduced costs related to
resource adequacy because Long-Term Regional Transmission Facilities
can reduce the system-wide planning reserve margin requirements within
individual resource adequacy zones of a transmission planning region
and provide benefits by reducing the need for generation capital
expenditures.
---------------------------------------------------------------------------
\1689\ NOPR, 179 FERC ] 61,028 at P 194.
---------------------------------------------------------------------------
759. Many commenters support mandating consideration of Benefit
2(b). For example, DC and MD Offices of People's Counsel note that the
benefit of a reduced reserve planning margin has been used in multiple
cases.\1690\ We also find that it is feasible for transmission
providers to calculate the benefit of reduced planning reserve margins.
We reiterate here the example of MISO, which calculated a reduction in
planning reserves associated with its Multi-Value Projects portfolio,
reducing the need for future generation investments to meet reserve
requirements by using loss of load expectation reliability simulations.
MISO estimated that its Multi-Value Projects portfolio was expected to
reduce the required planning reserve margin by up to one percentage
point, which translated into a projected savings of $1.0 to $5.1
billion in benefits over 10 years.\1691\ We also note that the
Commission has accepted benefits for use in evaluating regional
transmission facilities in Order No. 1000 regional transmission
planning processes akin to Benefit 2(a), Reduced Loss of Load
Probability,\1692\ in non-RTO/ISO transmission planning regions.\1693\
---------------------------------------------------------------------------
\1690\ DC and MD Offices of People's Counsel at 22-23 (citing
Midcontinent Independent System Operator, Inc., Proposed Multi Value
Project Portfolio: Business Case Workshop, at 36-38 (Sept. 19 & 29,
2011); SPP, Benefits for the 2013 Regional Cost Allocation Review
(Sept. 13, 2012); Investigation on Comm'n's Own Motion to Review 18
Percent Planning Reserve Margin Requirement, Docket No. 5-EI-141
(PSC REF# 102692), at 5 (Pub. Serv. Comm'n Wis. Oct. 9, 2008); SPP,
The Value of Transmission, at 16 (Jan. 26, 2016); Midcontinent
Independent System Operator, Inc., MISO Value Proposition 2020:
Forward View, at 20-21 (June 2022); PJM Interconnection, L.L.C., PJM
Value Proposition, at 2 (2019); Australian Energy Market Operator,
2022 Integrated System Plan, at 64 (June 2022)).
\1691\ NOPR, 179 FERC ] 61,028 at P 197 (citing Midcontinent
Independent System Operator, Inc., Proposed Multi Value Project
Portfolio: Business Case Workshop, at 36-38 (Sept. 19 & 29, 2011)).
\1692\ PacifiCorp, 147 FERC ] 61,057 at PP 133-134, 141-143;
Pub. Serv. Co. of Colo., 142 FERC ] 61,206 at P 314.
\1693\ PacifiCorp, 147 FERC ] 61,057 at PP 132, 134, 141-143.
---------------------------------------------------------------------------
760. Finally, we disagree with West Virginia Commission's claim
that calculation of this benefit requires evidence based on assumptions
that are difficult, if not impossible, to quantify in advance.\1694\ As
noted above, there are multiple examples in the record of transmission
providers that currently calculate these benefits. Because we find that
transmission providers will be able to calculate either Benefit 2(a) or
2(b) and recognize the importance of accounting for Benefit 2 in Long-
Term Regional Transmission Planning, we require transmission providers
to measure and use Benefit 2.
---------------------------------------------------------------------------
\1694\ West Virginia Commission Supplemental Comments at 4.
---------------------------------------------------------------------------
iii. Benefit 3: Production Cost Savings
(a) NOPR Description
761. The Commission described Benefit 3 in the NOPR as savings in
fuel and other variable operating costs of power generation that are
realized when transmission facilities allow for displacement of higher-
cost supplies through the increased dispatch of suppliers that have
lower incremental costs of production, as well as a reduction in market
prices as lower-cost suppliers set market clearing prices.\1695\ The
Commission stated that most regional transmission planning processes
currently estimate production cost savings. Generally, within RTOs/
ISOs, security-constrained production cost models simulate the hourly
operations of the electric system and the wholesale electricity market
by emulating how system operators would commit and dispatch generation
resources to serve load at least cost, subject to transmission and
operating constraints. The traditional method for estimating the
changes in adjusted production costs associated with proposed
transmission facilities (or portfolio of facilities) is to compare the
adjusted production costs with and without those facilities. Analysts
typically call the market simulations without the proposed transmission
facilities the ``Base Case'' and the simulations with those facilities
the ``Change Case.'' \1696\
---------------------------------------------------------------------------
\1695\ NOPR, 179 FERC ] 61,028 at P 198 & n.333 (proposing to
define this as adjusted production cost savings when the calculation
is adjusted to account for purchases and sales outside the region).
\1696\ NOPR, 179 FERC ] 61,028 at P 199.
---------------------------------------------------------------------------
762. The Commission further explained that approaches used to
calculate production cost savings vary. MISO uses production cost
savings (adjusted for import costs and export revenues) to allocate the
costs of its Market Efficiency Projects to cost allocation zones based
on each zone's share of the total adjusted production cost
savings.\1697\ The Commission also explained, in contrast, that NYISO
and PJM use reductions to load energy payments (adjusted to reflect the
reduced value of transmission congestion contracts) to allocate the
costs of economic transmission facilities.\1698\
---------------------------------------------------------------------------
\1697\ NOPR, 179 FERC ] 61,028 at P 200 (citing MISO, FERC
Electric Tariff, attach. FF, Benefit Metrics section (I)(A)(1)
(33.0.0)).
\1698\ NOPR, 179 FERC ] 61,028 at P 200 & n.335 (citing PJM
Interconnection L.L.C., 142 FERC ] 61,214 at P 416; N.Y. Indep. Sys.
Operator Corp., 143 FERC ] 61,059, at PP 268, 269, n.516 (2013);
NYISO, NYISO Tariffs, OATT, attach. Y, section 31.5 (Cost Allocation
and Cost Recovery) (30.0.0), section 31.5.4.3.2.) (``For high
voltage economic transmission facilities, PJM allocates 50% of the
costs in accordance with its economic analysis and allocates the
other 50% of the costs on a load-ratio share basis.'').
---------------------------------------------------------------------------
763. The Commission stated that non-RTO/ISO regions, without
centrally organized energy markets, rely on other tools to perform
analyses of production cost savings. For example, WestConnect's
regional cost allocation method for regional transmission facilities
driven by economic considerations identifies the benefits and
beneficiaries of a proposed regional transmission facility or
facilities by modeling the potential of the transmission facilities to
support more economic bilateral transactions between generators and
loads in the region. Specifically, WestConnect considers the
transactions between loads and lower-
[[Page 49404]]
cost generation that a proposed regional transmission facility could
support and, accounting for the costs associated with transmission
service, identifies the transactions that are likely to occur.
WestConnect then estimates any resulting cost savings (in the form of
reductions in production costs and reserve sharing requirements) and
allocates the costs of the regional transmission facilities on that
basis.\1699\
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\1699\ NOPR, 179 FERC ] 61,028 at P 201 (citing Pub. Serv. Co.
of Colo., 142 FERC ] 61,206 at P 314).
---------------------------------------------------------------------------
(b) Comments
764. A number of commenters support mandating consideration of this
benefit.\1700\ AEP recommends including Benefit 3 as a part of a
combination of benefits.\1701\ According to TAPS, all of the RTOs/ISOs
already consider production cost savings; TAPS argues that the
Commission should require transmission providers in non-RTO/ISO
transmission planning regions to consider them as well.\1702\ Indicated
PJM TOs state that this benefit is one of the main benefits that will
drive the selection of transmission facilities in PJM.\1703\
---------------------------------------------------------------------------
\1700\ Acadia Center and CLF Initial Comments at 21-22; ACEG
Initial Comments at 32; ACORE Initial Comments at 12; AEE Reply
Comments at 25; AEP Initial Comments at 25; Amazon Initial Comments
at 5; Breakthrough Energy Initial Comments at 21-22; Certain TDUs
Reply Comments at 1-2; Clean Energy Associations Initial Comments at
19-20; DC and MD Offices of People's Counsel Initial Comments at 19-
20; ENGIE Reply Comments at 3; Hannon Armstrong Initial Comments at
3; Interwest Initial Comments at 12-14; National and State
Conservation Organizations Initial Comments at 1; Joint Consumer
Advocates Initial Comments at 11; New Jersey Commission Initial
Comments at 13-14 (including reduced production costs during
transmission outages, extreme events, and higher than normal load
conditions in Benefit 3); Pine Gate Initial Comments at 34-37; PIOs
Initial Comments at 38-41; PJM Initial Comments at 96; RMI Initial
Comments at 1; SEIA Initial Comments at 16; Southeast PIOs Initial
Comments at 50; TAPS Initial Comments at 14; US DOE Initial Comments
at 31-32.
\1701\ AEP Initial Comments at 25.
\1702\ TAPS Initial Comments at 14.
\1703\ Indicated PJM TOs Initial Comments at 17.
---------------------------------------------------------------------------
765. Some commenters opine on how to calculate this benefit.\1704\
ACEG states that production cost savings should include fuel and
variable operating cost savings, adjustments for imports from
neighboring transmission planning regions, reduced costs of cycling
power plants, reduced amounts and costs of operating reserves and other
ancillary services, and mitigation of reliability-must-run
conditions.\1705\ Likewise, DC and MD Offices of People's Counsel state
that production cost savings should include ancillary service cost
savings.\1706\ MISO notes that, in addition to evaluating production
cost savings under normal patterns of renewable dispatch and load,
transmission providers can analyze production cost savings that accrue
during transmission outages using historical sampling or statistical
modeling of transmission outage patterns.\1707\ MISO TOs state that its
process to evaluate Multi-Value Projects considers production cost
savings that can be realized through reduced transmission congestion
and transmission energy losses, capacity loss savings, capacity
savings, long-term cost savings, and ``any other financially
quantifiable benefit.''\1708\
---------------------------------------------------------------------------
\1704\ ACEG Initial Comments at 40; DC and MD Offices of
People's Counsel Initial Comments at 25; GridLab Initial Comments at
26-27; MISO Initial Comments at 49-50.
\1705\ ACEG Initial Comments at 40.
\1706\ DC and MD Offices of People's Counsel Initial Comments at
25.
\1707\ MISO Initial Comments at 49-50.
\1708\ MISO TOs Initial Comments at 21 (citing MISO Open Access
Transmission, Energy and Operating Reserve Markets Tariff, attach.
FF (90.0.0), section II.C.5).
---------------------------------------------------------------------------
766. Some commenters oppose or express concerns regarding mandating
consideration of production cost savings.\1709\ For example, Southern
states that considering production cost savings could result in the
double-counting of benefits in its footprint by, for example, making
generation pricing/cost decisions that have already been made or will
ultimately be made in integrated resource planning or request for
proposal processes.\1710\ Relatedly, North Carolina Commission and
Staff state that requiring consideration of production cost savings
would conflict with state-jurisdictional resource decisions.\1711\
Mississippi Commission contends that this benefit may not always be
applicable, such as where financial transmission rights fully hedge the
cost of congestion.\1712\ PJM Market Monitor states that in PJM,
comparing production cost savings across different gas prices and
different generation resource capacity may not provide meaningful
guidance as to the benefits of a transmission facility beyond that
currently provided by satisfying reliability criteria because of
potentially inaccurate forecasts for key values.\1713\ Pacific
Northwest Utilities assert that this benefit is not easily
quantifiable.\1714\
---------------------------------------------------------------------------
\1709\ Mississippi Commission Initial Comments at 35-36; North
Carolina Commission and Staff Initial Comments at 7; Pacific
Northwest Utilities Initial Comments at 9; PJM Market Monitor
Initial Comments at 5; Southern Initial Comments at 26.
\1710\ Southern Initial Comments at 26 (citing Southern Initial
Comments Ex. 1, ]] 8, 15).
\1711\ North Carolina Commission and Staff Initial Comments at
7.
\1712\ Mississippi Commission Initial Comments at 36.
\1713\ PJM Market Monitor Initial Comments at 5.
\1714\ Pacific Northwest Utilities Initial Comments at 9.
---------------------------------------------------------------------------
(c) Commission Determination
767. We adopt the NOPR proposal, with modification, to require
transmission providers in each transmission planning region to measure
and use Benefit 3, Production Cost Savings, in Long-Term Regional
Transmission Planning. We adopt the NOPR's proposed description of
Benefit 3 as savings in fuel and other variable operating costs of
power generation that are realized when transmission facilities allow
for displacement of higher-cost supplies through the increased dispatch
of suppliers that have lower incremental costs of production, as well
as a reduction in market prices as lower-cost suppliers set market
clearing prices. We find that requiring the use of Benefit 3 is
necessary because Long-Term Regional Transmission Facilities could
result in savings in fuel and other variable operating costs of power
generation that are realized when transmission facilities allow for
displacement of higher-cost supplies through the increased dispatch of
suppliers that have lower incremental costs of production. We further
find that, absent a requirement for transmission providers to measure
and use Benefit 3 in Long-Term Regional Transmission Planning,
transmission providers may not identify, evaluate, and select Long-Term
Regional Transmission Facilities that more efficiently or cost-
effectively address Long-Term Transmission Needs.
768. We do not require a standardized method for measuring
production cost savings, and, consistent with this approach, we decline
commenter requests to specify the exact types of cost savings for which
transmission providers must account when measuring this benefit.\1715\
As the Commission stated in the NOPR,\1716\ different transmission
planning regions have different approaches toward the calculation of
this benefit, and this final order provides flexibility for
transmission providers in developing the method that they use to
measure production cost savings, consistent with the requirement to
measure and use the required set of benefits in Long-Term Regional
Transmission Planning described above.
---------------------------------------------------------------------------
\1715\ See ACEG Initial Comments at 40; DC and MD Offices of
People's Counsel Initial Comments at 25; GridLab Initial Comments at
26-27; MISO Initial Comments at 49-50.
\1716\ NOPR, 179 FERC ] 61,028 at PP 200-201.
---------------------------------------------------------------------------
[[Page 49405]]
769. We note that Benefit 3 is distinct from other benefits that we
require transmission providers to measure and use in Long-Term Regional
Transmission Planning. Although Benefit 3 and Benefit 6, as described
in this final order, both measure production cost savings (including
savings that occur during generation outage contingencies), the system
conditions used in calculating each benefit are distinct. For example,
Benefit 6 can include higher electricity demand, forecast errors,
volatile production costs, and a more expansive set of generation
outages such as unplanned generation outages due to extreme weather.
And as we discuss below in the context of Benefit 5, because Benefit 3,
Production Cost Savings, as described in this order, does not capture
production cost savings during transmission outages, we require
transmission providers to measure and use Benefit 5 to ensure that they
are accounting for reduced production costs during transmission outages
as well.
770. We also do not believe that requiring transmission providers
to measure and use Benefit 3 in Long-Term Regional Transmission
Planning will, as Southern suggests, result in double-counting of
benefits because such benefits are also considered in state resource
planning. While we acknowledge that integrated resource planning
processes, where they exist, may consider similar benefits compared to
those required by this final order, the consideration of benefits in a
state-jurisdictional process does not result in the double-counting of
benefits within any Commission-jurisdictional transmission planning
process. Because practices affecting rates, terms, and conditions for
interstate transmission service are the exclusive jurisdiction of the
Commission, we must ensure that Commission-jurisdictional regional
transmission planning processes result in rates that are just and
reasonable and not unduly or discriminatory. To this end, this final
order is focused on ensuring that, when conducting Long-Term Regional
Transmission Planning, transmission providers consider the broader set
of benefits provided by Long-Term Regional Transmission Facilities so
that they may determine whether to select such facilities as the more
efficient or cost-effective regional transmission solution to address
Long-Term Transmission Needs.
771. Pacific Northwest Utilities assert that production cost
savings are not easily quantifiable.\1717\ We acknowledge that there
are some challenges associated with measuring this benefit, but we
conclude that it is nonetheless necessary to require such measurement
in order to ensure that transmission rates are just, reasonable, and
not unduly discriminatory or preferential. We also note that there is
an abundance of examples of how transmission providers can measure this
benefit. Production cost savings are used extensively in many
transmission planning regions, including MISO, NYISO, PJM, SPP, CAISO,
ISO-NE, NorthernGrid, and WestConnect.\1718\ We believe that
transmission providers are capable of measuring production cost savings
given that this benefit has been used as a metric in transmission
planning for decades.
---------------------------------------------------------------------------
\1717\ Pacific Northwest Utilities Initial Comments at 9.
\1718\ See NOPR, 179 FERC ] 61,028 at PP 200-201; Brattle-Grid
Strategies Oct. 2021 Report at 31; ISO New England, Inc.,
Transmission Planning: Maintaining Power System Reliability Amid
Change, https://www.iso-ne.com/system-planning/transmission-planning
(last visited Mar. 25, 2024); NorthernGrid, Study Scope for the
2022-2023 NorthernGrid Planning Cycle, 2 (Sept. 21, 2022), https://www.northerngrid.net/private-media/documents/NG_Study_Scope_2022-2023_Approved.pdf; The Brattle Group, The Benefits of Electric
Transmission: Identifying and Analyzing the Value of Investments, 31
(July 2013), https://www.brattle.com/wp-content/uploads/2021/06/The-Benefits-of-Electric-Transmission-Identifying-and-Analyzing-the-Value-of-Investments.pdf (noting that in the Western Electricity
Coordinating Council (WECC), whose service area includes one RTO
(CAISO) and three non-RTO regions (ColumbiaGrid, Northern Tier
Transmission Group (NTTG), and WestConnect) production costs
simulations are used to calculate the energy costs savings of
transmission projects in WECC's long-term transmission planning
studies).
---------------------------------------------------------------------------
772. In response to North Carolina Commission and Staff's
contention that requiring consideration of production cost savings
conflicts with state-jurisdictional resource decisions,\1719\ we find
that North Carolina Commission and Staff have failed to explain why
there may be a conflict. As noted in the Need for Reform, there are
deficiencies in the Commission's existing transmission planning and
cost allocation requirements, including that they fail to require
transmission providers to adequately consider the broader set of
benefits of regional transmission facilities planned to meet Long-Term
Transmission Needs. We are concerned that failing to adequately
identify and consider the benefits, including production cost benefits,
of such transmission facilities may lead to relatively inefficient and
less cost-effective transmission development. Additionally, as
described above in the Categories of Factors section, transmission
providers must incorporate, and not discount, state-jurisdictional
resource decisions, such as integrated resource plans, into all Long-
Term Scenarios to identify Long-Term Transmission Needs. Therefore, we
believe that requiring transmission providers to measure production
cost savings will not conflict with state-jurisdictional resource
decisions, because the effects of such resource decisions on Long-Term
Transmission Needs must be fully accounted for in all Long-Term
Scenarios, which are used to help identify more efficient or cost-
effective regional transmission solutions within the Commission-
jurisdictional regional transmission planning process. Moreover, as
discussed in the Legal Authority to Adopt Reforms for Long-Term
Regional Transmission Planning section of this final order, nothing in
this final order conflicts with or infringes on the states' reserved
authority under FPA section 201.
---------------------------------------------------------------------------
\1719\ North Carolina Commission and Staff Initial Comments at
7.
---------------------------------------------------------------------------
773. We disagree with Mississippi Commission's assertion that
production cost savings may not always be applicable, such as where
financial transmission rights fully hedge the cost of congestion.\1720\
Financial transmission rights are required in RTO/ISO markets and allow
the market participant that owns the right to mitigate the congestion
charge along an existing transmission path for the capacity of that
path.\1721\ A new transmission facility could reduce congestion and
allow that market participant to purchase more electricity, exceeding
the capacity of the transmission path for the financial transmission
right, at a lower price. This reduced congestion allows for load to
access lower cost resources, and results in more efficient dispatch of
resources and, thus, provides avoided production cost benefits that are
distinct from the avoided congestion charges associated with financial
transmission rights.
---------------------------------------------------------------------------
\1720\ Mississippi Commission Initial Comments at 36.
\1721\ Long-Term Firm Transmission Rights in Organized Elec.
Mkts., Order No. 681, 116 FERC ] 61,077, at PP 5, 19-21, reh'g
denied, Order No. 681-A, 117 FERC ] 61,201 (2006), order on reh'g &
clarification, Order No. 681-B, 126 FERC ] 61,254 (2009).
---------------------------------------------------------------------------
774. We recognize the PJM Market Monitor's concern regarding the
potential for inaccurate forecasts of key inputs to the calculation of
production cost savings.\1722\ However, we conclude that this potential
concern does not outweigh the value of measuring and using this
benefit, as demonstrated by long-standing use of this benefit within
PJM and other transmission planning regions, including all RTOs/ISOs
and some non-RTO/ISO regions. Moreover,
[[Page 49406]]
as noted in the Long-Term Scenarios section of this final order, the
use of Long-Term Scenarios in Long-Term Regional Transmission Planning
mitigates such uncertainty in transmission planning outcomes.
Specifically, comparing the production cost savings, as well as the
other benefits that we require transmission providers to measure and
use in Long-Term Regional Transmission Planning, provided by Long-Term
Transmission Facilities across three distinct Long-Term Scenarios
should help to address the uncertainty noted by the PJM Market Monitor.
---------------------------------------------------------------------------
\1722\ PJM Market Monitor Initial Comments at 5.
---------------------------------------------------------------------------
iv. Benefit 4: Reduced Transmission Energy Losses
(a) NOPR Description
775. The Commission described this benefit in the NOPR as reduced
total energy necessary to meet demand stemming from reduced energy
losses incurred in transmittal of power from generation to loads.\1723\
---------------------------------------------------------------------------
\1723\ NOPR, 179 FERC ] 61,028 at P 202.
---------------------------------------------------------------------------
776. The Commission explained that production cost savings metrics
used today typically exclude reduced transmission energy losses and
three other production cost savings-related benefits proposed in the
NOPR. The Commission also stated that including those additional
proposed benefits can produce a more robust set of congestion and
production cost benefits that can be quantified and integrated into the
method for calculating production cost savings and, therefore, help to
ensure that more efficient or cost-effective transmission facilities
are selected through Long-Term Regional Transmission Planning.\1724\
---------------------------------------------------------------------------
\1724\ Id. P 203.
---------------------------------------------------------------------------
777. The Commission noted that to measure reduced transmission
energy losses, transmission providers could: (1) simulate losses in
production cost models; (2) estimate changes in losses with power flow
models for a range of hours; or (3) estimate how the cost of supplying
losses will likely change with marginal loss charges. For example, ATC
measured reduced transmission energy losses based on changes in
marginal loss charges and loss refund estimates using the marginal loss
component from the PROMOD \1725\ electric market simulation software
simulations for the Paddock-Rockdale 345 kV Access Project,\1726\ which
produced cost reduction benefits using adjusted production cost
analysis. Also, SPP's analysis for its Regional Cost Allocation Review
process estimated energy loss reductions through post-processing the
marginal loss component of the locational marginal prices in PROMOD
simulation results.\1727\
---------------------------------------------------------------------------
\1725\ PROMOD is a generator and portfolio modeling system.
Hitachi Energy: PROMOD, https://www.hitachienergy.com/us/en/products-and-solutions/energy-portfolio-management/enterprise/promod
(last visited Apr. 2024).
\1726\ NOPR, 179 FERC ] 61,028 at P 204 & n.338 (citing ATC,
Planning Analysis of the Paddock-Rockdale Project, Docket No. 137-
CE-149, app. C, Ex. 1, at 34-38 (Wisc. Pub. Serv. Comm'n Apr. 5,
2007)).
\1727\ SPP, SPP Regional Cost Allocation Review Report for RCAR
II, at 56, 64 (July 11, 2016), https://www.spp.org/documents/46235/rcar%202%20report%20final.pdf.
---------------------------------------------------------------------------
(b) Comments
778. A number of commenters support mandating consideration of
Benefit 4.\1728\ While not favoring a benefits measurement requirement,
Southern states that this benefit would likely prove workable under
Southern's non-RTO/ISO construct because SERTP Sponsors' regional and
interregional transmission planning and cost allocation processes
already incorporate the benefit of reduced transmission energy
losses.\1729\
---------------------------------------------------------------------------
\1728\ Acadia Center and CLF Initial Comments at 21-22; ACEG
Initial Comments at 32; ACORE Initial Comments at 12; AEE Reply
Comments at 25; Amazon Initial Comments at 5; Breakthrough Energy
Initial Comments at 21-22; Clean Energy Associations Initial
Comments at 19-20; DC and MD Offices of People's Counsel Initial
Comments at 19-20; ENGIE Reply Comments at 3; Hannon Armstrong
Initial Comments at 3; Interwest Initial Comments at 12-14; National
and State Conservation Organizations Initial Comments at 1; New
Jersey Commission Initial Comments at 13-14; Pine Gate Initial
Comments at 34-37; PIOs Initial Comments at 38-41; RMI Initial
Comments at 1; SEIA Initial Comments at 16; Southeast PIOs Initial
Comments at 50; US DOE Initial Comments at 31-32.
\1729\ Southern Initial Comments at 25.
---------------------------------------------------------------------------
779. Several commenters comment on the manner in which Benefit 4
should be calculated.\1730\ ACEG states that this benefit has been
calculated in various studies.\1731\
---------------------------------------------------------------------------
\1730\ ACEG Initial Comments at 41; NARUC Initial Comments at 23
(noting that advanced technologies also provide this benefit and
should be preferred over greenfield construction); Utah Division of
Public Utilities Initial Comments at 8.
\1731\ ACEG Initial Comments at 41 (citing ATC, Planning
Analysis of the Paddock-Rockdale Project, app. C Ex. 1, at 34-38
(Wisc. Pub. Serv. Docket No. 137-CE-149); SPP, Regional Cost
Allocation Review Report for RCAR II, at 5 (July 11, 2016), https://www.spp.org/documents/46235/rcar%202%20report%20final.pdf).
---------------------------------------------------------------------------
780. West Virginia Commission opposes the use of Benefit 4, arguing
that the calculation of benefits from reduced transmission losses
requires significant evidence based on assumptions that are difficult,
if not impossible, to quantify before the fact.\1732\
---------------------------------------------------------------------------
\1732\ West Virginia Commission Supplemental Comments at 4.
---------------------------------------------------------------------------
(c) Commission Determination
781. We adopt the NOPR proposal, with modification, to require
transmission providers to measure and use Benefit 4, Reduced
Transmission Energy Losses, in Long-Term Regional Transmission
Planning. We adopt the NOPR's proposed description of Benefit 4, as
modified, as the reduced total energy necessary to meet demand stemming
from reduced energy losses incurred in transmittal of power from
generation to loads. We find that requiring the measurement and use of
Benefit 4 in Long-Term Regional Transmission Planning is necessary
because reduced energy losses are widely understood to be a benefit of
transmission facilities.\1733\ As such, we find that transmission
providers must measure and use this benefit in Long-Term Regional
Transmission Planning because it will help to ensure that they
identify, evaluate, and select more efficient or cost-effective
regional transmission solutions to address Long-Term Transmission
Needs.
---------------------------------------------------------------------------
\1733\ See Acadia Center and CLF Initial Comments at 21-22; ACEG
Initial Comments at 32; ACORE Initial Comments at 12; AEE Reply
Comments at 25; Amazon Initial Comments at 5; Breakthrough Energy
Initial Comments at 21-22; Clean Energy Associations Initial
Comments at 19-20; DC and MD Offices of People's Counsel Initial
Comments at 19-20; ENGIE Reply Comments at 3; Hannon Armstrong
Initial Comments at 3; Interwest Initial Comments at 12-14; National
and State Conservation Organizations Initial Comments at 1; New
Jersey Commission Initial Comments at 11-14; Pine Gate Initial
Comments at 34-37; PIOs Initial Comments at 38-41; RMI Initial
Comments at 1; SEIA Initial Comments at 16; Southeast PIOs Initial
Comments at 50; US DOE Initial Comments at 31-32.
---------------------------------------------------------------------------
782. We recognize that there are multiple ways for transmission
providers to measure reduced transmission energy losses.\1734\ We note
that this final order does not require transmission providers to adopt
any single method to measure reduced transmission energy losses. As
described in the NOPR, transmission providers could: (1) simulate
losses in production cost models; (2) estimate changes in losses with
power flow models for a range of hours; or (3) estimate how the cost of
supplying losses will likely change with marginal loss charges.\1735\
Transmission providers could also follow the example of ATC, which
measured reduced transmission energy losses based on changes in
marginal loss charges and loss refund estimates provided by the PROMOD
electric market simulation software.\1736\
[[Page 49407]]
Similarly, SPP estimates energy loss reductions through its Regional
Cost Allocation Review process by post-processing the marginal loss
component of the locational marginal prices in PROMOD simulation
results.\1737\
---------------------------------------------------------------------------
\1734\ See, e.g., ACEG Initial Comments at 41 (citing studies in
which Benefit 4 has been calculated).
\1735\ NOPR, 179 FERC ] 61,028 at P 204.
\1736\ ATC, Planning Analysis of the Paddock-Rockdale Project,
Docket No. 137-CE-149, app. C Ex. 1, at 34-38 (Wisc. Pub. Serv.
Comm'n Apr. 5, 2007).
\1737\ SPP, Regional Cost Allocation Review Report for RCAR II,
at 56, 64 (July 11, 2016), https://www.spp.org/documents/46235/rcar%202%20report%20final.pdf.
---------------------------------------------------------------------------
783. Because we find that transmission providers have multiple ways
of calculating the benefit of reduced transmission energy losses, as
well as record evidence demonstrating that the calculation of Benefit 4
is either already considered or is feasible in multiple transmission
planning regions, we disagree with West Virginia Commission's claim
that calculation of this benefit requires evidence based on assumptions
that are difficult, if not impossible, to quantify in advance.\1738\ We
also note that the Commission has accepted benefits for use in
evaluating regional transmission facilities in Order No. 1000 regional
transmission planning processes akin to Benefit 4, Reduced Transmission
Energy Losses, in non-RTO/ISO transmission planning regions.\1739\
---------------------------------------------------------------------------
\1738\ West Virginia Commission Supplemental Comments at 4.
\1739\ PacifiCorp, 147 FERC ] 61,057 at PP 132, 134, 141-143.
---------------------------------------------------------------------------
v. Benefit 5: Reduced Congestion Due to Transmission Outages
(a) NOPR Description
784. The Commission described Benefit 5 in the NOPR as reduced
production costs resulting from avoided congestion during transmission
outages. Such benefits include reduced production costs during
transmission outages that significantly increase transmission
congestion. Production cost simulations typically consider planned
generation outages and, in most cases, a random distribution of
unplanned generation outages. In contrast, they do not generally
reflect transmission outages, planned or unplanned.\1740\ The
Commission noted that transmission providers could measure this
benefit, for example, by either building a data set of a normalized
outage schedule (not including extreme events) that can be introduced
into simulations or by inducing system constraints more frequently. One
application of this approach is SPP's Regional Cost Allocation Review
process, which, inter alia, measured the benefits of reducing
congestion resulting from transmission outages. In this process, SPP
modeled outage events and new constraints based on these outages in
PROMOD for a 2025 case year, and then conducted PROMOD simulations to
calculate adjusted production cost savings for a base case and the
change case including the transmission line.\1741\
---------------------------------------------------------------------------
\1740\ NOPR, 179 FERC ] 61,028 at P 205 & n.340 (citing Brattle-
Grid Strategies Oct. 2021 Report at 79).
\1741\ Id. P 205 & n.341 (citing SPP, Inc., Regional Cost
Allocation Review Report for RCAR II, at 51-52 (July 11, 2016),
https://www.spp.org/documents/46235/rcar%202%20report%20final.pdf.
To estimate incremental savings associated with mitigation of
transmission outage costs, SPP analyzed outage cases in PROMOD for
the 2025 study year. SPP developed cases based on 12 months of
historical SPP transmission data. SPP said that because of the high
volume of historical transmission outage data (approximately 7,000
outage events) and based on the expectation that many outages would
not lead to significant increases in congestion, SPP only modeled a
subset of outage events. The events selected were those expected to
create significant congestion and met at least one of three
conditions. Id. at 51.)
---------------------------------------------------------------------------
(b) Comments
785. A number of commenters support mandating consideration of
Benefit 5.\1742\ While Southern does not support a requirement to use
this or other benefits, it states that this benefit--which Southern
understands as ``operational flexibility''--could be explored for
potential adoption in its footprint.\1743\
---------------------------------------------------------------------------
\1742\ Acadia Center and CLF Initial Comments at 21-22; ACEG
Initial Comments at 32; ACORE Initial Comments at 12; AEE Reply
Comments at 25; Amazon Initial Comments at 5; Breakthrough Energy
Initial Comments at 21-22; Clean Energy Associations Initial
Comments at 18-20; DC and MD Offices of People's Counsel Initial
Comments at 20; ENGIE Reply Comments at 2-3; Hannon Armstrong
Initial Comments at 2-3; Interwest Initial Comments at 12-14;
National and State Conservation Organizations Initial Comments at 1;
Pine Gate Initial Comments at 34-37; PIOs Initial Comments at 37-38;
RMI Initial Comments at 1; SEIA Initial Comments at 16; Southeast
PIOs Initial Comments at 50.
\1743\ Southern Initial Comments at 25.
---------------------------------------------------------------------------
786. A few commenters opine on how to calculate the benefit of
reduced congestion due to transmission outages.\1744\ ACEG states that
most transmission planning models ignore unplanned transmission outages
that are likely to occur during extreme weather events, which ACEG
claims will underestimate the value of Benefit 5.\1745\ Similarly, DC
and MD Offices of People's Counsel argue that, because unplanned
transmission outages cause a significant portion of congestion costs,
calculation of this benefit should account for such outages.\1746\
---------------------------------------------------------------------------
\1744\ ACEG Initial Comments at 41-42; DC and MD Offices of
People's Counsel Initial Comments at 25-26.
\1745\ ACEG Initial Comments at 41.
\1746\ DC and MD Offices of People's Counsel Initial Comments at
25-26.
---------------------------------------------------------------------------
787. Some commenters oppose mandating consideration of Benefit
5.\1747\ AEP argues that reduced congestion due to transmission outages
is of lesser importance and does not need to be in the required minimum
set of benefits.\1748\ NARUC states that benefits associated with new
construction to alleviate congestion is already a planning
consideration.\1749\ Pacific Northwest Utilities and West Virginia
Commission assert that this benefit is not easily quantifiable.\1750\
Idaho Power states that non-RTO/ISO transmission planning regions may
not be able to calculate reduced congestion.\1751\
---------------------------------------------------------------------------
\1747\ AEP Initial Comments at 27-28; NARUC Initial Comments at
23; Pacific Northwest Utilities Initial Comments at 9; West Virginia
Commission Supplemental Comments at 4.
\1748\ AEP Initial Comments at 27.
\1749\ NARUC Initial Comments at 23.
\1750\ Pacific Northwest Utilities Initial Comments at 9; West
Virginia Commission Supplemental Comments at 4.
\1751\ Idaho Power Initial Comments at 8.
---------------------------------------------------------------------------
(c) Commission Determination
788. We adopt the NOPR proposal, with modification, to require
transmission providers in each transmission planning region to measure
and use Benefit 5, Reduced Congestion Due to Transmission Outages, in
Long-Term Regional Transmission Planning. We adopt the NOPR's proposed
description of Benefit 5 as reduced production costs resulting from
avoided congestion during transmission outages. Such benefits include
reduced production costs during transmission outages that significantly
increase transmission congestion. We find that requiring the
measurement and use of Benefit 5, as described, is necessary because
reduced congestion due to transmission outages is widely understood to
be a benefit of transmission facilities.\1752\ As such, we find that
transmission providers must measure and use this benefit in Long-Term
Regional Transmission Planning because it will help to ensure that they
identify, evaluate, and select more efficient or cost-effective
regional
[[Page 49408]]
transmission solutions to address Long-Term Transmission Needs.
---------------------------------------------------------------------------
\1752\ See Acadia Center and CLF Initial Comments at 21-22; ACEG
Initial Comments at 32; ACORE Initial Comments at 12; AEE Reply
Comments at 25; Amazon Initial Comments at 5; Breakthrough Energy
Initial Comments at 21-22; Clean Energy Associations Initial
Comments at 18-20; DC and MD Offices of People's Counsel Initial
Comments at 20; ENGIE Reply Comments at 2-3; Hannon Armstrong
Initial Comments at 2-3; Interwest Initial Comments at 12-14;
National and State Conservation Organizations Initial Comments at 1;
Pine Gate Initial Comments at 34-37; PIOs Initial Comments at 37-38;
RMI Initial Comments at 1; SEIA Initial Comments at 16; Southeast
PIOs Initial Comments at 50.
---------------------------------------------------------------------------
789. We also find that consideration of Benefit 5 is necessary
because most current production cost simulations only consider
generation outages--both planned generation outages and random
distributions of unplanned generation outages; by contrast, production
cost simulations do not typically address transmission outages, either
planned or unplanned. Given that transmission facilities can provide
benefits by reducing production costs during both generation outages
and transmission outages, we find that it is necessary for transmission
providers to measure and use production cost savings during both
generation outages and transmission outages in Long-Term Regional
Transmission Planning. Because Benefit 3, Production Cost Savings, as
described in this order does not capture production cost savings during
transmission outages, we require transmission providers to measure and
use Benefit 5 to ensure that they are accounting for reduced production
costs during transmission outages as well. We note that Benefit 6 is
distinct from other benefits that we require transmission providers to
measure and use in Long-Term Regional Transmission Planning. Although
Benefit 5 and Benefit 6 both measure the benefit of reduced congestion
due to transmission outages, the system conditions used to measure
Benefit 6 include a more expansive set of transmission outages such as
unplanned outages due to extreme weather.
790. For the reasons stated above, we disagree with AEP's arguments
that reduced congestion due to transmission outages is less important
than other benefits and thus should not be required.\1753\ And while
some commenters object to consideration of reduced congestion due to
transmission outages as a benefit on the grounds that this benefit is
not easily quantifiable,\1754\ we believe this benefit is merely
another variant in production cost savings modeling that we already
require for other benefits, such as Benefits 3 and 4.
---------------------------------------------------------------------------
\1753\ AEP Initial Comments at 27.
\1754\ See Pacific Northwest Utilities Initial Comments at 9;
West Virginia Commission Supplemental Comments at 4.
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vi. Benefit 6: Mitigation of Extreme Weather Events and Unexpected
System Conditions
(a) NOPR Description
791. The Commission described the benefit of mitigation of extreme
events and system contingencies in the NOPR as reductions in production
costs resulting from reduced high-cost generation and emergency
procurements necessary to support the transmission system during
extreme events (such as unusual weather conditions, fuel shortages, or
multiple or sustained generation and transmission outages) and system
contingencies.\1755\ These benefits include reduced production costs
during extreme events facilitated by a more robust transmission system
that reduces high-cost generation and emergency procurements necessary
to support the system.\1756\ The Commission noted that transmission
providers can measure benefits from the mitigation of extreme events
and system contingencies by calculating the probability-weighted
production cost savings through production cost simulation for a set of
extreme historical market conditions. The Commission provided as one
example CAISO's analysis of Devers-Palo Verde Line No. 2, where CAISO
modeled several contingencies to determine the value of the line during
high-impact, low-probability events and, as another example, ATC's
production cost simulation analysis of insurance benefits for the ATC
Paddock-Rockdale transmission line. ATC found that probability-weighted
savings from reducing production and power purchase costs during a
number of simulated extreme events offset 20% of total project
costs.\1757\ The Commission also noted that a study found development
of an additional 1,000 MW of transmission capacity into Texas would
have fully paid for itself over four days during Winter Storm Uri and
the same into MISO would have saved $100 million during the same time
period.\1758\
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\1755\ NOPR, 179 FERC ] 61,028 at P 206.
\1756\ Id.
\1757\ Id. P 207 & n.342 (Opinion Granting Certificate of Public
Convenience and Necessity, In the Matter of the Application of
Southern California Edison Company (U 338-E) for a Certificate of
Public Convenience and Necessity Concerning the Devers-Palo Verde
No. 2 Transmission Line Project, Application 05-04-015 (Cal. Comm'n
Jan. 27, 2007)) & n.343 (ATC, Planning Analysis of the Paddock-
Rockdale Project, Docket No. 137-CE-149, app. C, Ex. 1, at 4, 50-53
(Wisc. Pub. Serv. Comm'n Apr. 5, 2007)).
\1758\ Id. P 207 & n.344 (M. Goggin, Grid Strategies, LLC,
Transmission Makes the Power System Resilient to Extreme Weather
(July 2020)).
---------------------------------------------------------------------------
792. Separately, the Commission described the benefit of mitigation
of weather and load uncertainty in the NOPR as reduced production costs
during higher than normal load conditions or significant shifts in
regional weather patterns.\1759\ The Commission stated that this is
beyond the effects of extreme weather described above and may account
for, for example, regional and sub-regional load variances that will
occur due to changing weather patterns.\1760\ The Commission provided,
as one example, simulations that ERCOT performed for normal loads,
higher-than-normal loads, and lower-than-normal loads for a Houston
import project, which showed increased benefits with a probability-
weighted average for all three simulated load conditions.\1761\
---------------------------------------------------------------------------
\1759\ Id. P 208.
\1760\ Id.
\1761\ Id. P 209 & n.345 (citing ERCOT, Economic Planning
Criteria: Question 1: 1/7/2011 Joint CMWG/PLWG Meeting, at 10 (Mar.
4, 2011). The $57.8 million probability-weighted estimate is
calculated based on ERCOT's simulation results for three load
scenarios and Luminant Energy estimated probabilities for the same
scenarios).
---------------------------------------------------------------------------
(b) Comments
793. A number of commenters support mandating consideration of the
benefit of mitigation of extreme events and system contingencies.\1762\
For instance, Grid United states that extreme weather conditions
significantly affect the electric grid and that requiring transmission
providers to consider transmission projects based on their ability to
mitigate extreme weather events will enhance resilience.\1763\ ACEG and
DC and Maryland Offices of People's Counsel state that consideration of
the benefit of mitigation of extreme events and system contingencies is
merited given ``the hundreds of millions of dollars that would have
been saved if transmission capacity had been greater during a number of
actual severe weather episodes.'' \1764\ Clean Energy Associations
assert that transmission providers should not calculate benefits
[[Page 49409]]
solely based on average system conditions, as transmission investments
can provide significant benefits during abnormal or extreme conditions
or events.\1765\
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\1762\ Acadia Center and CLF Initial Comments at 21-22; ACEG
Initial Comments at 32; ACORE Initial Comments at 12; ACORE
Supplemental Comments at 1; AEE Reply Comments at 25; Amazon Initial
Comments at 5; Breakthrough Energy Initial Comments at 21-22; Clean
Energy Associations Initial Comments at 18-20; DC and MD Offices of
People's Counsel Initial Comments at 20; ENGIE Reply Comments at 2-
3; Grid United Initial Comments at 3; Hannon Armstrong Initial
Comments at 2-3; Interwest Initial Comments at 12-14; National and
State Conservation Organizations Initial Comments at 1; Pine Gate
Initial Comments at 34-37; PIOs Initial Comments at 37-38; PJM
Initial Comments at 94 (in combination with Benefit 7, noting that
significant stakeholder engagement is needed to implement); RMI
Initial Comments at 1; SEIA Initial Comments at 16; Southeast PIOs
Initial Comments at 50; US DOE Initial Comments at 31-32; US Senator
Schumer Supplemental Comments at 2-3.
\1763\ Grid United Initial Comments at 3.
\1764\ ACEG Initial Comments at 43 & n.119; DC and Maryland
Offices of People's Counsel Initial Comments at 26-27 & n.65 (both
citing Grid Strategies, LLC, Transmission Makes the Power System
Resilient to Extreme Weather (Jul. 2021), https://acore.org/wp-content/uploads/2021/07/GS_Resilient-Transmission_proof.pdf).
\1765\ Clean Energy Associations Initial Comments at 21.
---------------------------------------------------------------------------
794. Some commenters comment on the manner in which the benefit of
mitigation of extreme events and system contingencies should be
calculated.\1766\ ACEG states that the benefit of mitigation of extreme
events and system contingencies can be calculated by retrospective
analysis or probabilistically. Additionally, ACEG recommends that the
Commission require transmission providers to include avoided scarcity
pricing, storm hardening and wildfire resilience, grid strength, and
increased fuel diversity and system flexibility in addition to
production cost savings when calculating the benefit of mitigation of
extreme events and system contingencies.\1767\ Similarly, DC and MD
Offices of People's Counsel assert that the benefit of mitigation of
extreme events and system contingencies should include resilience
benefits such as storm and wildfire hardening, fuel diversity, and
system flexibility, as well as reduced prices to consumers given that
many regions set scarcity prices at values higher than generator
production costs.\1768\
---------------------------------------------------------------------------
\1766\ ACEG Initial Comments at 43; Clean Energy Associations
Initial Comments at 21; DC and MD Offices of People's Counsel
Initial Comments at 26-27; MISO Initial Comments at 51; NARUC
Initial Comments at 23; Pacific Northwest Utilities Initial Comments
at 9.
\1767\ ACEG Initial Comments at 43-44.
\1768\ DC and MD Offices of People's Counsel Initial Comments at
26-27.
---------------------------------------------------------------------------
795. A number of commenters also support mandating consideration of
the benefit of mitigation of weather and load uncertainty.\1769\ Some
commenters comment on the manner in which the benefit of mitigation of
weather and load uncertainty should be calculated.\1770\ GridLab posits
that mitigation of weather and load uncertainty should only be included
in the context of planning and operating reserves because ``the cost to
system operators of mitigating uncertainty is [the same as] the cost of
holding additional reserves.'' \1771\
---------------------------------------------------------------------------
\1769\ Acadia Center and CLF Initial Comments at 21-22; ACEG
Initial Comments at 32; ACORE Initial Comments at 12; AEE Reply
Comments at 25; Amazon Initial Comments at 5; Breakthrough Energy
Initial Comments at 21-22; Clean Energy Associations Initial
Comments at 18-20; DC and MD Offices of People's Counsel Initial
Comments at 20; ENGIE Reply Comments at 2-3; Grid United Initial
Comments at 3; Hannon Armstrong Initial Comments at 2-3; Interwest
Initial Comments at 12-14; National and State Conservation
Organizations Initial Comments at 1; Pine Gate Initial Comments at
34-37; PIOs Initial Comments at 37-38; PJM Initial Comments at 94
(in combination with Benefit 6, noting that significant stakeholder
engagement would be necessary to implement); RMI Initial Comments at
1; SEIA Initial Comments at 16; Southeast PIOs Initial Comments at
50; US DOE Initial Comments at 31-32.
\1770\ ACEG Initial Comments at 44; GridLab Initial Comments at
26; NARUC Initial Comments at 23.
\1771\ GridLab Initial Comments at 26.
---------------------------------------------------------------------------
796. Other commenters oppose mandating consideration of the benefit
of mitigation of extreme events and system contingencies, arguing that
it is challenging to quantify and that its calculation entails
subjective judgment.\1772\ Louisiana Commission states that the value
of mitigating extreme weather events can vary significantly across
transmission planning regions and states. Louisiana Commission opposes
any extreme weather benefit category that would result in the
assignment of costs of transmission hardening projects to Louisiana
ratepayers from which they do not benefit. Louisiana Commission further
states that any analysis of this benefit should be limited to
sensitivities.\1773\
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\1772\ NRECA Initial Comments at 45; Pacific Northwest Utilities
Initial Comments at 9; West Virginia Commission Supplemental
Comments at 4.
\1773\ Louisiana Commission Initial Comments at 18-19.
---------------------------------------------------------------------------
797. Some commenters oppose mandating consideration of the
mitigation of weather and load uncertainty.\1774\ AEP states that this
benefit should not be included in the minimum set of benefits because
it is of lesser importance than other benefits described in the
NOPR.\1775\ NRECA argues that quantifying this benefit requires
subjective judgment.\1776\ According to Pacific Northwest Utilities,
this benefit accrues to generation and load-serving entities, not to
transmission providers.\1777\
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\1774\ AEP Initial Comments at 27; NARUC Initial Comments at 23;
NRECA Initial Comments at 45; Pacific Northwest Utilities Initial
Comments at 9.
\1775\ AEP Initial Comments at 27.
\1776\ NRECA Initial Comments at 45.
\1777\ Pacific Northwest Utilities Initial Comments at 9.
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798. NARUC states that the benefits of mitigation of extreme
events, system contingencies, weather, and load uncertainties may be
more appropriate for consideration in interregional transmission
planning, depending on the size of the transmission planning region.
While NARUC states that mitigation of such contingencies is among the
soundest reasons for Interregional Transfer Capability planning, it
also notes that in regions with a large footprint (e.g., PJM, MISO) it
may be possible to assess these resilience benefits in the regional
transmission planning process.\1778\
---------------------------------------------------------------------------
\1778\ NARUC Initial Comments at 21, 23.
---------------------------------------------------------------------------
799. MISO states that the treatment of mitigation of extreme events
and system contingencies and mitigation of weather and load uncertainty
as economic benefits differ only to the degree at which production cost
savings are realized. MISO also states that ``mitigation of extreme
events'' may be represented as a reliability benefit where a value of
outage costs can be used to monetize the benefits of mitigating the
risk of load shedding.\1779\ PJM suggests that the Commission should
consolidate the benefits of mitigation of extreme events and system
contingencies and the benefits of mitigation of weather and load
uncertainty into a single enhanced reliability benefit that would
evaluate the ability of grid enhancements to serve load reliably under
extreme events and vulnerabilities.\1780\ MISO and NARUC state that
their comments regarding mitigation of extreme events and system
contingencies are equally applicable to mitigation of weather and load
uncertainty.\1781\
---------------------------------------------------------------------------
\1779\ MISO Initial Comments at 51.
\1780\ PJM Initial Comments at 94.
\1781\ MISO Initial Comments at 51; NARUC Initial Comments at
23.
---------------------------------------------------------------------------
(c) Commission Determination
800. We adopt the NOPR proposal, with modification, to require
transmission providers in each transmission planning region to measure
and use Final Order Benefit 6, mitigation of extreme weather events and
unexpected system conditions, in Long-Term Regional Transmission
Planning. The revised Final Order Benefit 6 modifies and combines two
of the benefits proposed in the NOPR: (1) mitigation of extreme events
and system contingencies (NOPR Benefit 6) and (2) mitigation of weather
and load uncertainty (NOPR Benefit 7).\1782\ In combining these two
proposed NOPR benefits, we modify the description of NOPR Benefit 6 and
describe Final Order Benefit 6 as reduced production costs and reduced
loss of load (or emergency procurements necessary to support the
system), including due to increased Interregional Transfer Capability,
during extreme weather events and unexpected system conditions, such as
unusual weather conditions or fuel shortages that result in multiple
concurrent and sustained generation and/or transmission outages. The
description of Final Order Benefit 6 that we adopt in this final order
[[Page 49410]]
includes three additional modifications to the NOPR proposals
describing NOPR Benefit 6 and NOPR Benefit 7. First, we require
transmission providers to measure, as part of Benefit 6,\1783\ the
benefits of reduced loss of load (not only reduced production costs).
Second, we require transmission providers, as part of Benefit 6, to
account for both extreme weather events and unexpected system
conditions when transmission facilities have particularly high value.
The unexpected system conditions can include, for example, system
contingencies in the form of generator and/or transmission outages,
extreme or volatile production costs, and generation and/or load
forecast errors. Third, we require transmission providers to measure,
as part of Benefit 6, the benefits associated with any increase in
Interregional Transfer Capability provided by a Long-Term Regional
Transmission Facility during an extreme weather event or unexpected
system condition that results in multiple and concurrent sustained
generation and/or transmission outages.
---------------------------------------------------------------------------
\1782\ NOPR, 179 FERC ] 61,028 at PP 206-207 (NOPR Benefit 6),
208-209 (NOPR Benefit 7).
\1783\ Throughout this final order, ``Benefit 6'' refers to
``Final Order Benefit 6'' unless preceded by ``NOPR.''
---------------------------------------------------------------------------
801. We find that requiring the measurement and use of Benefit 6 in
Long-Term Regional Transmission Planning is necessary because Long-Term
Regional Transmission Facilities could result in reduced production
costs and reduced loss of load (or reduced emergency procurements
necessary to support the system), including reductions due to increased
Interregional Transfer Capability, and improved performance during
extreme weather events and unexpected system conditions. Further, the
benefit of mitigation of high production costs resulting from extreme
weather events and unexpected system conditions can be economically
significant. A relatively few numbers of hours could represent a large
share of the total benefit of reduced congestion costs that a Long-Term
Regional Transmission Facility provides.\1784\ We also find that it is
critical for transmission providers to measure and use Benefit 6 given
that extreme weather events and unexpected system conditions have
significantly and increasingly affected the reliable operation of the
electric grid. As the Commission has previously noted, extreme weather
events have occurred with greater frequency in recent years, leading to
load shed events that present an unacceptable risk to life and have an
extreme economic impact.\1785\ By requiring the use of Benefit 6, we
ensure that transmission providers measure and use the benefit of Long-
Term Regional Transmission Facilities under these conditions when
performing Long Term Regional Transmission Planning. Further, by
requiring use of Benefit 6, we enable transmission providers to
identify, evaluate, and select Long-Term Regional Transmission
Facilities that more efficiently or cost-effectively address Long-Term
Transmission Needs.
---------------------------------------------------------------------------
\1784\ E.g., ACORE Initial Comments at 11 (citing LBNL Aug. 2022
Transmission Value Study at 33).
\1785\ See Order No. 896, 183 FERC ] 61,191 at P 2; Order No.
897, 183 FERC ] 61,192 at PP 21-22.
---------------------------------------------------------------------------
802. Regarding the first modification listed above, we require
transmission providers to measure, as part of Benefit 6, reduced loss
of load (or reduced emergency energy procurement to avoid loss of
load), not only reduced production costs. We find it necessary to
include reduced loss of load because Long-Term Regional Transmission
Facilities can provide benefits by improving reliability during extreme
weather events and unexpected system conditions,\1786\ which can be
significant given the high cost and risk to life during periods with
insufficient generation to meet system load. An example of how a
reduction in loss of load could be measured is by quantifying the
reduction in expected unserved energy but for the Long-Term Regional
Transmission Facility during an extreme weather event or unexpected
system conditions, determining the value of lost load, and multiplying
these two values to obtain a monetary value.\1787\
---------------------------------------------------------------------------
\1786\ PJM Initial Comments at 94; MISO Initial Comments at 12-
13; Order No. 897, 183 FERC ] 61,192 at PP 6-12.
\1787\ E.g., MISO, LRTP Tranche 2 Business Case Benefit Metrics,
6-7 (Aug. 31, 2023), https://cdn.misoenergy.org/20230831%20LRTP%20Workshop%20Item%2002%20Business%20Case%20Metrics%20Development630034.pdf.
---------------------------------------------------------------------------
803. We note that Benefit 6 is distinct from other benefits that we
require transmission providers to measure and use, because transmission
providers must model different system conditions (extreme weather
events and unexpected system conditions) when measuring Benefit 6.
Specifically, Benefit 2(a) measures reduced loss of load probability in
the context of the system conditions used for resource adequacy
planning, which typically includes consideration of normal system
conditions and may vary by region. In contrast, Benefit 6 measures
reduced loss of load for specific extreme weather events and unexpected
system conditions identified by the transmission providers.\1788\
Additionally, while Benefit 3 and Benefit 6 both measure production
cost savings, the system conditions used to measure Benefit 6 can
include higher electricity demand, volatile production costs, and a
more expansive set of generation outages, such as unplanned generation
outages due to extreme weather. Similarly, Benefit 5 and Benefit 6 both
measure the benefits of reduced congestion due to transmission outages;
however, the system conditions used to measure Benefit 6 include a more
expansive set of transmission outages, such as unplanned transmission
outages due to extreme weather.
---------------------------------------------------------------------------
\1788\ Benefit 2(b), which measures the benefit of reduced
planning reserve margin, is also used in the context of resource
adequacy planning. We do not allow transmission providers to measure
Benefit 6 in terms of reduced planning reserve margin because system
planners do not always model extreme weather events or unexpected
system conditions when establishing the planning reserve margin used
for resource adequacy purposes. In contrast, reduced loss of load
can be measured for any system condition, even those conditions that
are not used for resource adequacy planning.
---------------------------------------------------------------------------
804. Regarding the second modification listed above, we require
transmission providers, as part of Benefit 6, to account for mitigation
of unexpected system conditions during periods when transmission
facilities have particularly high value, not only during extreme
weather events. We recognize that unexpected system conditions can
create periods when Long-Term Regional Transmission Facilities have
particularly high value because of, for example, generator and/or
transmission outages, extreme or volatile production costs, and
generation and/or load forecast errors.\1789\ Limited resource
availability, or limited system flexibility, can make
[[Page 49411]]
it challenging for system operators to immediately address these
unexpected system conditions, and Long-Term Regional Transmission
Facilities that provide benefits under Benefit 6 will equip system
operators with more options to manage the worst-case outcomes. These
high-value periods of unexpected system conditions, while infrequent
and not necessarily during extreme weather events, may account for a
large share of the potential value of a Long-Term Regional Transmission
Facility.\1790\ We require transmission providers to account for
circumstances that contribute to these infrequent and high-value
periods specific to their transmission planning region when measuring
Benefit 6. Transmission providers may, for example, identify historical
periods when significant transmission congestion was due to certain
conditions (e.g., generators being unavailable due to a forecast
error), then model those conditions in each Long-Term Scenario.\1791\
Therefore, we require transmission providers to use not only
information from modeling extreme weather events but also information
from additional modeling that accounts for unexpected system
conditions, as part of Benefit 6. To avoid double-counting of similar
circumstances, transmission providers must account for extreme weather
events and unexpected system conditions that are separate and distinct
such that the benefits of mitigating each system condition can be
combined into a single benefit measure.
---------------------------------------------------------------------------
\1789\ See, e.g., ACEG Initial Comments at 42-45 (citing
Pfeifenberger, Ruiz, Van Horn, The Value of Diversifying Uncertain
Renewable Generation through the Transmission System (Oct. 14,
2020), https://open.bu.edu/handle/2144/41451; The Brattle Group and
Grid Strategies, Transmission Planning for the 21st Century: Proven
Practices that Increase Value and Reduce Costs, 2, 34, 78, 85-86, 99
(2021), https://www.brattle.com/wp-content/uploads/2021/10/2021-10-12-Brattle-GridStrategies-TransmissionPlanning-Report_v2.pdf); DC
and MD Offices of People's Counsel Initial Comments at 28 (citing
Pfeifenberger, Ruiz, Van Horn, The Value of Diversifying Uncertain
Renewable Generation through the Transmission System, BU-ISE (Oct.
14, 2020), https://open.bu.edu/handle/2144/41451); US Senator
Schumer Supplemental Comments at 2-3 (citing Millstein et al.,
Lawrence Berkeley National Laboratory, The Latest Market Data Show
that the Potential Savings of New Electric Transmission was Higher
Last Year than at Any Point in the Last Decade, 3-6 (Feb. 2023),
https://eta-publications.lbl.gov/sites/default/files/lbnl-transmissionvalue-fact_sheet-2022update-20230203.pdf); US Senator
Whitehouse Supplemental Comments at 2 (referencing outages related
to extreme events having costs, including economic costs of in the
billions of dollars from elevated energy costs).
\1790\ LBNL Aug. 2022 Transmission Value Study at 33 (stating
that the majority of transmission value estimated occurs during
``extreme'' conditions that fall outside of the 171 designated
extreme weather event days between 2012 and 2021); Millstein et al.,
Lawrence Berkeley National Laboratory, The Latest Market Data Show
that the Potential Savings of New Electric Transmission was Higher
Last Year than at Any Point in the Last Decade, 3-6 (Feb. 2023),
https://eta-publications.lbl.gov/sites/default/files/lbnl-transmissionvalue-fact_sheet-2022update-20230203.pdf.
\1791\ Alternatively, transmission providers may, for example,
use probabilistic transmission planning methods to account for
infrequent and high-value periods.
---------------------------------------------------------------------------
805. Finally, we require transmission providers to measure, as part
of Benefit 6, the benefits associated with any increase in
Interregional Transfer Capability that a Long-Term Regional
Transmission Facility would provide during an extreme weather event and
unexpected system conditions that results in multiple concurrent and
sustained generation and/or transmission outages. As discussed above,
we find that Long-Term Regional Transmission Facilities can increase
Interregional Transfer Capability by changing the topology of the
transmission system.\1792\ Further, we find that the benefits of
mitigating extreme weather events and unexpected system conditions due
to increased Interregional Transfer Capability provided by Long-Term
Regional Transmission Facilities can be significant.\1793\ To comply
with this requirement, transmission providers must include in the
modeling they use to measure Benefit 6 any increase in Interregional
Transfer Capability that a Long-Term Regional Transmission Facility
would provide during an extreme weather event and unexpected system
conditions that results in multiple concurrent and sustained generation
and/or transmission outages.
---------------------------------------------------------------------------
\1792\ Supra Long-Term Regional Transmission Planning, Long-Term
Scenarios Requirements, Sensitivities for High-Impact, Low-Frequency
Events section.
\1793\ ACEG Initial Comments at 5; ACEG Reply Comments at 3-5;
BP Initial Comments at 10; Breakthrough Energy Initial Comments at
2; Clean Energy Associations Initial Comments at 5, 21; Kansas
Corporation Commission Initial Comments at 8-9; NARUC Initial
Comments at 23; US DOE Initial Comments at 39-42.
---------------------------------------------------------------------------
806. To account for extreme weather events as part of Benefit 6,
transmission providers may incorporate information from the sensitivity
they must develop and apply to each Long-Term Scenario that includes
multiple concurrent and sustained generation and/or transmission
outages due to an extreme weather event across a wide area.\1794\ We
reiterate that we require transmission providers to measure the
required benefits under each Long-Term Scenario. However, in the case
of Benefit 6, transmission providers may measure the benefit of
mitigating extreme weather events using the required extreme weather
event sensitivity applied to each Long-Term Scenario; we do not require
them to separately measure the benefit of mitigating extreme weather
events in each scenario without applying that sensitivity.\1795\
---------------------------------------------------------------------------
\1794\ Supra Long-Term Regional Transmission Planning, Long-Term
Scenarios Requirements, Sensitivities for High-Impact, Low-Frequency
Events section (stating transmission providers must develop at least
one sensitivity, applied to each Long-Term Scenario, to account for
uncertain operational outcomes that determine the benefits of and/or
need for transmission facilities during multiple concurrent and
sustained generation and/or transmission outages due to an extreme
weather event across a wide area). Transmission providers may also
incorporate analyses from an Extreme Weather Vulnerability
Assessment as generally described in Order No. 897.
\1795\ We recognize that transmission providers may not use an
extreme weather event sensitivity that includes system conditions
that allow transmission providers to measure the benefit of
mitigating unexpected system conditions in every Long-Term Scenario.
In such cases, transmission providers must measure the benefit of
mitigating unexpected system conditions in each Long-Term Scenario
even without an extreme weather event sensitivity applied to those
scenarios or must apply a separate sensitivity that allows for the
measurement of Benefit 6 to each Long-Term Scenario.
---------------------------------------------------------------------------
807. Consistent with all other benefits that we require
transmission providers to measure, we do not require a standardized
method for measuring Benefit 6 subject to measuring the components
described above.\1796\ As the Commission stated in the NOPR, there are
different approaches to calculating components of this benefit,\1797\
and this final order provides transmission providers with flexibility
in developing the method that they will use to measure this benefit.
---------------------------------------------------------------------------
\1796\ E.g., ACEG Initial Comments at 42-44; DC and MD Offices
of People's Counsel Initial Comments at 26-27.
\1797\ NOPR, 179 FERC ] 61,028 at P 207 (providing examples of
CAISO's analysis of Devers-Palo Verde Line No. 2, ATC's production
cost simulation analysis of insurance benefits for the ATC Paddock-
Rockdale transmission line, and a Grid Strategies study).
---------------------------------------------------------------------------
808. We disagree with commenters who express general concerns
regarding the difficulty of measuring this benefit.\1798\ In the NOPR,
the Commission identified studies that measured benefits of a
transmission facility in a manner similar to the requirements in
Benefit 6.\1799\ Because we allow flexibility as far as the method
transmission providers use to measure each benefit included in the
required set of benefits, including Benefit 6, we believe that
transmission providers should be able to tailor a method for measuring
Benefit 6 that fits their circumstances. Further, transmission
providers can build on methods that they use to measure the other
benefits required by this final order to measure Benefit 6. For
example, transmission providers can use the same method to measure
reduced production costs in accordance with Benefit 6 as they do to
measure Benefit 3, Production Costs Savings, but modify the model
inputs to capture reduced production costs during extreme weather
events and unexpected system conditions. Moreover, we recognize that
there is a balance between requiring transmission providers to measure
the benefits of Long-Term Regional Transmission Facilities that are
most readily measured and ensuring that transmission providers are
appropriately capturing the value of Long-Term Regional Transmission
Facilities when evaluating them for selection. Even to the extent to
which Benefit 6 may be more difficult to measure than the other
benefits that
[[Page 49412]]
we require, we nonetheless find that requiring transmission providers
to measure Benefit 6 is necessary because Benefit 6 is
significant.\1800\
---------------------------------------------------------------------------
\1798\ NRECA Initial Comments at 45; Pacific Northwest Utilities
Initial Comments at 9; West Virginia Commission Supplemental
Comments at 4.
\1799\ NOPR, 179 FERC ] 61,028 at PP 207, 209.
\1800\ Supra P 797.
---------------------------------------------------------------------------
809. We are unpersuaded by general arguments that transmission
providers should not consider this benefit because it varies by
transmission planning region or it only accrues to certain
entities.\1801\ We are not requiring transmission providers to model a
specific extreme weather event or unexpected system condition;
transmission providers may decide what extreme weather event and
unexpected system conditions to model, allowing them to ensure that the
conditions modeled are relevant to circumstances in their transmission
planning region. In response to NRECA's argument that this benefit
requires subjective judgement,\1802\ we conclude that transmission
providers have sufficient expertise to identify and model extreme
weather events and unexpected system conditions when evaluating Long-
Term Regional Transmission Facilities.\1803\ In response to AEP's
argument that NOPR Benefit 7 (mitigation of weather and load
uncertainty) is of lesser importance compared to other benefits
described in the NOPR and should be optional for transmission providers
to measure and use,\1804\ we disagree because the evidence in the
record demonstrates that Final Order Benefit 6 (which includes NOPR
Benefit 7) is significant.\1805\
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\1801\ Louisiana Commission Initial Comments at 18-19; Pacific
Northwest Utilities Initial Comments at 9.
\1802\ NRECA Initial Comments at 45.
\1803\ NESCOE Initial Comments at 42.
\1804\ AEP Initial Comments at 27.
\1805\ Supra note 1769; see also ACORE Initial Comments at 11
(citing LBNL Aug. 2022 Transmission Value Study at 33).
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810. NARUC states that the benefit of mitigation of extreme weather
events may need to be more fully considered only in large transmission
planning regions or in interregional transmission planning.\1806\
Although transmission providers could also consider the benefits of
mitigation of extreme weather events as part of interregional
transmission coordination, we believe transmission providers can
measure and use the benefit of mitigation of extreme weather events in
regional transmission planning processes regardless of the size of the
transmission planning region, because extreme weather events can occur
and affect the transmission system in any region. If the size of the
extreme weather event is larger than the transmission planning region,
transmission providers can consider the extent to which they can rely
on interregional flows from other transmission planning regions during
the extreme weather event. We note that transmission providers in each
transmission planning region must coordinate and share information with
the transmission providers in each neighboring transmission planning
region and must identify and jointly evaluate interregional
transmission facilities that may be more efficient or cost-effective
transmission facilities to address Long-Term Transmission Needs, as
described in more detail in the Interregional Transmission Coordination
section of this final order. Better measurement of the benefits of
mitigation of extreme weather events as part of regional transmission
planning can only help facilitate such efforts. We encourage
transmission providers in neighboring transmission planning regions to
share information with one another that would be useful to measure
Benefit 6 more accurately through their interregional transmission
coordination procedures.
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\1806\ NARUC Initial Comments at 21, 23.
---------------------------------------------------------------------------
811. Some commenters state that the benefits of mitigation of
extreme events and system contingencies and mitigation of weather and
load uncertainty overlap, or should be combined.\1807\ We note that
Benefit 6, as described above, modifies and combines the benefits
proposed in the NOPR of (1) mitigation of extreme events and system
contingencies and (2) mitigation of weather and load uncertainty, which
should address concerns of separately requiring transmission providers
to use two similar benefits that some argue could overlap.
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\1807\ MISO Initial Comments at 51; PJM Initial Comments at 94.
---------------------------------------------------------------------------
vii. Final Order Benefit 7: Capacity Cost Benefits From Reduced Peak
Energy Losses
(a) NOPR Description
812. The Commission described this benefit, NOPR Benefit 8
(renumbered in this final order as Final Order Benefit 7), in the NOPR
as reduced generation capacity investment needed to meet peak
load.\1808\ The Commission noted that capacity cost savings from
reduced peak energy losses benefits refer to the ability of proposed
transmission facilities to lessen the amount of transmission system
energy losses during peak-load conditions which, over time, would
decrease the need for new generation capacity installations or
purchases. To the extent that new transmission facilities result in
changes to generation dispatch and flows, transmission system energy
losses will also change. If transmission system losses are reduced via
the new transmission facilities, transmission providers will not have
to construct or procure additional generation to satisfy installed
capacity requirements for peak-load conditions. If there is a reduction
in energy losses during peak conditions, this would result in,
presumably, lowered investments for generation capacity resources to
meet the peak load. For example, Entergy found that potential
transmission facilities in its footprint could reduce peak-load
transmission losses and associated needed generation investment by 2%
of total transmission facility costs.\1809\ The Commission noted that
capacity cost savings from reduced peak energy losses only attempt to
evaluate benefits for peak-load conditions.
---------------------------------------------------------------------------
\1808\ NOPR, 179 FERC ] 61,028 at P 210.
\1809\ Id. P 211 & n.346 (citing ITC, Joint Application, Docket
No. EC12-145-000, Ex. ITC-600 (Testimony of Pfeifenberger), at 77-78
(filed Sept. 24, 2012)).
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813. The Commission stated that one potential way to calculate
capacity cost savings from reduced peak energy losses is to calculate
the present value of capital cost savings associated with the reduction
in installed generation requirements.\1810\ To arrive at the value of
associated capital cost savings, the estimated net cost of new entry
(Net CONE) (i.e., the cost of new peaking generating capacity net of
operating margins earned in energy and ancillary services markets when
the region is resource constrained) would be multiplied by the
reduction in installed generation capacity requirements. The resulting
value would represent the avoided cost of procuring more generation to
cover transmission system losses during peak-load conditions that would
be passed on to consumers via lowered generation capacity costs.\1811\
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\1810\ Id. P 212.
\1811\ Id.
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(b) Comments
814. A number of commenters support mandating consideration of NOPR
Benefit 8.\1812\ ACEG and DC and
[[Page 49413]]
MD People's Counsel state that NOPR Benefit 8 is a distinct benefit
category that has been measured before.\1813\ PIOs state that SPP
quantified NOPR Benefit 8 in its 2016 Regional Cost Allocation Review
and that ``leav[ing] these cost savings on the cutting room floor will
ultimately raise costs for consumers and result in an inefficient
transmission plan.'' \1814\
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\1812\ Acadia Center and CLF Initial Comments at 21-22; ACEG
Initial Comments at 32, 45; ACORE Initial Comments at 12; AEE Reply
Comments at 25; Amazon Initial Comments at 5; Breakthrough Energy
Initial Comments at 21-22; Clean Energy Associations Initial
Comments at 18-20; DC and MD Offices of People's Counsel Initial
Comments at 20; ENGIE Reply Comments at 2-3; Hannon Armstrong
Initial Comments at 2-3; Interwest Initial Comments at 12-14;
National and State Conservation Organizations Initial Comments at 1;
Pine Gate Initial Comments at 34-37; PIOs Initial Comments at 37-38;
RMI Initial Comments at 1; SEIA Initial Comments at 16; Southeast
PIOs Initial Comments at 50.
\1813\ ACEG Initial Comments at 48; DC and MD People's Counsel
Initial Comments at 28 (both citing ITC, Joint Application, Docket
No. EC12-145-000, Ex. ITC-600 (Testimony of Pfeifenberger), at 77-78
(filed Sept. 24, 2012); SPP, SPP Priority Projects Phase II Report,
Rev. 1, April 27, 2010, at 26; ATC, Planning Analysis of the
Paddock-Rockdale Project, April 5, 2007 (filed in PSCW Docket 137-
CE-149, PSC Reference # 75598), at 4, 63; and MISO, Proposed Multi
Value Project Portfolio, Technical Study Task Force and Business
Case Workshop, August 22, 2011, at 25, 27)).
\1814\ PIOs Initial Comments at 42.
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815. Other commenters, such as NARUC, oppose mandating
consideration of NOPR Benefit 8. NARUC contends that this benefit is a
subset of the lowered system reserve margins benefit. NARUC states that
NOPR Benefit 8 is unlikely to occur within organized, competitive
generation markets because additional transmission will not deter the
installation of new generation under current Federal open access
policies. However, NARUC argues, this benefit may be attainable in
transmission planning regions served by vertically integrated utilities
where transmission can substitute for new generation construction.
NARUC asserts that hundreds of thousands of megawatts of generation
currently await interconnection studies in the various RTOs/ISOs and
non-RTO/ISO transmission planning regions, and it is difficult to see
how construction of new transmission facilities can remove any of this
demand for additional generator interconnection.\1815\
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\1815\ NARUC Initial Comments at 24.
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816. West Virginia Commission also opposes a requirement to use
NOPR Benefit 8, arguing that the calculation requires significant
evidence based on assumptions that are difficult, if not impossible, to
quantify before the fact.\1816\
---------------------------------------------------------------------------
\1816\ West Virginia Commission Supplemental Comments at 4.
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(c) Commission Determination
817. As an initial matter, we renumber NOPR Benefit 8 and refer to
it in this determination section as Final Order Benefit 7. We adopt the
NOPR proposal, with modification, to require transmission providers in
each transmission planning region to measure and use Final Order
Benefit 7, Capacity Cost Benefits from Reduced Peak Energy Losses, in
Long-Term Regional Transmission Planning. We adopt the NOPR's proposed
description of Final Order Benefit 7 as reduced generation capacity
investment needed to meet peak load.\1817\ We find that requiring the
use and measurement of Final Order Benefit 7, as described, is
necessary to ensure that capacity cost benefits from reduced peak
energy losses are not excluded from Long-Term Regional Transmission
Planning because standard production cost modeling and the other
benefits that this final order requires transmission providers to
measure and use will not capture this benefit. Absent a requirement for
transmission providers to measure and use Final Order Benefit 7 in
Long-Term Regional Transmission Planning, transmission providers may
not identify, evaluate, and select Long-Term Regional Transmission
Facilities that more efficiently or cost-effectively address Long-Term
Transmission Needs.
---------------------------------------------------------------------------
\1817\ We note that in the NOPR, this benefit was designated as
Benefit 8. We have revised the ordering designation of this benefit
in this final order.
---------------------------------------------------------------------------
818. One potential way to measure capacity cost savings from
reduced peak energy losses is to calculate the present value of capital
cost savings associated with the reduction in installed generation
requirements. To arrive at the value of capital cost savings, the
estimated net cost of new entry (i.e., the cost of new peaking
generating capacity net of operating margins earned in energy and
ancillary services markets when the region is resource constrained)
could be multiplied by the reduction in installed generation capacity
requirements. The resulting value would represent the avoided cost of
procuring more generation to cover transmission system losses during
peak-load conditions, savings that would be passed on to customers via
lowered generation capacity costs.
819. We disagree with NARUC's contention that this benefit is a
subset of the lowered system reserve margins benefit and that it is
unlikely to occur within organized, competitive generation
markets.\1818\ ACEG and DC and MD People's Counsel both indicate that
Final Order Benefit 7 is a distinct benefit category that has been
measured before, citing MISO's Multi-Value Project portfolio, among
other examples of its use, which measures capacity cost savings from
reduced peak energy losses as an independent benefit.\1819\ While we
acknowledge that this benefit may have the effect of lowering system
reserve margins, we agree with PIOs that these cost savings are
distinct from Benefit 2 and that failing to specifically evaluate
potential cost savings related to reduced peak energy losses may result
in higher capacity costs and relatively inefficient or less cost-
effective transmission development. As discussed above, Benefit 2
recognizes potential cost savings of providing additional pathways for
connecting generation resources with load. Here, we are assessing the
benefits of limiting transmission losses along those pathways. We also
note that this approach is consistent with Benefits 3 and 4 above that
separately recognize potential cost savings associated with lower
production costs and reduced transmission energy losses in energy
markets. In light of the evidence that multiple transmission providers
have successfully measured this benefit, as well as the example that we
provide above describing how a transmission provider may be able to
calculate this benefit, we further disagree with West Virginia
Commission's argument that calculation of this benefit is based on
assumptions that are difficult to quantify in advance.
---------------------------------------------------------------------------
\1818\ NARUC Initial Comments at 24.
\1819\ ACEG Initial Comments at 48; DC and MD People's Counsel
Initial Comments at 28 (both citing ITC, Joint Application, Docket
No. EC12-145-000, Ex. ITC-600 (Testimony of Pfeifenberger), at 77-78
(filed Sept. 24, 2012); SPP, SPP Priority Projects Phase II Report,
Rev. 1, April 27, 2010, at 26; ATC, Planning Analysis of the
Paddock-Rockdale Project, April 5, 2007 (filed in PSCW Docket 137-
CE-149, PSC Reference # 75598), at 4, 63; and MISO, Proposed Multi
Value Project Portfolio, Technical Study Task Force and Business
Case Workshop, August 22, 2011, at 25, 27)).
---------------------------------------------------------------------------
viii. Other Benefits
(a) Comments
820. Numerous commenters address in various ways the other five
benefits that the Commission described in the NOPR but that we do not
require transmission providers to measure and use in Long-Term Regional
Transmission Planning in this final order: mitigation of weather and
load uncertainty,\1820\ deferred generation capacity investments,
access to lower cost generation, increased competition, and increased
market liquidity.\1821\
[[Page 49414]]
Other commenters address in various ways benefits not listed in the
NOPR for transmission providers to consider for use in evaluating Long-
Term Regional Transmission Facilities.\1822\
---------------------------------------------------------------------------
\1820\ We note that elements of this benefit are now contained
in Benefit 6, the description of which has been revised from the
NOPR.
\1821\ Acadia Center and CLF Initial Comments at 21-22; ACEG
Initial Comments at 32, 45-48; ACORE Initial Comments at 12; AEE
Reply Comments at 25; AEP Initial Comments at 25-27; Amazon Initial
Comments at 5; Breakthrough Energy Initial Comments at 21-22; Clean
Energy Associations Initial Comments at 18-20; DC and MD Offices of
People's Counsel Initial Comments at 20, 28-30; ENGIE Reply Comments
at 2-3; Hannon Armstrong Initial Comments at 2-3; Idaho Power
Initial Comments at 7-8; Interwest Initial Comments at 12-14; ISO-NE
Initial Comments at 34; Joint Consumer Advocates Initial Comments at
11-12; MISO Initial Comments at 50-51; NARUC Initial Comments at 21,
24-25; National and State Conservation Organizations Initial
Comments at 1; New Jersey Commission Initial Comments at 11-14;
North Carolina Commission and Staff Initial Comments at 6-7; NRECA
Initial Comments at 45; Pacific Northwest Utilities Initial Comments
at 9; Pine Gate Initial Comments at 34-37; PIOs Initial Comments at
37-38; PJM Initial Comments at 94; PJM Market Monitor Initial
Comments at 5-6; PPL Initial Comments at 13-15; RMI Initial Comments
at 1; SEIA Initial Comments at 16; Southeast PIOs Initial Comments
at 50; Southeast PIOs Reply Comments at 27-28; Southern Initial
Comments at 25-27; West Virginia Commission Supplemental Comments at
4; US DOE Initial Comments at 31-32.
\1822\ ACEG Initial Comments at 6-8; AEE Reply Comments at 25-
26; AEP Initial Comments at 6, 23-27; Amazon Initial Comments at 5;
Breakthrough Energy Initial Comments at 21-23; California Commission
Initial Comments at 31-34; California Energy Commission Initial
Comments at 3; CARE Coalition Initial Comments at 32-33; Certain
TDUs Reply Comments at 1-3; Clean Energy Associations Initial
Comments at 19-20; Clean Energy Buyers Initial Comments at 20-21;
Clean Energy States Initial Comments at 6-8; DC and MD Offices of
People's Counsel Initial Comments at 18-19; Entergy Initial Comments
at 21; Environmental Groups Supplemental Comments at 2-3; Grand
Rapids NAACP Initial Comments at 21-23; GridLab Initial Comments at
25-28; Interwest Initial Comments at 13-14; ITC Initial Comments at
21-22; Joint Consumer Advocates Initial Comments at 11-12; Large
Public Power Initial Comments at 28-29; Michigan Commission Initial
Comments at 7; Nevada Commission Initial Comments at 10-11;
Northwest and Intermountain Initial Comments at 15-16; NYISO Initial
Comments at 39; Pattern Energy Reply Comments at 8-9; PIOs Initial
Comments at 43-44; PIOs Reply Comments at 7-8; PJM Initial Comments
at 94-96; Policy Integrity Initial Comments at 28; Policy Integrity
Supplemental Comments at 4-8; PPL Initial Comments at 14-15; R
Street Initial Comments at 9-10; Rail Electrification Initial
Comments at 6-7; RMI Initial Comments at 2; SEIA Initial Comments at
16-17; Shell Initial Comments at 14-16; Tabors Caramanis Rudkevich
Initial Comments at 6; US DOE Initial Comments at 33-34; Vistra
Initial Comments at 15-16; WE ACT Initial Comments at 2-3.
---------------------------------------------------------------------------
(b) Commission Determination
821. We decline to require transmission providers to measure and
use the remaining five benefits described in the NOPR in Long-Term
Regional Transmission Planning (i.e., mitigation of weather and load
uncertainty, generation capacity investments, access to lower-cost
generation, increased competition, and increased market liquidity). We
find that the required set of benefits that we adopt herein is a
sufficiently broad range of benefits to ensure that transmission
providers are identifying, evaluating, and selecting Long-Term Regional
Transmission Facilities that more efficiently or cost-effectively
address Long-Term Transmission Needs. As such, we find that the
measurement and use of additional benefits in Long-Term Regional
Transmission Planning is not necessary to ensure that rates remain just
and reasonable.
822. However, we recognize that Long-Term Regional Transmission
Facilities may provide additional benefits that may merit consideration
when transmission providers are identifying, evaluating, and selecting
such facilities to address Long-Term Transmission Needs more
efficiently or cost-effectively. Therefore, transmission providers may
measure and use additional benefits beyond those included in the
required set of benefits in Long-Term Regional Transmission Planning,
including on a transmission facility or plan-specific basis, subject to
the requirement that they do so in a manner that is consistent with
their obligations under Order No. 890 and Order No. 1000 transmission
planning principles to be open and transparent as to their transmission
planning processes.
3. Identification, Measurement, and Evaluation of the Benefits of Long-
Term Regional Transmission Facilities
a. NOPR Proposal
823. The Commission proposed to require transmission providers in
each transmission planning region to identify on compliance the
benefits that they will use in Long-Term Regional Transmission
Planning, how they will calculate those benefits, and how the benefits
will reasonably reflect the benefits of regional transmission
facilities to meet identified transmission needs driven by changes in
the resource mix and demand. The Commission proposed that as part of
this compliance obligation, transmission providers would be required to
explain the rationale for using the benefits identified.\1823\
---------------------------------------------------------------------------
\1823\ NOPR, 179 FERC ] 61,028 at P 183.
---------------------------------------------------------------------------
b. Comments
824. Many commenters support requiring identification of, and
transparency regarding, the benefits that transmission providers will
use in Long-Term Regional Transmission Planning.\1824\ For example,
Nebraska Commission states that the NOPR proposal will foster the
necessary flexibility to accommodate varying needs and approaches of
different transmission planning regions.\1825\
---------------------------------------------------------------------------
\1824\ APPA Initial Comments at 5; Avangrid Initial Comments at
7, 29; Business Council for Sustainable Energy Initial Comments at
5; California Commission Initial Comments at 28-30; California
Energy Commission Initial Comments at 3; ENGIE Reply Comments at 3;
Handy Law Initial Comments at 8; Massachusetts Attorney General
Initial Comments at 3; Michigan Commission Initial Comments at 6;
Nebraska Commission Initial Comments at 7; NESCOE Initial Comments
at 44 (citing NOPR, 179 FERC ] 61,028 at PP 183, 186); NRECA Initial
Comments at 46; NYISO Initial Comments at 37-38; Pennsylvania
Commission Initial Comments at 9; PJM Initial Comments at 7; Vermont
State Entities Initial Comments at 6.
\1825\ Nebraska Commission Initial Comments at 7.
---------------------------------------------------------------------------
825. Certain TDUs and Michigan Commission state that transmission
providers must clearly articulate their methods for calculating
identified benefits.\1826\ Certain TDUs further state that benefits
should be evaluated with consistent reference cases to ensure
consistency across scenarios.\1827\ Certain TDUs and Entergy state that
transmission providers should incorporate their benefit calculation
methods, as well as, according to Entergy, their role in selection,
into the OATT.\1828\ Entergy argues that the Commission should allow
transmission providers to use different benefits on a regional or
subregional level, but that benefits should not change from one
transmission project or portfolio to the next without an OATT
amendment.\1829\
---------------------------------------------------------------------------
\1826\ Certain TDUs Initial Comments at 13; Michigan Commission
Initial Comments at 6.
\1827\ Certain TDUs Initial Comments at 13-14.
\1828\ Certain TDUs Initial Comments at 14-15; Entergy Reply
Comments at 4-5 (citing City & Cnty. of San Francisco v. FERC, 24
F.4th 652, 661 (D.C. Cir. 2022); Sw. Power Pool, Inc., 180 FERC ]
61,074, at PP 24-31 (2022), order on reh'g and setting aside, 182
FERC ] 61,100 (2023)).
\1829\ Entergy Reply Comments at 5.
---------------------------------------------------------------------------
826. MISO TOs state that MISO already meets the NOPR's proposed
requirement to identify benefits used in Long-Term Regional
Transmission Planning and explain how they will be calculated.\1830\
---------------------------------------------------------------------------
\1830\ MISO TOs Initial Comments at 19-22 (citing MISO, Electric
Tariff, attach. FF Sec. Sec. II.C.2, II.C.5; MISO, LRTP Tranche 1
Portfolio Detailed Business Case, at 15-49, 60 (June 25, 2022),
https://cdn.misoenergy.org/LRTP%20Tranche%201%20Detailed%20Business%20Case625789.pdf).
---------------------------------------------------------------------------
827. Some commenters express concerns with the Commission's
proposed benefit identification requirement,\1831\ including concerns
over perceived excessive quantification \1832\ or requirements to
calculate benefits individually.\1833\ Duke asserts that the Commission
should
[[Page 49415]]
clarify that it will not force transmission providers to assign dollar
values for every benefit because some benefits' quantification is
subjective.\1834\ EEI asserts that transmission providers should not
have to calculate all of the benefits for a transmission project but
states that those benefits used for cost allocation purposes should be
quantifiable.\1835\ NYISO requests that the final order confirm that it
does not prescribe how benefits must be calculated and, more
specifically, that transmission providers are not required to calculate
the listed benefits in the exact manner described in the NOPR.\1836\
---------------------------------------------------------------------------
\1831\ DC and MD Offices of People's Counsel Initial Comments at
19; Duke Initial Comments at 24; EEI Initial Comments at 20; Entergy
Initial Comments at 22; Illinois Commission Initial Comments at 13-
14; Louisiana Commission Initial Comments at 18; Michigan Commission
Initial Comments at 6; US Chamber of Commerce Initial Comments at 7-
8. Further detail on the basis for these commenters' concerns is
provided infra.
\1832\ See, e.g., Duke Initial Comments at 24.
\1833\ See, e.g., EEI Initial Comments at 20.
\1834\ Duke Initial Comments at 24.
\1835\ EEI Initial Comments at 20.
\1836\ NYISO Initial Comments at 36-40.
---------------------------------------------------------------------------
828. MISO notes that the benefits it currently uses in regional
transmission planning are not all specified in the Tariff itself but
were developed as part of the review process with MISO stakeholders.
MISO adds that the flexibility to look for relevant benefits and apply
them in long-term planning scenarios is important in the process to
identify long-term regional solutions that reflect the needs and value-
drivers of the MISO footprint.\1837\ MISO states that if limited to a
prescriptive set of benefits, MISO may not be in the same position to
move forward the transmission projects of the greatest benefit and
value to MISO and its stakeholders.\1838\
---------------------------------------------------------------------------
\1837\ MISO Initial Comments at 9-10.
\1838\ Id. at 9.
---------------------------------------------------------------------------
829. Some commenters opine on requirements or best practices for
identifying, measuring, and combining benefits.\1839\ For example, some
commenters comment on the measurement and/or calculation of
benefits.\1840\ Entergy argues that the Commission should require all
benefits to be reasonably achievable in real-time operations.\1841\ SPP
Market Monitor states that assumptions into benefit calculations should
be improved to ensure that they result in just and reasonable
rates.\1842\ Large Public Power emphasizes that the Commission should
clarify that benefits must reflect load-serving entities' actual use of
proposed transmission facilities, measured by anticipated power
flows.\1843\
---------------------------------------------------------------------------
\1839\ Acadia Center and CLF Initial Comments at 23; ACORE Reply
Comments at 3; ACEG Initial Comments at 32; AEP Initial Comments at
21-24; APPA Initial Comments at 32; City of New Orleans Council
Initial Comments at 11; Clean Energy Associations Initial Comments
at 20-21; DC and MD Offices of People's Counsel Initial Comments at
19; Duke Initial Comments at 24; EEI Initial Comments at 20; Entergy
Initial Comments at 22; Illinois Commission Initial Comments at 13-
14; Large Public Power Initial Comments at 28; Louisiana Commission
Initial Comments at 18; Michigan State Entities Initial Comments at
5-7; NARUC Initial Comments at 20-26; NASUCA Initial Comments at 10;
NRECA Initial Comments at 45; NYISO Initial Comments at 37; PJM
Market Monitor Initial Comments at 4; SEIA Initial Comments at 18-
19; Six Cities Initial Comments at 2-3; Southern Initial Comments at
31; SPP Market Monitor Initial Comments at 11; US Chamber of
Commerce Initial Comments at 7-8; US DOE Initial Comments at 31;
Vermont State Entities Initial Comments at 6.
\1840\ AEP Initial Comments at 21-24; Clean Energy Associations
Initial Comments at 21; Large Public Power Initial Comments at 28;
SEIA Initial Comments at 18-19; SPP Market Monitor Initial Comments
at 11.
\1841\ Entergy Initial Comments at 22.
\1842\ SPP Market Monitor Initial Comments at 11.
\1843\ Large Public Power Initial Comments at 28.
---------------------------------------------------------------------------
830. SEIA suggests that there are many resources to inform methods
for the calculation of benefits, including MISO's Long Range
Transmission Plan Tranche 1 portfolio.\1844\ Also referencing MISO's
process, AEP contends that the benefits of regional transmission
facilities should be evaluated collectively, through a multi-value
analysis, and cites MISO's existing process as an example.\1845\
---------------------------------------------------------------------------
\1844\ SEIA Initial Comments at 18-19 (citing Rob Gramlich,
Enabling Low-Cost Clean Energy & Reliable Service Through Better
Transmission Benefits Analysis, at 17, https://acore.org/wp-content/uploads/2022/08/ACORE-Enabling-Low-Cost-Clean-Energy-and-Reliable-Service-Through-Better-Transmission-Analysis.pdf).
\1845\ AEP Initial Comments at 21-24.
---------------------------------------------------------------------------
831. Some commenters opine on the need for quantification and/or
specificity of benefits.\1846\ DC and MD Offices of People's Counsel
assert that any benefit used should be pre-defined and its measurement
accurate and transparent.\1847\ PIOs also state that the Brattle-Grid
Strategies Oct. 2021 Report provides evidence that benefits from
transmission facilities are not difficult to quantify despite claims to
the contrary.\1848\ NASUCA asserts that the methods for calculating and
assigning benefits should be based on objective, measurable, clear, and
specific metrics.\1849\ Similarly, Illinois Commission, Pacific
Northwest Utilities, and NARUC assert that transmission benefits must
be verifiable and quantifiable.\1850\
---------------------------------------------------------------------------
\1846\ ACORE Reply Comments at 3 (citing US DOE Initial Comments
at 31); Concerned Scientists Reply Comments at 8-10; DC and MD
Offices of People's Counsel Initial Comments at 19; Entergy Initial
Comments at 22; NASUCA Initial Comments at 10; US DOE Initial
Comments at 31.
\1847\ DC and MD Offices of People's Counsel Initial Comments at
19.
\1848\ PIOs Initial Comments at 42-44.
\1849\ NASUCA Initial Comments at 10.
\1850\ Illinois Commission Initial Comments at 13-14; NARUC
Initial Comments at 20-25; Pacific Northwest Utilities Initial
Comments at 8-9.
---------------------------------------------------------------------------
832. A few commenters address the ease of quantification of the
benefits listed in the NOPR. NARUC states that NOPR Benefits 1-5 and 8-
10 seem somewhat capable of quantification.\1851\ NRECA asserts that
the benefits at the top of the list in the NOPR are reasonably
quantifiable, while those farther down the list require more subjective
judgements.\1852\ APPA agrees that some of the benefits listed in the
NOPR would be more challenging to quantify and therefore would be more
difficult to justify as a just and reasonable way to allocate
costs.\1853\
---------------------------------------------------------------------------
\1851\ NARUC Initial Comments at 21.
\1852\ NRECA Initial Comments at 45.
\1853\ APPA Initial Comments at 32.
---------------------------------------------------------------------------
833. Some commenters support the use of benefit-cost analysis
frameworks.\1854\ Michigan State Entities express that having a
prescribed benefit-cost analysis framework can help ensure appropriate
quantification of benefits, adding that there is less transparency when
individual transmission providers may determine how these benefits
stack up against each other.\1855\ Therefore, Michigan State Entities
recommend that the Commission adopt the cost-benefit analysis framework
already used throughout the Federal Government. According to Michigan
State Entities, the Commission's legal authority to do so is well-
established by court decisions and it would help to ensure sufficient
regional transmission cooperation to achieve just and reasonable
rates.\1856\
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\1854\ Michigan State Entities Initial Comments at 5-7; Six
Cities Initial Comments at 2-3; Southern Initial Comments at 31;
Vermont State Entities Initial Comments at 6-7.
\1855\ Michigan State Entities Initial Comments at 5.
\1856\ Id. at 6-7.
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834. Six Cities argues that transmission planning should assess
both project benefits and costs.\1857\ Vermont State Entities agree
that a comprehensive benefit-cost analysis would lead to better and
more cost-effective transmission planning.\1858\ Southern also states
that the burdens associated with proposed transmission projects should
be recognized, including not only immediate cost and rate impacts, but
also effects on local communities and landowners and issues of equity
and environmental justice.\1859\
---------------------------------------------------------------------------
\1857\ Six Cities Initial Comments at 2-3.
\1858\ Vermont State Entities Initial Comments at 6-7.
\1859\ Southern Initial Comments at 31.
---------------------------------------------------------------------------
835. Likewise, certain commenters state that they support the
adoption of benefit-cost analysis using quantifiable, replicable, non-
duplicative, and forward-looking metrics.\1860\ US
[[Page 49416]]
Chamber of Commerce contends that the objective nature of such metrics
should limit uncertainty otherwise present in projections spanning
multiple decades and reduce the variability and error in benefit
calculations.\1861\ Acadia Center and CLF and ACEG argue that an
unbiased analysis of both benefits and costs is essential for ensuring
just and reasonable rates and that the Commission should seek to ensure
that a minimum set of benefits is applied consistently across RTO/ISO
and non-RTO/ISO transmission planning regions.\1862\ ACORE agrees with
US DOE that consistency in benefit quantification could facilitate
improved interregional transmission planning.\1863\
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\1860\ City of New Orleans Council Initial Comments at 11;
Entergy Initial Comments at 22; Louisiana Commission Initial
Comments at 18; US Chamber of Commerce Initial Comments at 7-8.
\1861\ US Chamber of Commerce Initial Comments at 8.
\1862\ Acadia Center and CLF Initial Comments at 23; ACEG
Initial Comments at 32.
\1863\ ACORE Reply Comments at 3 (citing US DOE Initial Comments
at 31).
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836. Other commenters state that the NOPR's proposed reforms will
help improve transmission providers' existing benefit-cost
analyses.\1864\ GridLab states that the NOPR's approach balances
regional flexibility with Federal standardization in benefit categories
across transmission providers and more accountability by transmission
providers in their benefit-cost analysis.\1865\ PJM Market Monitor
states that PJM's current benefit-cost analysis does not accurately
measure the costs and benefits of transmission projects because it does
not account for the fact that benefits are uncertain and sensitive to
modeling assumptions or that costs may exceed estimates.\1866\ Illinois
Commission states that the use of too many metrics could lead to the
evaluation of transmission projects based on the margins and
inequitable cost allocation.\1867\ Illinois Commission further states
that some metrics may be most relevant for interregional and regional
transmission projects identified in the Long-Term Regional Transmission
Planning process and that the Commission can aid transmission planning
regions in putting together a shorter list of these metrics.\1868\
---------------------------------------------------------------------------
\1864\ GridLab Initial Comments at 25; PJM Market Monitor
Initial Comments at 4-5; Southeast PIOs Initial Comments at 49-50.
\1865\ GridLab Initial Comments at 25.
\1866\ PJM Market Monitor Initial Comments at 4-5.
\1867\ Illinois Commission Initial Comments at 13.
\1868\ Id. at 14.
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c. Commission Determination
837. We adopt the NOPR proposal, with modification, and require
transmission providers in each transmission planning region to include
in their OATTs a general description of how they will measure each of
the seven benefits included in the required set of benefits that we
require them to measure and use in Long-Term Regional Transmission
Planning. As discussed above, we clarify that transmission providers
may use and measure additional benefits, beyond the seven required by
this final order.\1869\
---------------------------------------------------------------------------
\1869\ While we conclude that it is important for transmission
providers to at minimum use and measure the required seven benefits,
we agree with MISO that the flexibility to look for relevant
benefits and apply them in long-term planning scenarios can be
important in the process to identify long-term regional solutions
that reflect region-specific needs and value-drivers. MISO Initial
Comments at 9. We therefore afford flexibility to transmission
planners in identifying and measuring benefits that go beyond the
core set of seven required here.
---------------------------------------------------------------------------
838. We find that requiring such a description in transmission
providers' OATTs for the seven required benefits is necessary to ensure
that all stakeholders have transparency regarding the benefits that
transmission providers use to identify, evaluate, and select Long-Term
Regional Transmission Facilities that more efficiently or cost-
effectively address Long-Term Transmission Needs. We further conclude
that requiring inclusion of this information in the OATT will better
ensure transmission providers measure and use the set of benefits
required in the final order in Long-Term Regional Transmission
Planning.
839. Some commenters express concerns regarding excessive
quantification of benefits.\1870\ But the approach adopted in this
final order--of requiring transmission providers to measure and use a
required set of benefits in Long-Term Regional Transmission Planning
and requiring transmission providers to include in their OATTs a
general description of the method they will use to measure each of
those benefits--represents a reasonable balance between specificity and
flexibility. As discussed above, we provide flexibility to transmission
providers to specify the method for measuring each of the seven
required benefits. However, because our requirement that transmission
providers measure and use these benefits in Long-Term Regional
Transmission Planning is necessary to address the identified
deficiencies in existing regional transmission planning and cost
allocation processes, we find that it is also necessary for
transmission providers to include in their OATTs a general description
of how they will measure each of these benefits. Such a requirement
will ensure that transmission providers consider a sufficiently broad
range of benefits when determining whether to select a Long-Term
Regional Transmission Facility as a more efficient or cost-effective
regional transmission solution to Long-Term Transmission Needs.
---------------------------------------------------------------------------
\1870\ See, e.g., Duke Initial Comments at 24.
---------------------------------------------------------------------------
840. In response to some commenters, such as MISO, that urge that
requiring details on measurement of benefits to be incorporated into
the OATT could impede development and use of new transmission metrics,
we clarify that the description for each required benefit in the OATT
must only be sufficient to enable stakeholders to understand the manner
by which transmission providers will measure these benefits. We do not
require further details on measurement of the benefits to be included
in the OATT.
841. Large Public Power asks that the Commission clarify that any
acceptable list of benefits detailed in compliance filings must
emphasize load-serving entities' actual use of the proposed
transmission facilities, which should be measured by anticipated power
flows that occur across these facilities.\1871\ We decline to adopt
Large Public Power's suggested clarification as we are not mandating
any particular method for measuring the seven benefits included in the
required set of benefits.
---------------------------------------------------------------------------
\1871\ Large Public Power Initial Comments at 28.
---------------------------------------------------------------------------
842. We decline certain commenters' requests to require that
transmission providers justify why they omit any categories of
benefits.\1872\ Such a requirement is unnecessary because of our
modifications to the NOPR proposal, which now require transmission
providers to measure and use the required set of benefits in Long-Term
Regional Transmission Planning.
---------------------------------------------------------------------------
\1872\ GridLab Initial Comments at 25; NYISO Initial Comments at
37-38; Vermont State Entities Initial Comments at 6-7.
---------------------------------------------------------------------------
4. Evaluation of Transmission Benefits Over a Longer Time Horizon
a. NOPR Proposal
843. In the NOPR, the Commission proposed to require transmission
providers in each transmission planning region to evaluate, as part of
Long-Term Regional Transmission Planning, the benefits of regional
transmission facilities over a time horizon that covers, at a minimum,
20 years starting from the estimated in-service date of the regional
transmission facilities.\1873\
---------------------------------------------------------------------------
\1873\ NOPR, 179 FERC ] 61,028 at P 227.
---------------------------------------------------------------------------
844. The Commission proposed to require transmission providers to
evaluate benefits over this time horizon in all stages of Long-Term
Regional Transmission Planning, which includes evaluating regional
transmission
[[Page 49417]]
facilities, selecting more efficient or cost-effective regional
transmission facilities in the regional transmission plan for purposes
of cost allocation, and allocating the costs of such regional
transmission facilities in a manner that is at least roughly
commensurate with estimated benefits. The Commission proposed that for
consistency and a matching comparison of benefits and costs over time,
to the extent that transmission providers estimate the costs of
transmission facilities beyond the in-service date of the transmission
facilities, that transmission providers should estimate those future
costs over the same time horizon as the estimated benefit.\1874\ The
Commission proposed that approaches may exceed this minimum
requirement, but transmission providers must demonstrate that their
proposal is consistent with or superior to any final order in this
proceeding.
---------------------------------------------------------------------------
\1874\ Id. P 228.
---------------------------------------------------------------------------
b. Comments
i. Requirement for a Benefits Evaluation Time Horizon of a Minimum of
20 Years From the In-Service Date
845. Several commenters support the Commission's proposal to
require that transmission providers in each transmission planning
region evaluate, as part of Long-Term Regional Transmission Planning,
the benefits of regional transmission facilities over a time horizon
that covers, at a minimum, 20 years starting from the estimated in-
service date of the transmission facilities.\1875\ NARUC, for example,
states that transmission planning must strike a reasonable balance
between considering benefits only through the end of the transmission
planning horizon regardless of the transmission facility's in-service
date and considering benefits over its full expected life, which NARUC
states that the NOPR proposal achieves.\1876\ Northwest and
Intermountain state that they cautiously support the Commission's
proposal to establish a minimum 20-year horizon for the calculation of
benefits, noting that their concerns are mitigated by the NOPR proposal
to allow flexibility within each transmission planning region to tailor
cost allocation criteria to that region's needs.\1877\ Similarly,
Vermont State Entities and NESCOE state that a rigid one-size-fits-all
rule could be counterproductive and would not necessarily lead to just
and reasonable transmission rates.\1878\ NARUC states that, while it
supports the NOPR proposal, transmission providers should be allowed
independent entity variations to deviate above or below the 20-year
horizon after gaining experience with Long-Term Regional Transmission
Planning.\1879\ NYISO contends that it already employs a 30-year study
period in evaluating the benefits of transmission projects in its
public policy transmission planning process.\1880\
---------------------------------------------------------------------------
\1875\ ACEG Initial Comments at 24; California Commission
Initial Comments at 36; Certain TDUs Reply Comments at 3; ITC
Initial Comments at 22-23; NARUC Initial Comments at 26-27; NYISO
Initial Comments at 40; OMS Initial Comments at 8-9; Pacific
Northwest State Agencies Initial Comments at 16-19.
\1876\ NARUC Initial Comments at 26.
\1877\ Northwest and Intermountain Initial Comments at 8.
\1878\ NESCOE Initial Comments at 45; Vermont State Entities
Initial Comments at 6.
\1879\ NARUC Initial Comments at 39-40.
\1880\ NYISO Initial Comments at 40.
---------------------------------------------------------------------------
846. MISO supports the Commission's proposal, stating that a
minimum period of 20 years is adequate to assess the benefits of
regional transmission facilities.\1881\ MISO cautions, however, that
the benefits determined over this time horizon represent the minimum
benefits that a regional transmission facility provides and that the
analysis should recognize that additional benefits would be realized
over the life of the investment even if changing system conditions
create uncertainty as to the precise value of those benefits.\1882\
---------------------------------------------------------------------------
\1881\ MISO Initial Comments at 52.
\1882\ Id.
---------------------------------------------------------------------------
847. Other commenters suggest that the time horizon for the
evaluation of benefits in Long-Term Regional Transmission Planning
should align with the useful life of the transmission asset.\1883\
Breakthrough Energy and CARE Coalition contend that the proper time
horizon for evaluation of benefits in standard economics and public
policy is the life of the transmission asset, noting that transmission
assets can often last 40 years or longer.\1884\ ACEG agrees, noting
that, while it supports use of a 20-year minimum horizon to evaluate
benefits, standard regulatory practice for a benefit-cost analysis is
typically the life of the asset.\1885\ Likewise, PIOs contend that,
while they agree with the NOPR proposal, it would be preferable to
align the time horizon for evaluating benefits with the useful life of
the transmission project.\1886\ PIOs state that calculating the
benefits and costs of a transmission project over a shorter timespan
can understate the benefit-cost ratio because benefits tend to grow
over time, while transmission revenue requirements will decline over
time as the asset is depreciated.\1887\
---------------------------------------------------------------------------
\1883\ ACEG Initial Comments at 24; Breakthrough Energy Initial
Comments at 23; CARE Coalition Initial Comments at 40-41; Clean
Energy Associations Initial Comments at 21; CTC Global Initial
Comments at 16-17; ENGIE Initial Comments at 2; ENGIE Reply Comments
at 2; Indicated PJM TOs Initial Comments at 17-18; Interwest Initial
Comments at 14; Interwest Reply Comments at 6-7; Pine Gate Initial
Comments at 35; PIOs Initial Comments at 40-41; US DOE Initial
Comments at 33-34; WIRES Initial Comments at 7.
\1884\ Breakthrough Energy Initial Comments at 23; CARE
Coalition Initial Comments at 40-41.
\1885\ ACEG Initial Comments at 24.
\1886\ PIOs Initial Comments at 40 (citing PIOs Initial Comments
Ex. A, ]] 24-29).
\1887\ Id. (citing PIOs Initial Comments Ex. A, ] 28).
---------------------------------------------------------------------------
848. CTC Global states that while it supports the NOPR proposal, it
argues that it would be more appropriate to align the timeline for
evaluating benefits with the asset life, because while advanced
conductors are almost always more expensive than legacy conductors
initially, their costs are offset by efficiency and resilience benefits
decades into the future.\1888\ Indicated PJM TOs state that benefits
``should be calculated on the same time horizon as the project that is
being assessed to allow for the ability to properly compare projects.''
\1889\
---------------------------------------------------------------------------
\1888\ CTC Global Initial Comments at 16-17.
\1889\ Indicated PJM TOs Initial Comments at 18.
---------------------------------------------------------------------------
849. Given that transmission assets often have a useful life of at
least 40 years, US DOE encourages the Commission to require
transmission providers to evaluate costs and benefits over a minimum of
30 years after the in-service date of a transmission facility rather
than the proposed 20 years. According to US DOE, doing so would better
align with the useful life assumptions that generation developers
make.\1890\
---------------------------------------------------------------------------
\1890\ US DOE Initial Comments at 33-34.
---------------------------------------------------------------------------
850. Clean Energy Buyers and PG&E suggest that benefits should be
evaluated over the same 20-year horizon as the proposed Long-Term
Regional Transmission Planning transmission planning horizon.\1891\
Similarly, PPL states that, while it supports the proposed 20-year
minimum duration to evaluate benefits in Long-Term Regional
Transmission Planning, the Commission should require transmission
providers to measure benefits from the study date rather than the
proposed in-service date of the Long-Term Regional Transmission
Facility. PPL contends that the NOPR proposal would introduce
significant variability that will make it challenging to align the
outcome with the long-term need and would incentivize transmission
developers to delay or adjust the timing
[[Page 49418]]
of transmission projects to maximize the demonstrated benefit.\1892\
---------------------------------------------------------------------------
\1891\ Clean Energy Buyers Initial Comments at 20; PG&E Initial
Comments at 7.
\1892\ PPL Initial Comments at 15-17.
---------------------------------------------------------------------------
851. In contrast, GridLab contends that the 20-year Long-Term
Regional Transmission Planning transmission planning horizon need not
correspond with the time horizon over which transmission providers
evaluate the benefits and costs of potential transmission investments.
GridLab recommends that the Commission clarify the distinction between
the requirement for a 20-year transmission planning horizon and for a
20-year period to evaluate benefits, while keeping both
requirements.\1893\
---------------------------------------------------------------------------
\1893\ GridLab Initial Comments at 6-8.
---------------------------------------------------------------------------
852. Many commenters assert that evaluating benefits over a 20-year
time horizon is difficult or speculative.\1894\ Ohio Consumers and
Dominion argue that, since transmission providers would be required to
plan for potential transmission needs in 20 years and evaluate benefits
over a 20-year project life span, the requirement effectively amounts
to a 40-year cost allocation process and will be particularly
challenging.\1895\ APS agrees, stating that calculating benefits over a
potential 40 years may lead to benefit calculations that are overstated
or yield unreasonable or unrealistic results.\1896\
---------------------------------------------------------------------------
\1894\ APPA Initial Comments at 32; Dominion Initial Comments at
17; Louisiana Commission Initial Comments at 18; NRECA Initial
Comments at 46; Ohio Consumers Initial Comments at 8; PJM Initial
Comments at 97.
\1895\ Ohio Consumers Initial Comments at 8.
\1896\ APS Initial Comments at 8-9.
---------------------------------------------------------------------------
853. Some commenters request certain clarifications or
modifications to address that uncertainty.\1897\ For example, Exelon
states that benefits should tie back to customer value and suggests
that the Commission should give transmission providers flexibility to
assign more weight to nearer-term benefits tied to specific savings
that are more certain.\1898\ SERTP Sponsors and Duke agree, and Duke
requests that the Commission clarify that transmission providers are
permitted to discount benefits based on increased uncertainty in later
years for purposes of evaluating, selecting, and allocating the costs
of Long-Term Regional Transmission Facilities.\1899\
---------------------------------------------------------------------------
\1897\ Duke Initial Comments at 23-24; Exelon Initial Comments
at 16; SERTP Sponsors Initial Comments at 31.
\1898\ Exelon Initial Comments at 16.
\1899\ Duke Initial Comments at 23-24; SERTP Sponsors Initial
Comments at 31.
---------------------------------------------------------------------------
854. Several commenters oppose requiring a minimum 20-year horizon
for evaluating benefits of Long-Term Regional Transmission
Facilities.\1900\ For example, Idaho Commission argues that the NOPR
proposal is founded on benefits that are not ``generally accepted or
regionally flexible'' and may not be beneficial for regional
transmission planning benefit evaluation.\1901\ Furthermore, Idaho
Commission argues, it is difficult to accurately predict and quantify
benefits over a 20-year period for purposes of cost allocation.\1902\
---------------------------------------------------------------------------
\1900\ Dominion Reply Comments at 4-5; Idaho Commission Initial
Comments at 4; NARUC Initial Comments at 5-6; NESCOE Initial
Comments at 44-45; Pacific Northwest Utilities Initial Comments at
6-7; Pennsylvania Commission Initial Comments at 4-5.
\1901\ Idaho Commission Initial Comments at 4.
\1902\ Id.
---------------------------------------------------------------------------
855. Similarly, Dominion requests that the Commission decline to
adopt the NOPR proposal or provide clarification that the Commission
did not intend to propose that benefits would need to be evaluated over
a potential 40-year period. Dominion states that it would be
unreasonable for the Commission to require transmission providers to
consider benefits over a 40-year period, because identifying benefits
and beneficiaries that far into the future would involve too much
speculation.
856. Pennsylvania Commission requests that the Commission revise
the NOPR proposal to set a long-term horizon of no longer than 20 years
for planning and benefit-cost analysis. Pennsylvania Commission argues
that as the planning and benefit-cost analysis horizons lengthen,
uncertainty in predictions of load growth, costs, and benefits will
increase, potentially leading to uneconomic transmission
projects.\1903\ Pacific Northwest Utilities oppose the NOPR proposal
because, they argue, beneficiaries and benefits cannot be identified or
quantified with any reasonable certainty over a 20-year transmission
planning horizon. Specifically, Pacific Northwest Utilities contend
that there is no plausible reason to believe that such speculative
benefits would be roughly commensurate with the costs that are
allocated to identified beneficiaries.\1904\
---------------------------------------------------------------------------
\1903\ Pennsylvania Commission Initial Comments at 4-5.
\1904\ Pacific Northwest Utilities Initial Comments at 7 (citing
ICC v. FERC I, 576 F.3d 470).
---------------------------------------------------------------------------
ii. Applicability of Benefits Evaluation Horizon to Long-Term Regional
Transmission Planning Stages (Evaluation of Facilities, Selection, and
Cost Allocation)
857. Pacific Northwest State Agencies supports the Commission's
proposal to require that transmission providers evaluate benefits over
a consistent time horizon in all stages of Long-Term Regional
Transmission Planning, which includes evaluating regional transmission
facilities, selecting more efficient or cost-effective regional
transmission facilities in the regional transmission plan for purposes
of cost allocation, and allocating the costs of such transmission
facilities in a manner that is roughly commensurate with estimated
benefits.\1905\
---------------------------------------------------------------------------
\1905\ Pacific Northwest State Agencies Initial Comments at 18.
---------------------------------------------------------------------------
858. Several commenters also support the Commission's proposal
that, to the extent that transmission providers estimate the costs of
transmission facilities beyond the in-service date of the transmission
facilities, they should estimate those future costs over the same time
horizon as the estimated benefits.\1906\ For instance, MISO states that
costs and benefits for regional transmission investments should be
evaluated using the same time horizon to ensure there is consistency in
accounting for the effects of time in the calculations.\1907\ MISO
attests that since benefits are only realized once a transmission
project or portfolio of projects is in service, transmission providers
should assess the benefits over the period of time starting with the
in-service date to align with costs.\1908\ Pacific Northwest State
Agencies and Certain TDUs agree.\1909\
---------------------------------------------------------------------------
\1906\ Certain TDUs Reply Comments at 3 (citing MISO Initial
Comments at 53); MISO Initial Comments at 53; NARUC Initial Comments
at 27; OMS Initial Comments at 8-9; Pacific Northwest State Agencies
Initial Comments at 18.
\1907\ MISO Initial Comments at 53.
\1908\ Id.
\1909\ Certain TDUs Reply Comments at 3 (citing MISO Initial
Comments at 53); Pacific Northwest State Agencies Initial Comments
at 18.
---------------------------------------------------------------------------
c. Commission Determination
859. We adopt the NOPR proposal, with modification, to require
transmission providers in each transmission planning region, as part of
Long-Term Regional Transmission Planning, to calculate the benefits of
Long-Term Regional Transmission Facilities over a time horizon that
covers, at a minimum, 20 years starting from the estimated in-service
date of the transmission facilities, and we require that this minimum
20-year benefit horizon be used both for the evaluation and selection
of Long-Term Regional Transmission Facilities.\1910\ However,
[[Page 49419]]
we do not adopt the NOPR proposal to require a minimum 20-year horizon
to calculate benefits for purposes of cost allocation. As described in
the Identification of Benefits Considered in Cost Allocation for Long-
Term Regional Transmission Facilities section of this final order,
requiring transmission providers to adopt this provision for purposes
of cost allocation would unduly complicate development and review of
Long-Term Regional Transmission Cost Allocation Methods, with little
incremental gain. Lastly, for consistency and a matching comparison of
costs over time, we adopt the NOPR proposal to require that, to the
extent that transmission providers estimate the costs of Long-Term
Regional Transmission Facilities beyond the in-service date of the
transmission facilities, they must estimate those future costs over the
same time horizon as the estimated benefits.
---------------------------------------------------------------------------
\1910\ In the NOPR, the Commission used the term ``regional
transmission facilities''; however, as this reform only concerns
Long-Term Regional Transmission Planning, we clarify that the
Commission's intent was to refer only to Long-Term Regional
Transmission Facilities. As discussed in the Development of Long-
Term Scenarios section, transmission providers also use these
benefits to help to inform their identification of Long-Term
Transmission Needs that manifest during the 20-year transmission
planning horizon.
---------------------------------------------------------------------------
860. We find that calculating benefits both for the evaluation and
selection of Long-Term Regional Transmission Facilities over a timeline
that covers, at a minimum, 20 years starting from the estimated in-
service date of the Long-Term Regional Transmission Facility, strikes
an appropriate balance. This balance reasonably reflects the benefits
that a Long-Term Regional Transmission Facility is likely to provide
over its useful life, a time period that can exceed 40 years,\1911\
while recognizing the inherent difficulties in attempting to predict
system conditions too far into the future. As described in the Long-
Term Regional Transmission Planning section of this final order, the
uncertainty associated with forecasting future transmission needs over
a long-term transmission planning horizon can be mitigated through the
use of multiple Long-Term Scenarios and sensitivities.
---------------------------------------------------------------------------
\1911\ ACEG Initial Comments at 24; Breakthrough Energy Initial
Comments at 23; CARE Coalition Initial Comments at 40-41; Clean
Energy Associations Initial Comments at 21; CTC Global Initial
Comments at 16-17; ENGIE Initial Comments at 2; ENGIE Reply Comments
at 2; Indicated PJM TOs Initial Comments at 18; Interwest Initial
Comments at 14; Interwest Reply Comments at 7; Pine Gate Initial
Comments at 35; PIOs Initial Comments at 40-41; US DOE Initial
Comments at 33-34; WIRES Initial Comments at 7.
---------------------------------------------------------------------------
861. Specifically, this final order requires transmission providers
to develop multiple plausible and diverse Long-Term Scenarios, which
will allow transmission providers to better understand how certain
categories of factors will give rise to Long-Term Transmission Needs,
and also requires transmission providers to update their assumptions
periodically. Additionally, transmission providers are permitted to
assess the extent to which the projected change to Long-Term
Transmission Needs due to factors in Factor Categories Four through
Seven is likely to be realized in full, in part, or exceeded, for
purposes of developing a plausible and diverse set of Long-Term
Scenarios.\1912\ Because of these reforms, we believe that transmission
providers will be able to identify Long-Term Transmission Needs with a
higher likelihood of occurrence, and, therefore, the benefits resulting
from Long-Term Regional Transmission Facilities to more efficiently or
cost-effectively address these Long-Term Transmission Needs will
similarly be more certain.
---------------------------------------------------------------------------
\1912\ Supra Long-Term Regional Transmission Planning, Long-Term
Scenarios Requirements, Categories of Factors section.
---------------------------------------------------------------------------
862. Moreover, as described in the Evaluation and Selection of
Regional Transmission Facilities section of this final order, we
provide transmission providers with considerable flexibility to develop
an evaluation process and selection criteria that will provide them the
opportunity to select Long-Term Regional Transmission Facilities in a
way that maximizes benefits accounting for costs over time without
over-building transmission facilities. In particular, transmission
providers have the flexibility to evaluate Long-Term Regional
Transmission Facilities and their measured benefits across the
different Long-Term Scenarios and sensitivities in a manner that
addresses the inherent uncertainty in Long-Term Regional Transmission
Planning, for example through the use of a least-regrets or a weighted-
benefits approach. Lastly, as is the case under the existing Order No.
1000 regional transmission planning processes, the final order does not
require transmission providers to select any transmission facilities as
part of Long-Term Regional Transmission Planning. Taken together, the
aspects of the final order described above offer transmission providers
meaningful tools to address uncertainty in Long-Term Regional
Transmission Planning, including the calculation of benefits.
863. We disagree with NESCOE and Vermont State Entities, who argue
that a requirement to calculate benefits over a minimum of 20 years
from the estimated in-service date is overly rigid and may not lead to
transmission rates that are just and reasonable. As discussed above,
this requirement strikes a reasonable balance between the benefits that
a Long-Term Regional Transmission Facility is likely to provide over
its useful life, while recognizing the inherent difficulties in
attempting to forecast system conditions too far into the future.
Further, allowing transmission providers to calculate benefits over a
shorter period would more likely undervalue the total benefits that
Long-Term Regional Transmission Facilities can provide and could
therefore lead to relatively inefficient and less cost-effective
transmission development, as Long-Term Regional Transmission Facilities
that provide significant net benefits may not be selected to address
Long-Term Transmission Needs. Lastly, and as stated above, we are not
requiring transmission providers to use a minimum 20-year horizon to
calculate benefits for purposes of cost allocation.
864. Similarly, we also disagree with commenters that suggest that
the results of the benefits evaluation would not be accurate or
dependable enough for transmission providers to use in making the
decision to select Long-Term Regional Transmission Facilities.\1913\ We
further note that transmission providers in multiple transmission
planning regions already evaluate the benefits of transmission
facilities over a 20-year time horizon as part of their regional
transmission planning processes.\1914\ For example, NYISO states that
it employs a 30-year study period in evaluating the benefits of
transmission projects in its public policy transmission planning
process.\1915\
---------------------------------------------------------------------------
\1913\ APPA Initial Comments at 32; APS Initial Comments at 8-9;
Dominion Initial Comments at 17; Idaho Commission Initial Comments
at 4; Louisiana Commission Initial Comments at 18; NRECA Initial
Comments at 46; Ohio Consumers Initial Comments at 8; Pacific
Northwest Utilities Initial Comments at 7; PJM Initial Comments at
97.
\1914\ MISO Initial Comments at 52; NYISO Initial Comments at
40; see also MISO, LRTP Business Case, Long Range Transmission
Planning Workshop, at 7 (Jan. 21, 2022, revised Feb. 2, 2022),
https://cdn.misoenergy.org/20220121%20LRTP%20Workshop%20Item%2004%20Business%20Case%20Presentation619895.pdf; CAISO, 20-Year Transmission Outlook (Jan. 31, 2022),
http://www.caiso.com/InitiativeDocuments/Draft20-YearTransmissionOutlook.pdf; SPP Engineering, 2021 SPP Transmission
Expansion Plan Report (Jan. 11, 2021), https://spp.org/documents/56611/2021%20step%20report.pdf.
\1915\ NYISO Initial Comments at 40.
---------------------------------------------------------------------------
865. Some commenters suggest that the Commission should provide
additional flexibility to account for uncertainty in calculating
benefits over a minimum 20-year time horizon, including that the
Commission make clear that transmission providers may discount or
weight the calculated benefits based on the relative certainty
throughout the benefits horizon.\1916\ As
[[Page 49420]]
we described above, this final order affords transmission providers
considerable flexibility in how to address uncertainty in Long-Term
Regional Transmission Planning, including by allowing transmission
providers to assess the extent to which the projected change to Long-
Term Transmission Needs due to factors in factor Categories Four
through Seven is likely to be realized in full, in part, or exceeded,
for purposes of developing a plausible and diverse set of Long-Term
Scenarios. Given these flexibilities, we find that while transmission
providers may discount the benefits calculated for purposes of
determining a present value of those benefits, they may not further
discount those benefits to reflect uncertainty over the minimum 20-year
time horizon for calculating benefits.
---------------------------------------------------------------------------
\1916\ Duke Initial Comments at 23-24; Exelon Initial Comments
at 16; SERTP Sponsors Initial Comments at 31.
---------------------------------------------------------------------------
866. In response to Dominion's request for clarification that the
Commission did not intend to propose that benefits would need to be
evaluated over a potential 40-year period, we reiterate that
transmission providers must calculate the benefits of Long-Term
Regional Transmission Facilities over a minimum of 20 years from their
estimated in-service date, even if the estimated in-service date is 20
years into the future. The failure to take such an approach could
result in transmission providers' consideration of a Long-Term Regional
Transmission Facility's cost but not the facility's corresponding
benefits.
867. We also decline to modify the proposal, as requested by
Pennsylvania Commission,\1917\ to require a benefits horizon of no
longer than 20 years as a means of reducing speculation and uncertainty
in calculating benefits of Long-Term Regional Transmission Facilities,
as well as NARUC's request that the Commission permit transmission
providers to deviate below the 20-year benefit evaluation horizon. As
explained above, a minimum of 20 years strikes a reasonable balance for
calculating the benefits of Long-Term Regional Transmission Facilities.
In addition, as indicated by many commenters, calculating the benefits
of a Long-Term Transmission Facility over a time horizon longer than 20
years is consistent with the long life of transmission facilities--
which generally exceeds 20 years by a substantial margin--and also
consistent with the fact that transmission facilities may provide
significant benefits over their entire useful life. While we reiterate
that transmission providers must calculate the benefits of Long-Term
Regional Transmission Facilities over a time horizon that covers, at a
minimum, 20 years starting from the estimated in-service date of the
transmission facilities, to the extent that transmission providers
would like to consider a longer time horizon for the evaluation of
benefits, they may propose to do so on compliance.
---------------------------------------------------------------------------
\1917\ Pennsylvania Commission Initial Comments at 4-5.
---------------------------------------------------------------------------
868. In response to Pacific Northwest Utilities' argument that
transmission providers will be unable to identify the beneficiaries of
Long-Term Regional Transmission Facilities over a 20-year time horizon,
and therefore that the costs of Long-Term Regional Transmission
Facilities will not be allocated in a manner that is roughly
commensurate with the benefits received,\1918\ we note that this final
order modifies the NOPR proposal and transmission providers are not
required to use a benefits time horizon of 20 years for purposes of
cost allocation. We find this modification to the final order moots
Pacific Northwest Utilities' argument.
---------------------------------------------------------------------------
\1918\ Pacific Northwest Utilities Initial Comments at 7 (citing
ICC v. FERC I, 576 F.3d 470).
---------------------------------------------------------------------------
869. We disagree with PPL's comments arguing that calculating
benefits from the estimated in-service date of a Long-Term Regional
Transmission Facility will present challenges to align the outcome with
the actual needs in Long-Term Regional Transmission Planning or
otherwise create perverse incentives for transmission developers to
delay or adjust the timing of certain transmission projects to maximize
benefits.\1919\ To the contrary, establishing a minimum benefits
horizon of 20 years starting from the estimated in-service date of
Long-Term Regional Transmission Facilities will allow for a comparable
evaluation of benefits that identified Long-Term Regional Transmission
Facilities may provide, even when such facilities may be placed in
service at different times during the transmission planning horizon. We
therefore decline PPL's request that the Commission modify the proposal
to require that transmission providers measure benefits for a minimum
of 20 years starting from the study date, rather than the estimated in-
service date of the Long-Term Regional Transmission Facility.
---------------------------------------------------------------------------
\1919\ PPL Initial Comments at 15-17.
---------------------------------------------------------------------------
870. In response to GridLab's request that the Commission clarify
the distinction between the requirements for a minimum 20-year
transmission planning horizon and a minimum 20-year benefits evaluation
period,\1920\ we reiterate the example provided in the NOPR whereby, if
the Long-Term Regional Transmission Planning process identifies a Long-
Term Regional Transmission Facility that is estimated to be in service
in year 10 of the 20-year Long-Term Regional Transmission Planning
horizon, then the estimate of benefits for that same facility will
commence at year 10 and cover an additional 20 years. Thus, the
requirement to use a 20-year transmission planning horizon is separate
and distinct from the requirement to calculate benefits of an
identified Long-Term Regional Transmission Facility over a minimum of
20 years from its estimated in-service date.
---------------------------------------------------------------------------
\1920\ GridLab Initial Comments at 6-8.
---------------------------------------------------------------------------
5. Evaluation of the Benefits of Portfolios of Transmission Facilities
a. NOPR Proposal
871. In the NOPR, the Commission proposed to provide transmission
providers in each transmission planning region with the flexibility to
propose to use a portfolio approach in the evaluation of benefits of
regional transmission facilities through their Long-Term Regional
Transmission Planning. Rather than mandating its use, the Commission
encouraged the use of this approach by transmission providers.\1921\
The Commission proposed to require transmission providers that propose
to use a portfolio approach to include in their OATTs provisions
describing how they would analyze the benefits of regional transmission
facilities under such an approach and whether the portfolio approach
would be used for Long-Term Regional Transmission Planning universally
or would be used only in certain specified instances.\1922\
---------------------------------------------------------------------------
\1921\ NOPR, 179 FERC ] 61,028 at PP 233-234.
\1922\ Id. P 234.
---------------------------------------------------------------------------
b. Comments
i. General Interest in the Use of Portfolios
872. Most commenters who addressed the issue support the use of a
portfolio approach to the evaluation of the benefits of regional
transmission facilities in Long-Term Regional Transmission Planning,
under which transmission providers would evaluate multiple transmission
facilities in an aggregated, integrated fashion rather than doing so on
a facility-by-facility basis.\1923\ Exelon states that benefits
[[Page 49421]]
assessments for portfolios are likely to be more robust and less
sensitive to changes in study assumptions than project-by-project
analyses, tend to have widely distributed benefits, which can help
garner stakeholder support, and may provide for administrative
efficiencies in transmission planning.\1924\ ACEG states that portfolio
planning more accurately evaluates the benefits that new transmission
provides to the system.\1925\ Georgia Commission states that evaluating
transmission facilities collectively, rather than on a facility-by-
facility basis, may provide a better picture of the benefits to each
state or transmission planning region and result in a more robust
selection of transmission facilities.\1926\
---------------------------------------------------------------------------
\1923\ See, e.g., Acadia Center and CLF Initial Comments at 10;
ACEG Initial Comments at 49; ACORE Initial Comments at 2; AEP
Initial Comments at 6, 27-28; Ameren Initial Comments at 19; Clean
Energy Associations Initial Comments at 10; Eversource Initial
Comments at 25; Exelon Initial Comments at 15-16; Joint Consumer
Advocates Initial Comments at 11; Massachusetts Attorney General
Initial Comments at 15-16; Pacific Northwest State Agencies Initial
Comments at 7; PG&E Initial Comments at 8; PJM Reply Comments at 23;
PIOs Initial Comments at 28; TANC Initial Comments at 16; US DOE
Initial Comments at 34-35.
\1924\ Exelon Initial Comments at 15-16, 18 (citing NOPR, 179
FERC ] 61,028 at P 233).
\1925\ ACEG Initial Comments at 49.
\1926\ Georgia Commission Initial Comments at 7.
---------------------------------------------------------------------------
873. Renewable Northwest states that using portfolios in
transmission planning is a best practice because it more completely
captures systems benefits and leads to cost efficiencies.\1927\
Renewable Northwest also comments that singularly focused planning
processes often fail to identify the most cost-effective and efficient
investments and instead have led to a bottom-up approach that has
created a patchwork of transmission projects with high costs largely
borne by ratepayers.\1928\ EEI explains that the portfolio approach
comprehensively addresses a number of transmission needs while ensuring
a ``no regrets'' set of beneficial regional transmission
projects.\1929\ Eversource states that a portfolio approach can allow
transmission providers to devise a set of transmission solutions that
collectively create the most value compared to a piecemeal
process.\1930\
---------------------------------------------------------------------------
\1927\ Renewable Northwest Initial Comments at 9-10 (citing
Brattle-Grid Strategies Oct. 2021 Report at 23).
\1928\ Id. at 9.
\1929\ EEI Initial Comments at 15.
\1930\ Eversource Initial Comments at 25.
---------------------------------------------------------------------------
874. AEP states that the portfolio approach offers three
advantages: (1) it enables transmission planning regions to identify
transmission projects with synergistic benefits across transmission
planning regions because regions will be able to recognize the
efficiencies of a collection of transmission projects that provide
greater overall value to the grid together than they each provide on an
individual basis; (2) there are administrative efficiencies; and (3) a
portfolio approach best incorporates consideration of non-transmission
alternatives and grid-enhancing technologies.\1931\
---------------------------------------------------------------------------
\1931\ AEP Initial Comments at 27-28.
---------------------------------------------------------------------------
875. Numerous commenters point to the MISO Multi-Value Project
process as an example of the successful use of portfolios.\1932\ Clean
Energy Associations state that the Multi-Value Project process has
resulted in lower interconnection costs for generators as compared to
transmission upgrades planned in response to interconnection
requests.\1933\ US DOE suggests the Multi-Value Project process is an
example of the use of portfolios to generate benefits that exceed
costs.\1934\ MISO states that it has worked with stakeholders to apply
broad benefit metrics in the evaluation of Multi-Value Projects to
identify portfolios of projects with benefits spread broadly throughout
the region.\1935\
---------------------------------------------------------------------------
\1932\ See, e.g., EEI Initial Comments at 15; Clean Energy
Associations Initial Comments at 10; MISO Initial Comments at 14; US
DOE Initial Comments at 34-35 (citing Brattle-Grid Strategies Oct.
2021 Report at 65-66).
\1933\ Clean Energy Associations Initial Comments at 10.
\1934\ US DOE Initial Comments at 35 (citing Brattle-Grid
Strategies Oct. 2021 Report at 65-66).
\1935\ MISO Initial Comments at 14.
---------------------------------------------------------------------------
876. Some commenters believe that the Commission should require the
use of portfolios in the evaluation of benefits of regional
transmission facilities.\1936\ US DOE supports requiring transmission
planners to evaluate the benefits of proposed transmission facilities
as a portfolio, rather than as individual investments, to reduce the
uncertainty of estimating system-level benefits, to simplify cost
allocation, and to reduce administrative burden.\1937\ US DOE states
that if the portfolio approach is inappropriate in a particular
circumstance, the impacted entities could petition the Commission, on a
case-by-case basis, to describe their proposed alternative
approach.\1938\
---------------------------------------------------------------------------
\1936\ Acadia Center and CLF Initial Comments at 4-5; ACEG
Initial Comments at 31, 48-49; Cypress Creek Reply Comments at 8-9;
ITC Initial Comments at 6, 23-24; Pattern Energy Initial Comments at
15-17; Pine Gate Initial Comments at 38-39; PIOs Initial Comments at
28; SEIA Initial Comments at 20-21; US DOE Initial Comments at 34-
35; WATT Initial Comments at 8-9.
\1937\ US DOE Initial Comments at 34-35.
\1938\ Id. at 35.
---------------------------------------------------------------------------
877. New Jersey Commission states that the evidence from multiple
studies of and experiences with long-term multi-driver and portfolio-
based transmission planning proves that these approaches save
ratepayers billions of dollars and failure to use them is per se unjust
and unreasonable.\1939\ Cypress Creek argues that a portfolio approach
is essential to optimize benefits and reduce the likelihood of a state
or agency derailing a transmission project with proven regional
benefits.\1940\
---------------------------------------------------------------------------
\1939\ New Jersey Commission Initial Comments at 7.
\1940\ Cypress Creek Reply Comments at 9.
---------------------------------------------------------------------------
878. PIOs state that the costs of a transmission project in a rural
area that enhances access to renewable resources may exceed its
benefits when evaluated alone, but, if evaluated with another project
that relieves congestion, the two projects may support power flows that
would not otherwise be possible.\1941\ PIOs further state that
portfolio planning can reduce the risk that transmission projects are
underutilized because they were built for a single resource that is no
longer used or only a narrow set of users were considered.\1942\
---------------------------------------------------------------------------
\1941\ PIOs Initial Comments at 31-32.
\1942\ Id. at 36.
---------------------------------------------------------------------------
879. ITC argues that the Commission should mandate the use of a
portfolio approach in RTO/ISOs to ensure that the most efficient, cost-
effective, and broadly beneficial set of transmission projects are
selected in each transmission planning cycle.\1943\ ITC states that the
use of a portfolio approach ensures that the greatest number of
subregions within a transmission planning region receive benefits from
each transmission planning cycle and provides significant efficiency
gains because transmission providers can examine the whole portfolio to
ensure that benefits exceed costs.\1944\
---------------------------------------------------------------------------
\1943\ ITC Initial Comments at 6, 23-24.
\1944\ Id. at 23.
---------------------------------------------------------------------------
880. Pattern Energy urges the Commission to require transmission
providers to adopt portfolio approaches and explain why a portfolio
approach was not (or could not be) identified in any Long-Term Regional
Transmission Plan when an incremental transmission solution is
proposed.\1945\ Pattern Energy suggests that, if the Commission does
not require portfolios, it should set a voltage threshold to identify
portfolio solutions and require that transmission providers must
explain why a portfolio approach was not taken when proposing
incremental transmission facilities at voltage levels above 100
kV.\1946\ Similarly, Shell states that if the Commission does not
require a portfolio approach, it should require transmission
[[Page 49422]]
providers to explain why portfolios are not being used.\1947\
---------------------------------------------------------------------------
\1945\ Pattern Energy Initial Comments at 15-17.
\1946\ Id. at 17.
\1947\ Shell Initial Comments at 16.
---------------------------------------------------------------------------
ii. Interest in Flexibility in the Use of Portfolios
881. Many other commenters assert that the Commission should only
permit, not require, the use of portfolios in the evaluation of
benefits.\1948\ For example, Duke states that a facility-by-facility
approach may be better suited if Long-Term Scenarios reveal the same or
nearly identical constraints in discrete and isolated areas of the
transmission grid where upgrades would be beneficial, whereas if Long-
Term Scenarios reveal more disparate issues in different scenarios a
portfolio approach may be better suited to gaining consensus and
allowing for more even distribution of benefits.\1949\ Duke asks the
Commission to provide that, on compliance, a transmission provider may
document processes for switching between or using both a facility-by-
facility analysis and a portfolio approach.\1950\
---------------------------------------------------------------------------
\1948\ APPA Initial Comments at 32; Arizona Commission Initial
Comments at 8; California Commission Initial Comments at 36-37;
Dominion Initial Comments at 36; Duke Initial Comments at 25;
Georgia Commission Initial Comments at 25; Michigan Commission
Initial Comments at 8; MISO Initial Comments at 54; NARUC Initial
Comments at 27-29; Nebraska Commission Initial Comments at 7-8;
NESCOE Initial Comments at 45; NYISO Initial Comments at 9, 41-42;
PPL Initial Comments at 16-17; SDG&E Initial Comments at 3; SPP
Initial Comments at 10; TANC Initial Comments at 16; TAPS Initial
Comments at 14; Vermont State Entities Initial Comments at 7; Xcel
Initial Comments at 12.
\1949\ Duke Initial Comments at 25-26.
\1950\ Id. at 25.
---------------------------------------------------------------------------
882. Dominion Energy states that some transmission providers may
not have a portfolio of transmission projects to examine. NYISO asserts
that transmission providers should not be required to mix and match
components of different transmission developers' proposed transmission
solutions to develop a portfolio to address a single transmission
need.\1951\ APPA and TANC urge the Commission to allow regional
flexibility to use a portfolio approach to evaluate benefits.\1952\
---------------------------------------------------------------------------
\1951\ NYISO Initial Comments at 41.
\1952\ APPA Initial Comments at 32; TANC Initial Comments at 16.
---------------------------------------------------------------------------
883. PPL argues that a portfolio approach should not be mandated
because one-size-fits-all portfolio-based planning may have downsides
and may not be applicable in all circumstances or transmission planning
regions.\1953\ PPL further states that relying on portfolios could lead
to complications in siting and cost allocation.\1954\ Relatedly,
Michigan Commission argues that requiring portfolios could cause
unnecessary delays for transmission projects that have strong
stakeholder buy-in and incentivize including transmission projects less
deserving of regional cost allocation purely to bolster assertions that
all zones in multi-state RTOs/ISOs will benefit.\1955\
---------------------------------------------------------------------------
\1953\ PPL Initial Comments at 16-17.
\1954\ Id. at 17.
\1955\ Michigan Commission Initial Comments at 8.
---------------------------------------------------------------------------
884. CAISO states that portfolio planning should be optional,
arguing that CAISO's sequential transmission planning approach achieves
multi-benefit and holistic objectives without requiring a portfolio
approach.\1956\ CAISO explains that a project-by-project review does
not mean examining only one transmission need at a time or failing to
consider transmission projects that meet multiple needs or deliver
multiple benefits.\1957\
---------------------------------------------------------------------------
\1956\ CAISO Reply Comments at 22.
\1957\ Id. at 21-22.
---------------------------------------------------------------------------
iii. Interest in Including the Portfolio Approach in a Transmission
Provider's OATT
885. In response to the Commission's proposal that a transmission
provider that proposes a portfolio approach must include in its OATT a
description of when it would use the approach and how it would analyze
benefits, some commenters agree that even if use of portfolios is
flexible, the Commission should have such a requirement.\1958\ Vermont
State Entities suggest that if a transmission provider elects to use a
portfolio approach, it must include in its OATT a description of how it
would use such an approach and whether that approach would be used
universally or only in certain specified instances.\1959\
---------------------------------------------------------------------------
\1958\ Clean Energy Associates Initial Comments at 14; NESCOE
Initial Comments at 45; Vermont State Entities Initial Comments at
7.
\1959\ Vermont State Entities Initial Comments at 7.
---------------------------------------------------------------------------
iv. Integrating Economic and Reliability Planning With Long-Term
Regional Transmission Planning
886. PIOs state that portfolio planning is necessary and that the
use of portfolios should incorporate long-term reliability and economic
needs and benefits along with long-term Public Policy Requirements,
because doing so allows transmission providers to select transmission
projects with the higher benefit-to-cost ratios that resolve needs at
least cost.\1960\ PIOs state that by assessing all transmission needs
at once and evaluating potential solutions, stakeholders will be able
to find more efficient solutions that address multiple transmission
needs that affect different jurisdictions simultaneously.\1961\ PIOs
ask that the final order allow transmission providers to continue to
address unforeseen short-term local reliability needs but establish a
rebuttable requirement that all long-term economic, public policy, and
regional reliability needs and benefits will be assessed on a portfolio
basis in Long-Term Regional Transmission Planning.\1962\
---------------------------------------------------------------------------
\1960\ PIOs Initial Comments at 30-32.
\1961\ Id. at 35.
\1962\ PIOs Initial Comments at 32.
---------------------------------------------------------------------------
887. SEPA states that the portfolio approach can be further
enhanced by considering all categories of benefits: reliability,
economic, public policy, and resilience.\1963\ Likewise, SEIA states
that the Commission should require portfolio-based planning that
integrates all relevant factors, reliability, economic, and public
policy, into Long-Term Regional Transmission Planning.\1964\ Acadia
Center and CLF discuss portfolio planning as integrating Long-Term
Regional Transmission Planning with economic and reliability planning
and state that the final order should require portfolio-based planning
that assesses economic, reliability, and other needs at the same
time.\1965\
---------------------------------------------------------------------------
\1963\ SEPA Initial Comments at 1.
\1964\ SEIA Initial Comments at 20-21.
\1965\ Acadia Center and CLF Initial Comments at 4-5.
---------------------------------------------------------------------------
v. Concerns With the Portfolio Approach
888. A few commenters express apprehension about the portfolio
approach, including concerns that the use of portfolios may mask bad
individual transmission projects in a portfolio or result in good
transmission projects not being approved because of difficulties in
obtaining multiple state approvals that may be necessary for a
portfolio.\1966\ For example, Pennsylvania Commission states that a
portfolio approach may cause siting concerns if a single transmission
project in a portfolio is found by a state siting authority to be
inconsistent with its state's public interest and siting
regulations.\1967\ Idaho Commission opposes requiring the use of a
portfolio under any circumstances, stating that flexibility is
necessary in transmission planning. It further states that a Commission
requirement to use a portfolio approach under certain circumstances
without specifying what
[[Page 49423]]
these circumstances are could result in unjust and unreasonable
rates.\1968\ Louisiana Commission also opposes any requirement to use a
portfolio approach and disagrees with the NOPR's encouragement of such
an approach.\1969\
---------------------------------------------------------------------------
\1966\ CAISO Reply Comments at 24; Duke Initial Comments at 25-
26; Idaho Commission Initial Comments at 4; Louisiana Commission
Initial Comments at 26; NARUC Initial Comments at 28; Pennsylvania
Commission Initial Comments at 10; PPL Initial Comments at 17.
\1967\ Pennsylvania Commission Initial Comments at 10.
\1968\ Idaho Commission Initial Comments at 4.
\1969\ Louisiana Commission Initial Comments at 26.
---------------------------------------------------------------------------
c. Commission Determination
889. We adopt the NOPR proposal to allow, but not require,
transmission providers in each transmission planning region to use a
portfolio approach when evaluating the benefits of Long-Term Regional
Transmission Facilities. Further, we adopt with modification the NOPR
proposal to require transmission providers that propose to use a
portfolio approach when evaluating the benefits of Long-Term Regional
Transmission Facilities to include provisions in their OATTs regarding
their use of the portfolio approach. While we adopt the NOPR proposal
to require transmission providers to include provisions in their OATTs
regarding their use of a portfolio approach, we do not adopt the other
proposed requirements. Specifically, we decline to adopt the NOPR
proposal to require transmission providers to indicate whether a
portfolio approach will be used universally or only in certain
specified instances or to describe how they will analyze the benefits
of regional transmission facilities under a portfolio approach. These
requirements could impede transmission provider consideration and
development of portfolio approaches. In response to Duke's request that
the final order provide transmission providers with the flexibility to
switch between or use both facility-by-facility and portfolio
approaches,\1970\ we clarify that transmission providers may use either
or both facility-by-facility and portfolio approaches within the same
Long-Term Regional Transmission Planning cycle.
---------------------------------------------------------------------------
\1970\ Duke Initial Comments at 25-26.
---------------------------------------------------------------------------
890. We find that there are numerous advantages to a portfolio
approach to evaluating benefits, including administrative efficiencies
related to economies of scale and a more stable or even distribution of
benefits that may result from a portfolio evaluation, which is likely
to facilitate agreement on regional cost allocation. However, these
advantages must be balanced against other considerations, and we
therefore find that providing transmission providers in each
transmission planning region with flexibility as to whether to use a
portfolio approach is appropriate. Accordingly, we decline the request
of some commenters \1971\ to require transmission providers to use a
portfolio approach.
---------------------------------------------------------------------------
\1971\ Acadia Center and CLF Initial Comments at 4-5; ACEG
Initial Comments at 31, 48-49; Cypress Creek Reply Comments at 8-9;
ITC Initial Comments at 6, 23-24; Pattern Energy Initial Comments at
16-18; Pine Gate Initial Comments at 38-39; PIOs Initial Comments at
28; SEIA Initial Comments at 20-21; US DOE Initial Comments at 34-
35; WATT Initial Comments at 8-9.
---------------------------------------------------------------------------
6. Issues Related to Use of Benefits
a. NOPR Proposal
891. The Commission in the NOPR declined, consistent with Order No.
1000, to propose to prescribe any particular definition of ``benefits''
or ``beneficiaries.'' \1972\
---------------------------------------------------------------------------
\1972\ NOPR, 179 FERC ] 61,028 at P 183 & n.324 (citing Order
No. 1000, 136 FERC ] 61,051 at PP 624-625).
---------------------------------------------------------------------------
b. Comments
892. Some commenters request specific definitions for the terms
``benefits'' or ``beneficiaries'' or offer guidance on
definitions.\1973\ NASUCA urges the Commission not to define benefits
so broadly that every transmission project would qualify to be built,
stating that overly broad benefit definitions reduce any rational
relationship between cost allocation and identifiable
beneficiaries.\1974\
---------------------------------------------------------------------------
\1973\ ELCON Initial Comments at 14-15; NASUCA Initial Comments
at 10.
\1974\ NASUCA Initial Comments at 10.
---------------------------------------------------------------------------
893. In contrast, other commenters agree with the Commission's
proposal not to define ``benefits'' or ``beneficiaries.'' \1975\ For
example, OMS and the Indiana Commission express support for the NOPR
proposal to allow for flexibility in determining the definitions of
benefits and beneficiaries for the purpose of selecting transmission
facilities in Long-Term Regional Transmission Planning.\1976\
---------------------------------------------------------------------------
\1975\ APPA Initial Comments at 31-33; Clean Energy Buyers Reply
Comments at 9; Georgia Commission Initial Comments at 6-7; Indiana
Commission Initial Comments at 6-7; Louisiana Commission Reply
Comments at 9-10; Nebraska Commission Initial Comments at 7; TANC
Initial Comments at 16; US Chamber of Commerce Initial Comments at
7-8.
\1976\ Indiana Commission Initial Comments at 6-7; OMS Initial
Comments at 13.
---------------------------------------------------------------------------
894. Some commenters call for a state role in identifying benefits
or metrics for use in Long-Term Regional Transmission Planning.\1977\
California Commission states that the Commission should require
transmission providers to demonstrate that they consulted with the
Relevant State Entities in their transmission planning region regarding
benefits metrics.\1978\ California Commission further states that the
Commission should require transmission providers to indicate in their
compliance filings whether their proposed benefits and metrics are
supported by the Relevant State Entities, as well as to explain any
points of disagreement.\1979\ Likewise, New York Commission and NYSERDA
state that, especially in single-state RTOs/ISOs, the state should be
afforded a central role in determining the benefits that transmission
providers will consider and the metrics for quantifying them.\1980\
---------------------------------------------------------------------------
\1977\ California Commission Initial Comments at 35;
Massachusetts Attorney General Initial Comments at 14; Michigan
Commission Initial Comments at 7-8; NESCOE Initial Comments at 41-
43; North Carolina Commission and Staff Initial Comments at 6; PJM
Market Monitor Initial Comments at 4.
\1978\ California Commission Initial Comments at 35.
\1979\ Id.
\1980\ New York Commission and NYSERDA Initial Comments at 8.
---------------------------------------------------------------------------
895. North Carolina Commission and Staff state that, given the
focus of the NOPR on transmission needs driven by changes in the
generation mix and demand, which are areas of state jurisdiction, the
Commission should require state agreement at every stage of the Long-
Term Regional Transmission Planning process from identification of
transmission needs, to the evaluation of the benefits of regional
transmission facilities to meet those needs, to establishment of
selection criteria, and finally to establishment of a cost allocation
method.\1981\ Similarly, NESCOE explains that, while transmission
providers have the technical expertise to identify, calculate, and
explain the benefits that a given transmission facility may provide,
states must be involved where state laws and policies are the project
drivers.\1982\ As such, NESCOE requests that the Commission require
that transmission providers either elevate and codify the states' role
in all four phases of Long-Term Regional Transmission Planning or
explain how and why, following consultation with the Relevant State
Entities, the transmission provider developed a different
approach.\1983\ NESCOE asserts that this requirement would ensure that
states, if they so elect, have a defined role in the evaluation phase
of Long-Term Regional Transmission Planning.\1984\
---------------------------------------------------------------------------
\1981\ North Carolina Commission and Staff Initial Comments at
6.
\1982\ NESCOE Initial Comments at 41-43.
\1983\ Id. at 9-10, 41-43.
\1984\ Id. at 41-43.
---------------------------------------------------------------------------
896. Virginia Commission Staff contends that the NOPR-identified
benefits should be used only if affected
[[Page 49424]]
states agree to their use.\1985\ PJM Market Monitor agrees that it
makes sense to attempt an evaluation of a broad set of benefits and
beneficiaries through increased state involvement.\1986\
---------------------------------------------------------------------------
\1985\ Virginia Commission Staff Initial Comments at 5.
\1986\ PJM Market Monitor Initial Comments at 4.
---------------------------------------------------------------------------
897. Michigan Commission asserts that state regulators should be
afforded substantial deference in identifying what benefit metrics and
calculation methods should be used to justify long-term transmission
plans, arguing that states with objections or concerns that an approved
benefit metric is too speculative or otherwise inappropriate may find
it more challenging to justify ratepayer investments and land
condemnation in state siting proceedings.\1987\ Massachusetts Attorney
General states that the Commission should require that transmission
providers establish an open and transparent process that provides
states and other stakeholders with a meaningful opportunity to
participate in the process of identifying the benefits to be used in
Long-Term Regional Transmission Planning and determining how such
benefits will be calculated.\1988\ Several commenters state that
decisions regarding benefit determination, metrics, and implementation
of metrics should be made in coordination with all stakeholders.\1989\
NRECA and Vermont State Entities assert that transmission providers
should be required to demonstrate that all stakeholders are provided an
opportunity to become fully aware of the analytic framework for
incorporating benefits that will be used in Long-Term Regional
Transmission Planning.\1990\
---------------------------------------------------------------------------
\1987\ Michigan Commission Initial Comments at 7-8.
\1988\ Massachusetts Attorney General Initial Comments at 14.
\1989\ NYISO Initial Comments at 37; NRECA Initial Comments at
46; Vermont State Entities Initial Comments at 6.
\1990\ NRECA Initial Comments at 46; Vermont State Entities
Initial Comments at 6.
---------------------------------------------------------------------------
898. PPL stresses the important role that states play in siting
transmission facilities and the significance of benefits from
transmission facilities in this process, cautioning that differences
between states' and the Commission's delineation and evaluation of
benefits will result in great uncertainty. PPL asserts that this
uncertainty could lead to abandoned projects, costly litigation, and a
largely underutilized planning tool, akin to transmission projects
driven by public policy needs under Order No. 1000.\1991\
---------------------------------------------------------------------------
\1991\ PPL Initial Comments at 14-15.
---------------------------------------------------------------------------
899. In contrast, ACORE notes that the benefits of transmission
facilities are often spread out among states regardless of the state
policies contributing to the need for such transmission
facilities.\1992\
---------------------------------------------------------------------------
\1992\ ACORE Initial Comments at 12; ACORE Reply Comments at 6.
---------------------------------------------------------------------------
900. SoCal Edison urges the Commission not to decouple policy
projects from reliability and economic projects in transmission
planning, so as to reduce barriers to regional coordination and ensure
analysis of all potential benefits of a transmission project.\1993\
---------------------------------------------------------------------------
\1993\ SoCal Edison Initial Comments at 12-13.
---------------------------------------------------------------------------
901. Indiana Commission states that it supports the NOPR proposal
as long as the final order provides for an equitable cost allocation
method that allocates costs to the cost causer and beneficiaries of
regional transmission development.\1994\
---------------------------------------------------------------------------
\1994\ Indiana Commission Initial Comments at 6-7.
---------------------------------------------------------------------------
c. Commission Determination
902. Consistent with the NOPR, we continue to decline to define
``benefits'' or ``beneficiaries.'' We discuss above descriptions of the
seven required benefits, and we further require transmission providers
to propose a method to measure each of those benefits. These
descriptions and requirements for these seven benefits will facilitate
transparency regarding the use of benefits in Long-Term Regional
Transmission Planning and represent an improvement in this respect over
Order No. 1000, which lacked such descriptions.\1995\ However, we do
not believe that establishing a definition of ``benefits'' or
``beneficiaries'' would significantly improve upon these descriptions
and we are concerned that any such definition could inadvertently
exclude benefits and beneficiaries.
---------------------------------------------------------------------------
\1995\ As noted above, we do not require transmission providers
to include additional benefits that they use for purposes of
evaluation and selection of Long-Term Regional Transmission
Facilities in their OATTs.
---------------------------------------------------------------------------
903. We acknowledge comments requesting greater clarity regarding
states' roles in determining benefits in their transmission planning
regions and regarding the benefits that will be used by transmission
providers in Long-Term Regional Transmission Planning, including
NRECA's and Vermont State Entities' assertions that transmission
providers should be required to demonstrate that all stakeholders
(including state entities and load-serving entities) are provided an
opportunity to become fully aware of the analytic framework for
incorporating benefits that will be used in Long-Term Regional
Transmission Planning.\1996\ In response, we note this final order
provides transmission providers with flexibility as to how they measure
the seven required benefits, as well as flexibility to use additional
benefits beyond the seven that we require. Consistent with other
reforms in this final order incorporating an inclusive role for states
in transmission planning, we encourage transmission providers to
consult with states as they develop proposals to comply with the
requirements of this final order and consider whether, and if so, how,
to use additional benefits in Long-Term Regional Transmission
Planning.\1997\
---------------------------------------------------------------------------
\1996\ NRECA Initial Comments at 46; Vermont State Entities
Initial Comments at 6.
\1997\ See supra Other Benefits section.
---------------------------------------------------------------------------
E. Evaluation and Selection of Long-Term Regional Transmission
Facilities
1. Requirement To Adopt an Evaluation Process and Selection Criteria
a. NOPR Proposal
904. In the NOPR, the Commission proposed to require that
transmission providers, as part of their Long-Term Regional
Transmission Planning, include in their OATTs a transparent and not
unduly discriminatory evaluation process and criteria to identify and
evaluate transmission facilities (or portfolios of transmission
facilities) for potential selection that address transmission needs
driven by changes in the resource mix and demand.\1998\ The Commission
preliminarily found that the development and analysis of Long-Term
Scenarios cannot remedy the deficiencies in the Commission's existing
regional transmission planning requirements without the inclusion of
such an evaluation process and selection criteria because, without
them, transmission providers' Commission-jurisdictional rates may be
unjust and unreasonable and unduly discriminatory and
preferential.\1999\
---------------------------------------------------------------------------
\1998\ See NOPR, 179 FERC ] 61,028 at PP 241-242.
\1999\ Id. P 250.
---------------------------------------------------------------------------
905. The Commission further proposed in the NOPR that, consistent
with Order No. 1000, the developer of a transmission facility selected
through Long-Term Regional Transmission Planning to address
transmission needs driven by changes in the resource mix and demand
would be eligible to use the applicable cost allocation method for the
Long-Term Regional Transmission Facility.
b. Comments
906. Many commenters support the Commission's proposal to require
[[Page 49425]]
transmission providers to include in their OATTs provisions providing
criteria that they will use to identify and evaluate transmission
facilities for potential selection to address transmission needs driven
by changes in the resource mix and demand.\2000\ For example, Pacific
Northwest State Agencies argue that this reform is critical to ensuring
that Long-Term Regional Transmission Planning results in appropriate
modeling and evaluation of Long-Term Regional Transmission
Facilities.\2001\ ACEG contends that transparent selection processes
are key to reducing conflict (including costly litigation), developing
legally sustainable long-term regional transmission plans, and
maximizing benefits over time to consumers without over-building
transmission facilities.\2002\
---------------------------------------------------------------------------
\2000\ ACEG Initial Comments at 9; ACORE Initial Comments at 14;
Amazon Initial Comments at 9; Ameren Initial Comments at 20; APPA
Initial Comments at 33; CARE Coalition Initial Comments at 11-12;
Clean Energy Buyers Initial Comments at 22; Exelon Initial Comments
at 17; GridLab Initial Comments at 19; NRECA Initial Comments at 25;
[Oslash]rsted Initial Comments at 5-6; Pacific Northwest State
Agencies Initial Comments at 19; PPL Initial Comments at 18; Resale
Iowa Initial Comments at 7-8.
\2001\ Pacific Northwest State Agencies Initial Comments at 19.
\2002\ ACEG Initial Comments at 9, 58.
---------------------------------------------------------------------------
907. Other commenters oppose the Commission's proposal. Many of
these commenters argue that Long-Term Regional Transmission Planning
should be for informational purposes only and that the Commission
should not require transmission providers to include selection criteria
in their OATTs.\2003\ Alabama Commission contends that Long-Term
Regional Transmission Planning should not involve selection or
construction obligations unless the affected state regulators support
such actions.\2004\ ELCON argues that selection should occur in
``nearer-term planning (i.e., 10-15 years)'' when there is greater
certainty that there is a specific transmission need.\2005\
---------------------------------------------------------------------------
\2003\ Alabama Commission Initial Comments at 3; ELCON Initial
Comments at 10; Kansas Commission Initial Comments at 14; NRECA
Initial Comments at 23-24; NRG Initial Comments at 6, 14; Ohio
Consumers Initial Comments at 20; see also NARUC Initial Comments at
5 (``Long-Term Regional Transmission Planning [should] be used as a
planning tool and not a construction requirement.''); TANC Initial
Comments at 10 (commenting that TANC ``requests that the Commission
clarify[ ] that the Commission is not proposing to require use of a
20-year planning horizon for . . . selecting Long-Term Regional
Transmission Facilities'').
\2004\ Alabama Commission Initial Comments at 3. Relatedly,
Avangrid argues that the Commission should more clearly articulate
how selection affects the actual construction of the transmission
facility. Avangrid Initial Comments at 17.
\2005\ ELCON Initial Comments at 10-11.
---------------------------------------------------------------------------
908. Some commenters argue that it is unnecessary for the
Commission to require that transmission providers include additional
selection criteria in their OATTs. For example, Dominion contends that
Order No. 1000 already requires transmission providers to include
selection criteria in their OATTs, and that the final order should
allow, but not require, them to add to those existing selection
criteria.\2006\ Idaho Commission also believes that Order No. 1000's
requirements are adequate and argues that the Commission has not
demonstrated that there is a need to modify them.\2007\ Similarly,
Idaho Power argues that selection criteria specific to Long-Term
Regional Transmission Planning are unnecessary in light of existing
processes to identify and evaluate transmission facilities in the
NorthernGrid transmission planning region.\2008\ NYISO requests that
the Commission confirm that the final order will not require changes to
or the replacement of existing selection criteria.\2009\ Chemistry
Council argues that the Commission should affirm that transmission
providers must continue addressing nearer-term regional transmission
needs, giving significant weight to transmission facilities that meet
customer and end-user needs, ensure grid reliability and energy
security, and prevent abandonment of needed resources.\2010\
---------------------------------------------------------------------------
\2006\ Dominion Initial Comments at 37 (citing NOPR, 179 FERC ]
61,028 at P 236).
\2007\ Idaho Commission Initial Comments at 4-5.
\2008\ Idaho Power Initial Comments at 8.
\2009\ NYISO Initial Comments at 43.
\2010\ Chemistry Council Initial Comments at 6-7.
---------------------------------------------------------------------------
909. Clean Energy Buyers state that they support the NOPR proposal
to grant eligibility to use the applicable cost allocation method to
the developer of a Long-Term Regional Transmission Facility selected,
subject to applicable development schedules. Clean Energy Buyers argue
that this proposal could provide a more stable source of revenue and
help resolve the ``first-mover problem,'' which in turn could support
additional transmission development.\2011\
---------------------------------------------------------------------------
\2011\ Clean Energy Buyers Initial Comments at 21-22 (citing
NOPR, 179 FERC ] 61,028 at P 247).
---------------------------------------------------------------------------
910. Finally, SPP contends that allowing transmission providers to
include selection criteria in business practice manuals rather than
their OATTs would give them more flexibility if they need to adjust
study approaches.\2012\
---------------------------------------------------------------------------
\2012\ SPP Initial Comments at 21-22.
---------------------------------------------------------------------------
c. Commission Determination
911. We adopt the NOPR proposal to require transmission providers
in each transmission planning region to include in their OATTs an
evaluation process, including selection criteria, that they will use to
identify and evaluate Long-Term Regional Transmission Facilities for
potential selection to address Long-Term Transmission Needs. We set
forth requirements with respect to the evaluation process and selection
criteria in the following sections.
912. We also adopt the NOPR proposal that, consistent with Order
No. 1000, the transmission developer of a Long-Term Regional
Transmission Facility that is selected, whether incumbent or
nonincumbent, will be eligible to use the applicable cost allocation
method for the Long-Term Regional Transmission Facility.
913. As explained above, transmission providers currently are not
identifying or evaluating Long-Term Regional Transmission Facilities
that might more efficiently or cost-effectively address Long-Term
Transmission Needs and, therefore, do not have the opportunity to
select such transmission facilities. We find that remedying these
deficiencies in the Commission's existing regional transmission
planning requirements requires the inclusion in transmission providers'
OATTs of an evaluation process and selection criteria for Long-Term
Regional Transmission Facilities, as outlined below, which, together
with other aspects of this final order, will help to ensure that
transmission providers' Commission-jurisdictional rates are just and
reasonable and not unduly discriminatory or preferential.
914. We find that the inclusion in transmission providers' OATTs of
an evaluation process and selection criteria for Long-Term Regional
Transmission Facilities is essential to the reforms that we adopt in
this final order. Without these essential components, Long-Term
Regional Transmission Planning would merely inform the existing
regional transmission planning processes rather than solving the
deficiencies in the Commission's existing regional transmission
planning requirements that we identify in this final order. The
complete set of reforms that we adopt here are fundamental to resolving
these deficiencies and to ensuring that transmission providers have the
opportunity to select more efficient or cost-effective Long-Term
Regional Transmission Facilities to meet Long-Term Transmission Needs.
Therefore, we disagree with commenters who suggest that an evaluation
process or selection criteria are unnecessary or
[[Page 49426]]
inappropriate for the Long-Term Regional Transmission Planning \2013\
reforms that we adopt in this final order.
---------------------------------------------------------------------------
\2013\ See, e.g., Alabama Commission Initial Comments at 3;
Dominion Initial Comments at 37; ELCON Initial Comments at 10-11;
Idaho Commission Initial Comments at 4-5; Idaho Power Initial
Comments at 8; Kansas Commission Initial Comments at 14; NRECA
Initial Comments at 23-24; NRG Initial Comments at 6, 14; TANC
Initial Comments at 10; see also Ohio Consumers Initial Comments at
20 (arguing that a 20-year transmission planning horizon is
inappropriate for constructing or allocating the costs of
transmission facilities).
---------------------------------------------------------------------------
915. We understand that transmission providers might propose to re-
purpose existing evaluation processes or selection criteria (with or
without modifications thereto) to use in Long-Term Regional
Transmission Planning. In their compliance filings, transmission
providers must propose the evaluation process and selection criteria
that they will use in Long-Term Regional Transmission Planning, and
they must demonstrate that they meet the final order requirements. In
response to NYISO's request,\2014\ however, we clarify that nothing in
this final order requires transmission providers to modify or replace
selection criteria used in their existing reliability and economic
Order No. 1000 regional transmission planning processes.
---------------------------------------------------------------------------
\2014\ NYISO Initial Comments at 43. We reiterate that, as
discussed above in the Participation in Long-Term Regional
Transmission Planning section, transmission providers may propose to
continue using some or all aspects of the existing regional
transmission planning and cost allocation processes that they use to
consider transmission needs driven by Public Policy Requirements,
provided that transmission providers demonstrate that continued use
of any such processes does not interfere with or otherwise undermine
Long-Term Regional Transmission Planning as set forth in this final
order.
---------------------------------------------------------------------------
916. As discussed below, to meet the requirements of this final
order, transmission providers in each transmission planning region must
establish a Long-Term Regional Transmission Planning evaluation process
that: (1) identifies Long-Term Regional Transmission Facilities that
address Long-Term Transmission Needs; (2) measures the benefits of the
identified Long-Term Regional Transmission Facilities consistent with
the final order requirements; and (3) designates a point in the
evaluation process at which transmission providers will determine
whether to select or not select identified Long-Term Regional
Transmission Facilities in the regional transmission plan for purposes
of cost allocation.\2015\ We recognize the inherent uncertainty
involved in identifying Long-Term Transmission Needs over the minimum
transmission planning horizon adopted in this final order and in
measuring the benefits that could be provided by Long-Term Regional
Transmission Facilities. However, we continue to believe that there are
selection criteria that transmission providers could adopt, following
consultation with stakeholders and with Relevant State Entities in
their transmission planning region's footprint, that minimize these
risks while allowing for selection of Long-Term Regional Transmission
Facilities that more efficiently or cost-effectively meet Long-Term
Transmission Needs. We emphasize that we do not require transmission
providers to select any particular Long-Term Regional Transmission
Facilities but rather to adopt an evaluation process and selection
criteria that meet the final order requirements. This evaluation
process will ensure that Long-Term Regional Transmission Planning will
provide transmission providers with a framework that allows for the
selection of Long-Term Regional Transmission Facilities that more
efficiently or cost-effectively address Long-Term Transmission
Needs.\2016\
---------------------------------------------------------------------------
\2015\ See, e.g., NOPR, 179 FERC ] 61,028 at P 56 (setting forth
requirements for Long-Term Regional Transmission Planning).
\2016\ For these reasons, in addition to those discussed above,
we disagree with ELCON that transmission providers should only
select transmission facilities in ``near-term planning (i.e., 10-15
years).'' ELCON Initial Comments at 10-11.
---------------------------------------------------------------------------
917. We reiterate that, consistent with Order No. 1000,\2017\
selection in the regional transmission plan does not entitle the
transmission developer of a selected Long-Term Regional Transmission
Facility to site or construct that transmission facility, nor does it
obviate the need for the transmission developer to obtain other state,
local, and/or Federal permits or authorizations. For this reason, we
disagree with comments suggesting that the Commission proposed to do
otherwise in the NOPR.\2018\
---------------------------------------------------------------------------
\2017\ E.g., Order No. 1000-A, 139 FERC ] 61,132 at P 191.
\2018\ See, e.g., Alabama Commission Initial Comments at 3;
Dominion Reply Comments at 8 (citing PIOs Initial Comments at 28;
NARUC Initial Comments at 5-6, 39); NARUC Initial Comments at 5, 39.
---------------------------------------------------------------------------
918. Finally, we find that, consistent with the Commission's rule
of reason,\2019\ transmission providers' evaluation processes and
selection criteria significantly affect rates, are reasonably
susceptible to specification, and are not otherwise so generally
understood as to render their recitation superfluous and therefore must
be included in their OATTs. As such, we reject SPP's request that we
allow transmission providers to instead maintain evaluation processes
and selection criteria in their business practice manuals.\2020\
---------------------------------------------------------------------------
\2019\ See Cal. Indep. Sys. Operator Corp., 185 FERC ] 61,210,
at P 183 (2023) (citing Hecate Energy Greene Cnty. 3 LLC v. FERC, 72
F.4th 1307, 1314 (D.C. Cir. 2023); City of Cleveland v. FERC, 773
F.2d 1368, 1376 (D.C. Cir. 1985)).
\2020\ SPP Initial Comments at 21-22.
---------------------------------------------------------------------------
2. Flexibility
a. NOPR Proposal
919. Subject to certain minimum requirements, the Commission
proposed in the NOPR to provide transmission providers with the
flexibility to propose the selection criteria that they, in
consultation with their stakeholders, believe will ensure that more
efficient or cost-effective regional transmission facilities to address
the region's transmission needs driven by changes in the resource mix
and demand ultimately are selected.\2021\ The Commission stated that
this proposed flexibility would help accommodate regional differences,
such as differences in transmission needs, factors driving those needs,
and market structures.\2022\ The Commission stated that providing
flexibility to propose evaluation processes and selection criteria
would allow transmission providers, in consultation with their
stakeholders, to determine criteria for assessing the efficiency or
cost-effectiveness of various regional transmission facilities, whether
by reference, for example, to a benefit-cost ratio or by aggregate net
benefits.\2023\ The Commission stated that it further believed this
proposed flexibility would allow transmission providers in each
transmission planning region to develop selection criteria that could
sufficiently balance individual state interests within each
transmission planning region.\2024\
---------------------------------------------------------------------------
\2021\ NOPR, 179 FERC ] 61,028 at P 242.
\2022\ Id. P 243.
\2023\ Id. P 243.
\2024\ Id. P 244.
---------------------------------------------------------------------------
b. Comments
920. Many commenters support the Commission's proposal to provide
transmission providers with the flexibility to propose an evaluation
process and selection criteria that they, in consultation with their
stakeholders, believe will ensure that more efficient or cost-effective
Long-Term Regional Transmission Facilities to address the transmission
planning region's transmission needs driven by changes in the resource
mix and demand ultimately are selected.\2025\
---------------------------------------------------------------------------
\2025\ APPA Initial Comments at 33-34; Avangrid Initial Comments
at 17; California Commission Initial Comments at 37; Chemistry
Council Initial Comments at 6; Duke Initial Comments at 26;
Eversource Initial Comments at 26; GridLab Initial Comments at 19;
ISO-NE Initial Comments at 35; MISO Initial Comments at 54; Nebraska
Commission Initial Comments at 8; TAPS Initial Comments at 16; US
Chamber of Commerce Initial Comments at 8.
---------------------------------------------------------------------------
[[Page 49427]]
921. For example, Nebraska Commission asserts that this flexibility
will allow transmission providers to develop selection criteria that
balance individual states' interests.\2026\ Eversource argues that
flexibility will foster investments in cost-effective regional
transmission facilities, accommodate differences in transmission needs
between transmission planning regions, and encourage stakeholder
engagement.\2027\ While NEPOOL supports flexibility as a general
matter, it asserts that the Commission should articulate guiding
principles for how selection decisions will be made and by whom, and
guidelines regarding when transmission solutions should be selected to
address long-term transmission needs.\2028\
---------------------------------------------------------------------------
\2026\ Nebraska Commission Initial Comments at 8 (citing NOPR,
179 FERC ] 61,028 at P 244).
\2027\ Eversource Initial Comments at 26 (citing NOPR, 179 FERC
] 61,028 at PP 242-243).
\2028\ NEPOOL Initial Comments at 7-8.
---------------------------------------------------------------------------
922. By contrast, some commenters argue that the Commission should
establish pro forma selection criteria.\2029\ Clean Energy Associations
argues that doing so would enhance transparency, minimize differences
across seams, and enable state regulators, consumers, and other market
participants to evaluate transmission projects that result from Long-
Term Regional Transmission Planning on an apples-to-apples basis.\2030\
Similarly, SEIA urges the Commission to establish a set of minimum
requirements for selecting transmission facilities in Long-Term
Regional Transmission Planning, arguing that transmission planning
regions otherwise may fail to select transmission facilities that
provide significant regional benefits.\2031\ For its part, Clean Energy
Buyers contends that adopting pro forma selection criteria would
provide greater transparency and consistency across transmission
planning regions, hopefully help to avoid disputes, and allow for
consultation with states and other stakeholders.\2032\
---------------------------------------------------------------------------
\2029\ See, e.g., ACORE Reply Comments at 5-6 (citing Policy
Integrity Initial Comments at 2-3); Policy Integrity Initial
Comments at 2-3.
\2030\ Clean Energy Associations Initial Comments at 22-23.
\2031\ SEIA Initial Comments at 5, 19.
\2032\ Clean Energy Buyers Initial Comments at 22-23.
---------------------------------------------------------------------------
923. Acadia Center and CLF argue that requiring a minimum set of
selection criteria will provide critical information to transmission
providers who rely on the Commission to make clear what considerations
they may weigh in Long-Term Regional Transmission Planning,
facilitating more productive conversations at the regional level.\2033\
---------------------------------------------------------------------------
\2033\ Acadia Center and CLF Initial Comments at 10-11.
---------------------------------------------------------------------------
c. Commission Determination
924. Subject to the requirements described further below, we adopt
the NOPR proposal to require transmission providers in each
transmission planning region to propose, after consultation with
Relevant State Entities and other stakeholders, evaluation processes,
including selection criteria, that they believe will ensure that more
efficient or cost-effective Long-Term Regional Transmission Facilities
are selected to address the transmission planning region's Long-Term
Transmission Needs. We believe that providing transmission providers
with this flexibility will allow them to design evaluation processes
and selection criteria that can accommodate regional differences.
925. We reject requests that, instead of providing transmission
providers with flexibility, we set forth standard evaluation processes
and selection criteria in this final order that transmission providers
would be required to adopt.\2034\ While we recognize that there may be
some benefits to doing so, we also find that transmission planning
regions have different transmission needs and market structures that
make designing a standard evaluation process and selection criteria
difficult.
---------------------------------------------------------------------------
\2034\ Acadia Center and CLF Initial Comments at 10-11; Clean
Energy Associations Initial Comments at 22-23; SEIA Initial Comments
at 5, 19.
---------------------------------------------------------------------------
926. In response to NEPOOL,\2035\ we clarify that transmission
providers make the selection decisions in Long-Term Regional
Transmission Planning. Although we do not require transmission
providers to select any particular Long-Term Regional Transmission
Facility to address Long-Term Transmission Needs, as discussed below in
the No Selection Requirement section, we do set forth minimum
requirements with respect to the evaluation process and selection
criteria, which will help to ensure that transmission providers select
Long-Term Regional Transmission Facilities to more efficiently or cost-
effectively address Long-Term Transmission Needs.
---------------------------------------------------------------------------
\2035\ NEPOOL Initial Comments at 8.
---------------------------------------------------------------------------
3. Minimum Requirements
a. NOPR Proposal
927. In the NOPR, the Commission proposed certain minimum
requirements such that transmission providers' selection criteria must
(1) be transparent and not unduly discriminatory; (2) aim to ensure
that more efficient or cost-effective transmission facilities are
selected in the regional transmission plan for purposes of cost
allocation; and (3) seek to maximize benefits to consumers over time
without over-building transmission facilities.\2036\ The Commission
noted that, to comply with the Order Nos. 890 and 1000 transmission
planning principles, the evaluation process must result in a
determination that is sufficiently detailed for stakeholders to
understand why a particular transmission facility was selected or not
selected in the regional transmission plan for purposes of cost
allocation to address transmission needs driven by changes in the
resource mix and demand.\2037\ The Commission stated that the
evaluation process and, specifically, the selection criteria, must seek
to maximize benefits to consumers over time without over-building
transmission facilities.\2038\
---------------------------------------------------------------------------
\2036\ NOPR, 179 FERC ] 61,028 at PP 241-242, 245.
\2037\ Id. P 242 (citing Order No. 1000, 136 FERC ] 61,051 at P
328).
\2038\ Id.
---------------------------------------------------------------------------
928. The Commission stated that providing flexibility to propose
selection criteria would allow transmission providers, in consultation
with their stakeholders, to determine criteria for assessing the
efficiency or cost-effectiveness of various regional transmission
facilities, whether by reference, for example, to a benefit-cost ratio
or by aggregate net benefits.\2039\ The Commission also stated that
transmission providers would have the flexibility to propose to use a
portfolio approach in selecting regional transmission facilities that
address transmission needs driven by changes in the resource mix and
demand.\2040\ The Commission proposed to require transmission providers
that propose such an approach to include in their OATTs provisions
describing whether the selection criteria would apply to one proposed
regional transmission facility or to a portfolio of regional
transmission facilities, as well as whether the portfolio approach
would be used for Long-Term Regional Transmission Planning universally
to address transmission needs driven by changes in
[[Page 49428]]
the resource mix and demand or would be used only in certain specified
instances.\2041\
---------------------------------------------------------------------------
\2039\ Id. P 243.
\2040\ Id. P 249.
\2041\ Id.
---------------------------------------------------------------------------
929. The Commission recognized the inherent uncertainty involved in
predicting future transmission needs, including those driven by changes
in the resource mix and demand, as well as the concerns that many
commenters expressed in response to the ANOPR that imperfect
information may lead to selecting transmission facilities that become
stranded assets.\2042\ The Commission also stated that there are
selection criteria that transmission providers could adopt, following
consultation with stakeholders and with Relevant State Entities in
their transmission planning region's footprint, that could minimize
these risks while allowing for investment in transmission facilities
that more efficiently or cost-effectively meet transmission needs
driven by changes in the resource mix and demand.\2043\ The Commission
noted that under a ``least-regrets'' approach, for example,
transmission providers in a transmission planning region would select a
transmission facility (or portfolio of transmission facilities) that is
net-beneficial in most or all Long-Term Scenarios, even if other
transmission facilities have more net benefits or a higher benefit-cost
ratio in a single Long-Term Scenario. The Commission stated that
another approach is a ``weighted-benefits approach,'' in accordance
with which transmission providers in a transmission planning region
would select a transmission facility (or portfolio of regional
transmission facilities) based on its probability-weighted average
benefits, where probabilities have been assigned to each Long-Term
Scenario studied.\2044\
---------------------------------------------------------------------------
\2042\ Id. P 251.
\2043\ Id.
\2044\ Id. (citing Brattle-Grid Strategies Oct. 2021 Report at
59-60).
---------------------------------------------------------------------------
b. Comments
930. Commenters make a wide variety of arguments with respect to
the minimum requirements that the Commission should impose with respect
to evaluation processes and selection criteria. Many commenters support
the Commission's proposal to require that selection criteria: (1) be
transparent and not unduly discriminatory; (2) aim to ensure that more
efficient or cost-effective transmission facilities are selected in the
regional transmission plan for purposes of cost allocation to address
transmission needs driven by changes in the resource mix and demand;
and (3) seek to maximize benefits to consumers over time without over-
building transmission facilities.\2045\
---------------------------------------------------------------------------
\2045\ See ACEG Initial Comments at 58-59; ACORE Initial
Comments at 14; Amazon Initial Comments at 9; APPA Initial Comments
at 33-34; CARE Coalition Initial Comments at 11-12; NESCOE Initial
Comments at 46; NRECA Initial Comments at 25; [Oslash]rsted Initial
Comments at 5-6; Pacific Northwest State Agencies Initial Comments
at 19; PPL Initial Comments at 17-18; TAPS Initial Comments at 16.
---------------------------------------------------------------------------
931. Some commenters generally support the Commission's proposal
with certain modifications. For example, Ameren argues that requiring
selection criteria to maximize benefits to consumers over time without
over-building transmission facilities is highly subjective, because
such a requirement could refer to maximizing gross or net benefits and
because certain interpretations could override the consideration of
costs.\2046\ Vistra likewise argues that the directive to maximize
benefits to consumers over time without over-building transmission
facilities is unhelpfully vague and that maximizing benefits should not
be understood to disregard costs.\2047\ WATT Coalition states that the
Commission should require maximization of net benefits and cautions
that it would be unjust and unreasonable to ignore benefits or costs in
the assessment of options.\2048\
---------------------------------------------------------------------------
\2046\ Ameren Initial Comments at 20 (citing NOPR, 179 FERC ]
61,028 at P 243 n.390).
\2047\ Vistra Initial Comments at 17-18.
\2048\ WATT Coalition Initial Comments at 9.
---------------------------------------------------------------------------
932. GridLab argues that selection criteria should seek to manage
uncertainty and risk, stating that the Commission should clarify that
the criteria must address not only the risk of over-building but also
of under-building transmission.\2049\ In contrast, New York State
Department argues that selection criteria should be designed to
minimize the financial risk to ratepayers of over-building the
transmission system.\2050\ NYISO requests clarification on the
definition of over-building and argues that the final order should
provide additional guidance on how transmission planning regions should
address this risk. NYISO contends that the final order should treat the
risk of over-building as an additional qualitative criterion that
transmission planning regions should consider, as informed by open and
transparent stakeholder review.\2051\
---------------------------------------------------------------------------
\2049\ GridLab Initial Comments at 19.
\2050\ New York State Department Initial Comments at 4.
\2051\ NYISO Initial Comments at 43.
---------------------------------------------------------------------------
933. EEI contends that it is appropriate for the Commission to
provide guidance by providing non-mandatory factors for transmission
planning regions to consider.\2052\ ELCON argues that transparency with
respect to selection criteria requires that the criteria and their
proper weighting must be clear and easily accessible to consumers
through transmission providers' OASIS and OATT.\2053\
---------------------------------------------------------------------------
\2052\ EEI Initial Comments at 45-46.
\2053\ ELCON Initial Comments at 17.
---------------------------------------------------------------------------
934. Commenters make several arguments with respect to the metrics
that the Commission should allow or require transmission providers to
use when evaluating whether to select Long-Term Regional Transmission
Facilities. For example, some commenters argue that transmission
providers should select transmission facilities by using metrics that
seek to maximize net benefits instead of ones that rely on benefit-cost
ratios.\2054\ ACEG argues that the Commission can require metrics that
seek to maximize net benefits using the same authority it relied upon
in promulgating Order No. 1000.\2055\
---------------------------------------------------------------------------
\2054\ ACEG Initial Comments at 49-50; Breakthrough Energy
Initial Comments at 23; Clean Energy Associations Initial Comments
at 22; DC and MD Offices of People's Counsel Initial Comments at 33;
Evergreen Action Initial Comments at 4; ITC Initial Comments at 25;
WATT Coalition Initial Comments at 9.
\2055\ See ACEG Initial Comments at 49-50 (citing S.C. Pub.
Serv. Auth. v. FERC, 762 F.3d at 58).
---------------------------------------------------------------------------
935. Breakthrough Energy states that, while metrics such as
benefit-cost ratios are useful indicators, the efficient solution is
the one that maximizes net benefits.\2056\ WATT Coalition contends
that, in Australia, the transmission planner lists all transmission
facility alternatives ranked by the net present value of the consumer
benefits that the alternatives would provide, and selects the option
that provides the most benefits in the absence of a compelling reason
not to do so.\2057\
---------------------------------------------------------------------------
\2056\ Breakthrough Energy Initial Comments at 23.
\2057\ WATT Coalition Initial Comments at 9.
---------------------------------------------------------------------------
936. MISO argues that selection criteria should maximize long-term
transmission value, defined as the difference between total benefits
and total costs on a present value basis over a pre-determined
transmission planning horizon.\2058\ MISO contends that using such a
metric is important when benefit-cost ratios are high and transmission
expansion is substantial, as many of the benefits provided by new
transmission facilities are difficult to quantify in terms of dollars
despite providing significant qualitative benefits.\2059\ Relatedly,
CTC Global argues that selecting transmission facilities with the
lowest capital costs is no longer a best
[[Page 49429]]
practice, in light of increased debate in many RTOs/ISOs about issues
such as mandated resource mixes, compensation in capacity markets,
transmission planning criteria and cost allocation, and carbon
taxes.\2060\ CTC Global asserts that, if a transmission project is
selected with least capital cost as a selection criterion, consumers
will pay higher energy costs and higher total costs than what they
would pay if the Commission were to require transmission providers to
evaluate the NOPR's proposed benefits as well as cost.\2061\
---------------------------------------------------------------------------
\2058\ MISO Initial Comments at 55-56.
\2059\ Id.
\2060\ CTC Global Initial Comments at 6-7 (citing State
Voluntary Agreements to Plan and Pay for Transmission Facilities,
175 FERC ] 61,225 (2021) (Christie, Comm'r, concurring at PP 4-5)).
\2061\ Id. at 9.
---------------------------------------------------------------------------
937. Commenters also offer a variety of perspectives regarding
benefit-cost ratios. Clean Energy Associations recommend that, if the
Commission continues to allow benefit-cost ratios, such ratios not
exceed Order No. 1000's maximum allowable benefit-cost ratio of 1.25-
to-1.00.\2062\ ITC argues that, if the Commission allows transmission
providers to use benefit-cost ratios, it should require the use of a
1.00-to-1.00 benefit-cost ratio for the evaluation of candidate
portfolios.\2063\ Cypress Creek asserts that the Commission should
retain the maximum permitted benefit-cost ratio of 1.25-to-1.00 and
consider lowering that threshold to 1.00-to-1.00 because a transmission
facility with a benefit-cost ratio of at least 1.00-to-1.00 is
beneficial.\2064\
---------------------------------------------------------------------------
\2062\ Clean Energy Associations Initial Comments at 22.
\2063\ ITC Initial Comments at 25-26.
\2064\ See Cypress Creek Reply Comments at 8 & n.14 (citing
Order No. 1000, 136 FERC ] 61,051 at P 646).
---------------------------------------------------------------------------
938. Pattern Energy argues that the existing maximum 1.25-to-1.00
allowable benefit-cost ratio is too high for purposes of Long-Term
Regional Transmission Planning. Pattern Energy explains that scenarios
and sensitivities typically are created to bookend what the future may
look like, and those bookends are often weighted lower than a
``business as usual'' scenario. In this context, Pattern Energy argues
that a lower benefit-to-cost ratio is necessary because the standard to
approve transmission facilities is so high that transmission ratepayers
are not receiving an appropriate opportunity to realize the value of
new transmission infrastructure. Pattern Energy suggests that a more
reasonable benefit-cost ratio would be 1.10-to-1.00 but notes that a
higher benefit-to-cost ratio may be appropriate to evaluate a portfolio
of transmission facilities (e.g., 1.15-1.25).\2065\
---------------------------------------------------------------------------
\2065\ Pattern Energy Initial Comments at 14-15.
---------------------------------------------------------------------------
939. By contrast, New York State Department asserts that
transmission providers should not select a transmission facility unless
benefits in the long term greatly exceed costs and that adopting a much
higher benefit-cost ratio than the existing 1.25 standard may be
required (e.g., 2.25-to-1.00).\2066\
---------------------------------------------------------------------------
\2066\ New York State Department Initial Comments, Montalvo Aff.
at 14-15.
---------------------------------------------------------------------------
940. Some commenters express support for least-regrets \2067\ or
weighted-benefits approaches \2068\ to selecting transmission
facilities in Long-Term Regional Transmission Planning. For example,
National Grid argues that identifying least-regrets transmission
facilities should be the goal of Long-Term Regional Transmission
Planning.\2069\
---------------------------------------------------------------------------
\2067\ See Avangrid Initial Comments at 10-11; Eversource
Initial Comments at 26-27; Exelon Initial Comments at 18; GridLab
Initial Comments at 19-20; National Grid Initial Comments at 11-12;
NRECA Initial Comments at 48; PG&E Initial Comments at 6.
\2068\ See ACORE Initial Comments at 14 (citing Brattle-Grid
Strategies Oct. 2021 Report at 59-60; Derek Stenclik and Ryan Deyoe,
Multi-Value Transmission Planning for a Clean Energy Future: A
Report of the Transmission Benefits Valuation Task Force, Energy
Systems Integration Group, 37 (June 2022), https://www.esig.energy/wp-content/uploads/2022/07/ESIG-Multi-Value-Transmission-Planning-report-2022a.pdf) (Energy Systems Integration Group June 2022
Report)); Clean Energy Associations Initial Comments at 22 (citing
NOPR, 179 FERC ] 61,028 at P 251).
\2069\ National Grid Initial Comments at 11-12 (citing National
Grid ANOPR Initial Comments at 16).
---------------------------------------------------------------------------
941. Avangrid explains that ``no regrets'' or ``low regrets''
transmission facilities are those that likely will be needed under
multiple scenarios and a broad range of assumptions.\2070\ PG&E agrees
and argues that these transmission facilities are most likely to
realize projected benefits.\2071\ PG&E states that transmission
facilities that provide more limited benefits or benefits under a
limited number of scenarios may require additional study and should not
be selected until there is more certainty that their benefits will be
realized.\2072\
---------------------------------------------------------------------------
\2070\ Avangrid Initial Comments at 10-11.
\2071\ PG&E Initial Comments at 6.
\2072\ Id.
---------------------------------------------------------------------------
942. Exelon also advocates for a least-regrets approach, arguing
that it minimizes risk and maximizes value for customers and
transmission owners.\2073\ Eversource contends that a least-regrets
approach is most likely to build the consensus among stakeholders that
can support transmission facilities through planning, financing,
siting, and cost allocation.\2074\ NRECA argues that a least-regrets
approach will help mitigate the risk that consumers will pay for
unnecessary transmission facilities.\2075\
---------------------------------------------------------------------------
\2073\ Exelon Initial Comments at 18.
\2074\ Eversource Initial Comments at 26-27.
\2075\ NRECA Initial Comments at 48.
---------------------------------------------------------------------------
943. ACORE recommends the use of a weighted-benefits approach,
which ACORE argues has been endorsed in recent expert reports on
transmission planning.\2076\ Dominion sees promise in both least-
regrets and weighted-benefits approaches but argues that requiring
transmission providers to propose specific selection criteria may
result in litigation, delay, and increased costs.\2077\
---------------------------------------------------------------------------
\2076\ ACORE Initial Comments at 14 (citing Brattle-Grid
Strategies Oct. 2021 Report at 59-60; Energy Systems Integration
Group June 2022 Report at 37).
\2077\ See Dominion Initial Comments at 38.
---------------------------------------------------------------------------
944. New England for Offshore Wind argues that the Commission
should require transmission providers to give preference to
transmission facilities that perform well under a range of
scenarios.\2078\ A number of commenters caution, however, that the
Commission should allow transmission providers to select transmission
facilities even where they are not net-beneficial in every Long-Term
Scenario.\2079\
---------------------------------------------------------------------------
\2078\ New England for Offshore Wind Initial Comments at 2; see
also Clean Energy Associations Initial Comments at 22 (arguing for
selecting transmission facilities that maximize net benefits across
multiple scenarios).
\2079\ ACEG Initial Comments at 7, 30; ACORE Initial Comments at
14; Evergreen Action Initial Comments at 4; Pine Gate Initial
Comments at 37-38.
---------------------------------------------------------------------------
945. A number of commenters recommend accounting for siting
considerations in various ways in the selection of transmission
facilities. For example, CARE Coalition recommends that the Commission
require transmission providers to work with state authorities and other
stakeholders to develop environmental- and energy justice-based siting
criteria to guide transmission project selection and cost
allocation.\2080\ CARE Coalition also states that the Commission should
allow RTOs/ISOs to take a flexible approach to identifying siting-based
criteria that consider local and regional impacts, local and regional
energy justice impacts (including use of existing transmission
corridors and investment flow to disadvantaged communities as defined
by the President's Justice40 Initiative), integration with plans for
energy storage, and integration with major infrastructure development
plans (e.g., highways, rail corridors).\2081\ CARE Coalition states
that planners and stakeholders should consider the
[[Page 49430]]
economic, environmental, and other impacts associated with the full
expected useful lives of proposed transmission and associated
facilities.\2082\
---------------------------------------------------------------------------
\2080\ CARE Coalition Initial Comments at 7-8.
\2081\ Id. at 10.
\2082\ Id.
---------------------------------------------------------------------------
946. Similarly, ACEG recommends selection criteria that account for
whether potential transmission facilities use existing rights-of-way,
contribute to equitable energy service, alleviate environmental justice
concerns, or impact employment and economic development.\2083\ Exelon
also recommends giving preference to approaches that prioritize
existing rights-of-way, given that they are more readily accomplished
and have fewer environmental impacts than greenfield transmission
projects.\2084\
---------------------------------------------------------------------------
\2083\ ACEG Initial Comments at 59.
\2084\ Exelon Initial Comments at 18.
---------------------------------------------------------------------------
947. Acadia Center and CLF urge the Commission to provide
transmission providers clear guidance, by adopting minimum selection
criteria in the final order, on their ability to consider factors such
as environmental justice, mitigating environmental impacts, use of
existing transmission facilities, and non-transmission alternatives,
which have community and environmental benefits. Acadia Center and CLF
contend that the consideration of these issues is consistent with NEPA,
the FPA, and state law, and that, in the absence of such guidance,
transmission providers may continue to exclude consideration of these
issues given concerns regarding their authority and jurisdiction to do
so.\2085\ Grand Rapids NAACP also argues that the Commission has the
authority to require that transmission providers explicitly incorporate
energy equity and justice concerns into selection criteria, and that
the Commission should do so in a final order.\2086\ WE ACT states that
equity considerations and other non-energy benefits (e.g., pollution
reduction, health, jobs, and local economic development) should be
among the benefits that transmission providers could use in selecting
transmission facilities.\2087\ PIOs assert that the Commission should
require transmission providers to consider equity impacts when
determining which transmission facilities to select, including whether
construction of such facilities will impact environmental justice
communities and what the cumulative impacts of the facilities will
be.\2088\
---------------------------------------------------------------------------
\2085\ Acadia Center and CLF Initial Comments at 11-12.
\2086\ Grand Rapids NAACP Initial Comments at 17-23 (citations
omitted).
\2087\ WE ACT Initial Comments at 5.
\2088\ PIOs Reply Comments at 17 (citations omitted).
---------------------------------------------------------------------------
948. DC and MD Offices of People's Counsel suggest that
transmission providers should select transmission facilities that
optimize the interconnection of portfolios of generation resources,
including those that deliver benefits arising from grid decarbonization
and the benefits set forth in the NOPR.\2089\ Eversource argues that
the Commission should consider requiring transmission providers to
address needs identified in high-impact, low-frequency event scenarios,
such that selection criteria would accommodate worst-case scenarios
like Winter Storm Uri.\2090\ Exelon urges that selection criteria be
tied to well-established and defined needs, like reliability and market
economics, such as reduced production costs, congestion, or capacity
costs.\2091\
---------------------------------------------------------------------------
\2089\ DC and MD Offices of People's Counsel Initial Comments at
38-39.
\2090\ Eversource Initial Comments at 26-27 (citing FERC, North
American Electric Reliability Corporation, Regional Entity Staff
Report, The February 2021 Cold Weather Outages in Texas, and the
South-Central United States (Nov. 2021), https://www.ferc.gov/media/february-2021-cold-weather-outages-texas-and-south-central-united-states-ferc-nerc-and).
\2091\ Exelon Initial Comments at 18.
---------------------------------------------------------------------------
949. Duke asserts that selection of a transmission facility in the
absence of clear consensus from load-serving entities, states, and/or
customers would be problematic and thwart the Commission's objectives,
especially where certain transmission facilities will not be supported
by state commissions in siting decisions or by consumer advocates in
cost recovery proceedings.\2092\ As such, Duke argues that the
Commission should allow transmission providers to include a qualitative
selection criterion of whether there is state and consumer support for
a particular Long-Term Regional Transmission Facility or portfolio of
facilities.\2093\ New York TOs state that New York Commission should
retain its flexibility under NYISO's public policy transmission
planning process such that, when the New York Commission identifies a
transmission need driven by Public Policy Requirements, it can also
require certain selection criteria in addition to those in NYISO's
OATT.\2094\
---------------------------------------------------------------------------
\2092\ Duke Initial Comments at 26-27.
\2093\ Id. at 4, 26-27.
\2094\ New York TOs Initial Comments at 9, 11-12, 15.
---------------------------------------------------------------------------
950. NYISO contends that the final order should continue to allow
transmission providers to use a range of qualitative and quantitative
criteria to rank and select transmission projects as the more efficient
or cost-effective transmission facility.\2095\ ACEG encourages the
Commission to provide guidance in the final order as to selection
criteria that meet its requirements, arguing that doing so would
facilitate efficient compliance proceedings.\2096\
---------------------------------------------------------------------------
\2095\ NYISO Initial Comments at 39-40.
\2096\ ACEG Initial Comments at 59.
---------------------------------------------------------------------------
951. Maine Public Advocate also argues that the Commission should
require transmission providers to select non-transmission alternatives
when they meet an identified transmission need at the same or lower
cost.\2097\
---------------------------------------------------------------------------
\2097\ Maine Public Advocate Initial Comments at 1-2.
---------------------------------------------------------------------------
952. TAPS asserts that the Commission should require transmission
providers to explain how their selection criteria would account for the
uncertainty involved in predicting future transmission needs and to
report ``Affordability Metrics'' that disclose the impact that
selection of a particular transmission facility would have on
transmission rates.\2098\ TAPS argues that these ``Affordability
Metrics'' would enhance the transparency of stakeholder processes in
Long-Term Regional Transmission Planning and assist states in
discussions about cost allocation and in considering whether to
voluntarily fund a particular transmission facility or portfolio of
transmission facilities.\2099\
---------------------------------------------------------------------------
\2098\ TAPS Initial Comments at 16-17.
\2099\ Id. at 19-20 (citing Alliant Energy, et al., ANOPR
Initial Comments at 14; Alliant Energy, et al., ANOPR Reply Comments
at 2-3).
---------------------------------------------------------------------------
953. ELCON states that, given the potential for massive
transmission investment in the next 10 to 25 years, it is vitally
important that consumers be protected from any unnecessary costs.\2100\
As such, ELCON argues that selection criteria must incorporate metrics
for reliability and economic efficiency, incorporate all potential
drivers of transmission needs, and afford greater weight to those
transmission facilities that produce benefits in more than one
category.\2101\
---------------------------------------------------------------------------
\2100\ ELCON Initial Comments at 16 (citing Eric Larson et al.,
Net-Zero America: Potential Pathways, Infrastructure, and Impacts,
Net Zero America, 108 (Oct. 29, 2021), https://www.dropbox.com/s/ptp92f65lgds5n2/Princeton%20NZA%20FINAL%20REPORT%20%2829Oct2021%29.pdf?dl=0).
\2101\ Id.
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[[Page 49431]]
c. Commission Determination
i. Transparent and Not Unduly Discriminatory; More Efficient or Cost-
Effective Transmission Facilities
954. We adopt the NOPR proposal, with modification, to require
transmission providers in each transmission planning region to propose
evaluation processes, including selection criteria, that are
transparent and not unduly discriminatory. Consistent with Order No.
1000,\2102\ we adopt the NOPR proposal to establish a requirement that
transmission providers' evaluation of transmission facilities must
culminate in a determination that is sufficiently detailed for
stakeholders to understand why a particular Long-Term Regional
Transmission Facility (or portfolio of such Facilities) was selected or
not selected. As discussed further below, we modify the NOPR proposal
to include a requirement that the determination of why a particular
Long-Term Regional Transmission Facility (or portfolio of such
Facilities) was selected or not selected must include the measured
benefits for each alternative Long-Term Regional Transmission Facility
(or portfolio of such Facilities) considered in the Long-Term Regional
Transmission Planning process.
---------------------------------------------------------------------------
\2102\ Order No. 1000, 136 FERC ] 61,051 at P 328.
---------------------------------------------------------------------------
955. We also adopt the NOPR proposal, with modification, to require
transmission providers to propose on compliance evaluation processes,
including selection criteria, that aim to ensure that more efficient or
cost-effective Long-Term Regional Transmission Facilities are selected
to address Long-Term Transmission Needs. We modify the NOPR proposal to
provide additional clarity as to how transmission providers' evaluation
processes must aim to ensure the selection of more efficient or cost-
effective Long-Term Regional Transmission Facilities to address Long-
Term Transmission Needs by adopting several requirements. First,
transmission providers in a transmission planning region must identify
one or more Long-Term Regional Transmission Facilities (or portfolio of
such Facilities) that address the Long-Term Transmission Needs that the
transmission providers have identified through Long-Term Regional
Transmission Planning. As part of this identification, consistent with
Order Nos. 890 and 1000,\2103\ nonincumbent transmission developers
must be able to propose transmission facilities in Long-Term Regional
Transmission Planning. Thus, we clarify that transmission providers in
each transmission planning region must make clear in their OATTs the
point in the Long-Term Regional Transmission Planning evaluation
process at which they will accept Long-Term Regional Transmission
Facility proposals from stakeholders, including nonincumbent
transmission developers. Second, transmission providers' evaluation
processes must estimate the costs and measure the benefits of the Long-
Term Regional Transmission Facilities (or portfolio of such Facilities)
that are identified or proposed for potential selection, in addition to
evaluating the identified Long-Term Regional Transmission Facilities
(or portfolio of such Facilities) using any qualitative or other
quantitative selection criteria that the transmission providers in a
transmission planning region propose to apply. Third, transmission
providers must designate a point in the evaluation process at which
transmission providers will determine whether to select or not select
identified Long-Term Regional Transmission Facilities (or portfolio of
such Facilities).\2104\ This point must be no later than three years
following the beginning of the Long-Term Regional Transmission Planning
cycle.\2105\ Finally, the evaluation process must culminate in
determinations that are sufficiently detailed for stakeholders to
understand why a particular Long-Term Regional Transmission Facility
(or portfolio of such Facilities) was selected or not selected. We
reiterate, however, that, as discussed further below in the No
Selection Requirement section, this final order does not require
transmission providers to select any particular Long-Term Regional
Transmission Facility (or portfolio of such Facilities) to address
Long-Term Transmission Needs.
---------------------------------------------------------------------------
\2103\ See id. P 315 (citing Order No. 890, 118 FERC ] 61,119 at
P 494; Order No. 890-A, 121 FERC ] 61,297 at PP 215-216).
\2104\ As described further below in the Voluntary Funding
Opportunities section, transmission providers must also provide
Relevant State Entities with the opportunity to fund the cost of, or
part of the cost of, the Long-Term Regional Transmission Facility
(or portfolio of such Facilities) to ensure that it meets the
transmission providers' selection criteria.
\2105\ We note, however, consistent with the discussion above in
the Frequency of Long-Term Scenario Revisions section, that
transmission providers may evaluate and select additional Long-Term
Regional Transmission Facilities during the period of the Long-Term
Regional Transmission Planning cycle after this point and before the
commencement of the next such cycle.
---------------------------------------------------------------------------
956. As discussed earlier, this final order requires transmission
providers to develop and use at least three Long-Term Scenarios, and
one sensitivity analysis applied to each Long-Term Scenario, when
conducting Long-Term Regional Transmission Planning. Each Long-Term
Scenario or sensitivity analysis may suggest that different Long-Term
Transmission Needs exist, that different Long-Term Regional
Transmission Facilities would resolve those needs, or that such Long-
Term Regional Transmission Facilities would provide different benefits
for transmission customers. We clarify that, in the context of Long-
Term Regional Transmission Planning, Order No. 890's requirements that
transmission providers conduct coordinated, open, and transparent
transmission planning on the regional level \2106\ requires that
transmission providers make transparent the methods that they used to
analyze each individual Long-Term Scenario and the sensitivity or
sensitivities applied to each scenario to determine the Long-Term
Transmission Needs that exist in the transmission planning region, the
Long-Term Regional Transmission Facilities that would resolve those
needs, and the benefits of those Long-Term Regional Transmission
Facilities for purposes of selection.\2107\
---------------------------------------------------------------------------
\2106\ Order No. 890, 118 FERC ] 61,119 at P 435.
\2107\ For example, transmission providers might weigh specific
Long-Term Scenarios and sensitivities based on the probability that
the analyses reflect future system conditions (which the Commission
referred to in the NOPR as a ``weighted-benefits approach''). NOPR,
179 FERC ] 61,028 at P 251 (citing Brattle-Grid Strategies Oct. 2021
Report at 59-60).
---------------------------------------------------------------------------
957. Consistent with the Order No. 1000 regional transmission
planning requirements,\2108\ the Long-Term Regional Transmission
Planning process must result in a regional transmission plan that
identifies the Long-Term Regional Transmission Facilities that more
efficiently or cost-effectively meet the transmission planning region's
Long-Term Transmission Needs. To effectuate this requirement, we
clarify that transmission providers have an affirmative obligation to
identify Long-Term Regional Transmission Facilities that more
efficiently or cost-effectively address Long-Term Transmission Needs,
regardless of whether any stakeholder proposes potential Long-Term
Regional Transmission Facilities for consideration in Long-Term
Regional Transmission Planning. In this section, we enumerate specific
requirements for how transmission providers conduct their Long-Term
Regional Transmission Planning with the aim to ensure that more
efficient or cost-effective Long-Term Regional Transmission Facilities
[[Page 49432]]
are selected. By clearly enumerating their evaluation processes and
selection criteria in their OATTs, transmission providers will provide
significant transparency to stakeholders to understand how Long-Term
Transmission Needs will be addressed, whether there are more efficient
or cost-effective Long-Term Regional Transmission Facilities that may
meet those needs, and their benefits.
---------------------------------------------------------------------------
\2108\ Order No. 1000, 136 FERC ] 61,051 at PP 55, 146-148; see
Louisville Gas & Elec. Co., 144 FERC ] 61,054, at PP 61-62 (2013),
on reh'g sub nom., Duke Energy Carolinas LLC, 147 FERC ] 61,241, at
PP 82-83 (2014).
---------------------------------------------------------------------------
958. Provided that transmission providers' evaluation processes and
selection criteria comply with the requirements that we adopt here, we
provide transmission providers with flexibility to determine how they
will evaluate whether Long-Term Regional Transmission Facilities more
efficiently or cost-effectively address Long-Term Transmission Needs,
including by using benefit-cost ratios, assessing their net benefits
and selecting the Long-Term Regional Transmission Facilities that
maximize those benefits, and/or using some other method.\2109\
Consistent with Order No. 1000 regional cost allocation principle (3),
and as further discussed below in the Regional Transmission Cost
Allocation section, transmission providers may not impose as a
selection criterion a minimum benefit-cost ratio that is higher than
1.25-to-1.00.\2110\ We decline to reduce or increase the maximum
benefit-cost ratio that transmission providers may use as a selection
criterion in Long-Term Regional Transmission Planning. As the
Commission found in Order No. 1000,\2111\ requiring that a benefit-cost
ratio, if adopted, not exceed 1.25-to-1.00 ensures that the ratio is
not so high as to exclude Long-Term Regional Transmission Facilities
with significant positive net benefits from selection.
---------------------------------------------------------------------------
\2109\ Nothing in this final order requires the use of any
particular approach, and we clarify that transmission providers may
use more than one approach complementarily. Compare, e.g., MISO
Initial Comments at 54-56 (explaining MISO's approach to selecting
transmission facilities with the goal of maximizing ``long-term
transmission value''), with MISO, FERC Electric Tariff, MISO OATT,
attach. FF, Transmission Expansion Planning Protocol (90.0.0),
sections II.B.1.c, II.C.2.b (setting forth as a minimum selection
criterion a benefit-cost ratio of 1.25 or 1.00 for Market Efficiency
Projects and Multi-Value Projects, respectively).
\2110\ NOPR, 179 FERC ] 61,028 at P 243 n.390; Order No. 1000,
136 FERC ] 61,051 at P 646.
\2111\ Order No. 1000, 136 FERC ] 61,051 at P 648.
---------------------------------------------------------------------------
959. We decline to require transmission providers to account for
siting considerations in their evaluation process and selection
criteria.\2112\ We acknowledge that siting considerations (e.g., use of
existing rights-of-way) may affect the costs, timeline, or feasibility
of developing a Long-Term Regional Transmission Facility. While such
siting considerations may inform the evaluation process and selection
criteria, we do not require transmission providers to account for such
considerations in this final order. We note, however, that, as
discussed below in the Role of Relevant State Entities section, this
final order requires that transmission providers consult with and seek
the support of Relevant State Entities \2113\ regarding the evaluation
process and selection criteria that transmission providers propose to
use to evaluate Long-Term Regional Transmission Facilities for
selection.
---------------------------------------------------------------------------
\2112\ CARE Coalition Initial Comments at 7-8; see also ACEG
Initial Comments at 59; Exelon Initial Comments at 18.
\2113\ Many Relevant State Entities exercise their state's
authority over the siting of transmission facilities.
---------------------------------------------------------------------------
960. We also do not require transmission providers to include
environmental justice or equity considerations in their evaluation
process or selection criteria. While several commenters recommend that
we impose such requirements,\2114\ none provides any approach for how
these concerns would be incorporated into transmission providers'
evaluation process and selection criteria on a generic basis. We
acknowledge that the selection of Long-Term Regional Transmission
Facilities represents a substantial step in the development of new
electric transmission infrastructure, which may impact environmental
justice communities or raise equity concerns. We further recognize that
such environmental justice or equity considerations may affect the
costs, timeline, or feasibility of developing a Long-Term Regional
Transmission Facility, particularly in regions where legal frameworks
provide for consideration of environmental justice and equity. Nothing
in this final order precludes transmission providers from proposing on
compliance to include environmental justice considerations within their
evaluation process and selection criteria.
---------------------------------------------------------------------------
\2114\ See, e.g., Acadia Center and CLF Initial Comments at 11-
12; Grand Rapids NAACP Initial Comments at 17-23 (citations
omitted); PIOs Reply Comments at 17 (citations omitted).
---------------------------------------------------------------------------
961. NYISO requests that the Commission clarify that transmission
providers may continue to use qualitative and quantitative measures in
the Long-Term Regional Transmission Planning process.\2115\ We clarify
that nothing in this final order prohibits transmission providers from
proposing to use qualitative factors in their evaluation processes and/
or selection criteria. Accordingly, transmission providers may propose
to use qualitative factors in their evaluation processes and/or
qualitative selection criteria, provided that they demonstrate on
compliance that their proposals comply with the evaluation process and
selection criteria requirements of this final order.
---------------------------------------------------------------------------
\2115\ NYISO Initial Comments at 39-40.
---------------------------------------------------------------------------
962. In response to Duke's request to allow transmission providers
to include a selection criterion that is a qualitative evaluation of
whether there is state and consumer support for a particular Long-Term
Regional Transmission Facility or portfolio of such Facilities,\2116\
we find that transmission providers may not include in their evaluation
process or selection criteria any prohibition on the selection of a
Long-Term Regional Transmission Facility based on the transmission
providers' anticipated response of a state public utility commission or
consumer advocates to particular Long-Term Regional Transmission
Facilities. Rather than address this issue via selection criteria
regarding a transmission provider's anticipation of such an entity's
response, we conclude that the requirement discussed below to consult
with and seek support from Relevant State Entities regarding the
evaluation process and selection criteria is a more appropriate
mechanism to account for the Relevant State Entity's views. We also
note that beyond this consultative process, state public utility
commissions and consumer advocates have numerous opportunities to
express their views on transmission development, including through
state- and Commission-jurisdictional proceedings. Further, allowing
such features in evaluation processes or selection criteria could
amount to a requirement that transmission providers obtain the consent
of Relevant State Entities, which, as discussed below in the Role of
Relevant State Entities section, we do not believe is necessary or
appropriate to resolve the deficiencies identified in this final
order.\2117\
---------------------------------------------------------------------------
\2116\ Duke Initial Comments at 4, 26-27.
\2117\ See New York v. FERC, 535 U.S. at 26-28 (upholding
Commission's decision not to assert jurisdiction over bundled retail
transmission).
---------------------------------------------------------------------------
963. In response to New York TOs,\2118\ we decline to require that
transmission providers include selection criteria requested by state
public utility commissions. As discussed further below in the Role of
Relevant State Entities section, transmission providers must propose on
compliance an evaluation process and selection criteria that comply
with the
[[Page 49433]]
requirements of this final order after consulting with and seeking the
support of Relevant State Entities. To the extent that a transmission
provider believes that a selection criterion proposed by a Relevant
State Entity would comply with the final order requirements, they may
propose to include that criterion in their compliance filings, and the
Commission will determine if it complies with these requirements.
---------------------------------------------------------------------------
\2118\ New York TOs Initial Comments at 9, 11-12, 15.
---------------------------------------------------------------------------
ii. Maximize Benefits
964. We adopt the NOPR proposal, with modification, to require that
transmission providers in each transmission planning region propose
evaluation processes, including selection criteria, that seek to
maximize benefits accounting for costs over time without over-building
transmission facilities. In the NOPR, the Commission proposed that the
evaluation processes and selection criteria seek to maximize benefits
to consumers over time without over-building transmission facilities.
However, we believe that it is appropriate to modify that proposal for
clarity. We modify the requirement to require that transmission
providers' evaluation processes and selection criteria seek to maximize
benefits accounting for costs. Some commenters have interpreted the
NOPR as proposing to allow transmission providers to disregard costs
and simply maximize benefits.\2119\ We clarify that was not the
Commission's intent, and we modify the NOPR proposal in this final
order to make that clear. Further, we note that while we omit reference
``to consumers'' in the requirement for brevity, we do not view this
change as substantive. As discussed above, this requirement, together
with other aspects of this final order, helps to ensure transmission
providers identify, evaluate, and select Long-Term Regional
Transmission Facilities that more efficiently or cost-effectively
address Long-Term Transmission Needs in order to ensure just and
reasonable Commission-jurisdictional rates, which ultimately benefits
ratepayers.
---------------------------------------------------------------------------
\2119\ See, e.g., Ameren Initial Comments at 20 (citing NOPR,
179 FERC ] 61,028 at P 242); Vistra Initial Comments at 17-18; WATT
Coalition Initial Comments at 9.
---------------------------------------------------------------------------
965. As discussed in the Requirement for Transmission Providers to
Use a Set of Seven Required Benefits section, transmission providers
conducting Long-Term Regional Transmission Planning must use and
measure a set of benefits to evaluate Long-Term Regional Transmission
Facilities. In setting forth an evaluation process and selection
criteria, we clarify, consistent with the directive to seek to maximize
benefits accounting for costs over time without over-building
transmission facilities, that transmission providers may not disregard
benefits that we require them to use and measure when implementing
their approved evaluation process and selection criteria.\2120\ We
further clarify that transmission providers may not disregard benefits
even where those benefits are only measured in certain transmission
system conditions, such as may be the case with Benefit 6, Mitigation
of Extreme Weather Events and Unexpected System Conditions, and
therefore are captured only under certain Long-Term Scenarios or
sensitivities thereto. While transmission providers may not disregard
such benefits, transmission providers' evaluation processes and
selection criteria may account for the fact that certain benefits are
only measured under certain conditions by, for example, weighting how
likely certain conditions expressed in specific Long-Term Scenarios or
sensitivities are to occur.
966. As discussed further below, transmission providers have the
discretion to select or not select any Long-Term Regional Transmission
Facility that they identify through Long-Term Regional Transmission
Planning, even a facility that otherwise meets the selection criteria.
However, as noted above, the evaluation process must culminate in a
determination that is sufficiently detailed for stakeholders to
understand why a particular Long-Term Regional Transmission Facility
was selected or not selected to address Long-Term Transmission Needs.
We clarify that this determination must include the estimated costs and
measured benefits of each alternative Long-Term Regional Transmission
Facility (or portfolio of such Facilities) evaluated by the
transmission providers, whether or not the Long-Term Regional
Transmission Facility (or portfolio of such Facilities) is
selected.\2121\
---------------------------------------------------------------------------
\2121\ Where transmission providers employ a portfolio approach
to evaluating and selecting Long-Term Regional Transmission
Facilities, we require only that they include in such a
determination the measured benefits for the portfolio of Long-Term
Regional Transmission Facilities on an aggregate basis.
---------------------------------------------------------------------------
967. We acknowledge commenters' concerns that there is inherent
uncertainty in Long-Term Regional Transmission Planning.\2122\ This
final order adopts provisions that allow for significant flexibility
for transmission providers to address that uncertainty. As stated above
in the Participation in Long-Term Regional Transmission Planning
section, we require transmission providers to develop and use Long-Term
Scenarios, which are a critical tool for managing uncertainty and
facilitating regional transmission planning that account for a range of
potential futures, as well as an assessment of the likelihood of each
scenario manifesting, when identifying, evaluating, and selecting Long-
Term Regional Transmission Facilities. Further, transmission providers
could adopt evaluation processes and selection criteria that would
allow transmission providers to make selection decisions while
minimizing the future risk of developing a previously selected Long-
Term Regional Transmission Facility that is not the more efficient or
cost-effective regional transmission solution to Long-Term Transmission
Needs. For example, transmission providers might develop a least-
regrets approach under which they would select Long-Term Regional
Transmission Facilities in the regional transmission plan for purposes
of cost allocation if those Long-Term Regional Transmission Facilities
are net beneficial in more than one Long-Term Scenario and sensitivity
analyses even if other transmission facilities have a higher benefit-
cost ratio or provide more net benefits in a single Long-Term Scenario
or particular sensitivity. Transmission providers might also adopt a
weighted-benefits approach under which they would select a Long-Term
Regional Transmission Facility based on its probability-weighted
average benefits, where probabilities have been assigned to each Long-
Term Scenario or sensitivity thereof that is studied. Under either
approach, to maximize benefits accounting for costs over time without
over-building transmission facilities, transmission providers must
consider not only the risk that changing conditions might produce fewer
benefits than originally anticipated, but also that they might produce
more benefits than originally anticipated. Finally, as discussed below
in the Reevaluation section, we require transmission providers to
reevaluate certain selected Long-Term Regional Transmission Facilities
to determine whether they continue to meet the transmission providers'
selection criteria.
---------------------------------------------------------------------------
\2122\ See, e.g., GridLab Initial Comments at 19; TAPS Initial
Comments at 16-17.
---------------------------------------------------------------------------
968. While we acknowledge commenters' wide support for least-
regrets and weighted-benefits approaches to selecting Long-Term
Regional Transmission Facilities in Long-Term Regional Transmission
Planning, we decline to require
[[Page 49434]]
transmission providers to use either approach. However, we clarify that
transmission providers may not adopt an approach under which they would
not select a Long-Term Regional Transmission Facility unless it meets
their selection criteria in every Long-Term Scenario and sensitivity.
We are concerned that such an approach could impose a threshold for
selection that is so onerous it limits selection of most or all Long-
Term Regional Transmission Facilities, and, as such, is inconsistent
with the requirement that selection criteria seek to maximize benefits
accounting for costs over time without over-building transmission
facilities. We find that such an approach would not ensure that
transmission providers have the opportunity to select Long-Term
Regional Transmission Facilities to more efficiently or cost-
effectively address Long-Term Transmission Needs, an opportunity that
we find, as described in the Transparent and Not Unduly Discriminatory;
More Efficient or Cost-Effective Transmission Facilities section above,
is necessary to ensure just and reasonable Commission-jurisdictional
rates.
969. Again, we emphasize that this final order does not require
that transmission providers select any particular Long-Term Regional
Transmission Facility (or portfolio of such Facilities). Rather, this
final order simply requires transmission providers to adopt an
evaluation process and selection criteria that meet the minimum
requirements set forth in this final order, including that they aim to
maximize benefits accounting for costs over time without over-building
transmission facilities. In response to NYISO,\2123\ however, we
decline to clarify the definition of ``over-building,'' because doing
so would limit transmission providers' flexibility to assess what
constitutes over-building in their transmission planning region.
Transmission planning regions have a wide variety of market structures,
and numerous factors drive transmission needs, which may require
evaluation processes and selection criteria that maximize benefits
accounting for costs or guard against over-building in different ways.
We expect that evaluation processes and selection criteria that
maximize benefits accounting for costs over time without over-building
transmission facilities will include a variety of features, based on
their regional circumstances, that combine to ensure that transmission
providers give careful, informed consideration to Long-Term Regional
Transmission Facilities that more efficiently or cost-effectively
address Long-Term Transmission Needs. We also note that, in response to
CTC Global's concerns about the selection criteria being limited to
considering regional transmission facilities with the least capital
costs,\2124\ we clarify that both estimated benefits and costs must be
disclosed when evaluating a Long-Term Regional Transmission Facility
for selection and that transmission providers must adopt selection
criteria that seek to maximize benefits accounting for costs over time
without over-building transmission facilities.
---------------------------------------------------------------------------
\2123\ NYISO Initial Comments at 43.
\2124\ CTC Global Initial Comments at 9.
---------------------------------------------------------------------------
970. In response to Maine Public Advocate,\2125\ we decline to
require transmission providers to select non-transmission alternatives
where such non-transmission alternatives meet a Long-Term Transmission
Need at a lower cost than an alternative Long-Term Regional
Transmission Facility. The Commission did not propose to require
transmission providers to consider non-transmission alternatives for
potential selection in the NOPR, and we are not persuaded to do so in
this final order. We note, however, that transmission providers already
are required to consider non-transmission alternatives on a comparable
basis in regional transmission planning.\2126\
---------------------------------------------------------------------------
\2125\ Maine Public Advocate Initial Comments at 1-2.
\2126\ Order No. 1000, 136 FERC ] 61,051 at P 148.
---------------------------------------------------------------------------
971. Finally, in response to TAPS,\2127\ we decline to require
transmission providers to develop affordability metrics to provide
along with other information about a particular Long-Term Regional
Transmission Facility. The Commission did not propose such a
requirement in the NOPR, and we are not persuaded to adopt a
requirement for such metrics in this final order.
---------------------------------------------------------------------------
\2127\ TAPS Initial Comments at 16-17, 19-20 (citations
omitted).
---------------------------------------------------------------------------
4. Role of Relevant State Entities
a. NOPR Proposal
972. In the NOPR, the Commission proposed to require that
transmission providers, as part of their Long-Term Regional
Transmission Planning, include in their OATTs a process to coordinate
with the Relevant State Entities in developing selection
criteria.\2128\ Regarding this requirement, the Commission proposed to
require transmission providers to demonstrate on compliance that they
consulted with and sought support from the Relevant State Entities in
their transmission planning region's footprint to develop their
proposed selection criteria.\2129\
---------------------------------------------------------------------------
\2128\ NOPR, 179 FERC ] 61,028 at P 241.
\2129\ Id. P 246.
---------------------------------------------------------------------------
b. Comments
i. Support/Oppose
973. Many commenters support the Commission's proposal to require
transmission providers to consult with and seek support from Relevant
State Entities \2130\ and include in their OATTs a process to
coordinate with the Relevant State Entities \2131\ in developing
selection criteria. For example, ELCON argues that coordination with
Relevant State Entities in identifying selection criteria is critical
because it will promote cooperation and could result in more efficient
state siting and permitting processes.\2132\ Pennsylvania Commission
asserts that requiring consultation will provide states the opportunity
to influence regional transmission planning and cost allocation,
thereby promoting the public interest and reducing conflicts and
disputes on these matters.\2133\
---------------------------------------------------------------------------
\2130\ See ACEG Initial Comments at 59-60; Ameren Initial
Comments at 20; American Municipal Power Initial Comments at 12;
California Commission Initial Comments at 37; ELCON Initial Comments
at 17; Nebraska Commission Initial Comments at 8-9; North Carolina
Commission and Staff Initial Comments at 4-5; Pennsylvania
Commission Initial Comments at 10; PJM States Initial Comments at 3.
\2131\ See NARUC Initial Comments at 44; NESCOE Initial Comments
at 9-10, 46; Pacific Northwest State Agencies Initial Comments at
19; PJM States Initial Comments at 3.
\2132\ ELCON Initial Comments at 17.
\2133\ Pennsylvania Commission Initial Comments at 10.
---------------------------------------------------------------------------
974. ISO-NE supports the proposal to provide states with a greater
role in the selection of transmission facilities.\2134\ Further, ISO-NE
argues that, in the context of policy-based planning, states should be
responsible for determining whether to select transmission facilities,
with ISO-NE playing a supporting, technical role.\2135\ While NESCOE
supports the proposal that transmission providers must consult with and
seek support from Relevant State Entities within their transmission
planning region's footprint to develop selection criteria, NESCOE
requests that the Commission provide Relevant State Entities an
expanded role in the selection of transmission projects where the
project is identified as needed in response to state laws or policy
goals and require transmission providers to include such a role in
their OATTs.\2136\
---------------------------------------------------------------------------
\2134\ ISO-NE Initial Comments at 35.
\2135\ Id. NESCOE supports ISO-NE's position. NESCOE Reply
Comments at 5 & n.16.
\2136\ NESCOE Initial Comments at 9-10, 48-49.
---------------------------------------------------------------------------
[[Page 49435]]
975. PJM states that it also supports providing additional
opportunity for involvement by states and stakeholders in Long-Term
Regional Transmission Planning; however, in response to ISO-NE, PJM
urges the Commission to make clear that transmission providers retain
authority to select transmission facilities and argues that such role
is more than a ``technical supporting role.'' \2137\ PJM States contend
that an upfront and transparent process, with substantive state
involvement, will ensure that selection criteria are thoroughly
discussed by stakeholders and are consistent with the rest of Long-Term
Regional Transmission Planning.\2138\
---------------------------------------------------------------------------
\2137\ PJM Reply Comments at 35-36 (citing ISO-NE Initial
Comments at 16).
\2138\ PJM States Reply Comments at 8.
---------------------------------------------------------------------------
976. New York Commission and NYSERDA state that the Commission
should allow Relevant State Entities to be part of the decision-making
process regarding the appropriate timeframe for selecting a
transmission facility.\2139\
---------------------------------------------------------------------------
\2139\ New York Commission and NYSERDA Initial Comments at 12.
---------------------------------------------------------------------------
977. California Commission urges the Commission to require that
transmission providers indicate in their compliance filings whether the
selection criteria they propose are supported by the Relevant State
Entities and, if not, to explain any points of disagreement.\2140\ PJM
States argue that the Commission should, without dictating any
substantive outcomes, ``recognize the primacy of the role for retail
regulators'' in the final order.\2141\ By contrast, ACEG cautions that
transmission providers must balance all states' interests when
developing selection criteria instead of maximizing one state's
interest over another's.\2142\ NYISO states that each transmission
planning region should have flexibility to determine how it will
consult with and seek support from Relevant State Entities regarding
selection criteria.\2143\
---------------------------------------------------------------------------
\2140\ California Commission Initial Comments at 37-38.
\2141\ PJM States Initial Comments at 3-4 (citing NOPR, 179 FERC
] 61,028 at P 245).
\2142\ ACEG Initial Comments at 59-60.
\2143\ NYISO Initial Comments at 44.
---------------------------------------------------------------------------
978. To ensure that consultation is successful, NARUC recommends
that the Commission require transmission providers to take two steps:
(1) communicate with the Relevant State Entities promptly following
issuance of a final order in a manner that is reasonably calculated to
be received by the Relevant State Entities; and (2) establish a forum
for negotiation that enables full and robust participation by both
transmission providers and Relevant State Entities during the period
allotted for making compliance filings.\2144\
---------------------------------------------------------------------------
\2144\ NARUC Initial Comments at 44.
---------------------------------------------------------------------------
979. Some commenters oppose the Commission's NOPR proposal.\2145\
Dominion argues that mandating involvement by Relevant State Entities
would unnecessarily burden transmission providers.\2146\ Louisiana
Commission argues that the proposal would represent ``superficial state
involvement'' and serve as ``window dressing'' for the erosion of state
authority due to Long-Term Regional Transmission Planning. Louisiana
Commission argues that collective oversight by the states within an
RTO/ISO is not equivalent to state oversight of its own retail electric
service companies, particularly in circumstances where states are
subject to the decisions of the majority.\2147\
---------------------------------------------------------------------------
\2145\ See, e.g., Clean Energy Associations Initial Comments at
22-23 (arguing that, while state involvement should play a role, the
Commission should set forth pro forma selection criteria).
\2146\ Dominion Initial Comments at 37-38.
\2147\ Louisiana Commission Initial Comments at 27.
---------------------------------------------------------------------------
980. APPA opposes any requirement for transmission providers to
consult with, and/or seek the support of, Relevant State Entities in
identifying selection criteria.\2148\ APPA contends that Relevant State
Entities should be considered in the same manner as other stakeholders
under the requirements of Order Nos. 890 and 1000.\2149\ DC and MD
Offices of People's Counsel disagree with APPA, arguing that the
Commission should afford Relevant State Entities an expansive role in
the selection of transmission facilities in Long-Term Regional
Transmission Planning.\2150\ DC and MD Offices of People's Counsel
contend that Relevant State Entities can reach agreement quickly and
have access to the best available data used for baseline planning and
scenario analysis of transmission facilities.\2151\
---------------------------------------------------------------------------
\2148\ APPA Initial Comments at 34.
\2149\ Id.
\2150\ DC and MD Offices of People's Counsel Reply Comments at 9
(citing APPA Initial Comments at 35).
\2151\ Id.
---------------------------------------------------------------------------
981. MISO takes no position but argues that its existing processes
already entail extensive stakeholder engagement, including consulting
with state regulatory commissions individually and through OMS, to
determine the selection criteria that should be used to maximize long-
term transmission value and to ensure an adequate, reliable, and
resilient transmission system.\2152\
---------------------------------------------------------------------------
\2152\ MISO Initial Comments at 55.
---------------------------------------------------------------------------
ii. Obtaining/Not Obtaining Consent
982. Several commenters discuss whether transmission providers need
only consult with and seek support from Relevant State Entities in the
development of selection criteria, or whether they also must obtain
their consent.\2153\ For example, Indicated PJM TOs support the NOPR
proposal but argue that the Commission should not require transmission
providers to obtain the agreement of Relevant State Entities in
determining selection criteria.\2154\ AEP agrees and argues that state
input should be only one factor and that engineering considerations
should drive the establishment of selection criteria. AEP also
expresses skepticism that requiring transmission providers to consult
with Relevant State Entities will increase the chances that states will
site the transmission facilities that transmission providers select,
because transmission line siting processes will occur years after the
establishment of selection criteria, will likely be performed by
different personnel, and will address considerations separate from
those in establishing selection criteria.\2155\
---------------------------------------------------------------------------
\2153\ See, e.g., Acadia Center and CLF Initial Comments at 27-
28 (arguing that states should have veto authority over transmission
providers' selection criteria in certain circumstances).
\2154\ Indicated PJM TOs Initial Comments at 18 (citing NOPR
179, FERC ] 61,028 at PP 244, 246).
\2155\ AEP Initial Comments at 29-30.
---------------------------------------------------------------------------
983. Southeast PIOs argue that, while they do not oppose factoring
state and consumer support into the selection of transmission
facilities, the Commission should not require transmission providers to
obtain the approval of Relevant State Entities prior to selection of
transmission facilities, because doing so would risk indefinitely
delaying Long-Term Regional Transmission Planning.\2156\
---------------------------------------------------------------------------
\2156\ Southeast PIOs Reply Comments at 27.
---------------------------------------------------------------------------
984. PJM argues that it should be able to develop selection
criteria in the event that Relevant State Entities do not agree on the
establishment of selection criteria. PJM recommends that the Commission
clarify that any requirement to demonstrate that transmission providers
have consulted with and sought support from Relevant State Entities
could be satisfied even if the transmission provider is unable to
secure the agreement of Relevant State Entities.\2157\
---------------------------------------------------------------------------
\2157\ PJM Initial Comments at 104.
---------------------------------------------------------------------------
985. By contrast, NARUC opposes a process in which transmission
providers consult with and seek support from Relevant State Entities
but are empowered to override or ignore selection criteria proposed and
[[Page 49436]]
supported by Relevant State Entities. NARUC seeks clarification as to
what recourse will be available to Relevant State Entities in the event
that there is not agreement on selection criteria.\2158\ Nebraska
Commission argues that the Commission should require transmission
providers to demonstrate to the greatest extent possible that they
gained the support of Relevant State Entities, because otherwise the
process of consulting with and seeking support from Relevant State
Entities could become a mere exercise.\2159\
---------------------------------------------------------------------------
\2158\ NARUC Initial Comments at 45.
\2159\ Nebraska Commission Initial Comments at 8-9.
---------------------------------------------------------------------------
986. Mississippi Commission suggests that the Commission require
transmission providers to obtain the agreement of Relevant State
Entities on selection criteria for Long-Term Regional Transmission
Planning.\2160\ Southern goes further, arguing that the Commission
should allow Relevant State Entities to use the State Agreement Process
not only to allocate the costs of Long-Term Regional Transmission
Facilities, but also to select such transmission facilities in the
first instance. Southern contends that, if the Commission does not
allow states to select transmission facilities, the Commission will
unlawfully intrude into state jurisdiction over resource
planning.\2161\
---------------------------------------------------------------------------
\2160\ Mississippi Commission Initial Comments at 3-4 (citing
NOPR, 179 FERC ] 61,028 (Christie, Comm'r, concurring at P 11)).
\2161\ Southern Initial Comments at 6-10 & n.12 (citations
omitted).
---------------------------------------------------------------------------
987. Acadia Center and CLF assert that states should have the
authority to propose selection criteria, arguing that this will ensure
that transmission providers do not refuse to consider states' interests
and goals regarding transmission needs. Acadia Center and CLF further
contend that states should have veto authority over transmission
providers' selection criteria in certain scenarios, such as ISO-NE,
where a majority of states in a transmission planning region have
decarbonization goals but the ISO/RTO continues to apply business-as-
usual selection criteria that prioritize reliability and economic
considerations.\2162\
---------------------------------------------------------------------------
\2162\ Acadia Center and CLF Initial Comments at 27-28.
---------------------------------------------------------------------------
988. AEE argues that the final order should clearly provide an
opportunity for states to suggest selection criteria and inputs for
analyzing transmission projects, noting that such a process may need to
be continually developed following issuance of a final order.\2163\
---------------------------------------------------------------------------
\2163\ AEE Initial Comments at 30-32 (citations omitted).
---------------------------------------------------------------------------
iii. Consultation With Other Entities
989. A number of commenters argue that transmission providers
should consult with and seek support from other entities in addition to
Relevant State Entities. Large Public Power does not object to the NOPR
proposal but argues that it is essential that municipal utilities also
be included as participants in the consultative process.\2164\ American
Municipal Power urges the Commission to recognize that publicly-owned
utilities play a role analogous to state commissions, in that they are
publicly accountable, operate through open and transparent procedures,
and adopt policies reflecting the consensus of communities that own and
support them. American Municipal Power argues that FPA section
217(b)(4) requires the Commission to revise the NOPR proposal such that
load-serving entities, including publicly-owned utilities, are on a par
with Relevant State Entities.\2165\ NRECA agrees, arguing that Relevant
State Entities may not have regulatory authority over electric
cooperatives, and therefore the Commission must modify its proposal to
include consultation with load-serving entities to conform with FPA
section 217(b)(4) and Order No. 1000's transmission planning
principles.\2166\
---------------------------------------------------------------------------
\2164\ Large Public Power Initial Comments at 30.
\2165\ American Municipal Power Initial Comments at 12-13.
\2166\ NRECA Initial Comments at 50.
---------------------------------------------------------------------------
990. Relatedly, NARUC argues that nothing in the final order should
inhibit states from permitting the participation of certain quasi-
public/private state and Federal entities or other state entities in
addition to Relevant State Entities.\2167\ NEPOOL states that the
selection of any transmission facilities should be made with
substantial input from both market participant stakeholders and the
transmission planning region's states.\2168\
---------------------------------------------------------------------------
\2167\ NARUC Initial Comments at 29-30 (citation omitted).
\2168\ NEPOOL Initial Comments at 8.
---------------------------------------------------------------------------
iv. Practical Implementation Issues
991. Several commenters discuss practical issues with the
requirement that transmission providers consult with and seek the
support of Relevant State Entities in developing selection criteria.
For example, PPL generally supports the Commission's proposal but
contends that some states may find it difficult to fulfill the role
described in the NOPR. PPL therefore argues that the Commission should
allow transmission providers flexibility in developing consultative
processes.\2169\ AEP argues that some states will be unable to
participate effectively given a lack of resources or statutory
limitations, such that the consultative process may result in selection
criteria ``that unfairly or unreasonably emphasize certain values.''
\2170\ NESCOE states that the Commission should provide flexibility as
to how states elect to engage in the transmission planning process,
noting that a state official's role in siting electric infrastructure
may make it preferable for a different state official to provide that
state's view on certain aspects of Long-Term Regional Transmission
Planning, such as transmission project selection.\2171\
---------------------------------------------------------------------------
\2169\ PPL Initial Comments at 18-19.
\2170\ AEP Initial Comments at 30 (quoting NOPR, 179 FERC ]
61,028 at P 290).
\2171\ NESCOE Initial Comments at 9 n.16.
---------------------------------------------------------------------------
992. NEPOOL requests that the Commission articulate principles for
who should make selection decisions when a Long-Term Regional
Transmission Facility may address transmission needs driven by
reliability, economics, and public policy.\2172\
---------------------------------------------------------------------------
\2172\ NEPOOL Initial Comments at 8.
---------------------------------------------------------------------------
993. Michigan State Entities argue that the success of the
Commission's proposed reforms depends on transmission providers
meaningfully engaging with stakeholders, which requires that
stakeholders have the time and capability to participate in a
stakeholder review process. Michigan State Entities further assert that
stakeholders representing diffuse and broad interests (e.g.,
residential ratepayers), as opposed to concentrated interests, tend to
have fewer resources with which to fund participation in these
processes, noting that many states have created consumer advocacy
agencies to correct this imbalance. Michigan State Entities assert that
the Commission should require that transmission providers include RTO/
ISO-level, publicly funded consumer advocates in the stakeholder
processes that are empowered to participate in approving selection
criteria.\2173\
---------------------------------------------------------------------------
\2173\ Michigan State Entities Initial Comments at 4-5.
---------------------------------------------------------------------------
c. Commission Determination
994. We adopt the NOPR proposal, with modification, to require
transmission providers in each transmission planning region to consult
with and seek support from Relevant State Entities regarding the
evaluation process, including selection criteria, that transmission
providers propose to use to identify and evaluate Long-Term Regional
Transmission Facilities for selection. Specifically, we require
transmission providers to demonstrate on compliance that they made good
[[Page 49437]]
faith efforts to consult with and seek support from Relevant State
Entities in their transmission planning region's footprint when
developing the evaluation process and selection criteria that they
propose to include in their OATTs.\2174\
---------------------------------------------------------------------------
\2174\ In response to New York Commission and NYSERDA, we note
that such consultation may include discussion of the appropriate
timeframe for selecting a Long-Term Regional Transmission Facility.
New York Commission and NYSERDA Initial Comments at 12.
---------------------------------------------------------------------------
995. We decline to adopt the NOPR proposal to require transmission
providers to include in their OATTs a process for coordinating with
Relevant State Entities. We believe that the requirement adopted in
this final order will simplify compliance efforts without sacrificing
the benefits of consulting with and seeking the support of Relevant
State Entities. We disagree with Dominion that requiring transmission
providers to consult with and seek support from Relevant State Entities
will prove burdensome, and we believe that our decision not to require
transmission providers to include a process for such consultation in
their OATTs will further reduce any administrative burden of this
requirement.\2175\
---------------------------------------------------------------------------
\2175\ See Dominion Initial Comments at 37-38.
---------------------------------------------------------------------------
996. We clarify that we require transmission providers to seek
support from Relevant State Entities, but do not require transmission
providers to obtain their support, before proposing an evaluation
process and selection criteria on compliance.\2176\ In response to
Acadia Center and CLF, we note that Relevant State Entities may propose
selection criteria to transmission providers, but ultimately, it is
transmission providers who must propose on compliance an evaluation
process and selection criteria that comply with the requirements of
this final order. We further note that providing states with veto
authority over transmission providers' proposed selection criteria
would be akin to requiring transmission providers to obtain the support
of Relevant State Entities, and therefore we do not adopt Acadia Center
and CLF's recommendation.\2177\ While we believe that Long-Term
Regional Transmission Planning is more likely to be successful where
transmission providers, Relevant State Entities, and other stakeholders
collaborate to develop an evaluation process and selection criteria, we
reiterate that transmission planning is the tariff obligation of each
transmission provider and transmission providers retain ultimate
responsibility for regional transmission planning, including Long-Term
Regional Transmission Planning, as well as complying with the
obligations of this final order.\2178\ Moreover, we acknowledge that
achieving consensus may not be possible in every instance.
---------------------------------------------------------------------------
\2176\ See, e.g., PJM Initial Comments at 104 (requesting
clarification that transmission providers are permitted to submit an
evaluation process and selection criteria on compliance in the
absence of obtaining the support of Relevant State Entities).
\2177\ See Acadia Center and CLF Initial Comments at 27-28.
\2178\ See Order No. 1000, 136 FERC ] 61,051 at P 153 (``[T]he
ultimate responsibility for transmission planning remains with
public utility transmission providers.'' (citing Order No. 890, 118
FERC ] 61,119 at P 454)).
---------------------------------------------------------------------------
997. We disagree with NARUC that, in the absence of a requirement
that transmission providers obtain the support of Relevant State
Entities, transmission providers will be empowered to ignore the input
of Relevant State Entities. In this final order, we require
transmission providers to make good faith efforts to consult with and
seek the support of Relevant State Entities. We do not agree that the
failure to obtain the support of Relevant State Entities is necessarily
evidence that transmission providers did not exercise good faith
efforts to seek their support.
998. For similar reasons, we also disagree with Louisiana
Commission when it argues that requiring transmission providers to
simply consult with and seek support from Relevant State Entities will
amount to only superficial state involvement in the development of an
evaluation process and selection criteria.\2179\ In response to
Louisiana Commission's additional contention that collective oversight
of regional transmission planning processes by the transmission
planning region's states is not equivalent to state oversight of its
own retail electric service companies, we reiterate that this final
order requires transmission providers to engage in and conduct
sufficiently long-term, forward-looking, and comprehensive transmission
planning and cost allocation processes to identify and plan for Long-
Term Transmission Needs in order to ensure Commission-jurisdictional
rates are just and reasonable. As discussed in the Legal Authority to
Adopt Reforms for Long-Term Regional Transmission Planning section, the
final order neither aims at nor conflicts with state authority over
retail rates.
---------------------------------------------------------------------------
\2179\ Louisiana Commission Initial Comments at 27.
---------------------------------------------------------------------------
999. We do not believe that it is necessary to adopt California
Commission's proposal to require transmission providers to indicate in
their compliance filings whether Relevant State Entities support the
proposal or explain any points of disagreement that they may have with
Relevant State Entities. Relevant State Entities may intervene in
compliance filing proceedings and provide this information for the
Commission's consideration as it determines whether transmission
providers have met the requirements that we adopt in this final order.
Nor do we adopt NARUC's request that we impose specific requirements
dictating how transmission providers should consult with and seek the
support of Relevant State Entities beyond the requirement that they
demonstrate good faith efforts to do so. We believe that it is
appropriate to provide transmission providers with flexibility in how
to consult with and seek support of Relevant State Entities based on
the specific needs and makeup of their transmission planning region.
Further, we acknowledge, as argued by some commenters,\2180\ that
practical or legal limitations may limit the extent to which some
Relevant State Entities may participate in such processes, reinforcing
the need for flexibility.
---------------------------------------------------------------------------
\2180\ See AEP Initial Comments at 30 (quoting NOPR, 179 FERC ]
61,028 at P 290); NESCOE Initial Comments at 9 n.16; PPL Initial
Comments at 18-19.
---------------------------------------------------------------------------
1000. We clarify that nothing in this final order diminishes the
role of stakeholders that are not Relevant State Entities, nor absolves
transmission providers of any existing obligations that they may have
to provide opportunities for stakeholder input.\2181\ That said, we
decline to require transmission providers to consult with or seek
support from entities in addition to Relevant State Entities, including
load-serving entities.\2182\ This final order recognizes that Relevant
State Entities play a unique role in representing the interests of
states, which retain a variety of authorities, including those under
FPA section 201, that are integral to the success of Long-Term Regional
Transmission Planning.
---------------------------------------------------------------------------
\2181\ In response to NARUC and NEPOOL, see NARUC Initial
Comments at 29-30; NEPOOL Initial Comments at 9, we reiterate that
this may include other state entities in addition to Relevant State
Entities, such as Federal entities, market participants, and other
stakeholders.
\2182\ See, e.g., American Municipal Power Initial Comments at
12-13; Large Public Power Initial Comments at 30.
---------------------------------------------------------------------------
1001. Further, we disagree with American Municipal Power that FPA
section 217(b)(4) requires that this final order treat load-serving
entities on par with Relevant State Entities. Through the requirements
of this final order, we seek to ensure that adequate
[[Page 49438]]
transmission capacity is built to allow load-serving entities to meet
their service obligations and facilitate the planning of a reliable
grid, consistent with FPA section 217(b)(4). Nothing in our
determination to require transmission providers to consult with and
seek support from Relevant State Entities (but not load-serving
entities) changes that aim or undercuts the ability of Long-Term
Regional Transmission Planning to achieve it. We continue to find that
other requirements in the final order, including the requirement to
incorporate state-approved integrated resource plans and expected
supply obligations for load-serving entities in the development of
Long-Term Scenarios, ensure load-serving entities' reasonable needs for
transmission capacity to meet their service obligations are
incorporated into Long-Term Regional Transmission Planning.
1002. Finally, in response to commenters,\2183\ we clarify that
transmission providers, not Relevant State Entities, must determine
whether or not to select Long-Term Transmission Facilities to meet
Long-Term Transmission Needs. Under the FPA, the Commission has
jurisdiction over transmission providers, and those entities, not
Relevant State Entities, are subject to the requirements of this final
order. As discussed above in the Transparent and Not Unduly
Discriminatory; More Efficient or Cost-Effective Transmission
Facilities section, we require herein that transmission providers
designate a point in the evaluation process at which they will
determine whether to select or not select identified Long-Term Regional
Transmission Facilities (or portfolio of such Facilities).
---------------------------------------------------------------------------
\2183\ See, e.g., ISO-NE Initial Comments at 35 (arguing that
states should be responsible for determining whether to select
transmission facilities and that transmission providers should play
a supportive, technical role); NEPOOL Initial Comments at 8
(requesting that the Commission articulate principles for who should
select multi-value transmission facilities); NESCOE Initial Comments
at 9,48-49 (requesting that the Commission require transmission
providers to include a role in their OATTs for Relevant State
Entities in the selection of Long-Term Regional Transmission
Facilities); PJM Reply Comments at 36 (requesting that the
Commission clarify that transmission providers retain the authority
to select transmission facilities).
---------------------------------------------------------------------------
5. Voluntary Funding Opportunities
a. NOPR Proposal
1003. In the NOPR, the Commission sought comment on whether
Relevant State Entities should have the opportunity to voluntarily fund
the cost of, or a portion of the cost of, a Long-Term Regional
Transmission Facility to enable such facility to meet transmission
providers' selection criteria (e.g., any benefit-cost threshold), and
if so, what mechanism would be appropriate to document such voluntary
funding agreements, how transmission providers would be assured that
commitments to provide funding would be sufficiently binding, and what
the most appropriate point would be in the process for such voluntary
commitments.\2184\ The Commission also sought comment on whether such a
voluntary funding opportunity should be extended to other entities,
such as interconnection customers.\2185\
---------------------------------------------------------------------------
\2184\ NOPR, 179 FERC ] 61,028 at P 252. The Commission stated
that, for Long-Term Regional Transmission Facilities, such an
opportunity for the Relevant State Entities could enable them to
assign a value to achieving their particular policy goals while
ensuring that their customers bear the corresponding costs. Id. P
252 n.399.
\2185\ Id.
---------------------------------------------------------------------------
b. Comments
1004. Of commenters that address the question posed in the NOPR
regarding whether Relevant State Entities should have the opportunity
to voluntarily fund the cost of, or a portion of the cost of, a Long-
Term Regional Transmission Facility, nearly all argue that the
Commission should allow such an opportunity.\2186\ ISO-NE argues that
the Commission should provide flexibility to transmission providers to
determine the specific means for documenting the state's agreement to
provide such funding.\2187\ APPA argues that the Commission should
require the filing under FPA section 205 of agreements to fund the cost
of, or a portion of the cost of, a transmission facility so that
affected parties have an opportunity to comment.\2188\
---------------------------------------------------------------------------
\2186\ See Ameren Initial Comments at 21; APPA Initial Comments
at 34-35; Clean Energy Associations Initial Comments at 23; Duke
Initial Comments at 28-29; Grid United Initial Comments at 6; Idaho
Commission Initial Comments at 5; ISO-NE Initial Comments at 36;
Louisiana Commission Initial Comments at 29; NARUC Initial Comments
at 31-32 (citing MISO-SPP Joint Targeted Interconnection Queue Study
(JTIQ), MISO, https://www.misoenergy.org/engage/committees/miso-spp-joint-targeted-interconnection-queue-study/); New Jersey Commission
Initial Comments at 25; PPL Initial Comments at 19; SDG&E Initial
Comments at 4; WATT Coalition Initial Comments at 11; Xcel Initial
Comments at 14 (stating that neither the FPA nor the Commission's
rules and regulations categorically preclude voluntary agreement to
plan and pay for new transmission facilities (citing Order No. 1000,
136 FERC ] 61,051 at PP 146, 561, 724; State Voluntary Agreements to
Plan & Pay for Transmission Facilities, 175 FERC ] 61,225 at P 3)).
\2187\ ISO-NE Initial Comments at 36.
\2188\ APPA Initial Comments at 34-35 (citing PJM
Interconnection, L.L.C., 179 FERC ] 61,024 (2022)).
---------------------------------------------------------------------------
1005. Grid United argues that, while it supports ex ante cost
allocation methods, the Commission also should continue to permit
alternative cost recovery arrangements, including participant funding
agreements and voluntary agreements entered into by generation
developers and Relevant State Entities.\2189\ Duke asserts that the
Commission should avoid prescriptive rules that discourage or
undervalue voluntary funding from transmission providers, states,
Relevant State Entities, or interconnection customers.\2190\ Xcel
argues that the Commission should state in a final order that neither
the FPA nor the Commission's rules and regulations forbid voluntary
arrangements for planning and paying for transmission facilities.\2191\
---------------------------------------------------------------------------
\2189\ Grid United Initial Comments at 6.
\2190\ Duke Initial Comments at 28-29.
\2191\ Xcel Initial Comments at 14.
---------------------------------------------------------------------------
1006. NARUC argues that the final order should not inhibit the
flexibility of Relevant State Entities in developing approaches to such
voluntary funding commitments.\2192\ NARUC argues that the final order
should be as flexible as possible in providing voluntary funding
opportunities to account for the variety of state laws enabling such
authority and to allow for the possibility of sharing the costs of such
transmission facilities between load and generator developers.\2193\
---------------------------------------------------------------------------
\2192\ NARUC Initial Comments at 31-32; accord Idaho Commission
Initial Comments at 5.
\2193\ NARUC Initial Comments at 32.
---------------------------------------------------------------------------
1007. Louisiana Commission supports the NOPR proposal and argues
that voluntary agreement is the only fair, reasonable, and just way to
allocate the costs of transmission facilities selected in Long-Term
Regional Transmission Planning.\2194\ Ameren believes that Relevant
State Entities should have the opportunity to fund a portion of the
cost of a transmission facility that otherwise would not meet the OATT
selection criteria but requests that the Commission clarify that this
decision ``is referring to cost allocation.'' \2195\ Ameren argues that
without this clarification, Relevant State Entities could fund part of
the transmission facility while imposing on a transmission owner the
obligation to operate and maintain that facility and assure regulatory
compliance without adequate compensation, in violation of the D.C.
Circuit's determination in Ameren Services Co. v. FERC that
transmission owners ``should not be forced to operate as a non-
profit.'' \2196\
---------------------------------------------------------------------------
\2194\ Louisiana Commission Initial Comments at 29.
\2195\ Ameren Initial Comments at 21-22 (citing NOPR, 179 FERC ]
61,028 at P 252).
\2196\ Id. (citing Ameren Servs. Co. v. FERC, 880 F.3d 571 (D.C.
Cir. 2018)).
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[[Page 49439]]
1008. Clean Energy Associations suggest two mechanisms to provide
opportunities for states and interconnection customers to ensure that
necessary transmission facilities are built. First, Clean Energy
Associations would provide a ``Transmission Alternative Right,''
through which states or interconnection customers could pay the
difference between evaluated benefits and the level of benefits
necessary to meet the applicable benefits threshold. Second, Clean
Energy Associations would provide a ``Transmission Expansion Right,''
which would allow states or interconnection customers to provide
funding to expand transmission facilities beyond those identified in
Long-Term Regional Transmission Planning. With respect to this second
right, Clean Energy Associations contend that the funding parties
should receive time-limited priority usage of additional transmission
expansion that they fund and retain incremental capacity attributes
associated with the expanded capability.\2197\ Clean Energy
Associations also suggest that the portion of the expanded Long-Term
Regional Transmission Facility originally identified in the regional
transmission plan would receive the applicable regional cost
allocation.\2198\
---------------------------------------------------------------------------
\2197\ Clean Energy Associations Initial Comments at 23-24
(citing Clean Energy Associations ANOPR Initial Comments at 76).
Clean Energy Associations assert this would be consistent with Order
No. 807. Id. (citing Clean Energy Associations ANOPR Initial
Comments at 76-78; Open Access & Priority Rights on Interconnection
Customer's Interconnection Facilities, Order No. 807, 150 FERC ]
61,211, at P 109, order on reh'g, Order No. 807-A, 153 FERC ] 61,047
(2015)).
\2198\ See id.
---------------------------------------------------------------------------
1009. New Jersey Commission argues that allowing Relevant State
Entities the opportunity to fund the cost of or part of the cost of
transmission facilities would provide a way to value a transmission
facility's public policy benefits and a mechanism for co-optimizing
reliability and economic benefits while meeting public policy needs.
However, New Jersey Commission states that, while the proposed 20-year
transmission planning horizon should ensure that transmission providers
identify opportunities for multi-driver transmission projects in
sufficient time for states to provide funding, the Commission should
mandate that transmission providers reach out to Relevant State
Entities to inform them of such opportunities on a timely basis.\2199\
---------------------------------------------------------------------------
\2199\ New Jersey Commission Initial Comments at 28.
---------------------------------------------------------------------------
1010. SPP takes no position on the voluntary funding issue but
states that its Regional State Committee developed a cost allocation
framework that includes the option for entities to sponsor specific
transmission projects, assuming cost responsibility without imposing
burdens on others through the general rate structure. SPP states that
this mechanism could be used by a state or states to fund projects that
SPP otherwise would not select.\2200\
---------------------------------------------------------------------------
\2200\ SPP Initial Comments at 22 (citing SPP, Governing
Documents Tariff, Bylaws, First Revised Volume No. 4 (0.0.0), Sec.
7.2).
---------------------------------------------------------------------------
1011. While PPL supports the ability of states to fund the cost of,
or a portion of the costs of, transmission facilities that otherwise
would not meet selection criteria, PPL argues that the final order
should not require transmission providers to facilitate such an
opportunity with states.\2201\ APS contends that it is not appropriate
for a Relevant State Entity to volunteer its ratepayers to fund, and
APS to build, a transmission facility. APS explains that Arizona is a
diverse state with several non-jurisdictional entities; as such, APS
contends that the state would not have the authority to volunteer all
the state's ratepayers to fund the transmission facility, which
ultimately may burden transmission providers with additional costs and
responsibilities.\2202\
---------------------------------------------------------------------------
\2201\ PPL Initial Comments at 19.
\2202\ APS Initial Comments at 10.
---------------------------------------------------------------------------
c. Commission Determination
1012. We modify the NOPR proposal and require transmission
providers in each transmission planning region to include in their
OATTs a process to provide Relevant State Entities and interconnection
customers with the opportunity to voluntarily fund the cost of, or a
portion of the cost of, a Long-Term Regional Transmission Facility that
otherwise would not meet the transmission providers' selection
criteria. We provide transmission providers with the flexibility to
propose certain features of such a voluntary funding process in their
compliance filings.\2203\ However, this voluntary funding process must
be transparent and not unduly discriminatory or preferential and
provide for the four components discussed below. Further, as with other
aspects of the evaluation process and selection criteria, transmission
providers must consult with and seek support from Relevant State
Entities when developing a process to provide Relevant State Entities
and interconnection customers with the opportunity to voluntarily fund
the cost of, or a portion of the cost of, a Long-Term Regional
Transmission Facility that they propose to include in their OATTs.
---------------------------------------------------------------------------
\2203\ See ISO-NE Initial Comments at 36; NARUC Initial Comments
at 31-32 (requesting flexibility to design voluntary funding
processes).
---------------------------------------------------------------------------
1013. In setting forth the requirement that transmission providers
include in their OATTs a process to provide Relevant State Entities and
interconnection customers with the opportunity to voluntarily fund the
cost of, or a portion of the cost of, a Long-Term Regional Transmission
Facility that otherwise would not meet the transmission providers'
selection criteria, we direct transmission providers to propose OATT
provisions on compliance that describe: (1) the process by which the
transmission providers will make voluntary funding opportunities
available to Relevant State Entities and interconnection customers,
which must ensure that Relevant State Entities and interconnection
customers receive timely notice of such opportunities and provide a
meaningful opportunity for Relevant State Entities and interconnection
customers; (2) the period during which Relevant State Entities and
interconnection customers may exercise the option to provide voluntary
funding; (3) the method that transmission providers will use to
determine the amount of voluntary funding required to ensure that the
Long-Term Regional Transmission Facility meets the transmission
providers' selection criteria; and (4) the mechanism through which
transmission providers and Relevant State Entities or interconnection
customers will memorialize any voluntary funding agreement, e.g., a pro
forma agreement in the OATT. We clarify that, for any portion of the
costs of a selected Long-Term Regional Transmission Facility that is
not voluntarily funded by a Relevant State Entity (or Entities) or
interconnection customers, those remaining costs must be allocated
according to the applicable Long-Term Regional Transmission Cost
Allocation Method (or cost allocation method resulting from a State
Agreement Process, if such a process is adopted by the transmission
providers in the associated transmission planning region).
1014. We believe that requiring transmission providers to include a
voluntary funding process in their OATTs ultimately may increase the
number of Long-Term Regional Transmission Facilities that are selected.
The voluntary funding processes that we are requiring transmission
providers to include in their OATTs will allow Relevant State Entities
and interconnection customers to voluntarily fund the cost of, or a
portion of the cost of, a Long-Term
[[Page 49440]]
Regional Transmission Facility, with any remaining costs allocated to
beneficiaries in a manner that is at least roughly commensurate with
the estimated benefits that they will receive. As such, a voluntary
funding process will allow the development of Long-Term Regional
Transmission Facilities that Relevant State Entities or interconnection
customers believe are beneficial but that might not otherwise be
selected.\2204\ We also believe that such a voluntary funding process
could help transmission providers to avoid, manage, or resolve
otherwise difficult disputes among stakeholders in their transmission
planning regions, such as those arising from situations in which
Relevant State Entities or interconnection customers value the
development of certain Long-Term Regional Transmission Facilities
differently.
---------------------------------------------------------------------------
\2204\ See, e.g., New Jersey Commission Initial Comments at 25-
26 (arguing that voluntary funding would provide a way to value a
transmission facility's public policy benefits and a mechanism for
co-optimizing reliability and economic benefits while meeting public
policy needs).
---------------------------------------------------------------------------
1015. We acknowledge, consistent with APS's comments, that in
certain states Relevant State Entities may not have the necessary
authority to require all of that state's ratepayers to provide the
funding needed to take advantage of voluntary funding
opportunities.\2205\ We do note, however, nothing in this final order
is intended to limit, preempt, or otherwise affect state or local laws
or regulations with respect to the ability of any Relevant State Entity
to voluntarily fund any costs of a Long-Term Regional Transmission
Facility. Whether and to what extent a Relevant State Entity chooses to
take advantage of an opportunity to voluntarily fund the costs of a
Long-Term Regional Transmission Facility is dependent on whether that
entity has the requisite authority to do so.
---------------------------------------------------------------------------
\2205\ APS Initial Comments at 10.
---------------------------------------------------------------------------
1016. In response to Ameren,\2206\ we decline to determine at this
point what effect Ameren Services Co. v. FERC may have on voluntary
funding arrangements or the allocation of the costs of a transmission
facility net of that voluntary funding, which may depend on how
transmission providers propose to allow for voluntary funding
opportunities.
---------------------------------------------------------------------------
\2206\ Ameren Initial Comments at 21-22.
---------------------------------------------------------------------------
1017. We decline Clean Energy Associations' request that we require
transmission providers to allow voluntary funding opportunities to
expand a Long-Term Regional Transmission Facility beyond what was
identified through Long-Term Regional Transmission Planning (e.g.,
voluntarily funding the construction of a 500 kV transmission line
where a 345 kV transmission line was identified through Long-Term
Regional Transmission Planning).\2207\ While we recognize that there
may be interest in providing additional opportunities for voluntary
funding, we find that there is insufficient record evidence to support
imposing this modification to the voluntary funding opportunity we
require in this final order. We note, however, that nothing in this
final order prohibits this type of voluntary funding approach and
transmission providers may either seek to demonstrate that a proposal
including such an approach is consistent with or superior to what is
required by this order, or else submit a filing under FPA section 205
to propose the inclusion in their OATTs of voluntary funding
opportunities that go beyond those required in this final order.
---------------------------------------------------------------------------
\2207\ Clean Energy Associations Initial Comments at 23-24
(citations omitted).
---------------------------------------------------------------------------
1018. Finally, in response to APPA,\2208\ we decline to impose any
specific requirement for transmission providers to file agreements that
memorialize voluntary funding arrangements under FPA section 205. The
Commission will evaluate on compliance the mechanism that transmission
providers propose for memorializing voluntary funding agreements
between transmission providers and Relevant State Entities or
interconnection customers, as applicable.
---------------------------------------------------------------------------
\2208\ APPA Initial Comments at 34-35 (citing PJM
Interconnection, L.L.C., 179 FERC ] 61,024).
---------------------------------------------------------------------------
6. No Selection Requirement
a. NOPR Proposal
1019. The Commission did not propose in the NOPR to require that
transmission providers select transmission facilities, even in the
event that a transmission facility meets the selection criteria
established by the transmission providers.\2209\
---------------------------------------------------------------------------
\2209\ See NOPR, 179 FERC ] 61,028 at P 9 (noting that the
proposed reforms related to regional transmission planning and cost
allocation requirements, like those of Order Nos. 890 and 1000, are
focused on the transmission planning process, and not on any
substantive outcomes that may result from this process); see also
id. P 241 (requiring transmission providers to propose selection
criteria to identify and evaluate transmission facilities for
potential selection).
---------------------------------------------------------------------------
b. Comments
1020. Many commenters express opposition to any potential
requirement under which the Commission would require transmission
providers to select Long-Term Regional Transmission Facilities.\2210\
For example, ISO-NE states that the final order should be clear that
transmission providers are not required to select any identified Long-
Term Regional Transmission Facilities for inclusion in system plans or
cost allocation purposes, and NESCOE agrees.\2211\ Ameren contends that
a mandate to select any transmission facility may result in over-
building the transmission system.\2212\ Xcel makes a similar point,
arguing that it would result in a loss of confidence in the
transmission planning process. Furthermore, Xcel argues, transmission
planning is subjective and removing all discretion from transmission
planners would result in bad outcomes.\2213\
---------------------------------------------------------------------------
\2210\ See, e.g., California Water Initial Comments at 14-15;
Dominion Initial Comments at 18; Dominion Reply Comments at 8
(citing NARUC Initial Comments at 5-6, 39); ISO-NE Initial Comments
at 35-36 (citing NOPR, 179 FERC ] 61,028 (Christie, Comm'r,
concurring at P 10)); NESCOE Initial Comments at 46-47; NRECA
Initial Comments at 48; NRECA Reply Comments at 4-8 (citations
omitted); NYISO Initial Comments at 44 (citing N.Y. Indep. Sys.
Operator, Inc., 148 FERC ] 61,044, at P 125 (2014)); TANC Initial
Comments at 10.
\2211\ ISO-NE Initial Comments at 35-36 (citing NOPR, 179 FERC ]
61,028 (Christie, Comm'r, concurring at P 10)); NESCOE Reply
Comments at 5 (citing ISO-NE Initial Comments at 35-36).
\2212\ Ameren Initial Comments at 13 (citing Large Public Power
Initial Comments at 10).
\2213\ Xcel Initial Comments at 13-14.
---------------------------------------------------------------------------
1021. SERTP Sponsors urge the Commission to make clear that there
is no requirement for transmission providers to select Long-Term
Regional Transmission Facilities based on long-term studies without
specific express support and agreement of the relevant regulatory
authorities and policy makers.\2214\ NRECA asserts that transmission
planning using a 20-year transmission planning horizon is an exercise
fraught with uncertainty, and requests that the Commission clarify that
it is not mandating that transmission providers select Long-Term
Regional Transmission Facilities 20 years in advance.\2215\ NRECA
states that other commenters also expressed concerns about risks to
consumers associated with selecting transmission projects in the
regional transmission plan for purposes of cost allocation 20 years
before they may be needed.\2216\
---------------------------------------------------------------------------
\2214\ SERTP Sponsors Initial Comments at 5; see also Alabama
Commission Initial Comments at 3 (contending that Long-Term Regional
Transmission Planning should not involve selection or construction
obligations unless the affected state regulators support such
actions).
\2215\ NRECA Initial Comments at 27, 48.
\2216\ NRECA Reply Comments at 4-8 (citing APPA Initial Comments
at 22, 24-36; California Municipal Utilities Initial Comments at 2-
3, 5-7, 15; ELCON Initial Comments at 10; Large Public Power Initial
Comments at 6-8, 11-13; Nebraska Commission Initial Comments at 2;
New York Commission and NYSERDA Initial Comments at 8, 11-12;
Pennsylvania Commission Initial Comments at 4-5; PJM Initial
Comments at 59-62; TANC Initial Comments at 10).
---------------------------------------------------------------------------
[[Page 49441]]
1022. Dominion claims that Long-Term Regional Transmission Planning
should not be a mandated development and construction plan of
transmission facilities and argues that it should instead merely be a
tool to help transmission providers understand where transmission needs
may exist now and in the future.\2217\
---------------------------------------------------------------------------
\2217\ Dominion Reply Comments at 8 (citing PIOs Initial
Comments at 13, 28; NARUC Initial Comments at 5-6, 39).
---------------------------------------------------------------------------
1023. PJM requests that the Commission clarify that transmission
providers can identify trends across multiple Long-Term Regional
Transmission Planning cycles without needing to select specific
transmission facilities, arguing that it should have the flexibility to
open solicitations for transmission facilities as system needs
arise.\2218\
---------------------------------------------------------------------------
\2218\ PJM Reply Comments at 36-37.
---------------------------------------------------------------------------
1024. A few commenters favor selection mandates in at least some
circumstances. For example, Eversource argues that the Commission
should consider requiring transmission providers to address
transmission needs that are identified in multiple Long-Term Scenarios
or in the ``high-impact, low-frequency event'' scenario. Eversource
contends that transmission providers otherwise risk failing to select
transmission facilities that will greatly increase reliability,
resiliency, and affordability.\2219\
---------------------------------------------------------------------------
\2219\ Eversource Initial Comments at 26 (citing NOPR, 179 FERC
] 61,028 at P 124).
---------------------------------------------------------------------------
1025. PIOs state that experience with Order No. 1000 demonstrates
that some transmission providers may only do the bare minimum to comply
and therefore may fail to select, allocate the costs of, or construct
much needed transmission. As such, PIOs state, the Commission should
require transmission providers to use good faith efforts to select
recommended transmission facilities.\2220\
---------------------------------------------------------------------------
\2220\ PIOs Initial Comments at 12-13.
---------------------------------------------------------------------------
c. Commission Determination
1026. The Commission did not propose in the NOPR, and we will not
require in this final order, that transmission providers select any
particular Long-Term Regional Transmission Facility--even where a
particular transmission facility meets the transmission providers'
selection criteria in their OATTs.\2221\ This final order improves
regional transmission planning processes by ensuring that transmission
providers identify Long-Term Transmission Needs, identify Long-Term
Regional Transmission Facilities that resolve those needs and assess
the benefits thereof, and provide the opportunity for transmission
providers to select such Long-Term Regional Transmission Facilities. In
other words, as in Order No. 1000, our focus is on ensuring that
regional transmission planning processes result in just and reasonable
rates, and not on requiring that these processes achieve any particular
substantive outcome.
---------------------------------------------------------------------------
\2221\ See, e.g., ISO-NE Initial Comments at 35-36 (citing NOPR,
179 FERC ] 61,028 (Christie, Comm'r, concurring at P 10)); NESCOE
Reply Comments at 5 (citing ISO-NE Initial Comments at 35-36); SERTP
Sponsors Initial Comments at 5.
---------------------------------------------------------------------------
1027. We believe that transmission providers implementing Long-Term
Regional Transmission Planning and developing regional transmission
plans require the flexibility to balance competing interests in the
transmission planning region and to exercise engineering judgment to
ensure the reliable operation of the transmission system and compliance
with a variety of regulatory requirements.
1028. We clarify that nothing in this final order prohibits
transmission providers from proposing to impose upon themselves a
requirement to select a Long-Term Regional Transmission Facility in
certain circumstances. For example, transmission providers might
propose selection criteria that would require them to select a Long-
Term Regional Transmission Facility if it would meet a Long-Term
Transmission Need that appears in multiple Long-Term Scenarios, or if
it exceeded selection criteria by a pre-set margin.
7. Other Issues
a. Comments
1029. Clean Energy Associations argue that any transmission
projects that are approved at the end of a transmission planning cycle
should be included in updated models in the next transmission planning
cycle, as well as in generation interconnection studies.\2222\
---------------------------------------------------------------------------
\2222\ Clean Energy Associations Initial Comments at 10.
---------------------------------------------------------------------------
1030. R Street argues that the status quo selection process
undermines the NOPR's objective of advancing efficient and cost-
effective transmission expansion and that many transmission projects,
especially reliability projects, are not subject to economic scrutiny.
Therefore, R Street argues that the Commission should require that all
transmission projects pass a cost-benefit analysis under the purview of
an independent transmission planner and/or monitor across all Order No.
1000 transmission planning regions.\2223\
---------------------------------------------------------------------------
\2223\ R Street Initial Comments at 10.
---------------------------------------------------------------------------
b. Commission Determination
1031. In response to Clean Energy Associations, we clarify that we
are not imposing specific requirements regarding the treatment of
selected Long-Term Regional Transmission Facilities in subsequent Long-
Term Regional Transmission Planning cycles, beyond the overall
requirements discussed in the Development of Long-Term Scenarios
section of this final order. As we explain above, selection is only one
of a number of steps in the transmission development process, and we
believe that it is appropriate to provide transmission providers
flexibility on how to update their planning models in a manner that
most effectively addresses the specifics of their regional transmission
planning processes, consistent with the requirements of this final
order.
1032. Finally, we note that this final order generally does not
require transmission providers to replace or otherwise make changes to
existing Order No. 1000 regional reliability and economic transmission
planning and cost allocation processes. As such, we decline to adopt R
Street's proposal to require that all transmission projects pass a
cost-benefit analysis.
8. Reevaluation
a. NOPR Proposal
1033. The Commission proposed in the NOPR that, consistent with
Order No. 1000, the developer of a transmission facility selected
through Long-Term Regional Transmission Planning to address
transmission needs driven by changes in the resource mix and demand
would be eligible to use the applicable cost allocation method for the
Long-Term Regional Transmission Facility. The Commission proposed that
the existing transmission developer requirements would apply, including
that the developer of the selected regional transmission facility must
submit a development schedule that indicates the required steps, such
as the granting of state approvals necessary to develop and construct
the transmission facility such that it meets the transmission needs of
the transmission planning region.\2224\ The Commission
[[Page 49442]]
proposed that, to the extent the Relevant State Entities in a
transmission planning region agree to a State Agreement Process, as
described in the Regional Transmission Cost Allocation section, the
development schedule should also include relevant steps related to that
process.\2225\
---------------------------------------------------------------------------
\2224\ NOPR, 179 FERC ] 61,028 at P 247 (citing Order No. 1000-
A, 139 FERC ] 61,132 at P 442). The Commission also stated in Order
No. 1000-A that, as part of the ongoing monitoring of the progress
of a transmission facility once it is selected, the transmission
providers in a transmission planning region must establish a date by
which state approvals to construct must have been achieved that is
tied to when construction must begin to timely meet the need that
the facility is selected to address. If such critical steps have not
been achieved by that date, then the transmission providers in a
transmission planning region may ``remove the transmission project
from the selected category and proceed with reevaluating the
regional transmission plan to seek an alternative solution.'' Order
1000-A,139 FERC ] 61,132 at P 442.
\2225\ NOPR, 179 FERC ] 61,028 at P 247.
---------------------------------------------------------------------------
1034. The Commission noted that, given the longer-term nature of
transmission needs driven by changes in the resource mix and demand,
the required development schedule for a transmission facility selected
may make it unnecessary for the developer to take actions or incur
expenses in the near-term if the transmission facility will not need to
be in service in the near-term. The Commission also noted that a
transmission provider may make that Long-Term Regional Transmission
Facility's selection status subject to the outcomes of subsequent Long-
Term Regional Transmission Planning cycles, such that the previously
selected transmission facility is no longer needed. The Commission
proposed that transmission providers include in their selection
criteria how they will address the selection status of a previously
selected transmission facility based on the outcomes of subsequent
Long-Term Regional Transmission Planning cycles.\2226\
---------------------------------------------------------------------------
\2226\ Id. P 248.
---------------------------------------------------------------------------
b. Comments
1035. Some commenters argue that the Commission should allow or
require transmission providers to make the selection of a Long-Term
Regional Transmission Facility subject to the outcomes of subsequent
Long-Term Regional Transmission Planning cycles.\2227\ For example,
Kansas Commission contends that transmission providers should be able
to de-select any transmission facility selected through Long-Term
Regional Transmission Planning if other regional transmission planning
processes do not establish a need for that transmission facility.\2228\
Illinois Commission argues that periodic review and revision of the
underlying modeling assumptions incorporated in Long-Term Scenarios
will help to ensure that Long-Term Regional Transmission Planning
allows transmission providers the opportunity to modify regional
transmission plans.\2229\
---------------------------------------------------------------------------
\2227\ See, e.g., Ameren Initial Comments at 20-21 (citing NOPR,
179 FERC ] 61,028 at P 248).
\2228\ Kansas Commission Initial Comments at 14.
\2229\ Illinois Commission Initial Comments at 6.
---------------------------------------------------------------------------
1036. APPA supports the NOPR proposal, stating that ``off ramps''
from Long-Term Regional Transmission Planning are necessary to protect
customers from the costs of transmission facilities that are rendered
unneeded or inefficient by material changes in available resources,
technology, load characteristics, or laws.\2230\ APPA continues that
the Commission should also require transmission providers to include in
their selection criteria how they will address the selection status of
previously selected transmission facilities in subsequent transmission
planning cycles. APPA further argues that, to facilitate such review,
the Commission should require transmission providers to have clear
mechanisms for tracking costs and benefits of Long-Term Regional
Transmission Facilities and to file periodic cost tracking reports with
the Commission so that stakeholders have an opportunity to
comment.\2231\
---------------------------------------------------------------------------
\2230\ APPA Initial Comments at 22 (citing APPA ANOPR Initial
Comments at 9-10; APPA ANOPR Reply Comments at 4; APPA, et al.,
Statement of Bryce Nielsen, Docket No. RM21-17-000, at 2 (filed Nov.
12, 2021)).
\2231\ Id. at 35-36.
---------------------------------------------------------------------------
1037. LS Power argues that transmission providers should perform
``variance analyses'' of all previously selected regional transmission
facilities.\2232\ LS Power contends that all variations in costs, from
the initial regional planning estimate through project completion,
should be maintained in a single publicly available database.\2233\
---------------------------------------------------------------------------
\2232\ LS Power Supplemental Comments at 13-15.
\2233\ Id. at 13.
---------------------------------------------------------------------------
1038. Certain TDUs argue that the Commission should require each
transmission provider, at the time it selects a transmission facility
that is expected to be in service more than three years later, (1) to
identify the key assumptions that drove its inclusion in the regional
transmission plan and (2) to review triennially whether those key
assumptions remain valid or have materially changed. To promote
customer affordability by avoiding over-building or under-building
transmission facilities, Certain TDUs contend that if these key
assumptions have materially changed, the Commission should require
transmission providers to evaluate whether any revisions are necessary
with respect to such transmission facilities.\2234\
---------------------------------------------------------------------------
\2234\ Certain TDUs Initial Comments at 20.
---------------------------------------------------------------------------
1039. Large Public Power argues that, following selection of
transmission facilities in Long-Term Regional Transmission Planning,
the Commission should require transmission providers to create a cost
and risk management framework. Specifically, Large Public Power argues
that the Commission should require transmission providers to develop
and implement protocols requiring the developer of a transmission
facility to file periodic reports with the Commission tracking
anticipated project costs against cost projections and updating
benefits information. In the period before construction begins, if such
reports indicate that anticipated costs have exceeded an identified
threshold, or that benefit-cost ratios have declined by an identified
percentage, Large Public Power states that stakeholders could consider
remedial action and the transmission developer could present
stakeholders with mitigation plans. Further, if stakeholders do not
reach consensus on the developer's mitigation plan, Large Public Power
argues that stakeholders could petition the Commission to disallow
regional cost allocation for the transmission facility. Finally, under
Large Public Power's proposal, if the Commission disallowed regional
cost allocation, the transmission developer would be eligible for
abandoned plant cost recovery in the absence of imprudence.\2235\
---------------------------------------------------------------------------
\2235\ Large Public Power Initial Comments at 11-12.
---------------------------------------------------------------------------
1040. Large Public Power argues that its proposal would provide
more protection to consumers than did Order No. 1000. Large Public
Power further contends that its proposal is similar to, but more
expansive than, MISO's existing variance analysis process, and that it
would work together with the Commission's proposal to allow
transmission providers to make the selection of a Long-Term Regional
Transmission Facility subject to the outcome of subsequent Long-Term
Regional Transmission Planning cycles.\2236\ APPA agrees with Large
Public Power's proposal and argues that all interested stakeholders
should have the opportunity to participate in any
[[Page 49443]]
process to reassess previously approved transmission projects.\2237\
---------------------------------------------------------------------------
\2236\ Id. (citing NOPR, 179 FERC ] 61,028 at P 248; Order No.
1000, 136 FERC ] 61,051 at PP 7, 263, 329; MISO, FERC Electric
Tariff, MISO OATT, attach. FF (Transmission Expansion Planning
Protocol) (90.0.0)).
\2237\ APPA Reply Comments at 11-12 (citing Large Public Power
Initial Comments at 11-12).
---------------------------------------------------------------------------
1041. New York Commission and NYSERDA state that, while
transmission providers can identify transmission needs using a 20-year
transmission planning horizon, transmission facilities should be
selected closer in time to when the need is anticipated to materialize.
New York Commission and NYSERDA state the final order should direct
transmission providers to develop ``off ramps'' in Long-Term Regional
Transmission Planning so that previously identified Long-Term Regional
Transmission Facilities can be reevaluated as the facility's needed-by
date approaches. New York Commission and NYSERDA state that conducting
ongoing review can help reduce the risk of stranded costs.\2238\
---------------------------------------------------------------------------
\2238\ New York Commission and NYSERDA Initial Comments at 12.
---------------------------------------------------------------------------
1042. NRECA contends that selecting transmission projects 20 years
in advance is not necessary or even workable. NRECA contends that under
the Commission's proposal, transmission providers would select Long-
Term Regional Transmission Facilities conditionally and wait until a
subsequent Long-Term Regional Transmission Planning cycle to confirm
that selection decision, at which point the transmission developer
would become eligible to use the applicable regional cost allocation
method. NRECA argues that the Commission should allow a transmission
provider during such a subsequent cycle to find that a previously
selected transmission facility is no longer needed, either because the
transmission need no longer exists or because the facility is no longer
the most efficient or cost-effective solution to meet the need.\2239\
---------------------------------------------------------------------------
\2239\ NRECA Initial Comments at 25-26 (citing NOPR, 179 FERC ]
61,028 at P 248).
---------------------------------------------------------------------------
1043. ISO-NE takes no position on the Commission's proposal but
argues that the Commission should allow transmission providers the
flexibility to determine the treatment of previously selected
transmission projects based on outcomes of subsequent Long-Term
Regional Transmission Planning cycles.\2240\
---------------------------------------------------------------------------
\2240\ ISO-NE Initial Comments at 36.
---------------------------------------------------------------------------
1044. A number of commenters oppose or express concerns with the
Commission's proposal to allow transmission providers to make the
selection of a Long-Term Regional Transmission Facility subject to the
outcome of subsequent Long-Term Regional Transmission Planning cycles.
For example, AEP argues that, once selected through Long-Term Regional
Transmission Planning, transmission providers should include
transmission facilities in future scenario analysis except where a new
study raises serious doubt that the transmission facilities continue to
provide net benefits. AEP contends that re-studying such transmission
facilities will lead to an endless cycle of study and ultimately
underinvestment in necessary transmission infrastructure, as well as
increased costs for customers.\2241\ Similarly, Indicated PJM TOs argue
that, once selected, transmission facilities should remain in the
regional transmission plan unless there is serious doubt a transmission
facility would provide net benefits.\2242\
---------------------------------------------------------------------------
\2241\ AEP Initial Comments at 13-14.
\2242\ Indicated PJM TOs Initial Comments at 11.
---------------------------------------------------------------------------
1045. Avangrid argues that there must be a high bar in subsequent
Long-Term Regional Transmission Planning cycles for removing a
previously selected transmission facility from the regional
transmission plan because transmission developers must have confidence
that selection in Long-Term Regional Transmission Planning represents a
``definitive directive[ ] to invest capital.'' \2243\ Avangrid states
that transmission facilities should not be de-selected unless there are
changed circumstances that would make continued development of the
project materially detrimental. Avangrid argues that otherwise, Long-
Term Regional Transmission Planning effectively will be an
informational exercise on which investors cannot rely.\2244\
---------------------------------------------------------------------------
\2243\ Avangrid Initial Comments at 11.
\2244\ Id.
---------------------------------------------------------------------------
1046. Eversource recommends that the Commission clarify that once
transmission facilities are selected in a Long-Term Regional
Transmission Planning cycle, they will not be subject to reevaluation,
because such reevaluation would undermine the transmission planning
process and deter transmission investment that the Commission is
seeking to encourage.\2245\ Similarly, Exelon argues that the
Commission should clarify that the selection of transmission facilities
identified in Long-Term Regional Transmission Planning should be a
conclusive action that is reasonably final and on which transmission
developers can rely. Exelon explains that Long-Term Regional
Transmission Facilities are likely to be high-voltage backbone
facilities that meaningfully impact power flows on the transmission
system and argues that restudy or reconsideration should be the
exception and not the rule, allowing for their inclusion in system
planning models used for other purposes (e.g., regional transmission
planning addressing reliability and economic transmission needs and
generator interconnection studies).\2246\
---------------------------------------------------------------------------
\2245\ Eversource Initial Comments at 15-16.
\2246\ Exelon Initial Comments at 17-18.
---------------------------------------------------------------------------
1047. WIRES contends that the Commission should clarify that
transmission providers need not reevaluate previously selected Long-
Term Regional Transmission Facilities after updating Long-Term
Scenarios. WIRES claims that doing so would disrupt transmission
facility development and raise costs.\2247\ Similarly, PPL argues that
the Commission should exempt transmission facilities that are under
construction or for which equipment has been purchased from any
reevaluation in subsequent Long-Term Regional Transmission Planning
cycles.\2248\ Invenergy argues that while Long-Term Scenarios should be
regularly reassessed and updated, these updates should apply only to
future Long-Term Regional Transmission Planning cycles and should not
result in re-assessment of previously selected transmission
facilities.\2249\
---------------------------------------------------------------------------
\2247\ WIRES Initial Comments at 7.
\2248\ PPL Initial Comments at 6.
\2249\ Invenergy Initial Comments at 4-5 (citing NOPR, 179 FERC
] 61,028 at app. B).
---------------------------------------------------------------------------
c. Commission Determination
1048. We adopt the NOPR proposal, with modification, to require
transmission providers in each transmission planning region to include
in their OATTs provisions that require them--in certain circumstances--
to reevaluate Long-Term Regional Transmission Facilities that
previously were selected. These OATT provisions must meet the
requirements set forth below, as well as the minimum requirements for
transmission providers' broader evaluation process and selection
criteria described above in the Minimum Requirements section.
1049. Specifically, we direct transmission providers to revise
their OATTs to require reevaluation of any selected Long-Term Regional
Transmission Facilities in the following three situations, subject to
limitations that we set forth below: (1) delays in the development of a
previously selected Long-Term Regional Transmission Facility would
jeopardize a transmission provider's ability to meet its reliability
needs or reliability-related service obligations; \2250\ (2) the actual
or
[[Page 49444]]
projected costs of a previously selected Long-Term Regional
Transmission Facility significantly exceed cost estimates used in the
selection of a Long-Term Regional Transmission Facility; or (3)
significant changes in Federal, federally-recognized Tribal, state, or
local laws or regulations cause reasonable concern that a previously
selected Long-Term Regional Transmission Facility may no longer meet
the transmission providers' selection criteria.\2251\
---------------------------------------------------------------------------
\2250\ We note that this is the same as the requirement adopted
in Order No. 1000. See Order No. 1000, 136 FERC ] 61,051 at P 329;
Order No. 1000-A, 139 FERC ] 61,132 at P 442; NOPR, 179 FERC ]
61,028 at P 247 & n.395.
\2251\ NOPR, 179 FERC ] 61,028 at P 248.
---------------------------------------------------------------------------
1050. In addition, we require transmission providers to include
specific criteria in their OATTs that they will use to determine when
one of these three situations occurs, thereby triggering the
reevaluation of a previously selected Long-Term Regional Transmission
Facility. For example, with respect to exceeding cost estimates (the
second situation listed above), transmission providers may propose a
specific threshold of cost escalation (e.g., a percent of total
facility cost) above which the transmission providers would reevaluate
a previously selected Long-Term Regional Transmission Facility. As
another example, with respect to delays (the first situation listed
above), transmission providers may propose specific development
milestones that, if missed, may jeopardize the transmission developer's
schedule and ultimately a transmission provider's ability to meet its
reliability needs or reliability-related service obligations. We
provide transmission providers with flexibility to propose these
criteria on compliance, subject to the requirement that, as with the
transmission providers' selection criteria, the reevaluation criteria
must seek to maximize benefits accounting for costs over time without
over-building transmission facilities. As such, in establishing such
criteria, we expect transmission providers will balance the need to
provide transmission developers with adequate investment certainty,
absent which more efficient or cost-effective Long-Term Regional
Transmission Facilities will not be developed, against the risk that,
due to significant changes in circumstances, failing to reevaluate a
selected Long-Term Regional Transmission Facility may result in the
over-building of transmission. In addition, transmission providers must
designate a point after which all selected Long-Term Regional
Transmission Facilities will no longer be subject to reevaluation, such
that the transmission developer of the selected Long-Term Regional
Transmission Facility has adequate certainty to make investment
decisions, e.g., when the facility's transmission developer has secured
all relevant permits and authorizations for the Long-Term Regional
Transmission Facility.
1051. Further, as discussed further below, transmission providers
may not reevaluate any selected Long-Term Regional Transmission
Facility on the basis of significant changes in Federal, federally
recognized-Tribal, state, or local laws or regulations unless, during
the Long-Term Regional Transmission Planning cycle in which
transmission providers selected the Long-Term Regional Transmission
Facility, the Long-Term Regional Transmission Facility's targeted in-
service date was in the latter half of the 20-year transmission
planning horizon for Long-Term Regional Transmission Planning.
1052. We also require transmission providers to include in the
reevaluation provisions in their OATTs the process and procedures that
they will use to reevaluate a previously selected Long-Term Regional
Transmission Facility, including the potential outcomes of reevaluation
(e.g., taking no action, imposing a mitigation plan, reassigning the
Long-Term Regional Transmission Facility to a different transmission
developer, modifying the Long-Term Regional Transmission Facility,
removing the Long-Term Regional Transmission Facility from the regional
transmission plan).\2252\ In particular, transmission providers must
describe the conditions under which they would remove a previously
selected Long-Term Regional Transmission Facility from the regional
transmission plan.\2253\ We provide flexibility to transmission
providers to propose such processes and procedures, subject to the
following requirements. First, reevaluation on the basis of cost
increases or significant changes in Federal, federally-recognized
Tribal, state, or local laws or regulations must be part of a
subsequent Long-Term Regional Transmission Planning cycle following
selection and must take into account not only the updated costs but
also the updated benefits of the Long-Term Regional Transmission
Facility.\2254\ Second, in order to allow for reevaluation to occur,
these processes and procedures must include mechanisms for tracking
costs so that transmission providers have an accurate way to determine
if the actual or projected costs of the previously selected Long-Term
Regional Transmission Facility exceed cost estimates by the relevant
threshold, therefore requiring transmission providers to reevaluate
that Long-Term Regional Transmission Facility. Third, the reevaluation
processes and procedures must seek to maximize benefits accounting for
costs over time without over-building transmission facilities. Again,
we expect transmission providers in establishing these processes and
procedures, including potential mitigation measures, to consider
outcomes that enable more efficient or cost-effective Long-Term
Regional Transmission Facilities to be developed, while addressing the
risk of over-building.
---------------------------------------------------------------------------
\2252\ See, e.g., MISO, FERC Electric Tariff, MISO OATT, attach.
FF (Transmission Expansion Planning Protocol) (90.0.0), Sec. IX.E
(setting forth potential outcomes of MISO's variance analysis
procedures). Mitigation plans would provide to transmission
developers the opportunity to address the cause of the reevaluation.
For example, where reevaluation occurs because there are delays in
the development of a previously selected Long-Term Regional
Transmission Facility, transmission providers might require the
transmission developer to develop an operating procedure to ensure
that the transmission providers are able to address the reliability
need or meet the reliability-related service obligation in the
period before the Long-Term Regional Transmission Facility will be
placed in service.
\2253\ We note that, in the event that the Long-Term Regional
Transmission Facility was subject to competitive processes when it
was selected, we do not require transmission providers to re-conduct
these competitive processes in the event that the reevaluation
process results in a change to the scope of the Long-Term Regional
Transmission Facility. Instead, transmission providers have the
flexibility to propose on compliance and explain whether, and if so
when, they will re-run the competitive transmission development
process as part of the reevaluation process.
\2254\ Further, to perform the reevaluation analysis, we expect
that transmission providers will use the updated Long-Term Scenarios
and associated transmission system models that are developed for the
Long-Term Regional Transmission Planning cycle in which the
transmission provider reevaluates the selected Long-Term Regional
Transmission Facility.
---------------------------------------------------------------------------
1053. We note that in setting forth these requirements, we have
carefully reviewed the record developed here and weighed commenters'
countervailing arguments. We believe that the reevaluation requirements
set forth above strike a careful balance between two broad objectives
of Long-Term Regional Transmission Planning. On the one hand, we
believe that transmission providers must have the opportunity to select
more efficient or cost-effective Long-Term Regional Transmission
Facilities, which requires sufficiently long-term, forward-looking, and
comprehensive regional transmission planning practices. Moreover, for
selection to meaningfully result in the development of such more
efficient or cost-effective Long-Term Regional
[[Page 49445]]
Transmission Facilities, it must provide adequate certainty to
transmission developers to support capital investment.
1054. On the other hand, we also acknowledge the inherent
uncertainty involved in predicting future transmission needs, and the
continued selection of Long-Term Regional Transmission Facilities that
no longer meet the transmission providers' selection criteria closer to
the time that those facilities are expected to go into service could be
costly for consumers. Where transmission providers have selected Long-
Term Regional Transmission Facilities further out in the transmission
planning horizon, and where transmission providers timely obtain
updated information about significant changes to the costs or benefits
of such facilities, we believe that transmission providers must,
consistent with the requirements in this final order, reevaluate a
selected Long-Term Regional Transmission Facility in order to ensure
that the facility continues to meet the transmission providers'
selection criteria.
1055. In the NOPR, the Commission attempted to balance these
objectives by proposing that, because the required development schedule
of a previously selected Long-Term Regional Transmission Facility may
not require its transmission developer to take actions or incur
expenses in the near-term, transmission providers might be able to make
the selection status of a previously selected Long-Term Regional
Transmission Facility subject to the outcome of subsequent Long-Term
Regional Transmission Planning cycles.\2255\ On further reflection,
however, and after reviewing comments submitted in response to the
NOPR,\2256\ we find that conditioning the selection of a Long-Term
Regional Transmission Facility in this manner and on a routine basis
may introduce too much uncertainty into transmission providers'
evaluation and selection of Long-Term Regional Transmission
Facilities.\2257\ We agree with AEP that routine reevaluation would
require repeated studies and ultimately could lead to underinvestment
in Long-Term Regional Transmission Facilities that more efficiently or
cost-effectively address Long-Term Transmission Needs.\2258\ Therefore,
we do not adopt the NOPR proposal to allow transmission providers to
make the selection status of a previously selected Long-Term Regional
Transmission Facility subject to the outcome of subsequent Long-Term
Regional Transmission Planning cycles.
---------------------------------------------------------------------------
\2255\ NOPR, 179 FERC ] 61,028 at P 248.
\2256\ See, e.g., Exelon Initial Comments at 17-18 (arguing that
selection should be ``reasonably final'' and that routine
reevaluation would harm the certainty required for developing Long-
Term Regional Transmission Facilities, inhibit efficient
interconnection queue processing, and undermine system reliability
as a whole).
\2257\ For this reason, we are unpersuaded by NRECA's argument
that transmission providers should conditionally select Long-Term
Regional Transmission Facilities subject to confirmation in a
subsequent Long-Term Regional Transmission Planning cycle. NRECA
Initial Comments at 25-26 (citing NOPR, 179 FERC ] 61,028 at P 248).
\2258\ See AEP Initial Comments at 13-14.
---------------------------------------------------------------------------
1056. Nevertheless, we continue to believe that transmission
providers may be reticent to select--and Relevant State Entities and
other stakeholders may not support the selection of--certain Long-Term
Regional Transmission Facilities in the absence of a requirement for
transmission providers to reevaluate the selection of such facilities
should significant new information become available that could give
rise to concerns that those facilities no longer meet the transmission
providers' selection criteria.\2259\ Further, as is required for
regional transmission planning processes under Order No. 1000,
transmission providers also must have the ability to take action when
delays in developing a Long-Term Regional Transmission Facility risk
jeopardizing a transmission provider's ability to meet its reliability
needs or reliability-related service obligations.\2260\
---------------------------------------------------------------------------
\2259\ See, e.g., APPA Initial Comments at 22 (arguing that
there should be ``off ramps'' protecting transmission customers from
Long-Term Regional Transmission Facilities that, following
selection, are rendered unnecessary or inefficient by intervening
changes (citations omitted)).
\2260\ Order No. 1000, 136 FERC ] 61,051 at P 329; Order No.
1000-A, 139 FERC ] 61,132 at P 442.
---------------------------------------------------------------------------
1057. As discussed above, selection of a Long-Term Regional
Transmission Facility is only one step in the process of developing,
constructing, and placing that facility in service for the benefit of
customers. Given the risks involved in transmission development, it is
necessary to provide sufficient certainty to transmission developers
and their financing partners that reevaluation will not lead to endless
studies and protracted dispute. Therefore, we require transmission
providers to set forth in their OATTs a reevaluation process, as
outlined above, that ensures that any reevaluation of Long-Term
Regional Transmission Facilities that have been selected will occur
only in the circumstances that we have described.
1058. We agree with APPA that reevaluation--and in particular any
determination of whether a Long-Term Transmission Need continues to
exist or whether a Long-Term Regional Transmission Facility continues
to meet the transmission providers' selection criteria--will require
transmission providers to be able to track the costs of developing
Long-Term Regional Transmission Facilities.\2261\ We note above that
transmission providers must propose on compliance the mechanism that
they will use to track the costs of selected Long-Term Regional
Transmission Facilities.
---------------------------------------------------------------------------
\2261\ APPA Initial Comments at 36.
---------------------------------------------------------------------------
1059. As discussed above, however, we note that, when conducting a
reevaluation of a selected Long-Term Regional Transmission Facility,
transmission providers must update not only actual and projected costs
but also their calculation of the benefits of the selected Long-Term
Regional Transmission Facility. Such a requirement will ensure that
transmission providers are comparing the relevant costs and benefits,
i.e., the updated costs and benefits of the selected Long-Term Regional
Transmission Facility, to determine whether the Long-Term Regional
Transmission Facility continues to be a more efficient or cost-
effective regional transmission solution to Long-Term Transmission
Needs. Because updating the calculation of the benefits of a Long-Term
Regional Transmission Facility is not as straightforward as tracking
costs, we require reevaluation on the basis of cost escalations or of
changes in Federal, federally-recognized Tribal, state, or local laws
and regulations to occur as part of a subsequent Long-Term Regional
Transmission Planning cycle. We find that this requirement is
appropriate given the substantial time and resources that we expect
will be necessary to update the underlying assumptions used in the
transmission planning models, which must take place in order to update
the calculation of the benefits of selected Long-Term Regional
Transmission Facilities for purposes of such reevaluations. Requiring
transmission providers to update these assumptions and their
transmission planning models, including all Long-Term Scenarios and any
associated sensitivities, beyond a subsequent Long-Term Regional
Transmission Planning cycle would introduce unnecessary disruptions and
potentially impede the efficient conduct of the next Long-Term Regional
Transmission Planning cycle.
1060. In response to Kansas Commission, we decline to allow
transmission providers to remove a Long-Term Regional Transmission
Facility from a regional transmission
[[Page 49446]]
plan for purposes of cost allocation solely because other regional
transmission planning processes do not establish a need for that
transmission facility.\2262\ Long-Term Regional Transmission Planning
and existing Order No. 1000 regional transmission planning processes
identify transmission needs differently, and we do not agree based on
the requirements that we establish in this final order for Long-Term
Regional Transmission Planning that reevaluation based solely on
transmission needs identified through existing Order No. 1000 regional
transmission planning processes is appropriate. We also decline Certain
TDUs' request that the Commission require transmission providers to
identify certain key assumptions driving the selection of Long-Term
Regional Transmission Facilities and to review these assumptions in
subsequent Long-Term Regional Transmission Planning cycles. Long-Term
Regional Transmission Planning will necessitate that transmission
providers compile a wide range of information from multiple data
sources, analyze the effect of that information, develop Long-Term
Scenarios that provide a view into what Long-Term Transmission Needs
may be, and evaluate Long-Term Regional Transmission Facilities in
light of these multiple different scenarios. In this light, we believe
that Certain TDUs' suggested approach would not capture the complex
interactions of the various factors giving rise to Long-Term
Transmission Needs.
---------------------------------------------------------------------------
\2262\ See Kansas Commission Initial Comments at 14.
---------------------------------------------------------------------------
1061. Finally, we note that a coalition of diverse interests,
including transmission developer, utility, and consumer interests,
jointly expressed support for a framework that would provide for
reconsideration of a Long-Term Regional Transmission Facility where
cost and benefit projections deviate substantially from those at the
time of selection.\2263\ We appreciate such efforts to bridge divergent
interests to find common ground in a compromise proposal, and believe
that the reevaluation requirements adopted here, like that widely
supported compromise, strike a balance between competing interests.
---------------------------------------------------------------------------
\2263\ See Advocates Advance Transmission Planning Cost
Management Proposal At FERC, Large Public Power Council (Mar. 6,
2024), https://www.lppc.org/news/lppc-and-advocacy-groups-advance-transmission-planning-cost-management-proposal-at-ferc (describing
endorsements by LPPC, ACEG, CEBA, and NASUCA).
---------------------------------------------------------------------------
F. Implementation of Long-Term Regional Transmission Planning
1. NOPR Proposal
1062. In the NOPR, the Commission proposed to require transmission
providers to explain on compliance how the initial timing sequence for
Long-Term Regional Transmission Planning interacts with existing
regional transmission planning efforts. The Commission stated that it
recognized the possibility that there may be overlap in the time
horizon for the proposed Long-Term Regional Transmission Planning and
existing near-term regional transmission planning processes and that
they will likely inform each other.\2264\ The Commission also stated
that it is possible that, in some cases, transmission facilities
selected to address transmission needs driven by changes in the
resource mix and demand may provide near-term reliability or economic
benefits, and thus potentially displace regional transmission
facilities that are under consideration as part of existing regional
transmission planning processes.
---------------------------------------------------------------------------
\2264\ NOPR, 179 FERC ] 61,028 at P 253.
---------------------------------------------------------------------------
1063. In the NOPR, the Commission also sought comment on whether
the Commission should host a periodic forum for transmission providers,
transmission experts, relevant Federal and state agencies, and other
stakeholders to share best practices in implementing Long-Term Regional
Transmission Planning.\2265\
---------------------------------------------------------------------------
\2265\ Id. P 255.
---------------------------------------------------------------------------
2. Comments
a. Comments on the Initial Timing Sequence
1064. Several commenters support requiring transmission providers
to explain on compliance how Long-Term Regional Transmission Planning
will interact with existing Order No. 1000 regional transmission
planning processes.\2266\ Several commenters urge the Commission to
allow regional flexibility with respect to coordination between
existing Order No. 1000 regional transmission planning processes and
Long-Term Regional Transmission Planning.\2267\ NESCOE argues that it
could be counterproductive and unnecessary for the Commission to
dictate the initial timing of new processes to coordinate them with
existing Order No. 1000 regional transmission planning processes.\2268\
PPL stresses the need for clarity on how the existing Order No. 1000
regional transmission planning processes interacts with Long-Term
Regional Transmission Planning and states that each transmission
planning region will need to address how planned reliability and
economic projects should or should not be reflected in, evaluated
against, and affected by long-term studies.\2269\
---------------------------------------------------------------------------
\2266\ Ameren Initial Comments at 22-23; APPA Initial Comments
at 5, 24-25; Idaho Commission Initial Comments at 5; National Grid
Initial Comments at 19; NYISO Initial Comments at 13.
\2267\ Ameren Initial Comments at 22-23; Duke Initial Comments
at 29; NARUC Initial Comments at 33; National Grid Initial Comments
at 19; NESCOE Initial Comments at 51-52; NYISO Initial Comments at
13; Pacific Northwest State Agencies Initial Comments at 20.
\2268\ NESCOE Initial Comments at 51-52.
\2269\ PPL Initial Comments at 4.
---------------------------------------------------------------------------
1065. R Street states that the NOPR correctly identifies challenges
in harmonizing existing Order No. 1000 and Long-Term Regional
Transmission Planning. R Street argues that the two processes should
use different time frames and assumptions, with timing optimized to
account for uncertainty. R Street maintains that existing Order No.
1000 transmission planning should be conducted annually over a
transmission planning horizon of up to five years and should account
for only those generators that are existing, under construction, or
have interconnection agreements. R Street states that Long-Term
Regional Transmission Planning should be conducted every two or three
years over a 20-year transmission planning horizon and should account
for representative generation development expectations and longer-term
load growth. R Street posits that the long-term process should then
feed into the near-term process, and transmission projects failing a
cost-benefit test in one transmission planning cycle can roll over to
the next in-kind cycle.\2270\
---------------------------------------------------------------------------
\2270\ R Street Initial Comments at 10-11.
---------------------------------------------------------------------------
1066. PIOs contend that the different timing for Order No. 1000
transmission planning process cycles across transmission planning
regions can create inconsistent assumptions, uncoordinated project
identification between the two processes, confusion, and administrative
burden.\2271\ To address this concern, PIOs assert that the Commission
should: (1) mandate Order No. 1000 regional transmission planning
process cycles be no longer than Long-Term Regional Transmission
Planning cycles and if shorter, divide Long-Term Regional Transmission
Planning cycles evenly; \2272\ (2) synchronize assumptions so that
assumptions are identical for years
[[Page 49447]]
where both a Long-Term Regional Transmission Planning cycle and an
existing Order No. 1000 regional transmission planning cycle start; (3)
clarify the time period for existing Order No. 1000 regional
transmission planning for economic and reliability needs; and (4)
require transmission providers to clarify when results of one
transmission planning process are incorporated into another, and
require reasonable efforts to avoid one process disrupting the
other.\2273\
---------------------------------------------------------------------------
\2271\ PIOs Initial Comments at 47.
\2272\ As an example, if a transmission provider uses a 36-month
Long-Term Regional Transmission Planning cycle, its Order No. 1000
transmission planning cycles should be 36, 18, or 12 months. Id.
\2273\ Id. at 48-49.
---------------------------------------------------------------------------
b. Comments on Periodic Forums
1067. Several commenters support the Commission's proposal to host
a periodic forum for transmission providers, transmission experts,
relevant Federal and state agencies, and other stakeholders to share
best practices in implementing Long-Term Regional Transmission
Planning.\2274\ For example, AEP states that periodic forums would
allow stakeholders to discuss best available data, modeling inputs, and
techniques for calculating benefits.\2275\ GridLab states that a
periodic forum, along with follow-on technical conferences and a
periodic forum, could promote greater convergence in planning methods
among transmission providers.\2276\
---------------------------------------------------------------------------
\2274\ ACORE Initial Comments at 15; AEP Initial Comments 6, 31;
Arizona Commission Initial Comments at 9; GridLab Initial Comments
at 3, 5, 19-20; Idaho Commission Initial Comments at 5; NARUC
Initial Comments at 34; NESCOE Initial Comments at 52; Nevada
Commission Initial Comments at 12; Northwest and Intermountain
Initial Comments at 9, 17; NYISO Initial Comments at 14; Pacific
Northwest State Agencies Initial Comments at 20; PJM Initial
Comments at 7, 77; R Street Initial Comments at 11; SDG&E Initial
Comments at 4; SPP Initial Comments at 24; US DOE Initial Comments
at 35-36.
\2275\ AEP Initial Comments at 31.
\2276\ GridLab Initial Comments at 5.
---------------------------------------------------------------------------
1068. Pacific Northwest State Agencies suggest that the Commission
could hold technical conferences or regional sessions similar to the
Federal State Task Force on Electric Transmission.\2277\ In contrast,
PJM states that the periodic forum should be less formal than the
technical conference format and that the Commission should consider
using existing interconnection-wide organizations to host some of these
forums.\2278\ SPP also notes that there are existing forums that could
be leveraged, such as the Eastern Interconnection Planning
Collaborative.\2279\
---------------------------------------------------------------------------
\2277\ Pacific Northwest State Agencies Initial Comments at 20.
\2278\ PJM Initial Comments at 77.
\2279\ SPP Initial Comments at 24.
---------------------------------------------------------------------------
1069. Some commenters recommend that the forums be held on an
annual or a triennial schedule.\2280\ MISO notes that, while the
current pace of change might warrant multiple technical discussions to
understand emerging trends, over the long term such technical forums
may only be necessary when new industry trends are identified.\2281\
Nevada Commission and Northwest and Intermountain suggest that the
forum could be structured into two parts, separated by policy and
technical discussion, by RTOs/ISOs and OATT transmission planning
regions, or by Eastern and Western Interconnection.\2282\
---------------------------------------------------------------------------
\2280\ AEP Initial Comments at 31; Arizona Commission Initial
Comments at 9; Nevada Commission Initial Comments at 12.
\2281\ MISO Initial Comments at 57.
\2282\ Nevada Commission Initial Comments at 12; Northwest and
Intermountain Initial Comments at 9, 17.
---------------------------------------------------------------------------
1070. Dominion and Idaho Power oppose the Commission hosting
additional periodic forums.\2283\ Dominion recommends that the
Commission use the existing Joint Federal-State Task Force on Electric
Transmission instead.\2284\ Idaho Power asserts that the most useful
approach would be to allow transmission planning regions the time
necessary to formulate processes that meet the Commission's
requirements, and additional time for implementation and integration of
those processes into current transmission planning processes.\2285\
---------------------------------------------------------------------------
\2283\ Dominion Initial Comments at 15-16; Idaho Power Initial
Comments at 8-9.
\2284\ Dominion Initial Comments at 15-16.
\2285\ Idaho Power Initial Comments at 8-9.
---------------------------------------------------------------------------
3. Commission Determination
a. Initial Timing Sequence Implementation
1071. We adopt the NOPR proposal to require transmission providers
to explain on compliance how the initial timing sequence for Long-Term
Regional Transmission Planning interacts with existing regional
transmission planning processes. Transmission providers must provide in
their explanations any information necessary to ensure that
stakeholders understand this interaction, including at least the
following two components. First, we find that transmission providers
must address the possible interaction between the transmission planning
cycle for Long-Term Regional Transmission Planning and existing Order
No. 1000 regional transmission planning processes. As the Commission
stated in the NOPR, we recognize the possibility that there may be
overlap in the time horizon for Long-Term Regional Transmission
Planning and existing Order No. 1000 regional transmission planning
processes and that these processes will likely inform each other.
Second, we find that transmission providers must address the possible
displacement of regional transmission facilities from the existing
regional transmission planning processes. As the Commission noted in
the NOPR, it is possible that, in some cases, Long-Term Regional
Transmission Facilities selected to address Long-Term Transmission
Needs may provide near-term reliability or economic benefits, and thus
could displace regional transmission facilities that are under
consideration as part of existing regional transmission planning
processes.\2286\
---------------------------------------------------------------------------
\2286\ NOPR, 179 FERC ] 61,028 at P 253.
---------------------------------------------------------------------------
1072. We find that transmission providers should have the
flexibility to integrate the existing regional transmission planning
processes with Long-Term Regional Transmission Planning in a manner
that mitigates the potential for disruption of the existing regional
transmission planning processes, and we note the agreement of some
commenters on this point.\2287\ However, we are also concerned that too
much flexibility for transmission providers with respect to the date by
which they must begin the first Long-Term Regional Transmission
Planning cycle could lead to unnecessary delay in realizing these
beneficial reforms for customers. Thus, we require transmission
providers in each transmission planning region to propose on compliance
a date, no later than one year from the date on which initial filings
to comply with this final order are due, on which they will commence
the first Long-Term Regional Transmission Planning cycle. However, we
understand that it will likely be useful to align in some manner the
Long-Term Regional Transmission Planning cycle with existing
transmission planning cycles. In some cases, such alignment may not be
possible to do within this one-year deadline. Therefore, transmission
providers in a transmission planning region may propose to start the
first Long-Term Regional Transmission Planning cycle on a date later
than one year from the initial compliance filing due date, only to the
extent needed to
[[Page 49448]]
align transmission planning cycles. While we encourage transmission
providers to align transmission planning cycles if useful, to ensure
that there is no inappropriate delay to starting Long-Term Regional
Transmission Planning, transmission providers in a transmission
planning region that propose a commencement date of later than one year
from the compliance due date must include adequate support explaining
how the proposed date to begin the first Long-Term Regional
Transmission Planning cycle is necessary and appropriately tailored for
their transmission planning region.
---------------------------------------------------------------------------
\2287\ Ameren Initial Comments at 22-23; Anbaric Initial
Comments at 4-5, 22-27; CAISO Initial Comments at 2-3, 9, 17-20;
Duke Initial Comments at 29; Indicated PJM TOs Initial Comments at
12; Large Public Power Initial Comments at 14-16; NARUC Initial
Comments at 33; National Grid Initial Comments at 19; NESCOE Initial
Comments at 51-52; NYISO Initial Comments at 13; PPL Initial
Comments at 4; Pacific Northwest State Agencies Initial Comments at
20; Transmission Dependent Utilities Initial Comments at 4-5.
---------------------------------------------------------------------------
1073. In addition, we recognize commenters' concerns regarding the
coordination of Long-Term Regional Transmission Planning and the
existing Order No. 1000 regional transmission planning processes, and
we encourage transmission providers to address in their explanation how
their proposed Long-Term Regional Transmission Planning would
facilitate moving beyond piecemeal transmission expansion to address
relatively near-term transmission needs and toward a more robust, well-
planned transmission system.\2288\
---------------------------------------------------------------------------
\2288\ See supra Need for Reform section.
---------------------------------------------------------------------------
1074. With respect to the argument by NESCOE that it would be
counterproductive and unnecessary for the Commission to dictate the
initial timing of new processes,\2289\ we disagree. We find that it is
necessary to establish a requirement for transmission providers to
propose on compliance a date, no later than one year from the date on
which initial filings to comply with this final order are due (subject
to the limited exception described above), on which they will commence
the first Long-Term Regional Transmission Planning Cycle, in order to
guarantee that implementation will not be subject to unreasonable or
unnecessary delay. With regard to the proposals made by PIOs and R
Street,\2290\ we decline to adopt these proposals because we lack the
record to assess the impacts that these more prescriptive proposed
requirements would have on existing transmission planning processes,
and whether these proposals would work effectively across the differing
transmission planning processes in each transmission planning region.
---------------------------------------------------------------------------
\2289\ NESCOE Initial Comments at 51-52.
\2290\ PIOs Initial Comments at 44-48; R Street Initial Comments
at 10-11.
---------------------------------------------------------------------------
b. Periodic Forums
1075. We believe that it will be beneficial for the Commission to
host a periodic forum for transmission providers, transmission experts,
relevant Federal and state agencies, and other stakeholders to share
best practices in implementing Long-Term Regional Transmission
Planning, and note commenters' agreement on this point.\2291\
Accordingly, the Commission will organize forums to share best
practices in implementing Long-Term Regional Transmission Planning and
provide notice and relevant details in advance of the forums.
---------------------------------------------------------------------------
\2291\ ACORE Initial Comments at 15; AEP Initial Comments 6, 31;
Arizona Commission Initial Comments at 9; GridLab Initial Comments
at 3, 5, 19-20; Idaho Commission Initial Comments at 5; NARUC
Initial Comments at 34; NESCOE Initial Comments at 52; Nevada
Commission Initial Comments at 12; Northwest and Intermountain
Initial Comments at 9, 17; NYISO Initial Comments at 14; Pacific
Northwest State Agencies Initial Comments at 20; PJM Initial
Comments at 7, 77; R Street Initial Comments at 11; SDG&E Initial
Comments at 4; SPP Initial Comments at 24; US DOE Initial Comments
at 35-36.
---------------------------------------------------------------------------
IV. Coordination of Regional Transmission Planning and Generator
Interconnection Processes
A. Need for Reform and Overall Reform
1. NOPR Proposal
1076. In the NOPR, the Commission proposed to require that
transmission providers consider, as part of their Long-Term Regional
Transmission Planning, regional transmission facilities that address
certain interconnection-related transmission needs that the
transmission provider has identified multiple times in the generator
interconnection process but that have never been constructed due to the
withdrawal of the underlying interconnection request(s).\2292\
---------------------------------------------------------------------------
\2292\ NOPR, 179 FERC ] 61,028 at P 166.
---------------------------------------------------------------------------
1077. The Commission preliminarily found that this requirement will
support the establishment of just and reasonable and not unduly
discriminatory or preferential Commission-jurisdictional rates by
addressing a potential barrier to integrating new sources of generation
that may otherwise continue to exist absent such requirement in the
regional transmission planning process.\2293\ As the Commission
explained in the NOPR, the interaction between regional transmission
planning and cost allocation processes and the generator
interconnection process is limited--the baseline regional transmission
planning models generally only incorporate interconnection projects
that have completed an interconnection facilities study and are
therefore near the end of the generator interconnection process.\2294\
The Commission stated, however, that where transmission system needs
are repeatedly identified through generator interconnection processes,
more efficient or cost-effective transmission expansion could be
achieved through regional transmission planning and cost allocation
that allocates costs in a manner that is at least roughly commensurate
with estimated benefits and eliminates a potential barrier to entry for
new generation resources.\2295\
---------------------------------------------------------------------------
\2293\ Id. P 168.
\2294\ Id. P 155 (citing ANOPR, 176 FERC ] 61,024 at P 23).
\2295\ Id. P 161.
---------------------------------------------------------------------------
1078. Additionally, the Commission sought comment on how the
proposed requirement to evaluate such facilities for selection should
interact with existing regional transmission planning processes and
Long-Term Regional Transmission Planning.\2296\
---------------------------------------------------------------------------
\2296\ Id. P 174.
---------------------------------------------------------------------------
2. Comments
a. On the Overall Reform
1079. Multiple commenters express support for the general notion of
coordinating the transmission planning and generator interconnection
processes.\2297\ Other commenters explicitly support the coordination
proposal laid out in the NOPR,\2298\ with some of these commenters
arguing that the NOPR proposal does not go far enough (as described
below).\2299\
---------------------------------------------------------------------------
\2297\ ACEG Initial Comments at 51-53; Clean Energy Buyers
Initial Comments at 19; DC and Maryland Office of People's Counsel
Initial Comments at 16; Fervo Reply Comments at 1; Handy Law Initial
Comments at 8-9; Interwest Initial Comments at 10-11; Invenergy
Initial Comments at 2; Ohio Commission Federal Advocate Initial
Comments at 8; PIOs Initial Comments at 72-73; R Street Initial
Comments at 7-8.
\2298\ ACEG Initial Comments at 51-53; California Commission
Initial Comments at 27; SDG&E Initial Comments at 3.
\2299\ Acadia Center and CLF Initial Comments at 25-26; ACORE
Initial Comments at 13.
---------------------------------------------------------------------------
1080. Other commenters offer more qualified support for the NOPR
proposal. APPA and Exelon see value in the proposal but emphasize that
any interconnection-related network upgrades that meet the specified
criteria must independently satisfy any other applicable criteria for
selection.\2300\ Similarly, NRECA requests that the Commission clarify
that interconnection-related network upgrades associated with withdrawn
interconnection requests will not receive preferential treatment in
Long-Term Regional Transmission Planning.\2301\ Clean Energy
Associations and ENGIE support the proposal but argue that the
Commission's concern could be more efficiently addressed
[[Page 49449]]
with better regional transmission planning.\2302\
---------------------------------------------------------------------------
\2300\ APPA Initial Comments at 31; Exelon Initial Comments at
11-13.
\2301\ NRECA Reply Comments at 10-11.
\2302\ Clean Energy Associations Initial Comments at 15; ENGIE
Initial Comments at 5.
---------------------------------------------------------------------------
b. Requesting Additional Reform
1081. Some commenters suggest that the NOPR proposal does not go
far enough to integrate the transmission planning and generator
interconnection processes or to improve interconnection-related network
upgrade cost allocation.\2303\ ACORE argues that more dramatic reforms
are necessary.\2304\ Anbaric contends that a planning assessment should
be conducted whenever an interconnection request triggers
interconnection-related network upgrades on the larger transmission
system beyond the interconnection substation and associated
facilities.\2305\ ELCON states that Long-Term Regional Transmission
Planning should be integrated with the generator interconnection
queue.\2306\ It suggests that the Commission hold regular workshops to
review best practices for coordinating the interconnection queue,
current regional transmission planning, and Long-Term Regional
Transmission Planning to reduce interconnection queue backlogs, leading
to larger regional transmission projects that would both incorporate
interconnection-related transmission needs and be eligible for
competitive bidding.\2307\
---------------------------------------------------------------------------
\2303\ Anbaric Initial Comments at 7-9; Clean Energy
Associations Initial Comments at 25-26; Concerned Scientists Initial
Comments at 21-22; ELCON Initial Comments at 13-14; Enel Initial
Comments at 4-5; Invenergy Initial Comments at 10-13; Invenergy
Reply Comments at 12-13; PIOs Initial Comments at 72-73; Shell Reply
Comments at 3-7.
\2304\ ACORE Initial Comments at 13.
\2305\ Anbaric Initial Comments at 7-8.
\2306\ ELCON Initial Comments at 13-14.
\2307\ Id. at 14-15.
---------------------------------------------------------------------------
1082. Similarly, Enel urges the Commission to consolidate the
generator interconnection process into the regional transmission
planning process to allow transmission providers to jointly assess the
benefits, and allocate the costs, of transmission projects that benefit
system loads and new generation.\2308\ Likewise, Shell suggests that
the Commission integrate Long-Term Regional Transmission Planning and
generator interconnection processes, requiring the use of the same
benefits analysis under the same criteria, including reliability,
economic, and public policy needs. Shell asserts that this approach
would: increase opportunities to reduce costs to produce power and
deliver it to load, unlock economies of scale and scope, improve
processing times for generator interconnection requests, address first
mover and free-rider risk, and potentially increase states' willingness
to participate in cost allocation.\2309\
---------------------------------------------------------------------------
\2308\ Enel Initial Comments at 4-5 (citing Enel, Plugging In: A
Roadmap for Modernizing & Integrating Interconnection and
Transmission Planning, https://www.enelgreenpower.com/content/dam/enel-egp/documenti/share/working-paper.pdf (last visited Apr.
2024)).
\2309\ Shell Reply Comments at 3, 5, 6-7.
---------------------------------------------------------------------------
1083. Acadia Center and CLF argue that the proposal does not fully
address shortfalls with the current method for cost allocation
associated with interconnection-related network upgrades.\2310\ They
also express concern that the NOPR proposal would address a limited
subset of generator interconnection needs and call for additional
changes to better allocate the costs of interconnection-related network
upgrades (especially those related to offshore wind development) to
regional beneficiaries.\2311\ Similarly, PIOs state the current cost
allocation for interconnection-related network upgrades violates
settled law that requires costs to be allocated both to cost causers
and beneficiaries.\2312\ Relatedly, Invenergy argues that the most
significant factor influencing an interconnection customer's decision
to leave the interconnection queue is typically the cost of assigned
interconnection-related network upgrades.\2313\
---------------------------------------------------------------------------
\2310\ Acadia Center and CLF Initial Comments at 25-26.
\2311\ Id. at 25.
\2312\ PIOs Initial Comments at 72.
\2313\ Invenergy Reply Comments at 14.
---------------------------------------------------------------------------
1084. Invenergy also argues that interconnection-related network
upgrades would remedy existing issues and should thus be addressed
through the regional transmission planning process.\2314\ Invenergy
asserts that some regions use different dispatch and other assumptions
in the regional transmission planning and generator interconnection
processes, which can result in persistent system overloads not being
addressed through the regional transmission planning process.\2315\
Similarly, Concerned Scientists aver that generator interconnection
requests could be 10 years old when the NOPR proposal designates the
related interconnection-related network upgrades as suitable for
consideration in future Long-Term Scenarios.\2316\ Concerned Scientists
argue that the Commission should require the inclusion in Long-Term
Scenarios of interconnection-related transmission needs that the
generator interconnection process identified multiple times.\2317\
---------------------------------------------------------------------------
\2314\ Id. at 12.
\2315\ Id.
\2316\ Concerned Scientists Reply Comments at 22.
\2317\ Id.
---------------------------------------------------------------------------
c. Concerns With the Overall Reform
1085. Some commenters oppose the Commission's proposal.\2318\ AEP,
Ameren, CAISO, and Utah Division of Public Utilities argue that the
proposal is unnecessary.\2319\ Duke argues that the Commission's
proposal is unnecessarily prescriptive, difficult to implement, and
risks introducing significant subjectivity and complex administration
into the transmission planning process.\2320\ Ameren claims the
proposal will result in inefficient regional transmission planning
because it will not minimize total cost to end-use customers.\2321\
---------------------------------------------------------------------------
\2318\ AEP Initial Comments at 6, 18; Ameren Initial Comments at
17; CAISO Initial Comments at 34; Duke Initial Comments at 4;
Illinois Commission Initial Comments at 8-9; MISO Initial Comments
at 44-47; PJM Initial Comments at 7, 85-86; PPL Initial Comments at
12.
\2319\ AEP Initial Comments at 18-20; Ameren Initial Comments at
18; CAISO Initial Comments at 6, 34-35; Utah Division of Public
Utilities Initial Comments at 7.
\2320\ Duke Initial Comments at 4, 20.
\2321\ Ameren Initial Comments at 18.
---------------------------------------------------------------------------
1086. Vistra argues that the NOPR proposal does not address how the
newly created interconnection capacity will be allocated and how the
timing and implementation of such upgrades would work.\2322\
---------------------------------------------------------------------------
\2322\ Vistra Initial Comments at 33-34.
---------------------------------------------------------------------------
1087. MISO contends that the Commission should not adopt
prescriptive rules for integrating the generator interconnection and
regional transmission planning processes, but instead continue to allow
the RTOs/ISOs to develop those processes that best fit their
footprint.\2323\ MISO argues that expanding the generator
interconnection process beyond its current five-year outlook would slow
the generator interconnection process.\2324\ MISO requests that if the
Commission does not eliminate the NOPR proposal, as MISO would prefer,
then the requirement should be altered so that transmission providers
would only be required to post a list of generator interconnection
upgrades that met the defined criteria.\2325\
---------------------------------------------------------------------------
\2323\ MISO Initial Comments at 44; MISO Reply Comments at 28.
\2324\ MISO Reply Comments at 29.
\2325\ MISO Initial Comments at 45.
---------------------------------------------------------------------------
1088. CAISO disagrees with California Commission's comments that
the NOPR proposal could improve CAISO's existing interconnection-
related network upgrade provisions because the two processes have
significantly different eligibility requirements,
[[Page 49450]]
purposes, and impacts.\2326\ CAISO further argues that the NOPR
proposal could require transmission planners to study only outdated
interconnection-related network upgrades.\2327\
---------------------------------------------------------------------------
\2326\ CAISO Reply Comments at 28-29 (citing California
Commission Initial Comments at 27).
\2327\ Id. at 32.
---------------------------------------------------------------------------
1089. Mississippi Commission states that interconnection-related
network upgrades should focus on reducing costs and providing price
signals and not be included in Long-Term Regional Transmission
Planning.\2328\
---------------------------------------------------------------------------
\2328\ Mississippi Commission Reply Comments at 9.
---------------------------------------------------------------------------
1090. Some commenters argue that it is incorrect to assume that
interconnection customers withdraw from the interconnection queue due
solely to high interconnection-related network upgrade costs instead of
other reasons \2329\ such as the project being uneconomic,\2330\ the
project having insufficient site control or permitting delays,\2331\
the project being speculative,\2332\ or some other regulatory or
economic factor.\2333\
---------------------------------------------------------------------------
\2329\ CAISO Reply Comments at 29; NRECA Reply Comments at 9;
PJM Initial Comments at 87.
\2330\ American Municipal Power Initial Comments at 33-34;
Indicated PJM TOs Initial Comments at 13-14; Pennsylvania Commission
Initial Comments at 8; Vistra Initial Comments at 20.
\2331\ Duke Initial Comments at 20-21; Idaho Power Initial
Comments at 6; Pennsylvania Commission Initial Comments at 8; PJM
Initial Comments at 88-89.
\2332\ Entergy Initial Comments at 25.
\2333\ PJM Initial Comments at 89.
---------------------------------------------------------------------------
1091. PJM recommends an alternative proposal for funding generation
interconnections in which states play the major role.\2334\ Under the
PJM proposal, states that want to incent generation interconnections,
perhaps to support a renewable portfolio standard, could fund a
backbone transmission system to help facilitate these
interconnections.\2335\
---------------------------------------------------------------------------
\2334\ Id. at 89-90.
\2335\ Id. at 90.
---------------------------------------------------------------------------
1092. Invenergy asks the Commission not to consider certain
alternative proposals advanced by other commenters.\2336\
---------------------------------------------------------------------------
\2336\ Invenergy Reply Comments at 15 (citing MISO Initial
Comments at 45; PJM Initial Comments 85, 90-92).
---------------------------------------------------------------------------
d. Cost Allocation
1093. Some commenters oppose the NOPR proposal on the assumption
that it could shift the cost for interconnection-related network
upgrades from interconnection customers to load.\2337\ In addition, PJM
states that the Commission's proposal could lead to undue
discrimination and would distort the price signal that generator
developers should see to make reasonable investment decisions.\2338\
Industrial Customers state that generators should be able to recover
the costs of interconnection through market revenues if their projects
are competitive.\2339\ Industrial Customers further argue that under
the cost causation principle, a new generator should pay for
interconnection-related network upgrades if such upgrades are only
required because of the generator's interconnection.\2340\ Vistra
asserts that, although the proposal shifts costs indirectly, the
Commission still must rationally explain its decision to depart from
the existing just and reasonable ``but-for'' policy of Order No.
2003.\2341\
---------------------------------------------------------------------------
\2337\ APPA Initial Comments at 31; Industrial Customers Initial
Comments at 13; NRECA Initial Comments at 41-42 (citation omitted);
NRECA Reply Comments at 8-9; PJM Initial Comments at 89-90; Vistra
Initial Comments at 8; Xcel Initial Comments at 15.
\2338\ PJM Initial Comments at 89.
\2339\ Industrial Customers Initial Comments at 13-14.
\2340\ Id. at 21-22.
\2341\ Vistra Initial Comments at 9 (citation omitted).
---------------------------------------------------------------------------
1094. Other commenters oppose the Commission's proposed reform
because it will increase the cost to serve load. AEP asserts that such
a proposal would possibly result in the development of unnecessary
transmission infrastructure, which would lead to increased transmission
customer costs for no benefit.\2342\ Dominion argues that this proposal
could result in over-building and excessive rates for transmission
customers.\2343\ TAPS asks the Commission to clarify that consideration
of interconnection-related transmission needs would not foreclose
transmission providers from proposing a cost allocation method that is
different from the cost allocation for other types of Long-Term
Regional Transmission Facilities.\2344\
---------------------------------------------------------------------------
\2342\ AEP Initial Comments at 20.
\2343\ Dominion Initial Comments at 32.
\2344\ TAPS Initial Comments at 13-14.
---------------------------------------------------------------------------
e. Interconnection Queue Gaming Considerations
1095. Several commenters express concerns that the NOPR proposal
would incentivize gaming by interconnection customers to promote
development of interconnection-related network upgrades through the
regional transmission planning process.\2345\ Some commenters claim
that the Commission's proposal could create a perverse incentive for
interconnection customers to submit and withdraw multiple
interconnection requests so that interconnection-related network
upgrades can be considered for regional cost allocation,\2346\
especially in transmission planning regions with lower thresholds for
entering and maintaining a position in the interconnection queue.\2347\
---------------------------------------------------------------------------
\2345\ Ameren Initial Comments at 18-19; American Municipal
Power Initial Comments at 34; Dominion Initial Comments at 32;
Dominion Reply Comments at 7-8; EEI Initial Comments at 18;
Eversource Initial Comments at 23-24; Idaho Power Initial Comments
at 6; Pennsylvania Commission Initial Comments at 9; PJM Initial
Comments at 89; PPL Initial Comments at 12-13; Shell Initial
Comments at 29-30; SPP Initial Comments at 16; Xcel Initial Comments
at 16.
\2346\ Ameren Initial Comments at 18; American Municipal Power
Initial Comments at 33-34; EEI Initial Comments at 18; Idaho Power
Initial Comments at 6; PJM Initial Comments at 89.
\2347\ EEI Initial Comments at 18.
---------------------------------------------------------------------------
1096. Pennsylvania Commission, Shell, Eversource, and US DOE
recommend the Commission modify the NOPR proposal to limit or prevent
gaming. Pennsylvania Commission argues that adding more commitments on
the part of the interconnection customer or requiring a more thorough
analysis of the reasons for withdrawal is an appropriate way of
addressing the concern.\2348\ Shell states that, to prevent gaming, the
Commission should revise its proposal so that an upgrade is only
eligible for inclusion in the Long-Term Regional Transmission Plan if
it appears in one generator interconnection study cycle over a five-
year period.\2349\ Eversource asks the Commission to find that
submitting and withdrawing interconnection requests simply so that the
required interconnection-related network upgrades would be identified
twice in the operative period, for example, would violate the
Commission's regulations, including but not limited to the duty of
candor and the prohibition of market manipulation.\2350\ US DOE states
that the Commission should strive to ensure that the reforms do not
create the potential for gaming by generators, which, absent
mitigation, could increase delays and backlogs in the interconnection
queue.\2351\
---------------------------------------------------------------------------
\2348\ Pennsylvania Commission Initial Comments at 9.
\2349\ Shell Initial Comments at 30.
\2350\ Eversource Initial Comments at 23-24 (citing 18 CFR
35.41; 18 CFR 1c.2)
\2351\ US DOE Initial Comments at 27-28.
---------------------------------------------------------------------------
1097. In response, Interwest argues that suggestions that increased
coordination would result in gaming assumes that developers know in
advance what interconnection-related network upgrades they will be
assigned through the interconnection process.\2352\ Interwest argues
that, given the uncertainty about whether, and when, such a process
could apply and result in selection and construction of facilities
under Long-Term Regional
[[Page 49451]]
Transmission Planning, it would not incentivize gaming.\2353\
Similarly, Invenergy argues that developers would have no reasonable
expectation that any interconnection-related network upgrade meeting
the NOPR criteria ultimately would be selected through the multi-year
regional transmission planning process and actually constructed on a
timeline that accommodates the developer's generation facility.\2354\
If the Commission is concerned about possible gaming, however,
Invenergy urges the Commission to revise the proposal to require that
withdrawn interconnection requests must have been submitted by
unaffiliated entities.\2355\
---------------------------------------------------------------------------
\2352\ Interwest Reply Comments at 5-6 (citing EEI Initial
Comments at 18).
\2353\ Id. at 6.
\2354\ Invenergy Reply Comments at 14.
\2355\ Id. at 14-15.
---------------------------------------------------------------------------
f. Miscellaneous
1098. SEIA asks the Commission to clarify that the phrase
``interconnection-related transmission needs'' would allow transmission
providers to include either individual or aggregated transmission
solutions that address specific needs.\2356\ SEIA asks the Commission
to require transmission providers to assume that these interconnection-
related network upgrades will be built and include the interconnection-
related network upgrades in their Long-Term Regional Transmission
Planning.\2357\
---------------------------------------------------------------------------
\2356\ SEIA Initial Comments at 14 (citing SPP, 2020 Integrated
Transmission Planning Assessment Report, at 87 (Oct. 27, 2020)).
\2357\ Id.
---------------------------------------------------------------------------
1099. Several commenters argue that the reforms issued under Order
No. 2023, Improvements to Generator Interconnection Procedures and
Agreements, will address interconnection-related issues more
appropriately than the NOPR proposal.\2358\ Some commenters argue that
the Commission should defer consideration of the NOPR proposal until
the reforms issued under Order No. 2023 are implemented.\2359\
---------------------------------------------------------------------------
\2358\ Dominion Reply Comments at 8; Idaho Power Initial
Comments at 6-7; Illinois Commission Initial Comments at 9; Pacific
Northwest Utilities Initial Comments at 15.
\2359\ Duke Initial Comments at 20; EEI Initial Comments at 18;
Entergy Initial Comments at 24-25.
---------------------------------------------------------------------------
3. Need for Reform
1100. Based on the record, we find that there is substantial
evidence to support the conclusion that the Commission's existing
regional transmission planning requirements are unjust, unreasonable,
and unduly discriminatory or preferential because they do not
adequately consider certain interconnection-related transmission needs
that the transmission provider has identified multiple times in the
generator interconnection process but that have never been resolved due
to the withdrawal of the underlying interconnection request(s). We
therefore adopt the preliminary findings in the NOPR concerning the
need for reform. Specifically, we find that there is insufficient
coordination between the Commission's existing generator
interconnection processes and regional transmission planning and cost
allocation processes regarding interconnection-related transmission
needs that are repeatedly identified in the generator interconnection
process. As a result of this deficiency, transmission providers do not
currently consider those identified interconnection-related
transmission needs in their regional transmission planning processes,
nor do they evaluate whether more efficient or cost-effective regional
transmission solutions to these needs could be achieved through
regional transmission planning processes and cost allocation.
Accordingly, we find that existing regional transmission planning and
cost allocation processes are insufficient to ensure just and
reasonable rates, and we direct the reforms discussed below to address
this deficiency.
1101. As explained in the NOPR,\2360\ we are concerned about the
prevalence of interconnection-related network upgrades being repeatedly
identified in the generator interconnection process in multiple
interconnection queue cycles during a short period of time (e.g., five
years) but not being developed because the interconnection request(s)
driving the need for the upgrade are withdrawn. The record indicates
that the level of spending on interconnection-related network upgrades
has dramatically increased in recent years, escalating the cost of
interconnecting new generation to the transmission system.\2361\ The
evidence also suggests that this trend is leading to more and more
interconnection customers withdrawing their interconnection requests in
the face of significant costs associated with interconnection-related
network upgrades.\2362\ For example, between January 2016 and July
2020, 245 generation projects in advanced stages in the MISO generator
interconnection process withdrew from the queue, with the project
developers citing high interconnection-related network upgrade costs as
the primary reason for their withdrawal.\2363\ While interconnection
customers may choose to withdraw from the interconnection queue for a
number of reasons, in recent years, the deciding factor has
increasingly become the interconnection customer's ``sticker shock'' at
its cost responsibility for interconnection-related network
upgrades.\2364\
---------------------------------------------------------------------------
\2360\ NOPR, 179 FERC ] 61,028 at PP 161-165.
\2361\ See ICF Resources, LLC, Just and Reasonable? Transmission
Upgrades Charged to Interconnecting Generators Are Delivering
System-Wide Benefits, 2 (Sept. 9, 2021), https://acore.org/wp-content/uploads/2021/09/Just-Reasonable-Transmission-Upgrades-Charged-to-Interconnecting-Generators-Are-Delivering-System-Wide-Benefits.pdf (ICF Sept. 2021 Interconnection Report); Jay Caspary et
al., ACEG, Disconnected: The Need for a New Generator
Interconnection Policy, 14 (2021)), https://cleanenergygrid.org/wp-content/uploads/2021/01/Disconnected-The-Need-for-a-New-Generator-Interconnection-Policy-1.pdf (ACEG 2021 Interconnection Report).
\2362\ ACEG 2021 Interconnection Report at 17.
\2363\ Id. (naming the high cost of interconnection-related
network upgrades as the fundamental problem that interconnection
queue reform has failed to address thus far).
\2364\ See ACORE ANOPR Comments at 12; DC and Maryland Office of
People's Counsel Initial Comments at 16; Invenergy Reply Comments at
14; Northwest and Intermountain Initial Comments at 14; see also
Order No. 2023, 184 FERC ] 61,054 at P 41; Order No. 2023-A, 186
FERC ] 61,199 at P 14.
---------------------------------------------------------------------------
1102. When interconnection customers withdraw from the
interconnection queue, the identified interconnection-related network
upgrades associated with those interconnection customers remain unbuilt
and the underlying interconnection-related transmission needs go
unaddressed. In many cases, when the interconnection-related
transmission need is not addressed via development of interconnection-
related network upgrades in one interconnection queue cycle, the same
interconnection-related transmission need--and oftentimes the same or a
substantially similar interconnection-related network upgrade--will
appear in subsequent interconnection queue cycles. One study, which
analyzed 12 specific interconnection-related network upgrades
identified by MISO and SPP, found that SPP identified three of the
upgrades in two interconnection queue cycles and one in three
interconnection queue cycles, and MISO identified three of the upgrades
in two interconnection queue cycles and two in three interconnection
queue cycles.\2365\ In other words, both SPP and MISO were repeatedly
identifying the same interconnection-related network upgrades as
interconnection customers withdrew from the interconnection queue,
leaving later-in-time interconnection customers to address
[[Page 49452]]
the same interconnection-related transmission needs.
---------------------------------------------------------------------------
\2365\ ICF Sept. 2021 Interconnection Report at 25-26.
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1103. Where interconnection-related transmission needs are
repeatedly identified in interconnection studies, the implication may
be that the area, despite the potentially prohibitive interconnection
costs if borne by one or a small number of interconnection customers,
is otherwise desirable for generators to locate (e.g., it is located
close to fuel sources). This repeated interest in accessing the
transmission system, combined with the lack of available transmission
capacity and prohibitive costs of interconnection-related network
upgrades, together create a barrier to accessing the transmission
system and establish a known interconnection-related transmission need.
We find that this barrier to entry can hinder the timely development of
new generation, thereby stifling competition in wholesale electricity
markets and limiting access to lower-cost generation.\2366\ We find
that existing regional transmission planning processes do not
adequately consider or account for this specific set of
interconnection-related transmission needs that go unaddressed in the
generator interconnection processes. By failing to consider such
interconnection-related transmission needs, the regional transmission
planning process is unable to identify the more efficient or cost-
effective regional transmission solutions.
---------------------------------------------------------------------------
\2366\ The Commission has previously found that policies
eliminating barriers to entry for generation resources can enhance
competition in bulk power markets. Standardization of Generator
Interconnection Agreements & Procs., Order No. 2003, 68 FR 49846
(Aug. 19, 2003), 104 FERC ] 61,103, at PP 694 (2003), order on
reh'g, Order No. 2003-A, 69 FR 15932 (Mar. 26, 2004), 106 FERC ]
61,220 at P 579, order on reh'g, Order No. 2003-B, 70 FR 265 (Jan.
4, 2005), 109 FERC ] 61,287 (2004), order on reh'g, Order No. 2003-
C, 70 FR 37661 (June 30, 2005), 111 FERC ] 61,401 (2005), aff'd sub
nom. Nat'l Ass'n of Regul. Util. Comm'rs v. FERC, 475 F.3d 1277
(D.C. Cir. 2007); Order No. 2023, 184 FERC ] 61,054 at P 44. Limited
access to new and more competitive supplies of generation can
increase the energy rates paid by wholesale customers. Order No.
2023, 184 FERC ] 61,054 at P 43.
---------------------------------------------------------------------------
1104. Moreover, the Commission has long recognized that
interconnection-related network upgrades provide transmission benefits
that extend beyond the interconnection customer.\2367\ By upgrading the
transmission system in a piecemeal fashion through the generator
interconnection process, as described above, the current regional
transmission planning paradigm can impose costs on interconnection
customers for transmission facilities that provide benefits beyond
those received by the interconnection customer. This paradigm allocates
transmission costs in a way that may not be roughly commensurate with
the distribution of benefits, a result that can lead to unjust and
unreasonable rates. The reform adopted below requires the consideration
of regional transmission facilities to meet interconnection-related
transmission needs repeatedly identified in the generator
interconnection process in the Order No. 1000 regional transmission
planning and cost allocation processes, which we believe will result in
more efficient or cost-effective regional transmission expansion, cost
allocation for such regional transmission facilities that is at least
roughly commensurate with estimated benefits, and elimination of a
barrier to entry for new generation resources (which can enhance
competition in wholesale electricity markets and facilitate access to
lower-cost generation). In turn, we expect that these reforms will
ensure just and reasonable and not unduly discriminatory or
preferential Commission-jurisdictional rates.
---------------------------------------------------------------------------
\2367\ See, e.g., Order No. 2003, 104 FERC ] 61,103 at P 65
(stating that ``[f]acilities beyond the Point of Interconnection
[(i.e., interconnection-related network upgrades)] are part of the
Transmission Provider's Transmission System and benefit all
users'').
---------------------------------------------------------------------------
1105. Additionally, as discussed further below, we disagree with
commenters that question the necessity of this reform. In addition to
our findings that this reform will help ensure just and reasonable
rates, we find that the specific purpose of this reform--to require
transmission providers to evaluate certain interconnection-related
transmission needs--is not a requirement of any existing process.
Additionally, we find that the qualifying criteria established by this
reform will ensure that the reform avoids placing an onerous burden on
transmission providers. Finally, we disagree that this reform is overly
prescriptive; it does not dictate a specific result or require that
transmission providers select a regional transmission facility to
address identified interconnection-related transmission needs. This
reform merely requires consideration of these interconnection-related
transmission needs in the regional transmission planning process.
4. Commission Determination
1106. We adopt the NOPR proposal, with modification, to require
transmission providers in each transmission planning region to revise
the regional transmission planning processes in their OATTs, consistent
with the requirements in this final order, to evaluate for selection
regional transmission facilities that address certain identified
interconnection-related transmission needs associated with certain
interconnection-related network upgrades originally identified through
the generator interconnection process, as more fully described below.
We find that this requirement will ensure that more efficient or cost-
effective transmission expansion can be effectuated through regional
transmission planning processes and will eliminate a potential barrier
to entry for new generation resources, thereby enhancing competition in
wholesale electricity markets and facilitating access to lower-cost
generation. As a result, this reform will ensure just and reasonable
and not unduly discriminatory or preferential Commission-jurisdictional
rates.
1107. In this final order, we adopt the NOPR proposal with
modification. First, we require transmission providers to evaluate for
selection regional transmission facilities to address certain
identified interconnection-related transmission needs in their existing
Order No. 1000 regional transmission planning and cost allocation
processes, rather than in Long-Term Regional Transmission Planning.
Second, we modify the NOPR proposal to require that an interconnection-
related network upgrade associated with identified interconnection-
related transmission needs must satisfy both the minimum cost and
voltage criteria proposed in the NOPR to qualify for evaluation for
selection.
1108. In recent years, spending on interconnection-related network
upgrades has increased dramatically, and the high cost of
interconnection is increasing the rate at which generators withdraw
from the interconnection queue.\2368\ While interconnection customers
may withdraw for multiple reasons, the record in this proceeding shows
that, in recent years, the deciding factor in many cases of withdrawal
has become the interconnection customer's cost responsibility for
expensive interconnection-related network upgrades.\2369\ Consequently,
interconnection customers are unlikely to resolve these
interconnection-related transmission needs through the generator
interconnection process.
---------------------------------------------------------------------------
\2368\ ACEG 2021 Interconnection Report at 17.
\2369\ NOPR, 179 FERC ] 61,028 at P 162; DC and Maryland Office
of People's Counsel Initial Comments at 16; Invenergy Reply Comments
at 14; Northwest and Intermountain Initial Comments at 14.
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1109. Where interconnection-related transmission needs are
repeatedly
[[Page 49453]]
identified but not constructed, the implication is that, despite the
potentially prohibitive interconnection costs if borne by one or a
small number of interconnection customers, there are compelling
reasons, such as proximity to fuel sources, why generators seek to
locate a point of interconnection at a specific location or locations
associated with transmission constraints. When interconnection
customers that have invested time and resources in engaging in the
generator interconnection process choose to withdraw rather than fund
interconnection-related network upgrades, it becomes increasingly
apparent that interconnection customer(s) are unlikely to resolve
interconnection-related transmission needs through the generator
interconnection process.
1110. At the same time, the Commission has found, and courts have
affirmed, that interconnection-related network upgrades identified in
the generator interconnection process can provide widespread
transmission benefits that extend beyond the interconnection
customer.\2370\ As a result, planning these types of upgrades to the
transmission system in a piecemeal fashion, exclusively through the
generator interconnection process, limits the development of
transmission facilities that would provide benefits to the transmission
system beyond those received by the interconnection customer. This is
the case where interconnection-related network upgrades of substantial
cost are repeatedly identified to address interconnection-related
transmission needs, but those needs continue to go unresolved through
the generator interconnection process. In such cases, it may be more
efficient or cost-effective to address such needs through the regional
transmission planning and cost allocation process. Therefore, reforms
are necessary to require interconnection-related transmission needs
associated with interconnection-related network upgrades that are
repeatedly identified in the generator interconnection process to be
evaluated through the regional transmission planning and cost
allocation process. We believe that this approach will result in
selection of more efficient or cost-effective regional transmission
solutions that will provide benefits to the transmission system, cost
allocation for such regional transmission facilities that is at least
roughly commensurate with estimated benefits, and elimination of a
barrier to entry for new generation resources (which will enhance
competition in wholesale electricity markets and facilitate access to
lower-cost generation).\2371\ As a result, these reforms will ensure
just and reasonable and not unduly discriminatory or preferential
Commission-jurisdictional rates.
---------------------------------------------------------------------------
\2370\ See, e.g., Entergy Svs., Inc. v. FERC, 391 F.3d 1240,
1247-48 (2004); Order No. 2003, 104 FERC ] 61,103 at P 65 (stating
that ``[f]acilities beyond the Point of Interconnection [(i.e.,
interconnection-related network upgrades)] are part of the
Transmission Provider's Transmission System and benefit all
users''); see also ACORE ANOPR Comments, Ex. 5 at 4-7; CAISO ANOPR
Comments at 53-54 (stating that in CAISO ``transmission facilities
at 200 kV and above are eligible for regional cost allocation,''
including location-constrained resources interconnection facilities,
because ``this voltage threshold . . . recognizes that high voltage
transmission facilities support and provide benefits to all
customers to the CAISO grid'').
\2371\ While in this portion of the final order we discuss the
requirement that transmission providers evaluate in their existing
regional transmission planning and cost allocation processes
regional transmission facilities that address certain
interconnection-related needs, we also expect that many of the other
reforms in this final order regarding Long-Term Regional
Transmission Planning will address the difficulties generators face
in interconnecting to the transmission system and the cost
allocation mismatch described here, including required Factor
Category Six, interconnection requests and withdrawals.
---------------------------------------------------------------------------
1111. While we require transmission providers to evaluate regional
transmission facilities that address certain interconnection-related
transmission needs identified by this reform in the existing Order No.
1000 regional transmission planning and cost allocation processes, we
allow for flexibility in how transmission providers evaluate such
facilities for selection. Transmission providers may adopt the
evaluation method and selection criteria from any of their existing
Order No. 1000 regional transmission planning and cost allocation
processes (e.g., economic or reliability processes) to evaluate and
potentially select these types of transmission facilities. By not
requiring a specific process, we permit transmission providers to
propose the best method to incorporate this requirement within their
existing regional transmission planning processes. We also encourage
transmission providers to consider, as part of the evaluation process,
whether regional transmission facilities that address certain
identified interconnection-related transmission needs may also address
other regional transmission needs more efficiently or cost-effectively.
1112. Several commenters suggest alternative reforms to coordinate
or consolidate regional transmission planning and generator
interconnection processes or to modify existing cost allocation
criteria.\2372\ We find these requests to be outside the scope of this
proceeding and lacking in record support to adequately consider whether
to adopt them in this final order. In this final order, we are
addressing the narrow issue of interconnection-related transmission
needs being repeatedly identified yet continuing to go unresolved
through the generator interconnection process, even though it may be
more efficient and cost-effective to evaluate such needs through the
regional transmission planning and cost allocation process.
---------------------------------------------------------------------------
\2372\ E.g., Enel Initial Comments at 4-5.
---------------------------------------------------------------------------
1113. We find uncompelling general arguments from commenters that
oppose the Commission's proposal because the reform addresses a
deficiency in existing regional transmission planning and cost
allocation processes, will ensure just and reasonable and not unduly
discriminatory or preferential Commission-jurisdictional rates, is not
unduly burdensome, and does not dictate a particular outcome. The level
of prescriptiveness of this reform strikes the right balance between an
open-ended requirement, which might not address the need for reform,
and a very prescriptive requirement that could be overly burdensome to
transmission providers.
1114. We are unpersuaded by Ameren's argument that this reform will
result in inefficient regional transmission planning because it will
not minimize the total cost to end-use customers.\2373\ As explained
above, this reform will enable transmission providers to identify
through regional transmission planning the more efficient or cost-
effective transmission solution to address an interconnection-related
transmission need.
---------------------------------------------------------------------------
\2373\ Ameren Initial Comments at 18.
---------------------------------------------------------------------------
1115. We clarify in response to Vistra that transmission providers
must make the newly created interconnection capacity equally available
to all interconnection and transmission customers consistent with the
Commission's open access policy.\2374\ Any interconnection customers
whose interconnection requests related to the initial identification of
the interconnection-related transmission need would not have any
priority rights to that newly created interconnection or transmission
capacity. Additionally, we clarify, in response to NRECA's request,
that we are not requiring interconnection-related network upgrades
associated with withdrawn interconnection requests to be given
[[Page 49454]]
preferential treatment in regional transmission planning.\2375\
---------------------------------------------------------------------------
\2374\ Vistra Initial Comments at 33-34.
\2375\ NRECA Reply Comments at 10-11.
---------------------------------------------------------------------------
1116. In response to commenters arguing that it is incorrect to
assume that interconnection customers withdraw from the interconnection
queue due solely to high interconnection-related network upgrade
costs,\2376\ we explain that we are not requiring transmission
providers to evaluate regional transmission facilities that address
interconnection-related transmission needs for every withdrawn
interconnection request. Instead, this reform is focused only on
certain interconnection-related transmission needs that meet the
specific qualifying criteria detailed below. We do not assume that
where these criteria are met, the relevant interconnection customers
have necessarily withdrawn from the interconnection queue solely due to
high interconnection-related network upgrade costs. Rather, we
determine that these criteria only suggest that high costs were likely
a factor prompting, or at least contributing to, the relevant
withdrawals. We conclude that where the criteria are met, there may be
an opportunity for a more efficient or cost-effective regional
transmission solution, such that an evaluation of the relevant
interconnection-related transmission need(s) is appropriate.
---------------------------------------------------------------------------
\2376\ CAISO Reply Comments at 29; NRECA Reply Comments at 9;
PJM Initial Comments at 87.
---------------------------------------------------------------------------
1117. We are not persuaded to reject this reform based on
commenters' assertions that this reform will shift the costs of
interconnection-related network upgrades from interconnection customers
to load.\2377\ This final order requires transmission providers to
evaluate in their existing Order No. 1000 regional transmission
planning and cost allocation processes regional transmission facilities
that address certain identified interconnection-related transmission
needs associated with certain interconnection-related network upgrades
originally identified through the generator interconnection process.
Transmission providers will still have to evaluate and select any
regional transmission facilities that address the interconnection-
related transmission needs as the more efficient or cost-effective
regional transmission solution as part of the regional transmission
planning process in order for any regional cost allocation method to
apply, and this final order does not alter the existing cost allocation
methods in either the generator interconnection or existing Order No.
1000 regional transmission planning process. If a regional transmission
facility that addresses identified interconnection-related transmission
needs is not selected as part of the regional transmission planning
process, then the associated regional cost allocation method would not
apply; however, if the facility is selected, then the regional
transmission planning process has determined that the regional
transmission facility is a more efficient or cost-effective regional
transmission solution. Additionally, if such a facility is selected,
the Commission-approved ex ante regional cost allocation method for
that facility would allocate its costs at least roughly commensurate
with its estimated benefits.
---------------------------------------------------------------------------
\2377\ APPA Initial Comments at 31; Industrial Customers Initial
Comments at 13; NRECA Initial Comments at 41-42 (citation omitted);
NRECA Reply Comments at 8-9; PJM Initial Comments at 89-90; Vistra
Initial Comments at 8; Xcel Initial Comments at 15.
---------------------------------------------------------------------------
1118. In response to TAPS' request that the Commission clarify that
regions may propose differing cost allocation methods for transmission
facilities selected to address interconnection-related transmission
needs versus transmission facilities selected to address other types of
transmission needs,\2378\ we clarify that the requirements adopted here
merely create an obligation for transmission providers to evaluate
regional transmission facilities that address certain identified
interconnection-related transmission needs in the existing regional
transmission planning and cost allocation processes. As such, to the
extent that transmission providers wish to propose further changes to
their Order No. 1000 regional transmission planning cost allocation
method(s) because of this requirement, they would need to do so in
separate FPA section 205 filings rather than on compliance with this
final order.
---------------------------------------------------------------------------
\2378\ TAPS Initial Comments at 13-14.
---------------------------------------------------------------------------
1119. We disagree with commenters that the requirements adopted
herein will incentivize gaming by interconnection customers to include
interconnection-related network upgrades in the regional transmission
planning process.\2379\ We also disagree with commenters that claim
that interconnection customers will submit spurious interconnection
requests.\2380\ Interconnection requests require significant financial
commitments from the interconnection customer (e.g., application fees,
study deposits, and site control requirements), which the Commission
made more stringent in Order No. 2023,\2381\ and therefore we find it
unlikely that an interconnection customer would submit multiple
interconnection requests (in multiple queue cycles) in order to trigger
this requirement because of the possibility that transmission providers
may eventually develop an interconnection-related network upgrade by
selecting it in a regional transmission plan for purposes of cost
allocation. An interconnection customer would face several risks in
pursuing such a strategy, including the risk that the regional
transmission solution for the interconnection-related transmission need
is not selected, and the risk that the newly created interconnection or
transmission capacity is allocated to a different transmission or
interconnection customer. For these reasons, we decline to adopt
Invenergy's request to modify the proposal to require that withdrawn
interconnection requests must have been submitted by unaffiliated
entities.\2382\
---------------------------------------------------------------------------
\2379\ Ameren Initial Comments at 18-19; American Municipal
Power Initial Comments at 34; Dominion Initial Comments at 32;
Dominion Reply Comments at 7-8; EEI Initial Comments at 18;
Eversource Initial Comments at 23-24; Idaho Power Initial Comments
at 6; Pennsylvania Commission Initial Comments at 9; PJM Initial
Comments at 89; PPL Initial Comments at 12-13; Shell Initial
Comments at 29-30; SPP Initial Comments at 16; Xcel Initial Comments
at 16.
\2380\ Ameren Initial Comments at 18; American Municipal Power
Initial Comments at 33-34; EEI Initial Comments at 18; Idaho Power
Initial Comments at 6; PJM Initial Comments at 89.
\2381\ See, e.g., Order No. 2023, 184 FERC ] 61,054 at P 502.
\2382\ Invenergy Reply Comments at 14-15.
---------------------------------------------------------------------------
1120. In response to Eversource's request that the Commission
clarify that submitting and withdrawing interconnection requests with
the intent of requiring transmission providers to evaluate the
associated interconnection-related transmission needs in their regional
transmission planning process is in violation of the Commission's
regulations, including but not limited to the duty of candor and
prohibition of market manipulation,\2383\ as noted above, the generator
interconnection process requires significant financial commitments for
interconnection requests to enter and proceed in the queue, and many
transmission providers have imposed additional readiness requirements
to encourage early withdrawal of non-viable interconnection requests.
For these reasons, we disagree with the gaming concerns raised by
Eversource.\2384\
---------------------------------------------------------------------------
\2383\ Eversource Initial Comments at 23-24 (citing 18 CFR
35.41; 18 CFR 1c.2).
\2384\ While we are not concerned about gaming here, to the
extent that there is evidence of a false representation or gaming of
the market rules, a referral to the Office of Enforcement may be
appropriate to determine whether a violation of the Commission's
regulations has occurred.
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[[Page 49455]]
1121. We also grant SEIA's request to clarify that the phrase
``interconnection-related transmission needs'' allows transmission
providers to identify individual regional transmission solutions to
address each identified interconnection-related transmission need, or
an aggregate regional transmission solution to address multiple
interconnection-related transmission needs. In response to commenters
arguing that the reforms issued under Order No. 2023 will address
interconnection-related issues more appropriately than the NOPR
proposal,\2385\ we explain that the reforms in this rulemaking are
intended to address situations when interconnection-related network
upgrades are repeatedly identified but not constructed and instances
when regional transmission solutions to address the needs that would
have been addressed by those interconnection-related network upgrades
would provide widespread transmission benefits that extend beyond the
interconnection customer, which are not addressed in Order No. 2023.
---------------------------------------------------------------------------
\2385\ Dominion Reply Comments at 8; Idaho Power Initial
Comments at 6-7; Illinois Commission Initial Comments at 8; Pacific
Northwest Utilities Initial Comments at 15.
---------------------------------------------------------------------------
B. Transmission Planning Process Evaluation
1. NOPR Proposal
1122. In the NOPR, the Commission proposed to require the
transmission providers in each transmission planning region to consider
regional transmission facilities that address interconnection-related
transmission needs pursuant to the proposed coordination reform through
the Long-Term Regional Transmission Planning process proposed in the
NOPR. Specifically, the Commission proposed to require that
transmission providers in each transmission planning region incorporate
the specific interconnection-related transmission needs identified
through the coordination reform as a factor used to develop Long-Term
Scenarios in the Long-Term Regional Transmission Planning proposed in
the NOPR.\2386\
---------------------------------------------------------------------------
\2386\ NOPR, 179 FERC ] 61,028 at P 167.
---------------------------------------------------------------------------
2. Comments
1123. Several commenters assert that the NOPR proposal is
unnecessary because well-executed Long-Term Regional Transmission
Planning will identify the transmission needed to support
interconnections.\2387\ For example, Xcel argues that Long-Term
Scenarios will be driven by the same factors that cause interconnection
customers to make interconnection requests, such as optimal geographic
locations for generation development.\2388\ Similarly, EEI states that
Long-Term Regional Transmission Planning, if properly implemented,
already takes into account factors that support generator
interconnection.\2389\
---------------------------------------------------------------------------
\2387\ AEP Initial Comments at 19; EEI Initial Comments at 18;
ENGIE Initial Comments at 5; Illinois Commission Initial Comments at
8-9; Vistra Initial Comments at 33; Xcel Initial Comments at 15.
\2388\ Xcel Initial Comments at 15.
\2389\ EEI Initial Comments at 18.
---------------------------------------------------------------------------
1124. Some of these commenters further claim that the Commission's
coordination proposal's reliance on backward-looking interconnection
needs would be less effective than planning on future system
interconnection needs. CAISO argues that the Commission's proposal is
backward-looking and therefore will not promote productive, forward-
looking transmission planning.\2390\ Vistra claims that an effective
transmission planning process will identify interconnection needs and
provide solutions within the context of a future system, rather than
relying on prior interconnection studies addressing a specific
generator interconnection request.\2391\ Similarly, ISO/RTO Council
recommends that the Commission direct transmission planners to consider
generator interconnection as a driver of Long-Term Transmission Needs
on a forward-looking basis, rather than the coordination proposal's
backwards-looking process.\2392\
---------------------------------------------------------------------------
\2390\ CAISO Initial Comments at 6, 34-35.
\2391\ Vistra Initial Comments at 33.
\2392\ ISO/RTO Council Initial Comments at 9.
---------------------------------------------------------------------------
1125. MISO states that because the generator interconnection
process is designed to identify the minimum amount of interconnection-
related network upgrades to interconnect new resources, Long-Term
Regional Transmission Planning is the proper avenue to holistically
evaluate system needs. MISO notes that it already has a mechanism in
place to include interconnection-related network upgrades in its Long-
Range Transmission Plan process if the interconnection-related network
upgrade is found to have region-wide benefits.\2393\
---------------------------------------------------------------------------
\2393\ MISO Initial Comments at 44, 46-47; MISO Reply Comments
at 29.
---------------------------------------------------------------------------
3. Commission Determination
1126. We adopt the NOPR proposal, with modification, to require
transmission providers in each transmission planning region to evaluate
regional transmission facilities that address certain interconnection-
related transmission needs in their existing Order No. 1000 regional
transmission planning and cost allocation processes instead of in Long-
Term Regional Transmission Planning. We find that this modification
will better alleviate transmission limitations by providing a starting
point for identifying and evaluating regional transmission solutions
that are more efficient or cost-effective when analyzed in the near
term.\2394\ Specifically, requiring transmission providers to evaluate
identified interconnection-related transmission needs in existing Order
No. 1000 regional transmission planning and cost allocation processes
will allow such needs to be addressed within a timeframe that is
relevant for identifying more efficient or cost-effective near-term
regional transmission solutions. Evaluation of interconnection-related
transmission needs in the existing Order No. 1000 regional transmission
planning and cost allocation processes is most appropriate because such
evaluation would occur at shorter intervals and would likely result in
more expeditious development of regional transmission facilities to
address the nearer-term interconnection-related transmission needs
identified through the generator interconnection process.
---------------------------------------------------------------------------
\2394\ See NOPR, 179 FERC ] 61,028 at P 165.
---------------------------------------------------------------------------
1127. We agree with commenters that future interconnection-related
transmission needs will be considered as part of Long-Term Regional
Transmission Planning and incorporated in the development of Long-Term
Scenarios. Nonetheless, for the reasons described above, we find that
current interconnection-related transmission needs can be considered
more effectively through the nearer-term existing Order No. 1000
regional transmission planning and cost allocation processes. As such,
we disagree with commenters that assert that the Commission's proposal
is unnecessary because well-executed Long-Term Regional Transmission
Planning will identify the transmission needed to support generator
interconnections.\2395\ That said, we emphasize that, as transmission
providers gain experience with Long-Term Regional Transmission
Planning, we anticipate that they will identify
[[Page 49456]]
fewer interconnection-related transmission needs associated with
certain interconnection-related network upgrades originally identified
through the generator interconnection process because transmission
providers will plan to address Long-Term Transmission Needs, including
those driven by Factor Category One: Federal, federally-recognized
Tribal, state, and local laws and regulations that affect the future
resource mix and demand; Factor Category Two: Federal, federally-
recognized Tribal, state, and local laws and regulations on
decarbonization and electrification; Factor Category Six: generator
interconnection requests and withdrawals, and Factory Category Seven:
utility and corporate commitments and Federal, federally-recognized
Tribal, state, and local policy goals that affect Long-Term
Transmission Needs, through Long-Term Regional Transmission Planning.
---------------------------------------------------------------------------
\2395\ AEP Initial Comments at 18-19; EEI Initial Comments at
18; ENGIE Initial Comments at 5; Illinois Commission Initial
Comments at 8-9; Vistra Initial Comments at 33; Xcel Initial
Comments at 15.
---------------------------------------------------------------------------
1128. Some commenters, including Vistra and ISO/RTO Council, claim
that the NOPR proposal to rely on needs identified in prior
interconnection studies would be less effective at planning for
interconnection-related transmission needs compared to more future-
oriented approaches. We agree that an effective regional transmission
planning process will identify interconnection-related transmission
needs and evaluate regional transmission solutions to those needs
within the context of a future system. We further agree that
transmission providers should consider generator interconnection as a
driver of Long-Term Transmission Needs on a forward-looking basis. For
these reasons, we require transmission providers to incorporate seven
specific categories of factors in their development of Long-Term
Scenarios used in Long-Term Regional Transmission Planning, including
Factory Category Six: generator interconnection requests and
withdrawals. However, we disagree that the coordination proposal should
not rely on past results from the generator interconnection process or
specific interconnection requests in determining what interconnection-
related transmission needs should be evaluated in the existing Order
No. 1000 regional transmission planning and cost allocation processes.
Interconnection-related network upgrades repeatedly identified in past
interconnection studies are strongly indicative that a location
(despite presenting potentially prohibitive interconnection costs if
borne by one or a small number of interconnection customers) is
otherwise valuable for location of new generation.
1129. Finally, because we are modifying the NOPR proposal to no
longer apply to Long-Term Regional Transmission Planning, commenters'
specific concerns that this proposal is duplicative to the categories
of factors requirements in the development of Long-Term Scenarios are
moot.
C. Qualifying Criteria
1. NOPR Proposal
1130. In the NOPR, the Commission proposed to require that
transmission providers evaluate for selection regional transmission
facilities to address interconnection-related transmission needs that
have been identified in the generator interconnection process as
requiring interconnection-related network upgrades where: (1) the
transmission provider has identified interconnection-related network
upgrades in interconnection studies to address those interconnection-
related transmission needs in at least two interconnection queue cycles
during the preceding five years (beginning at the time of the
withdrawal of the first underlying interconnection request); (2) the
interconnection-related network upgrade identified to meet those
interconnection-related transmission needs has a voltage of at least
200 kV and/or an estimated cost of at least $30 million; (3) those
interconnection-related network upgrades have not been developed and
are not currently planned to be developed because the interconnection
request(s) driving the need for the upgrade has been withdrawn; and (4)
the transmission provider has not identified an interconnection-related
network upgrade to address the relevant interconnection-related
transmission need in an executed generator interconnection agreement or
in a generator interconnection agreement that the interconnection
customer requested that the transmission provider file unexecuted with
the Commission.\2396\
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\2396\ NOPR, 179 FERC ] 61,028 at P 166.
---------------------------------------------------------------------------
1131. The Commission proposed that the initial five-year time
period begin five calendar years prior to the initial effective date of
the Commission-accepted tariff provisions proposed to comply with this
reform such that, upon the Commission's acceptance of such tariff
provisions, the transmission provider would consider interconnection-
related network upgrades identified to address the same
interconnection-related transmission need in at least two
interconnection queue cycles in the five calendar years prior to the
effective date established in the order accepting those tariff
revisions.\2397\ The Commission also proposed to require that
transmission providers in each transmission planning region consider
whether the interconnection-related transmission need for which the
transmission provider identified the interconnection-related network
upgrade is the same in multiple interconnection queue cycles.\2398\
That is, if an interconnection-related transmission need is driving the
identification of an interconnection-related network upgrade on the
transmission system in one interconnection queue cycle and an
interconnection-related network upgrade with, for example, a different
voltage, starting point, or ending point is identified in the next
interconnection queue cycle to address the same interconnection-related
transmission need, then the first criterion of the proposed
coordination reform would be satisfied.\2399\ The Commission stated
that it believes that this approach will appropriately account for
differences in technology, study assumptions, system topology, and/or
interconnection requests that may occur over time that may result in
different interconnection-related network upgrades to address the same
interconnection-related need.\2400\
---------------------------------------------------------------------------
\2397\ Id. P 170.
\2398\ Id. P 171.
\2399\ Id.
\2400\ Id.
---------------------------------------------------------------------------
1132. The Commission stated that it believes that the proposed
criteria the transmission provider must use to identify the
interconnection-related transmission needs that should be considered in
the regional transmission planning process will help to ensure that the
associated interconnection-related network upgrades are likely to have
produced benefits beyond those provided to the interconnection
customers whose interconnection requests the interconnection-related
network upgrades are needed to accommodate.\2401\
---------------------------------------------------------------------------
\2401\ Id. P 168.
---------------------------------------------------------------------------
1133. To avoid shifting costs inappropriately from generators in
the generator interconnection process to transmission customers through
the regional transmission planning process, the Commission further
proposed to limit the scope of interconnection-related transmission
needs to be considered in the regional transmission planning process to
those interconnection-related transmission needs not addressed by
interconnection-related network upgrades memorialized in an executed
generator
[[Page 49457]]
interconnection agreement (or in a generator interconnection agreement
that the interconnection customer requested to be filed unexecuted with
the Commission).\2402\
---------------------------------------------------------------------------
\2402\ Id. P 173.
---------------------------------------------------------------------------
2. Comments
1134. Multiple commenters generally support the NOPR proposal but
express concerns about the eligibility criteria proposed in the NOPR
and request modification.\2403\ SDG&E states that the criteria defined
in the NOPR strike an appropriate balance to cover many situations in
which generation is needed, while also protecting ratepayers from
unnecessary costs.\2404\
---------------------------------------------------------------------------
\2403\ NARUC Initial Comments at 19-20; Pattern Energy Initial
Comments at 28; Pine Gate Initial Comments 31-33; SEIA Initial
Comments at 14-15; Shell Initial Comments at 30; TAPS Initial
Comments at 13; US DOE Initial Comments at 28.
\2404\ SDG&E Initial Comments at 3.
---------------------------------------------------------------------------
1135. Avangrid argues that, while the NOPR proposal has merit, the
Commission should allow transmission providers to determine the most
appropriate thresholds.\2405\ SEIA asks the Commission to allow each
transmission planning region to determine its own threshold, which may
include lower voltage lines and substations.\2406\ Indicated PJM TOs
further argue that the proposed criteria may not be appropriate in all
transmission planning regions.\2407\
---------------------------------------------------------------------------
\2405\ Avangrid Initial Comments at 12.
\2406\ SEIA Initial Comments at 15.
\2407\ Indicated PJM TOs Initial Comments at 15-16.
---------------------------------------------------------------------------
1136. MISO argues that transmission planning regions should be able
to develop their own cost and voltage criteria. MISO explains that it
may be difficult to implement the requirement that interconnection-
related network upgrades that qualify must ``not currently be planned
to be developed'' in the interconnection process because in MISO's
experience interconnection-related network upgrades shift from queue
cycle to queue cycle as withdrawals occur, and as a result MISO
suggests deleting this requirement. MISO opposes the requirement to
identify any interconnection-related network upgrade that is identified
in multiple generator interconnection studies as it would require the
review and comparison of numerous studies to comply with no increased
benefit.\2408\
---------------------------------------------------------------------------
\2408\ MISO Initial Comments at 45-46.
---------------------------------------------------------------------------
1137. Multiple commenters that generally support the NOPR proposal
suggest modification to the NOPR's proposed cost and voltage
eligibility criteria. Pattern Energy suggests that the Commission
should allow consideration of interconnection-related network upgrades
that would meet either a voltage or a cost threshold because, for
example, lower voltage lines that cost more than $30 million can often
satisfy an interconnection need.\2409\ Pattern Energy and Pine Gate
argue that the Commission should lower the voltage threshold to 100
kV.\2410\ Shell asks the Commission to lower the 200 kV threshold to
115 kV or to remove it entirely in favor of a cost threshold that is
updated regularly based on inflation or some other Commission-approved
indicator.\2411\
---------------------------------------------------------------------------
\2409\ Pattern Energy Initial Comments at 28.
\2410\ Pattern Energy Initial Comments at 28; Pine Gate Initial
Comments at 32.
\2411\ Shell Initial Comments at 30.
---------------------------------------------------------------------------
1138. Pine Gate argues that the Commission should reduce the cost
threshold to $10 million.\2412\ SEIA argues that the cost threshold
should be replaced with a $100,000/MW threshold.\2413\ US DOE argues
that a $30 million cost threshold may not be appropriate because some
interconnection-related network upgrades that meet this eligibility
factor may only benefit a limited number of interconnection customers.
As an alternative, US DOE adds that the Commission should consider
interconnection-related network upgrades ``that would provide benefits
beyond the local interconnection level or that would improve
interconnection efficiencies across a wider geographic area and not
substations, voltage support devices, or other local connection
upgrades.'' \2414\
---------------------------------------------------------------------------
\2412\ Pine Gate Initial Comments at 32.
\2413\ SEIA Initial Comments at 15.
\2414\ US DOE Initial Comments at 28.
---------------------------------------------------------------------------
1139. Dominion states that the relatively low voltage and cost
thresholds in the Commission's proposal invites interconnection
customers to seek bigger investments than needed or select a location
that increases the cost of interconnection.\2415\ Dominion further
argues that the number, size, or frequency of interconnection requests
should not be used as a basis for planning transmission projects,
because the process could be subject to gaming, where speculative
interconnection requests could result in transmission buildouts and
spending that are not justified by actual grid needs or
economics.\2416\
---------------------------------------------------------------------------
\2415\ Dominion Initial Comments at 32.
\2416\ Dominion Reply Comments at 7-8.
---------------------------------------------------------------------------
1140. Some commenters take issue with the NOPR's proposed criteria.
Indicated PJM TOs argue that there is no record evidence to support the
proposed 200 kV and $30 million cost threshold criteria.\2417\ PJM
states that few interconnection studies have identified the need for
interconnection-related network upgrades in excess of $30
million.\2418\ Illinois Commission contends that many projects in the
interconnection queue are associated with interconnection-related
network upgrades that meet the repeatedly-identified and 200 kV
thresholds and that simply folding interconnection costs into
transmission planning may expedite the queue at the expense of
efficiency and cost-effectiveness.\2419\ Indicated PJM TOs argue that
limiting consideration to only generating facilities that have not yet
signed (or had filed) an interconnection agreement will result in
studying only uneconomic projects, which would run afoul of the cost
causation principle.\2420\
---------------------------------------------------------------------------
\2417\ Indicated PJM TOs Initial Comments at 15.
\2418\ PJM Initial Comments at 88.
\2419\ Illinois Commission Initial Comments at 8-9.
\2420\ Indicated PJM TOs Initial Comments at 16.
---------------------------------------------------------------------------
1141. Interwest argues that the Commission should not require the
identification of the interconnection-related network upgrade in two
queue cycles over the five-year lookback period because such a
requirement would limit the number of identified interconnection-
related network upgrades that would trigger this newly proposed
process.\2421\ Pine Gate states that the Commission's look-back period
should be at least the two immediately preceding interconnection queue
cycles, or, where serial studies have been performed, during the
preceding five years beginning at the time of the withdrawal of the
first underlying interconnection request.\2422\ Pine Gate argues that
this revision will ensure that study results will be available for use
in identifying interconnection-related network upgrades to
evaluate.\2423\ SEIA argues that once a transmission provider
identifies the same interconnection-related network upgrade in two
interconnection cycles, that line should be included in the next Long-
Term Regional Transmission Planning update cycle even if five years
have not passed since initial identification.\2424\ Pattern Energy
supports SEIA's requests.\2425\
---------------------------------------------------------------------------
\2421\ Interwest Initial Comments at 3, 11.
\2422\ Pine Gate Initial Comments at 31.
\2423\ Id.
\2424\ SEIA Initial Comments at 15.
\2425\ Pattern Energy Reply Comments at 10-11.
---------------------------------------------------------------------------
1142. EEI and Eversource are unsure of the stage of the generator
interconnection process at which a project would meet the proposed
criteria.\2426\ Eversource requests that the
[[Page 49458]]
Commission require transmission providers to specify the stage in the
interconnection process that an interconnection-related network upgrade
is identified.\2427\
---------------------------------------------------------------------------
\2426\ EEI Initial Comments at 17-18; Eversource Initial
Comments at 24.
\2427\ Eversource Initial Comments at 24.
---------------------------------------------------------------------------
1143. Pine Gate asks the Commission to combine the third and fourth
criteria into one criterion: those interconnection-related network
upgrades that are not developed or in development and not currently
committed to be built under an interconnection service agreement or any
related construction agreement.\2428\
---------------------------------------------------------------------------
\2428\ Pine Gate Initial Comments at 32-33.
---------------------------------------------------------------------------
1144. Some commenters argue that the Commission's proposed criteria
create too simplistic of a method for determining which
interconnection-related network upgrades should be evaluated in Long-
Term Regional Transmission Planning.\2429\ Pennsylvania Commission
argues that, without a rigorous examination of why an interconnection
application failed, there is no proof that there exists a need for
building interconnection-related network upgrades as part of Long-Term
Regional Transmission Planning.\2430\ NARUC argues that the meaning of
the term ``multiple times'' should be informed by a process that also
examines the reasons why the previous interconnection requests were
withdrawn, including generation developer land acquisition decisions or
the identification of more economic transmission design
alternatives.\2431\ Vistra takes issue with the fact that the
Commission does not distinguish between situations when developers
simply sought to develop in an uneconomic area versus when a more
efficient or cost-effective transmission project would have been
identified as part of the regional transmission planning process.\2432\
---------------------------------------------------------------------------
\2429\ NARUC Initial Comments at 19; Pennsylvania Commission
Initial Comments at 8; Vistra Initial Comments at 20.
\2430\ Pennsylvania Commission Initial Comments at 8.
\2431\ NARUC Initial Comments at 19.
\2432\ Vistra Initial Comments at 20.
---------------------------------------------------------------------------
3. Commission Determination
1145. We adopt the NOPR proposal, with modification, to require
that, for a regional transmission facility to address an
interconnection-related transmission need to qualify for evaluation
through the regional transmission planning process for selection under
this reform, any interconnection-related network upgrade identified to
meet that interconnection-related transmission need must meet both the
proposed voltage and cost criteria. Thus, we require transmission
providers to evaluate for selection in their existing Order No 1000
regional transmission planning processes regional transmission
facilities to address interconnection-related transmission needs that
have been identified in the generator interconnection process as
requiring interconnection-related network upgrades where: (1) the
transmission provider has identified interconnection-related network
upgrades in interconnection studies to address those interconnection-
related transmission needs in at least two interconnection queue cycles
during the preceding five years (looking back from the effective date
of the Commission-accepted tariff provisions proposed to comply with
this reform, and the later-in-time withdrawn interconnection request
occurring after the effective date of the Commission-accepted tariff
provisions); (2) an interconnection-related network upgrade identified
to meet those interconnection-related transmission needs has a voltage
of at least 200 kV and an estimated cost of at least $30 million; (3)
such interconnection-related network upgrade(s) have not been developed
and are not currently planned to be developed because the
interconnection request(s) driving the need for the network upgrade(s)
has been withdrawn; and (4) the transmission provider has not
identified an interconnection-related network upgrade to address the
relevant interconnection-related transmission need in an executed
generator interconnection agreement or in a generator interconnection
agreement that the interconnection customer requested that the
transmission provider file unexecuted with the Commission.
1146. We find it necessary to establish these criteria to limit the
scope of the requirement for transmission providers to evaluate
regional transmission facilities to address interconnection-related
transmission needs in their regional transmission planning processes to
those interconnection-related transmission needs that are likely to
persist, are not unique to a single interconnection request, and might
be addressed by regional transmission facilities that have the
potential to provide more widespread benefits to transmission
customers. We find that each of the four criteria are necessary to
identify the appropriate set of interconnection-related transmission
needs. Moreover, we find that the modification to require that an
interconnection-related network upgrade identified to meet an
interconnection-related transmission need must satisfy both the voltage
and cost thresholds better limits the scope of this reform by ensuring
that any regional transmission facilities evaluated to address such
interconnection-related transmission needs are more likely to provide
widespread benefits to transmission customers.\2433\
---------------------------------------------------------------------------
\2433\ The Commission has previously found that network upgrades
can benefit all transmission customers. See Order No. 2003, 104 FERC
] 61,103 at PP 21, 65 (stating ``[m]ost improvements to the
Transmission System, including Network Upgrades, benefit all
transmission customers'' and ``the definition of Network Upgrade
[includes] the phrase `at or beyond the Point of Interconnection,' .
. . [f]acilities beyond the Point of Interconnection are part of the
Transmission Provider's Transmission System and benefit all
users''); Order No. 2003-A, 106 FERC ] 61,220 at P 584 (citing
Entergy Servs., Inc. v. FERC, 319 F.3d 536, 543-544 (D.C. Cir.
2003)). The Commission has also previously found, and the record
demonstrates, that higher-voltage transmission facilities are more
likely to provide widespread benefits to transmission customers. See
NOPR, 179 FERC ] 61,028 at PP 32 (citing Order No. 1000, 136 FERC ]
61,051 at P 486), 168; Sw. Power Pool, Inc., 131 FERC ] 61,252, at P
73 (2010); Midwest Indep. Trans. Sys. Operator, Inc., 129 FERC ]
61,060, at P 8 (2009). See also, e.g., CAISO ANOPR Comments at 54;
Invenergy Initial Comments at 14; Southeast PIOs Initial Comments at
24.
---------------------------------------------------------------------------
1147. We further find that these criteria strike a reasonable
balance between precision and workability. Our reforms here are
intended to ensure that transmission providers must identify
interconnection-related transmission needs for evaluation in their
regional transmission planning processes that are likely to persist,
are not unique to a single interconnection request, and might be
addressed by regional transmission facilities that have the potential
to provide more widespread benefits to transmission customers.
Requiring in-depth qualitative analysis of individual interconnection
requests, including consideration of why they were withdrawn, as some
commenters suggest, would undermine these goals. Furthermore, these
criteria simply determine whether transmission providers must evaluate
regional transmission facilities to address any given interconnection-
related transmission need for potential selection; transmission
providers may still separately assess whether any particular regional
transmission facility qualifies for selection in the relevant existing
regional transmission planning process(es). Therefore, we disagree with
commenters that argue that the proposed criteria create too simplistic
a method for determining which interconnection-related transmission
needs should be evaluated in regional
[[Page 49459]]
transmission planning and cost allocation processes.\2434\
---------------------------------------------------------------------------
\2434\ See NARUC Initial Comments at 19; Pennsylvania Commission
Initial Comments at 8; Vistra Initial Comments at 20.
---------------------------------------------------------------------------
1148. We decline to allow transmission providers to determine
appropriate qualifying criteria,\2435\ because the record supports our
adoption of the qualifying criteria established by this order. As
described directly above, we find that these specific criteria ensure
that the interconnection-related transmission needs that we require
transmission providers to evaluate through their regional transmission
planning processes are likely to persist, are not unique to a single
interconnection request, and might be addressed by regional
transmission facilities that have the potential to provide more
widespread benefits to transmission customers. Furthermore,
transmission providers retain the flexibility to determine whether to
select a regional transmission facility, and these criteria will simply
determine whether transmission providers, pursuant to this final order,
must evaluate interconnection-related transmission needs in the Order
No. 1000 regional transmission planning and cost allocation processes.
---------------------------------------------------------------------------
\2435\ See Avangrid Initial Comments at 12; MISO Initial
Comments at 45-46; SEIA Initial Comments at 15.
---------------------------------------------------------------------------
1149. We also disagree with Indicated PJM TOs' argument that the
proposed criteria may not be appropriate in all transmission planning
regions because of the differences in scales, topology, and
economics.\2436\ While each transmission planning region is unique, we
find that the criteria that we establish here are broad enough to
capture interconnection-related network upgrades that are likely to
produce benefits beyond the interconnection customer across
transmission planning regions despite their differences. Furthermore,
as stated above, transmission providers in each transmission planning
region retain the flexibility to select regional transmission
facilities, and the criteria that we adopt here do not mandate that the
transmission providers in any transmission planning region select any
particular regional transmission facilities to address interconnection-
related transmission needs.
---------------------------------------------------------------------------
\2436\ See Indicated PJM TOs Initial Comments at 15-16.
---------------------------------------------------------------------------
1150. Additionally, we find that the qualifying criteria that we
establish here that an interconnection-related need must be repeated
twice and meet both voltage and cost thresholds are just and
reasonable. We disagree with commenters that argue for the adoption of
different criteria or for the elimination of one or both
criteria.\2437\ We find that the purpose of the criteria established
here is precisely to limit the number of interconnection-related
transmission needs that transmission providers must evaluate to those
that merit consideration in the existing Order No. 1000 regional
transmission planning and cost allocation processes. The requirement of
the repeat identification of an interconnection-related need in at
least two interconnection queue cycles during the preceding five years
criterion provides an important limit on the extent to which evaluation
is required. Namely, this and the other criteria together indicate that
it is likely that the relevant interconnection-related transmission
needs will persist but were not resolved because the high associated
interconnection-related network upgrade costs drove the withdrawal of
the underlying interconnection requests. The repeat identification of
interconnection-related network upgrades driven by a common
interconnection-related transmission need also indicates that the
constraint that the interconnection-related network upgrades were
identified to address is not unique to a single interconnection request
at a single point in time. Additionally, relaxing this repeat
identification requirement may be overburdensome to transmission
providers because it could increase the number of interconnection-
related transmission needs that transmission providers must evaluate in
their regional transmission planning and cost allocation processes.
---------------------------------------------------------------------------
\2437\ See Dominion Initial Comments at 32; Indicated PJM TOs
Initial Comments at 15; Interwest Initial Comments at 3, 11; Pattern
Energy Initial Comments at 28; Pine Gate Initial Comments at 32;
SEIA Initial Comments at 15; Shell Initial Comments at 30.
---------------------------------------------------------------------------
1151. We find that it is necessary to establish a cost threshold
criterion that is stringent enough to capture those interconnection-
related network upgrades that are likely to have caused the underlying
interconnection requests to withdraw. Additionally, we find that it is
necessary to establish a voltage criterion that is high enough so that
any regional transmission facility evaluated to address the underlying
interconnection-related transmission need(s) is likely to produce
benefits that extend beyond the interconnection customer. We further
believe that these criteria are important to limit the number of
interconnection-related transmission needs that transmission providers
must evaluate to a practical set so that transmission providers do not
have to evaluate numerous regional transmission facilities to address
those needs that are unlikely to be selected.
1152. Consequently, the modification adopted here to require that
an interconnection-related network upgrade identified to meet an
interconnection-related transmission need satisfies both the voltage
and cost criteria will achieve these results. In particular, this
modification will prevent transmission providers from evaluating
interconnection-related transmission needs associated with
interconnection-related network upgrades that are either above 200 kV
but lower-cost or cost more than $30 million but are less than 200 kV,
which means that they are less likely to provide more widespread
benefits to transmission customers.
1153. The change to the voltage and cost criteria also address
commenters' concerns.\2438\ For example, as US DOE notes, in some
instances, network upgrades that cost $30 million or more may only
benefit a limited number of interconnection customers.\2439\
Consequently, the change that we adopt to require that an
interconnection-related network upgrade identified to meet an
interconnection-related transmission need satisfy both the voltage and
cost criteria will more narrowly define a set of interconnection-
related transmission needs that the transmission provider must evaluate
in the regional transmission planning process.
---------------------------------------------------------------------------
\2438\ Pine Gate Initial Comments at 32; SEIA Initial Comments
at 15; US DOE Initial Comments at 28.
\2439\ US DOE Initial Comments at 28.
---------------------------------------------------------------------------
1154. The record supports a 200 kV threshold. For example, as noted
in the NOPR, the Commission has previously found CAISO's use of a 200
kV threshold was just and reasonable for determining eligibility for
evaluating interconnection-related network upgrades in the regional
transmission planning process. The Commission found that CAISO's
proposed threshold ``strikes a reasonable balance between . . .
accommodating the generators' need to interconnect . . . in a timely
manner, and the benefits that can flow from evaluating the larger
projects in the comprehensive transmission planning process.'' \2440\
As such, we continue to believe that a 200 kV voltage threshold is
sufficiently high such that the interconnection-related network
upgrades can more reasonably be expected to produce regional benefits
to
[[Page 49460]]
transmission customers than lower-voltage transmission facilities.
---------------------------------------------------------------------------
\2440\ Cal Indep. Sys. Operator Corp., 133 FERC ] 61,224, at P
103 (2010); see also NOPR, 179 FERC ] 61,028 at P 165 n.300 & P 172
n.302.
---------------------------------------------------------------------------
1155. We also continue to believe that $30 million is an
appropriate threshold for the cost criteria related to this
requirement. We find that the $30 million threshold is consistent with
the record established in this proceeding regarding how the costs of
interconnection-related network upgrades lead to interconnection
customers withdrawing from the queue.\2441\ A lower cost criterion may
require transmission providers to evaluate in the regional transmission
planning process interconnection-related transmission needs associated
with interconnection-related network upgrades that have a greater
likelihood to be affordable for interconnection customers.
Additionally, we are concerned that the $/kW cost threshold proposed by
SEIA may not capture interconnection-related network upgrades that are
more likely to provide regional benefits to transmission customers
beyond the interconnection customer. Further, transmission providers
may face practical challenges in identifying the specific kW size
corresponding to the interconnection-related transmission need
associated with an interconnection-related network upgrade because the
same interconnection-related network upgrade can be identified as
needed for multiple interconnection requests (or groups of requests) of
different kW sizes.
---------------------------------------------------------------------------
\2441\ NOPR, 179 FERC ] 61,028 at P 172 n.303.
---------------------------------------------------------------------------
1156. Additionally, we reiterate that the criteria adopted herein
do not require transmission providers to select any particular regional
transmission facility to address interconnection-related transmission
needs. Instead, we require transmission providers to simply evaluate
regional transmission facilities to address interconnection-related
transmission needs that meet these criteria for potential selection,
recognizing that transmission providers may ultimately determine
through their regional transmission planning processes that such
regional transmission facilities are not eligible or sufficiently
beneficial to be selected.
1157. We disagree with Indicated PJM TOs' argument that limiting
evaluation to exclude interconnection-related network upgrades
identified in generator interconnection requests that have executed (or
requested to be filed unexecuted) an interconnection agreement will
result in studying only uneconomic projects.\2442\ This criterion
ensures that transmission providers are not required to evaluate in
their regional transmission planning process interconnection-related
transmission needs associated with interconnection-related network
upgrades for which an interconnection customer has already agreed to
pay.\2443\ Furthermore, in response to MISO's suggestion to delete this
limiting aspect, we clarify that this criterion excludes instances in
which an interconnection-related network upgrade is identified in an
executed generator interconnection agreement (or in a generator
interconnection agreement that the interconnection customer requested
to be filed unexecuted with the Commission),\2444\ not instances where
an interconnection-related network upgrade that meets the criteria in
this section is identified as needed for an interconnection request
that has not proceeded to the generator interconnection agreement phase
of the interconnection study process.
---------------------------------------------------------------------------
\2442\ Indicated PJM TOs Initial Comments at 16.
\2443\ NOPR, 179 FERC ] 61,028 at P 173.
\2444\ MISO Initial Comments at 46.
---------------------------------------------------------------------------
1158. The criterion requiring that interconnection-related
transmission needs are identified in at least two interconnection queue
cycles during the preceding five years will help to ensure that an
interconnection-related transmission need is likely to persist and is
not unique to a single interconnection request before requiring
transmission providers to evaluate a regional transmission facility to
address that need for potential selection.\2445\ We recognize that, in
limited circumstances, it is possible that there may be only one
interconnection queue cycle during a five-year period. We clarify that
if more than five years pass between interconnection queue cycles, then
this criterion should be read to include the interconnection queue
cycle that immediately preceded the current interconnection queue where
the interconnection-related transmission need is identified.\2446\
---------------------------------------------------------------------------
\2445\ Pattern Energy Reply Comments at 10-11; Pine Gate Initial
Comments at 31; SEIA Initial Comments at 14-15.
\2446\ See Pine Gate Initial Comments at 31.
---------------------------------------------------------------------------
1159. We adopt the NOPR proposal that the initial five-year period
will begin five calendar years prior to the effective date of the
Commission-accepted tariff provisions proposed to comply with this
final order. Thus, transmission providers must evaluate an
interconnection-related transmission need that has been previously
identified multiple times within the five years prior to the effective
date of the Commission-accepted tariff provisions, but never been
resolved due to the withdrawal of the underlying interconnection
request(s). This assumes that the other qualifying criteria are met for
the interconnection-related transmission need. The evaluation for
selection of regional transmission facilities that address certain
identified interconnection-related transmission needs must occur in the
first Order No. 1000 regional transmission planning and cost allocation
processes cycle that commences after the later-in-time withdrawn
interconnection request occurring after the effective date of the
accepted tariff provisions.
1160. Additionally, we clarify that if there are no queue cycles in
the preceding five-year period because the transmission provider uses a
first-come, first-served serial interconnection process, then this
criterion will be met based on the identification of interconnection-
related transmission needs in individual interconnection studies. That
is, if the interconnection-related transmission need is identified in
at least two individual interconnection studies during the preceding
five-year period for interconnection customers that subsequently
withdrew from the interconnection queue, then this criterion is met. We
further clarify, as discussed immediately above, that if a transmission
provider identifies the same interconnection-related transmission need
in two interconnection queue cycles during a five-year period or less,
the transmission provider must evaluate that interconnection-related
transmission need even if five years have not yet passed since the
initial identification.\2447\
---------------------------------------------------------------------------
\2447\ See Pattern Energy Reply Comments at 10-11; SEIA Initial
Comments 15.
---------------------------------------------------------------------------
1161. In response to Eversource's request that we require
transmission providers to specify the stage in the generator
interconnection process that an interconnection-related network upgrade
is identified,\2448\ we clarify that the criterion discussed herein
applies no matter the stage in which the upgrades are identified,
because we are concerned with interconnection-related transmission
needs going unaddressed due to withdrawals regardless of the stage of
the generator interconnection process.
---------------------------------------------------------------------------
\2448\ See EEI Initial Comments at 17-18; Eversource Initial
Comments at 24.
---------------------------------------------------------------------------
1162. Finally, we decline to combine the third and fourth criteria
into one criterion as Pine Gate suggests, because we find that it is
unnecessary.\2449\ This reform creates a process for the evaluation of
interconnection-related
[[Page 49461]]
transmission needs in regional transmission planning and cost
allocation processes if those needs have not been addressed and are
unlikely to be addressed through the development of an interconnection-
related network upgrade in the generator interconnection process. The
purpose of the third criterion is to limit the reform to those
interconnection-related transmission needs where the associated
interconnection requests have been withdrawn; that is, this criterion
requires the repeat withdrawal. The fourth criterion, that the
interconnection-related network upgrade not be identified in a
generator interconnection agreement, ensures that the interconnection-
related network upgrade has not been developed and is not planned to be
developed because a generator interconnection agreement memorializes
the transmission owner's obligation to develop an identified
interconnection-related network upgrade.\2450\
---------------------------------------------------------------------------
\2449\ See Pine Gate Initial Comments at 32-33.
\2450\ See Pro forma LGIA art. 11.3 (``Transmission Provider or
Transmission Owner shall design, procure, construct, install, and
own the Network Upgrades . . . described in Appendix B.'').
---------------------------------------------------------------------------
V. Consideration of Dynamic Line Ratings and Advanced Power Flow
Control Devices
A. General Proposal
1. NOPR Proposal
1163. In the NOPR, the Commission proposed to require transmission
providers in each transmission planning region to consider two specific
technologies more fully in regional transmission planning and cost
allocation processes: dynamic line ratings and advanced power flow
control devices. The Commission recognized that selecting transmission
facilities that incorporate such technologies serving a transmission
function in the regional transmission plan for purposes of cost
allocation could be more efficient or cost-effective than a proposed
regional transmission facility that does not use such
technologies.\2451\
---------------------------------------------------------------------------
\2451\ NOPR, 179 FERC ] 61,028 at PP 272-273.
---------------------------------------------------------------------------
1164. More specifically, the Commission proposed to require
transmission providers in each transmission planning region to consider
for each identified regional transmission need whether selecting
transmission facilities that incorporate dynamic line ratings or
advanced power flow control devices would be more efficient or cost-
effective than selecting transmission facilities that do not
incorporate these technologies. The Commission proposed that such
consideration should first address whether incorporating dynamic line
ratings or advanced power flow control devices into existing
transmission facilities could meet the same regional transmission need
more efficiently or cost-effectively than other transmission facilities
that are being considered for potential selection. Second, the
Commission proposed that, when evaluating transmission facilities for
potential selection, transmission providers in each transmission
planning region must also consider whether incorporating dynamic line
ratings and advanced power flow control devices as part of any
potential regional transmission facility would be more efficient or
cost-effective than potential regional transmission facilities that do
not incorporate such technologies. The Commission proposed to apply
this requirement in all aspects of the regional transmission planning
processes, including the existing regional transmission planning
process for near-term regional transmission needs and Long-Term
Regional Transmission Planning. As is the case for any other
transmission facility selected, the Commission proposed that the costs
to incorporate dynamic line ratings or advanced power flow control
devices selected, whether as an addition to an existing transmission
facility or as part of a new regional transmission facility, be
allocated using the applicable regional cost allocation method.\2452\
---------------------------------------------------------------------------
\2452\ Id. P 274.
---------------------------------------------------------------------------
1165. The Commission noted that, as required by Order No. 1000, the
evaluation process must culminate in a determination that is
sufficiently detailed for stakeholders to understand why a particular
transmission facility was selected or not selected.\2453\ The
Commission proposed to extend this requirement such that transmission
providers must ensure that the determination of whether to incorporate
dynamic line ratings and advanced power flow control devices is
sufficiently detailed for stakeholders to understand why they were or
were not incorporated into selected regional transmission
facilities.\2454\
---------------------------------------------------------------------------
\2453\ Id. P 275 (citing Order No. 1000, 136 FERC ] 61,051 at P
328; Order No. 1000-A, 139 FERC ] 61,132 at P 267).
\2454\ Id.
---------------------------------------------------------------------------
1166. The Commission also sought comment on whether non-RTO/ISO
transmission planning regions should be required to update their energy
management systems or make other similar changes if dynamic line
ratings are identified as a more efficient or cost-effective
transmission facility.\2455\
---------------------------------------------------------------------------
\2455\ Id. P 277.
---------------------------------------------------------------------------
2. Comments on General Proposal
1167. Many commenters, including technology developers,
environmental advocates, ratepayer advocates, and independent market
monitors, support the NOPR proposal.\2456\ For example, many commenters
state that these technologies provide significant annual cost savings
\2457\ or affect both the capital investment and consumer benefits of
cost allocation.\2458\ Additionally, some Federal legislators support
the NOPR proposal.\2459\ CARE
[[Page 49462]]
Coalition asserts that the Commission should use all available tools
and technologies to increase the efficiency and capacity of the
transmission network.\2460\ ELCON states that transmission planning
processes should ascertain whether current infrastructure can be
improved before reviewing costlier or slower options like greenfield
transmission, and greater weight should be given to those transmission
projects that incorporate grid enhancing technologies.\2461\ Certain
TDUs state that they participate actively in the MISO transmission
planning process, and that they have observed that grid enhancing
technologies and other non-transmission alternatives do not receive the
attention that they deserve.\2462\ AEE contends that the Commission has
an obligation to promote the adoption of alternative transmission
technologies, as directed by Congress in the Energy Policy Act of 2005,
and AEE states that the Commission has not made explicit efforts to
implement this mandate beyond offering rate incentives for alternative
transmission technologies.\2463\
---------------------------------------------------------------------------
\2456\ ACEG Initial Comments at 31; ACORE Initial Comments at
15-16; ACORE Supplemental Comments at 1; Advanced Energy Buyers
Initial Comments at 4; AEE Initial Comments at 27-28; CARE Coalition
Initial Comments at 2-3; Certain TDUs Reply Comments at 7-9; Clean
Energy Associations Initial Comments at 28; Clean Energy
Associations Reply Comments at 7-8; Conservative Energy Network
Supplemental Comments at 1-2; Conservatives for Clean Energy--
Florida Supplemental Comments at 1-2; Conservatives for Clean
Energy--South Carolina Supplemental Comments at 1; Cross Sector
Representatives Supplemental Comments at 1; DC and MD Offices of
People's Counsel Initial Comments at 36; DC and MD Offices of
People's Counsel Reply Comments at 8-9; Evergreen Action Initial
Comments at 4; Hannon Armstrong Reply Comments at 2; Illinois
Commission Initial Comments at 11-13; Indicated US Senators and
Representatives Initial Comments at 2; Joint Consumer Advocates
Initial Comments at 13; Massachusetts Attorney General Initial
Comments at 16-18; Michigan Conservative Energy Forum Supplemental
Comments at 1; Michigan State Entities Initial Comments at 10; NARUC
Initial Comments at 35; NASEO Initial Comments at 6; NASUCA Initial
Comments at 7-8; NESCOE Initial Comments at 53; Nevada Commission
Initial Comments at 13; Ohio Conservative Energy Forum Supplemental
Comments at 1; Pennsylvania Commission Initial Comments at 11; PIOs
Initial Comments at 22; PJM Market Monitor Initial Comments at 6;
Potomac Economics Initial Comments at 5; Prysmian Initial Comments
at 1; Smart Wires Initial Comments at 1; SPP Market Monitor Initial
Comments at 9; US DOE Initial Comments at 36-37; WATT Coalition
Initial Comments at 2; WATT Coalition Supplemental Comments at 2-3;
Western Way Colorado Supplemental Comments at 1-2; Western Way
Nevada Supplemental Comments at 2; Wisconsin Conservative Energy
Forum Supplemental Comments at 1.
\2457\ Cross Sector Representatives Supplemental Comments at 1;
WATT Coalition Supplemental Comments at 2-3.
\2458\ Conservative Energy Network Supplemental Comments at 1-2;
Conservatives for Clean Energy--Florida Supplemental Comments at 1-
2; Conservatives for Clean Energy--South Carolina Supplemental
Comments at 1; Michigan Conservative Energy Forum Supplemental
Comments at 1; Ohio Conservative Energy Forum at 1; Western Way
Colorado Supplemental Comments at 2; Western Way Nevada Supplemental
Comments at 2; Western Way Utah Supplemental Comments at 2;
Wisconsin Conservative Energy Forum Supplemental Comments at 1.
\2459\ Environmental Legislators Caucus Supplemental Comments at
2; Senator Schumer Supplemental Comments at 2; Senator Whitehouse
Supplemental Comments at 3.
\2460\ CARE Coalition Initial Comments at 3.
\2461\ ELCON Initial Comments at 5, 20.
\2462\ Certain TDUs Reply Comments at 8.
\2463\ AEE Initial Comments at 29 (citing 42 U.S.C. 16422).
---------------------------------------------------------------------------
1168. Industrial Customers assert that requiring dynamic line
ratings, advanced power flow control devices, and other grid enhancing
technologies will require transmission utilities to deploy capital
where it is needed most to maintain reliability, which will reduce
transmission costs to consumers because dynamic line ratings extend the
useful life of existing transmission infrastructure and optimize
existing grid capabilities.\2464\ ENGIE claims that deploying grid
enhancing technologies could help to contain costs and support
efficient, advanced projects.\2465\ Invenergy argues that, even if
there may be instances where dynamic line ratings and advanced power
flow control devices do not provide the best option with respect to
cost, transmission providers should still undertake the analysis.\2466\
Potomac Economics observes that incorporating grid enhancing
technologies in the transmission planning process will help ensure that
transmission owners do not incur inefficient transmission upgrade costs
to mitigate congestion that can be reduced more cost-effectively by
grid enhancing technologies.\2467\
---------------------------------------------------------------------------
\2464\ Industrial Customers Reply Comments at 13-14.
\2465\ ENGIE Reply Comments at 3-4.
\2466\ Invenergy Reply Comments at 17.
\2467\ Potomac Economics Initial Comments at 5.
---------------------------------------------------------------------------
1169. Individual state governmental entities as well as NASEO,
NASUCA, and NESCOE emphasize the importance of considering more
efficient or cost-effective alternatives.\2468\ Some state commissions
and US DOE cite the benefits of cost containment for customers.\2469\
DC and MD Offices of People's Counsel and Clean Energy Associations
assert that grid enhancing technologies provide value beyond lowering
transmission costs, as they can be deployed quickly, are modular, have
low environmental and geographic footprints, and can be developed at
low risk.\2470\ NARUC asserts that an effective transmission planning
process should maximize the use of existing transmission and allow for
building new transmission only where necessary or economic.\2471\
Indicated US Senators and Representatives support the use of advanced
transmission technologies to increase the efficiency and resilience of
the electric grid.\2472\
---------------------------------------------------------------------------
\2468\ Massachusetts Attorney General Initial Comments at 16-18;
Michigan State Entities Initial Comments at 10 (citing Institute for
Policy Integrity ANOPR Reply Comments at 8); NASEO Initial Comments
at 6; NASUCA Initial Comments at 7-8; NESCOE Initial Comments at 53.
\2469\ Illinois Commission Initial Comments at 11-13; NARUC
Initial Comments at 35-36; Nevada Commission Initial Comments at 13;
Pennsylvania Commission Initial Comments at 11; US DOE Initial
Comments at 36-37.
\2470\ Clean Energy Associations Initial Comments at 27; DC and
MD Offices of People's Counsel Reply Comments at 8.
\2471\ Industrial Customers Reply Comments at 12; NARUC Initial
Comments at 35.
\2472\ Indicated US Senators and Representatives Initial
Comments at 2.
---------------------------------------------------------------------------
1170. Many commenters support the consideration of alternative
transmission technologies in transmission planning. For example,
Certain TDUs argue that the Commission must protect ratepayers and
consider all alternatives to ensure safe, reliable, and cost-effective
transmission solutions, including the use of alternative transmission
technologies.\2473\ Invenergy avers that there may be instances where
better using these technologies may require certain foundational
investments (e.g., appropriate software), but that only reinforces the
need to establish a requirement to drive change.\2474\ Industrial
Customers state that transmission providers should have to consider
grid enhancing technologies whenever additional transmission investment
is the alternative because the cost of installing them will almost
always be nominal compared to the benefits of reduced congestion, lower
energy and capacity costs, and reduced need for increases in
transmission system capability.\2475\
---------------------------------------------------------------------------
\2473\ Certain TDUs Reply Comments at 8.
\2474\ Invenergy Reply Comments at 17.
\2475\ Industrial Customers Reply Comments at 16.
---------------------------------------------------------------------------
1171. WATT Coalition asserts that alternative transmission
technologies and new transmission capacity are complementary.\2476\
WATT Coalition and Industrial Customers further assert that there is
substantial value in considering dynamic line ratings in Long-Term
Regional Transmission Planning because they can provide data to
strengthen assumptions made in the planning process.\2477\
Specifically, WATT Coalition explains that historical data sets of
dynamic transmission line ratings can be analyzed to create
probabilistic line ratings on a seasonal, monthly, or more granular
level to inform the transmission planning process, helping to maximize
its efficiency.\2478\ Finally, WATT Coalition states that the use of
forecasted ambient-adjusted ratings (Ambient Adjusted Ratings)
demonstrates that more granular data inputs can and should be captured
to increase the value of new transmission investment, as well as
increased reliability and market efficiency.\2479\
---------------------------------------------------------------------------
\2476\ WATT Coalition Reply Comments at 2.
\2477\ Industrial Customers Reply Comments at 18; WATT Coalition
Reply Comments at 1-3 (citing Appendix B of its Reply Comments).
\2478\ WATT Coalition Reply Comments Appendix B at 12. For
example, WATT Coalition reports that ERCOT uses historical dynamic
line rating data in its regional transmission plan. Id. (citing
ERCOT 2021 Regional Transmission Plan Report, section 1.2, https://www.ercot.com/files/docs/2021/12/23/2021_Regional_Transmission_Plan_Report_Public.zip).
\2479\ Id. Appendix B at 13.
---------------------------------------------------------------------------
1172. Invenergy states that, if there are concerns about the burden
associated with evaluating alternative transmission technologies, the
Commission could adopt a reasonable threshold under which transmission
providers are required to consider whether dynamic line ratings,
advanced power flow control devices, and other grid enhancing
technologies may be more efficient or cost-effective. For example,
Invenergy suggests that, if an overload is identified and the relevant
facilities are overloaded by 20% or less, the transmission provider
should be required to consider grid enhancing technologies as a
solution. Invenergy urges the Commission to reject calls to make the
proposal an optional process, noting that transmission providers can
already consider these technologies, but many do not.\2480\
---------------------------------------------------------------------------
\2480\ Invenergy Reply Comments at 16-17.
---------------------------------------------------------------------------
[[Page 49463]]
1173. Some commenters express partial support for the NOPR proposal
but raise concerns about certain aspects.\2481\ California Water
supports consideration of dynamic line ratings and advanced power flow
control devices in Long-Term Regional Transmission Planning but
recommends that any final order clarify that such technologies should
be adopted only if they are considered in the regional transmission
planning process as the Commission proposes, serve the purpose of cost
containment, and are found to be efficient and cost-effective.\2482\
TAPS states that while it supports the implementation of grid enhancing
technologies, they may be better suited for consideration on a shorter
regional transmission planning horizon.\2483\ While Pattern Energy
supports the consideration of grid enhancing technologies in Long-Term
Regional Transmission Planning, it similarly notes that dynamic line
ratings and advanced power flow control devices are shorter-term
transmission solutions--helping to ``squeeze more'' out of the
infrastructure that is operating or planned to be constructed.\2484\
---------------------------------------------------------------------------
\2481\ CAISO Initial Comments at 37-39, California Water Initial
Comments at 20; ENGIE Initial Comments at 6; Invenergy Initial
Comments at 14-16; Ohio Consumers Initial Comments at 32-33; Pattern
Energy Initial Comments at 29; SEIA Initial Comments at 21-22; SPP
Initial Comments at 25-26, TAPS Initial Comments at 4, 21-22.
\2482\ California Water Initial Comments at 20.
\2483\ TAPS Initial Comments at 4, 21-22.
\2484\ Pattern Energy Initial Comments at 29.
---------------------------------------------------------------------------
1174. While ENGIE supports the Commission's proposal to require the
evaluation and deployment of dynamic line ratings and advanced power
flow control devices where beneficial in Long-Term Regional
Transmission Planning, it notes that the operational data used by such
devices are not yet easily incorporated into the transmission planning
framework.\2485\ Similarly, SEIA and Invenergy raise concerns that
utilities struggle to consider, evaluate, and select these technologies
as transmission solutions due to a lack of information about how they
might be integrated into the transmission planning process.\2486\
---------------------------------------------------------------------------
\2485\ ENGIE Initial Comments at 6.
\2486\ Invenergy Initial Comments at 14-16; SEIA Initial
Comments at 21-22.
---------------------------------------------------------------------------
1175. Finally, National Grid generally supports the notion that
transmission providers should consider whether and how alternative
transmission technologies can be incorporated into transmission
planning and states that such technologies, in certain instances, may
offer a more efficient or cost-effective alternative to other regional
transmission facilities.\2487\ However, National Grid states that, if
the Commission adopts in a final order the requirement to fully
consider dynamic line ratings and advanced power flow control devices,
it should explain how it expects RTOs/ISOs to implement the first step
of the consideration process articulated in the NOPR, i.e., that the
alternative transmission technologies being incorporated into existing
transmission facilities ``could meet the same regional transmission
need more efficiently or cost-effectively than other potential
transmission facilities.'' \2488\ According to National Grid, such a
requirement would exceed the RTO/ISO's authority as the independent
administrator of the competitive solicitation process.\2489\
---------------------------------------------------------------------------
\2487\ National Grid Initial Comments at 21.
\2488\ Id. at 23 (quoting NOPR, 179 FERC ] 61,028 at P 274).
\2489\ Id.
---------------------------------------------------------------------------
1176. Many commenters oppose the NOPR proposal.\2490\ Some
commenters warn the Commission of the potential reliability and
operational impacts of the widespread use of dynamic line ratings and
advanced power flow control devices.\2491\ APPA asserts that
transmission dynamic line ratings and advanced power flow control
devices should not be required until the industry has further
experience with Ambient-Adjusted Ratings deployment.\2492\ Exelon
asserts that transmission providers already consider grid enhancing
technologies and notes that, in many instances, the selection and
deployment of grid enhancing technologies are fundamentally
incompatible with the competitive transmission requirements in Order
No. 1000, particularly in the context of development of new
transmission facilities, where grid enhancing technologies are unlikely
to be the lower cost solution, and may be considerably more expensive
than traditional transmission technologies.\2493\
---------------------------------------------------------------------------
\2490\ AEP Initial Comments at 33; Ameren Initial Comments at
23-24; APPA Initial Comments at 37; ATC Initial Comments at 7-8;
Avangrid Initial Comments at 31; DATA Initial Comments at 17;
Dominion Initial Comments at 40; Duke Initial Comments at 29-32; EEI
Initial Comments at 20-22; Entergy Initial Comments at 26-28;
Eversource Initial Comments at 27-28; Exelon Initial Comments at 18-
23; Georgia Commission Initial Comments at 7-8; Idaho Power Initial
Comments at 9; Indicated PJM TOs Initial Comments at 19-20; ITC
Initial Comments at 26-28; ITC Reply Comments at 27; LADWP Initial
Comments at 5; Large Public Power Initial Comments at 31-34; MISO
TOs Initial Comments at 23-24; Mississippi Commission Reply Comments
at 8; New York TOs Initial Comments at 22-23; NRECA Initial Comments
at 52; NYISO Initial Comments at 45, 47; OMS Initial Comments at 9;
Pacific Northwest Utilities Initial Comments at 15-16; PJM Initial
Comments at 105-109; PPL Initial Comments at 22-23; Southern Initial
Comments at 35; SERTP Sponsors Initial Comments at 36-37; US Chamber
of Commerce Initial Comments at 9.
\2491\ Duke Initial Comments at 31-32; Entergy Initial Comments
at 27-28; MISO Initial Comments at 59-60.
\2492\ APPA Initial Comments at 5.
\2493\ Exelon Initial Comments at 21.
---------------------------------------------------------------------------
1177. Some commenters argue that further support is needed to
justify any mandate to consider alternative transmission technologies
in transmission planning.\2494\ Kansas Commission asserts that any new
requirements should be based on a data-driven, robust analysis
demonstrating ratepayer benefits; it also cautions against using such
technologies as a short-term fix.\2495\ ATC states that the Commission
should develop a record of the costs, risks, and potential impacts of
widespread implementation of dynamic line ratings before mandating
further action.\2496\
---------------------------------------------------------------------------
\2494\ ATC Reply Comments at 3; Kansas Commission Initial
Comments at 19-20.
\2495\ Kansas Commission Initial Comments at 19-20.
\2496\ ATC Reply Comments at 3.
---------------------------------------------------------------------------
1178. Some commenters raise concerns about the costs of alternative
transmission technologies. Mississippi Commission argues that mandating
the use of technologies without considering their cost is not just and
reasonable.\2497\ ATC asserts that the costs of implementing dynamic
line ratings system wide would not be nominal.\2498\ US Chamber of
Commerce asserts that dynamic line ratings are not a way to obtain
``free'' transmission capacity because there are costs associated with
monitoring the ratings.\2499\
---------------------------------------------------------------------------
\2497\ Mississippi Commission Reply Comments at 8.
\2498\ ATC Reply Comments at 3 (citing Pattern Energy Initial
Comments at 30; Pine Gate Initial Comments at 40-41).
\2499\ US Chamber of Commerce Initial Comments at 9.
---------------------------------------------------------------------------
1179. Other commenters argue that the Commission should favor
flexibility and not mandate that dynamic line ratings and advanced
power flow control devices be considered.\2500\ Georgia Commission
states that it is reasonable for the Commission to encourage, rather
than require, consideration of dynamic line ratings and advanced power
flow control devices in Long-Term Regional Transmission Planning.\2501\
LADWP suggests that instead of mandating consideration of specific
technologies that become obsolete, the Commission
[[Page 49464]]
should require transmission providers to use Good Utility Practice to
identify and use technologies that maximize the use of transmission
assets in order to minimize impacts to ratepayers and the public.\2502\
---------------------------------------------------------------------------
\2500\ Avangrid Initial Comments at 31; Clean Energy Buyers
Initial Comments at 25; Eversource Initial Comments at 27; Georgia
Commission Initial Comments at 7-8; Idaho Power Initial Comments at
9; New York TOs Initial Comments at 23; OMS Initial Comments at 9;
PPL Initial Comments at 23.
\2501\ Georgia Commission Initial Comments at 7.
\2502\ LADWP Initial Comments at 5.
---------------------------------------------------------------------------
1180. Similarly, National Grid argues that the Commission should
not favor the deployment of the two proposed technologies over more
efficient or cost-effective transmission facilities, and that focusing
on specific technologies is likely to stifle innovation and will not
lead to the identification of the more efficient or cost-effective
transmission facilities.\2503\ ATC disagrees with commenters that state
that utilities are reluctant to implement these technologies,\2504\
noting that it advocates for and uses advanced power flow control
devices and other advanced technologies on its system.\2505\ However,
ATC describes widespread dynamic line rating deployment as
costly.\2506\
---------------------------------------------------------------------------
\2503\ National Grid Initial Comments at 22-23.
\2504\ ATC Reply Comments at 2 (citing Invenergy Initial
Comments at 15).
\2505\ Id. (citing ATC Initial Comments at 7).
\2506\ Id. at 3.
---------------------------------------------------------------------------
1181. Other commenters urge the Commission to complete its
consideration of the record in the Notice of Inquiry on the
Implementation of Dynamic Line Ratings\2507\ and/or wait for
transmission providers to comply with Order No. 881\2508\ before
implementing the NOPR proposal on dynamic line ratings.\2509\ Large
Public Power states that the Commission appears to sidestep the record
in the Notice of Inquiry on the Implementation of Dynamic Line Ratings,
especially the technical and cybersecurity-related concerns in that
docket.\2510\ MISO TOs state that imposing a mandate in this proceeding
would complicate the issue.\2511\ ATC argues that a more prudent course
of action would be to gain experience with Ambient-Adjusted Ratings
before moving on to consideration of the use of dynamic line
ratings.\2512\ ITC asserts that dynamic line ratings and advanced power
flow control devices should be implemented on an operational basis
through existing Commission proceedings addressing such
technologies.\2513\
---------------------------------------------------------------------------
\2507\ Implementation of Dynamic Line Ratings, 178 FERC ] 61,110
(2022).
\2508\ Managing Transmission Line Ratings, Order No. 881, 177
FERC ] 61,179 (2021).
\2509\ ATC Reply Comments at 4-5; Dominion Initial Comments at
40; Large Public Power Initial Comments at 5, 32-33; MISO TOs
Initial Comments at 23-24.
\2510\ Large Public Power Initial Comments at 32.
\2511\ MISO TOs Initial Comments at 23.
\2512\ ATC Initial Comments at 10.
\2513\ ITC Reply Comments at 27.
---------------------------------------------------------------------------
1182. Several commenters specifically support the NOPR proposal of
requiring consideration of both: (1) whether incorporating dynamic line
ratings or advanced power flow control devices into existing
transmission facilities could meet the same regional transmission need
more efficiently or cost-effectively than other transmission facilities
that are being considered for potential selection; and (2) whether
incorporating dynamic line ratings and advanced power flow control
devices as part of any potential regional transmission facility would
be more efficient or cost-effective than those without incorporating
such technologies.\2514\ Ohio Consumers emphasize the importance of
considering dynamic line ratings and advanced power flow control
devices for both proposed and existing projects, noting that the goal
of using these technologies is to lower overall costs of new
transmission for consumers, and citing to a DOE study that found that
these technologies can defer or reduce the need for significant
investment in new infrastructure projects, and increase the use of
renewables by maximizing the capacity of current infrastructure.\2515\
---------------------------------------------------------------------------
\2514\ ACORE Initial Comments at 15; Clean Energy Associations
Initial Comments at 28; DC and MD Offices of People's Counsel
Initial Comments at 36; Industrial Customers Initial Comments at 32-
34; Michigan State Entities Initial Comments at 11; NASEO Initial
Comments at 6; Ohio Consumers Initial Comments at 34; State Agencies
Initial Comments at 17-18.
\2515\ Ohio Consumers Initial Comments at 32-34 (citing US DOE,
Grid-Enhancing Technologies: A Case Study on Ratepayer Impact (Feb.
2022), https://www.energy.gov/sites/default/files/2022-04/Grid%20Enhancing%20Technologies%20-%20A%20Case%20Study%20on%20Ratepayer%20Impact%20-%20February%202022%20CLEAN%20as%20of%20032322.pdf).
---------------------------------------------------------------------------
1183. Others oppose the consideration of alternative transmission
technologies on new transmission facilities.\2516\ CAISO contends that
a requirement to consider whether to incorporate dynamic line ratings
and advanced power flow control devices as part of every new regional
transmission facility identified to meet a reliability need would
create more work without yielding significant benefits because
incorporating such measures would not alter the scope of the underlying
transmission facilities that are necessary to meet the reliability
need.\2517\ LADWP states that identification of specific technologies
in a rulemaking seems inappropriate and asserts a transmission line
that is not yet built has no operating history, and it should therefore
be at the discretion of the transmission planner to consider and
implement dynamic line ratings, as it would slow down the design and
construction of the transmission line.\2518\ Exelon states that,
particularly in the context of new transmission facilities, grid
enhancing technologies are very unlikely to be the lower cost solution
relative to traditional transmission technologies, and for many
technologies, they should be expected to be considerably more expensive
than traditional transmission technologies (notwithstanding any
additional benefits they may offer).\2519\
---------------------------------------------------------------------------
\2516\ CAISO Initial Comments at 6; LADWP Initial Comments at 5.
\2517\ CAISO Initial Comments at 6. CAISO, however, supports
considering these technologies in connection with new transmission
facilities intended to meet economic or public policy needs. Id.
\2518\ LADWP Initial Comments at 5.
\2519\ Exelon Initial Comments at 21-22.
---------------------------------------------------------------------------
1184. Clean Energy Associations, Industrial Customers, and WATT
Coalition support the implementation of a requirement for non-RTO/ISO
regions to update their energy management systems if dynamic line
ratings are identified as a more efficient or cost-effective
transmission facility selected.\2520\ ELCON agrees, asserting that the
Commission's requirement for dynamic line ratings and advanced power
flow control devices should apply to all Commission-jurisdictional
transmission utilities, regardless of whether they are RTOs/ISOs.\2521\
WATT Coalition adds that all transmission providers should be required
to upgrade their energy management systems and keep them consistent
across all transmission providers to accommodate the latest
technologies.\2522\ WATT Coalition further states that advanced power
flow control devices and topology optimization do not require
modifications to existing energy management systems, but that the
implementation of such technologies would benefit from the increased
flexibility of dynamic line rating-enabled energy management
systems.\2523\
---------------------------------------------------------------------------
\2520\ Clean Energy Associations Initial Comments at 28;
Industrial Customers Initial Comments at 32-33; Industrial Customers
Reply Comments at 11; WATT Coalition Initial Comments at 7.
\2521\ ELCON Initial Comments at 21.
\2522\ WATT Coalition Initial Comments at 7.
\2523\ Id.
---------------------------------------------------------------------------
1185. Pattern Energy states that energy management systems and
other equipment will need upgrades to integrate readouts from the
dynamic line ratings equipment to minimize operator intervention and
enhance operational awareness. Pattern Energy
[[Page 49465]]
surmises, however, that any upgrades necessitated by a final order in
this proceeding may be nominal given that dynamic line ratings and
advanced power flow control devices should already be readily
integrated with upgrades to energy management systems needed to comply
with Order No. 881.\2524\
---------------------------------------------------------------------------
\2524\ Pattern Energy Initial Comments at 30 (citing Order No.
881, 177 FERC ] 61,179).
---------------------------------------------------------------------------
1186. Some commenters suggest alternative approaches to
incorporating alternative transmission technologies into the
transmission system. Vistra asserts that the Commission should modify
the NOPR proposal to require: (1) the long-term transmission planning
evaluation to include a generation capacity expansion scenario that
incorporates the potential for enhanced capability through new market
services; (2) early input during the transmission planning cycle from
independent market monitors and stakeholders on market improvements
that could enhance grid operations; and (3) all solicitations for long-
term solutions to equally consider non-transmissions solutions that may
include generation, technology, or market design changes that could
more efficiently or cost-effectively address a need that otherwise
would require construction or modification of transmission
facilities.\2525\
---------------------------------------------------------------------------
\2525\ Vistra Initial Comments at 32.
---------------------------------------------------------------------------
1187. Some commenters request that the Commission establish more
prescriptive requirements regarding the evaluation of the alternative
transmission technologies than those proposed in the NOPR. Invenergy
asserts that the NOPR proposal should be expanded to include other
technologies and require transmission providers to select alternative
transmission technologies when they provide the most efficient
option.\2526\
---------------------------------------------------------------------------
\2526\ Invenergy Reply Comments at 16 (citing Invenergy Initial
Comments at 14-17).
---------------------------------------------------------------------------
1188. WATT Coalition urges the Commission to include an operational
planning timeframe for topology optimization, dynamic line ratings, and
modular advanced power flow control devices, which can all be deployed
quickly. WATT Coalition states that the Commission could require
consideration of these technologies for the top 5 or 10 most costly or
critical constraints on a quarterly basis.\2527\ WATT Coalition states
that market participants should be able to request the use of grid
enhancing technologies, and receive an answer from the transmission
provider within a defined period of time, to be evaluated against
alternatives used by the transmission provider.\2528\ WATT Coalition
also asserts that grid enhancing technologies should be required in
appropriate instances and encouraged through incentives because
utilities have little incentive to deploy them under standard cost-of-
service regulation,\2529\ and after implementing this order, the
Commission should develop transmission incentives to complement a
congestion threshold requirement, driving other creative applications
of grid enhancing technologies where they would create the most value
to consumers.\2530\
---------------------------------------------------------------------------
\2527\ WATT Coalition Initial Comments at 5.
\2528\ Id. at 5-6.
\2529\ WATT Coalition Reply Comments at 3.
\2530\ WATT Coalition Supplemental Comments at 3.
---------------------------------------------------------------------------
1189. Some commenters request more requirements regarding
evaluation and/or deployment of alternative transmission technologies
to meet transmission needs. WATT Coalition states that there are
certain transmission technologies that are faster to deploy than
traditional lines and urges the Commission to require an annual review
of the Long-Term Regional Transmission Planning process and establish a
fast track process for solutions with a lead time of less than 12
months and a capital cost of less than $50 million.\2531\ WATT
Coalition further states that the requirement to consider dynamic line
ratings and advanced power flow control devices should also apply in
any case where transmission capacity is valuable but the costs of a new
line are not justified.\2532\
---------------------------------------------------------------------------
\2531\ WATT Coalition Initial Comments at 8.
\2532\ Id. at 4.
---------------------------------------------------------------------------
1190. Smart Wires and WATT Coalition argue that the Commission
should direct transmission providers to: (1) designate advanced power
flow control devices as the default solution for projects requiring a
series capacitor; (2) ``require evaluation of advanced power flow
control devices for thermal overloads that fall within 50% of the line
rating,'' which they argue is when such devices are often most
economically advantageous; (3) require evaluation of advanced power
flow control devices for interconnection-related network upgrades
associated with new load connections, given that these technologies can
be used to rebalance flows quickly and adjusted to mirror actual
growth; and (4) mandate deployment of advanced power flow control
devices as the default solution for voltage stability management on
100-plus mile AC transmission lines.\2533\
---------------------------------------------------------------------------
\2533\ Smart Wires Initial Comments at 1, 3-5; WATT Coalition
Initial Comments at 3-4.
---------------------------------------------------------------------------
1191. Some commenters suggest that the Commission should collect
additional data and require reporting on the deployment of alternative
transmission technologies. PIOs and DC and MD Offices of People's
Counsel ask the Commission to require that transmission providers
explain how they considered alternative transmission technologies in
the transmission planning process and if they were not used, why.\2534\
DC and MD Offices of People's Counsel assert that data collected from
dynamic line ratings should be shared with stakeholders to provide
transparency as to the necessity or economic efficiency of certain
transmission upgrades, and a mechanism should be implemented to
independently review the projected costs and benefits of advanced
transmission technologies from an efficiency and cost-allocation
perspective.\2535\ NASEO states that the Commission should include a
requirement for those seeking to make changes to RTOs/ISOs' facilities
to provide an analysis of the new technologies and how they meet
present and expected future challenges, suggesting that RTOs/ISOs be
required to consult with US DOE, the DOE national laboratories, and
state energy offices to ensure new technologies are incorporated into
Long-Term Regional Transmission Planning.\2536\ Certain TDUs argue that
the Commission should require transmission planners to document their
evaluation of alternative transmission solutions in the transmission
planning process, which should include the methods used to integrate
grid enhancing technologies alone or in combination with transmission
upgrades.\2537\
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\2534\ DC and MD Offices of People's Counsel Initial Comments at
36; PIOs Initial Comments at 22.
\2535\ DC and MD Offices of People's Counsel Initial Comments at
36.
\2536\ NASEO Initial Comments at 6-7.
\2537\ Certain TDUs Reply Comments at 8-9 (citing OMS Initial
Comments at 9; Certain TDUs Initial Comments at 24).
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1192. ENGIE recommends that the Commission require transmission
providers to provide a report to the Commission every five years on the
deployment and operational analysis of grid enhancing technologies to
ensure these technologies are being properly evaluated in Long-Term
Regional Transmission Planning.\2538\ R Street suggests that the
Commission require the incorporation, not just consideration, of
advanced transmission technologies, and should require the inclusion of
commercially viable
[[Page 49466]]
technologies on a rolling basis as informed by a regularly updated list
of qualifying technologies through, for example, a periodic forum with
technology experts from US DOE.\2539\ SEIA states that the Commission
should host regular technical conferences to discuss improvements and
innovations in grid enhancing technologies as experience with these
technologies grows.\2540\ SEIA states that to determine whether such
technologies are feasible, transmission providers should provide the
following information to market participants: modeling assumptions,
contingency analysis results, asset age, and environmental and
footprint constraints.\2541\
---------------------------------------------------------------------------
\2538\ ENGIE Initial Comments at 6.
\2539\ R Street Initial Comments at 4.
\2540\ SEIA Initial Comments at 21.
\2541\ Id. at 22.
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1193. Pattern Energy states that the Commission should be mindful
that limited supplies of dynamic line ratings, advanced power flow
control devices, and SCADA-based implementation equipment (and service
providers thereto) may cause shortages that will constrain transmission
facility developers and owners.\2542\ Pattern Energy adds that, when
evaluating the costs to implement such devices, transmission providers
may need to assume cost parameters (e.g., cost per mile or cost per
installation) for such devices in order to have an ``apples-to-apples
comparison.'' \2543\
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\2542\ Pattern Energy Initial Comments at 29-30.
\2543\ Id. at 30.
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3. Need for Reform
1194. Based on the record, we find that there is substantial
evidence to support the conclusion that the Commission's existing
regional transmission planning requirements are unjust, unreasonable,
and unduly discriminatory or preferential because they do not require
consideration of alternative transmission technologies in the regional
transmission planning process. We therefore adopt the preliminary
findings in the NOPR concerning the need for reform. Specifically, we
find that the Commission's existing regional transmission planning
requirements fail to ensure that transmission providers consider
whether to incorporate alternative transmission technologies into
regional transmission facilities as part of their regional transmission
planning processes and, consequently, fail to ensure that transmission
providers are identifying more efficient or cost-effective regional
transmission solutions through those processes. As a result,
transmission providers overlook or undervalue the benefits of certain
alternative transmission technologies and, in turn, undertake
relatively inefficient and less cost-effective investments in
transmission infrastructure, the costs of which are ultimately
recovered through Commission-jurisdictional rates. Accordingly, we find
that existing regional transmission planning requirements are
insufficient to ensure just and reasonable and not unduly
discriminatory or preferential rates.
1195. In the NOPR, the Commission stated that commercially
available alternative transmission technologies have the potential to
improve the operation of new and existing transmission facilities and
defer or mitigate the need for new transmission investments.\2544\
However, existing regional transmission planning processes are not
necessarily designed to consider the benefits that alternative
transmission technologies can provide.\2545\ Commenters state that some
transmission providers are reluctant to implement alternative
transmission technologies or that alternative transmission technologies
are not consistently evaluated in regional transmission planning in a
manner commensurate with the benefits that they can provide.\2546\ The
failure to consistently consider these technologies in regional
transmission planning prevents them from being identified, evaluated,
and selected as a more efficient or cost-effective solution to
transmission needs, to the detriment of customers that can benefit from
their deployment.
---------------------------------------------------------------------------
\2544\ NOPR, 179 FERC ] 61,028 at P 267.
\2545\ See, e.g., AEE Initial Comments at 29.
\2546\ Certain TDUs Initial Comments at 22-23; Invenergy Initial
Comments at 15-16; NASUCA Initial Comments at 7; WATT Coalition
Initial Comments at 4.
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1196. The record demonstrates that alternative transmission
technologies can provide significant capacity increases when
incorporated into transmission facilities, and that such incorporation
may provide benefits that outweigh its costs.\2547\ For example, a
white paper prepared by the Brattle Group highlights several recent
examples in which dynamic line ratings, transmission switching, and
advanced power flow control devices were deployed to cost-effectively
meet transmission needs in SPP, MISO, and other utility service
territories.\2548\ Additionally, a recent US DOE case study on dynamic
line ratings and advanced power flow control devices estimates that
these alternative transmission technologies can provide significant
production cost savings, net import savings, and avoided curtailment
savings.\2549\
---------------------------------------------------------------------------
\2547\ See, e.g., WATT Coalition Supplemental Comments at 2-3.
\2548\ The Brattle Group, Building a Better Grid: How Grid-
Enhancing Technologies Complement Transmission Buildouts 12-15 (Apr.
20, 2023), https://watt-transmission.org/wp-content/uploads/2023/04/Building-a-Better-Grid-How-Grid-Enhancing-Technologies-Complement-Transmission-Buildouts.pdf.
\2549\ US DOE, Grid-Enhancing Technologies: A Case Study on
Ratepayer Impact v-x (Feb. 2022), https://www.energy.gov/sites/default/files/2022-04/Grid%20Enhancing%20Technologies%20-%20A%20Case%20Study%20on%20Ratepayer%20Impact%20-%20February%202022%20CLEAN%20as%20of%20032322.pdf.
---------------------------------------------------------------------------
1197. We find that the failure to require transmission providers to
consider alternative transmission technologies renders the Commission's
existing regional transmission planning requirements insufficient to
ensure just and reasonable and not unduly discriminatory or
preferential rates, we are now requiring, pursuant to FPA section 206,
that transmission providers consider in Long-Term Regional Transmission
Planning and their existing Order No. 1000 regional transmission
planning process the alternative transmission technologies discussed
below. While the record indicates that some of the alternative
transmission technologies enumerated in this final order are sometimes
considered in certain transmission planning regions as solutions to
specific transmission needs,\2550\ we find that inconsistent
consideration of alternative transmission technologies in regional
transmission planning results in transmission providers overlooking or
undervaluing the benefits that these technologies can provide. We find
that the reforms concerning the consideration of alternative
transmission technologies that we adopt in this final order will render
the Commission's existing regional transmission planning requirements
just and reasonable, because they will result in transmission providers
identifying, evaluating, and selecting regional transmission facilities
that are more efficient or cost-effective, which will ensure that
Commission-jurisdictional rates are just and reasonable.
---------------------------------------------------------------------------
\2550\ See Exelon Initial Comments at 21-23.
---------------------------------------------------------------------------
4. Commission Determination
1198. We adopt the NOPR proposal, with modification, to require
transmission providers in each transmission planning region to
consider, in Long-Term Regional Transmission Planning and existing
Order No. 1000 regional transmission planning processes, dynamic line
[[Page 49467]]
ratings and advanced power flow control devices for each identified
transmission need. We modify the NOPR proposal to require that, in
addition to dynamic line ratings and advanced power flow control
devices, transmission providers must consider in Long-Term Regional
Transmission Planning and existing Order No. 1000 regional transmission
planning processes advanced conductors and transmission switching.
Thus, under this modification, transmission providers must consider:
(1) dynamic line ratings; \2551\ (2) advanced power flow control
devices; \2552\ (3) advanced conductors; \2553\ and (4) transmission
switching.\2554\ We clarify that transmission providers must consider
each of these enumerated technologies when evaluating new regional
transmission facilities, as well as upgrades to existing transmission
facilities.\2555\ Thus, for each identified transmission need, when
evaluating regional transmission facilities for potential selection,
transmission providers must consider whether regional transmission
facilities that incorporate, or solely consist of, any of the
enumerated list of alternative transmission technologies would be more
efficient or cost-effective than selecting new regional transmission
facilities or upgrades to existing transmission facilities that do not
incorporate these technologies.
---------------------------------------------------------------------------
\2551\ A dynamic line rating is ``a transmission line rating
that applies to a time period of not greater than one hour and
reflects up-to-date forecasts of inputs such as (but not limited to)
ambient air temperature, wind, solar heating, transmission line
tension, or transmission line sag.'' NOPR, 179 FERC ] 61,028 at P
259 n.408 (citations omitted); see also Order No. 881, 177 FERC ]
61,179 at P 7; Implementation of Dynamic Line Ratings, 178 FERC ]
61,110 at P 1.
\2552\ Advanced power flow control devices serve a transmission
function. These devices can help the system operator control power
flows over a given path and can include phase shifting transformers
(also known as phase angle regulators) and devices or systems
necessary for implementing optimal transmission switching. Advanced
power flow control devices allow power to be pushed and pulled to
alternate lines with spare capacity leading to maximum utilization
of existing transmission capacity. NOPR, 179 FERC ] 61,028 at P 270
n.437.
\2553\ Advanced conductors include present and future
transmission line technologies whose power flow capacities exceed
the power flow capacities of conventional aluminum conductor steel
reinforced conductors. See Order No. 2023-A, 186 FERC ] 61,199 at
631.
\2554\ Transmission switching is the opening or closing of
transmission elements to safely route power and direct flows away
from congestion, based on pre-existing forward analysis.
\2555\ We note that upgrades to existing transmission facilities
include both: (1) the incorporation of an alternative transmission
technology into an existing transmission facility with no additional
changes to the underlying transmission facility (e.g., adding
dynamic line ratings to an existing transmission facility); and (2)
the incorporation of an alternative transmission technology into an
existing transmission facility as part of a larger set of upgrades
(e.g., adding dynamic line ratings to a transmission facility that
is also being reconductored with a conventional aluminum conductor
steel reinforced conductor).
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1199. However, transmission providers' evaluation of the enumerated
alternative transmission technologies must be consistent with the
requirements in their OATTs for other transmission solutions. This
means that, for the purposes of Long Term Regional Transmission
Planning, transmission providers must evaluate the benefits of
incorporating the enumerated alternative transmission technologies into
Long-Term Regional Transmission Facilities in the same manner that they
evaluate any Long-Term Regional Transmission Facility, and in a manner
consistent with the requirements in the Evaluation of Benefits of
Regional Transmission Facilities and Evaluation and Selection of Long-
Term Regional Transmission Facilities sections of this final order.
Accordingly, we require transmission providers to measure the required
benefits and any additional benefits the transmission providers elect
to measure, as discussed in detail in the Required Benefits
section,\2556\ and use those measured benefits in their evaluation
processes to determine if a regional transmission facility that
incorporates, or solely consists of, any of the enumerated list of
alternative transmission technologies would more efficiently or cost-
effectively address Long-Term Transmission Needs. As discussed in
detail in the Evaluation and Selection of Long-Term Regional
Transmission Facilities section,\2557\ that determination would involve
applying the transmission providers' selection criteria, which must,
among other things, seek to maximize benefits accounting for costs over
time without over-building transmission facilities. Similarly, for the
purposes of existing Order No. 1000 regional transmission planning
processes, transmission providers must consider the benefits of
incorporating the enumerated alternative transmission technologies into
transmission facilities in the same way that they currently evaluate
regional transmission facilities in those existing processes to
determine if a regional transmission facility incorporating any of the
enumerated transmission technologies would be a more efficient or cost-
effective regional transmission solution.
---------------------------------------------------------------------------
\2556\ Supra Required Benefits section.
\2557\ Supra Evaluation and Selection of Long-Term Regional
Transmission Facilities section.
---------------------------------------------------------------------------
1200. In response to concerns regarding the mandatory consideration
of the enumerated alternative transmission technologies for new
regional transmission facilities,\2558\ and the incremental increase in
costs associated with incorporating an alternative transmission
technology into new regional transmission facilities or upgrades to
existing transmission facilities,\2559\ we reiterate that transmission
providers must follow the evaluation process and selection criteria in
their tariffs. As explained in the Evaluation and Selection of Long-
Term Regional Transmission Facilities section of this final order, this
does not require transmission providers to select any particular Long-
Term Regional Transmission Facility to address Long-Term Transmission
Needs (i.e., in this case it does not require the selection and
deployment of any particular alternative transmission technology with
regard to any particular Long-Term Transmission Need).\2560\ We
recognize that, in addition to considering the costs and benefits
associated with incorporating alternative transmission technologies
into transmission facilities, transmission providers must continue to
follow Good Utility Practice with regard to planning, evaluating,
selecting, constructing, operating, and maintaining all transmission
facilities, whether such transmission facilities are considered and
implemented through existing regional transmission planning processes
or as part of Long-Term Regional Transmission Planning as set forth in
this final order.\2561\
---------------------------------------------------------------------------
\2558\ CAISO Initial Comments at 6; Exelon Initial Comments at
21-22.
\2559\ Exelon Initial Comments at 19-20.
\2560\ Supra Evaluation and Selection of Long-Term Regional
Transmission Facilities section.
\2561\ See pro forma OATT section 28.2 (Transmission Provider
Responsibilities) (``The Transmission Provider will plan, construct,
operate and maintain its Transmission System in accordance with Good
Utility Practice and its planning obligations in Attachment K in
order to provide the Network Customer with Network Integration
Transmission Service over the Transmission Provider's Transmission
System.'').
---------------------------------------------------------------------------
1201. We find that it is appropriate to require transmission
providers to consider whether it may be more efficient or cost-
effective to incorporate the enumerated alternative transmission
technologies into both new regional transmission facilities and
upgrades to existing transmission facilities because the record
indicates that such technologies can provide benefits by improving the
efficiency of transmission facilities, regardless of whether the
facilities are already in-service or yet to be deployed.\2562\ We find
that incorporating the enumerated
[[Page 49468]]
alternative transmission technologies as upgrades to existing
transmission facilities has the potential to make the use of existing
transmission infrastructure more efficient and optimize the performance
of such infrastructure, mitigating or deferring the need for
development of new regional transmission facilities.\2563\ Adding
alternative transmission technologies to new regional transmission
facilities may provide cost savings by improving operational efficiency
of transmission facilities. Further, incorporating alternative
transmission technologies into new transmission facilities may present
more benefits and cost less than incorporating such technologies as
retrofits after the regional transmission facility is deployed. We
further find that requiring transmission providers to consider the
enumerated alternative transmission technologies in Long-Term Regional
Transmission Planning and existing regional transmission planning
processes will ensure that transmission providers more fully consider a
broader set of technologies that can address transmission needs more
efficiently or cost-effectively.
---------------------------------------------------------------------------
\2562\ See WATT Coalition Supplemental Comments at 2-3.
\2563\ Pattern Energy Initial Comments at 29.
---------------------------------------------------------------------------
1202. We clarify that the selection and use any of the enumerated
alternative transmission technologies that are incorporated into an
existing transmission facility should be treated as an upgrade to an
existing transmission facility. Order No. 1000's elimination of any
Federal right of right of first refusal for selected transmission
facilities does not apply to upgrades to an existing transmission
facility.\2564\ Therefore, an incumbent transmission provider would be
designated to develop any alternative transmission technology that is
selected for incorporation into that incumbent transmission provider's
existing transmission facilities as the more efficient or cost-
effective solution.
---------------------------------------------------------------------------
\2564\ The Commission stated in Order No. 1000 that the non-
incumbent transmission developer reforms do not affect the right of
an incumbent transmission provider to build, own and recover costs
for upgrades to its own transmission facilities, such as in the case
of tower change outs or reconductoring, regardless of whether or not
an upgrade has been selected in the regional transmission plan for
purposes of cost allocation. In other words, an incumbent
transmission provider would be permitted to maintain a Federal right
of first refusal for upgrades to its own transmission facilities.
Order No. 1000, 136 FERC ] 61,051 at P 319 (footnote omitted). The
Commission clarified that ``the term upgrade means an improvement
to, addition to, or replacement of a part of, an existing
transmission facility. The term upgrades does not refer to an
entirely new transmission facility.'' Order No. 1000-A, 139 FERC ]
61,132 at P 426. The Commission further clarified that the
requirement to eliminate a Federal right of first refusal does not
apply to any upgrade, even where the upgrade requires the expansion
of an existing right-of-way. Id. P 427.
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1203. With respect to alternative transmission technologies added
or deployed on a new selected regional transmission facility, we
clarify that the transmission developer that is designated to develop
the underlying selected regional transmission facility, whether that
developer is an incumbent transmission provider or a nonincumbent
transmission developer, must also be designated to develop any
alternative transmission technologies selected to be incorporated into
the regional transmission facility, and thus, would be eligible to use
the applicable regional cost allocation method.\2565\ For example, in a
competitive bidding model, the transmission developer that submits the
winning bid for a selected new regional transmission facility that
includes an alternative transmission technology would be eligible to
use the regional cost allocation method for that facility, including
for the costs of any alternative transmission technologies. Similarly,
in a sponsorship model, the transmission developer that sponsors a new
regional transmission facility that includes any alternative
transmission technologies would be eligible to use the regional cost
allocation method for that facility, including for the costs of any
alternative transmission technologies, consistent with the selection.
---------------------------------------------------------------------------
\2565\ See FERC, Staff Report, 2017 Transmission Metrics 8 (Oct.
6, 2017), https://www.ferc.gov/sites/default/files/2020-05/transmission-investment-metrics.pdf (describing the two general
types of competitive transmission development processes, the
``competitive bidding model'' and the ``sponsorship model'').
---------------------------------------------------------------------------
1204. We further clarify that, under a sponsorship model,
transmission providers' addition of an alternative transmission
technology to a sponsored regional transmission facility proposal that
is ultimately selected must not lead to the original sponsored regional
transmission facility being labeled as an unsponsored regional
transmission facility. Therefore, the sponsoring developer would be
eligible to use the regional cost allocation method for the selected
new regional transmission facility, as modified with the alternative
transmission technology.
1205. We also clarify that, for every competitive transmission
development process in a given transmission planning region,
transmission providers must identify with sufficient detail in their
OATTs the point or points in a given process at which the transmission
providers in the transmission planning region will consider the
potential use of alternative transmission technologies, including the
point at which qualified transmission developers must submit any
proposal to incorporate alternative transmission technologies. This
clarification is meant to ensure transparency for competing
transmission developers and other stakeholders.\2566\
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\2566\ For example, in a competitive bidding model, transmission
providers must make clear whether, and if so when, a qualified
transmission developer can propose to incorporate alternative
transmission technologies into a bid for a selected Long-Term
Regional Transmission Facility. This transparency requirement
ensures that competing transmission developers will be treated
comparably because they will know whether and when they can propose
to incorporate any additional alternative transmission technologies
into a bid for a regional transmission facility that has been
selected.
---------------------------------------------------------------------------
1206. In response to comments that transmission providers should
not be required to consider the enumerated alternative transmission
technologies in regional transmission planning processes due to the
costs and challenges associated with implementation,\2567\ we find that
the examples in the record of implementation of dynamic line ratings,
including ERCOT's experience with dynamic line ratings since 2005 and
data from Oncor from 2011 to 2013,\2568\ and overall support for the
consideration of advanced power flow control devices in transmission
planning,\2569\ sufficiently demonstrate that transmission providers
are capable of considering the enumerated alternative transmission
technologies in Long-Term Regional Transmission Planning and existing
regional transmission planning processes. Kansas Commission's position
that consideration of alternative transmission technologies in regional
transmission planning processes should be data-driven and supported by
robust analysis demonstrating benefits is consistent with our
determinations here.\2570\ Therefore, transmission providers must
consider the incorporation of these enumerated alternative transmission
technologies consistent with the specific requirements for analysis and
evaluation of benefits in their OATTs, including those applicable to
existing regional transmission planning processes and those required in
this final order for Long-Term Regional
[[Page 49469]]
Transmission Planning.\2571\ We acknowledge Mississippi Commission's
concerns about deploying alternative transmission technologies without
consideration of their costs and note that, to the extent that a
transmission provider selects a regional transmission facility that
incorporates an enumerated alternative transmission technology, the
transmission provider would only do so after evaluating the costs and
benefits of that transmission facility, including the incorporation of
the alternative transmission technology.\2572\
---------------------------------------------------------------------------
\2567\ See, e.g., ATC Reply Comments at 3.
\2568\ Hannon Armstrong Reply Comments at 2-3; WATT Coalition
Reply Comments at app. B.
\2569\ Ameren Initial Comments at 24-25; EEI Initial Comments at
20-21; Entergy Initial Comments at 29; Exelon Initial Comments at
23.
\2570\ Kansas Commission Initial Comments at 19-20.
\2571\ See supra Evaluation of the Benefits of Regional
Transmission Facilities section.
\2572\ Mississippi Commission Reply Comments at 8.
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1207. We disagree with commenter assertions that alternative
transmission technologies are only operational tools and that
transmission providers cannot rely on any additional capacity created
by these technologies for the purpose of meeting transmission
needs.\2573\ We note that Long-Term Regional Transmission Planning and
existing regional transmission planning processes are designed to
address a variety of needs, including not only reliability needs but
also Long-Term Transmission Needs and economic needs. These processes
are well-suited to evaluate the economic benefits of the enumerated
alternative transmission technologies, which are relevant to assessing
whether a regional transmission facility that incorporates such
technologies is more efficient or cost-effective than a proposed
regional transmission facility that does not use such technologies. We
believe that the particular benefit measurement methods that
transmission providers must develop, pursuant to requirements discussed
below, to evaluate proposed Long-Term Regional Transmission Facilities
can be used to measure the economic benefits of incorporating the
enumerated alternative transmission technologies into transmission
facilities.\2574\ As more fully described above in the Required
Benefits section, these benefits include, but are not limited to,
methods to measure production cost savings, reduced congestion due to
fewer transmission outages, and capacity cost benefits from reduced
peak energy losses. Similarly, we find that the enumerated alternative
transmission technologies can provide those economic benefits that are
already evaluated in existing regional transmission planning processes.
Finally, contrary to commenters' concerns, the record here demonstrates
that certain alternative transmission technologies are in some cases
capable of enhancing reliability and providing additional
capacity.\2575\
---------------------------------------------------------------------------
\2573\ AEP Initial Comments at 6, 33; Indicated PJM TOs Initial
Comments at 19; ITC Initial Comments at 6, 26-28; Louisiana
Commission Initial Comments at 14 (citing Potomac Economics Initial
Comments at 2); PJM Initial Comments at 8, 106, 108; PPL Initial
Comments at 22; SERTP Sponsors Initial Comments at 36-37.
\2574\ See supra Evaluation of the Benefits of Regional
Transmission Facilities section.
\2575\ See infra P 1241 for a more detailed discussion of the
reliability benefits of dynamic line ratings and advanced power flow
control devices; see also Ameren Initial Comments at 24; Bekaert
Supplemental Comments at 1-2; CTC Global Initial Comments at 15.
---------------------------------------------------------------------------
1208. In response to concerns about administrative burden and
assertions that predictions about benefits are speculative,\2576\ we
find that the potential advantages associated with adopting this reform
(i.e., identifying more efficient or cost-effective regional
transmission solutions) outweigh the potential administrative and
analytical burden. As it pertains to dynamic line ratings, the
information needed to inform the calculation of dynamic line ratings
should be widely available. For example, NREL has published data on
annual averages of windspeeds at 10 meters above the ground that could
inform predictions for future wind conditions to facilitate
calculations of economic benefits.\2577\ For the calculation of the
economic benefits associated with dynamic lines ratings, it is
appropriate for such calculations to use historical average wind speed
and direction data to calculate average increases to transmission line
transfer limits for use in benefit calculations. Average predicted wind
speeds and direction should be sufficient to inform the transmission
provider as to whether the implementation of dynamic line ratings on a
specific transmission line may render that line a more efficient or
cost-effective regional transmission solution, and such data are widely
available.\2578\ We acknowledge that there is uncertainty with
projections of any kind; however, it is not necessary to understand the
precise future wind conditions at a specific future period to assess
the expected economic benefits associated with the implementation of
dynamic line ratings.
---------------------------------------------------------------------------
\2576\ ATC Initial Comments at 10; Duke Initial Comments at 30-
31 (citing attach. A, Robert Pierce Aff. ]] 8-9); ISO-NE Initial
Comments at 40-41; ITC Initial Comments at 26; Kansas Commission
Initial Comments at 19-20; Large Public Power Initial Comments at
32-33; MISO Initial Comments at 58; MISO TOs Initial Comments at 24;
New York TOs Initial Comments at 22; Pacific Northwest Utilities
Initial Comments at 15-16; SERTP Sponsors Initial Comments at 36-37;
Southern Initial Comments at 35, Ex. 2, Daryl C. McGee at ] 16; US
Chamber of Commerce Initial Comments at 9.
\2577\ Data on annual averages of windspeeds at 10 meters above
the ground is published by NREL in the form of both maps and tabular
data. See NREL, Wind Resource Maps and Data, https://www.nrel.gov/gis/wind-resource-maps.html. As another example, data on monthly
prevailing wind direction is published by the U.S. Department of
Agriculture for various cities in all U.S. states in the form of
graphical ``wind roses.'' See U.S. Dep't. of Agric., National.
Weather and Climate Center, https://www.wcc.nrcs.usda.gov/ftpref/downloads/climate/windrose/.
\2578\ See, e.g., NREL, Wind Resource Maps and Data, https://www.nrel.gov/gis/wind-resource-maps.html; U.S. Dep't of Agric.,
National Weather and Climate Center, https://www.wcc.nrcs.usda.gov/ftpref/downloads/climate/windrose/.
---------------------------------------------------------------------------
1209. In response to arguments that the Commission should favor
transmission provider flexibility with respect to consideration of
alternative transmission technologies,\2579\ we note that the reforms
adopted in this final order provide transmission providers with an
appropriate amount of flexibility and do not require the selection of
any particular enumerated alternative transmission technology to
address any particular transmission need. As previously discussed, this
requirement will ensure that transmission providers more consistently
consider the costs and benefits associated with incorporating the
enumerated alternative transmission technologies into regional
transmission facilities. However, we recognize that transmission
providers must also continue to follow Good Utility Practice when
planning, evaluating, selecting, constructing, operating, and
maintaining transmission facilities.
---------------------------------------------------------------------------
\2579\ Avangrid Initial Comments at 31; Clean Energy Buyers
Initial Comments at 25; Eversource Initial Comments at 27; Georgia
Commission Initial Comments at 7-8; Idaho Power Initial Comments at
9; New York TOs Initial Comments at 23; OMS Initial Comments at 9;
PPL Initial Comments at 23.
---------------------------------------------------------------------------
1210. Moreover, we decline to mandate further details on how
transmission providers should evaluate the enumerated list of
alternative transmission technologies as more efficient or cost-
effective solutions to transmission needs, beyond the requirements
adopted in this final order. Thus, in response to comments from Smart
Wires and WATT Coalition proposing that the Commission mandate either
consideration or deployment of advanced power flow control devices in
specific situations,\2580\ we find that transmission providers are the
appropriate entity to identify, evaluate, and select specific solutions
to specific transmission needs.\2581\
---------------------------------------------------------------------------
\2580\ Smart Wires Initial Comments at 1, 3-5; WATT Coalition
Initial Comments at 3-4.
\2581\ See Order No. 1000, 136 FERC ] 61,051 at P 153 (noting
that transmission providers retain the ultimate responsibility for
transmission planning). As Entergy and Exelon attest, advanced power
flow control devices are already considered in some transmission
planning processes. See Entergy Initial Comments at 29; Exelon
Initial Comments at 23.
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[[Page 49470]]
1211. In response to commenters urging the Commission to wait for
transmission providers to comply with Order No. 881 before implementing
the NOPR proposal,\2582\ such concerns are unpersuasive. Public utility
transmission providers subject to Order No. 881 are required to
implement these requirements by July 12, 2025.\2583\ As the Compliance
Procedures section of the final order states, the date that
transmission providers are required to begin considering the enumerated
alternative transmission technologies will be the effective date of the
applicable tariff provisions submitted to comply with this final order
requirement. The final order also states that transmission providers
must submit their compliance filings within ten months of the effective
date of this final order, which is 60 days from the date of publication
in the Federal Register. Moreover, even if the compliance submission
deadline falls shortly before Order No. 881's implementation deadline,
the operative date here is the date that the tariff revisions proposed
in a transmission provider's compliance filing to this final order
become effective, which is the effective date requested by the
submitting transmission provider and accepted by the Commission.\2584\
Consequently, the transmission provider would not need to implement
this final order requirement prior to the implementation of Order No.
881 on July 12, 2025 unless it requests, and the Commission accepts, an
earlier effective date for its tariff revisions.
---------------------------------------------------------------------------
\2582\ ATC Reply Comments at 4-5; Dominion Initial Comments at
40; Large Public Power Initial Comments at 5, 32-33; MISO TOs
Initial Comments at 23-24.
\2583\ See MATL LLP, 185 FERC ] 61,028, at P 10 (2023) (stating
that July 12, 2025 is the implementation date of Order No.
881(citing Order No. 881, 177 FERC ] 61,179 at P 361)).
\2584\ See infra Compliance Procedures section.
---------------------------------------------------------------------------
1212. Moreover, we find that concerns raised by commenters with
respect to the interactions between the requirements that we establish
in this final order and Order No. 881 to be speculative. We believe
that the requirements to consider the enumerated alternative
transmission technologies are separate from (but complementary to) the
Commission's requirements in Order No. 881. In Order No. 881, as most
relevant here, the Commission required the use of more accurate
transmission line ratings using up-to-date forecasts of ambient air
temperatures in transmission line ratings. By contrast, regarding the
requirement to consider dynamic line ratings in this final order,
transmission providers must consider the benefits associated with
additional up-to-date transmission line rating input assumptions,
specifically wind speed and direction and solar heating intensity.
1213. We disagree with concerns that any mandate to consider
dynamic line ratings in this proceeding might complicate the dynamic
line ratings notice of inquiry (NOI) proceeding,\2585\ or that a
mandate to consider dynamic line ratings in this proceeding ignores the
record, and the technical challenges identified in, the dynamic line
ratings NOI proceeding.\2586\ We find such concerns unpersuasive. Any
potential future Commission action in the dynamic line ratings NOI
proceeding remains hypothetical. Moreover, we expect transmission
providers to consider both the benefits of dynamic line rating
implementation and the challenges and costs associated with dynamic
line rating implementation as part of their consideration of the
technology in Long-Term Regional Transmission Planning and their
existing regional transmission planning processes.
---------------------------------------------------------------------------
\2585\ MISO TOs Initial Comments at 23-24.
\2586\ Large Public Power Initial Comments at 32.
---------------------------------------------------------------------------
1214. In response to requests for additional transparency,\2587\ we
also adopt the NOPR proposal to expand the existing requirement
established in Order No. 1000 for transmission providers' evaluation
processes to culminate in a determination that is sufficiently detailed
for stakeholders to understand why a particular transmission facility
was selected or not selected. Specifically, we adopt the NOPR proposal
to require that the determination include an explanation that is
sufficiently detailed for stakeholders to understand why dynamic line
ratings, advanced power flow control devices, advanced conductors, and/
or transmission switching were or were not incorporated into selected
regional transmission facilities.
---------------------------------------------------------------------------
\2587\ Certain TDUs Reply Comments at 8-9; DC and MD Offices of
People's Counsel Initial Comments at 36; ENGIE Initial Comments at
6; PIOs Initial Comments at 22.
---------------------------------------------------------------------------
1215. With regard to the Commission's request for comment on
whether to require non-RTO/ISO transmission planning regions to update
their energy management systems or make other similar changes if
dynamic line ratings are selected as a more efficient or cost-effective
regional transmission facility, we require transmission providers to
update their energy management systems, if needed to implement dynamic
line ratings or any of the alternative transmission technologies. We
note that some transmission providers in non-RTO/ISO transmission
planning regions may already be able to implement the alternative
transmission technologies, and, as a result of the Commission's
Ambient-Adjusted Rating requirements in Order No. 881,\2588\ may have
already updated their energy management systems, and therefore may not
need further updates to their energy management systems. However, if a
transmission provider must upgrade its energy management systems to
implement any of the alternative transmission technologies, then
consistent with other requirements in this final order, we require
transmission providers to consider any possible energy management
system upgrade costs needed to implement the selected alternative
transmission technologies as part of their broader consideration of
whether transmission facilities that incorporate alternative
transmission technologies are more efficient or cost-effective regional
transmission solutions. We further reiterate that transmission
providers must provide an explanation that is sufficiently detailed for
stakeholders to understand why any of the enumerated alternative
transmission technologies were, or were not, incorporated into
transmission facilities selected in the regional transmission plan for
purposes of cost allocation. Moreover, we clarify that this explanation
must be sufficiently clear to demonstrate whether the transmission
provider did not select transmission facilities that incorporate any of
the enumerated alternative transmission technologies, in part or
primarily, due to concerns over the costs of upgrading energy
management systems.
---------------------------------------------------------------------------
\2588\ Order No. 881, 177 FERC ] 61,179 at P 84.
---------------------------------------------------------------------------
1216. Finally, we find that WATT Coalition's request to consider
incentives for deploying alternative transmission technologies is
outside the scope of this proceeding.
B. Specific Alternative Transmission Technologies
1. NOPR Proposal
1217. The Commission sought comment on whether there are other
transmission technologies serving a transmission function that should
be considered in regional transmission planning and cost allocation
processes. The following section discusses comments on specific
alternative transmission technologies that transmission providers are
required to
[[Page 49471]]
consider pursuant to the requirements of this final order.
2. Comments on Specific Technologies
1218. AEE notes that dynamic line ratings implementation will
increase capacity and provide significant benefits to customers.\2589\
Michigan State Entities state that dynamic line ratings hold tremendous
value for states like Michigan with cold, cloudy winters, during which
there is a greater reliance on transmission to move distant wind
generation.\2590\
---------------------------------------------------------------------------
\2589\ AEE Reply Comments at 29 (citing US DOE, Dynamic Line
Ratings Report to Congress 2019 26 (June 2022), https://www.energy.gov/sites/prod/files/2019/08/f66/Congressional_DLR_Report_June2019_final_508_0.pdf).
\2590\ Michigan State Entities Initial Comments at 10.
---------------------------------------------------------------------------
1219. AEE states that dynamic line ratings and similar technologies
are so useful because they improve predictability.\2591\ AEE further
contends that, in the longer-term, changing conditions will necessitate
greater transmission deployment and the need for more transmission
capacity, but without considering complementary technologies, the
transmission buildout may be less efficient.\2592\
---------------------------------------------------------------------------
\2591\ AEE Reply Comments at 30 (citing MISO Initial Comments at
57-58).
\2592\ Id.
---------------------------------------------------------------------------
1220. Hannon Armstrong contends that ERCOT's experience with
dynamic line ratings since 2005, as well as data from Oncor from 2011
to 2013, demonstrates that this technology can provide significant
savings through reduced congestion costs, allow for granular congestion
management, and furnish congestion data. According to Hannon Armstrong,
real-time dynamic ratings and reliability analysis improve transmission
system operation and planning, provide opportunities for congestion
mitigation, and could justify the cancellation of planned transmission
upgrades. Hannon Armstrong concludes that dynamic line ratings can
promote just and reasonable rates without compromising
reliability.\2593\
---------------------------------------------------------------------------
\2593\ Hannon Armstrong Reply Comments at 2.
---------------------------------------------------------------------------
1221. As mentioned above, some commenters warn the Commission of
potential reliability and operational impacts of the widespread use of
dynamic line ratings.\2594\ Entergy explains that it has experienced
significantly different weather readings at nearby weather sensors and
cautions that the 2003 blackout was partially caused by overestimating
the wind in transmission line ratings.\2595\
---------------------------------------------------------------------------
\2594\ Duke Initial Comments at 31-32 (citing attach. A, Robert
Pierce Aff. ] 11); Entergy Initial Comments at 27-28; MISO Initial
Comments at 59-60.
\2595\ Entergy Initial Comments at 27-28 (citing U.S. Canada
Power System Outage Task Force, Final Report on the August 14, 2003
Blackout in the United States and Canada: Causes and Recommendations
58 (Apr. 2004)).
---------------------------------------------------------------------------
1222. Some commenters that oppose the use of dynamic line ratings
in transmission planning raise concerns about the reliability risks
presented by dynamic line ratings.\2596\ PJM argues that dynamic line
ratings are inappropriate for addressing reliability needs and may
introduce operational risk because, for example, forecasted wind might
not materialize and the actual real-time ratings would be lower than
forecasted.\2597\ Southern argues that the assumption of dynamic line
ratings leading to additional capacity will likely result in reduced
system expansion, which could cause reliability problems in the long
run.\2598\ Large Public Power and LADWP maintain that there is
meaningful cybersecurity risk associated with the communications
equipment needed to support dynamic line ratings.\2599\ However, WATT
Coalition states that both traditional transmission solutions and grid
enhancing technologies can result in problems, so the impact of
solutions should be evaluated carefully to ensure that a solution to
one problem does not create another.\2600\
---------------------------------------------------------------------------
\2596\ ATC Initial Comments at 7, 10; Duke Initial Comments at
31; Exelon Initial Comments at 22; Indicated PJM TOs Initial
Comments at 19; LADWP Initial Comments at 5; NRECA Initial Comments
at 53; PJM Initial Comments at 108-109; Southern Initial Comments at
35 (citing Ex. 2, Daryl C. McGee at ] 17); SERTP Sponsors Initial
Comments at 36-37.
\2597\ PJM Initial Comments at 108-109.
\2598\ Southern Initial Comments at 35, Ex. 2, Daryl McGee at ]
17.
\2599\ LADWP Initial Comments at 5; Large Public Power Initial
Comments at 35.
\2600\ WATT Coalition Reply Comments at 4-5.
---------------------------------------------------------------------------
1223. Some commenters argue that dynamic line ratings are
operational in nature and do not belong in the transmission planning
process.\2601\ Dominion and Exelon state that a transmission provider
must plan and build its system for worst case scenarios, which limits
the usefulness of dynamic line ratings in transmission planning.\2602\
ITC asserts that transmission systems must be planned based on actual
transfer capacity under the worst-case scenario, and not on contingent,
variable capacity of the type that dynamic line ratings provide.\2603\
EEI and Entergy note that the inherent variability and unpredictability
associated with wind speed, solar heating intensity, and transmission
line tension make dynamic line ratings inappropriate for addressing
longer-term system planning objectives.\2604\ MISO adds that for
transmission planning horizons of five to 20 years or more into the
future, it is impossible to predict the real-time conditions on which
dynamic line ratings are based.\2605\ NRECA explains that dynamic line
ratings are not a substitute for an upgraded or new transmission
facility.\2606\
---------------------------------------------------------------------------
\2601\ AEP Initial Comments at 33; Dominion Initial Comments at
40; Duke Initial Comments at 5; EEI Initial Comments at 21-22;
Entergy Initial Comments at 5-6; Exelon Initial Comments at 22;
Indicated PJM TOs Initial Comments at 19; ISO-NE Initial Comments at
40-41; ITC Initial Comments at 6, 26-28; Louisiana Commission
Initial Comments at 14 (citing Potomac Economics Initial Comments at
2); MISO Initial Comments at 57; MISO TOs Initial Comments at 23;
NRECA Initial Comments at 52; Pacific Northwest Utilities Initial
Comments at 15-16; PJM Initial Comments at 8, 106, 108; PPL Initial
Comments at 22; Southern Initial Comments at 35; SERTP Sponsors
Initial Comments at 36-37; US Chamber of Commerce Initial Comments
at 9.
\2602\ Dominion Initial Comments at 40; Exelon Initial Comments
at 22.
\2603\ ITC Initial Comments at 26.
\2604\ EEI Initial Comments at 21; Entergy Initial Comments at
27.
\2605\ MISO Initial Comments at 57-58.
\2606\ NRECA Initial Comments at 52.
---------------------------------------------------------------------------
1224. Many opposing commenters argue that the benefits of dynamic
line ratings are too speculative.\2607\ MISO states that dynamic line
ratings may not always produce the benefits anticipated, explaining
that static ratings are typically based on conservative wind speeds and
best-case wind direction, so the assumptions used to develop static
ratings are not always worst-case.\2608\ ISO-NE asserts that, for
example, under summer peak load conditions, the dynamic line rating
would be the same as that assumed in the planning study.\2609\ Southern
cautions that including dynamic line ratings in transmission planning
would likely assume additional capacity that may not materialize in
real time, increasing congestion.\2610\ Large Public Power and MISO TOs
argue that dynamic line ratings do not provide sufficient incremental
benefits over Ambient Adjusted Ratings to justify the additional
expense.\2611\
---------------------------------------------------------------------------
\2607\ ATC Initial Comments at 10; Duke Initial Comments at 30
(citing attach. A, Robert Pierce Aff. ] 8); ISO-NE Initial Comments
at 40-41; ITC Initial Comments at 26; Kansas Commission Initial
Comments at 19-20; Large Public Power Initial Comments at 32-33;
MISO Initial Comments at 58; MISO TOs Initial Comments at 24; New
York TOs Initial Comments at 22; Pacific Northwest Utilities Initial
Comments at 15-16; SERTP Sponsors Initial Comments at 36-37;
Southern Initial Comments at 35, Ex. 2, Daryl C. McGee at ]] 16-17;
US Chamber of Commerce Initial Comments at 9.
\2608\ MISO Initial Comments at 58.
\2609\ ISO-NE Initial Comments at 40-41.
\2610\ Southern Initial Comments at 35, Ex. 2, Daryl C. McGee at
]] 16-17.
\2611\ Large Public Power Initial Comments at 32-33; MISO TOs
Initial Comments at 24.
---------------------------------------------------------------------------
[[Page 49472]]
1225. Some commenters argue that advanced power flow control
devices are appropriate technologies to consider in transmission
planning, contrasting them with dynamic line ratings.\2612\ Southern
states that it generally supports consideration of advanced power flow
control devices, and Ameren argues that they may be appropriate in
certain circumstances for regional transmission planning.\2613\
Additionally, while WATT Coalition agrees that conductor-mounted
advanced power flow control devices are limited in impact, it contends
that today's ground-mounted versions can significantly increase
transfer capacity and integration of renewables.\2614\
---------------------------------------------------------------------------
\2612\ EEI Initial Comments at 20-21; Entergy Initial Comments
at 29; Exelon Initial Comments at 23-24.
\2613\ Ameren Initial Comments at 24-25; Southern Initial
Comments, Ex. 2, Daryl C. McGee at ] 15.
\2614\ WATT Coalition Reply Comments at 4.
---------------------------------------------------------------------------
1226. Industrial Customers assert that the Commission should compel
the use of advanced power flow control devices because they are
instrumental to ensuring that transmission lines are fully used to
their safest and most efficient potential.\2615\ Industrial Customers
further argue that the use of advanced power flow control devices will
allow for the optimization of transmission lines under various weather
conditions.\2616\ Smart Wires states that advanced power flow control
devices can provide a more affordable means of servicing the type of
load growth driving Long-Term Regional Transmission Facilities.\2617\
In addition, Smart Wires argues that several system studies have
verified that advanced power flow control devices avoid sub-synchronous
resonance events on long radial transmission lines, which can result in
extensive damage.\2618\
---------------------------------------------------------------------------
\2615\ Industrial Customers Reply Comments at 13-14.
\2616\ Id. at 18-19 (citing PPL, Initial Comments, Docket No.
AD22-5-000, at 3 (filed Apr. 25, 2022)).
\2617\ Smart Wires Initial Comments at 3-4.
\2618\ Id. at 1, 4.
---------------------------------------------------------------------------
1227. In response to the administrative burden of considering
advanced power flow control devices specifically, WATT Coalition states
that it provides guidance and evidence of successful modeling schemes
for such devices.\2619\ WATT Coalition argues that advanced power flow
control devices are a valuable solution to limitations of power system
studies because they can be adjusted by grid operators for unforeseen
grid challenges.\2620\ WATT Coalition adds that advanced power flow
control devices have a granular dispatchability that can also support
real-time operational needs, which may differ from those identified in
the transmission planning timeframe.\2621\
---------------------------------------------------------------------------
\2619\ WATT Coalition Reply Comments at 3 (citing app. C).
\2620\ Id. at 4.
\2621\ Id.
---------------------------------------------------------------------------
1228. Similar to dynamic line ratings, many commenters argue that
advanced power flow control devices are not appropriate in the
transmission planning context and are more appropriate for operational
timeframes.\2622\ Duke and MISO caution against widespread deployment
of advanced power flow control devices.\2623\ Duke argues that they
should be applied judiciously, and that increased deployment creates a
greater risk of wide area cascading events by increasing the
probability of the system being in a previously unanalyzed state.\2624\
MISO states that, while advanced power flow control devices work best
to address specific isolated issues, it is not feasible to coordinate
the operation and deployment of these devices en masse, either manually
or automatically. According to MISO, deployment of these devices could
create other issues, and thus their operation and deployment must be
managed on a holistic basis.\2625\ MISO further states that advanced
power flow control devices could result in continued cascading issues
across the system because of the potential widespread impact of
adjusting line impedances that may get pushed to other
facilities.\2626\
---------------------------------------------------------------------------
\2622\ AEP Initial Comments at 6; Indicated PJM TOs Initial
Comments at 19; ITC Initial Comments at 6, 26-28; Louisiana
Commission Initial Comments at 14 (citing Potomac Economics Initial
Comments at 2); PJM Initial Comments at 8, 106, 108; PPL Initial
Comments at 22; SERTP Sponsors Initial Comments at 36-37.
\2623\ Duke Initial Comments at 31-32; MISO Initial Comments at
59-60.
\2624\ Duke Initial Comments at 31-32.
\2625\ MISO Initial Comments at 59.
\2626\ Id. at 60.
---------------------------------------------------------------------------
1229. A number of commenters assert that the Commission should
expand the list of alternative transmission technologies that must be
considered.\2627\ Several commenters suggest that the Commission should
require transmission providers to consider specific additional
technologies in Long-Term Regional Transmission Planning, including
storage that performs a transmission function, advanced conductors,
transmission switching, topology optimization, and dynamic reactive
power devices.\2628\ Some Federal legislators agree, offering support
for a requirement to consider energy storage, reconductoring using
advanced conductors,\2629\ and topology optimization.\2630\ AEE argues
that expanding the list of technologies that must be considered in
transmission planning would fulfill the Commission's obligations under
the FPA to encourage the adoption of advanced transmission
technologies.\2631\
---------------------------------------------------------------------------
\2627\ ACEG Initial Comments at 31; ACORE Initial Comments at
16; ACORE Supplemental Comments at 1; AEE Reply Comments at 27-28;
Bekaert Supplemental Comments at 1; Breakthrough Energy Initial
Comments at 16; CARE Coalition Initial Comments at 2-3; CARE
Coalition Reply Comments at 5; Certain TDUs Reply Comments at 8-9;
City of New York Reply Comments at 4 (citing PIOs Initial Comments
at 84); Clean Energy Associations Initial Comments at 27-28; Clean
Energy Associations Reply Comments at 7; CTC Global Initial Comments
at 14-15; Industrial Customers Reply Comments at 11; Invenergy
Initial Comments at 16; Vermont State Entities Initial Comments at
9.
\2628\ Dynamic reactive power is produced from equipment that
can quickly change the Mvar level independent of the voltage level.
Thus, the equipment can increase its reactive power production level
when voltage drops and prevent a voltage collapse. Static VAR
compensators, synchronous condensers, and generators provide dynamic
reactive power. FERC, Staff Report, Principles for Efficient and
Reliable Reactive Power Supply and Consumption 7 (Feb. 4, 2005),
https://www.ferc.gov/sites/default/files/2020-04/20050310144430-02-04-05-reactive-power.pdf.
\2629\ Environmental Legislators Caucus Supplemental Comments at
2; Senator Schumer Supplemental Comments at 2.
\2630\ Environmental Legislators Caucus Supplemental Comments at
2.
\2631\ AEE Reply Comments at 27-28, 34 (citing 42 U.S.C.
16422(b)).
---------------------------------------------------------------------------
1230. Several commenters urge the Commission to require that
storage be considered.\2632\ CARE Coalition states that utilities can
use storage to defer investments as supply and demand patterns change,
allowing them to avoid all-in, 50-year investments in favor of shorter-
term flexibility.\2633\ CARE Coalition cites a number of ways that
storage can improve transmission,
[[Page 49473]]
including providing voltage support in a transmission-constrained zone,
ensuring reliability while repairs are executed, reducing peak loads,
increasing capacity on congested lines, directing power flow away from
lower capacity transmission lines, and controlling the timing of power
flows to remain under thresholds.\2634\
---------------------------------------------------------------------------
\2632\ Advanced Energy Buyers Initial Comments at 4; AEP Initial
Comments at 33-34; CAISO Initial Comments at 38; California
Commission Initial Comments at 38-40 (citing Jennifer Chen & Devin
Hartmann, Transmission Reform Strategy From A Customer Perspective:
Optimizing Net Benefits And Procedural Vehicles R Street Policy
Study 7 (May 2022), https://www.rstreet.org/wp-content/uploads/2022/05/RSTREET257.pdf); CARE Coalition Initial Comments at 2-3; Clean
Energy Associations Initial Comments at 30-31; Conservative Energy
Network Supplemental Comments at 1-2; Conservatives for Clean
Energy--Florida Supplemental Comments at 1-2; Conservatives for
Clean Energy--South Carolina Supplemental Comments at 1; DC and MD
Offices of People's Counsel Initial Comments at 36-37; Illinois
Commission Initial Comments at 12; Industrial Customers Reply
Comments at 11; Joint Consumer Advocates Initial Comments at 13;
Michigan Conservative Energy Forum Supplemental Comments at 1; NARUC
Initial Comments at 36; National Grid Initial Comments at 3-4; Ohio
Conservative Energy Forum Supplemental Comments at 1; OMS Initial
Comments at 9; Western Way Colorado Supplemental Comments at 2;
Western Way Nevada Supplemental Comments at 2; Western Way Utah
Supplemental Comments at 2; Wisconsin Conservative Energy Forum
Supplemental Comments at 1.
\2633\ CARE Coalition Initial Comments at 42-43.
\2634\ Id. at 42.
---------------------------------------------------------------------------
1231. AEP states that the Commission should require better
consideration of storage, noting that the technology has advanced
significantly in the past several years, yet is still not being
deployed as a transmission alternative. AEP cites two reasons for this:
(1) despite the multiple uses and benefits of storage, it is currently
categorized as only one of the following--transmission, generation, or
distribution, and (2) there is no traditional approach that assesses
the viability of storage proposals to solve reliability problems. AEP
states that, to solve these problems, the Commission should provide
more certainty around these questions, including how to schedule,
dispatch, and charge storage, as well as guidance on how to assess the
value of storage beyond reliability if, for example, the resource is
only needed during certain times of year.\2635\
---------------------------------------------------------------------------
\2635\ AEP Initial Comments at 33-34.
---------------------------------------------------------------------------
1232. Some commenters suggest that the Commission should require
consideration of advanced conductors in Long-Term Regional Transmission
Planning.\2636\ CTC Global asserts that advanced conductors should be
required to be considered because of their ease of installation onto
existing structures, cost savings, lower line sag, and power flow
increase.\2637\ CTC Global adds that even in the case of a total
rebuild, advanced conductors can generate more capacity, efficiency,
resilience, and reliability than rebuilds using standard
conductors.\2638\ VEIR notes that if the final order requires the
consideration of advanced conductors, the Commission should define
advanced conductors to include all advanced conductor technologies,
including superconductors.\2639\ Bekaert states that the definition of
advanced conductors should extend beyond carbon fiber core technologies
to also include steel core technologies, which it contends can raise
ampacity, reduce line losses, and withstand extreme weather conditions,
all while offering a cost-effective solution.\2640\
---------------------------------------------------------------------------
\2636\ ACEG Initial Comments at 31; ACORE Initial Comments at
16; Breakthrough Energy Initial Comments at 15-19; CTC Global
Initial Comments at 15-16; DC and MD Offices of People's Counsel
Initial Comments at 36-37; Indicated US Senators and Representatives
Initial Comments at 2; NASEO Initial Comments at 6; Prysmian Initial
Comments at 1; VEIR Initial Comments at 5-6.
\2637\ CTC Global Initial Comments at 14-15.
\2638\ Id. at 15.
\2639\ VEIR Reply Comments at 5.
\2640\ Bekaert Supplemental Comments at 1-2.
---------------------------------------------------------------------------
1233. Some commenters suggest that the Commission should require
consideration of transmission switching in Long-Term Regional
Transmission Planning.\2641\ For example, Illinois Commission states
that line switching is a tool to make better use of the extant
transmission system.\2642\ NASEO states that the use of alternative
transmission technologies, including transmission switching, is
increasing.\2643\ However, MISO argues that grid enhancing technologies
that introduce automatic topology changes are not appropriate for
consideration over transmission planning horizons of 20 years or more
because they would be considered remedial action schemes, which MISO
and its transmission owners have attempted to reduce as a matter of
Good Utility Practice.\2644\
---------------------------------------------------------------------------
\2641\ Illinois Commission Initial Comments at 12; NASEO Initial
Comments at 6; Potomac Economics Initial Comments at 5.
\2642\ Illinois Commission Initial Comments at 12 (citing Pablo
A. Ruiz, The Brattle Group, Transmission Topology Optimization (Aug.
21, 2017) https://www.brattle.com/wp-content/uploads/2017/10/7204_transmission_topology_optimization.pdf (Brattle Group Aug. 2017
Report)).
\2643\ NASEO Initial Comments at 6.
\2644\ MISO Initial Comments at 60.
---------------------------------------------------------------------------
1234. A number of commenters suggest that the Commission should
require consideration of topology optimization in Long-Term Regional
Transmission Planning.\2645\ Potomac Economics states that network
optimization can allow a transmission operator to circumvent a limiting
transmission facility and substantially mitigate the associated
congestion, averting transmission upgrades that could prove wasteful
and inefficient.\2646\ With respect to topology optimization, WATT
Coalition recommends that the information provided in the evaluation
process should include modeling assumptions, contingency analysis
results, asset age and condition, environmental and footprint
constraints, etc.\2647\ In contrast, SPP states that technologies that
optimize transmission system operation should be considered short-term
solutions and not a replacement for long-term transmission
capacity.\2648\
---------------------------------------------------------------------------
\2645\ ACORE Initial Comments at 16; CARE Coalition Initial
Comments at 2-3; ENGIE Initial Comments at 5-6; Illinois Commission
Initial Comments at 11-13 (citing Brattle Group Aug. 2017 Report);
Indicated US Senators and Representatives Initial Comments at 2;
Potomac Economics Initial Comments at 5; R Street Initial Comments
at 4; Tabors Caramanis Rudkevich Initial Comments at 5; WATT
Coalition Initial Comments at 6.
\2646\ Potomac Economics Initial Comments at 5.
\2647\ WATT Coalition Initial Comments at 6.
\2648\ SPP Initial Comments at 26.
---------------------------------------------------------------------------
1235. ITC argues that the Commission should encourage transmission
providers to modernize transmission planning criteria to better
consider dynamic reactive power devices such as static VAR
compensators, static synchronous compensators, and unified power flower
controllers. ITC asserts that such technologies provide faster response
times to changes in voltage and power factor, relative to capacitor
banks and mechanically switched compensation schemes.\2649\
---------------------------------------------------------------------------
\2649\ ITC Initial Comments at 28.
---------------------------------------------------------------------------
1236. Industrial Customers and Ohio Consumers suggest that the
Commission should require the consideration of distributed energy
resources in Long-Term Regional Transmission Planning.\2650\ Industrial
Customers contend that demand response and load-limiting devices should
be considered as a way of optimizing the current transmission system,
claiming that they are less costly than transmission expansions.\2651\
QCo states that the Commission should consider the use of the thermal
mass of major buildings as a low-cost method to store energy and
provide flexibility to the grid.\2652\
---------------------------------------------------------------------------
\2650\ Industrial Customers Initial Comments at 35; Ohio
Consumers Initial Comments at 34.
\2651\ Industrial Customers Reply Comments at 11.
\2652\ QCo Initial Comments at 1-3.
---------------------------------------------------------------------------
1237. ENGIE asserts that the Commission should require
consideration of dynamic transformer rating technology in Long-Term
Regional Transmission Planning.\2653\
---------------------------------------------------------------------------
\2653\ ENGIE Initial Comments at 5-6.
---------------------------------------------------------------------------
1238. Exelon is concerned that making a list of technologies to
consider in transmission planning will result in a ``time-consuming
check-the-box exercise,'' increasing costs and creating litigation
opportunities.\2654\
---------------------------------------------------------------------------
\2654\ Exelon Initial Comments at 23-24.
---------------------------------------------------------------------------
3. Commission Determination
1239. As stated above, we adopt the NOPR proposal, with
modification, to require transmission providers in each transmission
planning region to consider dynamic line ratings and advanced power
flow control devices in Long-Term Regional Transmission Planning and
existing Order No. 1000 regional transmission planning processes.
1240. In response to comments that dynamic line ratings are
operational in nature and are inappropriate in transmission planning,
we continue to believe that there is enough real-world operational
experience with dynamic
[[Page 49474]]
line ratings for transmission providers to be able to reasonably
project their likely operations and, as such, the benefits that
regional transmission facilities that incorporate dynamic line ratings
can provide over the transmission planning horizon.\2655\ Dynamic line
ratings have the ability to increase transmission line ratings, and
thus permit more economic energy transfers in most intervals,\2656\
which, in turn, could result in benefits (including, but not limited
to, production cost savings, reduced congestion due to fewer
transmission outages resulting from improved situational awareness, and
capacity cost benefits from reduced peak energy losses) that we require
transmission providers to evaluate in Long-Term Regional Transmission
Planning,\2657\ and in their existing regional transmission planning
processes.
---------------------------------------------------------------------------
\2655\ NOPR, 179 FERC ] 61,028 at P 276.
\2656\ Hannon Armstrong Reply Comments at 1-3.
\2657\ See supra Required Benefits section.
---------------------------------------------------------------------------
1241. We acknowledge commenter concerns about the potential effects
that the widespread use of dynamic line ratings or advanced power flow
control devices could have on reliability.\2658\ But while these
technologies cannot solve all reliability needs, as noted above, the
record here demonstrates that alternative transmission technologies are
in certain circumstances capable of enhancing reliability and providing
additional capacity.\2659\ We recognize that, either dynamic line
ratings or advanced power flow control devices, on their own, may be
unlikely to resolve certain reliability needs that are assessed based
on worst case conditions.\2660\ We also reiterate that nothing in this
final order changes transmission providers' obligations to conduct
transmission planning in a manner that ensures the long-term
reliability of the bulk electric system.\2661\ However, we find that
dynamic line ratings and advanced power flow control devices can also
confer reliability benefits. For example, in Order No. 881, the
Commission found that, by accounting for ambient air temperatures in
transmission line ratings, transmission providers can reliably increase
power transfer capability, which results in significant reliability
benefits.\2662\ Such reliability benefits also apply to dynamic line
ratings. Specifically, by accounting for actual wind conditions,
dynamic line ratings can also reliably increase transfer capability and
thereby provide reliability benefits. Similarly, as Ameren describes,
it may be more efficient to use advanced power flow control devices,
which can address stability limitations by allowing for greater use of
a transmission facility.\2663\
---------------------------------------------------------------------------
\2658\ See, e.g., CAISO Initial Comments at 41-42.
\2659\ See supra P 1206 of this section.
\2660\ For example, as ISO-NE explains, the dynamic line rating
may be the same as the rating already assumed in the planning study
as transmission providers may need to assume worst case weather
inputs to transmission line ratings. ISO-NE Initial Comments at 40-
41.
\2661\ See, for example, TPL-001-5.1, Transmission System
Planning Performance Requirements, which establishes transmission
system planning performance requirements within the planning horizon
to develop a bulk electric system that will operate reliably over a
broad spectrum of system conditions and following a wide range of
probable contingencies.
\2662\ Order No. 881, 177 FERC ] 61,179 at P 85.
\2663\ Ameren Initial Comments at 24.
---------------------------------------------------------------------------
1242. Additionally, Long-Term Regional Transmission Planning
evaluates Long-Term Regional Transmission Facilities based on multiple
benefits, and some existing regional transmission planning processes
focus on economic benefits, while others may consider multiple
benefits, including economic benefits. At a minimum, regional
transmission solutions incorporating dynamic line ratings are
appropriately considered as part of these processes. Given the
potentially substantial economic benefits of dynamic line ratings, we
find that it is important for transmission providers to consider
dynamic line ratings in Long-Term Regional Transmission Planning and
their existing regional transmission planning processes so as to ensure
that they identify more efficient or cost-effective regional
transmission facilities for selection.
1243. We also disagree with commenters that argue that advanced
power flow control devices are not appropriate in the transmission
planning context and are more appropriate for operational timeframes.
We find that the potential benefits of using advanced power flow
control devices are sufficient to merit their consideration in Long-
Term Regional Transmission Planning and existing regional transmission
planning processes. For example, as Ameren states, where a transmission
line is stability-limited from carrying more power, the use of advanced
power flow controls may address the limitation and allow greater use of
the line. Ameren also notes that advanced power flow controls may be
beneficial in a situation where a transmission line that needs to be
upgraded traverses sensitive environmental areas.\2664\ Moreover, as
Entergy and Exelon attest, advanced power flow control devices are
already considered in some transmission planning processes.\2665\ As
discussed above, we modify the NOPR proposal to add two additional
alternative transmission technologies to the list of enumerated
alternative transmission technologies required to be considered in
Long-Term Regional Transmission Planning and existing regional
transmission planning: advanced conductors and transmission switching.
We find that advanced conductors may greatly increase the capacity of
transmission facilities, and thus a new regional transmission facility
or upgrade to an existing transmission facility that incorporates
advanced conductors may be a more efficient or cost-effective
alternative than a proposed regional transmission facility that does
not incorporate such technologies. Consistent with Order No. 2023, we
note that advanced conductors can increase transmission line ratings,
providing more ``headroom'' on the system to address normal and
contingency conditions.\2666\ We clarify that the definition of
advanced conductors that we adopt in this final order constitutes a
range of permissible present and future technologies, and is defined
relative to conventional aluminum conductor steel reinforced
conductors. Therefore, advanced conductors include, but are not limited
to, superconducting cables, advanced composite conductors, advanced
steel cores, high temperature low-sag conductors, fiber optic
temperature sensing conductors, and advanced overhead conductors. We
find that such advanced conductors can result in lower line sag and
increased power flow and can be installed on existing transmission
structures, thereby offering ease of installation.\2667\
---------------------------------------------------------------------------
\2664\ Id.
\2665\ Entergy Initial Comments at 29; Exelon Initial Comments
at 23.
\2666\ Order No. 2023, 184 FERC ] 61,054 at P 1597.
\2667\ CTC Global Initial Comments at 14-15.
---------------------------------------------------------------------------
1244. We agree with commenters that suggest that transmission
switching should be added to the list of alternative transmission
technologies that must be considered in Long-Term Regional Transmission
Planning and existing regional transmission planning processes.\2668\
We clarify that, in this final order, we define transmission switching
as the opening or closing of transmission elements to safely route
power and direct flows away from congestion, based on pre-existing
forward analysis. Transmission switching can be used to route energy
around areas with high congestion and
[[Page 49475]]
improve the overall transfer capability of the system. In doing so,
transmission switching may provide additional economic or reliability
benefits, which could therefore render a transmission facility that
uses transmission switching a more efficient or cost-effective
alternative than a regional transmission facility that does not use
transmission switching. In response to MISO's concern that automatic
topology changes are not appropriate for consideration over
transmission planning horizons of 20 years or more because they would
be considered remedial action schemes,\2669\ we note that there are
appropriate applications for transmission switching that offer the
potential to be a more efficient or cost-effective alternative than a
proposed regional transmission facility that does not use one of the
enumerated alternative transmission technologies. For example, the
record indicates that network optimization can allow a transmission
operator to circumvent a limiting transmission facility and
substantially mitigate the associated congestion, averting transmission
upgrades that could prove wasteful and inefficient.\2670\
---------------------------------------------------------------------------
\2668\ Illinois Commission Initial Comments at 12; NASEO Initial
Comments at 6; Potomac Economics Initial Comments at 5.
\2669\ MISO Initial Comments at 60.
\2670\ Potomac Economics Initial Comments at 5.
---------------------------------------------------------------------------
1245. We decline to add storage that performs a transmission
function to the list of enumerated alternative transmission
technologies. The Commission has determined that the evaluation of
whether an electric storage resource performs a transmission function
requires a case-by-case analysis of either how a particular electric
storage resource would be operated or the requirements set forth in an
OATT governing selection of such electric storage resources.\2671\ In
the context of regional transmission planning, we continue to find that
the evaluation of whether an electric storage resource performs a
transmission function requires a case-by-case analysis, and therefore
decline to generically require the consideration of storage that
performs a transmission function in regional transmission planning
processes.
---------------------------------------------------------------------------
\2671\ Order No. 2023, 184 FERC ] 61,054 at P 1599.
---------------------------------------------------------------------------
1246. For the following reasons, we also decline to add topology
optimization to the list of enumerated alternative transmission
technologies because it is technically much more challenging to
implement. We clarify that topology optimization is not specific to
individual transmission facilities but instead is the act of
determining the optimal use of the transmission system, which may
involve many different transmission facilities. Additionally, the
optimal use of the transmission system may frequently change depending
on system conditions throughout the operating day. By contrast,
transmission switching focuses on opening or closing transmission
elements in pre-determined circumstances based on prior analyses well
in advance of the operational time horizon.\2672\ We do not find that
it is necessary to require the consideration of topology optimization
in regional transmission planning processes currently. While topology
optimization software has been used to identify potential system
reconfiguration actions that could result in a reduction in real-time
congestion, it has not yet been deployed due to computational
complexity. Specifically, given the size and complexity of the power
grid and the large number of potential optimization solutions, finding
optimization solutions in the necessary real-time timelines is
extremely difficult and doing so risks poor model performance and lower
quality solutions, which, in turn, could adversely impact reliability.
While simplifications might be possible, such simplifications risk
oversimplifying, which, in turn, could also jeopardize
reliability.\2673\
---------------------------------------------------------------------------
\2672\ See supra P 1243 of this section on transmission
switching. We recognize that there may be overlap between the
concepts of transmission switching and topology optimization. As
noted below, nothing in this final order precludes transmission
providers from considering topology optimization solutions as an
alternative transmission technology, if they so choose.
\2673\ US DOE, Advanced Transmission Technologies 11-15 (Dec.
2020), https://www.energy.gov/oe/articles/advanced-transmission-technologies-report.
---------------------------------------------------------------------------
1247. Finally, we decline to add further additional alternative
transmission technologies suggested by commenters.\2674\ We note that,
while commenters express support for the concept of considering
additional alternative transmission technologies, in general, we do not
believe that the record is sufficient to include these additional
technologies on the enumerated list of alternative transmission
technologies that transmission providers must consider in Long-Term
Regional Transmission Planning and existing regional transmission
planning processes at this time. However, we note that nothing in this
final order precludes transmission providers from considering other
alternative transmission technologies or other potential solutions in
their Long-Term Regional Transmission Planning and existing regional
transmission planning processes.
---------------------------------------------------------------------------
\2674\ See supra PP 1235-1237.
---------------------------------------------------------------------------
VI. Regional Transmission Cost Allocation
A. Cost Allocation for Long-Term Regional Transmission Facilities
1. Cost Allocation Methods for Long-Term Regional Transmission
Facilities
a. NOPR Proposal
1248. In the NOPR, the Commission proposed to require transmission
providers in each transmission planning region to revise their OATTs to
include: (1) a Long-Term Regional Transmission Cost Allocation Method
to allocate the costs of Long-Term Regional Transmission Facilities;
(2) a State Agreement Process by which one or more Relevant State
Entities \2675\ may voluntarily agree to a cost allocation method; or
(3) a combination thereof.\2676\
---------------------------------------------------------------------------
\2675\ The definition of Relevant State Entities is discussed
below. See infra Requirement that Transmission Providers Seek the
Agreement of Relevant State Entities Regarding the Cost Allocation
Method or Methods for Long-Term Regional Transmission Facilities
section.
\2676\ NOPR, 179 FERC ] 61,028 at P 302. The Commission
explained that, for example, a ``combination'' approach may entail:
(1) providing a Long-Term Regional Transmission Cost Allocation
Method for certain types of Long-Term Regional Transmission
Facilities and providing a State Agreement Process for others; or
(2) providing for cost allocation for a Long-Term Regional
Transmission Facility, portfolio, or type of such facilities
partially based on a Long-Term Regional Transmission Cost Allocation
Method and partially based on funding contributions in accordance
with a State Agreement Process. Id. P 302 n.510.
---------------------------------------------------------------------------
1249. The Commission proposed to define a Long-Term Regional
Transmission Cost Allocation Method as an ex ante regional cost
allocation method that would be included in each transmission
provider's OATT as part of Long-Term Regional Transmission Planning.
The developer of a Long-Term Regional Transmission Facility would be
entitled to use the Long-Term Regional Transmission Cost Allocation
Method if it is the applicable method.\2677\ The Commission proposed to
define a State Agreement Process as an ex post cost allocation process
that would be included in each transmission provider's OATT as part of
Long-Term Regional Transmission Planning, which may apply to an
individual Long-Term Regional Transmission Facility or a portfolio of
such Facilities grouped together for purposes of cost allocation. After
a Long-Term Regional Transmission Facility is selected, the State
Agreement Process would be followed to establish a cost allocation
method for that facility (if agreement
[[Page 49476]]
can be reached). If the Commission approves the cost allocation method
that results from the State Agreement Process, the developer of the
Long-Term Regional Transmission Facility would be entitled to use that
cost allocation method if it is the applicable method.\2678\
---------------------------------------------------------------------------
\2677\ Id. P 302 n.508.
\2678\ Id. P 302 n.509.
---------------------------------------------------------------------------
1250. The Commission also proposed to apply the cost allocation
reforms only to new Long-Term Regional Transmission Facilities.
Therefore, these proposed reforms would neither provide grounds for re-
litigation of cost allocation decisions for transmission facilities
that are selected prior to the effective date of any final order in
this proceeding, nor would they apply to the cost allocation methods
associated with regional transmission facilities that address shorter-
term transmission needs driven by reliability and/or economic
considerations.\2679\
---------------------------------------------------------------------------
\2679\ Id. P 314.
---------------------------------------------------------------------------
1251. In addition, the Commission stated that, to the extent
transmission providers believe that their existing cost allocation
approaches comply with the requirements adopted in any final order in
this proceeding, including those related to the agreement of Relevant
State Entities, they could make such demonstration in their compliance
filings in response to any final order.\2680\
---------------------------------------------------------------------------
\2680\ Id.
---------------------------------------------------------------------------
b. Comments
i. Interest in the Proposed Cost Allocation Reforms
1252. Some commenters offer general support for the cost allocation
reforms proposed in the NOPR.\2681\
---------------------------------------------------------------------------
\2681\ E.g., Breakthrough Energy Initial Comments at 6; Business
Council for Sustainable Energy Initial Comments at 2; California
Democratic Representatives Supplemental Comments at 2; Joint
Consumer Advocates Initial Comments at 13; OMS Initial Comments at
9; Pine Gate Initial Comments at 45; WE ACT Initial Comments at 5.
---------------------------------------------------------------------------
1253. Several commenters indicate support for the proposal to
require transmission providers to revise their OATTs to include: (1) a
Long-Term Regional Transmission Cost Allocation Method to allocate the
costs of Long-Term Regional Transmission Facilities; (2) a State
Agreement Process by which one or more Relevant State Entities may
voluntarily agree to a cost allocation method; or (3) a combination
thereof.\2682\ Clean Energy Buyers state that this proposal will
provide certainty in the cost allocation process, lessening disputes
that may delay transmission development.\2683\ ITC suggests that the
Commission look to OMS' role in State Agreement Processes as a guide
for how other transmission planning regions can foster state
participation in Long-Term Regional Transmission Planning.\2684\ AEP
asserts that clear rules set in advance provide the regulatory
certainty necessary to support large, long-term transmission
investments and ensure customers and developers know how the associated
costs will be allocated.\2685\
---------------------------------------------------------------------------
\2682\ Certain TDUs Initial Comments at 2, 7; City of New
Orleans Council Initial Comments at 9-10; Entergy Initial Comments
at 29-30; Eversource Initial Comments at 29-30; ISO-NE Initial
Comments at 37; ITC Initial Comments at 28; Kentucky Commission
Chair Chandler Initial Comments at 3 (citing NOPR, 179 FERC ] 61,028
at PP 302-303); Michigan Commission Initial Comments at 8; NARUC
Initial Comments at 51; NESCOE Initial Comments at 10; New York
Commission and NYSERDA Initial Comments at 12-13; New York TOs
Initial Comments at 18; North Carolina Commission and Staff Initial
Comments at 15-16; NYISO Initial Comments at 48-49; OMS Initial
Comments at 10; Pacific Northwest State Agencies Initial Comments at
27; Pattern Energy Initial Comments at 18; PIOs Initial Comments at
64; PJM States Initial Comments at 9-10; Resale Iowa Initial
Comments at 2, 12.
\2683\ Clean Energy Buyers Initial Comments at 26-27.
\2684\ ITC Reply Comments at 28-29.
\2685\ AEP Initial Comments at 35.
---------------------------------------------------------------------------
1254. New Jersey Commission states that a hybrid method that
allocates costs partially ex ante, based on reliability and economic
benefits, and partially ex post, through a State Agreement Process/
negotiated participant funding approach, could have value, arguing that
negotiated cost allocations could reduce litigation and make it easier
to construct beneficial transmission facilities.\2686\ SEIA supports a
combination of a Long-Term Regional Transmission Cost Allocation Method
and a State Agreement Process, asserting that states should be allowed
to assume the costs of new transmission facilities to serve their
needs.\2687\
---------------------------------------------------------------------------
\2686\ New Jersey Commission Initial Comments at 17, 25.
\2687\ SEIA Initial Comments at 24.
---------------------------------------------------------------------------
ii. Requested Clarifications and Concerns Related to the Proposed Cost
Allocation Reforms
1255. Some commenters raise concerns and request clarifications on
the proposed reforms. For example, BP contends that, in the case of a
multi-value project, it is unclear whether only a part of the cost of a
transmission project associated with meeting changes in the resource
mix and demand will be allocated under a Long-Term Regional
Transmission Cost Allocation Method, as opposed to all of the
costs.\2688\ NARUC requests that the Commission provide a mechanism for
future review of cost allocation methods for Long-Term Regional
Transmission Facilities.\2689\
---------------------------------------------------------------------------
\2688\ BP Initial Comments at 12.
\2689\ NARUC Initial Comments at 49-50.
---------------------------------------------------------------------------
1256. Other commenters urge flexibility with respect to cost
allocation methods and state involvement,\2690\ citing regional
differences,\2691\ to improve the likelihood of achieving consensus
between affected states.\2692\ OMS stresses the need for flexibility
with respect to cost allocation methods to realize the NOPR's overall
objectives of cost-effective regional transmission expansion.\2693\
Louisiana Commission, however, asserts that, whichever cost allocation
method is adopted, it should not allow a majority to impose costs upon
non-consenting states.\2694\
---------------------------------------------------------------------------
\2690\ See, e.g., Entergy Initial Comments at 29-30; Eversource
Initial Comments at 29-30; Idaho Power Initial Comments at 10;
NESCOE Reply Comments at 5; Pacific Northwest Utilities Initial
Comments at 5-6, 11, 13.
\2691\ See, e.g., Dominion Initial Comments at 45; Ohio
Commission Federal Advocate Initial Comments at 11.
\2692\ New York TOs Initial Comments at 18; see also Northwest
and Intermountain Initial Comments at 18.
\2693\ OMS Initial Comments at 10.
\2694\ Louisiana Commission Initial Comments at 33-34.
---------------------------------------------------------------------------
1257. Shell states that the Commission should require coastal
transmission providers to explain how their Long-Term Regional
Transmission Planning processes facilitate transmission planning and
cost allocation for offshore wind.\2695\ Shell further asserts that the
Commission should require all transmission providers to account for the
risk of free-ridership in their OATTs, arguing that regardless of the
cost allocation method applied, the Commission should ensure that
first-movers are protected from free-ridership.\2696\
---------------------------------------------------------------------------
\2695\ Shell Initial Comments at 17.
\2696\ Id. at 25, 28.
---------------------------------------------------------------------------
1258. Some commenters express concerns about the proposed State
Agreement Process.\2697\ Dominion states that a practical challenge in
implementing the proposed reforms will be whether having an ex ante
cost allocation method combined with alternative proposals or some
combination thereof creates an additional opportunity to debate and
challenge a transmission project, resulting in delays and increased
costs.\2698\
---------------------------------------------------------------------------
\2697\ We also address comments regarding the State Agreement
Process in more detail below. See infra Proposals Relating to the
Design and Operation of State Agreement Processes section.
\2698\ Dominion Initial Comments at 52.
---------------------------------------------------------------------------
[[Page 49477]]
iii. Concerns With the Proposed Cost Allocation Reforms
1259. Some commenters generally oppose the proposed reforms. For
example, Southern states that the proposal to establish a specific cost
allocation process before Long-Term Regional Transmission Planning has
identified actual transmission projects is too abstract to work in
practice and will most likely fail to attract requisite state
support.\2699\ Southern further asserts that the NOPR's proposed cost
allocation processes do not satisfy the second prong of the
Commission's FPA section 206 burden of proof to establish a just and
reasonable replacement rate.\2700\ Pacific Northwest State Agencies
oppose the option in the NOPR proposal that allows transmission
providers to propose a Long-Term Regional Transmission Cost Allocation
Method without involving states in its development.\2701\
---------------------------------------------------------------------------
\2699\ Southern Initial Comments at 6-7.
\2700\ Id. at 7 n.7.
\2701\ Pacific Northwest State Agencies Initial Comments at 24-
25.
---------------------------------------------------------------------------
iv. Comments on Specific Aspects of the Proposed Cost Allocation
Reforms
(a) Use of Existing Cost Allocation Methods for Long-Term Regional
Transmission Facilities
1260. Some commenters assert that they should be able to use
existing cost allocation methods for Long-Term Regional Transmission
Planning, with some RTOs/ISOs \2702\ and RTO/ISO stakeholders \2703\
supporting these arguments. Other commenters support the Commission
permitting transmission providers to keep their existing processes that
involve states in cost allocation decisions.\2704\ PPL supports using
the existing regional cost allocation structures as a default. PPL
asserts that any change to the existing cost allocation method will
require an FPA section 205 filing, and interested parties, including
the states, may intervene and provide testimony and evidence regarding
the appropriateness of any benefit used.\2705\
---------------------------------------------------------------------------
\2702\ See, e.g., MISO Initial Comments at 61, 68; PJM Initial
Comments at 116; SPP Initial Comments at 28-29.
\2703\ See, e.g., Ameren Initial Comments at 25-27; Avangrid
Initial Comments at 28; Dominion Initial Comments at 3, 45; Ohio
Commission Federal Advocate Initial Comments at 2, 13; Omaha Public
Power Initial Comments at 4; Pennsylvania Commission Initial
Comments at 13-14; PJM States Initial Comments at 11-12; Virginia
Commission Staff Initial Comments at 6.
\2704\ Avangrid Initial Comments at 28; Dominion Reply Comments
at 11; Omaha Public Power Initial Comments at 4.
\2705\ PPL Initial Comments at 28-29.
---------------------------------------------------------------------------
1261. APS states that it agrees with the Commission that
collaboration with Relevant State Entities is a positive approach to
transmission planning, but it believes that the current cost allocation
process is appropriate and should not be altered. APS, noting that the
Commission has determined that additional complexities and
contentiousness may result from expanding the transmission planning
horizon to 20 years, argues that underlying cost causation principles
will apply, and, therefore, existing cost allocation processes remain
appropriate.\2706\
---------------------------------------------------------------------------
\2706\ APS Initial Comments at 11-12.
---------------------------------------------------------------------------
1262. Similarly, PJM contends that the need for new or expanded
transmission facilities identified through Long-Term Regional
Transmission Planning would fall under the reliability or market
efficiency studies that it performs today, and, therefore, the
Commission should permit it to use its existing ex ante cost allocation
methods as the default cost allocation method for transmission
facilities selected through Long-Term Regional Transmission Planning
(absent agreement by all affected states on an alternate method). PJM
states that using its existing ex ante approaches will provide
consistency and certainty in assigning cost responsibility.\2707\ PJM
States disagree, arguing that the Commission should not presume that
existing cost allocation methods are just and reasonable without a full
examination and input from retail regulators. According to PJM States,
the factors that make PJM's existing cost allocation methods just and
reasonable in the short term may not exist in the long term.\2708\
---------------------------------------------------------------------------
\2707\ PJM Initial Comments at 115.
\2708\ PJM States Reply Comments at 5.
---------------------------------------------------------------------------
1263. PJM further requests that the Commission clarify that if a
transmission provider proposes to use an existing cost allocation
method for regional transmission facilities selected through Long-Term
Regional Transmission Planning, such a proposal may not be a cause for
relitigating the use of that method for transmission projects selected
prior to the issuance of the final order.\2709\ MISO states that if
existing cost allocation methods previously were determined to comply
with the Order No. 1000 regional cost allocation principles, the
Commission should not require another demonstration and should clarify
that its proposals do not require transmission providers to modify or
set aside any existing regional cost allocation method.\2710\
Relatedly, ITC argues that the Commission should allow for streamlined
compliance plans from transmission providers that already have
substantial long-range planning processes in place.\2711\
---------------------------------------------------------------------------
\2709\ PJM Initial Comments at 115 (citing NOPR, 179 FERC ]
61,028 at P 314).
\2710\ MISO Initial Comments at 61.
\2711\ ITC Initial Comments at 29-30.
---------------------------------------------------------------------------
1264. PIOs proffer that having two distinct cost allocation methods
can be unjust, unreasonable, and unduly discriminatory even if those
methods are reasonable on their own, and that multiple cost allocation
methods may create uncertainty, which the Commission has recognized can
be a barrier to transmission development.\2712\ PIOs therefore request
that the Commission: (1) require transmission providers to identify and
justify differences between Long-Term Regional Transmission Planning
and near-term cost allocation; (2) find that compliance filings that
create opportunities for ``cost allocation arbitrage'' may not be
approved; and (3) require transmission providers to demonstrate that
their current Order No. 1000 cost allocation methods are just,
reasonable, and not unduly discriminatory or preferential.\2713\
---------------------------------------------------------------------------
\2712\ PIOs Initial Comments at 71 (citing NOPR, 179 FERC ]
61,028 at P 297).
\2713\ Id. at 72.
---------------------------------------------------------------------------
1265. Dominion requests that the Commission clarify that any cost
allocation method directed through this rulemaking proceeding is: (1)
limited to Long-Term Regional Transmission Facilities; and (2) limited
to Order No. 1000 transmission planning regions.\2714\
---------------------------------------------------------------------------
\2714\ Dominion Initial Comments at 49-50.
---------------------------------------------------------------------------
1266. Clean Energy Associations request that the Commission adopt
pro forma cost allocation provisions that would allow for regional
variation where cost allocation practices are consistent with or
superior to the requirements adopted in any final order. For example,
Clean Energy Associations state, if vertically integrated public
utilities subject to state-jurisdictional integrated resource planning
can demonstrate that the state planning process appropriately
identifies needs and assigns costs based on future planned generation
consistent with state policies, certain requirements may not be
applicable.\2715\
---------------------------------------------------------------------------
\2715\ Clean Energy Associations Initial Comments at 36.
---------------------------------------------------------------------------
(b) Comments on Whether Filing an Ex Ante Cost Allocation Method Should
Be Required
1267. Some commenters support a requirement that transmission
providers submit an ex ante cost allocation
[[Page 49478]]
method or methods that would apply to all Long-Term Regional
Transmission Facilities either in place of, or as a backstop for, a
State Agreement Process.\2716\ For example, Grid United suggests that
the Commission mandate that transmission providers develop ex ante cost
allocation methods for selected Long-Term Regional Transmission
Facilities to remove development and financial uncertainty, provide
transparency in how benefits are calculated, and ensure that cost
allocation is roughly commensurate with the distribution of
benefits.\2717\
---------------------------------------------------------------------------
\2716\ See, e.g., Grid United Initial Comments at 6; Illinois
Commission Initial Comments at 16-17; Minnesota State Entities
Initial Comments at 6; MISO TOs Initial Comments at 45-48; PIOs
Initial Comments at 70; RMI Supplemental Comments at 2-3.
\2717\ Grid United Initial Comments at 6.
---------------------------------------------------------------------------
1268. MISO TOs state that ex ante cost allocation provides upfront
certainty, explaining that MISO's ex ante processes work well and align
with past Commission findings regarding the difficulty of supporting
new construction without knowing who will pay for it and the importance
of working out cost allocation up front, rather than ``relitigating
it'' each time a transmission project is proposed.\2718\ MISO TOs do
not oppose states voluntarily agreeing to assume cost responsibility
for regional transmission projects, which Commission policy already
permits via participant funding, but argue that states that want to
voluntarily assume cost responsibility for part or all of a
transmission project should do so during the transmission planning
process (i.e., when considering potential transmission projects) rather
than after projects have been selected, so that those approving such
projects can know how costs will be allocated.\2719\
---------------------------------------------------------------------------
\2718\ MISO TOs Initial Comments at 45-48 (citing Order No. 890,
118 FERC ] 61,119 at PP 557, 561; Order No. 1000, 136 FERC ] 61,051
at P 499).
\2719\ Id. at 48-49.
---------------------------------------------------------------------------
1269. New Jersey Commission states that the Commission should not
allow transmission providers to use cost allocation methods that rely
solely on participant funding, such as PJM's State Agreement Approach.
New Jersey Commission explains that such mechanisms are an unjust and
unreasonable method for allocating the costs of holistically planned
multi-driver projects and portfolios because if transmission projects
can only be built if one or more states agree to assume 100% of the
resulting costs, more expensive projects or portfolios that maximize
net benefits to the transmission planning region will go unbuilt,
ultimately driving up system-wide costs.\2720\
---------------------------------------------------------------------------
\2720\ New Jersey Commission Initial Comments at 24.
---------------------------------------------------------------------------
1270. Illinois Commission states that ex ante approaches should be
the primary cost allocation method and include state input and
approval, and that the State Agreement Process should only be used for
exceptions in which public policy goals fall outside of the scope of
Long-Term Regional Transmission Planning. Illinois Commission expresses
concerns because it understands the NOPR to state that transmission
projects without an ex ante cost allocation method would not be funded
unless states decide to pay for them through a State Agreement Process,
which could create more expensive and siloed transmission planning that
does not meet future transmission needs.\2721\
---------------------------------------------------------------------------
\2721\ Illinois Commission Initial Comments at 16-17.
---------------------------------------------------------------------------
1271. Many commenters express concerns about the optionality of the
proposal and argue that it is necessary to have a default ex ante cost
allocation method where agreement cannot be reached among states and to
preserve FPA section 205 filing rights.\2722\ Numerous entities support
an ex ante cost allocation method for Long-Term Regional Transmission
Facilities to be used in the event a State Agreement Process does not
result in an agreed-upon cost allocation method.\2723\
---------------------------------------------------------------------------
\2722\ ACORE Supplemental Comments at 1; APPA Initial Comments
at 6, 44-45; Environmental Groups Supplemental Comments at 2-3;
Evergreen Action Initial Comments at 6; Georgia Commission Initial
Comments at 9; ITC Initial Comments at 30-31; Massachusetts Attorney
General Initial Comments at 18-21; TAPS Initial Comments at 4-5, 24-
26; WIRES Initial Comments at 12-13.
\2723\ Evergreen Action Initial Comments at 6; Exelon Initial
Comments at 24, 26; Georgia Commission Initial Comments at 8-9; ITC
Initial Comments at 30-31; Massachusetts Attorney General Initial
Comments at 18-20, 22-23; MISO Initial Comments at 67-68; Northwest
and Intermountain Initial Comments at 18; Pine Gate Initial Comments
at 7; PIOs Initial Comments at 67; TAPS Initial Comments at 4-5, 24-
25; WIRES Initial Comments at 12-13.
---------------------------------------------------------------------------
1272. For example, Minnesota State Entities contend that an ex ante
process that allocates costs at least roughly proportional to benefits
should be required as the default cost allocation method unless states
can agree on an ex post cost allocation method within 90 days.
Minnesota State Entities also recommend that the Commission require
RTOs/ISOs to use postage stamp cost allocation as the default cost
allocation method for Long-Term Regional Transmission Facilities (or
portfolios of such Facilities) unless the RTO/ISO can develop an
alternate cost allocation method that all affected states agree on
within 90 days following RTO/ISO approval.\2724\
---------------------------------------------------------------------------
\2724\ Minnesota State Entities Initial Comments at 6-7.
---------------------------------------------------------------------------
1273. PIOs argue that without a default cost allocation method,
transmission may be held up in stakeholder processes or by project-by-
project litigation to assign costs.\2725\ PIOs further caution that the
Long-Term Regional Transmission Planning framework is at risk without
an ex ante cost allocation method because successful negotiation of a
State Agreement Process for each transmission project would be unwieldy
and create opportunities for free-ridership and obstructionism.\2726\
Similarly, AEE argues that relying on a State Agreement Process would
not be just and reasonable and likely would stall the transmission
planning and cost allocation process.\2727\ Acadia Center and CLF
assert that where the Commission anticipates that states will fail to
agree, it should establish the Long-Term Regional Transmission Cost
Allocation Method because, otherwise, ineffective regional transmission
planning processes will remain in place.\2728\
---------------------------------------------------------------------------
\2725\ PIOs Initial Comments at 70.
\2726\ Id. at 67.
\2727\ AEE Reply Comments at 15, 34.
\2728\ Acadia Center and CLF Initial Comments at 31 (citing
NOPR, 179 FERC ] 61,028 at P 310).
---------------------------------------------------------------------------
1274. SEIA argues that having a default cost allocation method will
ensure that transmission that promotes public policy will be built even
in the face of disagreement.\2729\ R Street states that the Commission
should require schedule discipline and a default cost allocation
provision for circumstances where states cannot agree, which can
include an accelerated Commission-led arbitration process or Commission
application of preestablished criteria.\2730\
---------------------------------------------------------------------------
\2729\ SEIA Initial Comments at 25 (citing 16 U.S.C. 824p(b)).
\2730\ R Street Initial Comments at 4, 12.
---------------------------------------------------------------------------
1275. Georgia Commission asserts that, if Relevant State Entities
cannot reach agreement, or if a Relevant State Entity forgoes its
opportunity to participate in the State Agreement Process, there should
be a default Long-Term Regional Transmission Cost Allocation Method
when clear benefits have been identified for a specific transmission
facility or portfolio of facilities.\2731\
---------------------------------------------------------------------------
\2731\ Georgia Commission Initial Comments at 9.
---------------------------------------------------------------------------
1276. NYISO does not object to the final order directing each
transmission provider to adopt an ex ante cost allocation method for
transmission projects selected through Long-Term
[[Page 49479]]
Regional Transmission Planning for use when an alternative method is
not identified in a process that involves the state. NYISO references,
as an example, the process cited in the NOPR whereby the New York
Commission plays a role in determining the cost allocation method for
public policy transmission projects.\2732\
---------------------------------------------------------------------------
\2732\ NYISO Initial Comments at 49 (citing NOPR, 179 FERC ]
61,028 at P 300 & n.500).
---------------------------------------------------------------------------
1277. Exelon supports requiring a default ex ante cost allocation
method that would act as a backstop cost allocation method should the
states in a transmission planning region fail to negotiate an
alternative cost allocation method for a transmission project or
portfolio of projects. Exelon states that failure to reach an agreement
on cost allocation should not act as a barrier to needed transmission,
and whatever mechanism is developed for receiving state input should
not allow one or more states to thwart the goals of other states and
stakeholders.\2733\
---------------------------------------------------------------------------
\2733\ Exelon Initial Comments at 26.
---------------------------------------------------------------------------
1278. PPL asserts that the proposal to require a Long-Term Regional
Transmission Cost Allocation Method may not solve the problem of states
refusing to site transmission projects where they do not agree on cost
allocation, but in some transmission planning regions, it may
nevertheless be helpful to have a default cost allocation method.\2734\
---------------------------------------------------------------------------
\2734\ PPL Initial Comments at 26.
---------------------------------------------------------------------------
1279. Some commenters oppose requiring a default ex ante cost
allocation method, whether on its own or in combination with a State
Agreement Process.\2735\ For example, California Commission asserts
that the Commission should not mandate an ex ante cost allocation
method if states cannot agree to a cost allocation method by a certain
date.\2736\ NRG states that the Commission should focus on voluntary
cost allocation and should not use involuntary cost allocation as a
substitute to participant-funded interconnection and transmission
expansion.\2737\ NRG states that it would be unrealistic to expect
productive negotiation among states if recourse to an ex ante cost
allocation method is an option for any objecting state.\2738\
---------------------------------------------------------------------------
\2735\ See, e.g., Louisiana Commission Initial Comments at 30,
34; NRG Initial Comments at 6; SERTP Sponsors Initial Comments at
28; US Chamber of Commerce Initial Comments at 9-10.
\2736\ California Commission Initial Comments at 57.
\2737\ NRG Initial Comments at 6, 16.
\2738\ Id. at 20.
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1280. SERTP Sponsors express concern that requiring state
agreements or an ex ante cost allocation method before transmission
projects are identified is unworkable because regulators in the
Southeast will likely insist that the projects first be identified and
their benefits and costs determined before the projects are selected
and cost allocation commitments are made.\2739\ SERTP Sponsors state
that expecting states to accept a cost allocation for transmission
projects that they do not support, based on a process they have not
chosen, and to which they do not assign value or benefit for retail
ratepayers, will not succeed.\2740\ Alabama Commission agrees with
SERTP Sponsors, stating that the State Agreement Process is a more
appropriate and equitable mechanism for allocating the costs of Long-
Term Regional Transmission Facilities and should be the sole cost
allocation method.\2741\ Similarly, US Chamber of Commerce contends
that state utility regulators would risk not adequately protecting
their constituents if they were to agree to an ex ante cost allocation
method that assessed a fixed level of costs on ratepayers regardless of
the design and/or benefits of a proposed regional transmission
facility.\2742\
---------------------------------------------------------------------------
\2739\ SERTP Sponsors Initial Comments at 3, 28.
\2740\ Id. at 20.
\2741\ Alabama Commission Initial Comments at 9.
\2742\ US Chamber of Commerce Initial Comments at 9-10.
---------------------------------------------------------------------------
1281. EPSA argues that because long-term transmission planning
horizons introduce uncertainty risk that customers must bear, cost
allocation should be voluntary to the maximum degree possible.\2743\
Louisiana Commission opposes proceeding with any transmission projects
selected in Long-Term Regional Transmission Planning without the
voluntary cost allocation agreement of all impacted states.\2744\
Mississippi Commission asserts that the Commission should not require a
default ex ante cost allocation method because doing so would bias and
undermine cost allocation negotiations between states.\2745\
Mississippi Commission further argues that the Commission should
clarify that state agreement on cost allocation for each transmission
facility, or portfolio of facilities, is what is required, not simply
involvement in the stakeholder process.\2746\
---------------------------------------------------------------------------
\2743\ EPSA Initial Comments at 7.
\2744\ Louisiana Commission Initial Comments at 17-18, 30.
\2745\ Mississippi Commission Initial Comments at 27;
Mississippi Commission Reply Comments at 3.
\2746\ Mississippi Commission Initial Comments at 28.
---------------------------------------------------------------------------
1282. Xcel opposes a mandated ex ante cost allocation method,
stating that the industry engaged in more effective long-term
transmission planning before Order No. 1000, and that the Commission
should give transmission planning regions flexibility to identify
potential solutions before identifying the cost allocation for those
solutions. In addition, Xcel supports allowing transmission planning
regions flexibility to tailor the benefits evaluated to the purpose of
the study and project, citing MISO's experience with Long-Range
Transmission Planning.\2747\ Similarly, Southern states that the
Commission should not require an ex ante cost allocation process, but
if it does, it should adopt the NOPR proposal to allow transmission
providers to determine the appropriate benefits.\2748\
---------------------------------------------------------------------------
\2747\ Xcel Initial Comments at 11-12.
\2748\ Southern Initial Comments at 27.
---------------------------------------------------------------------------
1283. Duke asserts that the Commission has provided no support
other than pointing to Order No. 1000 as to why Long-Term Regional
Transmission Facilities should have a default ex ante cost allocation
method.\2749\ Duke explains that if states disagree with the need,
benefits, and cost allocation determined in Commission-jurisdictional
transmission planning processes, then states are likely to exercise
their jurisdiction over siting and retail cost allocation to thwart
development of a Long-Term Regional Transmission Facility.\2750\ Duke
asks that the Commission clarify that transmission providers may rely
solely on a State Agreement Process and are not required to adopt an ex
ante default Long-Term Regional Transmission Cost Allocation
Method.\2751\ Duke argues that an ex post cost allocation method from a
fully litigated Commission proceeding is a more durable solution than a
default ex ante cost allocation, which may be similarly litigated but
also delay siting approvals.\2752\
---------------------------------------------------------------------------
\2749\ Duke Initial Comments at 37.
\2750\ Id. at 3, 35-36.
\2751\ Id. at 33.
\2752\ Id. at 3, 36-37.
---------------------------------------------------------------------------
1284. NESCOE requests that the Commission confirm that if a
transmission provider files a State Agreement Process, the transmission
provider does not need to file an ex ante cost allocation method, and
the time period for a state-negotiated alternate cost allocation method
would not apply.\2753\
---------------------------------------------------------------------------
\2753\ NESCOE Initial Comments at 66-67.
---------------------------------------------------------------------------
v. Other Cost Allocation Method Proposals
1285. ACEG recommends having a threshold level of voltage or
capacity above which a transmission facility would receive regional
cost allocation
[[Page 49480]]
because the benefits of transmission depend directly on having a robust
grid capable not only of receiving diverse generation but also of
withstanding extreme weather.\2754\
---------------------------------------------------------------------------
\2754\ ACEG Initial Comments at 63.
---------------------------------------------------------------------------
1286. Shell argues that the Commission should be open to non-
traditional cost allocation methods, such as the sharing of benefits
when a defined benefit/cost ratio threshold is exceeded, to achieve the
goal of minimizing first-mover risk. Shell contends that sharing the
cost of interconnection-related network upgrades between first movers
and subsequent customers is common in the industry and points to ISO-
NE, PJM, and MISO as examples of RTOs/ISOs that have revised their
OATTs to attempt to address this concern.\2755\
---------------------------------------------------------------------------
\2755\ Shell Initial Comments at 25-28.
---------------------------------------------------------------------------
1287. ELCON notes that regardless of the funding mechanism or
approved cost allocation method, benefits and risks may change over
time as Long-Term Scenarios are updated and needs and solutions are
reassessed. Therefore, ELCON states that the three-year reexamination
of Long-Term Scenarios should also review cost allocation to ensure
that cost causers and willing beneficiaries continue to be assessed the
costs of a transmission project over its lifetime.\2756\
---------------------------------------------------------------------------
\2756\ ELCON Initial Comments at 19.
---------------------------------------------------------------------------
1288. Xcel proposes that transmission planning regions rely on
scenario-based studies that reflect load-serving entity inputs
regarding projected generation expansion, expected types and locations
of generators, and expected load. Xcel states that the load-serving
entities could then adjust their resource plans in light of the
resulting costs and benefits. Xcel asserts that this flexibility would
result in consensus-based cost allocation tied to the transmission that
load-serving entities actually need and would reduce the reluctance to
participate in planning as the outcomes could be adjusted to
accommodate adjustments in load-serving entity needs and
expectations.\2757\ Xcel also argues that the Commission should make
clear that it is sometimes appropriate to allocate costs to generators,
and that transmission access rights allocation should follow cost
allocation.\2758\
---------------------------------------------------------------------------
\2757\ Xcel Initial Comments at 18.
\2758\ Id. at 12-13.
---------------------------------------------------------------------------
1289. Certain TDUs argue that the Commission should require any ex
ante cost allocation method to follow a ``beneficiary pays'' approach,
as opposed to the default, postage stamp load ratio share model.\2759\
Certain TDUs claim that the advantages of adopting a beneficiary-pays
cost allocation approach are well documented, as the circumstances
appropriate for a postage stamp allocation are not necessarily present
when allocating costs for Long-Term Regional Transmission
Facilities.\2760\ R Street similarly asserts that the final order
should adhere to the beneficiary-pays principle to allocate the costs
of both transmission and interconnection-related network
upgrades.\2761\
---------------------------------------------------------------------------
\2759\ Certain TDUs Initial Comments at 2, 7.
\2760\ Id. at 8-9.
\2761\ R Street Initial Comments at 4, 12.
---------------------------------------------------------------------------
1290. Cypress Creek contends that where ``cost allocation would
hamper the use of contingent needs as a driver for multi-value
projects,'' there should be a hybrid approach. Specifically, Cypress
Creek suggests allocating costs up to the lesser of: (1) the cost of
necessary reliability improvements and (2) the benefit-cost threshold
ratio of the multi-value project to the party that needs the
improvements. Cypress Creek suggests that the remaining costs be
allocated according to multi-value project rules.\2762\
---------------------------------------------------------------------------
\2762\ Cypress Creek Reply Comments at 12.
---------------------------------------------------------------------------
c. Commission Determination
1291. We adopt the NOPR proposal, with modification, to require
transmission providers in each transmission planning region to file one
or more ex ante cost allocation methods that apply to selected Long-
Term Regional Transmission Facilities. Specifically, we modify the NOPR
proposal to require, instead of just permit, transmission providers in
each transmission planning region to revise their OATTs to include one
or more Long-Term Regional Transmission Cost Allocation Methods for
Long-Term Regional Transmission Facilities that are selected. We adopt
the NOPR's proposed definition, with modification, of Long-Term
Regional Transmission Cost Allocation Method as an ex ante regional
cost allocation method for one or more Long-Term Regional Transmission
Facilities (or a portfolio of such Facilities) that are selected in the
regional transmission plan for purposes of cost allocation. In addition
to this required Long-Term Regional Transmission Cost Allocation
Method, we also permit transmission providers to revise their OATTs to
include a State Agreement Process, if Relevant State Entities indicate
that they have agreed to such a process. Any State Agreement Process
that transmission providers voluntarily propose to include in their
OATTs would not comply with the requirements of this final order unless
Relevant State Entities indicate to the transmission providers that
Relevant State Entities have agreed to that process during the
Engagement Period (which we discuss further below).\2763\
---------------------------------------------------------------------------
\2763\ We discuss the definition of Relevant State Entities
below. See infra the Requirement that Transmission Providers Seek
the Agreement of Relevant State Entities Regarding the Cost
Allocation Method or Methods for Long-Term Regional Transmission
Facilities section.
---------------------------------------------------------------------------
1292. While we permit transmission providers to include a State
Agreement Process in their OATTs to determine cost allocation methods
for selected Long-Term Regional Transmission Facilities if the process
is agreed to by Relevant State Entities, it cannot be the sole method
filed for cost allocation for Long-Term Regional Transmission
Facilities. As discussed below, we find that sole reliance on a State
Agreement Process to determine a cost allocation method for selected
Long-Term Regional Transmission Facilities will not achieve the
objectives of this final order. Additionally, we modify the NOPR
proposal to require that, if a State Agreement Process fails to result
in a cost allocation method agreed to by Relevant State Entities and
any other authorized entities, or if the Commission ultimately finds
that the cost allocation method that results from a State Agreement
Process is unjust, unreasonable, or unduly discriminatory or
preferential, then the relevant Long-Term Regional Transmission Cost
Allocation Method on file would apply as a backstop. In other words, if
a Long-Term Regional Transmission Facility or portfolio of such
Facilities is selected but a State Agreement Process fails to result in
a Commission-accepted cost allocation method for that facility or
facilities, then their costs must be allocated through the Long-Term
Regional Transmission Cost Allocation Method or Methods that would
otherwise apply in the absence of a State Agreement Process (i.e., the
backstop Long-Term Regional Transmission Cost Allocation Method).\2764\
We clarify that, if the transmission providers have more than one Long-
Term Regional Transmission Cost Allocation Method on file, then the
[[Page 49481]]
method that would otherwise apply to the specific selected Long-Term
Regional Transmission Facility would serve as the backstop Long-Term
Regional Transmission Cost Allocation Method.
---------------------------------------------------------------------------
\2764\ For example, transmission providers could file two Long-
Term Regional Transmission Cost Allocation Methods, A and B. In this
example, Method A would apply only to Long-Term Regional
Transmission Facilities under 300 kV. Method B would apply to Long-
Term Regional Transmission Facilities at or above 300 kV only if an
agreed-upon State Agreement Process fails to result in a Commission-
accepted cost allocation method. If, on compliance, transmission
providers propose more than one Long-Term Regional Transmission Cost
Allocation Method, they must specify to which Long-Term Regional
Transmission Facilities each Long-Term Regional Transmission Cost
Allocation Method applies.
---------------------------------------------------------------------------
1293. We continue to find that facilitating state regulatory
involvement in the cost allocation process could minimize delays and
additional costs associated with state and local siting
proceedings.\2765\ Nevertheless, we find that the requirement for
transmission providers to include a Long-Term Regional Transmission
Cost Allocation Method in their OATTs is necessary because, if
transmission providers were to rely solely on a State Agreement Process
to determine the cost allocation for Long-Term Regional Transmission
Facilities and that process fails to result in agreement, there would
be no cost allocation method for Long-Term Regional Transmission
Facilities selected as the more efficient or cost-effective solutions
to Long-Term Transmission Needs. As a result, such selected Long-Term
Regional Transmission Facilities would be less likely to be developed,
and the benefits that these facilities would provide would not be
realized. Moreover, transmission providers would likely rely on
relatively inefficient or less cost-effective transmission facilities
to address the identified Long-Term Transmission Needs, or they may not
even address these needs at all, leading to unjust and unreasonable
Commission-jurisdictional rates. We further find that reliance solely
on a State Agreement Process would suffer from the same flaws that led
the Commission to require ex ante cost allocation for selected regional
transmission facilities in Order No. 1000, as the allocation of
transmission costs can be contentious and prone to litigation in multi-
state transmission planning regions.\2766\ Requiring a Long-Term
Regional Transmission Cost Allocation Method, even when transmission
providers also have a State Agreement Process in effect, provides a
level of certainty critical to the development of needed Long-Term
Regional Transmission Facilities.
---------------------------------------------------------------------------
\2765\ NOPR, 179 FERC ] 61,028 at P 301.
\2766\ Order No. 1000, 136 FERC ] 61,051 at PP 498-499; see also
S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 70 (finding that the
Commission reasonably balanced the benefits and claimed burdens of
Order No. 1000's reforms in concluding that the requirement that
each transmission provider include in its OATT a method(s) for
allocating ex ante the costs of new regional transmission facilities
``would reduce conflicts and `aid in the development and
construction of new transmission' '' and allow stakeholders ``to
determine ex ante `that the benefits associated with [a particular]
set of transmission facilities outweigh the costs' '' (citing Order
No. 1000, 136 FERC ] 61,051 at PP 499, 669)).
---------------------------------------------------------------------------
1294. As noted above, the relevant Long-Term Regional Transmission
Cost Allocation Method on file would serve as a backstop if the State
Agreement Process does not result in a Commission-accepted cost
allocation method for the selected Long-Term Regional Transmission
Facility or portfolio of such Facilities subject to the State Agreement
Process. This outcome could occur for several reasons. For instance,
Relevant State Entities may not reach agreement on a cost allocation
method pursuant to the terms of a State Agreement Process and the
transmission providers may choose not to file any cost allocation
method. In another instance, transmission providers may choose not to
file a cost allocation method agreed to pursuant to a State Agreement
Process and also choose not to file any alternative cost allocation
method. And finally, the Commission might not accept a cost allocation
method that results from a State Agreement Process and that
transmission providers submit to the Commission for filing under FPA
section 205 to the extent that it does not satisfy the requirement to
allocate costs at least roughly commensurate with estimated benefits or
is otherwise unjust or unreasonable.\2767\
---------------------------------------------------------------------------
\2767\ See PPL Elec. Utils. Corp., 181 FERC ] 61,178, at P 33
(2022) (``In light of the New Jersey state law, the New Jersey
[State Agreement Approach] Projects will benefit customers
throughout New Jersey, and thus we find that allocating the costs of
the New Jersey [State Agreement Approach] Projects on a load-ratio
share basis to all New Jersey customers is roughly commensurate with
the benefits provided by those projects.'') (footnote omitted).
---------------------------------------------------------------------------
1295. In response to NRG's and Mississippi Commission's concerns
that a Long-Term Regional Transmission Cost Allocation Method could
undermine productive negotiation among states if recourse to an ex ante
cost allocation method is an option for any objecting state,\2768\ on
balance, we find that this possibility is outweighed by the risk that
Long-Term Regional Transmission Facilities selected as the more
efficient or cost-effective solution to Long-Term Transmission Needs
may not have an associated cost allocation method absent this
requirement, and thus would be unlikely to be developed.\2769\ As we
explain above, the lack of a cost allocation method for selected Long-
Term Regional Transmission Facilities would likely result in
transmission providers relying on relatively inefficient or less cost-
effective transmission facilities to address identified Long-Term
Transmission Needs, or they may not even address these needs at all,
leading to unjust and unreasonable Commission-jurisdictional rates. We
further note that a Long-Term Regional Transmission Cost Allocation
Method provides certainty that the costs of Long-Term Regional
Transmission Facilities for which a State Agreement Process does not
result in a Commission-approved cost allocation method will be
allocated in a manner that the Commission has found to be just and
reasonable and not unduly discriminatory or preferential.
---------------------------------------------------------------------------
\2768\ Mississippi Commission Initial Comments at 27;
Mississippi Commission Reply Comments at 3; NRG Initial Comments at
20.
\2769\ As discussed below in the Requirement that Transmission
Providers Seek Agreement of Relevant State Entities Regarding the
Cost Allocation Method or Methods for Long-Term Regional
Transmission Facilities section, we decline to define what
constitutes agreement among Relevant State Entities and, as such, we
do not require unanimous agreement of Relevant State Entities
participating in the Engagement Period on a Long-Term Regional
Transmission Cost Allocation Method(s) and/or State Agreement
Process.
---------------------------------------------------------------------------
1296. In response to the arguments by SERTP Sponsors, Alabama
Commission, and Louisiana Commission emphasizing the importance of
voluntary cost allocation among states,\2770\ along with Mississippi
Commission's request for clarification that state agreement to a cost
allocation method be required for any Long-Term Regional Transmission
Facility under this final order,\2771\ we note that Relevant State
Entities will have the opportunity to provide their views on cost
allocation methods during the Engagement Period, as discussed further
below. Following this Engagement Period, Relevant State Entities may
agree to, and ask the transmission providers to file, a State Agreement
Process, which, if accepted by the Commission, would be the cost
allocation process used by the transmission providers in the
transmission planning region prior to the use of the relevant Long-Term
Regional Transmission Cost Allocation Method as a backstop. Further, as
discussed in the Proposals Relating to the Design and Operation of
State Agreement Processes section below, during the Engagement Period
or State Agreement Process, Relevant State Entities will have an
opportunity to agree to and ask transmission providers to file a Long-
Term Regional Transmission Cost Allocation Method. Thus, there are
multiple opportunities for Relevant State Entities to voluntarily
[[Page 49482]]
negotiate a cost allocation method for Long-Term Regional Transmission
Facilities.
---------------------------------------------------------------------------
\2770\ SERTP Sponsors Initial Comments at 3, 20, 28; Alabama
Commission Initial Comments at 9; Louisiana Commission Initial
Comments at 17-18, 30.
\2771\ Mississippi Commission Initial Comments at 28.
---------------------------------------------------------------------------
1297. We find that US Chamber of Commerce's concern, that state
utility regulators might fail to protect constituents if they were to
agree to an ex ante cost allocation method that assessed a fixed level
of costs on ratepayers regardless of the design or benefits of a
proposed regional transmission facility, is misplaced.\2772\ Any cost
allocation method(s) that transmission providers propose, be it as a
result of a State Agreement Process or a Long-Term Regional
Transmission Cost Allocation Method, must allocate costs in a manner
that is at least roughly commensurate with estimated benefits, as
discussed further below.\2773\ For the same reasons, we disagree with
EPSA's contention that, because Long-Term Regional Transmission
Planning introduces uncertainty risk that customers must bear, all the
relevant cost allocation methods on file should be voluntary.\2774\
---------------------------------------------------------------------------
\2772\ US Chamber of Commerce Initial Comments at 9-10.
\2773\ See infra Identification of Benefits Considered in Cost
Allocation for Long-Term Regional Transmission Facilities.
\2774\ EPSA Initial Comments at 7.
---------------------------------------------------------------------------
1298. We also acknowledge Duke's concerns that a default ex ante
cost allocation method could delay siting approvals and Xcel's concerns
associated with a mandated ex ante cost allocation method claiming that
the industry engaged more effectively in long-term transmission
planning before Order No. 1000.\2775\ We note that another modification
to the NOPR proposal that we adopt, as described below, allows State
Agreement Processes to occur before, as well as up to six months after,
selection of Long-Term Regional Transmission Facilities. This
modification helps to address Duke's and Xcel's concerns by providing
Relevant State Entities with an opportunity to agree on a cost
allocation method for a particular Long-Term Regional Transmission
Facility (or portfolio of such Facilities) after selection. However, we
find that, even if such an agreement on a State Agreement Process cost
allocation method cannot be achieved, on balance, the greater certainty
that ex ante cost allocation methods provide to allow the development
of Long-Term Regional Transmission Facilities outweighs the concerns
that Duke and Xcel express.
---------------------------------------------------------------------------
\2775\ Duke Initial Comments at 36; Xcel Initial Comments at 12.
---------------------------------------------------------------------------
1299. Furthermore, we find that allowing the use of a State
Agreement Process in addition to a Long-Term Regional Transmission Cost
Allocation method will assist in the development of Long-Term Regional
Transmission Facilities by taking into account state preferences. SEIA
and New Jersey Commission support such flexibility.\2776\ We agree with
New Jersey Commission that negotiated cost allocation methods may
reduce litigation and make it easier to construct needed transmission
facilities.\2777\ We recognize Dominion's concerns that implementing a
State Agreement Process with an ex ante approach could lead to delays;
\2778\ however, we find that both the backstop Long-Term Regional
Transmission Cost Allocation Method, combined with a six-month limit
after selection for deliberations under any State Agreement Process and
the filing of any resulting cost allocation method, as detailed below,
should limit such delays.
---------------------------------------------------------------------------
\2776\ New Jersey Commission Initial Comments at 25; SEIA
Initial Comments at 24.
\2777\ New Jersey Commission Initial Comments at 17.
\2778\ Dominion Initial Comments at 52.
---------------------------------------------------------------------------
1300. Next, we adopt the NOPR proposal to apply the cost allocation
reforms in this final order only to new Long-Term Regional Transmission
Facilities. We find that this reform does not apply to regional
reliability and economic transmission facilities that are selected
pursuant to the existing Order No. 1000 regional transmission planning
processes. We find, instead, that the existing Commission-accepted ex
ante regional cost allocation methods adopted pursuant to Order No.
1000 should continue to apply to those regional reliability and
economic transmission facilities. We find no basis in the record to
conclude that these existing regional cost allocation methods should
change, given that this final order does not alter existing regional
reliability and economic transmission planning processes. We believe
that this distinction between cost allocation methods for regional
reliability and economic transmission projects selected under existing
Order No. 1000 regional transmission planning processes and those for
new Long-Term Regional Transmission Facilities selected through Long-
Term Regional Transmission Planning will prevent the re-litigation of
cost allocation decisions for transmission facilities that are selected
prior to the effective date of this final order. In addition, we find
this distinction to be consistent with our decision not to apply Long-
Term Regional Transmission Cost Allocation Methods to transmission
facilities other than new Long-Term Regional Transmission
Facilities.\2779\
---------------------------------------------------------------------------
\2779\ As the Commission noted in the NOPR, the Commission took
a similar approach with respect to its cost allocation reforms in
Order No. 1000. See NOPR, 179 FERC ] 61,028 at P 314 n.517 (citing
Order No. 1000, 136 FERC ] 61,051 at P 565).
---------------------------------------------------------------------------
1301. We disagree with PIOs that allowing different cost allocation
methods to apply to different regional transmission planning processes
is unjust and unreasonable.\2780\ We find that because Long-Term
Regional Transmission Planning is a more long-term, forward-looking,
and comprehensive transmission planning process than existing Order No.
1000 regional transmission planning processes, it is appropriate for
transmission providers to consider, following the Engagement Period,
whether different cost allocation methods should apply to selected
Long-Term Regional Transmission Facilities.
---------------------------------------------------------------------------
\2780\ PIOs Initial Comments at 71.
---------------------------------------------------------------------------
1302. With respect to the potential use of existing regional cost
allocation methods as Long-Term Regional Transmission Cost Allocation
Methods, as well as assertions that existing cost allocation methods or
current existing processes for state involvement in cost allocation
decisions could be used for Long-Term Regional Transmission
Planning,\2781\ we adopt the NOPR proposal that, to the extent
transmission providers believe that their existing cost allocation
methods comply with the requirements adopted in this final order, they
may demonstrate in their compliance filings that such methods, as
applied to Long-Term Regional Transmission Facilities, would comply
with the requirements of this final order. This approach is consistent
with the approach that the Commission took in Order No. 1000, in which
the Commission declined commenter requests to decide in the rulemaking
itself whether existing cost allocation methods complied with the
requirements of Order No. 1000 and instead required transmission
providers to demonstrate on compliance that their existing cost
allocation methods met the rulemaking's requirements.\2782\
---------------------------------------------------------------------------
\2781\ See, e.g., Ameren Initial Comments at 25-27; APS Initial
Comments at 11-12; Avangrid Initial Comments at 28;Dominion Initial
Comments at 3, 45; Dominion Reply Comments at 11; MISO Initial
Comments at 61, 68; NYISO Initial Comments at 9, 50; Ohio Commission
Federal Advocate Initial Comments at 2, 13; Omaha Public Power
Initial Comments at 4; Pennsylvania Commission Initial Comments at
13-14; PJM Initial Comments at 116; PJM States Initial Comments at
11-12; SPP Initial Comments at 28-29; Virginia Commission Staff
Initial Comments at 6.
\2782\ See Order No. 1000, 136 FERC ] 61,051 at P 565; Order No.
1000-A, 139 FERC ] 61,132 at P 747.
---------------------------------------------------------------------------
[[Page 49483]]
1303. We disagree with PPL's contention that existing regional cost
allocation methods accepted by the Commission should be considered the
``default.'' The Commission accepted such ex ante regional cost
allocation methods based on demonstrations of how they met the six
Order No. 1000 regional cost allocation principles. We appreciate, as
the Commission has recognized, that some existing regional cost
allocation methods are complex, stakeholder-approved constructs and
that some are specifically designed to apply to broad portfolios of
transmission projects, such as MISO's regional cost allocation method
for Multi-Value Projects.\2783\ However, as described above, to the
extent that transmission providers propose on compliance to use an
existing regional cost allocation method as a Long-Term Regional
Transmission Cost Allocation Method, the transmission providers must
demonstrate that such existing regional cost allocation method, as
applied to Long-Term Regional Transmission Facilities, would comply
with the requirements of this final order. We disagree with ITC's
contention that the Commission should allow for streamlined compliance
plans for transmission providers that already have long-range
transmission planning processes; we reiterate that we require
transmission providers to submit proposed cost allocation processes on
compliance with this order so that the Commission may evaluate whether
those processes comply with the requirements of this final order.
---------------------------------------------------------------------------
\2783\ See, e.g., Midwest Indep. Transmission Sys. Operator,
Inc., 142 FERC ] 61,215, at P 434 (2013); Sw. Power Pool, Inc., 144
FERC ] 61,059, at P 347 (2013).
---------------------------------------------------------------------------
1304. BP raises a concern that it is not clear, in the case of a
multi-value project, whether only a part of the cost of a transmission
project associated with meeting changes in the resource mix and demand
will be allocated under a Long-Term Regional Transmission Cost
Allocation Method as opposed to all of the costs. With the exception of
Long-Term Regional Transmission Facilities that one or more Relevant
State Entities or interconnection customers agree to voluntarily fund,
we clarify that all costs associated with a selected Long-Term Regional
Transmission Facility must be allocated using the applicable Long-Term
Regional Transmission Cost Allocation Method or Methods, or an
applicable Commission-accepted cost allocation method that results from
a State Agreement Process.\2784\
---------------------------------------------------------------------------
\2784\ See supra Evaluation and Selection of Long-Term Regional
Transmission Facilities section. Moreover, in the Local Transmission
Planning Inputs in the Regional Transmission Planning Process
section below, we provide flexibility to transmission providers to
propose a cost allocation method for right-sized replacement
transmission facilities.
---------------------------------------------------------------------------
1305. In response to requests that a beneficiary-pays approach be
used rather than a postage stamp load ratio share model for cost
allocation methods,\2785\ we reiterate that any cost allocation method
applied to a Long-Term Regional Transmission Facility must ensure that
costs are allocated in a manner that is at least roughly commensurate
with the estimated benefits of the facility, consistent with cost
causation and court precedent.\2786\ Load ratio share, which charges
transmission customers in proportion to their use of the transmission
system as measured by their relative share of load, is a cost
allocation method that may be consistent with the beneficiary-pays
approach. The Commission will evaluate whether a proposed cost
allocation method allocates costs in a manner that is at least roughly
commensurate with estimated benefits on a fact-specific basis, relying
on the record in a given proceeding.
---------------------------------------------------------------------------
\2785\ See Certain TDUs Initial Comments at 2, 7, 8-9; R Street
Initial Comments at 4, 12.
\2786\ The cost causation principle requires costs to be
allocated to those who cause the costs to be incurred and reap the
resulting benefits. S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 87
(citing Nat'l Ass'n of Regul. Util. Comm'rs v. FERC, 475 F.3d at
1285); see also Order No. 1000, 136 FERC ] 61,051 at P 10 (``[T]he
principles-based approach requires that all regional and
interregional cost allocation methods allocate costs for new
transmission facilities in a manner that is at least roughly
commensurate with the benefits received by those who will pay those
costs. Costs may not be involuntarily allocated to entities that do
not receive benefits.''); ICC v. FERC I, 576 F.3d at 476 (``To the
extent that a utility benefits from the costs of new facilities, it
may be said to have `caused' a part of those costs to be incurred,
as without the expectation of its contributions the facilities might
not have been built, or might have been delayed.'').
---------------------------------------------------------------------------
1306. In response to commenters that request flexibility in cost
allocation,\2787\ we believe that the approach to cost allocation for
Long-Term Regional Transmission Facilities that we adopt in this final
order provides transmission providers and their stakeholders, and in
particular Relevant State Entities, with the flexibility needed to
address regional differences. Specifically, we find that the
flexibility to submit one or more Long-Term Regional Transmission Cost
Allocation Methods, as well as the flexibility to submit an additional
State Agreement Process, accommodate regional differences.
---------------------------------------------------------------------------
\2787\ See, e.g., Entergy Initial Comments at 29-30; Eversource
Initial Comments at 29-30; Idaho Power Initial Comments at 10;
NESCOE Reply Comments at 5; Pacific Northwest Utilities Initial
Comments at 5-6, 11, 13.
---------------------------------------------------------------------------
1307. We decline to adopt additional requirements with respect to
cost allocation that we did not propose in the NOPR, such as Shell's
request to require coastal transmission providers to explain how their
Long-Term Regional Transmission Planning facilitates cost allocation
for offshore wind.\2788\ We find that the record in this proceeding
does not support imposing this or other additional requirements.
Regarding certain cost allocation requirements suggested by
commenters,\2789\ including ACEG's suggestion for implementing a
voltage threshold level above which a transmission facility would
receive regional cost allocation,\2790\ we find such proposals to be
beyond the scope of this proceeding. The Commission did not make such
proposals in the NOPR.
---------------------------------------------------------------------------
\2788\ Shell Initial Comments at 17.
\2789\ Cypress Creek Reply Comments at 12; ELCON Initial
Comments at 19; R Street Initial Comments at 4, 12; Shell Initial
Comments at 25-28; Xcel Initial Comments at 12-13, 18.
\2790\ ACEG Initial Comments at 63.
---------------------------------------------------------------------------
2. Requirement That Transmission Providers Seek the Agreement of
Relevant State Entities Regarding the Cost Allocation Method or Methods
for Long-Term Regional Transmission Facilities
a. NOPR Proposal
1308. The Commission proposed to require transmission providers in
each transmission planning region to seek the agreement of Relevant
State Entities within the transmission planning region regarding the
Long-Term Regional Transmission Cost Allocation Method, State Agreement
Process, or combination thereof.\2791\ The Commission proposed to
require transmission providers in each transmission planning region to:
(1) explain how the proposed Long-Term Regional Transmission Cost
Allocation Method, State Agreement Process, or combination thereof
reflects the agreement of Relevant State Entities; or (2) to the extent
agreement of Relevant State Entities cannot be obtained, explain the
good faith efforts by the relevant transmission provider(s) to seek
agreement from such entities before proposing a Long-Term Regional
Transmission Cost Allocation Method, State Agreement Process, or
combination thereof.\2792\
---------------------------------------------------------------------------
\2791\ NOPR, 179 FERC ] 61,028 at P 303.
\2792\ Id. P 303.
---------------------------------------------------------------------------
1309. The Commission proposed to define Relevant State Entities for
purposes of the Long-Term Regional Transmission Planning cost
allocation requirements as ``any state entity responsible for utility
regulation or siting electric transmission facilities
[[Page 49484]]
within the state or portion of a state located in the transmission
planning region, including any state entity as may be designated for
that purpose by the law of such state.'' \2793\
---------------------------------------------------------------------------
\2793\ Id. P 304.
---------------------------------------------------------------------------
1310. The Commission proposed to require transmission providers in
each transmission planning region to seek to determine whether, for all
or a subset of Long-Term Regional Transmission Facilities, Relevant
State Entities agree to: (1) a Long-Term Regional Transmission Cost
Allocation Method; (2) a State Agreement Process; (3) forgo a role in
determining the cost allocation approach for Long-Term Regional
Transmission Facilities; or (4) some combination thereof.\2794\
---------------------------------------------------------------------------
\2794\ Id. P 305.
---------------------------------------------------------------------------
1311. The Commission proposed to afford transmission providers in
each transmission planning region flexibility in the process by which
they seek agreement from Relevant State Entities and to require
transmission providers to provide the state entities with flexibility
with regard to defining what constitutes ``agreement'' among the
Relevant State Entities on the cost allocation approach for Long-Term
Regional Transmission Facilities.\2795\ Although the Commission
proposed to provide transmission providers flexibility in determining
what constitutes state agreement, the Commission preliminarily found
that, for each state, a single entity should be designated as the
voting or representative entity to avoid confusion or over-
representation by a single state in a multi-state voting process.\2796\
---------------------------------------------------------------------------
\2795\ Id. P 306.
\2796\ Id. P 304.
---------------------------------------------------------------------------
1312. Noting that the Relevant State Entities may forgo a role in
determining the cost allocation approach for all or a subset of Long-
Term Regional Transmission Facilities, the Commission proposed that in
the event that the Relevant State Entities do so, the Commission would
require transmission providers to propose a Long-Term Regional
Transmission Cost Allocation Method consistent with the requirements of
Order No. 1000, including the prohibition on relying on voluntary
agreement among states or participant funding.\2797\ The Commission
explained that it was not proposing to impose any requirements on
states to participate in processes to establish regional cost
allocation methods for Long-Term Regional Transmission
Facilities.\2798\
---------------------------------------------------------------------------
\2797\ Id. P 307.
\2798\ Id. P 308.
---------------------------------------------------------------------------
b. Comments
i. State Involvement in Cost Allocation Proposals
1313. Many commenters generally support states having a role
negotiating proposed cost allocation methods.\2799\ However, some
commenters emphasize the importance of involving all stakeholders, and
not just Relevant State Entities, in this reform. Clean Energy Buyers
argue that the Commission should require transmission providers to
allow all stakeholders (not just states) to participate in, or at least
comment on, the development of the Long-Term Regional Transmission Cost
Allocation Method and to recognize the importance of states and all
other stakeholders.\2800\ Similarly, NEPOOL asserts that state
involvement should not diminish the opportunity for stakeholder
involvement from all market participants in the electric
industry.\2801\ APPA asserts that while coordination with state
regulators in cost allocation may aid in developing beneficial and
cost-effective transmission projects, the perspectives of state
regulators on cost allocation should not be elevated above those of
other stakeholders.\2802\
---------------------------------------------------------------------------
\2799\ See, e.g., AEP Initial Comments at 35; Ameren Initial
Comments at 25; American Municipal Power Initial Comments at 12;
Arizona Commission Initial Comments at 11; Clean Energy Associations
Initial Comments at 35; Clean Energy Buyers Initial Comments at 28-
29; Clean Energy States Initial Comments at 7; Cross Sector
Representatives Supplemental Comments at 1; Duke Initial Comments at
35; ELCON Initial Comments at 17; ISO-NE Initial Comments at 2;
Georgia Commission Initial Comments at 8-9; US House Republicans
Supplemental Comments at 1; ITC Initial Comments at 28; Joint
Consumer Advocates Initial Comments at 13; Maryland Energy
Administration Initial Comments at 2; Massachusetts Attorney General
Initial Comments at 19; Michigan Commission Initial Comments at 8;
MISO Initial Comments at 61; NARUC Initial Comments at 45 (citing
NOPR, 179 FERC ] 61,028 at PP 303-308), 46; New York Commission and
NYSERDA Initial Comments at 1; NESCOE Initial Comments at 54; North
Carolina Commission and Staff Initial Comments at 2; North Dakota
Commission Initial Comments at 4; NRG Initial Comments at 6; NYISO
Initial Comments at 49; OMS Initial Comments at 10; PacifiCorp and
NV Energy Initial Comments at 15; PIOs Initial Comments at 64;
Resale Iowa Initial Comments at 2; US Chamber of Commerce Initial
Comments at 9 (citing NOPR, 179 FERC ] 61,028 at P 288); Virginia
Commission Staff Initial Comments at 2; WIRES Initial Comments at
12.
\2800\ Clean Energy Buyers Initial Comments at 29.
\2801\ NEPOOL Initial Comments at 9.
\2802\ APPA Initial Comments at 42.
---------------------------------------------------------------------------
1314. Idaho Power states that the Commission should continue to
allow flexibility for transmission planning regions to determine the
appropriate level of state involvement.\2803\ Pacific Northwest
Utilities agree, stating that mandating additional state participation
could be burdensome and problematic.\2804\
---------------------------------------------------------------------------
\2803\ Idaho Power Initial Comments at 10.
\2804\ Pacific Northwest Utilities Initial Comments at 13.
---------------------------------------------------------------------------
1315. MISO states that the Commission should not extend any state
involvement that may be adopted pursuant to the final order to near-
term reliability and economic regional transmission planning processes,
which are beyond the scope of the final order.\2805\ MISO Coops state
that MISO provides a stakeholder forum where states' voices are heard,
and the final order should not diminish stakeholder processes that are
effective today.\2806\
---------------------------------------------------------------------------
\2805\ MISO Initial Comments at 71.
\2806\ MISO Coops Initial Comments at 2.
---------------------------------------------------------------------------
1316. Other commenters raise concerns about increased state
involvement in cost allocation decisions. For example, Vistra asserts
that a prioritized role for states in cost allocation is more likely to
create new challenges than ease development, and observes that it may
be difficult to coordinate state interests in multi-state transmission
planning regions versus single-state transmission planning
regions.\2807\ Six Cities opposes enhanced roles for Relevant State
Entities, suggesting that the proposed reforms represent neither an
appropriate oversight role for states under the FPA, nor a logical
extension of Order No. 890 and Order No. 1000 policies.\2808\
---------------------------------------------------------------------------
\2807\ Vistra Initial Comments at 2, 27-28.
\2808\ Six Cities Initial Comments at 7.
---------------------------------------------------------------------------
1317. ACEG and Georgia Commission agree with the Commission's
proposed definition of Relevant State Entities.\2809\ ACEG and Dominion
also support the proposal to have a single entity designated as the
voting representative for the state.\2810\ MISO agrees that having a
single entity designated for each state and/or applicable jurisdiction
as the voting or representative entity for that state/jurisdiction
makes sense, but notes that the City of New Orleans is an independent
member of OMS separate from the Louisiana Commission and therefore may
need to be considered a separate jurisdiction.\2811\ Louisiana
Commission voices similar concerns.\2812\ North Carolina Commission and
Staff state that it may be appropriate for different state entities to
be designated for different roles,\2813\ and Duke asserts that the
Commission should clarify that within a state there
[[Page 49485]]
may be multiple Relevant State Entities.\2814\
---------------------------------------------------------------------------
\2809\ ACEG Initial Comments at 65-66; Georgia Commission
Initial Comments at 8.
\2810\ ACEG Initial Comments at 65-66; Dominion Initial Comments
at 48 n.99.
\2811\ MISO Initial Comments at 66.
\2812\ Louisiana Commission Initial Comments at 33.
\2813\ North Carolina Commission and Staff Initial Comments at
17.
\2814\ Duke Initial Comments at 38-39.
---------------------------------------------------------------------------
1318. Some commenters generally agree with the Commission's
proposed definition of Relevant State Entities but request that the
definition be expanded or clarified to include self-regulated public
power utilities and cooperatives.\2815\ TAPS argues that a multi-state
voting process, as proposed, could fail to represent public power and
cooperatives' interests.\2816\ NRECA contends that a more inclusive
approach would be to use ``relevant electric regulatory authority,''
which includes a state public utility commission and the governing
board of a cooperative or public power utility.\2817\ Large Public
Power proposes to grant state and municipal utilities representation on
a load ratio share basis.\2818\
---------------------------------------------------------------------------
\2815\ American Municipal Power Initial Comments at 5; APPA
Initial Comments at 3, 42-43 (citing 16 U.S.C. 796(7), (15));
California Municipal Utilities Initial Comments at 17; MISO Coops
Initial Comments at 3-4; Six Cities Initial Comments at 10.
\2816\ TAPS Initial Comments at 5, 26-27.
\2817\ NRECA Initial Comments at 56-57.
\2818\ Large Public Power Initial Comments at 41.
---------------------------------------------------------------------------
1319. NASUCA urges the Commission to clarify that where applicable,
an approved state cost allocation process should include agreement by a
state's utility consumer advocate.\2819\ California Energy Commission
recommends expanding the definition of Relevant State Entities to
include any groups directly or indirectly affected by the construction
of a project, such as Native American Tribes,\2820\ and NESCOE requests
that the definition of Relevant State Entity be amended to accommodate
individual transmission planning regions' particular approaches toward
state involvement in cost allocation requirements, such as NESCOE
managers designated by each New England Governor to represent that
state's interests.\2821\
---------------------------------------------------------------------------
\2819\ NASUCA Initial Comments at 10-11.
\2820\ California Energy Commission Initial Comments at 3.
\2821\ NESCOE Initial Comments at 57.
---------------------------------------------------------------------------
1320. Nevada Commission requests flexibility in the term Relevant
State Entity.\2822\ New Mexico RETA urges flexibility to account for
state involvement of other entities not accounted for in the definition
of Relevant State Entities, including state authorities specifically
designated to assist in developing new electric transmission facilities
(like New Mexico RETA).\2823\
---------------------------------------------------------------------------
\2822\ Nevada Commission Initial Comments at 13.
\2823\ New Mexico RETA Initial Comments at 8-9 (citing NOPR 179
FERC ] 61,028 at P 304).
---------------------------------------------------------------------------
1321. ACEG recommends that the Commission clarify that existing
processes, such as SPP's Regional State Committee, MISO's OMS, and ISO-
NE's New England States Committee, should be used to determine the
Relevant State Entity for each state, unless another process is
demonstrated to be superior.\2824\
---------------------------------------------------------------------------
\2824\ ACEG Initial Comments at 66.
---------------------------------------------------------------------------
1322. SERTP Sponsors assert that which Relevant State Entity or
Entities would be appropriate for a particular state will be a function
of state law.\2825\ Pennsylvania Commission states that the
Commission's proposed definition of Relevant State Entity is imperfect
and may result in multiple entities within a single state being a
Relevant State Entity, given that the Commission refers to utility
regulation or siting authority in the definition, but a state's
legislature could have delegated this different authority among
different administrative agencies.\2826\
---------------------------------------------------------------------------
\2825\ SERTP Sponsors Initial Comments at 28-29.
\2826\ Pennsylvania Commission Initial Comments at 15.
---------------------------------------------------------------------------
ii. Requirement To Seek Agreement
1323. Many commenters generally support requiring transmission
providers in each transmission planning region to seek the agreement of
Relevant State Entities within the transmission planning region
regarding the Long-Term Regional Transmission Cost Allocation Method,
State Agreement Process, or combination thereof.\2827\
---------------------------------------------------------------------------
\2827\ See, e.g., Acadia Center and CLF Initial Comments at 29-
30; Avangrid Initial Comments at 28; City of New Orleans Council
Initial Comments at 9; Entergy Initial Comments at 29-30; Georgia
Commission Initial Comments at 8-9; ISO-NE Initial Comments at 37-
38; Louisiana Commission Initial Comments at 30; Michigan Commission
Initial Comments at 8; NARUC Initial Comments at 45, 47; Nebraska
Commission Initial Comments at 9; NESCOE Initial Comments at 54
(citing NOPR, 179 FERC ] 61,028 at PP 303, 305); North Carolina
Commission and Staff Initial Comments at 15-16; Ohio Commission
Federal Advocate Initial Comments at 11; Pacific Northwest State
Agencies Initial Comments at 27; PJM States Initial Comments at 9;
SoCal Edison Initial Comments at 3; Southeast PIOs Initial Comments
at 55 (citing NOPR, 179 FERC ] 61,028 at P 303); US Climate Alliance
Initial Comments at 2; WIRES Initial Comments at 12.
---------------------------------------------------------------------------
1324. Avangrid states that state input and collaboration is crucial
to the transmission planning process, and that intensive state (and
other stakeholder) participation and consensus-building will help to
ensure that transmission will not be overbuilt.\2828\ SoCal Edison
contends that without agreement among states on the respective benefits
and share of related costs, the development of multi-state transmission
projects will be nearly non-existent.\2829\ PPL supports transmission
providers seeking agreement with the states on cost allocation methods,
as well as voluntary coordination with states, which PPL argues will
make public policy projects more likely to succeed.\2830\
---------------------------------------------------------------------------
\2828\ Avangrid Initial Comments at 28.
\2829\ SoCal Edison Initial Comments at 3.
\2830\ PPL Initial Comments at 29.
---------------------------------------------------------------------------
1325. NYISO and ISO-NE support state entities playing a role in
determining the cost allocation method for transmission solutions to
Long-Term Transmission Needs.\2831\ ISO-NE contends that states should
be responsible for determining the cost allocation mechanism for
policy-based, long-term transmission facility investments because they
are uniquely situated to balance the benefits and costs of transmission
investments intended to advance their policy goals.\2832\
---------------------------------------------------------------------------
\2831\ NYISO Initial Comments at 49; ISO-NE Initial Comments at
37.
\2832\ ISO-NE Initial Comments at 37.
---------------------------------------------------------------------------
1326. Mississippi Commission argues that opponents of state
involvement in Long-Term Regional Transmission Planning fail to
recognize the existing state regulatory role in siting electricity
generation, transmission, and distribution facilities.\2833\
---------------------------------------------------------------------------
\2833\ Mississippi Commission Reply Comments at 5.
---------------------------------------------------------------------------
1327. In addition, some commenters support the agreement of states
when determining a Long-Term Regional Transmission Cost Allocation
Method. City of New Orleans Council comments that it is essential that
state and local regulators agree to any Long-Term Regional Transmission
Cost Allocation Method to ensure that the costs borne by retail
customers are just and reasonable and not unduly discriminatory or
preferential.\2834\ SoCal Edison concurs on the necessity for states to
reach agreement.\2835\ Southern argues that unless state regulators
agree to transmission project selection and cost allocation,
transmission projects that result from the Commission's proposed Long-
Term Regional Transmission Planning are not likely to come to
fruition.\2836\
---------------------------------------------------------------------------
\2834\ City of New Orleans Council Initial Comments at 9.
\2835\ SoCal Edison Initial Comments at 3, 13.
\2836\ Southern Initial Comments at 9-10.
---------------------------------------------------------------------------
iii. Seek Changes To, Raise Concerns About, or Oppose the Requirement
To Seek Agreement
1328. Some commenters support requiring transmission providers to
seek agreement with Relevant State Entities regarding the Long-Term
Regional Transmission Cost Allocation Method, State Agreement Process,
or a combination thereof, but propose changes to the proposal. For
example,
[[Page 49486]]
Kentucky Commission Chair Chandler asserts that states should not be
permanently bound by their agreement on an initial cost allocation
method, and that the Commission should clarify that transmission
providers should continue to seek agreement from states prior to
seeking Commission approval for any change to the cost allocation
method filed on compliance.\2837\ Similarly, PJM States request that
the Commission require transmission providers to show they sought
support of retail regulators for subsequent revisions of the initial
cost allocation method.\2838\ PJM States ask that the Commission also
require a regular check-in with retail regulators regarding the
appropriateness of any existing cost allocation method.\2839\
---------------------------------------------------------------------------
\2837\ Kentucky Commission Chair Chandler Initial Comments at 3.
\2838\ PJM States Initial Comments at 10.
\2839\ Id. at 10-11.
---------------------------------------------------------------------------
1329. Resale Iowa states that it is concerned that large, multi-
state transmission projects may increase the number of participants to
the point that agreement is difficult to achieve and suggests that
multi-state organizations may provide an avenue for conveying state
interests to transmission providers and reaching agreements.\2840\ DC
and MD Offices of People's Counsel support giving state entities a
``defined and expansive role'' in the regional transmission selection
and cost allocation processes but argue that this role must be anchored
by their ability to timely agree on cost allocation.\2841\
---------------------------------------------------------------------------
\2840\ Resale Iowa Initial Comments at 2, 12.
\2841\ DC and MD Offices of People's Counsel Initial Comments at
37.
---------------------------------------------------------------------------
1330. Other commenters offered modified versions of the NOPR
proposal. California Commission states that the Commission should
require that transmission providers use their FPA section 205 filing
rights to submit the ex post cost allocation method (and/or combined
method) agreed on by states even if the transmission providers in a
transmission planning region determine that they will propose an ex
ante cost allocation method for the Commission's consideration.\2842\
---------------------------------------------------------------------------
\2842\ California Commission Initial Comments at 55-56.
---------------------------------------------------------------------------
1331. Dominion states that it may be nearly impossible to achieve
state consensus in multi-state RTOs/ISOs and that if the states in a
transmission planning region are unable to agree on the proper cost
allocation method, the transmission providers should be able to file
their own proposed cost allocation method.\2843\
---------------------------------------------------------------------------
\2843\ Dominion Initial Comments at 48.
---------------------------------------------------------------------------
1332. Some commenters oppose the proposed requirement to seek
agreement. For example, Minnesota State Entities state that the term
``seeking state agreement'' is too vague and may lead to disputes over
the rights and responsibilities of individual states or state
commissions to veto or otherwise hold up needed region-wide
transmission plans. Minnesota State Entities suggest replacing the term
``seeking state agreement'' with ``take into account'' or ``evaluating
and incorporating'' state concerns in the regional cost allocation
approaches as regularly happens at MISO and other RTOs/ISOs.\2844\ MISO
Coops state that the NOPR proposal for a transmission provider to seek
agreement with Relevant State Entities is unnecessary and would be
inferior to current stakeholder processes, setting up redundant and
potentially conflicted processes.\2845\
---------------------------------------------------------------------------
\2844\ Minnesota State Entities Initial Comments at 7.
\2845\ MISO Coops Initial Comments at 4.
---------------------------------------------------------------------------
1333. Kansas Commission questions the necessity of a requirement to
seek the agreement of Relevant State Entities within a transmission
planning region like SPP, where the SPP Regional State Committee has
substantial influence over cost allocation.\2846\ PacifiCorp and NV
Energy oppose a requirement for transmission providers to seek state
agreement on a cost allocation method, contending that such a
requirement would add complexity and significant process and
time.\2847\ NRG states that under the proposal for transmission
providers to seek the agreement of Relevant State Entities on cost
allocation, customers that ultimately pay the cost of Long-Term
Regional Transmission Facilities are left out of the cost allocation
process. NRG suggests that the proposal be limited to transmission
projects included in regional transmission plans that would not exist
but for state public policy, as it is reasonable for states to fill
this negotiating role as described in the NOPR.\2848\
---------------------------------------------------------------------------
\2846\ Kansas Commission Initial Comments at 15-16.
\2847\ PacifiCorp and NV Energy Initial Comments at 16.
\2848\ NRG Initial Comments at 19.
---------------------------------------------------------------------------
1334. MISO TOs contend that MISO and MISO TOs have already afforded
opportunities for states to participate in the development of cost
allocation methods,\2849\ and argue that the NOPR requirements as
drafted are unnecessary for the MISO region.\2850\ MISO TOs argue that
the Commission should find compelling the fact that MISO, MISO TOs, and
OMS all support the existing collaborative process for cost allocation
in MISO, and request that the Commission not impose changes on this
process, but instead afford regional flexibility.\2851\
---------------------------------------------------------------------------
\2849\ MISO TOs Initial Comments at 45.
\2850\ MISO TOs Reply Comments at 3.
\2851\ Id. at 9 (citing APS Initial Comments at 10-11; MISO
Initial Comments at 55-69; MISO TOs Initial Comments at 41-45; OMS
Initial Comments at 10-13).
---------------------------------------------------------------------------
1335. MISO TOs disagree with commenters that argue that the NOPR
provided too much discretion and deference to transmission
providers,\2852\ or that the Commission should require transmission
providers to add a mechanism that ensures compliance with the
requirements to include Relevant State Entities in cost
allocation.\2853\ MISO TOs state that these proposals are contrary to
the FPA because they attempt to usurp the statutory rights of
transmission providers and point to similar sentiments expressed by the
Indicated PJM TOs.\2854\
---------------------------------------------------------------------------
\2852\ Id. at 4 (citing California Commission Initial Comments
at 51-54).
\2853\ Id. at 4-5 (citing NARUC Initial Comments at 49; NESCOE
Initial Comments at 16-19, 46 (requesting that the Commission either
require codification of states' roles for cost allocation of long-
term regional transmission facilities in OATTs or require
explanation following consultation with states of a different
approach)).
\2854\ Id. at 5, 8 (citing Indicated PJM TOs Initial Comments at
23).
---------------------------------------------------------------------------
iv. Requirements Associated With Seeking Agreement of Relevant State
Entities
1336. ACEG, ACORE, and NESCOE support the NOPR proposal to require
transmission providers to demonstrate their good faith efforts to seek
agreement from Relevant State Entities before proposing a Long-Term
Regional Transmission Cost Allocation Method, State Agreement Process,
or combination thereof.\2855\ AEE states that the final order should
better define what constitutes ``good faith effort'' to seek agreement
on cost allocation from states, including the Commission's minimum
expectations concerning the time that transmission providers must allow
states to reach agreement, the need to hold meetings, and related
topics.\2856\ OMS, on the other hand, urges the Commission to not
require a formal process in which transmission providers must
demonstrate how they sought the agreement of state entities.\2857\
---------------------------------------------------------------------------
\2855\ ACEG Initial Comments at 65; ACORE Initial Comments at 18
(citing NOPR, 179 FERC ] 61,028 at PP 306, 308); NESCOE Initial
Comments at 59 (citing NOPR, 179 FERC ] 61,028 at P 308).
\2856\ AEE Initial Comments at 33-34.
\2857\ OMS Initial Comments at 11.
---------------------------------------------------------------------------
1337. NARUC recommends that the Commission require, at a minimum,
that transmission providers: (1)
[[Page 49487]]
communicate with Relevant State Entities promptly in a manner that is
reasonably calculated to be received by the Relevant State Entities and
(2) establish a forum for negotiation that enables robust participation
from Relevant State Entities and transmission providers.\2858\
PacifiCorp and NV Energy urge the Commission to clarify that a
transmission provider's obligation under any final order is only to
provide state regulators an opportunity to participate in the process
of establishing a cost allocation method, should they so choose.\2859\
NESCOE asserts that the Commission should require transmission
providers to afford Relevant State Entities sufficient time to agree on
a cost allocation approach. NESCOE advocates for the Commission to give
states six months from the effective date of a final order to agree on
a cost allocation method, which NESCOE argues is needed due to the
complexity involved.\2860\
---------------------------------------------------------------------------
\2858\ NARUC Initial Comments at 44.
\2859\ PacifiCorp and NV Energy Initial Comments at 17.
\2860\ NESCOE Initial Comments at 60.
---------------------------------------------------------------------------
1338. Some commenters support the NOPR proposal to provide states
flexibility in determining what constitutes agreement among Relevant
State Entities on the cost allocation approach for Long-Term Regional
Transmission Facilities.\2861\ Alabama Commission contends that the
Commission should not establish any specific timeline for negotiation
to allow sufficient time for states to reach such agreement.\2862\ In
contrast, ACEG argues that there must be a firm time frame for any
negotiations, because allowing Relevant State Entities more time to
reach agreement could unnecessarily delay the process.\2863\ Likewise,
Pine Gate and PIOs support requiring a firm deadline, arguing that
absent such a requirement, a single state or a handful of states could
significantly delay transmission development.\2864\
---------------------------------------------------------------------------
\2861\ See, e.g., ACORE Initial Comments at 18 (citing NOPR, 179
FERC ] 61,028 at PP 306, 308); Georgia Commission Initial Comments
at 8; Massachusetts Attorney General Initial Comments at 20 (citing
NOPR, 179 FERC ] 61,028 at PP 306, 308); NARUC Initial Comments at
47-48 (citing NOPR, 179 FERC ] 61,028 at P 306); Nebraska Commission
Initial Comments at 10; NESCOE Initial Comments at 58; Pacific
Northwest State Agencies Initial Comments at 24-25 (citing NOPR, 179
FERC ] 61,028 at PP 309, 318).
\2862\ Alabama Commission Initial Comments at 9.
\2863\ ACEG Initial Comments at 64-65.
\2864\ Pine Gate Initial Comments at 46; PIOs Initial Comments
at 69-70.
---------------------------------------------------------------------------
1339. While ACEG supports the NOPR proposal, ACEG cautions that
this flexibility should not grant states veto power over the
agreement.\2865\ Similarly, PJM States argue that the Commission should
not require unanimity in determining an initial Long-Term Regional
Transmission Cost Allocation Method, and instead, retain the proposal
in the NOPR to allow states to determine how they will come to
agreement on a Long-Term Regional Transmission Facility cost allocation
approach.\2866\ New Jersey Commission further asserts that the
Commission must ensure that transmission providers cannot unilaterally
veto proposals that result from states' negotiations on a cost
allocation approach.\2867\
---------------------------------------------------------------------------
\2865\ ACEG Initial Comments at 66.
\2866\ PJM States Reply Comments at 4 (citing NOPR, 179 FERC ]
61,028 at PP 304, 319).
\2867\ New Jersey Commission Initial Comments at 17.
---------------------------------------------------------------------------
1340. Nebraska Commission asserts that the Commission should allow
RTOs/ISOs that have an existing decision-making process that includes
state entity participation to continue using it, citing SPP's Regional
State Committee and MISO's OMS as well-established processes developed
over many years with stakeholder input. Nebraska Commission adds that
providing flexibility in this process for transmission providers would
be the least disruptive and most useful approach.\2868\ Relatedly,
ACORE states that where agreements on cost allocation have already been
reached with state entities for transmission projects with multiple
benefits, the Commission should not require transmission providers to
revisit those agreements.\2869\
---------------------------------------------------------------------------
\2868\ Nebraska Commission Initial Comments at 10.
\2869\ ACORE Initial Comments at 18 (NOPR, 179 FERC ] 61,028 at
P 314).
---------------------------------------------------------------------------
1341. ISO-NE also supports the Commission's proposal to afford
transmission providers flexibility in determining what constitutes
state agreement, as well as the process by which they seek agreement
from the states. ISO-NE argues that if state agreement cannot be
reached, the Commission should allow the transmission planning region
to develop a fallback cost allocation method for use in the event that
the states agree to move forward with a long-term transmission facility
to advance public policy, but do not agree on a cost allocation method.
ISO-NE requests that a final order be clear that the OATT will be the
means by which the states will communicate the agreed cost allocation
method to the transmission provider, but the OATT should not dictate
the process by which states engage to achieve consensus.\2870\
---------------------------------------------------------------------------
\2870\ ISO-NE Initial Comments at 37-38.
---------------------------------------------------------------------------
1342. Some commenters favor mandating what constitutes agreement
among Relevant State Entities. Pine Gate states that the Commission
should establish a minimum set of criteria outlining when it will
consider there to be such agreement. Pine Gate also asks for
clarification as to whether unanimity is necessary for states to reach
agreement on a cost allocation method.\2871\ Similarly, AEE requests
additional guidance on what it means for states to ``agree'' to cost
allocation approaches.\2872\ Shell states that an OATT mechanism that
clearly delineates the process and timing for state input will
facilitate the participation of Relevant States Entities. However,
Shell further states, the OATT provision could provide flexibility for
stakeholders to identify the relevant agency for each state as the
voting entity for cost allocation decisions.\2873\
---------------------------------------------------------------------------
\2871\ Pine Gate Initial Comments at 45-46.
\2872\ AEE Initial Comments at 32-33 (citing NOPR, 179 FERC ]
61,028 at P 306).
\2873\ Shell Initial Comments at 16-17.
---------------------------------------------------------------------------
1343. Acadia Center and CLF assert that the Commission should
clarify that states within a given transmission planning region need
not unanimously agree on a cost allocation method and can define
agreement as necessary when a majority of states in such region approve
a cost allocation method for transmission facilities.\2874\ Acadia
Center and CLF explain that such an approach is consistent with
NESCOE's memorandum of understanding in ISO-NE,\2875\ and similarly,
New England for Offshore Wind argues that the Commission should not
require agreement to be unanimous among states in a multi-state
transmission planning region.\2876\
---------------------------------------------------------------------------
\2874\ Acadia Center and CLF Initial Comments at 30.
\2875\ Id. at 31 (citing Memorandum of Understanding Among ISO-
NE, NEPOOL, and NESCOE, at 3, 9 (Nov. 21, 2007), https://www.iso-ne.com/static-assets/documents/regulatory/part_agree/mou_final.pdf).
\2876\ New England for Offshore Wind Initial Comments at 4-5.
---------------------------------------------------------------------------
1344. PIOs also argue that the Commission should not require that
states in a particular transmission planning region unanimously approve
an ex ante cost allocation method. PIOs assert, rather, that the
Commission should allow transmission providers to adopt a cost
allocation method that is otherwise just and reasonable with agreement
among a majority of states. PIOs state that each RTO/ISO has an
organization of states that operates as a committee and that most of
these committees require a simple majority vote (for example, the SPP
Regional State Committee, OPSI, and OMS) and that the experience with
the RTO/ISO regional state committees can be
[[Page 49488]]
extrapolated and applied to the non-RTO/ISO transmission planning
regions as well.\2877\ Pattern Energy proposes that a reasonable
threshold for ``agreement'' would be for one-half of the Relevant State
Entities to agree to the Long-Term Regional Transmission Cost
Allocation Method, State Agreement Process, or combination
thereof.\2878\
---------------------------------------------------------------------------
\2877\ PIOs Initial Comments at 66-67.
\2878\ Pattern Energy Initial Comments at 19.
---------------------------------------------------------------------------
1345. In contrast, Southeast PIOs propose that state agreement
should require unanimous acceptance by the states in the relevant
transmission planning region. Southeast PIOs state that in the event
transmission providers are unable to achieve unanimity, the Commission
could presumptively impose the cost allocation mechanism approved by a
plurality of the transmission planning region's states.\2879\
---------------------------------------------------------------------------
\2879\ Southeast PIOs Initial Comments at 56.
---------------------------------------------------------------------------
v. Outcome if Relevant State Entities Forgo a Role in Determining a
Long-Term Regional Transmission Cost Allocation Method
1346. Some commenters support the Commission's proposal that, in
the event that states forgo a role in determining the cost allocation
approach for all or a subset of Long-Term Regional Transmission
Facilities, transmission providers must propose a Long-Term Regional
Transmission Cost Allocation Method.\2880\
---------------------------------------------------------------------------
\2880\ MISO Initial Comments at 67; NESCOE Initial Comments at
59; Pennsylvania Commission Initial Comments at 13; PIOs Initial
Comments at 67.
---------------------------------------------------------------------------
vi. Outcome if Relevant State Entities Fail To Reach Agreement on a
Cost Allocation Method
1347. Several commenters agree with the proposal that, in the event
that Relevant State Entities fail to reach an agreement on a cost
allocation method, transmission providers must file a cost allocation
method with the Commission.\2881\ NARUC recommends that if Relevant
State Entities are unable to reach agreement on cost allocation, the
Commission should require transmission providers to file changes to
their OATTs that reflect as much consensus as was reached.\2882\
---------------------------------------------------------------------------
\2881\ ACEG Initial Comments at 64; Entergy Initial Comments at
31; Pacific Northwest State Agencies Initial Comments at 29;
PacifiCorp and NV Energy Initial Comments at 16; Pattern Energy
Initial Comments at 19; TAPS Initial Comments at 4, 23-24.
\2882\ NARUC Initial Comments at 48-49.
---------------------------------------------------------------------------
1348. PIOs state that when cost allocation disputes occur, the
Commission could use its authority to convene a joint board with
affected states to consider issues and make decisions.\2883\ PIOs
further state that if states cannot agree to an ex ante cost allocation
method by the compliance deadline for the final order, the Commission
should institute a default cost allocation method.\2884\
---------------------------------------------------------------------------
\2883\ PIOs Initial Comments at 67 (citing 16 U.S.C. 824h; 18
CFR 385.1304).
\2884\ Id. at 69.
---------------------------------------------------------------------------
1349. Similarly, Eversource and Vermont Electric and Vermont
Transco state that when Relevant State Entities fail to agree on a cost
allocation method, the Commission should establish the Long-Term
Regional Transmission Cost Allocation Method.\2885\ To improve
transparency and certainty, Clean Energy Associations state that the
Commission should establish a cost allocation method upfront for
situations where ``state concurrence on either an ex ante or ex post
approach'' cannot be reached, submitting that a 90-day period would be
reasonable for the Commission to determine a cost allocation method in
the absence of state concurrence on either type of approach.\2886\
---------------------------------------------------------------------------
\2885\ Eversource Initial Comments at 30 (citing NOPR, 179 FERC
] 61,028 at P 310 (citation omitted)); Vermont Electric and Vermont
Transco Initial Comments at 4.
\2886\ Clean Energy Associations Initial Comments at 36.
---------------------------------------------------------------------------
1350. In contrast, Pacific Northwest State Agencies oppose the
Commission establishing a Long-Term Regional Transmission Cost
Allocation Method on its own initiative.\2887\ NESCOE states that
having the transmission provider file a cost allocation method when
states cannot agree is preferable to the Commission establishing the
cost allocation method. Specifically, NESCOE asserts that a more
appropriate role for the Commission is to establish general principles
under a final order and evaluate compliance filings made by
transmission providers (or subsequent FPA section 205 proposals down
the road) for adherence to those principles.\2888\
---------------------------------------------------------------------------
\2887\ Pacific Northwest State Agencies Initial Comments at 29.
\2888\ NESCOE Initial Comments at 61 (citing NOPR, 179 FERC ]
61,028 at P 314).
---------------------------------------------------------------------------
1351. NESCOE further suggests that if the states cannot reach
agreement within the first four months after the effective date of a
final order, they should be provided the opportunity to request that
the Commission appoint one or more senior staff members to facilitate
agreement.\2889\
---------------------------------------------------------------------------
\2889\ Id. at 60.
---------------------------------------------------------------------------
1352. In contrast, where agreement is not reached in the
established timeframe, ACEG states that the Commission should permit
transmission providers to explain their good faith efforts undertaken
to seek agreement.\2890\
---------------------------------------------------------------------------
\2890\ ACEG Initial Comments at 64-65.
---------------------------------------------------------------------------
1353. Clean Energy Associations, some state legislators, and some
US Senators state that the final order should provide clarity around
how disagreements among states or transmission providers regarding cost
allocation will be handled.\2891\ Clean Energy Associations recommend,
and [Oslash]rsted agrees, that in the absence of such agreement, the
Commission should require cost allocation to track the identified and
quantifiable benefits of Long-Term Regional Transmission
Facilities.\2892\ Senator Schumer supports providing guidance when
there is no state agreement on cost allocation to prevent state vetoes
of cost allocation methods and to prevent states being incentivized to
free ride on transmission planning and avoid costs.\2893\
---------------------------------------------------------------------------
\2891\ Clean Energy Associations Initial Comments at 35-36
(citing NOPR, 179 FERC ] 61,028 at P 310); Environmental Legislators
Caucus Supplemental Comments at 2; Senator Schumer Supplemental
Comments at 2; US Senators Supplemental Comments at 2.
\2892\ Clean Energy Associations Initial Comments at 35-36;
[Oslash]rsted Initial Comments at 9.
\2893\ Senator Schumer Supplemental Comments at 2.
---------------------------------------------------------------------------
c. Commission Determination
1354. We decline to adopt the NOPR proposal to require transmission
providers to seek the agreement of Relevant State Entities within the
transmission planning region regarding the relevant cost allocation
method to be applied to Long-Term Regional Transmission Facilities.
Instead, we modify the NOPR proposal to establish a six-month time
period (Engagement Period), during which transmission providers must:
(1) provide notice of the starting and end dates for the six-month time
period; (2) post contact information that Relevant State Entities may
use to communicate with transmission providers about any agreement
among Relevant State Entities on a Long-Term Regional Transmission Cost
Allocation Method(s) and/or a State Agreement Process, as well as a
deadline for communicating such agreement; and (3) provide a forum for
negotiation of a Long-Term Regional Transmission Cost Allocation
Method(s) and/or a State Agreement Process that enables meaningful
participation by Relevant State Entities.
1355. We adopt the NOPR proposal, with modification, to define
Relevant State Entities as any state entity responsible for electric
utility regulation or siting electric transmission facilities within
the state or portion of a state located in the transmission planning
[[Page 49489]]
region, including any state entity as may be designated for that
purpose by the law of such state.\2894\ We modify the definition to add
the word ``electric'' before ``utility regulation'' to make clear that
Relevant State Entities are those state agencies responsible for
electric utility regulation, and not other types of utility regulation.
---------------------------------------------------------------------------
\2894\ See NOPR, 179 FERC ] 61,028 at P 304.
---------------------------------------------------------------------------
1356. Specifically, with respect to the mechanics of the Engagement
Period, we require that transmission providers in each transmission
planning region provide notice, such as on its OASIS page or public
website, of the opportunity for any Relevant State Entity to
participate in, and the starting and end dates of, the Engagement
Period. The notice must include contact information for a single point
of contact in the transmission planning region that the Relevant State
Entities can use to communicate any agreement among Relevant State
Entities on a Long-Term Regional Transmission Cost Allocation Method(s)
and/or a State Agreement Process, as well as a deadline for
communicating such agreement.\2895\ Such deadline must be no earlier
than the end date of the Engagement Period.
---------------------------------------------------------------------------
\2895\ As we discuss above in the Cost Allocation for Long-Term
Regional Transmission Facilities section, Relevant State Entities
must indicate that they have agreed to any State Agreement Process
in order for any such process to be eligible for acceptance by the
Commission in compliance with this final order. Consistent with FPA
section 205, however, transmission providers have the right to not
file a State Agreement Process. See infra Filing Rights Under the
FPA section for a further discussion. See also Atl. City Elec. Co.
v. FERC, 295 F.3d 1, 9 (D.C. Cir. 2002) (finding that the Commission
may not require utility owners to give up statutory rights under FPA
section 205).
---------------------------------------------------------------------------
1357. We require transmission providers in each transmission
planning region to provide a forum for negotiation that enables
meaningful participation by Relevant State Entities during the
Engagement Period, consistent with NARUC's suggestion.\2896\ We require
transmission providers to explain on compliance how they complied with
the requirement to establish and provide notice of an Engagement Period
for Relevant State Entities to negotiate a Long-Term Regional
Transmission Cost Allocation Method(s) and/or State Agreement Process,
as well as how they complied with the requirement to provide a forum
for such negotiation. In response to commenters that argue that their
transmission planning regions already have mechanisms for state
involvement in regional transmission planning and cost allocation
processes,\2897\ we note that Relevant State Entities can choose to use
existing mechanisms for state involvement in regional transmission
planning and cost allocation processes, such as the SPP Regional State
Committee and the Organization of MISO States, to negotiate a Long-Term
Regional Transmission Cost Allocation Method(s) and/or a State
Agreement Process. However, even where Relevant State Entities indicate
to the transmission providers in a transmission planning region that
they will use such existing mechanisms as the forum for their
negotiations, transmission providers must still demonstrate on
compliance that, consistent with the requirements of this final order,
they provided notice of the starting and end dates for the six-month
time period and posted contact information that Relevant State Entities
may use to communicate with transmission providers about their proposed
Long-Term Regional Transmission Cost Allocation Method(s) and/or a
State Agreement Process to which Relevant State Entities have agreed,
as well as a deadline for communicating such agreement.
---------------------------------------------------------------------------
\2896\ NARUC Initial Comments at 44.
\2897\ E.g., MISO Initial Comments at 61; SPP Initial Comments
at 28-30; PJM Initial Comments at 116.
---------------------------------------------------------------------------
1358. As described above, we adopt a six-month time period for the
Engagement Period. While the NOPR did not propose a particular time
period for the Engagement Period, we believe that the six-month time
period that we adopt here balances the need to ensure that Relevant
State Entities have sufficient time to negotiate a Long-Term Regional
Transmission Cost Allocation Method(s) and/or State Agreement Process
if they choose to do so, particularly given the complexity that such
negotiations may involve, with the need to ensure that an extended
Engagement Period does not unduly delay the implementation of the
reforms that we adopt in this final order. We appreciate Alabama
Commission's concerns about establishing a specific time period for
negotiations, but we find that limiting the Engagement Period to six
months is necessary to ensure that transmission providers have
sufficient time to prepare their compliance filings in advance of the
compliance deadlines that we establish in this final order.\2898\
---------------------------------------------------------------------------
\2898\ Alabama Commission Initial Comments at 9.
---------------------------------------------------------------------------
1359. If the Relevant State Entities participating in an Engagement
Period agree on a Long-Term Regional Transmission Cost Allocation
Method(s) and/or State Agreement Process and provide that Method or
Methods and/or State Agreement Process to the transmission providers no
later than the deadline for communicating agreement, which must be no
earlier than the end date of the Engagement Period, the transmission
providers may file the agreed-to Long-Term Regional Transmission Cost
Allocation Method(s) and/or State Agreement Process on compliance. We
note, however, that the ultimate decision as to whether to file a Long-
Term Regional Transmission Cost Allocation Method(s) and/or State
Agreement Process to which Relevant State Entities have agreed will
continue to lie with the transmission providers.
1360. We do not adopt the NOPR proposal that for each state, a
single entity should be designated as the voting or representative
entity. In light of the fact that we now require an Engagement Period,
rather than mandating that transmission providers seek agreement with
Relevant Sate Entities on the relevant cost allocation method or
process, we decline to adopt a requirement that a single entity be
designated for each state as the voting or representative entity. In
addition, we decline to define what constitutes agreement among
Relevant State Entities, how such agreement is reached, and which
Relevant State Entities must reach such agreement during the Engagement
Period. Instead, we leave such matters, including whether to use
existing state processes as a forum for negotiations, as Nebraska
Commission advocates,\2899\ to the Relevant State Entities
participating in the Engagement Period to determine. The requirements
that we establish in the final order are that transmission providers
must demonstrate on compliance that they established and provided
notice of an Engagement Period for Relevant State Entities to negotiate
a Long-Term Regional Transmission Cost Allocation Method(s) and/or
State Agreement Process, as well as that they provided a forum for such
negotiation.
---------------------------------------------------------------------------
\2899\ Nebraska Commission Initial Comments at 10.
---------------------------------------------------------------------------
1361. Likewise, we do not agree with commenters, like Pine Gate,
that the Commission should establish a minimum set of criteria for a
state agreement.\2900\ Instead, we find that the criteria for agreement
are more appropriately determined by the Relevant State Entities
participating in the Engagement Period. Whether agreement should
require a majority,\2901\ a threshold of one-half of the participating
Relevant State Entities,\2902\ or unanimity (Southeast PIOs) \2903\ is
a
[[Page 49490]]
decision for the Relevant State Entities participating in the
Engagement Period. We find that this approach also addresses many of
the issues commenters raised relating to the potential difficulties
associated with mandating agreement on a Long-Term Regional
Transmission Cost Allocation Method(s), including ACEG's concern that
requiring agreement could lead to certain states holding a veto power
over the agreement.\2904\ Moreover, we reiterate that, as discussed in
the Cost Allocation Methods for Long-Term Regional Transmission
Facilities section above, transmission providers must file a Long-Term
Regional Transmission Cost Allocation Method on compliance with this
final order; a State Agreement Process cannot be the sole method filed
for cost allocation for Long-Term Regional Transmission Facilities.
---------------------------------------------------------------------------
\2900\ Pine Gate Initial Comments at 45-46.
\2901\ Acadia Center and CLF Initial Comments at 30; PIOs
Initial Comments at 66-67.
\2902\ Pattern Energy Initial Comments at 19.
\2903\ Southeast PIOs Initial Comments at 56.
\2904\ ACEG Initial Comments at 66.
---------------------------------------------------------------------------
1362. We acknowledge commenters' support of the NOPR proposal to
require transmission providers to seek the agreement of Relevant State
Entities regarding the relevant cost allocation method or process to be
applied to Long-Term Regional Transmission Facilities, based upon the
rationale that states play a critical role in transmission planning,
and that facilitating their engagement in cost allocation may minimize
delays and additional costs that can be associated with associated
transmission siting proceedings.\2905\ We find that requiring an
Engagement Period provides the same opportunity for robust engagement
in the cost allocation process as the NOPR proposal, and thus has the
potential to achieve the same important benefits, but will reduce the
practical challenges associated with requiring transmission providers
to seek the agreement of Relevant State Entities.\2906\
---------------------------------------------------------------------------
\2905\ NOPR, 179 FERC ] 61,028 at P 301 (footnote omitted); see,
e.g., Avangrid Initial Comments at 28; City of New Orleans Council
Initial Comments at 9; SoCal Edison Initial Comments at 3, 13.
\2906\ See, e.g., Minnesota State Entities Initial Comments at 7
(claiming that a requirement to seek agreement could lead to
disputes over the rights and responsibilities of individual states
or state commissions to veto or otherwise hold up needed region-wide
transmission plans).
---------------------------------------------------------------------------
1363. While we agree with commenters regarding the value of an
opportunity for state engagement regarding cost allocation, and
accordingly adopt the Engagement Period, we do not agree that the views
of state regulators regarding the appropriate cost allocation approach
are dispositive.\2907\ Transmission providers retain the ultimate
responsibility for transmission planning, and, as discussed below, they
have FPA section 205 filing rights to propose tariff changes to rates,
which the Commission cannot deprive them of via this final order.\2908\
The Commission has a statutory responsibility to review such filings to
ensure that any proposed cost allocation is just and reasonable and not
unduly discriminatory or preferential. Robust state engagement can
valuably inform a cost allocation approach, but it cannot supplant
these distinct, statutorily defined roles.
---------------------------------------------------------------------------
\2907\ See, e.g., Southern Initial Comments at 9.
\2908\ See, e.g., Atl. City Elec. Co. v. FERC, 295 F.3d at 9
(noting that section 205 of the FPA gives utilities the right to
file rates and terms for services rendered, and finding that the
Commission cannot require that utility owners give up those
statutory rights under FPA section 205); infra Filing Rights Under
the FPA section.
---------------------------------------------------------------------------
1364. We appreciate that certain commenters request to expand or
clarify the NOPR's proposed definition of Relevant State Entities to
include additional entities, or to otherwise allow the participation of
other entities in the Engagement Period. For example, some commenters
request that the definition be expanded to include Native American
Tribes, self-regulated public power utilities, cooperatives, non-
jurisdictional transmission providers, customer interests, state
utility consumer advocates, non-traditional state agencies, and local
regulatory bodies.\2909\ However, we decline to expand participation in
the Engagement Period beyond Relevant State Entities. As discussed in
the NOPR, ``regional transmission facilities face significant
uncertainty and risk of not reaching construction if certain
stakeholders--in particular, a state regulator responsible for
permitting transmission facilities--do not perceive the regional
transmission facilities' value as commensurate with their costs.''
\2910\ The Commission further stated, and we continue to believe, that
``providing state regulators with a formal opportunity to develop a
cost allocation method for [Long-Term Regional Transmission Facilities]
selected through Long-Term Regional Transmission Planning could help
increase stakeholder--and state--support for those facilities, which,
in turn, may increase the likelihood that those facilities are sited
and ultimately developed with fewer costly delays and better ensure
just and reasonable Commission-jurisdictional rates.'' \2911\ For the
same reasons, we also do not find it necessary to allow other
stakeholders to participate in the Engagement Period, as some
commenters advocate.\2912\ In response to Nevada Commission's request
for additional flexibility in the term Relevant State Entity,\2913\ and
NESCOE's request to amend the definition to accommodate individual
transmission planning regions' particular approaches to cost allocation
requirements, we find that the definition of Relevant State Entities,
as amended, recognizes the important role of states while providing
sufficient regional flexibility for effective Engagement Period
participation.\2914\
---------------------------------------------------------------------------
\2909\ American Municipal Power Initial Comments at 5; APPA
Initial Comments at 3, 42-43 (citing 16 U.S.C. 796(7), (15));
California Energy Commission Initial Comments at 3; California
Municipal Utilities Initial Comments at 16-17; Large Public Power
Initial Comments at 41; MISO Coops Initial Comments at 3-4;
Northwest and Intermountain Initial Comments at 18; NRECA Initial
Comments at 56-57; Six Cities Initial Comments at 10.
\2910\ NOPR, 179 FERC ] 61,028 at P 297 (footnote omitted).
\2911\ Id. at P 299.
\2912\ See, e.g., Clean Energy Buyers Initial Comments at 29.
\2913\ Nevada Commission Initial Comments at 13.
\2914\ NESCOE Initial Comments at 57. As discussed below in the
Proposals Relating to the Design and Operation of State Agreement
Process section, we will permit other participants beyond Relevant
State Entities to participate in the State Agreement Process, if
agreed to by Relevant State Entities.
---------------------------------------------------------------------------
1365. We acknowledge SERTP Sponsors' concern that determining which
Relevant State Entities would be appropriate to participate will be a
function of state law,\2915\ and, as Pennsylvania Commission points
out, a state's legislature could have divided utility regulation and
siting authority among different state agencies.\2916\ In response to
these concerns and Duke's clarification request,\2917\ and as we note
above, we provide flexibility on how Relevant State Entities reach
agreement during the Engagement Period and decline to adopt the
requirement that, for each state, a single entity should be designated
as the voting or representative entity. We clarify that there may be
multiple Relevant State Entities for each state, so long as each
Relevant State Entity meets the definition as provided in this final
order. As noted above, the definition of Relevant State Entity provides
sufficient flexibility for participation in the Engagement Period.
---------------------------------------------------------------------------
\2915\ SERTP Sponsors Initial Comments at 28-29.
\2916\ Pennsylvania Commission Initial Comments at 15.
\2917\ Duke Initial Comments at 38-39.
---------------------------------------------------------------------------
1366. We find that the decision to modify the NOPR proposal, which
would have required transmission providers to seek agreement of
Relevant State Entities, to instead require transmission providers to
establish a six-month Engagement Period largely moots several other
reforms proposed in the NOPR. We therefore decline to adopt other
proposed reforms that
[[Page 49491]]
detailed the requirements associated with transmission providers
seeking agreement of Relevant State Entities.
1367. We note that transmission providers' compliance with this
final order is not contingent on Relevant State Entities' participation
in the Engagement Period. Transmission providers' compliance with this
final order is also not contingent on Relevant State Entities reaching
an agreement on a Long-Term Regional Transmission Cost Allocation
Method(s) and/or State Agreement Process. If Relevant State Entities
fail to reach agreement on a Long-Term Regional Transmission Cost
Allocation Method(s) and/or State Agreement Process, transmission
providers must still file one or more Long-Term Regional Transmission
Cost Allocation Methods in compliance with this final order. We
acknowledge commenters' recommendations on action we should take in the
event Relevant State Entities fail to reach an agreement. But we
decline to convene a joint board of affected states if Relevant State
Entities cannot agree, as suggested by PIOs,\2918\ and the Commission
will not establish a Long-Term Regional Transmission Cost Allocation
Method in the event that Relevant State Entities fail to agree, as
proposed by Eversource and Vermont Electric and Vermont Transco.\2919\
Because this final order requires transmission providers to file a
Long-Term Regional Transmission Cost Allocation Method, these
additional steps are not necessary to ensure that there will be a cost
allocation method for Long-Term Regional Transmission Facilities that
are selected as the more efficient or cost-effective regional
transmission solutions to Long-Term Transmission Needs.
---------------------------------------------------------------------------
\2918\ PIOs Initial Comments at 67.
\2919\ Eversource Initial Comments at 30; Vermont Electric and
Vermont Transco Initial Comments at 4.
---------------------------------------------------------------------------
1368. Furthermore, we decline to adopt NARUC's request that the
Commission provide a mechanism for future review of cost allocation
methods for Long-Term Regional Transmission Facilities.\2920\ This
final order requires that transmission providers establish a one-time
Engagement Period for purposes of compliance with this final order;
transmission providers may file subsequent changes to their cost
allocation methods for Long-Term Regional Transmission Facilities
pursuant to their filing rights under FPA section 205, at which point
parties may file comments in support of or protests to such filings. We
note, however, that some RTOs/ISOs have stakeholder processes that
occur prior to making FPA section 205 filings on cost allocation, which
could provide an additional opportunity for stakeholders to present
their views on a proposed cost allocation method for Long-Term Regional
Transmission Facilities. We decline to require future Engagement
Periods beyond the initial Engagement Period but note that transmission
providers may hold future Engagement Periods if they believe such
periods would be beneficial.
---------------------------------------------------------------------------
\2920\ NARUC Initial Comments at 49-50.
---------------------------------------------------------------------------
3. Proposals Relating to the Design and Operation of State Agreement
Processes
a. NOPR Proposal
1369. The Commission preliminarily found that a State Agreement
Process by which one or more Relevant State Entities voluntarily agree
to a cost allocation method for Long-Term Regional Transmission
Facilities (or a portfolio of such Facilities) after they are selected
may be a just and reasonable approach to cost allocation for such
regional transmission facilities and that the State Agreement Process
could apply to all Long-Term Regional Transmission Facilities or only
to a subset thereof.\2921\
---------------------------------------------------------------------------
\2921\ NOPR, 179 FERC ] 61,028 at P 311.
---------------------------------------------------------------------------
1370. The Commission proposed to require that if the Relevant State
Entities agree on a State Agreement Process, then the transmission
providers in each transmission planning region must describe in their
OATTs the process by which Relevant State Entities would reach
voluntary agreement pursuant to that State Agreement Process regarding
the cost allocation for Long-Term Regional Transmission Facilities,
including the timeline for such processes. The Commission noted that,
for example, the transmission providers in each transmission planning
region could specify in their OATTs the procedures by which such
voluntary agreements by the Relevant State Entities may be filed with
the Commission for consideration under FPA section 205. The Commission
proposed to require that such procedures include a process by which
Relevant State Entities would agree to funding contributions and the
mechanism by which such costs would be allocated (e.g., through a pro
forma contract).\2922\
---------------------------------------------------------------------------
\2922\ Id. P 313.
---------------------------------------------------------------------------
b. Comments
i. Support for State Agreement Process
1371. Several commenters generally support the Commission's
proposal to permit transmission providers to submit a State Agreement
Process as a Long-Term Regional Transmission Cost Allocation
Method.\2923\ NARUC supports allowing Relevant State Entities to agree
to using the State Agreement Process to commit their customers to fund
all or a portion of the costs of a Long-Term Regional Transmission
Facility as a means of meeting a transmission planning region's
selection criteria.\2924\
---------------------------------------------------------------------------
\2923\ American Municipal Power Initial Comments at 12; City of
New Orleans Initial Comments at 9-10; Entergy Initial Comments at
34-35; Georgia Commission Initial Comments at 8-9; ISO-NE Initial
Comments at 37; ITC Initial Comments at 28-32; Louisiana Commission
Initial Comments at 33: Mississippi Commission Initial Comments at
6; NARUC Initial Comments at 53-54; NESCOE Initial Comments at 62;
North Carolina Commission and Staff Initial Comments at 15-16; Ohio
Commission Federal Advocate Initial Comments at 12; Pacific
Northwest State Agencies Initial Comments at 27, Pennsylvania
Commission Initial Comments at 12-13; PIOs Initial Comments at 64;
TAPS Initial Comments at 4-5, 24-26; Resale Iowa Initial Comments at
2, 12; Southern Initial Comments at 9; SERTP Sponsors Initial
Comments at 28-29.
\2924\ NARUC Initial Comments at 53-54 (citing NOPR, 179 FERC ]
61,028 at P 252).
---------------------------------------------------------------------------
1372. Mississippi Commission contends that the State Agreement
Process will likely promote transmission construction because authority
over transmission construction and siting rests with the states.\2925\
Mississippi Commission asserts that the State Agreement Process is
particularly suited to transmission facilities that promote state
policies, noting that Long-Term Regional Transmission Planning should
address state laws and utility integrated resource plans that affect
the resource mix, but the cost of the transmission facilities needed to
address those issues must be borne by the states and utilities whose
laws and integrated resource plans require those facilities.\2926\
Likewise, Ohio Commission Federal Advocate asserts that a State
Agreement Process is a just and reasonable way of allocating costs for
public policy projects.\2927\ Relatedly, ELCON states that the
Commission should emphasize that one state's public policy goals cannot
supplant the cost causation principle or be used to impose costs on
customers in states that do not have the same goals.\2928\
---------------------------------------------------------------------------
\2925\ Mississippi Commission Initial Comments at 22.
\2926\ Mississippi Commission Reply Comments at 3, 24 (citing
Alabama Commission Initial Comments at 4; Illinois Commission at 4,
7-8).
\2927\ Ohio Commission Federal Advocate Initial Comments at 12.
\2928\ ELCON Initial Comments at 17-18. Under the cost causation
principle, the cost of transmission facilities must be allocated to
those who benefit from those facilities in a manner that is at least
roughly commensurate with estimated benefits. See S.C. Pub. Serv.
Auth. v. FERC, 762 F.3d at 53 (quoting Order No. 1000, 136 FERC ]
61,051 at P 586); see also ICC v. FERC I, 576 F.3d at 476.
---------------------------------------------------------------------------
[[Page 49492]]
1373. Southern also notes that state support for transmission
projects is crucial as the states retain primary jurisdiction over
transmission siting and certification.\2929\ Southern asserts that
states should generally be allowed to make transmission project
selection and cost allocation decisions pursuant to the State Agreement
Process after the planning is performed and specific costs and benefits
are identified.\2930\ North Carolina Commission and Staff agree that
the Commission should allow states to negotiate a cost allocation
method after a transmission facility has been selected through Long-
Term Regional Transmission Planning.\2931\ Similarly, Pennsylvania
Commission states that having the State Agreement Process occur after
project selection will put planning in the driver's seat, and state
negotiation will be centered around a transmission project already
selected, which will ensure that project planning and selection run
smoothly while not frustrating the fulfillment of a state's need during
the state negotiation process.\2932\
---------------------------------------------------------------------------
\2929\ Southern Initial Comments at 9.
\2930\ Id. at 27.
\2931\ North Carolina Commission and Staff Initial Comments at
15-16.
\2932\ Pennsylvania Commission Initial Comments at 12-13.
---------------------------------------------------------------------------
1374. Massachusetts Attorney General states that, due to the range
and complexity of benefits and the uncertainty associated with using a
long transmission planning horizon, permitting states to diverge from
ex ante cost allocation requirements for particular transmission
projects or portfolios of projects may increase the likelihood that
those facilities are sited and developed with fewer costly delays and
will better ensure just and reasonable rates. Massachusetts Attorney
General states that the potential benefits of the State Agreement
Process outweigh any concerns about free ridership.\2933\ R Street
agrees that the proposal for a State Agreement Process could reduce
cost allocation and siting disputes, but asserts that states lack the
jurisdiction and resources to serve an economic oversight role and thus
that state participation is not a substitute for the Commission's
economic oversight or for competitive mechanisms.\2934\
---------------------------------------------------------------------------
\2933\ Massachusetts Attorney General Initial Comments at 19
(citing NOPR, 179 FERC ] 61,028 at PP 299, 314).
\2934\ R Street Initial Comments at 4, 12.
---------------------------------------------------------------------------
1375. NESCOE supports the proposal that the State Agreement Process
may apply to all, or a subset of, Long-Term Regional Transmission
Facilities. NESCOE contends that, depending on the circumstances,
Relevant State Entities may find it unnecessary to have the State
Agreement Process apply to all such facilities, and having the
flexibility to apply the State Agreement Process to a subset of
facilities is a reasonable approach.\2935\
---------------------------------------------------------------------------
\2935\ NESCOE Initial Comments at 62-63 (citing NOPR, 179 FERC ]
61,028 at P 311).
---------------------------------------------------------------------------
ii. Concerns and Conditions for Support Regarding State Agreement
Process
1376. Some commenters qualified their support for the State
Agreement Process and/or suggest that the Commission impose conditions
upon the process, including those that advocated for flexibility and
deference to existing efforts to incorporate state involvement.\2936\
US DOE, on behalf of its Federal power marketing administrations, notes
that, to the extent that state agreements may involve the participation
of Federal power marketing administrations, the process will need to
accommodate the jurisdictional implications of the parties involved and
that any agreements Federal power marketing administrations execute
must be consistent with their statutory authorities.\2937\
---------------------------------------------------------------------------
\2936\ Supra note 2923.
\2937\ US DOE Initial Comments at 50.
---------------------------------------------------------------------------
1377. Entergy states its understanding that state agreements will
not bind retail commissions in exercising other authorities like siting
and permitting.\2938\ Likewise, Pennsylvania Commission states that any
State Agreement Process cannot serve to waive or diminish the state's
siting authority over transmission facilities.\2939\
---------------------------------------------------------------------------
\2938\ Entergy Initial Comments at 29-30 (citing NOPR, 179 FERC
] 61,028 at PP 302-309, 314).
\2939\ Pennsylvania Commission Initial Comments at 14.
---------------------------------------------------------------------------
1378. Mississippi Commission states that involving state regulators
in cost allocation ensures that one state's policy choices are not
imposed on another state's consumers without their consent and that no
state should be forced to subsidize implementation of another state's
laws and policies.\2940\ Likewise, Avangrid states that one state
should not be required to fund public policies of another state, as
this could derail clean energy efforts and allow states to avoid paying
their fair share.\2941\ NRG supports a role for states on transmission
projects that would not exist but for state public policy.\2942\
Virginia Commission Staff avers that state entities should retain the
right to assume cost responsibility for transmission projects intended
to advance their public policy goals.\2943\
---------------------------------------------------------------------------
\2940\ Mississippi Commission Reply Comments at 2-3.
\2941\ Avangrid Initial Comments at 29.
\2942\ NRG Initial Comments at 6.
\2943\ Virginia Commission Staff Initial Comments at 6.
---------------------------------------------------------------------------
1379. Pennsylvania Commission argues that the terms ex ante and ex
post used in the definitions of the Long-Term Regional Transmission
Cost Allocation Method and State Agreement Process are vague and that
instead, the Commission should include in the definitions that the
Long-Term Regional Transmission Cost Allocation Method and State
Agreement Process are determined either before or after a transmission
facility is selected.\2944\
---------------------------------------------------------------------------
\2944\ Pennsylvania Commission Initial Comments at 14-15.
---------------------------------------------------------------------------
1380. Entergy asserts that the Commission should permit flexibility
as to when a State Agreement Process occurs despite the NOPR's
reference to the State Agreement Process as ``an ex post cost
allocation process'' because in some transmission planning regions, it
may be appropriate for the State Agreement Process to begin before
transmission projects are selected.\2945\ Entergy states that any State
Agreement Process should be finalized before a portfolio is submitted
to the MISO Board of Directors because it will provide certainty to
stakeholders as to how costs will be allocated and ensure that the MISO
Board of Directors understands how the cost allocation for the
portfolio is consistent with the law and capable of withstanding legal
challenges.\2946\ Relatedly, Mississippi Commission argues that Long-
Term Regional Transmission Facilities should not be presented to an
RTO/ISO governing board until states have reached agreement on cost
allocation.\2947\
---------------------------------------------------------------------------
\2945\ Entergy Initial Comments at 34-35.
\2946\ Id. at 35.
\2947\ Mississippi Commission Initial Comments at 25-26.
---------------------------------------------------------------------------
1381. Similarly, MISO asserts that the ex post nature of the State
Agreement Process renders it unsuitable as the sole cost allocation
method for Long-Term Regional Transmission Facilities. As such, MISO
contends, cost allocation should be available only during a defined
time set forth in the OATT, after the approval of the transmission
projects, to avoid delays in the competitive transmission development
process. MISO further states that failure to conclude the State
Agreement Process in that timeframe should result in the transmission
provider reverting to its
[[Page 49493]]
default Long-Term Regional Transmission Cost Allocation Method.
Finally, MISO asks that the Commission clarify that transmission
providers can make changes to their competitive transmission
development process to accommodate the State Agreement Process.\2948\
---------------------------------------------------------------------------
\2948\ MISO Initial Comments at 69.
---------------------------------------------------------------------------
1382. DC and MD Offices of People's Counsel recommend that the
State Agreement Process afford an opportunity for state entities to
participate in transmission project evaluation and selection. They
recommend this approach because of regional grid expansions that
optimize the interconnection of portfolios of resources that likely
result from power supply commitments made in conformity with state
policies, and because state entity participation in cost allocation
after a transmission project has already been selected may foreclose
the consideration of state-specific benefits of grid decarbonization
during project evaluation and selection.\2949\
---------------------------------------------------------------------------
\2949\ DC and MD Offices of People's Counsel Initial Comments at
37-38.
---------------------------------------------------------------------------
1383. Alabama Commission contends that the Commission should
provide for flexibility in the form and substance of any state
agreement. Specifically, Alabama Commission explains that under Alabama
law, it is unclear how the Alabama Commission would enter into such
agreement and that its agreement may instead have to take the form of
an order directed to Alabama Power.\2950\ SERTP Sponsors also state
that the Commission should recognize the importance of flexibility in
the development and structure of state agreements, agreeing that a
state public service commission may not have authority to enter into
binding state agreements. SERTP Sponsors offer that a state agreement
for a state public service commission could be an endorsement of a
voluntary participant funding agreement among its jurisdictional
transmission providers.\2951\ Southeast PIOs state that the applicable
cost allocation method should account for regional preferences and adds
that an ex ante method is likely a non-starter in the Southeast, but
that a State Agreement Process has real potential.\2952\
---------------------------------------------------------------------------
\2950\ Alabama Commission Initial Comments at 10 n.8.
\2951\ SERTP Sponsors Initial Comments at 28-29.
\2952\ Southeast PIOs Reply Comments at 22-23 (citing Dominion
Initial Comments at 50-52; Duke Initial Comments at 35-37; SERTP
Sponsors Initial Comments at 28-29; Southern Initial Comments at 27-
28).
---------------------------------------------------------------------------
1384. Acadia Center and CLF state that voluntary state agreements
relating to offshore wind could result in more efficient and cost-
effective Long-Term Regional Transmission Facilities but request
further clarity on voluntary agreements to assist states in
understanding how these agreements allocate costs of transmission
upgrades necessary for increased interconnection of renewable
projects.\2953\ New England Systems states that the Commission should
clarify that any State Agreement Process cannot increase the costs paid
by a non-consenting transmission customer under an existing cost
allocation method.\2954\ Pennsylvania Commission seeks clarification
that a state that is not a party to a cost allocation agreement
developed through the State Agreement Process cannot be required to pay
for a selected transmission project.\2955\
---------------------------------------------------------------------------
\2953\ Acadia Center and CLF Initial Comments at 32 & n.93.
\2954\ New England Systems Initial Comments at 23.
\2955\ Pennsylvania Commission Initial Comments at 12.
---------------------------------------------------------------------------
1385. Cypress Creek states that the involvement of states in Long-
Term Regional Transmission Planning is important but that a State
Agreement Process should not be required.\2956\ MISO requests that the
State Agreement Process be optional so as not to disrupt current
frameworks of state collaboration or delay transmission
expansion.\2957\ MISO further asserts that the proposed cost allocation
reforms may undermine existing cost allocation methods and that the
Commission should not extend any requirements regarding state
involvement to near-term reliability and economic regional transmission
planning processes, which are beyond the scope of the final
order.\2958\
---------------------------------------------------------------------------
\2956\ Cypress Creek Reply Comments at 14 (citing Clean Energy
Associations Initial Comments at 34).
\2957\ MISO Reply Comments at 19.
\2958\ MISO Initial Comments at 60, 71.
---------------------------------------------------------------------------
1386. In addition, MISO argues that there should be no requirement
for unanimous agreement under the State Agreement Process, particularly
if the decision to adopt it rests with Relevant State Entities.\2959\
MISO states that some flexibility as to what constitutes agreement of
Relevant State Entities may be justified.\2960\ While Interwest
supports increased state engagement, it argues that state entities
should not be authorized to limit regional transmission plans by veto
or by using unjust and unreasonable cost allocation principles that are
subjective or fail to comprehensively consider benefits.\2961\
---------------------------------------------------------------------------
\2959\ Id. at 66-67; MISO Reply Comments at 19.
\2960\ MISO Initial Comments at 66.
\2961\ Interwest Initial Comments at 16.
---------------------------------------------------------------------------
1387. Chemistry Council contends that consultation with affected
states should not give individual states the power to ``hijack'' the
transmission planning process by rejecting necessary investments,
withholding consent, or delaying the decision-making process. Chemistry
Council asserts that the Commission should clarify that in requiring
transmission providers to ``seek agreement'' from states in
transmission project selection, it is not suggesting that individual
states would have a veto in the process or the ability to unduly
influence the timing or outcome of decision-making.\2962\
---------------------------------------------------------------------------
\2962\ Chemistry Council Initial Comments at 7.
---------------------------------------------------------------------------
1388. Evergreen Action encourages the Commission to prohibit one
state or stakeholder from vetoing transmission projects or cost
allocation decisions. Evergreen Action further states that if consensus
is not reached under a State Agreement Process, transmission providers
should not extend the time allotted to reach agreement, because this
would allow individual parties to delay the approval of needed
transmission and remove the time pressure on Relevant State Entities to
reach agreement. Evergreen Action avers that instead transmission
providers should simply explain that they conducted a good-faith effort
to reach agreement.\2963\
---------------------------------------------------------------------------
\2963\ Evergreen Action Initial Comments at 6.
---------------------------------------------------------------------------
1389. SEIA also urges the Commission to limit the opportunity for
any single state to veto a transmission line and to use its backstop
authority under section 216 of the FPA if parties are unable to reach
an agreement and a relevant state authority withholds or denies the
siting permit for the transmission facility.\2964\ US Climate Alliance
agrees that the process should encourage states to engage in good faith
discussions to realize common benefits without over-leveraging a single
state's power over a regional transmission project.\2965\ National Grid
suggests that if states cannot agree within a reasonable period on a
proposed cost allocation method for a specific set of Long-Term
Regional Transmission Facilities, then the transmission providers or
developers building those facilities should be required to file a
proposed cost allocation method for them.\2966\ In contrast, NRG states
that without recourse to an ex ante cost allocation method,
negotiations under the State Agreement Process would be more
productive.\2967\
---------------------------------------------------------------------------
\2964\ SEIA Initial Comments at 25 (citing 16 U.S.C. 824p(b)).
\2965\ US Climate Alliance Initial Comments at 2.
\2966\ National Grid Initial Comments at 25-26.
\2967\ NRG Initial Comments at 20-21.
---------------------------------------------------------------------------
[[Page 49494]]
1390. California Commission is concerned that the NOPR proposal
grants too much deference to transmission providers and will enable
them to exercise veto power over state-negotiated cost allocation
agreements.\2968\ California Municipal Utilities and TANC ask that the
Commission require that local regulatory authorities be included in any
State Agreement Process, stating that the jurisdictional implications
of the NOPR proposal are unclear given that public power entities are
not generally subject to the jurisdiction of their respective state
commissions.\2969\ Mississippi Commission and Northwest and
Intermountain support expanding a State Agreement Process to include
non-jurisdictional utilities.\2970\ California Municipal Utilities
further assert that, if any state body is created to examine
transmission planning issues, it must include public power
entities.\2971\ Because the written comment process is not sufficient
to facilitate a constructive dialogue, California Municipal Utilities
urge the Commission to refrain from adopting any specific proposals
from the NOPR until such a dialogue between states and public power can
occur.\2972\
---------------------------------------------------------------------------
\2968\ California Commission Initial Comments at 51, 54-55
(citing NOPR, 179 FERC ] 61,028 at P 319).
\2969\ California Municipal Utilities Initial Comments at 16;
TANC Initial Comments at 17.
\2970\ Mississippi Commission Reply Comments at 5 (citing MISO
Coops Initial Comments at 3-4); Northwest and Intermountain Initial
Comments at 18.
\2971\ California Municipal Utilities Initial Comments at 4.
\2972\ California Municipal Utilities Reply Comments at 10.
---------------------------------------------------------------------------
1391. Some commenters are concerned about the reliance on voluntary
contributions that may occur under a State Agreement Process. Clean
Energy Associations states that while ex post frameworks that rely on
voluntary contributions from states or interconnection customers may be
useful in some circumstances, they may not appropriately acknowledge
system-wide benefits of high-voltage elements, which under the State
Agreement Process could be treated as benefitting only a single state.
According to Clean Energy Associations, courts have found such an
outcome improper, and this approach is unlikely to yield agreement in
practice.\2973\ Likewise, Cypress Creek asserts that any ex post cost
allocation method should acknowledge wide-spread benefits without
imposing new restrictions.\2974\ AEE contends that the State Agreement
Process, and more broadly the requirement to seek agreement of states
regarding applicable cost allocation methods, should not substitute for
allocating costs to all beneficiaries based on the broad set of
benefits that regional transmission investment can provide. AEE states
that reliance on voluntary state agreement should allow all states to
consider the broad benefits that additional regional transmission
facilities provide and the legal obligation to allocate costs
commensurate with benefits received.\2975\
---------------------------------------------------------------------------
\2973\ Clean Energy Associations Initial Comments at 35 (citing
Old Dominion Elec. Coop. v. FERC, 898 F.3d at 1261).
\2974\ Cypress Creek Reply Comments at 14.
\2975\ AEE Reply Comments at 15-16.
---------------------------------------------------------------------------
1392. DC and MD Offices of People's Counsel suggest that cost
allocation should be based on the NOPR's defined benefits to all
appropriate beneficiaries, with a further cost allocation to states
that opt to submit additional transmission needs. DC and MD Offices of
People's Counsel state that this approach would be more expansive than
the existing State Agreement Approach in PJM because it would allow for
a parallel default allocation of costs to the state entities not opting
in, but narrowed to align with the NOPR-listed benefits, and a second
round of cost allocation after the participating Relevant State
Entities have shared costs aligned with the broader measure of
benefits, which would help avoid the free-rider problem.\2976\
---------------------------------------------------------------------------
\2976\ DC and MD Offices of People's Counsel Initial Comments at
38-39 (citing PJM Interconnection, L.L.C., 179 FERC ] 61,024).
---------------------------------------------------------------------------
1393. Avangrid states that a fair approach to cost allocation under
the State Agreement Process could be payments and benefits based on
tiers, providing the example that if states A and B have public
policies supported by new transmission while state C does not, then
only states A and B should pay the cost of public policy benefits while
all three states should be responsible for the cost associated with
economic and reliability benefits.\2977\ Similarly, PIOs assert that
under the State Agreement Process, costs identified in Long-Term
Regional Transmission Planning should first be allocated to
transmission customers as the primary beneficiaries, and then states
and/or interconnection customers can voluntarily accept cost allocation
for the alternative or expanded transmission projects compared to
projects identified in the regional base case plan.\2978\
---------------------------------------------------------------------------
\2977\ Avangrid Initial Comments at 29-30.
\2978\ PIOs Initial Comments at 68 (citing NOPR, 179 FERC ]
61,028 at PP 75-76).
---------------------------------------------------------------------------
1394. AEE asks that the Commission provide additional guardrails
for the State Agreement Process to ensure that there are not
transmission project delays.\2979\ According to AEE, the Commission
must ensure that excessive reliance on the State Agreement Process does
not exacerbate free-ridership problems where states outside of those
agreements receive benefits from transmission projects developed under
state agreements but are not expected to contribute to the costs.\2980\
---------------------------------------------------------------------------
\2979\ AEE Initial Comments at 33 (citing NOPR, 179 FERC ]
61,028 at PP 311-318).
\2980\ Id.
---------------------------------------------------------------------------
1395. Duke argues that any tariff language memorializing the State
Agreement Process must specify that the transmission provider ``will
not be obligated to accept cost allocation methods proposed by Relevant
State Entities.'' \2981\ Duke also asks that the Commission clarify
that if transmission providers only adopt a State Agreement Process,
and that fails, then transmission providers are free to make an FPA
section 205 filing to implement an ex post cost allocation
method.\2982\ Further, Duke asks that the Commission clarify that the
regulatory text's reference to ``transmission provider'' is ``the
entity with the section 205 rights to initiate rate changes, which
depending upon the applicable governance and OATT structures, may be
the transmission owner, but not the transmission provider.'' \2983\
---------------------------------------------------------------------------
\2981\ Duke Initial Comments at 39-40.
\2982\ Id. at 3.
\2983\ Id. at 40 n.77.
---------------------------------------------------------------------------
1396. Some commenters support requiring state involvement in cost
allocation. For example, New York Commission and NYSERDA state that
state-led cost allocation should be a requirement in any final order
and that cost allocation for public policy-driven transmission projects
should be subject to state review and approval.\2984\ Pacific Northwest
State Agencies support requiring transmission providers to have an ex
post State Agreement Process as an alternative to an ex ante cost
allocation method.\2985\
---------------------------------------------------------------------------
\2984\ New York Commission and NYSERDA Initial Comments at 12,
14.
\2985\ Pacific Northwest State Agencies Initial Comments at 27.
---------------------------------------------------------------------------
iii. Opposition to a State Agreement Process
1397. Some commenters express concern that a State Agreement
Process may not be a just and reasonable approach to cost allocation
for regional transmission facilities.\2986\ R Street contends that
states do not represent all beneficiaries who may be assigned costs
and, as such, cost allocation predicated on state agreement may be
unjust and
[[Page 49495]]
unreasonable. R Street states, however, that a state advisory or
partial approval mechanism could be structured to give state agreement
pivotal influence over cost allocation decisions.\2987\
---------------------------------------------------------------------------
\2986\ APPA Initial Comments at 40, 44; MISO Coops Initial
Comments at 2; R Street Initial Comments at 12.
\2987\ R Street Initial Comments at 12.
---------------------------------------------------------------------------
1398. APPA claims that the proposed State Agreement Process is
unworkable and creates significant uncertainty and potential for
litigation.\2988\ APPA further asserts that providing state regulators
with an exclusive role in determining cost allocation methods will not
likely result in a broad consensus across stakeholders.\2989\ MISO
Coops add that it is unjust and unreasonable, arguing that, because
cooperatives are often not jurisdictional to a state entity, it is
unclear how cooperatives would be represented. Thus, MISO Coops state,
the State Agreement Process would reduce the involvement of
cooperatives in regional transmission planning processes while granting
states authority over entities outside their jurisdiction. MISO Coops
further state that the proposed State Agreement Process is unnecessary
because the current MISO stakeholder process is superior.\2990\ MISO
TOs oppose any provision that would mandate a State Agreement
Process.\2991\
---------------------------------------------------------------------------
\2988\ APPA Initial Comments at 40, 44.
\2989\ Id. at 43.
\2990\ MISO Coops Initial Comments at 2-4.
\2991\ MISO TOs Initial Comments at 5, 46.
---------------------------------------------------------------------------
iv. Requirement To Document State Agreement Process in OATT
1399. Some commenters agree with the NOPR proposal that for any
State Agreement Process, transmission providers in each transmission
planning region must detail in their OATTs the process by which
Relevant State Entities would reach agreement regarding the cost
allocation for Long-Term Regional Transmission Facilities pursuant to
the State Agreement Process, including the timeline for such
processes.\2992\ NESCOE contends that if the State Agreement Process is
chosen by the Relevant State Entities, the details of how the state
entities would agree to funding contributions and the mechanisms by
which the costs would be allocated should be mostly informed by states
and then filed by the transmission provider.\2993\ NESCOE suggests that
the Commission be open to variations in the State Agreement Process as
long as the details of all those variations are filed with the
Commission.\2994\
---------------------------------------------------------------------------
\2992\ Louisiana Commission Initial Comments at 33; NESCOE
Initial Comments at 63; SDG&E Initial Comments at 5; TAPS Initial
Comments at 24.
\2993\ NESCOE Initial Comments at 63.
\2994\ NESCOE Reply Comments at 5.
---------------------------------------------------------------------------
1400. Northwest and Intermountain state that the Commission should
review negotiated cost allocation methods.\2995\ Likewise, APPA argues
that the Commission should require that any state agreement to
voluntarily fund transmission facilities must be filed with the
Commission for approval, in order to afford parties the opportunity to
comment.\2996\
---------------------------------------------------------------------------
\2995\ Northwest and Intermountain Initial Comments at 18-19.
\2996\ APPA Initial Comments at 34-35.
---------------------------------------------------------------------------
1401. Some commenters disagree that the Commission should require
transmission providers in each transmission planning region to detail
such processes in their OATTs. For example, OMS argues that it is
unnecessary for transmission providers to explicitly define such a
process in their OATTs.\2997\ Mississippi Commission argues that the
Commission should clarify that OATT language describing the process by
which states reach agreement should not be prescriptive or limiting
and, instead, should provide only a general discussion of a
process.\2998\
---------------------------------------------------------------------------
\2997\ OMS Initial Comments at 12-13.
\2998\ Mississippi Commission Initial Comments at 27-28.
---------------------------------------------------------------------------
c. Commission Determination
1402. We adopt the NOPR proposal, with modification, to allow, but
not require, transmission providers in each transmission planning
region to adopt a State Agreement Process for allocating the costs of
all, or a subset of, Long-Term Regional Transmission Facilities. We
also modify the definition of State Agreement Process to be a process
by which one or more Relevant State Entities may voluntarily agree to a
cost allocation method for Long-Term Regional Transmission Facilities
(or a portfolio of such Facilities) either before or no later than six
months after the facilities are selected in the regional transmission
plan for purposes of cost allocation. We note that Relevant State
Entities have the option to include the participation of other entities
in a State Agreement Process.
1403. As discussed in more detail below, we also adopt the NOPR
proposal to require transmission providers that choose to file any
State Agreement Process agreed to by Relevant State Entities to
describe the State Agreement Process in proposed tariff provisions in
their OATTs. The tariff provisions must describe key information on how
the State Agreement Process will result in a cost allocation being
filed, including which entities can participate in the State Agreement
Process; what constitutes an agreement on cost allocation in that
process; how agreement is communicated to the transmission providers;
and the circumstances under which, or the information necessary for,
transmission providers to file or to consider filing the agreed cost
allocation method.\2999\
---------------------------------------------------------------------------
\2999\ NOPR, 179 FERC ] 61,028 at P 313.
---------------------------------------------------------------------------
1404. Consistent with the NOPR, we find that a State Agreement
Process can be a just and reasonable approach to allocate costs for
Long-Term Regional Transmission Facilities. We also find that State
Agreement Processes may apply to all Long-Term Regional Transmission
Facilities or only to a subset thereof.\3000\ We believe that allowing
State Agreement Processes will help to address some commenters' request
for a stronger state role in the cost allocation of Long-Term Regional
Transmission Facilities,\3001\ increasing the likelihood that more
efficient or cost-effective Long-Term Regional Transmission Facilities
that are selected will be developed. However, as discussed in Cost
Allocation Methods for Long-Term Regional Transmission Facilities
section above, a State Agreement Process cannot be the sole method
filed for cost allocation for Long-Term Regional Transmission
Facilities; we also require transmission providers to file a Long-Term
Regional Transmission Cost Allocation Method on compliance with this
final order so that if the State Agreement Process on file fails to
result in a Commission-accepted cost allocation method, there will
still be a cost allocation method for Long-Term Regional Transmission
Facilities that are selected as the more efficient or cost-effective
regional transmission solutions to Long-Term Transmission Needs.
---------------------------------------------------------------------------
\3000\ Id. P 311.
\3001\ See, e.g., Mississippi Commission Initial Comments at 22;
Southern Initial Comments at 9.
---------------------------------------------------------------------------
1405. We note that this final order provides significant
flexibility to Relevant State Entities with respect to the design and
implementation of any State Agreement Process. Such flexibility
includes, for example, the opportunity to decide which entities beyond
Relevant State Entities will participate in the State Agreement
Process, the ability to identify the Long-Term Regional Transmission
Facilities to which the State Agreement Process will apply, and how
agreement as to a cost allocation method will be reached.
1406. We further expand these flexibilities by modifying the NOPR
proposal to clarify that a State Agreement Process can occur either
before or no later than six months after
[[Page 49496]]
a Long-Term Regional Transmission Facility (or portfolio of such
Facilities) is selected. We believe that providing flexibility for a
State Agreement Process to occur (and thus for the Relevant State
Entities to agree on a cost allocation method) before Long-Term
Regional Transmission Facilities (or a portfolio of such Facilities)
are selected will increase the likelihood that Regional State Entities
support their selection and future development. We note that this
flexibility with regard to the timing of a State Agreement Process
should accommodate the timing preferences expressed by certain
commenters.\3002\ However, we also require that any State Agreement
Process must be completed, i.e., any resulting cost allocation method
must be filed with the Commission, no later than six months after
selection of the applicable Long-Term Regional Transmission Facility
(or portfolio of such Facilities).\3003\
---------------------------------------------------------------------------
\3002\ See, e.g., Pennsylvania Commission Initial Comments at
12-13; Entergy Initial Comments at 35.
\3003\ We discuss this duration requirement infra at P 1413.
---------------------------------------------------------------------------
1407. As the Commission has previously noted, agreements outside of
the context of Order No. 1000 regional cost allocation methods, such as
PJM's State Agreement Approach, can result in cost allocations that are
just and reasonable.\3004\ We also note that Order No. 1000 allows
market participants to negotiate alternative cost sharing arrangements
voluntarily and separately from the regional cost allocation method or
set of methods, and nothing in this final order would prohibit such
voluntary cost sharing arrangements.\3005\ Moreover, as the Commission
noted in the NOPR, the Commission recently issued a Policy Statement
addressing state efforts to develop transmission facilities through
voluntary agreements to plan and pay for those facilities, recognizing
that such voluntary agreements may allow state-prioritized transmission
facilities to be planned and built more quickly than would comparable
facilities that are through the regional transmission planning
process.\3006\ Further, while we require in this final order that
transmission providers have a Long-Term Regional Transmission Cost
Allocation Method for selected Long-Term Regional Transmission
Facilities, we note that nothing in this final order limits a
transmission provider's ability to propose under FPA section 205 any
other cost allocation methods in addition to the cost allocation method
used to comply with this final order.
---------------------------------------------------------------------------
\3004\ See PJM Interconnection, L.L.C., 142 FERC ] 61,214 at P
142; PJM Interconnection, L.L.C., 179 FERC ] 61,024 at PP 40-43.
\3005\ See Order No. 1000, 136 FERC ] 61,051 at P 561.
\3006\ NOPR, 179 FERC ] 61,028 at P 300 (citing State Voluntary
Agreements to Plan & Pay for Transmission Facilities, 175 FERC ]
61,225 at PP 2, 6).
---------------------------------------------------------------------------
1408. In the NOPR, the Commission noted that it has previously
expressed concern regarding participant funding, which shares some
similarities with State Agreement Processes.\3007\ In Order No. 1000,
for example, the Commission explained that reliance on participant
funding as a regional cost allocation method ``increases the incentive
of any individual beneficiary to defer investment in the hopes that
other beneficiaries will value a transmission project enough to fund
its development'' and would therefore not comply with the Order No.
1000 regional cost allocation principles.\3008\ The Commission declined
to allow transmission providers to file participant funding cost
allocation approaches as their ex ante cost allocation methods for
selected regional transmission facilities.\3009\ We take a similar
approach here: we require transmission providers to include in their
OATTs one or more Long-Term Regional Transmission Cost Allocation
Methods (i.e., their ex ante cost allocation method(s)) that can be
used to allocate the costs of selected Long-Term Regional Transmission
Facilities. As in Order No. 1000, the Long-Term Regional Transmission
Cost Allocation Method cannot be participant funding. We find that
requiring a Long-Term Regional Transmission Cost Allocation Method or
Methods that will apply to any selected Long-Term Regional Transmission
Facility reduces the incentive for project beneficiaries to defer
investment.
---------------------------------------------------------------------------
\3007\ See id. P 316 (citing Order No. 1000, 136 FERC ] 61,051
at P 723).
\3008\ Id. P 316 (quoting Order No. 1000, 136 FERC ] 61,051 at P
723). Under a participant funding approach to cost allocation, the
costs of a transmission facility are allocated only to those
entities that volunteer to bear those costs. Id. P 316 n.519 (citing
Order No. 1000, 136 FERC ] 61,051 at P 486 n.375).
\3009\ See Order No. 1000, 136 FERC ] 61,051 at P 723.
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1409. However, in addition to requiring a Long-Term Regional
Transmission Cost Allocation Method, we also provide flexibility to
Relevant State Entities to agree to a State Agreement Process, which
transmission providers may choose to file as part of their compliance
filings. We conclude that allowing such an approach as an option is
reasonable despite the Commission's previously-stated concerns with
participant funding, because a State Agreement Process is an
established process, agreed to in advance and described in transmission
providers' OATTs, through which Relevant State Entities agree to a cost
allocation method. We find that, for the purposes of Long-Term Regional
Transmission Planning, a State Agreement Process will help to
facilitate agreement and cooperation among Relevant State Entities. We
find that this approach balances the need for the certainty with
respect to cost allocation provided by an ex ante cost allocation
method with the flexibility of allowing for a State Agreement Process-
derived cost allocation method for selected Long-Term Regional
Transmission Facilities (or portfolios of such Facilities). We
emphasize, however, that the Commission will still review any cost
allocation method that results from a State Agreement Process to ensure
that it is just and reasonable and not unduly discriminatory or
preferential, and that it allocates costs in a manner that is at least
roughly commensurate with estimated benefits.
1410. In the context of Long-Term Regional Transmission Planning,
we believe that allowing the use of State Agreement Processes to derive
a cost allocation method for selected Long-Term Regional Transmission
Facilities will provide states with an opportunity to be more involved
in cost allocation for these transmission facilities, leading to an
increased likelihood that such facilities are developed. Specifically,
the engagement of Relevant State Entities in cost allocation
discussions could reduce instances in which a Long-Term Regional
Transmission Facility is selected and has an established ex ante cost
allocation method that applies to it, but ultimately is not developed
because it does not receive a necessary state approval.\3010\ We also
find that a State Agreement Process could provide greater confidence to
Relevant State Entities that customers are receiving benefits in a
manner that is at least roughly commensurate with the costs they are
paying for Long-Term Regional Transmission Facilities.
---------------------------------------------------------------------------
\3010\ NOPR, 179 FERC ] 61,028 at P 314.
---------------------------------------------------------------------------
1411. We acknowledge commenters' concerns that a State Agreement
Process could present free-ridership issues.\3011\ For example, there
could be free-ridership concerns if the Relevant State Entities in
certain states agree to be allocated all of the costs for a particular
Long-Term Regional Transmission Facility but that facility also
benefits other entities in other states that are not similarly
allocated costs under the cost allocation method arrived at through the
State Agreement Process. However, we
[[Page 49497]]
continue to find that allowing a State Agreement Process for Long-Term
Regional Transmission Facilities, where agreed to by the Relevant State
Entities, appropriately balances free-ridership concerns with the
benefit of greater state involvement in determining the cost allocation
method for Long-Term Regional Transmission Facilities and the increased
likelihood that such facilities will be built.\3012\ Additionally,
nothing in this final order changes the requirements for all cost
allocation methods, including those that result from a State Agreement
Process, to allocate costs in a manner that is at least roughly
commensurate with estimated benefits, and we believe that Commission
review to ensure that cost allocation methods meet that standard will
act to prevent free ridership.
---------------------------------------------------------------------------
\3011\ See, e.g., R Street Initial Comments at 12.
\3012\ NOPR, 179 FERC ] 61,028 at P 317.
---------------------------------------------------------------------------
1412. As noted above, there is significant commenter support for a
State Agreement Process, particularly among state entities. In
addition, we believe that many of the concerns expressed about the
State Agreement Process proposal appear to be based on a lack of
sufficient explanation in the NOPR regarding the implications of the
proposal, which we clarify here. Contrary to some comments, we do not
require transmission providers to adopt a State Agreement Process;
rather, as discussed in the Filing Rights Under the FPA section,
transmission providers may choose to file a State Agreement Process for
all, or a subset of, Long-Term Regional Transmission Facilities on
compliance. Also, we neither impose an obligation on a state or states
to agree to a cost allocation method for Long-Term Regional
Transmission Facilities, nor do we create any obligation that
transmission providers file a cost allocation method resulting from a
State Agreement Process, unless the transmission providers had clearly
indicated assent to do so in their OATTs.\3013\ As we note in the
discussion of transmission provider filing rights in the Filing Rights
Under the FPA section below, we believe that the applicable statute and
precedent require us to preserve the right of transmission providers to
file with the Commission their preferred cost allocation method for
Long-Term Regional Transmission Facilities to comply with the
requirements of this final order.
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\3013\ For example, transmission providers may voluntarily agree
as part of a State Agreement Process in their OATTs that
transmission providers shall file any cost allocation method that
meets the requirements of their State Agreement Process, even if
those transmission providers do not agree with that method.
---------------------------------------------------------------------------
1413. However, as noted earlier in this section, we establish a
deadline of no later than six months after selection of a Long-Term
Regional Transmission Facility (or portfolio of such Facilities) by
which transmission providers must file any cost allocation method that
results from a State Agreement Process. We believe that the State
Agreement Process can only be effective if there is a limit on the time
to reach agreement before defaulting to the Long-Term Regional
Transmission Cost Allocation Method that we require transmission
providers include in their OATTs. The lack of such a deadline could
cause delay and increase uncertainty regarding selected Long-Term
Regional Transmission Facilities. In addition, we agree with some
commenters \3014\ that a deadline, bolstered by a default Long-Term
Regional Transmission Cost Allocation Method, may increase the
incentive for Relevant State Entities to reach agreement on cost
allocation for a particular Long-Term Regional Transmission Facility
through a State Agreement Process.
---------------------------------------------------------------------------
\3014\ See Evergreen Action Initial Comments at 6; MISO Initial
Comments at 67-68; National Grid Initial Comments at 25-26.
---------------------------------------------------------------------------
1414. We find that six months is a reasonable period for State
Agreement Process deliberations on a cost allocation method because it
balances the need for adequate time for negotiations with transmission
providers' need for finality in their Long-Term Regional Transmission
Planning. While few commenters directly addressed the time period for
negotiation under a State Agreement Process for a particular Long-Term
Regional Transmission Facility (or portfolio of such Facilities), many
commenters favored this duration for the NOPR proposed reform of a
post-selection time period for states to negotiate an alternate cost
allocation method for selected Long-Term Regional Transmission
Facilities (or portfolios of such Facilities) when an ex ante cost
allocation method would otherwise apply.\3015\
---------------------------------------------------------------------------
\3015\ California Commission Initial Comments at 56; Kentucky
Commission Chair Chandler Initial Comments at 4; Louisiana
Commission Initial Comments at 34-35; NARUC Initial Comments at 52-
53; NRG Initial Comments at 21; Pacific Northwest State Agencies
Initial Comments at 27-28.
---------------------------------------------------------------------------
1415. We clarify that, if the Relevant State Entities indicate to
transmission providers, as part of the required Engagement Period
outlined above, that the Relevant State Entities have agreed to a State
Agreement Process, and the transmission providers decide to include
that State Agreement Process in their final order compliance filings,
then the transmission providers must also detail the State Agreement
Process in proposed tariff provisions to their OATTs. The tariff
provisions must describe how agreement would be reached regarding the
cost allocation method for Long-Term Regional Transmission Facilities
pursuant to the State Agreement Process, which also necessarily
requires that it be clear which entities can participate in the
specific State Agreement Process.\3016\ This requirement is in
furtherance of one of the goals of the final order, which is to allow a
greater role for states in establishing a cost allocation method for
Long-Term Regional Transmission Facilities (or portfolios of such
Facilities).
---------------------------------------------------------------------------
\3016\ NOPR, 179 FERC ] 61,028 at P 313.
---------------------------------------------------------------------------
1416. As noted above, after the required initial Engagement Period,
a State Agreement Process could include other entities beyond Relevant
State Entities, and those entities would need to be enumerated in the
State Agreement Process included in the OATT. Transmission providers
must first specify in their OATTs a description of how such voluntary
agreements by the Relevant State Entities may be shared with
transmission providers, as well as whether the transmission providers
voluntarily agree to undertake an obligation to file the agreed-upon
cost allocation method with the Commission for consideration under FPA
section 205 (in other words, whether the transmission providers
voluntarily waive their FPA section 205 filing rights such that they
commit themselves to file with the Commission any cost allocation
method that results from the State Agreement Process). Their OATT
provisions must, at a minimum, also include the event triggering the
beginning of the State Agreement Process, the duration of the State
Agreement Process (not to exceed six months after selection), and a
description of the Long-Term Regional Transmission Facilities to which
the process applies. Further, the State Agreement Process procedures
outlined in transmission providers' OATTs must set forth the manner in
which a transmission provider would file a section 205 filing to seek
Commission acceptance of a cost allocation method resulting from a
State Agreement Process. We note that Relevant State Entities that
participate in a State Agreement Process may need to provide relevant
information to transmission
[[Page 49498]]
providers to enable them to demonstrate that any cost allocation method
that results from a State Agreement Process is just, reasonable, and
not unduly discriminatory or preferential, and allocates cost in a
manner that is at least roughly commensurate with estimated benefits.
1417. We do not agree with the commenters that recommend against
memorializing and filing cost allocation methods resulting from a State
Agreement Process with the Commission.\3017\ To fulfill the
Commission's statutory obligations, any cost allocation method that
results from a State Agreement Process must be filed for review by the
Commission and determined to be just, reasonable, and not unduly
discriminatory or preferential. In addition, we believe that
transparency regarding such cost allocation methods and the opportunity
for stakeholders, particularly those that will be responsible for
paying the costs of Long-Term Regional Transmission Facilities, to
comment on them are an important safeguard to ensure that costs are
allocated in a manner that is at least roughly commensurate with
estimated benefits.
---------------------------------------------------------------------------
\3017\ Mississippi Commission Initial Comments at 27-28; OMS
Initial Comments at 12-13.
---------------------------------------------------------------------------
1418. We will not specify the level of agreement among Relevant
State Entities or other entities that is necessary before a
transmission provider files a cost allocation method derived from a
State Agreement Process. As a state-led process, we believe that
Relevant State Entities should have the ability to determine this
important facet of their State Agreement Process. To this end, we
decline to require unanimity or a set minimum threshold for agreement
of Relevant State Entities to participate in the State Agreement
Process.
1419. Some commenters request that the Commission clarify whether
and to what extent a cost allocation method that results from a State
Agreement Process can impose costs on entities that do not agree to
that cost allocation method. However, we decline to prejudge any State
Agreement Process or any cost allocation method that may result from a
State Agreement Process. Any cost allocation method for a Long-Term
Regional Transmission Facility (or portfolio of such Facilities) that
results from a State Agreement Process must be filed with the
Commission pursuant to FPA section 205, and the Commission must make a
finding as to whether that cost allocation method is just, reasonable,
and not unduly discriminatory or preferential. And, as noted above, we
reiterate that all cost allocation methods, including those resulting
from a State Agreement Process, must allocate costs in a manner that is
at least roughly commensurate with estimated benefits.\3018\ Parties
are free to raise any concerns about the costs that they may be
allocated under a State Agreement Process-derived cost allocation
method if and when that method is filed with the Commission.\3019\
---------------------------------------------------------------------------
\3018\ See ICC v. FERC I, 576 F.3d at 477; ICC v. FERC III, 756
F.3d at 564.
\3019\ E.g., New England Systems Initial Comments at 23;
Pennsylvania Commission Initial Comments at 12; Mississippi
Commission Reply Comments at 3.
---------------------------------------------------------------------------
1420. MISO asks that the final order make clear that transmission
providers can make necessary changes to the competitive transmission
developer selection process to accommodate the State Agreement
Process.\3020\ We clarify that the Commission will review any proposed
changes to transmission providers' competitive transmission developer
selection processes to accommodate State Agreement Processes as part of
their compliance filings to this final order.
---------------------------------------------------------------------------
\3020\ MISO Initial Comments at 68-70.
---------------------------------------------------------------------------
1421. With respect to California Municipal Utilities' and TANC's
requests that the Commission require that local regulatory authorities
be included in any State Agreement Process, the Mississippi
Commission's statement that it would support expanding the State
Agreement Approach to include non-jurisdictional utilities, we do not
proscribe in this final order that the State Agreement Processes
include other entities beyond Relevant State Entities. However, as
noted above, Relevant State Entities have the option to include the
participation of other entities in a State Agreement Process. Finally,
with respect to US DOE's comments related to the jurisdictional
implications of Federal power marketing administrations participating
in State Agreement Processes, we do not establish any specific
requirements for how State Agreement Processes will be designed. To the
extent that a Federal power marketing administration does participate
in such a process, it may advocate that such process facilitates its
participation in a manner that is consistent with its statutory
authority.\3021\
---------------------------------------------------------------------------
\3021\ US DOE Initial Comments at 50.
---------------------------------------------------------------------------
4. Filing Rights Under the FPA
a. Comments
1422. A number of commenters express concerns that a requirement to
seek agreement from Relevant State Entities regarding a cost allocation
approach could conflict with transmission providers' filing rights
under the FPA.\3022\ For example, AEP contends that in at least one
region where AEP operates, such a requirement would deprive
transmission owners of their exclusive right to file tariffs governing
the rates and terms of their transmission service under section 205 of
the FPA. AEP states that in Atlantic City Electric Company v. FERC, the
D.C. Circuit, held that ``[w]hen FERC attempts to deprive the utilities
of their rights to initiate rate design changes with respect to
services provided by their own assets, FERC has exceeded its
jurisdiction.'' \3023\
---------------------------------------------------------------------------
\3022\ AEP Initial Comments at 6, 36 (citing Atl. City Elec. Co.
v. FERC, 295 F.3d at 9-11 (``[T]his Court, among others, has
stressed that the power to initiate rate changes rests with the
utility and cannot be appropriated by FERC in the absence of a
finding that the existing rate was unlawful.''); Atl. City Elec. Co.
v. FERC, 329 F.3d 856, 858-59 (D.C. Cir. 2003) (per curiam)); MISO
Initial Comments at 63-64 (citing Atl. City Elec. Co. v. FERC, 295
F.3d at 9-11); MISO TOs Initial Comments at 37, 39-40 (citing 16
U.S.C. 824d; Atl. City Elec. Co. v. FERC, 295 F.3d at 9-11; Sw.
Power Pool, Inc., 132 FERC ] 61,042, at P 107 (2010); Mass. Dep't of
Pub. Utils. v. FERC, 729 F.2d 886, 887-88 (1st Cir. 1984)); PPL
Initial Comments at 25 & n.66 (``[T]he Atlantic City case makes
clear that the transmission owners are able to make Section 205
filings regarding cost allocation without additional conditions and
the Commission cannot compel the transmission owners to cede these
rights.'').
\3023\ AEP Initial Comments at 36 (quoting Atl. City Elec. Co.
v. FERC, 329 F.3d at 859); accord MISO Initial Comments at 63; MISO
TOs Initial Comments at 40; PPL Initial Comments at 25 n.66.
---------------------------------------------------------------------------
1423. Similarly, Dominion reminds the Commission that the
transmission provider has FPA section 205 rights, and that those rights
cannot be ceded to the state through this proceeding.\3024\ National
Grid asserts that the FPA gives transmission providers the ability to
make section 205 filings on cost allocation, and that the State
Agreement Process should be based on transmission providers voluntarily
affording a role for states.\3025\
---------------------------------------------------------------------------
\3024\ Dominion Initial Comments at 48-49 (citing Atl. City
Elec. Co. v. FERC, 295 F.3d 1; Atl. City Elec. Co. v. FERC, 329 F.3d
856).
\3025\ National Grid Initial Comments at 25.
---------------------------------------------------------------------------
1424. APPA contends that requiring public utilities to file rate
terms dictated by non-public utility entities raises jurisdictional
issues under the FPA. APPA does not believe it is reasonable to provide
to state regulators exclusive authority over the proposed cost
allocation method in the absence of agreement by relevant stakeholders,
and argues that if the Commission requires public utilities to file
cost allocation methods agreed to by Relevant State Entities, public
power utilities should be considered Relevant State Entities have a
formal voting role in agreeing on
[[Page 49499]]
the cost allocation method(s) for Long-Term Regional Transmission
Facilities.\3026\ Six Cities and Large Public Power argue that the
Commission's proposal is an unlawful delegation of the Commission's
exclusive statutory authority over rates under the FPA.\3027\
---------------------------------------------------------------------------
\3026\ APPA Initial Comments at 42-45.
\3027\ Large Public Power Initial Comments at 37-38 (citing City
of Tacoma v. FERC, 331 F.3d 106, 115 (D.C. Cir. 2002) (finding that
the Commission unlawfully delegated its responsibility to assess
annual charges imposed under the FPA against hydroelectric utilities
licenses to other Federal agencies) (additional citations omitted));
Six Cities Initial Comments at 8-9 (citing 16 U.S.C. 824d(a), 824e;
Nantahala Power & Light Co. v. Thornburg, 476 U.S. 953, 965-66
(1986); EPSA, 577 U.S. at 277).
---------------------------------------------------------------------------
1425. Some commenters seek clarification on the Commission's
proposal. MISO and Vistra request that the Commission clarify that
nothing in the final order should be read to override or diminish the
filing rights held, jointly and/or individually, by the RTOs/ISOs and
their transmission owning members.\3028\ Indicated PJM TOs argue that,
while seeking the agreement of Relevant State Entities is appropriate,
the Commission does not have the authority to require that transmission
providers obtain their agreement.\3029\ Similarly, WIRES states that
the Commission should clarify that transmission providers are only
required to seek agreement of Relevant State Entities and that they are
not required to achieve such agreement.\3030\ Duke asserts that the
Commission should clarify and revise the proposed State Agreement
Process to ensure that it does not conflict with transmission
providers' FPA section 205 rights to initiate rate changes.\3031\
---------------------------------------------------------------------------
\3028\ MISO Initial Comments at 64; Vistra Initial Comments at
29-30.
\3029\ Indicated PJM TOs Initial Comments at 20 (citing Atl.
City Elec. Co. v. FERC, 295 F.3d at 10-11).
\3030\ WIRES Initial Comments at 12 (citing 16 U.S.C. 824d; Atl.
City Elec. Co. v. FERC, 295 F.3d at 9-11; Atl. City Elec. Co. v.
FERC, 329 F.3d at 858-59).
\3031\ Duke Initial Comments at 39 (citing Atl. City Elec. Co.
v. FERC, 329 F.3d at 858-59).
---------------------------------------------------------------------------
1426. PJM States propose that if retail regulators reach an
agreement on cost allocation, transmission providers should be required
to file it for consideration under section 205 of the FPA.\3032\ PJM
States recommend that if the transmission providers in a transmission
planning region prefer a different cost allocation method, they can
file their preferred alternative while also presenting the method
agreed on by the Relevant State Entities.\3033\ PJM States add that
these proposals should be ``balanced'' and explain how the retail
regulators' preferences were considered.\3034\ Similarly, NESCOE states
that in cases of disagreement between state entities and transmission
providers, they would prefer that the transmission providers file a
state-preferred cost allocation method alongside their own preferred
method, arguing that such an approach would respect the FPA section 205
rights that public utilities hold.\3035\ Similarly, New Jersey
Commission recommends that in the event that the transmission provider
disagrees with the approach desired by states, the Commission should
require them to submit the states' approach as well as their own in
their section 205 filing. New Jersey Commission proposes that the
Commission would then decide which OATT filing to accept.\3036\
---------------------------------------------------------------------------
\3032\ PJM States Initial Comments at 10 (citing NOPR, 179 FERC
] 61,028 at P 303).
\3033\ Id. at 10.
\3034\ Id. at 10.
\3035\ NESCOE Reply Comments at 4.
\3036\ New Jersey Commission Initial Comments at 17-18.
---------------------------------------------------------------------------
1427. Entergy contends that the proposal is within the Commission's
authority because the Commission's proposal allows transmission
providers to retain their filing rights consistent with Atlantic City.
Entergy argues that the NOPR proposal does not conflict with Atlantic
City because it would only establish a process where states are
consulted on designing a cost allocation method, and that transmission
providers still must make a cost allocation filing, even if there is no
agreement.\3037\
---------------------------------------------------------------------------
\3037\ Entergy Initial Comments at 31-33 (citing Atl. City Elec.
Co. v. FERC, 295 F.3d at 11).
---------------------------------------------------------------------------
b. Commission Determination
1428. As a threshold matter, we note that the Commission is acting
pursuant to FPA section 206 in this final order. Under FPA section 206,
the Commission has determined that existing regional transmission
planning and cost allocation requirements are unjust, unreasonable,
unduly discriminatory or preferential, and thus has both the authority
and responsibility to establish a just and reasonable replacement rate
consistent with the final order's requirements.\3038\
---------------------------------------------------------------------------
\3038\ 16 U.S.C. 824e(a) (``[T]he Commission shall determine the
just and reasonable . . . practice . . . to be thereafter observed
and in force, and shall fix the same by order.'' (emphasis added)).
---------------------------------------------------------------------------
1429. As to commenters' FPA section 205 arguments, we find that our
directives in this final order regarding the development of a State
Agreement Process and any cost allocation methods to which the Relevant
State Entities agree pursuant to that process do not alter existing FPA
section 205 filing rights.\3039\ Specifically, we clarify that, after
the required Engagement Period, transmission providers in each
transmission planning region will decide what Long-Term Regional
Transmission Cost Allocation Method(s) and any State Agreement Process
to file as part of their compliance filings.\3040\ Therefore,
transmission providers in a transmission planning region could elect to
propose on compliance a Long-Term Regional Transmission Cost Allocation
Method and not file a State Agreement Process or other ex ante cost
allocation method to which Relevant State Entities agreed. In addition,
we do not impose any obligation on transmission providers to file a
cost allocation method for Long-Term Regional Transmission Facilities
with which they disagree, even if such a method were proposed to the
transmission providers pursuant to a Commission-approved State
Agreement Process, unless the transmission providers have clearly
indicated their assent to do so as part of a Commission-approved State
Agreement Process in their OATTs. In the same vein, we decline to
require, as PJM States, NESCOE, and New Jersey Commission suggest, that
transmission providers file two cost allocation methods--the
transmission providers' preferred cost allocation method and the cost
allocation method agreed to by the Relevant State Entities--if the
transmission providers disagree with a proposed cost allocation method
to which the Relevant State Entities agree.\3041\ Entities that oppose
or prefer a different cost allocation method than the transmission
providers' preferred cost allocation method can provide their comments
if and when such cost allocation method is filed with the Commission.
---------------------------------------------------------------------------
\3039\ See Dominion Initial Comments at 48-49 (citing Atl. City
Elec. Co. v. FERC, 295 F.3d 1; Atl. City Elec. Co. v. FERC, 329 F.3d
856).
\3040\ We note that the filing must include a Long-Term Regional
Transmission Cost Allocation Method (i.e., an ex ante cost
allocation method).
\3041\ PJM States Initial Comments at 10; NESCOE Reply Comments
at 4; New Jersey Commission Initial Comments at 17-18.
---------------------------------------------------------------------------
1430. We further clarify that unless voluntarily waived, a
transmission provider retains its FPA section 205 filing rights to
submit an ex ante cost allocation method for Long-Term Regional
Transmission Facilities at any time,\3042\ consistent with any
limitations a transmission provider may have agreed to, for example, as
part of its membership in an RTO/ISO. In response
[[Page 49500]]
to MISO and Vistra,\3043\ we also clarify that nothing in this final
order should be read to override or diminish the filing rights held,
jointly or individually, by RTOs/ISOs and their transmission owning
members.
---------------------------------------------------------------------------
\3042\ See Atl. City Elec. Co. v. FERC, 295 F.3d at 9-11; Atl.
City Elec. Co. v. FERC, 329 F.3d at 858-859.
\3043\ MISO Initial Comments at 64; Vistra Initial Comments at
29-30.
---------------------------------------------------------------------------
1431. In response to commenters arguing that the NOPR proposal to
require transmission providers to seek agreement of Relevant State
Entities regarding the Long-Term Regional Transmission Cost Allocation
Method, State Agreement Process, or combination thereof would interfere
with transmission providers' filing rights under FPA section 205,\3044\
those concerns are moot, as we decline to adopt this NOPR proposal, as
discussed above. We reiterate that transmission providers retain their
right to decide what Long-Term Regional Transmission Cost Allocation
Method(s) and any State Agreement Process to file in compliance with
this final order after the Engagement Period.
---------------------------------------------------------------------------
\3044\ AEP Initial Comments at 36; APPA Initial Comments at 42;
Dominion Initial Comments at 48-49; MISO Initial Comments at 63-64;
MISO TOs Initial Comments at 37, 39-40; MISO TOs Reply Comments at
5-7; PPL Initial Comments at 25 & n.66.
---------------------------------------------------------------------------
5. Time Period and Related Issues in the Long-Term Regional
Transmission Planning Cost Allocation Processes for State-Negotiated
Alternate Cost Allocation Method
a. NOPR Proposal
1432. In the NOPR, the Commission proposed to require transmission
providers to detail in their OATTs a process to provide a state or
states (in multi-state transmission planning regions) with a time
period to negotiate a cost allocation method for a transmission
facility (or portfolio of facilities) selected through Long-Term
Regional Transmission Planning that is different than any ex ante
regional cost allocation method (i.e., Long-Term Regional Transmission
Cost Allocation Method) that would otherwise apply. During this time
period, if a state or all states within the transmission planning
region in which the selected regional transmission facility will be
located unanimously agree on an alternate cost allocation method, the
transmission provider may elect to file that method with the Commission
for consideration under FPA section 205. The Commission explained that
the transmission provider may elect to file an alternate cost
allocation method because doing so increases the likelihood that
relevant stakeholders perceive the cost allocation as fair and that the
needed regional transmission facilities will actually be
constructed.\3045\
---------------------------------------------------------------------------
\3045\ NOPR, 179 FERC ] 61,028 at P 319.
---------------------------------------------------------------------------
1433. If the relevant state or states cannot agree on an alternate
cost allocation method memorialized in writing within the specified
timeframe after a transmission developer's transmission facility is
selected through Long-Term Regional Transmission Planning (e.g., 90
days), the Commission proposed that then the transmission developer
would be entitled to use any ex ante Long-Term Regional Transmission
Cost Allocation Method that would otherwise apply for that Long-Term
Regional Transmission Facility.\3046\
---------------------------------------------------------------------------
\3046\ Id. P 320.
---------------------------------------------------------------------------
1434. In particular, the Commission proposed to require that the
OATT provisions that describe the state-negotiated alternate cost
allocation method include when this time period will occur, what its
duration will be, and an affirmation that any alternate cost allocation
method must be submitted to the Commission for review and approval
under FPA section 205 prior to taking effect. Under this proposal, when
filed, the Commission would evaluate the alternate cost allocation
method to ensure that it is just and reasonable and allocates costs in
a manner that is at least roughly commensurate with estimated benefits.
If the Commission rejects a state-negotiated alternate cost allocation
method, the transmission developer of the Long-Term Regional
Transmission Facility would be entitled to use the applicable ex ante
regional cost allocation method that would have applied to it in the
absence of the proposed alternative cost allocation method.\3047\ The
Commission proposed to prescribe a 90-day time period for a state-
negotiated cost allocation method to be memorialized in writing.\3048\
---------------------------------------------------------------------------
\3047\ Id. P 322.
\3048\ Id. P 323.
---------------------------------------------------------------------------
1435. Finally, the Commission sought comment on whether to
establish a requirement for a time period for state involvement in
regional cost allocation for transmission facilities selected in
existing near-term reliability and economic regional transmission
planning processes.\3049\
---------------------------------------------------------------------------
\3049\ Id. P 324.
---------------------------------------------------------------------------
b. Comments
1436. Several commenters support the Commission's proposal to
require transmission providers to detail in their OATTs a process to
provide a state or states with a time period to negotiate a cost
allocation method for a transmission facility (or portfolio of
facilities) selected through Long-Term Regional Transmission Planning
that is different than any ex ante regional cost allocation method
(i.e., Long-Term Regional Transmission Cost Allocation Method).\3050\
NESCOE, Pennsylvania Commission, and PJM States support a requirement
for transmission providers to detail in their OATT provisions that
describe the state-negotiated cost allocation method.\3051\ Clean
Energy Buyers, Dominion, and PIOs agree that any alternate cost
allocation method must be submitted to the Commission for review and
approval under FPA section 205 prior to taking effect.\3052\
---------------------------------------------------------------------------
\3050\ Entergy Initial Comments at 29-30; Nebraska Commission
Initial Comments at 9; New England for Offshore Wind Initial
Comments at 5; Northwest and Intermountain Initial Comments at 18-
19; NRG Initial Comments at 21; Pacific Northwest State Agencies
Initial Comments at 27-28; PIOs Initial Comments at 69; SEIA Initial
Comments at 24.
\3051\ NESCOE Initial Comments at 71; Pennsylvania Commission
Initial Comments at 16; PJM States Initial Comments at 12-13.
\3052\ Clean Energy Buyers Initial Comments at 29-30; Dominion
Initial Comments at 52; PIOs Initial Comments at 71.
---------------------------------------------------------------------------
1437. PJM and Nebraska Commission support the proposal to require a
time period for state-negotiated alternate cost allocation with
suggested modifications. Nebraska Commission states that a process that
builds consensus is important for contentious issues such as cost
allocation and suggests adoption of a model similar to SPP's Regional
State Committee, which it contends has a proven track record for
achieving consensus among stakeholders.\3053\ PJM recommends that the
Commission provide clear direction as to the circumstances under which
a process for states to negotiate an alternate cost allocation method
would be appropriate. PJM also proposes that states seeking a state-
negotiated alternate cost allocation method should be required to
explain why the ex ante cost allocation method is not appropriate for
the identified transmission facility or facilities.\3054\
---------------------------------------------------------------------------
\3053\ Nebraska Commission Initial Comments at 9.
\3054\ PJM Initial Comments at 117.
---------------------------------------------------------------------------
1438. PJM States disagree, arguing that there is no proposed
requirement that retail regulators show why an ex ante approach is
inappropriate before agreeing to and advocating for an alternate. PJM
States further assert that allowing states to agree on an alternate
cost allocation approach after seeing what transmission projects are
selected may be beneficial since states will have more information on
specific projects.\3055\
---------------------------------------------------------------------------
\3055\ PJM States Reply Comments at 6.
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[[Page 49501]]
1439. Some commenters seek clarification on the NOPR proposal.
Pennsylvania Commission explains that because this negotiation would
occur after transmission facility selection, it is an ex post ``State
Agreement Process.'' As such, Pennsylvania Commission contends, it
could create confusion if the Commission does not clarify that
different rules apply to the 90-day ``renegotiation'' process.\3056\
Similarly, MISO states that it is not clear whether the proposed
requirements are intended as an alternative to the State Agreement
Process or to define how the State Agreement Process would be
implemented.\3057\
---------------------------------------------------------------------------
\3056\ Pennsylvania Commission Initial Comments at 15.
\3057\ MISO Initial Comments at 71.
---------------------------------------------------------------------------
1440. Some commenters oppose a requirement to provide a time period
for a state or states to negotiate a cost allocation method for a
transmission facility (or portfolio of facilities) selected in the
regional transmission plan that is different than any ex ante regional
cost allocation method (i.e., Long-Term Regional Transmission Cost
Allocation Method) that would otherwise apply.\3058\ Dominion and Idaho
Power argue that the Commission should permit regional flexibility as
to whether to adopt such a time period.\3059\ Idaho Power further
contends that the Commission's transmission planning processes are not
the primary barriers to transmission development; instead, Federal
permitting and siting processes and coordination with stakeholders are
greater barriers.\3060\
---------------------------------------------------------------------------
\3058\ Dominion Initial Comments at 51; Idaho Power Initial
Comments at 10-11; PPL Initial Comments at 27.
\3059\ Dominion Initial Comments at 51; Idaho Power Initial
Comments at 10-11.
\3060\ Idaho Power Initial Comments at 11 (noting National
Environmental Policy Act review and siting decisions with the Bureau
of Land Management as examples of Federal permitting and siting
processes).
---------------------------------------------------------------------------
1441. MISO recommends that rather than requiring the specific
process and ex post opportunities for states to negotiate an alternate
cost allocation method, the Commission should identify the opportunity
for state involvement in the development of cost allocation and leave
the details for that involvement to each transmission planning
region.\3061\ Pennsylvania Commission states that it does not view the
time period for state-negotiated alternate cost allocation as a
principal negotiation method for cost allocation and asserts that more
appropriate processes are the proposed State Agreement Process or PJM's
existing State Agreement Approach.\3062\
---------------------------------------------------------------------------
\3061\ MISO Initial Comments at 71.
\3062\ Pennsylvania Commission Initial Comments at 16.
---------------------------------------------------------------------------
1442. Dominion supports allowing but not requiring that ex ante
processes be coupled with an option for states to propose an alternate
method, stating that the process for establishing an alternative cost
allocation method could become cumbersome as the NOPR proposes to
require it to comply with the six Order No. 1000 regional cost
allocation principles.\3063\ Exelon recommends allowing states the
opportunity to propose an alternative cost allocation method to the ex
ante method after transmission project selection, but states that FPA
section 205 rights holders should be able to accept, modify, or reject
the proposed alternative cost allocation method. Exelon claims that
this approach would respect the legal rights of transmission owners,
pointing to PJM's State Agreement Approach as an example.\3064\ NESCOE
urges the Commission to reject Exelon's request that transmission
providers be free to accept or reject cost allocation methods proposed
by state entities.\3065\
---------------------------------------------------------------------------
\3063\ Dominion Initial Comments at 51.
\3064\ Exelon Initial Comments at 26-27.
\3065\ NESCOE Reply Comments at 3-4.
---------------------------------------------------------------------------
i. Permissive Right of Transmission Provider To File Alternate Cost
Allocation Method With the Commission Upon Unanimous State Agreement
1443. NARUC and NESCOE argue that if states unanimously agree on an
alternate cost allocation method, then the transmission provider should
be obligated to file it.\3066\ NARUC states that the transmission
provider may also file the cost allocation method that would otherwise
apply if it concludes that the negotiated cost allocation method does
not comply with the six Order No. 1000 regional cost allocation
principles or is otherwise deficient. NARUC contends that this approach
would not violate the transmission providers' FPA section 205 filing
rights.\3067\ Similarly, NESCOE asserts that the Commission should
allow the transmission provider to file its preferred approach, but
also require that the transmission provider file the state-negotiated
alternate cost allocation method, an approach that could be modeled
after existing provisions in NYISO and SPP.\3068\
---------------------------------------------------------------------------
\3066\ NARUC Initial Comments at 53; NESCOE Initial Comments at
68.
\3067\ NARUC Initial Comments at 53.
\3068\ NESCOE Initial Comments at 68-70.
---------------------------------------------------------------------------
1444. NESCOE also requests that the Commission clarify whether
unanimity means that each opting-in state has agreed to fund the Long-
Term Regional Transmission Facility or that all the states in the
transmission planning region have agreed that a subset of states will
fund the Long-Term Regional Transmission Facility.\3069\ NESCOE further
requests that the Commission clarify how it intends to reconcile the
unanimous agreement requirement in this proposal with the other NOPR
proposal that gives states the ability to choose the definition of
state agreement for purposes of a cost allocation method and where the
NOPR expressed a willingness to abide by the bylaws of an individual
regional state committee, which may not define agreement as full
unanimity.\3070\
---------------------------------------------------------------------------
\3069\ Id. at 10, 67-68.
\3070\ Id. at 68 (citing NOPR, 179 FERC ] 61,028 at P 306 &
n.512).
---------------------------------------------------------------------------
1445. Indiana Commission expresses concern that the requirement to
obtain unanimous state approval regarding an ex post cost allocation
process might prove unworkable. Indiana Commission argues that it may
be unrealistic to expect that states can reach unanimity on something
as contentious as cost allocation. Moreover, Indiana Commission is
concerned that states may use the requirement for unanimous agreement
to leverage their vote and to gain ground in other areas of
contention.\3071\
---------------------------------------------------------------------------
\3071\ Indiana Commission Initial Comments at 5.
---------------------------------------------------------------------------
1446. PIOs seek clarification on the intent behind the NOPR
language that ``the public utility transmission provider may elect to
file [a state-negotiated alternate cost allocation method] with the
Commission for consideration under FPA section 205.'' \3072\ Similarly,
Pennsylvania Commission and PJM States request clarification regarding
whether transmission providers could choose not to file an alternative
cost allocation method to which the states in a transmission planning
region have unanimously agreed.\3073\ Pennsylvania Commission asserts
that it sees no reason why a transmission provider should be able to
override the unanimous agreement of affected states.\3074\
---------------------------------------------------------------------------
\3072\ PIOs Initial Comments at 71 (citing NOPR, 179 FERC ]
61,028 at P 319).
\3073\ Pennsylvania Commission Initial Comments at 16-17; PJM
States Reply Comments at 6.
\3074\ Pennsylvania Commission Initial Comments at 17.
---------------------------------------------------------------------------
1447. In addition, PJM States recommend that to address the
inability for states to voice their cost allocation concerns, the
Commission should
[[Page 49502]]
consider how it can afford retail regulators greater participation
status in the FPA section 205 filing process.\3075\ Further, PJM States
note that other regional states committees have varying processes,
including the ability to request that a transmission provider file a
cost allocation method on their behalf.\3076\
---------------------------------------------------------------------------
\3075\ PJM States Reply Comments at 6-7.
\3076\ Id. at 7.
---------------------------------------------------------------------------
ii. Duration for the Time Period for State-Negotiated Cost Allocation
1448. A few commenters agree with the Commission's proposal to
require a 90-day time period for a state-negotiated cost allocation
method to be memorialized in writing.\3077\ For example, New England
for Offshore Wind states that it is essential that deadlines are
imposed to prevent delays caused by disagreements over cost
allocation.\3078\ PIOs assert that the 90-day time period should begin
when the transmission project or portfolio of projects is
selected.\3079\
---------------------------------------------------------------------------
\3077\ New England for Offshore Wind Initial Comments at 5;
Northwest and Intermountain Initial Comments at 18; PIOs Initial
Comments at 69; SEIA Initial Comments at 24.
\3078\ New England for Offshore Wind Initial Comments at 5.
\3079\ PIOs Initial Comments at 70.
---------------------------------------------------------------------------
1449. Many commenters, however, argue that the 90-day time period
is too short. For example, NARUC, National Grid, and Southern contend
that 90 days may be insufficient time for the states in large, multi-
state transmission planning regions to negotiate a cost allocation
method.\3080\ Similarly, NRG argues that the Commission might consider
alternative timelines for multi-state collaboration versus where there
is a single state entity responsible for the cost allocation.\3081\ US
Chamber of Commerce contends that the 90-day timeline for state-
negotiated cost allocation agreements is unreasonably tight and may
undermine the potential for agreement.\3082\
---------------------------------------------------------------------------
\3080\ NARUC Initial Comments at 52-53; National Grid Initial
Comments at 24-25; Southern Initial Comments at 7-8.
\3081\ NRG Initial Comments at 21.
\3082\ US Chamber of Commerce Initial Comments at 10.
---------------------------------------------------------------------------
1450. Several commenters, including state commissions, propose
longer time periods. For example, California Commission, Kentucky
Commission Chair Chandler, Louisiana Commission, NARUC, NRG, and
Pacific Northwest State Agencies propose at least six months (180 days)
as a more appropriate time period for state negotiation.\3083\
California Commission and Louisiana Commission request that states
should be provided with the opportunity to request extensions if they
fail to agree on a cost allocation method after six months (180
days).\3084\ OMS recommends that the Commission establish periodic
reporting requirements for transmission providers during the 90-day
period with an option to extend the deliberations for good cause.\3085\
---------------------------------------------------------------------------
\3083\ California Commission Initial Comments at 56; Kentucky
Commission Chair Chandler Initial Comments at 4; Louisiana
Commission Initial Comments at 34-35; NARUC Initial Comments at 52-
53; NRG Initial Comments at 21; Pacific Northwest State Agencies
Initial Comments at 27-28.
\3084\ California Commission Initial Comments at 56; Louisiana
Commission Initial Comments at 35.
\3085\ OMS Initial Comments at 13.
---------------------------------------------------------------------------
1451. Several other commenters contend that it should be left to
the transmission planning regions, with input from states, to determine
the appropriate time period.\3086\ For example, Dominion states that
the Commission should not dictate any particular timetable and should
instead evaluate proposals on a case-by-case basis.\3087\ Similarly,
Nevada Commission proposes that the Commission require relevant state
agencies to be involved in the process as early as possible, but to
provide no less than 120 days to allow for appropriate notice and
review of any state-negotiated agreement.\3088\ Exelon, Indiana
Commission, and SERTP Sponsors recommend allowing flexibility in
determining the appropriate time period to reflect regional
differences.\3089\ Idaho Power agrees but cautions that any process
should not extend the length of transmission planning processes or
development.\3090\ Pennsylvania Commission also supports flexibility in
determining the appropriate time period given that this process is new
and there is little knowledge and experience with respect to how it
will function in practice.\3091\
---------------------------------------------------------------------------
\3086\ Dominion Initial Comments at 51-52; Exelon Initial
Comments at 28-29; Indiana Commission Initial Comments at 5-6;
National Grid Initial Comments at 24-25; NESCOE Initial Comments at
71; Pennsylvania Commission Initial Comments at 16; PJM States
Initial Comments at 12-13; SERTP Sponsors Initial Comments at 15.
\3087\ Dominion Initial Comments at 51-52.
\3088\ Nevada Commission Initial Comments at 13-14.
\3089\ Exelon Initial Comments at 28-29; Indiana Commission
Initial Comments at 5-6; SERTP Sponsors Initial Comments at 15.
\3090\ Idaho Power Initial Comments at 10-11.
\3091\ Pennsylvania Commission Initial Comments at 16.
---------------------------------------------------------------------------
1452. NESCOE and PJM States assert that NYISO's process referenced
by the Commission can last longer than the 90-day time period for
state-negotiated cost allocation proposed in the NOPR.\3092\ Further,
NESCOE emphasizes that the NYISO process involves only one state
entity, whereas other transmission planning regions have multiple
states. Thus, NESCOE and PJM States argue, the Commission should allow
transmission planning regions to determine what time period is
appropriate.\3093\
---------------------------------------------------------------------------
\3092\ NESCOE Initial Comments at 70-71 (citing NOPR, 179 FERC ]
61,028 at P 323); PJM States Initial Comments at 12-13 (citing N.Y.
Indep. Sys. Operator, Inc., 151 FERC ] 61,040, at PP 119-121
(2015)).
\3093\ NESCOE Initial Comments at 71; PJM States Initial
Comments at 12-13.
---------------------------------------------------------------------------
1453. A few other commenters contend that state negotiation on an
alternate cost allocation method should not be limited by any time
period. For example, PPL asserts that limiting the timeframe merely
lowers the chance of state agreement, and thus the prospects for the
underlying transmission project to be constructed.\3094\ Southern
states that the Commission should allow transmission planning regions
to develop a process that has state support.\3095\ Similarly, Xcel
contends that transmission planning regions should have as much time as
needed to negotiate and identify cost allocation methods.\3096\
---------------------------------------------------------------------------
\3094\ PPL Initial Comments at 27.
\3095\ Southern Initial Comments at 7-8.
\3096\ Xcel Initial Comments at 11-12.
---------------------------------------------------------------------------
iii. Other Issues
1454. NESCOE, Northwest and Intermountain, PJM, and SEIA agree with
the proposal that if states cannot unanimously agree on an alternate
cost allocation method within the specified timeframe, then the
transmission developer would be entitled to use the cost allocation
method that would otherwise apply for that Long-Term Regional
Transmission Facility.\3097\ In contrast, NRG recommends that in the
case where states do not agree, the Commission could either require the
transmission provider to make a filing or subject rival state filings
to ``jump ball'' treatment. NRG contends that either of these
approaches would encourage comity and resolution of states'
differences.\3098\
---------------------------------------------------------------------------
\3097\ NESCOE Initial Comments at 70; Northwest and
Intermountain Initial Comments at 19; PJM Initial Comments at 117-
118; SEIA Initial Comments at 24.
\3098\ NRG Initial Comments at 21.
---------------------------------------------------------------------------
1455. MISO and PPL oppose establishing a requirement for a time
period for state involvement in regional cost allocation for
transmission facilities selected in existing near-term reliability and
economic regional transmission planning processes. MISO states that
[[Page 49503]]
there is no evidence in the record of this proceeding to support
extending the state involvement proposed in the NOPR to existing near-
term transmission planning processes.\3099\ PPL argues that departures
from an ex ante cost allocation method would lead to uncertainty,
delay, and costly litigation.\3100\
---------------------------------------------------------------------------
\3099\ MISO Initial Comments at 71.
\3100\ PPL Initial Comments at 27-28.
---------------------------------------------------------------------------
c. Commission Determination
1456. We decline to adopt the NOPR proposal to require transmission
providers to provide a time period after selection of Long-Term
Regional Transmission Facilities for states to negotiate an alternate
cost allocation that is different than any ex ante regional cost
allocation method that would otherwise apply. We find that requiring a
time period after selection for states to negotiate an alternate ex
post cost allocation method is largely duplicative given our decision
above to allow the use of a State Agreement Process before or after the
selection of a Long-Term Regional Transmission Facility (or a portfolio
of such Facilities). Furthermore, having two separate processes that
serve similar functions could add unnecessary complexity and create
confusion in the cost allocation process.\3101\ Relevant State Entities
will have an opportunity to provide input on and to potentially agree
to a Long-Term Regional Transmission Cost Allocation Method(s) and/or a
State Agreement Process as part of the Engagement Period that we
require transmission providers to establish. We are also concerned that
the burden associated with the NOPR proposal would have been
significant, as it would have created a requirement to allow for such
negotiations for all Long-Term Regional Transmission Facilities.
---------------------------------------------------------------------------
\3101\ See, e.g., MISO Initial Comments at 71 (seeking
clarification as to whether the proposed time period for states to
negotiate cost allocation is an alternative to the State Agreement
Process); Pennsylvania Commission Initial Comments at 16 (stating
that it does not view the proposed time period as the principal
method for negotiating cost allocation and that the more appropriate
process is the proposed State Agreement Process).
---------------------------------------------------------------------------
1457. Because we are declining to require that transmission
providers establish a time period after selection of Long-Term Regional
Transmission Facilities to allow states to negotiate an alternate ex
post cost allocation method, we need not address the comments on the
duration of such a time period and the requests for clarification by
MISO, Pennsylvania Commission, PIOs, and PJM States.\3102\
---------------------------------------------------------------------------
\3102\ MISO Initial Comments at 71; Pennsylvania Commission
Initial Comments at 15; PIOs Initial Comments at 71 (citing NOPR,
179 FERC ] 61,028 at P 319); PJM States Reply Comments at 6.
---------------------------------------------------------------------------
B. Long-Term Regional Transmission Facility Cost Allocation Compliance
With the Existing Six Order No. 1000 Regional Cost Allocation
Principles
1. NOPR Proposal
1458. The Commission proposed to require that the Long-Term
Regional Transmission Cost Allocation Method and any cost allocation
method resulting from the State Agreement Process for Long-Term
Regional Transmission Facilities comply with the existing six Order No.
1000 regional cost allocation principles.\3103\ The six regional
transmission cost allocation principles adopted in Order No. 1000 are:
(1) the costs of selected transmission facilities must be allocated to
those within the transmission planning region that benefit from those
facilities in a manner that is at least roughly commensurate with
estimated benefits; (2) those that receive no benefit from transmission
facilities, either at present or in a likely future scenario, must not
be involuntarily allocated any of the costs of those transmission
facilities; (3) a benefit to cost threshold ratio, if adopted, cannot
exceed 1.25 to 1; (4) costs must be allocated solely within the
transmission planning region unless another entity outside the region
voluntarily assumes a portion of those costs; (5) the method for
determining benefits and identifying beneficiaries must be transparent;
and (6) there may be different regional cost allocation methods for
different types of transmission facilities, such as those needed for
reliability, congestion relief, or to achieve Public Policy
Requirements.\3104\
---------------------------------------------------------------------------
\3103\ NOPR, 179 FERC ] 61,028 at P 302.
\3104\ Order No. 1000, 136 FERC ] 61,051 at PP 622, 637, 646,
657, 668, 685.
---------------------------------------------------------------------------
2. Comments
a. General Proposal
1459. Some commenters agree with the Commission's proposal that any
Long-Term Regional Transmission Cost Allocation Method and any cost
allocation method resulting from the State Agreement Process for Long-
Term Regional Transmission Facilities must comply with the existing six
Order No. 1000 regional cost allocation principles.\3105\ APPA requests
that the Commission clarify that it is not requiring changes to
existing Commission-approved Order No. 1000 regional cost allocation
principles.\3106\
---------------------------------------------------------------------------
\3105\ APPA Initial Comments at 40; Dominion Initial Comments at
45; Kentucky Commission Chair Chandler Initial Comments at 3; NESCOE
Initial Comments at 56; NRECA Initial Comments at 56; Ohio Consumers
Initial Comments at 12-13.
\3106\ APPA Initial Comments at 5.
---------------------------------------------------------------------------
1460. New Jersey Commission supports requiring that any negotiated
cost allocation method, whether ex ante or ex post, comply with the
Order No. 1000 regional cost allocation principles, except for
Principle 4.\3107\ New Jersey Commission opines that requiring that
cost allocation methods be consistent with the beneficiary-pays
principle is particularly necessary in a State Agreement Process to
avoid potential free ridership.\3108\
---------------------------------------------------------------------------
\3107\ New Jersey Commission Initial Comments at 18 (citing New
Jersey Commission ANOPR Comments at 7-8 (explaining why it opposes
Principle 4's policy of allowing beneficiaries in other transmission
planning regions to evade all cost allocation for transmission
projects that provide them with substantial benefits)).
\3108\ Id.
---------------------------------------------------------------------------
1461. Industrial Customers argue that, regardless of the cost
allocation method that is chosen, the Commission should explicitly
state that the cost causation principle must apply, as compliance with
Order No. 1000 may not ensure compliance with cost causation principles
on its own.\3109\ Large Public Power argues that the Commission must
hew closely to the first two principles governing cost allocation
articulated in Order No. 1000: (1) that costs must be allocated in a
way that is roughly commensurate with benefits; and (2) that there will
be no involuntary allocation of costs to non-beneficiaries.\3110\ Pine
Gate asserts that transmission providers must be required to propose
cost allocation methods that comport with the well-established
``roughly commensurate'' principle.\3111\ City of New Orleans Council
and Ohio Commission Federal Advocate state that cost allocation must
adhere to cost causation and beneficiary-pays principles.\3112\
---------------------------------------------------------------------------
\3109\ Industrial Customers Initial Comments at 23-24.
\3110\ Large Public Power Initial Comments at 29.
\3111\ Pine Gate Initial Comments at 42-44.
\3112\ City of New Orleans Council Initial Comments at 10; Ohio
Commission Federal Advocate Initial Comments at 14.
---------------------------------------------------------------------------
1462. OMS states that it developed its own principles through a
committee of regulators focused on cost allocation for long-range
transmission projects in response to the NOPR, which include: (1) costs
of new transmission projects should be allocated to cost causers and
beneficiaries in a manner roughly commensurate with the costs caused
and benefits of those projects; (2) cost
[[Page 49504]]
allocation should be as granular and accurate as possible such that
benefit-cost analysis uses metrics that are quantifiable, capable of
replication, non-duplicative, and forward-looking; (3) costs should not
be allocated to parties that receive negligible or negative benefits;
and (4) generators and load each can be considered cost causers,
beneficiaries, or both and should be allocated costs accordingly.\3113\
Louisiana Commission supports OMS' position on benefit metrics as
articulated in OMS' second principle.\3114\ OMS highlights that
regional flexibility must be preserved, pointing to MISO's Targeted
Market Efficiency Projects process as an example of a process that did
not strictly comply with Order No. 1000 but was effective and widely
supported.\3115\
---------------------------------------------------------------------------
\3113\ OMS Initial Comments at 12.
\3114\ Louisiana Commission Reply Comments at 10.
\3115\ OMS Initial Comments at 13.
---------------------------------------------------------------------------
1463. Ohio Consumers argue that the Commission should espouse three
fundamental principles when considering the benefits and cost
allocations associated with any Long-Term Regional Transmission
Facilities: (1) costs should be allocated to those who caused the costs
to be incurred; (2) subsidies are bad for competitive markets, because
they result in noncompetitive outcomes and inaccurate price signals;
and (3) consumers should not be charged until transmission projects are
found to be used and useful.\3116\ Also, Ohio Consumers assert, cost
allocations to consumers should adhere to the Commission's current
ratemaking standards in PJM.\3117\
---------------------------------------------------------------------------
\3116\ Ohio Consumers Initial Comments at 6-7, 12-14.
\3117\ Id. at 1.
---------------------------------------------------------------------------
1464. PIOs assert that the Commission should require that
transmission providers demonstrate on compliance that the cost
allocation method complies with the beneficiary-pays principle by
considering all quantifiable benefits.\3118\ ELCON states that cost
allocation proposals must comply with the cost causation principle ``by
comparing the costs assessed against a party to the burdens imposed or
benefits drawn by that party.'' ELCON remains concerned that, in an
effort to reach public policy goals, costs will be socialized among all
consumers without consideration of the cost causers, and states that
cost allocation must evaluate the drivers of the specific transmission
need and the party that caused the need for the additional
transmission.\3119\ Utah Division of Public Utilities asks that when
states or other stakeholders disagree on the cost allocation method due
to differing renewable goals, the Long-Term Regional Transmission Cost
Allocation Method be required to use cost causation principles to
determine what portion of the proposed transmission projects are due to
state policies.\3120\
---------------------------------------------------------------------------
\3118\ PIOs Initial Comments at 68.
\3119\ ELCON Initial Comments at 15.
\3120\ Utah Division of Public Utilities Initial Comments at 9-
10.
---------------------------------------------------------------------------
1465. West Virginia Commission states that it supports retention of
the cost-causation principles in Order No. 1000, noting that the Order
No. 1000 cost allocation principles are grounded in the beneficiary-
pays principle that the costs of transmission facilities should be
allocated commensurate with the benefits of those facilities. However,
West Virginia Commission contends that the beneficiary-pays principle
cannot and should not be applied on a presumptive regional basis when
new transmission is identified as needed to accommodate one or more
states' public policy decisions.\3121\ West Virginia Commission states
that longstanding legal precedent on cost causation and ratemaking
principles require that rates remain just and reasonable, that
customers pay for transmission upgrades based upon their roughly
commensurate benefits, and that new generators, or the willing and
voluntary benefactors of new generators, pay the costs for the
interconnection-related network upgrades if such upgrades would not be
needed but for the new generators.\3122\ West Virginia Commission
contends that to adopt a cost allocation that requires any non-
volunteering state to pay costs caused by another state's public
policies would depart from years of Commission precedent and would be
unjust and unreasonable.\3123\
---------------------------------------------------------------------------
\3121\ West Virginia Commission Reply Comments at 3; West
Virginia Commission Supplemental Comments at 3-4.
\3122\ West Virginia Commission Reply Comments at 6 (citing K N
Energy, Inc. v. FERC, 968 F.2d 1295, 1300 (D.C. Cir. 1992); ICC v.
FERC I, 576 F.3d at 477; ISO New England, Inc., 115 FERC ] 61,145,
at P 13 (2006), aff'd, TransCanada Power Mktg. Ltd. v. FERC, 811
F.3d 1 (D.C. Cir. 2015); El Paso Elec. Co. v. FERC, 832 F.3d 495,
499-500 & n.10 (5th Cir. 2016); Midcontinent Indep. Sys. Operator,
Inc., 159 FERC ] 63,016, at P 138 (2017), aff'd, 164 FERC ] 61,194
(2018); Order No. 1000, 136 FERC ] 61,051 at P 622); West Virginia
Commission Supplemental Comments at 5-6.
\3123\ West Virginia Commission Reply Comments at 6-7.
---------------------------------------------------------------------------
1466. Vermont Electric and Vermont Transco encourage the Commission
to ensure that any cost allocation approach ensures that the benefits
of transmission facilities are roughly commensurate with the costs
thereof for both small rural states and larger, more populated states.
Vermont Electric and Vermont Transco argue that the final order should
reflect equitable principles in accordance with which the significant
investments made by Vermont prior to the issuance of the final order
are taken into account in cost allocation processes.\3124\ MISO states
that the final order should not preclude applying different cost
allocation methods to transmission projects of the same type, noting
that Order No. 2000 contemplated ``the potential for different cost
allocation methodologies'' as RTO/ISO footprints grew.\3125\
---------------------------------------------------------------------------
\3124\ Vermont Electric and Vermont Transco Initial Comments at
3-4.
\3125\ MISO Reply Comments at 17-19.
---------------------------------------------------------------------------
b. Comments Specific to a State Agreement Process
1467. Certain commenters discuss the interaction between the Order
No. 1000 regional cost allocation principles and any cost allocation
methods resulting from the State Agreement Process. Pennsylvania
Commission supports the proposed requirement while also contending that
the Commission should defer to unanimous agreement by affected
states.\3126\ Avangrid argues that the Commission should relax this
requirement and defer to the balance achieved via state
agreement.\3127\ Mississippi Commission argues that the proposed
requirement is unnecessary because the State Agreement Process will
result in voluntary assumption of costs.\3128\ Likewise, PacifiCorp and
NV Energy argue that the Order No. 1000 regional cost allocation
principles should not apply to the State Agreement Process because
there will be no involuntary cost allocation given that states have
already agreed. They further contend that beneficiary analyses and
minimum cost-benefit ratios will foreclose state-favored cost
allocation solutions.\3129\ PacifiCorp and NV Energy argue that
agreeing to cost allocation will be a difficult task for states, and
the Commission should not further dictate the type of agreement.\3130\
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\3126\ Pennsylvania Commission Initial Comments at 13.
\3127\ Avangrid Initial Comments at 30.
\3128\ Mississippi Commission Initial Comments at 25.
\3129\ PacifiCorp and NV Energy Initial Comments at 17.
\3130\ Id.
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1468. PJM States ask the Commission not to preclude or limit the
availability of the PJM State Agreement Approach, which they assert is
not required to comply with the Order No. 1000
[[Page 49505]]
regional cost allocation principles.\3131\ Similarly, Exelon notes that
the Commission has indicated that voluntary state cost allocation
agreements need not comply with Order No. 1000.\3132\ Therefore, Exelon
asks the Commission to clarify that the proposed State Agreement
Process is supplementary to any previously accepted provisions for
state agreement-based cost allocation.\3133\
---------------------------------------------------------------------------
\3131\ PJM States Initial Comments at 11-12 (citing PJM
Interconnection, L.L.C., 142 FERC ] 61,214 at P 142).
\3132\ Exelon Initial Comments at 27-28 (citing State Voluntary
Agreements to Plan & Pay for Transmission Facilities, 175 FERC ]
61,225 at P 4).
\3133\ Exelon Initial Comments at 27-28 (citing PJM
Interconnection, L.L.C., 142 FERC ] 61,214).
---------------------------------------------------------------------------
3. Commission Determination
1469. We adopt the NOPR proposal, with modification, to require
Long-Term Regional Transmission Cost Allocation Methods to comply with
five of the six existing Order No. 1000 regional cost allocation
principles. Specifically, we require transmission providers in each
transmission planning region to demonstrate on compliance with this
final order that any Long-Term Regional Transmission Cost Allocation
Methods, that they propose that Relevant State Entities have not
indicated that they agree to, comply with Order No. 1000 regional cost
allocation principles (1) through (5). However, we do not require
transmission providers to demonstrate that any Long-Term Regional
Transmission Cost Allocation Methods that they propose complies with
Order No. 1000 regional cost allocation principle (6), and, as a
result, unlike under Order No. 1000, transmission providers cannot
adopt different Long-Term Regional Transmission Cost allocation Methods
for different types of Long-Term Regional Transmission Facilities, such
as those needed for reliability, congestion relief, or to achieve
Public Policy Requirements.
1470. However, as discussed further below, we do not adopt the NOPR
proposal to require compliance with the Order No. 1000 regional cost
allocation principles in two situations. First, we do not require a
Long-Term Regional Transmission Cost Allocation Method to comply with
any of the Order No. 1000 regional cost allocation principles if
Relevant State Entities indicate that they agreed to that method as
part of the Engagement Period. Second, we do not require a cost
allocation method resulting from a State Agreement Process to comply
with the Order No. 1000 regional cost allocation principles.
1471. The first five Order No. 1000 regional transmission cost
allocation principles are: (1) the costs of selected transmission
facilities must be allocated to those within the transmission planning
region that benefit from those facilities in a manner that is at least
roughly commensurate with estimated benefits; \3134\ (2) those that
receive no benefit from transmission facilities, either at present or
in a likely future scenario, must not be involuntarily allocated any of
the costs of those transmission facilities; \3135\ (3) a benefit to
cost threshold ratio, if adopted, cannot exceed 1.25 to 1; \3136\ (4)
costs must be allocated solely within the transmission planning region
unless another entity outside the region voluntarily assumes a portion
of those costs; \3137\ and (5) the method for determining benefits and
identifying beneficiaries must be transparent.\3138\
---------------------------------------------------------------------------
\3134\ Order No. 1000, 136 FERC ] 61,051 at P 622.
\3135\ Id. P 637.
\3136\ Id. P 646.
\3137\ Id. P 657.
\3138\ Id. P 668.
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1472. We find that Order No. 1000 regional cost allocation
principles (1) through (5) remain relevant for ex ante cost allocation
methods for Long-Term Regional Transmission Facilities that
transmission providers propose on compliance but with which Relevant
State Entities have not indicated their agreement. In Order No. 1000,
regarding regional cost allocation principle (1), the Commission stated
that ``[r]equiring a beneficiaries pay cost allocation method or
methods is fully consistent with the cost causation principle as
recognized by the Commission and the courts.'' \3139\ Since making that
statement, the Commission and the courts have only further strengthened
this connection between beneficiaries-pay cost allocation and the cost
causation principle.\3140\ Similarly, principle (2) continues to
``express[ ] a central tenet of cost causation'' and is ``thus
essential to proper cost allocation.'' \3141\
---------------------------------------------------------------------------
\3139\ Id. P 623. See also id. P 586 & n.453 (citing ICC v. FERC
I, 576 F.3d at 476-77; Midwest ISO Transmission Owners v. FERC, 373
F.3d 1361, 1369 (D.C. Cir. 2004); Sithe/Indep. Power Partners, L.P.
v. FERC, 285 F.3d 1, 5 (D.C. Cir. 2002)).
\3140\ Long Island Power Auth. v. FERC, 27 F.4th 705, 713-14
(D.C. Cir. 2022); Old Dominion Elec. Coop. v. FERC, 898 F.3d at
1261-63.
\3141\ Order No. 1000, 136 FERC ] 61,051 at P 637.
---------------------------------------------------------------------------
1473. Concerning regional cost allocation principle (3), as noted
in Order No. 1000, transmission providers may choose to establish such
a threshold to mitigate against uncertainty in the measurement of
benefits and costs, and this principle limits the threshold to one that
is not so high as to block inclusion of many worthwhile transmission
projects in the regional transmission plan.\3142\ As to regional cost
allocation principle (4), this final order maintains the close link
established by Order No. 1000 between regional transmission planning
and cost allocation to the region being planned for.\3143\ Further, we
find, similar to the Commission's findings in Order No. 1000, that
removing regional cost allocation principle (4) would be tantamount to
interconnection-wide transmission planning because unilateral
allocation of costs from one transmission planning region to another
would require stakeholders to actively monitor regional transmission
planning processes in numerous other regions.\3144\ Lastly, we find,
similar to Order No. 1000, that regional cost allocation principle (5)
will ensure that Long-Term Regional Transmission Cost Allocation
Methods are just and reasonable and not unduly discriminatory or
preferential, will help aid in development and construction of new
transmission, and may avoid contentious litigation or prolonged debate
among stakeholders.\3145\
---------------------------------------------------------------------------
\3142\ Id. PP 647-648.
\3143\ Id. P 660. See also S.C. Pub. Serv. Auth. v. FERC, 762
F.3d at 87-88.
\3144\ Order No. 1000, 136 FERC ] 61,051 at P 660. See also S.C.
Pub. Serv. Auth. v. FERC, 762 F.3d at 87-88.
\3145\ Order No. 1000, 136 FERC ] 61,051 at P 669.
---------------------------------------------------------------------------
1474. In contrast to the first five regional cost allocation
principles, Order No. 1000 regional cost allocation principle (6) is
inconsistent with Long-Term Regional Transmission Planning as directed
in this final order. Order No. 1000 Regional cost allocation principle
(6) provides that there may be different regional cost allocation
methods for different types of transmission facilities in the regional
transmission plan but that there can be only one cost allocation method
for each type of facility, and that method must be determined in
advance.\3146\ As we explain below, however, transmission providers may
not establish reliability, economic, or public policy transmission
facility types as part of Long-Term Regional Transmission Planning and,
therefore, may not establish Long-Term Regional Transmission Cost
Allocation Methods based on reliability, economic, or public policy
transmission facility types. Permitting such project-type-limited Long-
Term Regional Transmission Cost Allocation Methods would be
inconsistent with the long-term, forward-looking, more comprehensive
regional transmission planning that we require in this final order.
Accordingly, in declining to require that Long-Term Regional
[[Page 49506]]
Transmission Cost Allocation Methods comply with Order No. 1000
regional cost allocation principle (6), consistent with the request of
some commenters,\3147\ we find that reliability, economic, or public
policy transmission facility types reflect a more siloed approach to
regional transmission planning that is misaligned with our Long-Term
Regional Transmission Planning reforms and would likely lead to the
allocation of the costs of Long-Term Regional Transmission Facilities
in a manner that is not at least roughly commensurate with estimated
benefits.
---------------------------------------------------------------------------
\3146\ Id. P 685.
\3147\ Massachusetts Attorney General Initial Comments at 15,
21; [Oslash]rsted Initial Comments at 9.
---------------------------------------------------------------------------
1475. We clarify that this final order does not preclude the
adoption of multiple Long-Term Regional Transmission Cost Allocation
Methods, provided that the Long-Term Regional Transmission Cost
Allocation Method that will apply to a Long-Term Regional Transmission
Facility (or portfolio of such Facilities) is known before selection,
i.e., is an ex ante cost allocation method, and does not allocate costs
by project type. We find that knowing the applicability of a Long-Term
Regional Transmission Cost Allocation Method in advance is inherent to
the definition of, and one of the primary reasons for, requiring
transmission providers to include an ex ante cost allocation method in
their OATTs. As such, transmission providers that choose to propose
more than one Long-Term Regional Transmission Cost Allocation Method on
compliance are required to make clear in their OATTs which Long-Term
Regional Transmission Cost Allocation Method applies to which Long-Term
Regional Transmission Facilities (e.g., cost allocation methods that
apply to Long-Term Regional Transmission Facilities above a certain
voltage threshold or to Long-Term Regional Transmission Facilities
located within a specific portion of a transmission planning region's
footprint).\3148\ However, we emphasize that any Long-Term Regional
Transmission Cost Allocation Method that transmission providers
propose, except for those that Relevant State Entities indicate that
they agreed to and asked the transmission providers in their
transmission planning region to file, must comply with Order No. 1000
regional cost allocation principles (1) through (5) and the other
requirements of this final order.
---------------------------------------------------------------------------
\3148\ We believe that this finding should address MISO's
request that the final order not preclude applying different cost
allocation methods to projects of the same type.
---------------------------------------------------------------------------
1476. Regarding cost allocation methods resulting from a State
Agreement Process and Long-Term Regional Transmission Cost Allocation
Methods that Relevant State Entities indicate that they have agreed to
and asked transmission providers to file after the Engagement Period,
the Commission has previously found that ``Order No. 1000 allows market
participants, including states, to negotiate voluntarily alternative
cost sharing arrangements that are distinct from the relevant regional
cost allocation method(s).'' \3149\ Additionally, where transmission
providers have proposed cost allocation methods corresponding to such
voluntary arrangements, the Commission has held that it need not find
that those cost allocation methods comply with Order No. 1000.\3150\
Consistent with this precedent, we find that cost allocation methods
resulting from a State Agreement Process and Long-Term Regional
Transmission Cost Allocation Methods that Relevant State Entities
indicate that they have agreed to and have asked transmission providers
to file also qualify as voluntary alternative cost sharing arrangements
and, accordingly, we decline to require those methods to adhere to the
six Order No. 1000 regional cost allocation principles. However, those
methods must still comply with the cost causation principle and any
other legal requirements for cost allocation.
---------------------------------------------------------------------------
\3149\ State Voluntary Agreements to Plan & Pay for Transmission
Facilities, 175 FERC ] 61,225 at P 3 (citing Order No. 1000, 136
FERC ] 61,051 at PP 561, 724; Order No. 1000-A, 139 FERC ] 61,132 at
PP 728-729).
\3150\ See PJM Interconnection, L.L.C., 142 FERC ] 61,214 at PP
142-143, order on reh'g and compliance, 147 FERC ] 61,128 at P 92;
ISO New England Inc., 143 FERC ] 61,150 at P 121; Consol. Edison Co.
of N.Y., Inc., 180 FERC ] 61,106, at PP 48-50 (2022).
---------------------------------------------------------------------------
1477. We decline to adopt the NOPR proposal that required adherence
to the six Order No. 1000 regional cost allocation principles because
cost allocation methods resulting from a State Agreement Process and
Long-Term Regional Transmission Cost Allocation Methods that Relevant
State Entities indicate that they have agreed to are likely to
facilitate agreement over development of such Long-Term Regional
Transmission Facilities by, for example, making the Relevant State
Entities more confident that customers in the state are receiving
benefits at least roughly commensurate with their share of the cost of
such facilities and by reducing the likelihood that selected Long-Term
Regional Transmission Facilities cannot be constructed because they do
not receive necessary state regulatory approvals. Affording additional
flexibility for these methods may encourage their use, which would
facilitate the selection of more efficient or cost-effective Long-Term
Regional Transmission Facilities. However, as described in the next
section, we note that cost allocation methods resulting from a State
Agreement Process and Long-Term Regional Transmission Cost Allocation
Methods that Relevant State Entities indicate that they have agreed to
must be just and reasonable and not unduly discriminatory or
preferential and must allocate costs in a manner that is at least
roughly commensurate with estimated benefits.\3151\
---------------------------------------------------------------------------
\3151\ See, e.g., PPL Elec. Utils. Corp., 181 FERC ] 61,178 at P
33.
---------------------------------------------------------------------------
1478. ELCON and West Virginia Commission express concern that the
NOPR's proposals for cost allocation methods, including requiring
compliance with the six Order No. 1000 regional cost allocation
principles, might not sufficiently recognize specific Public Policy
Requirements as driving the needs for specific Long-Term Regional
Transmission Facilities and, therefore, allow cost allocation methods
that contradict precedent on cost causation. Similarly, Utah Division
of Public Utilities asks that the Long-Term Regional Transmission Cost
Allocation Method be required to use cost causation principles to
determine what portion of Long-Term Regional Transmission Facilities
are due to state policies when states or other stakeholders disagree on
the cost allocation method due to differing renewable goals. We believe
these concerns are misplaced and no further requirements are necessary.
First, while state laws, regulations, and goals make up some of the
drivers of Long-Term Transmission Needs, they do not comprise the
entirety of those needs, as described in the Development of Long-Term
Scenarios section of this final order. Second, as described below, all
cost allocation methods for Long-Term Regional Transmission Facilities
must allocate costs to transmission customers in a manner that is at
least roughly commensurate with their estimated benefits. Third, for
Long-Term Regional Transmission Cost Allocation Methods, except for
those that Relevant State Entities indicate that they agreed to and
asked the transmission providers in their transmission planning region
to file, compliance with five of the Order No. 1000 regional cost
allocation principles further safeguards against cost causation
concerns; notably, principles (1) and (2) require that benefits
received are at least roughly commensurate with costs paid and that
costs may not be involuntarily allocated
[[Page 49507]]
to those that do not benefit, respectively. Further, Order No. 1000
regional cost allocation principle (5), as well as the requirements in
this final order to disclose estimates of the benefits of selected
Long-Term Regional Transmission Facilities, ensures sufficient
transparency for stakeholders to understand how the costs of selected
Long-Term Regional Transmission Facilities will be allocated to
transmission customers in relation to the benefits that they are
forecasted to provide. Lastly, for cost allocation methods resulting
from a State Agreement Process and Long-Term Regional Transmission Cost
Allocation Methods that Relevant State Entities have agreed to and
asked transmission providers to file, we believe that states will have
an opportunity to come to consensus on cost allocation methods that
they perceive as allocating costs in a manner that is at least roughly
commensurate with estimated benefits.
1479. Regarding Vermont Electric and Vermont Transco's concern
regarding possible discrepancies between benefits received by small
rural states and larger, more populated states, we believe that our
requirement that all cost allocation methods for Long-Term Regional
Transmission Facilities must allocate costs in a manner that is at
least roughly commensurate with estimated benefits addresses this
concern. Regarding OMS's, Louisiana Commission's, and Ohio Consumers'
requests that the Commission adopt certain cost allocation principles
distinct from the six Order No. 1000 regional cost allocation
principles, the Commission did not propose adoption of any additional
principles or that the six Order No. 1000 regional cost allocation
principles be substituted for others. Accordingly, we find these
requests beyond the scope of this final order. Additionally, in
response to Exelon's request that the Commission clarify that the
proposed State Agreement Process is supplementary to any previously
accepted provisions for state agreement-based cost allocation,\3152\ we
clarify that any State Agreement Process that the Commission accepts in
compliance with this final order will apply to only Long-Term Regional
Transmission Facilities, while any existing voluntary state cost
allocation processes that the Commission has previously accepted apply
to other transmission facilities and, thus, are unaltered by this final
order.
---------------------------------------------------------------------------
\3152\ Exelon Initial Comments at 27-28.
---------------------------------------------------------------------------
C. Identification of Benefits Considered in Cost Allocation for Long-
Term Regional Transmission Facilities
1. NOPR Proposal
1480. The Commission proposed to require transmission providers in
each transmission planning region to identify on compliance the
benefits they will use in ex ante Long-Term Regional Transmission Cost
Allocation Methods associated with Long-Term Regional Transmission
Planning, how they will calculate those benefits, and how the benefits
will reasonably reflect the benefits of regional transmission
facilities to meet identified transmission needs driven by changes in
the resource mix and demand. The Commission proposed that as part of
this compliance obligation, transmission providers must explain the
rationale for using the benefits identified.\3153\ The Commission also
requested comment on whether the Commission should require that
transmission providers account for the full list of benefits, as
described in the Evaluation of the Benefits of Regional Transmission
Facilities section above, in Long-Term Regional Transmission Planning,
or whether no change to the benefits currently used in existing
regional transmission planning processes is needed.\3154\
---------------------------------------------------------------------------
\3153\ NOPR, 179 FERC ] 61,028 at P 326.
\3154\ Id. P 327.
---------------------------------------------------------------------------
1481. The Commission also proposed, for purposes of cost
allocation, to require that transmission providers in each transmission
planning region evaluate, as part of Long-Term Regional Transmission
Planning, the benefits of regional transmission facilities over a time
horizon that covers, at a minimum, 20 years starting from the estimated
in-service date of the transmission facilities.\3155\
---------------------------------------------------------------------------
\3155\ Id. P 228.
---------------------------------------------------------------------------
2. Comments
a. Agree With Proposal
1482. Some commenters agree with the NOPR proposal.\3156\ NESCOE
contends that it is critical that costs as well as benefits be clearly
identified in connection with project evaluation.\3157\
---------------------------------------------------------------------------
\3156\ Avangrid Initial Comments at 29; California Energy
Commission Initial Comments at 3; Idaho Power Initial Comments at
11; ITC Initial Comments at 30; NESCOE Initial Comments at 72;
Northwest and Intermountain Initial Comments at 18-19.
\3157\ NESCOE Initial Comments at 72.
---------------------------------------------------------------------------
1483. Many commenters supporting the proposal emphasize the
importance of flexibility and the lack of a proposed requirement in the
NOPR to require that specific benefits be accounted for in cost
allocation.\3158\ Dominion opposes making the NOPR's listed benefits
mandatory for cost allocation because identifying and measuring them
would be difficult and lead to disputes and litigation that would add
to the costs, borne by consumers, of transmission development.\3159\
NYISO states that considering the list of benefits in the NOPR in cost
allocation would introduce significant complexity and create a
burdensome and perhaps infeasible process.\3160\ Xcel states that not
all benefits need to be studied given that such study can be costly and
add little value, and that the analysis of future benefits should
balance uncertainties to ensure that it is not too speculative.\3161\
---------------------------------------------------------------------------
\3158\ APPA Initial Comments at 46; Dominion Initial Comments at
45-46; Dominion Reply Comments at 6, 9; Exelon Initial Comments at
29-30 (citing NOPR, 179 FERC ] 61,028 at P 312 & n.516; Midwest ISO
Transmission Owners, 373 F.3d at 1369); Louisiana Commission Initial
Comments at 35-36; NARUC Initial Comments at 38; National Grid
Initial Comments at 26-27; NYISO Initial Comments at 51-52; Pacific
Northwest Utilities Initial Comments at 8-9; PPL Initial Comments at
28; SERTP Sponsors Initial Comments at 30-31; Southern Initial
Comments at 27; Xcel Initial Comments at 12.
\3159\ Dominion Reply Comments at 6-7.
\3160\ NYISO Initial Comments at 52.
\3161\ Xcel Initial Comments at 12.
---------------------------------------------------------------------------
1484. Pacific Northwest Utilities and SERTP Sponsors argue that
many of the NOPR's proposed benefits would work only in RTO/ISO
transmission planning regions and are not appropriate in non-RTO/ISO
regions.\3162\ Pacific Northwest Utilities state that several of the
benefits listed in the NOPR do not benefit transmission providers and
argue that--in non-RTO/ISO transmission planning regions, like
NorthernGrid, where there is neither a single independent transmission
system operator nor any single independent transmission provider
through which to affect transmission rate impacts due to cost
allocation--costs allocated to transmission providers must be based on
benefits to the transmission provider, not benefits realized by others,
such as generators and load-serving entities.\3163\ California
Municipal Utilities argue that requiring consideration of the list of
benefits in the NOPR would not reflect the state and local nature of
resource portfolio planning and would fail to account for the costs of
such prescriptive measures and consumer protection against speculative
[[Page 49508]]
projects.\3164\ Louisiana Commission states that transmission providers
and retail regulators should be allowed to develop and agree on an
appropriate set of metrics to be used for cost allocation.\3165\
---------------------------------------------------------------------------
\3162\ Pacific Northwest Utilities Initial Comments at 8-10;
SERTP Sponsors Initial Comments at 29-30.
\3163\ Pacific Northwest Utilities Initial Comments at 9-10.
\3164\ California Municipal Utilities Reply Comments at 5-6
(citing ACEG Initial Comments at 26-48, 50-51, 60-63).
\3165\ Louisiana Commission Initial Comments at 35.
---------------------------------------------------------------------------
1485. APPA argues that regional flexibility should include allowing
transmission providers to demonstrate on compliance that the benefits
that they use to allocate the costs of transmission projects identified
through their existing regional transmission planning processes are
sufficient for Long-Term Regional Transmission Planning.\3166\ National
Grid asserts that flexibility avoids the risk of a static list of
benefits becoming outdated, citing as an example the growing numbers of
distributed resources in New England driving the need for transmission-
level upgrades in New England. National Grid claims that more granular
(state-specific or even direct assignment) cost allocation is
appropriate for such upgrades.\3167\
---------------------------------------------------------------------------
\3166\ APPA Initial Comments at 46.
\3167\ National Grid Initial Comments at 26-27.
---------------------------------------------------------------------------
1486. City of New Orleans Council, OMS, Louisiana Commission, and
Michigan Commission argue that any benefit metrics should comply with
OMS Cost Allocation Principle Committee Principle No. 2, which states
that ``[c]ost allocation should be as granular and accurate as
possible. Benefit-cost analysis should use metrics that are
quantifiable, capable of replication, non-duplicative, and forward-
looking.'' \3168\ NARUC similarly asserts that transmission benefits
must be verifiable and quantifiable to justify allocating costs to
ratepayers.\3169\ Likewise, Idaho Power, Pacific Northwest Utilities,
and West Virginia Commission state that benefits must be quantifiable
and justified, arguing that many benefits in the NOPR proposal would be
difficult to quantify, a difficulty, Idaho Power and Pacific Northwest
Utilities argue, exacerbated by the proposed 20-year transmission
planning horizon.\3170\
---------------------------------------------------------------------------
\3168\ City of New Orleans Council Initial Comments at 11;
Louisiana Commission Initial Comments at 35-36; Michigan Commission
Initial Comments at 9; OMS Initial Comments at 7-8, 14 (citing
Organization of MISO States, Inc., Organization of MISO States
Statement of Principles: Cost Allocation for Long Range Transmission
Planning Projects, https://www.misostates.org/images/PositionStatements/OMS_Position_Statement_of_Principles_Cost_Allocation_for_LRTPs.pdf).
\3169\ NARUC Initial Comments at 25, 38.
\3170\ Idaho Power Initial Comments at 11; Pacific Northwest
Utilities Initial Comments at 6-9; West Virginia Commission Reply
Comments at 4.
---------------------------------------------------------------------------
1487. West Virginia Commission argues that use of these benefits
allows for unfettered discretion by transmission providers to adopt
cost allocation methods that do not meet the cost causation
principle.\3171\
---------------------------------------------------------------------------
\3171\ West Virginia Commission Reply Comments at 4.
---------------------------------------------------------------------------
1488. Southern states that a cost allocation premised on an overly
broad, non-quantifiable construction of benefits would likely exceed
the Commission's authority because there must be a correlation between
the charges proposed and the expected benefits, as articulated by the
courts.\3172\ Southern states that the Commission must apply the
roughly commensurate standard by determining whether the benefits to
the intended beneficiaries are quantifiable and spread evenly across a
transmission planning region. Otherwise, Southern states, the
Commission must compile a record based on substantial evidence to
support the proposed allocation of costs.\3173\ Dominion similarly
cautions that assignment of costs requires more than generalized
articulation of benefits and that the list of benefits in the NOPR are
broadly defined and generalized.\3174\
---------------------------------------------------------------------------
\3172\ Southern Initial Comments at 28-30 (citing Pac. Gas &
Elec. Co. v. FERC, 373 F.3d 1315, 1321 (D.C. Cir. 2004)).
\3173\ Id. at 29-30 (citing ICC v. FERC I, 576 F.3d at 476-77;
Ill. Com. Comm'n v. FERC, 721 F.3d 764, 777 (7th Cir. 2013) (ICC v.
FERC II); ICC v. FERC III, 756 F.3d at 564-565).
\3174\ Dominion Initial Comments at 43-44.
---------------------------------------------------------------------------
1489. Ohio Consumers state that the Commission should base the
benefits attributable to Long-Term Regional Transmission Planning on
the electrons to be delivered from generating facilities. Ohio
Consumers point out that state consumer advocates disagree as to which
benefits should be considered in cost allocation.\3175\ Ohio Consumers
argue that adopting a broad definition of benefits that includes state
decarbonization plans and socialization of some portion of the
associated costs across a transmission planning region would violate
the Order No. 1000 regional cost allocation principles and the cost
causation principle.\3176\
---------------------------------------------------------------------------
\3175\ Ohio Consumers Reply Comments at 10.
\3176\ Ohio Consumers Reply Comments at 11 (citing DC and MD
Offices of People's Counsel Initial Comments at 31, 34, 38-39).
---------------------------------------------------------------------------
1490. Pennsylvania Commission takes no position on requiring
certain benefits to be accounted for in cost allocation, but states
that the need for objective, well-defined, and measurable benefits
applies not only to transmission planning but also to cost allocation,
noting that it is important that customers who pay the costs allocated
to them agree that they are paying for real and appreciable
benefits.\3177\
---------------------------------------------------------------------------
\3177\ Pennsylvania Commission Initial Comments at 11.
---------------------------------------------------------------------------
b. Requests To Reflect the Full Breadth of Benefits in Cost Allocation
Methods While Maintaining Flexibility
1491. Some commenters request that transmission providers reflect
the full breadth of benefits in cost allocation methods for Long-Term
Regional Transmission Facilities while also supporting
flexibility.\3178\ Vistra asserts that benefits considered in cost
allocation should not be confined to a prescriptive list.\3179\ NESCOE
argues that the Commission should include a list of benefits in the
final order as a required starting point and allow transmission
providers to add or subtract benefits from the list on compliance
following consultation with states in their transmission planning
region.\3180\
---------------------------------------------------------------------------
\3178\ APPA Initial Comments at 45-46; Massachusetts Attorney
General Initial Comments at 21; NESCOE Initial Comments at 72;
Vistra Initial Comments at 15.
\3179\ Vistra Initial Comments at 15.
\3180\ NESCOE Initial Comments at 43, 72.
---------------------------------------------------------------------------
c. Disagree With Proposal, Mostly Require Benefits
1492. Some commenters disagree with the Commission's proposal,
arguing that the Commission should require transmission providers to
account for a minimum set of benefits in cost allocation.\3181\
Indicated U.S. Senators and Representatives argue that unless all
benefits and costs are incorporated into transmission planning and cost
allocation, the result will be biased, resulting in unjust and
unreasonable costs and cost allocation.\3182\ Acadia Center and CLF
contend that failure to consider a minimum set of benefits could result
in the failure to select transmission projects that would have
benefited customers.\3183\ Certain TDUs argue that guardrails should be
put in place to require transmission providers to adequately define
quantifiable benefits and to make transparent their method for
identifying benefits; however, Certain TDUs contend that the
[[Page 49509]]
Commission should require transmission providers to account for, at
minimum, production cost savings and avoided or deferred reliability
transmission facilities and aging transmission infrastructure
replacement, as may be refined by transmission planning regions as
necessary.\3184\ US Climate Alliance states that each transmission
planning region could determine additional categories of benefits most
relevant to them.\3185\
---------------------------------------------------------------------------
\3181\ Acadia Center and CLF Initial Comments at 16-19; Certain
TDUs Reply Comments at 2-3; Indicated U.S. Senators and
Representatives Initial Comments at 2; U.S. Climate Alliance Initial
Comments at 2; U.S. Senators Supplemental Comments at 2.
\3182\ Indicated U.S. Senators and Representatives Initial
Comments at 2.
\3183\ Acadia Center and CLF Initial Comments at 16-19.
\3184\ Certain TDUs Reply Comments at 2-3.
\3185\ U.S. Climate Alliance Initial Comments at 2.
---------------------------------------------------------------------------
1493. Other commenters that disagree with the Commission's proposal
similarly argue for a required minimum set of benefits, but argue that
the Commission should require transmission providers to account for the
full list of 12 benefits in the NOPR.\3186\ ACEG and PIOs state that it
would be unjust and unreasonable for transmission providers to allocate
costs in a manner that ignores certain benefits or fails to provide a
full accounting of those benefits, including, PIOs assert, cost
allocation agreed to by states.\3187\ PIOs further argue that allowing
transmission providers to agree to a cost allocation method that does
not reflect all quantifiable benefits would re-introduce the risk of
free ridership.\3188\
---------------------------------------------------------------------------
\3186\ ACEG Initial Comments at 60; Clean Energy Associations
Initial Comments at 20-21, 34; DC and MD Offices of People's Counsel
Initial Comments at 20, 34; PIOs Initial Comments at 64-65.
\3187\ ACEG Initial Comments at 60-61 (citing ICC v. FERC I, 576
F.3d at 477); PIOs Initial Comments at 65; PIOs Reply Comments at 3.
\3188\ PIOs Initial Comments at 65.
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1494. Clean Energy Buyers state that they support the Commission
requiring each transmission provider to either adopt the benefits
identified by the Commission to be used for cost allocation for Long-
Term Regional Transmission Facilities or demonstrate why the exclusion
of any such benefit(s) is just and reasonable. However, Clean Energy
Buyers also recommend that the Commission consider how the factors
required for Long-Term Scenarios will translate into benefits and
ensure that there is no double-counting of benefits.\3189\
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\3189\ Clean Energy Buyers Initial Comments at 30.
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1495. Southwestern Power Group states that existing regional cost
allocation methods do not account for the range of benefits that
regional transmission expansion can provide. Consequently, Southwestern
Power Group argues, the costs of regional transmission projects are
allocated to too few of the beneficiaries, discouraging the development
of regional transmission projects.\3190\ Environmental Groups argue
that the Commission must ensure that any cost allocation method agreed
to by states complies with the beneficiary-pays principle by showing
that the method considers all quantifiable benefits of
transmission.\3191\
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\3190\ Southwestern Power Group Initial Comments at 14-15.
\3191\ Environmental Groups Supplemental Comments at 2.
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1496. SPP states that its regional cost allocation method does not
quantify the specific benefits of transmission facilities within each
planning assessment but instead analyzes the benefits and costs of
facilities approved in multiple assessments in a comprehensive manner.
SPP states that potential inequities are not appropriately quantified
in a single regional planning assessment cycle because potential
imbalances in one cycle may be offset in later cycles or changed
because of topology. SPP emphasizes that quantification of whether
benefits of transmission facilities are roughly commensurate with
allocated costs should be performed through multiple transmission
planning cycles that evaluate project portfolios, citing SPP's Highway-
Byway cost allocation method as an example.\3192\
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\3192\ SPP Initial Comments at 31.
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d. Alignment of Benefits Between Transmission Planning and Cost
Allocation
1497. Various commenters proffer arguments as to whether benefits
used in the evaluation and selection of Long-Term Regional Transmission
Facilities must align with the benefits used in cost allocation. For
example, SERTP Sponsors state that there could be differences between
the types of benefits used for evaluation and selection and those used
for cost allocation, asserting that benefits used in cost allocation
must be measured in a consistent and objective manner to limit
disputes.\3193\
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\3193\ SERTP Sponsors Initial Comments at 30-31.
---------------------------------------------------------------------------
1498. Some commenters argue that the benefits used in the
evaluation and selection of Long-Term Regional Transmission Facilities
should closely align with, but need not be the same as, those used in
cost allocation.\3194\ For example, Clean Energy Associations state
that close alignment does not preclude regional variation and points to
MISO's Multi-Value Projects' and SPP's Highway/Byway projects' cost
allocation methods.\3195\
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\3194\ Clean Energy Associations Initial Comments at 34; Cypress
Creek Reply Comments at 14-15; [Oslash]rsted Initial Comments at 9.
\3195\ Clean Energy Associations Initial Comments at 34-35.
---------------------------------------------------------------------------
1499. Some commenters argue that the same set of benefits used in
transmission planning should be used in cost allocation.\3196\ DC and
MD Offices of People's Counsel and the New Jersey Commission link such
a requirement with the beneficiary-pays principle.\3197\ New Jersey
Commission states that enforcing the beneficiary-pays principle based
on all of a transmission project's quantified benefits is necessary to
avoid free-rider problems that could arise, especially in the State
Agreement Process.\3198\ Additionally, New Jersey Commission states,
the policy of preventing states from involuntarily bearing the costs of
others' policies must not require states to always pay the full cost of
any transmission solution that supports their public policies or
prevent states from committing to paying more than what they perceive
to be their fair share to overcome disagreements over who will
benefit.\3199\ Similarly, BP recommends requiring that those
benefitting from transmission facilities that meet policy objectives,
but without similar policies themselves, be allocated an appropriate
share of costs to avoid free ridership.\3200\
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\3196\ DC and MD Offices of People's Counsel Initial Comments at
34; Fervo Reply Comments at 2-3; New Jersey Commission Initial
Comments at 18-23; SEIA Initial Comments at 24; Vermont Electric and
Vermont Transco Initial Comments at 4; WATT Coalition Initial
Comments at 8.
\3197\ DC and MD Offices of People's Counsel Initial Comments at
34 (citing ICC v. FERC I, 576 F.3d 470; ICC v. FERC II, 721 F.3d
764; ICC v. FERC III, 756 F.3d 556); New Jersey Commission Initial
Comments at 18-23 (citing Old Dominion Elec. Coop. v. FERC, 898 F.3d
at 1262-63; Entergy Ark. v. FERC, 40 F.4th 689, 701 (D.C. Cir.
2022)).
\3198\ New Jersey Commission Initial Comments at 18.
\3199\ Id. at 21-23.
\3200\ BP Initial Comments at 9-12.
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1500. Massachusetts Attorney General states that ex ante cost
allocation methods should reflect the same benefits considered in Long-
Term Regional Transmission Planning and not consider benefits in
silos.\3201\ [Oslash]rsted similarly supports a requirement that
transmission providers adopt cost allocation methods that recognize the
full breadth of benefits that transmission facilities provide.\3202\
---------------------------------------------------------------------------
\3201\ Massachusetts Attorney General Initial Comments at 21.
\3202\ [Oslash]rsted Initial Comments at 9.
---------------------------------------------------------------------------
1501. PIOs argue that cost allocation is necessarily implicated in
the NOPR's preliminary finding that failure to consider a broader set
of benefits and beneficiaries of transmission facilities may result in
unjust, unreasonable, and unduly discriminatory or preferential rates,
reasoning that cost allocation cannot be based on unlawful
[[Page 49510]]
identification of benefits and beneficiaries.\3203\
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\3203\ PIOs Initial Comments at 71.
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e. Additional Benefits or Suggestions for Refinement
1502. DC and MD Offices of People's Counsel recommend that the
Commission allow Relevant State Entities to propose additional benefit
categories for evaluation and to consent to the allocation of costs
that align with these additional benefits. At a minimum, DC and MD
Offices of People's Counsel argue, costs should be allocated to the
benefitting Relevant State Entities.\3204\
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\3204\ DC and MD Offices of People's Counsel Initial Comments at
34.
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1503. California Energy Commission recommends that transmission
providers be required to consider equity and environmental justice in
the calculation of benefits, including economic, health, and social
benefits to disadvantaged communities.\3205\ WE ACT recommends that the
Commission include non-energy benefits like pollution reduction,
health, jobs, and local economic development in the list of benefits
that transmission providers should be required to utilize in
identifying and evaluating Long-Term Regional Transmission Facility
need, selection, and cost allocation.\3206\
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\3205\ California Energy Commission Initial Comments at 3.
\3206\ WE ACT Initial Comments at 5.
---------------------------------------------------------------------------
1504. Louisiana Commission states that the Commission should permit
transmission providers to consider allocations to all cost causers and
beneficiaries, including generators.\3207\ Vistra argues that if
achieving voluntary corporate and utility clean energy goals is
factored into demand driving the need for an upgrade, then the costs of
such upgrades should not be assigned to regional load.\3208\
---------------------------------------------------------------------------
\3207\ Louisiana Commission Initial Comments at 32.
\3208\ Vistra Initial Comments at 21-22.
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3. Commission Determination
1505. We decline to adopt the NOPR proposal to require transmission
providers to identify on compliance the benefits that they will use in
Long-Term Regional Transmission Cost Allocation Methods, how they will
calculate those benefits, and how the benefits will reasonably reflect
the benefits of regional transmission facilities to meet identified
transmission needs driven by changes in the resource mix and demand.
1506. Instead, as we discuss above in the Long-Term Regional
Transmission Facility Cost Allocation Compliance with the Existing Six
Order No. 1000 Regional Cost Allocation Principles section, we require
transmission providers in each transmission planning region to
demonstrate on compliance that the required Long-Term Regional
Transmission Cost Allocation Method(s) that Relevant State Entities
have not indicated that they agree to comply with Order No. 1000
regional transmission cost allocation principles (1) through (5) and do
not allocate costs by project type (i.e., reliability, economic, or
transmission needs driven by Public Policy Requirements). While we do
not require that cost allocation methods resulting from State Agreement
Processes or Long-Term Regional Transmission Cost Allocation Methods
that Relevant States Entities indicate they agreed to, must comply with
any of the Order No. 1000 regional cost allocation principles, if filed
with the Commission, transmission providers must nonetheless
demonstrate that either of these types of cost allocation methods will
allocate costs in a manner at least roughly commensurate with estimated
benefits.\3209\ We do not require that any particular benefit used in
the evaluation and selection of Long-Term Regional Transmission
Facilities be reflected in a Long-Term Regional Transmission Cost
Allocation Method filed with the Commission. We adopt this modified
approach to the relationship of benefits used in Long-Term Regional
Transmission Planning and Long-Term Regional Transmission Cost
Allocation Methods because it provides transmission providers with
flexibility to propose a Long-Term Regional Transmission Cost
Allocation Method(s), allowing for negotiation in the Engagement
Period, which we believe will increase the chances that Long-Term
Regional Transmission Facilities selected as the more efficient or
cost-effective regional transmission solution will be developed. At the
same time, the requirements in this final order to disclose estimates
of the benefits of selected Long-Term Regional Transmission Facilities
will provide transparency and help to ensure a cost allocation is just
and reasonable.
---------------------------------------------------------------------------
\3209\ See ICC v. FERC I, 576 F.3d at 477; ICC v. FERC III, 756
F.3d at 564.
---------------------------------------------------------------------------
1507. We note that this flexible approach is consistent with the
approach that the Commission took in Order No. 1000 and in subsequent
orders on transmission providers' Order No. 1000 compliance filings,
where the Commission allowed a wide variety of cost allocation methods
and did not require that such methods specifically account for all
benefits used in evaluation and selection processes.\3210\ The cost
allocation method for MISO's Multi-Value Projects and the SPP Highway/
Byway cost allocation method are examples that reflect the flexibility
that transmission providers have had in adopting cost allocation
methods suited to their circumstances and that may not have been
possible under a less flexible approach.
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\3210\ Order No. 1000, 136 FERC ] 61,051 at PP 560, 624.
---------------------------------------------------------------------------
1508. The one exception to that flexibility, however, is the second
component of our compliance requirement, that transmission providers
must not allocate costs based on project types; namely, reliability,
economic, or Public Policy Requirements needs-driven cost allocation
methods. As described in the Long-Term Regional Transmission Facility
Cost Allocation Compliance with Existing Six Order No. 1000 Regional
Cost Allocation Principles section, we adopt this requirement because
permitting such project-type-limited cost allocation methods for Long-
Term Regional Transmission Facilities would be inconsistent with the
long-term, forward-looking, more comprehensive regional transmission
planning that we require in this final order. As we note above in the
Need for Reform section, allocating costs based on these project types
would result in transmission providers undertaking investments in
relatively inefficient or less cost-effective transmission
infrastructure, the costs of which are ultimately recovered through
Commission-jurisdictional rates. Allocating costs based on these
project types could, for example, encourage the selection of
transmission facilities based on either their economic or reliability
benefits alone rather than based on an evaluation of the wider range of
benefits that they may provide. This dynamic results in, among other
things, transmission customers paying more than is necessary or
appropriate to meet their transmission needs, customers forgoing
benefits that outweigh their costs, or some combination thereof, which
results in less efficient or cost-effective transmission investments.
We further find that permitting the use of such project-type-limited
cost allocation methods for Long-Term Transmission Facilities would not
allocate costs in a manner that is at least roughly commensurate to
estimated benefits.
1509. We decline to adopt the NOPR proposal to require transmission
providers to evaluate benefits over a 20-year time horizon for Long-
Term Regional Transmission Planning for
[[Page 49511]]
purposes of cost allocation. Given our decision to not require
transmission providers to explain the benefits that they are using in
cost allocation for Long-Term Regional Transmission Facilities, we
believe this proposal is moot.
1510. We acknowledge New Jersey Commission's concern that
permissive state-negotiated cost allocation could result in free
riders. However, we note that, even for cost allocation methods filed
pursuant to a State Agreement Process and Long-Term Regional
Transmission Cost Allocation Methods that Relevant State Entities
indicate that they have agreed, the costs allocated in accordance with
such methods must be, as noted above, at least roughly commensurate
with estimated benefits consistent with legal precedent. On compliance
with this final order, the Commission will evaluate whether any cost
allocation method agreed to pursuant to a State Agreement Process, or
Long-Term Regional Transmission Cost Allocation Methods that Relevant
State Entities indicate that they have agreed to, and filed with the
Commission, allocates the costs of Long-Term Regional Transmission
Facilities in a manner that is at least roughly commensurate with the
estimated benefits. Further, we believe that New Jersey Commission's
concern is reduced by our modification to the NOPR proposal to require
transmission providers to file a Long-Term Regional Transmission Cost
Allocation Method that must be used where a State Agreement Process
fails to result in agreement; to the extent Relevant State Entities do
not agree to a cost allocation method through the State Agreement
Process, the transmission provider's ex ante Long-Term Regional
Transmission Cost Allocation Method will apply.
1511. Given our modification to the NOPR proposal to not require
transmission providers to identify on compliance the benefits that they
will use in Long-Term Regional Transmission Cost Allocation Methods, we
find moot APPA's request that regional flexibility should include
allowing transmission providers to demonstrate on compliance that their
existing benefits used for cost allocation of transmission projects
identified through their existing regional transmission planning
processes are sufficient for Long-Term Regional Transmission
Planning.\3211\
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\3211\ APPA Initial Comments at 46. We also discuss related
concerns in the Cost Allocation for Long-Term Transmission
Facilities section, above.
---------------------------------------------------------------------------
1512. With respect to the comments of City of New Orleans Council,
OMS, Louisiana Commission, and Michigan Commission arguing that any
benefit metrics should comply with OMS Cost Allocation Principle
Committee Principle No. 2,\3212\ which states that ``[c]ost allocation
should be as granular and accurate as possible,'' \3213\ we note that
the flexibility we provide as to the consideration of benefits in cost
allocation does not prevent transmission providers in a particular
transmission planning region from adopting a more granular approach.
---------------------------------------------------------------------------
\3212\ City of New Orleans Council Initial Comments at 11;
Louisiana Commission Initial Comments at 35-36; Michigan Commission
Initial Comments at 9; OMS Initial Comments at 7-8, 14.
\3213\ OMS Initial Comments at 7-8.
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1513. With respect to Southern and Dominion's assertions that the
Commission must ensure that costs are allocated in a manner that is at
least roughly commensurate with benefits by conducting its evaluation
of proposed cost allocation methods in a particular manner,\3214\ we
reiterate that we will apply existing Commission and judicial
precedent, including that cited by Dominion and Southern, in our
evaluation of any proposed cost allocation methods for Long-Term
Regional Transmission Facilities. With respect to Louisiana
Commission's assertion that the cost allocation process should be
allowed to consider allocations to all cost causers and beneficiaries,
including generators,\3215\ we continue to adhere to the flexibility we
provided in Order No. 1000-A. In that order, we found that with respect
to generators being identified as beneficiaries and ultimately
responsible for costs, just as each transmission planning region
retains the flexibility to define benefit and beneficiary, the public
utility transmission providers in each transmission planning region, in
consultation with their stakeholders, may consider proposals to
allocate costs directly to generators as beneficiaries that could be
subject to regional or interregional cost allocation. However, we also
found that any effort to do so must not be inconsistent with the
generator interconnection process under Order No. 2003 because, as we
stated in Order No. 1000, the generator interconnection process and
interconnection cost recovery were outside the scope of that
rulemaking.\3216\
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\3214\ Southern Initial Comments at 29-30 (citing ICC v. FERC I,
576 F.3d at 476-77; ICC v. FERC II, 721 F.3d at 777; ICC v. FERC
III, 756 F.3d at 564-565); Dominion Initial Comments at 43-44
(citing ICC v. FERC I, 576 F.3d at 477).
\3215\ Louisiana Commission Initial Comments at 32.
\3216\ Order No. 1000-A, 139 FERC ] 61,132 at P 680. While
interconnection customers may voluntarily fund the cost of, or a
portion of the cost of, a Long-Term Regional Transmission Facility
as discussed in the Evaluation and Selection of Long-Term Regional
Transmission Facilities section, this process is distinct from
allocating costs to generators under the Long-Term Regional
Transmission Cost Allocation Method, as the Louisiana Commission
appears to contemplate.
---------------------------------------------------------------------------
1514. We find Pacific Northwest Utilities' assertion that costs
allocated to transmission providers in non-RTO/ISO transmission
planning regions, like NorthernGrid, must be based on benefits to the
transmission provider, not benefits realized by others, such as
generators and load-serving entities,\3217\ to be misplaced, as nothing
in this final order requires that only transmission providers in non-
RTO/ISO transmission planning regions bear the ultimate responsibility
for the costs of Long-Term Regional Transmission Facilities. We
recognize that, in the absence of a single regional transmission
provider who can recover the costs of Long-Term Regional Transmission
Facilities on behalf of its transmission-owning members from all of its
transmission customers in its transmission planning region,
transmission providers in non-RTO/ISO regions require alternative
arrangements to allocate and recover the costs of Long-Term Regional
Transmission Facilities from the transmission customers that benefit
from them. We expect that in non-RTO/ISO transmission planning regions,
as is the case with Order No. 1000 regional transmission planning and
cost allocation processes today,\3218\ transmission providers will
establish arrangements to implement the cost allocation methods for
Long-Term Regional Facilities and recover the costs of such facilities
from the transmission customers that benefit from them.
---------------------------------------------------------------------------
\3217\ Pacific Northwest Utilities Initial Comments at 9-10.
\3218\ See e.g., Duke Energy Carolinas, LLC, 147 FERC ] 61,241
at P 453; Pub. Serv. Co. of Colo., 142 FERC ] 61,206 at P 314.
---------------------------------------------------------------------------
1515. Some commenters advocate for accounting for public policy
benefits in cost allocation methods for Long-Term Regional Transmission
Facilities.\3219\ Although we are not requiring transmission providers
to account for public policy benefits in cost allocation methods for
Long-Term Regional Transmission Facilities, we are also not foreclosing
the possibility that transmission providers and stakeholders may seek
to account for certain public
[[Page 49512]]
policy benefits when developing Long-Term Regional Transmission Cost
Allocation Methods. We believe that states are well-positioned to value
the benefits of achieving their respective public policy goals,
consistent with past precedent in which we have affirmed the use of
public policy benefits in regional transmission planning cost
allocation,\3220\ and they or other stakeholders can similarly do so
through engagement with transmission providers in their efforts to
develop Long-Term Regional Transmission Cost Allocation Methods. In
addition, to the extent states believe that a particular Long-Term
Regional Transmission Facility would help achieve their public policy
goals, we note our adoption in the Evaluation and Selection of Long-
Term Regional Transmission Facilities section of this final order of
opportunities for Relevant State Entities to voluntarily fund a portion
of the cost of a Long-Term Regional Transmission Facility so that the
facility can qualify for selection.\3221\ The rule, consistent with the
cost causation principle, does not allow allocation of costs based on
benefits to entities that do not receive benefits or receive only
trivial benefits in relationship to costs of those transmission
facilities.\3222\
---------------------------------------------------------------------------
\3219\ See e.g., California Energy Commission Initial Comments
at 3 (recommending that equity and environmental justice benefits be
accounted for in cost allocation, including economic, health, and
social benefits to disadvantaged communities); WE ACT Initial
Comments at 5 (recommending the following benefits be accounted for
in cost allocation: pollution reduction, health, jobs, and local
economic development).
\3220\ As noted in the Evaluation of the Benefits of Regional
Transmission Facilities section, RTOs/ISOs that have used some form
of public policy benefit in regional transmission planning include
PJM and NYISO. Although explicitly not part of PJM's Order No. 1000
regional transmission planning, PJM uses a State Agreement Approach
to allow the development of public policy projects. See PPL Elec.
Utils. Corp., 181 FERC ] 61,178 at P 33 (finding that ``allocating
the costs of the New Jersey [State Agreement Approach] Projects on a
load-ratio share basis to all New Jersey customers is roughly
commensurate with the benefits provided by those projects''). NYISO
provides for cost allocations developed by the New York State Public
Service Commission for transmission projects developed to meet
public policy needs. See Consol. Edison Co. of N.Y., Inc., 180 FERC
] 61,106 at P 50 (finding that a volumetric load-ratio share cost
allocation for certain local transmission upgrades was appropriate
because the projects ``benefit customers throughout the state
insofar as they facilitate compliance with the New York State
climate and renewable energy goals as required by New York State law
and have been determined by the NYPSC to be necessary to meet such
obligation'').
\3221\ Supra Evaluation and Selection of Long-Term Regional
Transmission Facilities section.
\3222\ See Coal. of MISO Transmission Customers v. FERC, 45
F.4th 1004, 1009 (D.C. Cir. 2022) (``The cost-causation principle
requires that `the cost of transmission facilities be allocated to
those within the transmission planning region that benefit from
those facilities in a manner that is at least roughly commensurate
with estimated benefits.''') (cleaned up) (quoting S.C. Pub. Serv.
Auth. v. FERC, 762 F.3d at 53); ICC v. FERC I, 576 F.3d at 477.
---------------------------------------------------------------------------
D. Miscellaneous Cost Allocation Comments and Proposals
1. Comments
1516. Some commenters discuss the appropriate time frame for cost
allocation for Long-Term Regional Transmission Facilities. Dominion
states that costs should not be allocated until closer in time to when
a transmission project will be built and beneficiaries identified
rather than when the Long-Term Regional Transmission Facilities are
identified.\3223\ Ohio Consumers state that cost allocation decisions
must be made on the basis of current or near-term transmission needs,
and the Commission should not require subsidization for transmission
lines on the theory that the line may be needed to serve future
generation.\3224\ OMS supports a requirement that transmission
providers identify beneficiaries of transmission projects before any
costs are allocated.\3225\
---------------------------------------------------------------------------
\3223\ Dominion Initial Comments at 42.
\3224\ Ohio Consumers Initial Comments at 19.
\3225\ OMS Initial Comments at 9.
---------------------------------------------------------------------------
1517. Acadia Center and CLF state that the Commission should expand
its cost allocation proposals to encompass interregional transmission
planning and the generator interconnection processes.\3226\
---------------------------------------------------------------------------
\3226\ Acadia Center and CLF Initial Comments at 17.
---------------------------------------------------------------------------
1518. Some commenters stress the importance of cost containment
oversight by the Commission. Joint Commenters support a cost management
framework overseen by the Commission ensuring that the costs and
benefits on which transmission projects are initially approved for cost
allocation remain within initially contemplated parameters.\3227\ State
Water Contractors assert that the need for cost containment is acute
for consumers in California, asserting that the CAISO high voltage
transmission access charge has increased nearly 136% over the last
decade. State Water Contractors argue that as increases in transmission
costs have a direct impact on the cost of water delivery and treatment
and given that water and energy are particularly intertwined in
California, cost containment and regional flexibility are essential
components to the justness and reasonableness of any final order.\3228\
---------------------------------------------------------------------------
\3227\ Joint Commenters Reply Comments at 1.
\3228\ State Water Contractors Reply Comments at 2-3.
---------------------------------------------------------------------------
1519. Ohio Consumers state that the Commission should require that
the transmission providers implementing any Long-Term Regional
Transmission Planning requirements give appropriate consideration to
public grants and other external sources of funding in any cost
allocation processes, adding that transmission providers should first
seek public grants prior to charging customers, because infrastructure
funds must be accounted for, or else they would distort cost allocation
processes.\3229\
---------------------------------------------------------------------------
\3229\ Ohio Consumers Reply Comments at 15 (citing
Infrastructure Investment and Jobs Act of 2021, Public Law 117-58,
135 Stat 429).
---------------------------------------------------------------------------
1520. NextEra renews its request for the Commission to initiate a
new rulemaking to prohibit regional allocation of the costs of
transmission projects developed pursuant to an incumbent transmission
owner's exercise of state right-of-first-refusal rights and require the
direct assignment of such costs to customers in the incumbent
transmission owner's zone.\3230\
---------------------------------------------------------------------------
\3230\ NextEra Reply Comments at 26.
---------------------------------------------------------------------------
2. Commission Determination
1521. We decline to adopt a particular time frame for determining
the cost allocation for a Long-Term Regional Transmission Facility, as
requested by Dominion, Ohio Consumers, and OMS. We believe that
imposing a standardized time frame to determine cost allocation is
unnecessary and could impede the regional flexibility that we provide
to transmission providers under this final order. However, as discussed
above in the Long-Term Regional Transmission Facility Cost Allocation
Compliance with the Existing Six Regional Cost Allocation Principles
section, if only a Long-Term Regional Transmission Cost Allocation
Method is available for a particular Long-Term Regional Transmission
Facility (or portfolio of such Facilities), the determination of the
applicable cost allocation must occur by or before its selection.
1522. We find Acadia Center and CLF's assertion that the Commission
should expand its cost allocation proposals to encompass interregional
transmission planning and the generator interconnection processes to be
outside the scope of this proceeding, as is NextEra's request for the
Commission to initiate a new rulemaking to prohibit regional allocation
of the costs of transmission projects developed pursuant to an
incumbent transmission owner's exercise of a state right of first
refusal and require the direct assignment of such costs to customers in
the incumbent transmission owner's zone. These suggestions are beyond
the scope of the Commission's NOPR proposals and we believe that the
record
[[Page 49513]]
in this proceeding is insufficient to proceed with them.
1523. We also find outside the scope of this proceeding various
commenters' statements regarding cost containment. We note that the
Commission is examining issues related to transmission planning and
cost containment in other proceedings.\3231\
---------------------------------------------------------------------------
\3231\ See, e.g., Supplemental Notice of Technical Conference,
Transmission Planning and Cost Management, Docket No. AD22-8-000
(Oct. 4, 2022).
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VII. Construction Work in Progress Incentive
A. NOPR Proposal
1524. In the NOPR, the Commission proposed to not permit
transmission providers to take advantage of the allowance for inclusion
of 100% of Construction Work In Progress (CWIP) costs in rate base
(CWIP Incentive) for Long-Term Regional Transmission Facilities.\3232\
The Commission noted that transmission providers may still accrue
carrying costs incurred during the pre-construction or construction
phase as Allowance for Funds Used During Construction (AFUDC) and only
recover those costs from customers after the project is in service, in
accordance with generally accepted utility accounting principles for
AFUDC.\3233\ The Commission explained that this proposal would not
affect Commission policy and regulations established before Order No.
679.\3234\
---------------------------------------------------------------------------
\3232\ NOPR, 179 FERC ] 61,028 at PP 328-329 n.522-523, 525-527
(citing Order No. 679, 71 FR 43294 (July 31, 2006), 116 FERC ]
61,057 at PP 9, 116-117, n.70). The Commission stated that the
Commission has also provided that any public utility engaged in the
sale of electric power for resale can file to include in rate base
up to 50% of CWIP, subject to limitations. Construction Work in
Progress for Pub. Utils.; Inclusion of Costs in Rate Base, Order No.
298, 48 FR 24323 (June 1, 1983), FERC Stats. & Regs. ] 30,455 (1983)
(cross-referenced at 23 FERC ] 61,224), order on reh'g, 25 FERC ]
61,023 (1983). NOPR, 179 FERC ] 61,028 at P 329 n.524.
\3233\ NOPR, 179 FERC ] 61,028 at P 333.
\3234\ Id. P 333 n.530. There, the Commission stated that public
utility transmission providers would still be allowed to request 50%
CWIP in rate base, as is permitted pursuant to 18 CFR 35.25(c)(3),
subject to an FPA section 205 filing detailing how the request meets
the requirements of Order No. 298. The Commission believed that the
ability to include 50% CWIP in rate base, if requested and granted,
reflects a more reasonable sharing of risks and benefits than the
CWIP Incentive for Long-Term Regional Transmission Facilities given
the greater uncertainty inherent in Long-Term Regional Transmission
Planning, as proposed in this NOPR.
---------------------------------------------------------------------------
B. Comments
1. Interest in the NOPR Proposal
1525. Many commenters support the Commission's NOPR proposal to
prohibit Long-Term Regional Transmission Facilities from being eligible
for the CWIP Incentive and generally support permitting cost recovery
instead through AFUDC, agreeing that extending the CWIP Incentive to
Long-Term Regional Transmission Facilities would expose ratepayers to
risks and cost burdens by requiring them to pay for Long-Term Regional
Transmission Facilities that receive the incentive prior to those
facilities being placed into service.\3235\
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\3235\ American Municipal Power Initial Comments at 34; APPA
Initial Comments at 6, 46-47; California Commission Initial Comments
at 58; California Water Initial Comments at 19-20; Clean Energy
Buyers Initial Comments at 30-31; ELCON Initial Comments at 19;
Industrial Customers Initial Comments at 24-26; Joint Consumer
Advocates Initial Comments at 14; Kentucky Commission Chair Chandler
Initial Comments at 4; Large Public Power Initial Comments at 41-42;
Louisiana Commission Initial Comments at 36; Massachusetts Attorney
General Initial Comments at 23; NARUC Initial Comments at 54-55;
NASUCA Initial Comments at 8-9; NESCOE Initial Comments at 73;
Nevada Commission Initial Comments at 14; North Carolina Commission
and Staff Initial Comments at 17-18; NRG Initial Comments at 21-22;
Ohio Commission Federal Advocate Initial Comments at 15-16; Ohio
Consumers Initial Comments at 29; Pennsylvania Commission Initial
Comments at 17; PJM States Initial Comments at 13; Resale Iowa
Initial Comments at 2, 12-13; Six Cities Initial Comments at 11;
State Agencies Initial Comments at 24; TAPS Initial Comments at 5,
27-29; Transmission Dependent Utilities Initial Comments at 2-4;
Virginia Attorney General Initial Comments at 4-6.
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1526. California Commission and New England Systems argue that
there is no evidence that any of the incentives established under FPA
section 219, including the CWIP Incentive, have spurred investment in
transmission infrastructure.\3236\ California Commission argues that
there was a great need to develop new transmission to bolster
reliability and alleviate congestion when the CWIP Incentive was first
introduced in Order No. 679, but that the prior decline in transmission
investment has since been reversed.\3237\ Further, California
Commission argues that an inability to receive the CWIP Incentive would
not present a barrier to entry for transmission development,\3238\
stating that disallowing the CWIP Incentive for Long-Term Regional
Transmission Facilities would affect incumbent and nonincumbent
transmission developers equally, and that developers could continue to
seek the CWIP Incentive for economic and reliability transmission
projects.\3239\ Louisiana Commission states that if an independent
transmission developer or utility has won a competitive bidding process
to construct transmission facilities, that entity should have the
financial wherewithal to finance the project without a loan from
ratepayers.\3240\
---------------------------------------------------------------------------
\3236\ California Commission Reply Comments at 11-12; New
England Systems Reply Comments at 15-16.
\3237\ California Commission Reply Comments at 8-10 (citing US
DOE, National Electric Transmission Congestion Study, at 21(Sept.
2020), https://www.energy.gov/sites/default/files/2020/10/f79/2020%20Congestion%20Study%20FINAL%2022Sept2020.pdf).
\3238\ Id. at 19-20 (citing CAISO Initial Comments at 44).
\3239\ Id.
\3240\ Louisiana Commission Initial Comments at 36.
---------------------------------------------------------------------------
1527. Several commenters assert that the CWIP Incentive shifts
risks to customers.\3241\ Pennsylvania Commission, Large Public Power,
and Resale Iowa argue that allowing the CWIP Incentive could
substantially increase the risk of customers paying for transmission
facilities that are never built and from which they derive no benefit,
leading to rates that are unjust and unreasonable.\3242\ NARUC, New
England Systems, and Virginia Attorney General agree with the proposed
reform because it better aligns risk and reward between shareholders
and customers with respect to Long-Term Regional Transmission
Facilities.\3243\
---------------------------------------------------------------------------
\3241\ California Commission Reply Comments at 14; Large Public
Power Initial Comments at 41; Louisiana Commission Initial Comments
at 36; NARUC Initial Comments at 55-56; New England Systems Reply
Comments at 15; Ohio Commission Federal Advocate Initial Comments at
16; Pennsylvania Commission Initial Comments at 17; Resale Iowa
Initial Comments at 12-13; Virginia Attorney General Reply Comments
at 2.
\3242\ Large Public Power Initial Comments at 41; Pennsylvania
Commission Initial Comments at 17; Resale Iowa Initial Comments at
12-13.
\3243\ NARUC Initial Comments at 55-56; New England Systems
Reply Comments at 15 (citing NARUC Initial Comments at 56); Virginia
Attorney General Reply Comments at 2 (citing NARUC Initial Comments
at 55).
---------------------------------------------------------------------------
1528. Several other commenters state that the longer the
transmission planning horizon, the higher the risk that resulting
transmission facilities will not be needed, which may result in
stranded costs.\3244\ For this reason, Industrial Customers state that
shifting risks from transmission developers to customers is
particularly problematic for Long-Term Regional Transmission
Facilities.\3245\ Dominion states that it does not take a position on
the proposal to prohibit Long-Term Regional Transmission Facilities
from being eligible for the CWIP Incentive, but nevertheless asserts
that shifting the risk for long-term transmission projects to
transmission providers will help ensure that only those long-term
projects that are ``confidently needed'' will be developed. However,
for states that may
[[Page 49514]]
allow or require the inclusion of the CWIP Incentive in rate base,
Dominion states that the Commission should allow for deference to the
state cost recovery structure.\3246\
---------------------------------------------------------------------------
\3244\ Clean Energy Buyers Reply Comments at 10-11; Dominion
Initial Comments at 53-54; Industrial Customers Reply Comments at 9;
Transmission Dependent Utilities Reply Comments at 4; Virginia
Attorney General Reply Comments at 3.
\3245\ Industrial Customers Reply Comments at 9.
\3246\ Dominion Initial Comments at 53.
---------------------------------------------------------------------------
1529. Several commenters suggest that such reform may mitigate
certain risks of the transmission provider over-building the
system.\3247\ For example, Massachusetts Attorney General and North
Dakota Commission state that the Commission's proposed limit on the
CWIP Incentive would provide ratepayers greater protection from
financing inefficient or over-built regional transmission
projects.\3248\ New England Systems argue that entities in favor of
continuing the CWIP Incentive gain financially from the
incentive.\3249\ Industrial Customers state that the alleged benefits
of the CWIP Incentive to customers are tenuous at best.\3250\
---------------------------------------------------------------------------
\3247\ Massachusetts Attorney General Initial Comments at 24-25;
North Carolina Commission and Staff Initial Comments at 18; North
Dakota Commission Initial Comments at 6; Pennsylvania Commission
Initial Comments at 17-18; PJM States Initial Comments at 13; US
Climate Alliance Initial Comments at 2.
\3248\ Massachusetts Attorney General Initial Comments at 24-25;
North Dakota Commission Initial Comments at 6.
\3249\ New England Systems Reply Comments at 15-16 (citing
Avangrid Initial Comments at 26).
\3250\ Industrial Customers Reply Comments at 9-10.
---------------------------------------------------------------------------
1530. Multiple commenters suggest that prohibiting Long-Term
Regional Transmission Facilities from being eligible for the CWIP
Incentive may improve the planning and building of new transmission
facilities.\3251\ New England Systems, PJM States, and North Carolina
Commission and Staff assert that removing the CWIP Incentive will
appropriately reduce incentives to over-build transmission, which could
lead to rates being unjust and unreasonable.\3252\ Similarly, US
Climate Alliance supports prohibiting Long-Term Regional Transmission
Facilities from being eligible for the CWIP Incentive, as doing so
would align incentives for transmission providers to deliver
transmission projects on time and within budget.\3253\
---------------------------------------------------------------------------
\3251\ North Carolina Commission and Staff Initial Comments at
18; Pennsylvania Commission Initial Comments at 17; PJM States
Initial Comments at 13; US Climate Alliance Initial Comments at 2.
\3252\ New England Systems Reply Comments at 14-15; North
Carolina Commission and Staff Initial Comments at 18; PJM States
Initial Comments at 13.
\3253\ US Climate Alliance Initial Comments at 2.
---------------------------------------------------------------------------
1531. California Commission argues that money paid earlier as CWIP
is more valuable than money paid later and that comparisons of savings
under the CWIP Incentive and under AFUDC are only meaningful if an
interest adjustment is made to account for the time in which payments
are made.\3254\ Industrial Customers explain that, to customers, the
difference between the AFUDC and CWIP approaches is primarily the time
value of money.\3255\ Kentucky Commission Chair Chandler, NASUCA, and
California Commission express concern that today's ratepayers are
forced to pay for tomorrow's transmission projects, which they refer to
as intergenerational inequity, and they are especially concerned if a
project will not provide service until a much later date.\3256\
---------------------------------------------------------------------------
\3254\ California Commission Reply Comments at 13.
\3255\ Industrial Customers Reply Comments at 9.
\3256\ Kentucky Commission Chair Chandler Initial Comments at 8;
NASUCA Initial Comments at 9; California Commission Reply Comments
at 17 (citing NASUCA Initial Comments at 9).
---------------------------------------------------------------------------
2. Concerns With the NOPR Proposal
1532. Many commenters oppose the NOPR proposal to prohibit Long-
Term Regional Transmission Facilities from being eligible for the CWIP
Incentive.\3257\ Several commenters cite the Commission's findings in
Order No. 679 explaining that the CWIP Incentive can help remove a
disincentive to construct new transmission infrastructure, which can
involve very long lead times and considerable risk to the utility that
the project may not go forward.\3258\ National Grid and Avangrid, for
example, argue that Long-Term Regional Transmission Facilities will
likely have very long lead times and place even greater risk on
transmission providers relative to transmission facilities planned and
developed on a more typical timeframe.\3259\ Similarly, WIRES argues
that the rationale underlying the CWIP Incentive remains valid
today.\3260\
---------------------------------------------------------------------------
\3257\ AEP Initial Comments at 38-40; Ameren Initial Comments at
48-51; Avangrid Initial Comments at 24-28; CAISO Initial Comments at
43-45; Consumer Organizations Initial Comments at 7-10; Duke Initial
Comments at 44-45; Duquesne Light Initial Comments at 2-6; EEI
Initial Comments at 42-45; EEI Reply Comments at 17-18; Entergy
Initial Comments at 35-37; Eversource Initial Comments at 31-35;
Eversource Reply Comments at 2; Harvard ELI Initial Comments at 7-
10; Indicated PJM TOs Initial Comments at 26-28; MISO TOs Initial
Comments at 65-66; National Grid Initial Comments at 27-30; New York
TOs Initial Comments at 23-24; New York Transco Initial Comments at
13-16; Pattern Energy Initial Comments at 34-36; PG&E Initial
Comments at 18-20; PPL Initial Comments at 29-30; SoCal Edison
Initial Comments at 13-14; Transource Initial Comments at 3; WIRES
Initial Comments at 17-19.
\3258\ Ameren Initial Comments at 49; EEI Initial Comments at
42-43; EEI Reply Comments at 17-18; Eversource Reply Comments at 2;
MISO TOs Initial Comments at 66; National Grid Initial Comments at
28-29; WIRES Initial Comments at 17-18 (all citing Order No. 679,
116 FERC ] 61,057 at P 115).
\3259\ Avangrid Reply Comments at 6-7; National Grid Initial
Comments at 28-29.
\3260\ WIRES Initial Comments at 17-18.
---------------------------------------------------------------------------
1533. Some commenters also cite the Commission's 2012 Transmission
Incentive Policy Statement as support for the CWIP Incentive as a risk-
reducing mechanism to transmission providers, which these commenters
state can increase credit ratings and lower capital costs.\3261\ In
addition, several commenters reference Commission findings in numerous
prior incentive proceedings where the Commission has affirmed the
benefits that the CWIP Incentive provides to customers and transmission
providers, attesting that the NOPR proposal is in direct opposition to
such findings.\3262\
---------------------------------------------------------------------------
\3261\ Ameren Initial Comments at 49; EEI Initial Comments at
42; Eversource Initial Comments at 32 (all citing Promoting
Transmission Investment Through Pricing Reform, Policy Statement,
141 FERC ] 61,129, at P 12 (2012)).
\3262\ AEP Initial Comments at 38 (citing Ne. Utils. Serv. Co. &
Nat'l Grid USA, 125 FERC ] 61,183, at P 89 (2008)); Ameren Initial
Comments at 49 (citing United Illuminating, 119 FERC ] 61,182, at P
63 (2007)); Duquesne Light Initial Comments at 3 (citing Xcel Energy
Servs., Inc., 121 FERC ] 61,284, at P 58 (2007); Am. Elec. Power
Service Corp., 116 FERC ] 61,059, at P 3 (2006)); EEI Initial
Comments at 44 (citing PPL Elec. Utils. Corp., 123 FERC ] 61,068, at
PP 42-43 (2008), reh'g denied, 124 FERC ] 61,229 (2008)); National
Grid Initial Comments at 29 (citing Tucson Elec. Power Co., 174 FERC
] 61,223, at P 25 (2021); S. Cal. Edison Co., 172 FERC ] 61,241, at
P 31 (2020); United Illuminating Co., 167 FERC ] 61,126, at P 36
(2019)); MISO TOs Initial Comments at 66-67 (citing PJM
Interconnection, L.L.C., 135 FERC ] 61,229, at P 78 (2011); Duquesne
Light Co., 166 FERC ] 61,074, at P 32 (2019); United Illuminating,
Co., 167 FERC ] 61,126 at P 36; GridLiance W. Transco LLC, 164 FERC
] 61,049, at P 25 (2018); NextEra Energy Transmission N.Y., Inc.,
162 FERC ] 61,196, at P 64 (2018); PJM Interconnection, L.L.C., 158
FERC ] 61,089, at P 33 (2017); Duquesne Light Co., 179 FERC ]
61,218, at P 17 (2022)); New York TOs Initial Comments at 23 (citing
Okla. Gas & Elec. Co., 133 FERC ] 61,274, at P 48 (2010); Pepco
Holdings, Inc., 125 FERC ] 61,130, at P 63 (2008)).
---------------------------------------------------------------------------
1534. Some commenters assert that the NOPR proposal runs counter to
obligations established in the Energy Policy Act of 2005 and FPA
section 219 to facilitate capital investment in transmission
infrastructure and would likely impede the development of regional
transmission facilities identified to meet changes in the resource mix
and demand.\3263\
---------------------------------------------------------------------------
\3263\ Ameren Initial Comments at 48; CAISO Initial Comments at
43-44; EEI Initial Comments at 42-43; Indicated PJM TOs Initial
Comments at 26-28; MISO TOs Initial Comments at 71-72; National Grid
Initial Comments at 28; PPL Initial Comments at 29-30; WIRES Initial
Comments at 17-18.
---------------------------------------------------------------------------
1535. Numerous commenters argue that the proposal runs counter to
the objectives of the NOPR that seek to encourage the development and
completion of regional transmission facilities needed to address
changes in
[[Page 49515]]
the resource mix or demand over a longer time horizon.\3264\ For
example, CAISO, MISO TOs, and Avangrid suggest that it is
counterintuitive for the Commission to acknowledge a lack of regional
transmission facilities in the NOPR, yet propose to undo the most
reasonable tool that aids cash flow and reduces uncertainty associated
with building those facilities.\3265\ Certain commenters state that the
CWIP Incentive assists with getting needed transmission projects
built.\3266\ AEP and Avangrid state that the CWIP Incentive is
particularly well-suited to incentivizing the type of large, regional
transmission projects that the Commission hopes to increase through the
NOPR, which often present higher costs, longer lead times, an increase
in possible rate shock, and present cash flow difficulties.\3267\
---------------------------------------------------------------------------
\3264\ AEP Initial Comments at 39; Ameren Initial Comments at
50-51; Avangrid Initial Comments at 25; Avangrid Reply Comments at
6-8; Eversource Initial Comments at 2, 31-32; MISO TOs Initial
Comments at 70-76; Pattern Energy Initial Comments at 35-36; PG&E
Initial Comments at 18-19.
\3265\ Avangrid Reply Comments at 7 (citing CAISO Initial
Comments at 45; MISO TOs Initial Comments at 71-72, 74-75); CAISO
Initial Comments at 45; MISO TOs Initial Comments at 74-76 (citing
NOPR, 179 FERC ] 61,028 at PP 1, 9, 25, 35, 47, 330-331).
\3266\ AEP Initial Comments at 39; Ameren Initial Comments at
50; Avangrid Initial Comments at 26; MISO TOs Initial Comments at
69.
\3267\ AEP Initial Comments at 39; Avangrid Reply Comments at
10.
---------------------------------------------------------------------------
1536. Several commenters point to cash flow benefits enabled
through the CWIP Incentive and associated benefits to customers.\3268\
For example, New York TOs and PG&E contend that the cash flow benefits
from the CWIP Incentive allow a utility to reduce the need for external
financing and instead allocate capital to other projects that benefit
additional ratepayers.\3269\
---------------------------------------------------------------------------
\3268\ AEP Initial Comments at 38-39; Ameren Initial Comments at
49; Avangrid Initial Comments at 25; EEI Initial Comments at 44-45;
EEI Reply Comments at 17; Entergy Initial Comments at 37; Eversource
Initial Comments at 31; Indicated PJM TOs Initial Comments at 26-28;
MISO TOs Initial Comments at 66-67, 71, 74-76; National Grid Initial
Comments at 28-29; New York TOs Initial Comments at 23-24; New York
Transco Initial Comments at 13; Pattern Energy Initial Comments at
35; PG&E Initial Comments at 19; Transource Initial Comments at 3;
WIRES Initial Comments at 17-18.
\3269\ New York TOs Initial Comments at 23-24; PG&E Initial
Comments at 19.
---------------------------------------------------------------------------
1537. Several commenters contend that the Commission has failed to
adequately justify the NOPR proposal, asserting that the rationale is
weak or arguing that the Commission has not shown that its existing
policy is unjust and unreasonable.\3270\ MISO TOs argue that the
Commission's claim that ratepayers do not receive benefits from the
regional transmission facilities during the construction period is
unsupported by precedent or analysis and is contrary to longstanding
Commission policy. Further, they observe that a transmission facility
cannot be developed and placed into service overnight, so artificially
dividing up the customer benefits to pre-operation and post-operation
ignores the realities of transmission development.\3271\ Where the
proposal identified that additional ratepayer protections may be
necessary to balance customers' interest in just and reasonable rates
against investors' interest in earning a return on invested capital or
mitigating against over-investment in regional transmission facilities,
MISO TOs reiterate that the CWIP Incentive's benefits promote just and
reasonable rates by providing incentives encouraging transmission
construction consistent with the Commission's FPA mandate and assert
that an investor's rate of return is set in unrelated
proceedings.\3272\
---------------------------------------------------------------------------
\3270\ Ameren Initial Comments at 50-51; Duke Initial Comments
at 44-45; Duquesne Light Initial Comments at 2-3; EEI Initial
Comments at 44-45; Eversource Initial Comments at 33-34; MISO TOs
Initial Comments at 66-67 (citing NOPR, 179 FERC ] 61,028 at P 331);
Pattern Energy Initial Comments at 35.
\3271\ MISO TOs Initial Comments at 69 (citing NOPR, 179 FERC ]
61,028 at P 331).
\3272\ Id. at 72-73 (citing NOPR, 179 FERC ] 61,028 at P 331).
---------------------------------------------------------------------------
1538. Pattern Energy states that the Commission has provided no
policy justification or factual basis to distinguish the risk incurred
during the planning phase from other risk factors, such as size, scope,
or cost, which it asserts is a departure from the Order No. 679 policy
on the CWIP Incentive.\3273\
---------------------------------------------------------------------------
\3273\ Pattern Energy Initial Comments at 35.
---------------------------------------------------------------------------
1539. Many commenters also argue that, while the NOPR proposal to
prohibit Long-Term Regional Transmission Facilities from being eligible
for the CWIP Incentive is intended to mitigate shifting too much risk
to customers, the proposal ignores many of the benefits that the
current CWIP Incentive policy providers to customers.\3274\ EEI argues
that commenters that support the proposal also fail to recognize these
benefits and the important role that this incentive serves in
facilitating new transmission investment.\3275\ Many commenters that
oppose the NOPR proposal tout such benefits, such as improved cash flow
and the ability for transmission providers to secure better financing
through higher credit ratings, resulting in lower interest expense
costs that benefit customers.\3276\ Consumer Organizations and
Eversource contend that carrying a significant amount of debt in AFUDC
rather than being recovered through the CWIP Incentive can result in
lower credit ratings and higher capital costs, which are passed through
to customers, and assert that ``with AFUDC, consumers are likely to pay
more in the long run.'' \3277\
---------------------------------------------------------------------------
\3274\ AEP Initial Comments at 38-39; Ameren Initial Comments at
48-51; Avangrid Initial Comments at 27-28; Duke Initial Comments at
45; Duquesne Light Initial Comments at 3-5; EEI Initial Comments at
44-45; EEI Reply Comments at 18; Eversource Initial Comments at 31-
34; Indicated PJM TOs Initial Comments at 26; MISO TOs Initial
Comments at 66-76; National Grid Initial Comments at 29; New York
TOs Initial Comments at 23-24; New York Transco Initial Comments at
13-14; PG&E Initial Comments at 19-20; SoCal Edison Initial Comments
at 3, 13-14; WIRES Initial Comments at 18-19.
\3275\ EEI Reply Comments at 18 (citing NASUCA Initial Comments
at 8-9; Transmission Dependent Utilities Initial Comments at 2-4).
\3276\ Ameren Initial Comments at 42, 50; Avangrid Initial
Comments at 27; Duke Initial Comments at 45; Duquesne Light Initial
Comments at 4-6; EEI Initial Comments at 44-45; MISO TOs Initial
Comments at 66-67; PG&E Initial Comments at 19.
\3277\ Consumer Organizations Initial Comments at 7-8;
Eversource Reply Comments at 4 (quoting Consumer Organizations
Initial Comments at 7).
---------------------------------------------------------------------------
1540. Some commenters state that the CWIP Incentive helps to avoid
rate shock and provides other cost savings relative to AFUDC.\3278\
Avangrid states that arguments about the sharing of risk between
utilities and customers that the Commission used to support the NOPR
proposal fail to consider the budgeting risk to customers under the
AFUDC approach, and claims that these arguments ignore the benefit of
price stability.\3279\
---------------------------------------------------------------------------
\3278\ AEP Initial Comments at 38-39; Ameren Initial Comments at
50; Avangrid Initial Comments at 27-28; Avangrid Reply Comments at
10 (citing Kentucky Commission Chair Chandler Initial Comments at 4-
9); Consumer Organizations Initial Comments at 7-10; Duquesne Light
Initial Comments at 4; EEI Initial Comments at 44; EEI Reply
Comments at 17-18; Eversource Initial Comments at 31-32; Eversource
Reply Comments at 4-5; Indicated PJM TOs Initial Comments at 26;
MISO TOs Initial Comments at 66-76; National Grid Initial Comments
at 28-29; New York TOs Initial Comments at 23-24; PG&E Initial
Comments at 19; PG&E Reply Comments at 13-14; SoCal Edison Initial
Comments at 13-14; WIRES Initial Comments at 19.
\3279\ Avangrid Reply Comments at 10 (citing Kentucky Commission
Chair Chandler Initial Comments at 4-9).
---------------------------------------------------------------------------
1541. Several commenters state that the Commission can take more
targeted action to address concerns of uncertainty in Long-Term
Regional Transmission Planning rather than prohibiting Long-Term
Regional Transmission Facilities from being eligible for the CWIP
Incentive, for instance, by ensuring sufficiently robust selection
criteria, project review, and
[[Page 49516]]
approval processes.\3280\ CAISO contends that these measures are more
appropriate ways to account for the root cause of the risk of over-
building and to ensure that customers are protected from the costs of
transmission facilities that may be less certain.\3281\ R Street states
that the NOPR's proposal to remove the CWIP Incentive by itself will
not thwart increasing transmission costs, and the Commission must
recognize preserving and expanding competition as a way to contain
costs.\3282\
---------------------------------------------------------------------------
\3280\ Avangrid Reply Comments at 8 (citing CAISO Initial
Comments at 45); CAISO Initial Comments at 45; EEI Reply Comments at
18; PG&E Reply Comments at 13-14.
\3281\ CAISO Initial Comments at 6-7, 45.
\3282\ R Street Reply Comments at 2.
---------------------------------------------------------------------------
1542. Eversource and New York Transco assert that case-by-case
evaluation for any request for transmission incentives, including the
CWIP Incentive, affords interested parties the opportunity to intervene
and provide comments, culminating in a Commission determination of
whether the incentive is just and reasonable, thereby protecting
customer interests.\3283\
---------------------------------------------------------------------------
\3283\ Eversource Reply Comments at 4-5; New York Transco Reply
Comments at 7-8.
---------------------------------------------------------------------------
1543. Eversource, Harvard ELI, and National Grid state that it
would be best to make changes in incentives policy in a comprehensive
transmission incentives rulemaking instead of in this final
order.\3284\ Eversource and National Grid argue that, at a minimum, the
Commission should defer a decision on the CWIP Incentive to the
rulemaking proceeding on transmission incentives in Docket No. RM20-10-
000, where the Commission has already established a full and complete
record.\3285\ Harvard ELI suggests that any action on the CWIP
Incentive be deferred to another proceeding to develop a holistic
package of incentives, penalties, and oversight mechanisms after the
Commission has established the full goals and procedural rules for
Long-Term Regional Transmission Planning.\3286\
---------------------------------------------------------------------------
\3284\ Eversource Initial Comments at 33; Harvard ELI Initial
Comments at 4-5, 7-8, 10; National Grid Initial Comments at 27.
\3285\ Eversource Initial Comments at 33; National Grid Initial
Comments at 27.
\3286\ Harvard ELI Initial Comments at 4-5, 7-8, 10.
---------------------------------------------------------------------------
1544. Certain commenters raise concerns of unintended consequences
of the proposal. CAISO and Transource state that new transmission
developers may be disadvantaged if the Commission prohibits Long-Term
Regional Transmission Facilities from being eligible for the CWIP
Incentive.\3287\ Specifically, CAISO notes that the Commission approved
a provision in its OATT that permits a nonincumbent transmission
developer within CAISO to recover Commission-authorized transmission
revenue requirements associated with transmission projects under
construction before the facilities are turned over to CAISO operational
control, which CAISO contends is a way that it addresses barriers to
transmission development by nonincumbent transmission developers.\3288\
CAISO contends that the Commission should not preclude transmission
developers from using the CWIP Incentive for Long-Term Regional
Transmission Facilities, especially because the Commission would
continue to allow the CWIP Incentive for reliability and economic
transmission projects.\3289\
---------------------------------------------------------------------------
\3287\ CAISO Initial Comments at 43-45; Transource Initial
Comments at 3.
\3288\ CAISO Initial Comments at 43-44 (citing Cal. Indep. Sys.
Operator Corp., 146 FERC ] 61,237 (2014)).
\3289\ Id. at 44-45.
---------------------------------------------------------------------------
3. Interaction of the CWIP Incentive With the Abandoned Plant Incentive
1545. Many commenters raise concerns with the interaction between
the CWIP Incentive and the transmission incentive that allows
applicants to request 100% of prudently-incurred costs associated with
abandoned transmission projects be included in transmission rates if
such abandonment is outside the control of management (Abandoned Plant
Incentive).\3290\ APPA, California Commission, Industrial Customers,
NARUC, and Virginia Attorney General suggest that unless and until the
Commission reconsiders the Abandoned Plant Incentive, customers will
continue to face risks associated with Long-Term Regional Transmission
Facilities.\3291\ Specifically, APPA states that the proposal to
prohibit Long-Term Regional Transmission Facilities from being eligible
for the CWIP Incentive will not necessarily protect customers from the
costs of potentially unneeded facilities identified through Long-Term
Regional Transmission Planning, given the Commission's policies on
recovery of abandoned plant costs (including the Abandoned Plant
Incentive under Order No. 679).\3292\ Similarly, NARUC, Virginia
Attorney General, and Industrial Customers request that the Commission
review the current abandoned plant policy to ensure that customer
benefits from the adoption of the NOPR proposal with respect to the
CWIP Incentive do not disappear if those costs are still recovered from
customers as abandoned plant.\3293\
---------------------------------------------------------------------------
\3290\ Order No. 679, 116 FERC ] 61,057 at P 163.
\3291\ APPA Initial Comments at 46-47; California Commission
Reply Comments at 19 (citing Industrial Customers Initial Comments
at 27); Industrial Customers Initial Comments at 24-27; Industrial
Customers Reply Comments at 9; NARUC Initial Comments at 55;
Virginia Attorney General Initial Comments at 6-7; Virginia Attorney
General Reply Comments at 5-6.
\3292\ APPA Initial Comments at 46-47.
\3293\ Industrial Customers Reply Comments at 10 (citing MISO
States Initial Comments at 14; NARUC Initial Comments at 55); NARUC
Initial Comments at 55; Virginia Attorney General Reply Comments at
5 (citing NARUC Initial Comments at 55).
---------------------------------------------------------------------------
1546. Industrial Customers suggest that, without additional reforms
limiting the recovery of abandoned plant costs, customers will continue
to face the possibility of paying for transmission that is never
built.\3294\ Further, Industrial Customers and California Commission
state that AFUDC could be a superior approach for customers, but only
in a final order that adopts certain protections to ensure that
customers do not pay for abandoned plant costs.\3295\ Industrial
Customers argue that the Commission should adopt customer safeguards
for transmission projects that are abandoned, including a more thorough
review of whether costs were prudently incurred prior to
abandonment.\3296\
---------------------------------------------------------------------------
\3294\ Industrial Customers Initial Comments at 25-26.
\3295\ California Commission Reply Comments at 19 (citing
Industrial Customers Initial Comments at 27); Industrial Customers
Initial Comments at 26-27.
\3296\ Industrial Customers Reply Comments at 9.
---------------------------------------------------------------------------
C. Commission Determination
1547. We decline to act at this time to finalize the NOPR proposal
to limit the availability of the CWIP Incentive for Long-Term Regional
Transmission Facilities. We agree with commenters \3297\ that any
action on the CWIP Incentive is more appropriately considered in a
separate proceeding to allow for a holistic approach to transmission
incentives after the Commission has finalized its Long-Term Regional
Transmission Planning reforms. In particular, we conclude that whether
the Commission's transmission incentives are appropriately
``benefitting consumers by ensuring reliability and reducing the cost
of delivered power'' \3298\ is a question better evaluated by
considering the Commission's transmission incentives comprehensively
for all regional transmission facilities.
---------------------------------------------------------------------------
\3297\ Eversource Initial Comments at 33; Harvard ELI Initial
Comments at 4-5, 7-8, 10; National Grid Initial Comments at 27.
\3298\ 16 U.S.C. 824s(a).
---------------------------------------------------------------------------
[[Page 49517]]
VIII. Exercise of a Federal Right of First Refusal in Commission-
Jurisdictional Tariffs and Agreements
A. NOPR Proposal
1548. In the NOPR, the Commission proposed to use the discretion
afforded by FPA section 309 to amend Order No. 1000's findings and
nonincumbent transmission developer reforms in part, so as to permit
the exercise of Federal rights of first refusal for selected
transmission facilities, conditioned on the incumbent transmission
provider with the Federal right of first refusal for such regional
transmission facilities establishing joint ownership of the
transmission facilities consistent with certain proposed requirements
described in the NOPR.\3299\ The Commission reasoned that given the
investment trends observed since Order No. 1000's implementation, it is
possible that the Commission's Order No. 1000 nonincumbent transmission
developer reforms may be inadvertently discouraging investment in and
development of regional transmission facilities to some extent.\3300\
Specifically, the Commission posited that incumbent transmission
providers, as a result of those reforms, may be presented with perverse
investment incentives that do not adequately encourage those incumbent
transmission providers to develop and advocate for transmission
facilities that benefit more than just their own local retail
distribution service territory or footprint.\3301\
---------------------------------------------------------------------------
\3299\ See NOPR, 179 FERC ] 61,028 at P 351.
\3300\ Id. P 350.
\3301\ Id.
---------------------------------------------------------------------------
1549. The Commission preliminarily found that, while the
unconditional exercise of Federal rights of first refusal for entirely
new selected transmission facilities remains unjust and unreasonable,
Order No. 1000's remedy--requiring the elimination of all Federal
rights of first refusal for entirely new selected transmission
facilities--was overly broad.\3302\ The Commission further
preliminarily found that, while Order No. 1000's reforms have a sound
theoretical basis, the remedy prescribed by Order No. 1000 failed to
recognize that some of the expected benefits from the competitive
transmission development processes could be achieved or at least
reasonably approximated through other means.\3303\
---------------------------------------------------------------------------
\3302\ Id. PP 351-352, 354.
\3303\ Id. P 353.
---------------------------------------------------------------------------
1550. Accordingly, the Commission proposed to allow transmission
providers to propose, pursuant to FPA section 205, new Federal rights
of first refusal for incumbent transmission providers, conditioned on
the incumbent transmission provider with the Federal right of first
refusal for such regional transmission facilities establishing joint
ownership of the transmission facilities consistent with certain
requirements described in the NOPR.\3304\ The Commission asserted that
if the NOPR proposal was adopted, Order No. 1000's findings and
mandates would be amended such that joint ownership conditions would
presumptively be found to ensure just and reasonable Commission-
jurisdictional rates and limit opportunities for undue discrimination
by transmission providers, if imposed upon the exercise of an incumbent
transmission provider's Federal right of first refusal for selected
transmission facilities.
---------------------------------------------------------------------------
\3304\ Id. P 354.
---------------------------------------------------------------------------
1551. The Commission explained that an incumbent transmission
provider could establish qualifying joint ownership with unaffiliated
nonincumbent transmission developers as defined in Order No. 1000, or
another unaffiliated entity, including another incumbent transmission
provider.\3305\ However, the Commission also proposed that to qualify
for the presumption, incumbent transmission providers with a
conditional Federal right of first refusal would not be allowed to
structure joint-ownership arrangements such that unaffiliated entities
were offered less than a meaningful level of participation and
investment in the proposed regional transmission facility.\3306\ The
Commission further explained that an incumbent transmission provider's
conditional Federal right of first refusal should not significantly
delay the regional transmission planning process or result in prolonged
uncertainty regarding which transmission facilities will (or,
alternatively, will not) be subject to competitive transmission
development processes.\3307\
---------------------------------------------------------------------------
\3305\ Id. P 365.
\3306\ Id. P 371.
\3307\ Id. P 366.
---------------------------------------------------------------------------
1552. The Commission noted that proposals for jointly owned
regional transmission facilities would still need to be evaluated by
transmission providers in the transmission planning region and would
not be exempt from selection requirements. However, the Commission also
explained that the evaluation process for such jointly owned regional
transmission facility proposals would not involve running the region's
competitive transmission development process.\3308\
---------------------------------------------------------------------------
\3308\ Id. P 370.
---------------------------------------------------------------------------
B. Comments
1. General Perspectives and Approach To Reform
1553. Commenters share a variety of perspectives on the track
record of competitive transmission development processes, the wisdom of
the nonincumbent transmission developer reforms adopted in Order No.
1000, and the steps they believe the Commission should take in response
to the concerns identified in the NOPR. Several state entities,
customer-affiliated groups, and nonincumbent transmission developers,
such as LS Power, NextEra, and the US DOJ and FTC, defend competitive
transmission development processes as beneficial and argue for their
expansion.\3309\ Some US Senators agree, arguing that allowing for a
conditional Federal right of first refusal would be anti-competitive,
could hinder development of new transmission, and could cause excessive
costs to consumers.\3310\ On the other hand, representatives of
incumbent transmission providers and others (e.g., EEI, WIRES, DATA,
the MISO TOs) critique such processes and many call for the Commission
to restore unconditional Federal rights of first refusal.\3311\ Each
side of the debate
[[Page 49518]]
offers consultant reports to substantiate their position, with pro-
competition advocates relying on studies by the Brattle Group (Brattle)
that present competitive transmission development processes in a
largely favorable light,\3312\ and advocates for Federal rights of
first refusal relying on contrasting studies by Concentric Energy
Advisors (Concentric).\3313\ In general, pro-competition advocates,
such as LS Power, contend that competitive transmission development
processes are essential to just and reasonable rates, while
representatives of incumbent transmission providers counter that just
and reasonable transmission rates are separately and independently
ensured by and through FPA section 205 rate proceedings.\3314\
---------------------------------------------------------------------------
\3309\ See, e.g., American Municipal Power Reply Comments at 3-
4; Anbaric Initial Comments at 4-5; California Commission Initial
Comments at 100, 103-104; Competition Advocates Supplemental
Comments at 1-3 & n.17 (citing Jennifer Chen & Devin Hartman, R
Street Institute, Transmission Reform Strategy from a Customer
Perspective: Optimizing Net Benefits and Procedural Vehicles (May
2022), http://www.rstreet.org/research/transmission-reform-strategy-from-a-customer-perspective-optimizing-net-benefits-and-procedural-vehicles); Competition Coalition Initial Comments at 16-22, 68-70;
LS Power Initial Comments at 38-39, 44; LS Power Partial Reply
Comments at 20-23; LS Power and NRG Supplemental Comments at 38-39;
NextEra Initial Comments at 18-19, 24-27, 29; Ohio Consumers Reply
Comments at 16-18; Resale Iowa Reply Comments at 5-6; US DOJ and FTC
Initial Comments at 7-8, 10-11, 13, 22.
\3310\ U.S. Senators Heinrich and Lee Supplemental Comments at
1-2. See also Freeport-McMoRan Supplemental Comments at 6 (asserting
that the Federal right of first refusal is anticompetitive and would
enrich transmission owning utility shareholders).
\3311\ See, e.g., DATA Initial Comments at 3-7 (detailing
experiences by transmission planning regions and concluding that
``competitive processes have become a distraction from, and an
impediment to, the larger goal of expanding the transmission system
to support current and future needs''); EEI Initial Comments at 24,
26, 27-31; EEI Supplemental Comments at 1-3 (citing Concentric
Energy Advisors, Competitive Transmission: Experience To-Date Shows
Order No. 1000 Solicitations Fail to Show Benefits, at 1 (Aug. 2022)
(2022 Concentric Report); DATA Supplemental Comments at 4); MISO TOs
Initial Comments at 53-56; National Grid Initial Comments at 4-5, 31
(doubting that Order No. 1000 competitive transmission development
processes have broadly produced beneficial outcomes); PJM Initial
Comments at 47-48 (enumerating the challenges faced in and resources
required to complete competitive transmission development
processes); Vermont Electric and Vermont Transco Initial Comments at
4-5 (referencing ``a number of unintended consequences that have not
benefited the regional grid''); WIRES Initial Comments at 14-15;
WIRES Reply Comments at 4-8; Xcel Initial Comments at 5 (``[Right of
first refusal] elimination was a policy experiment that did not
bring about the desired result.'').
\3312\ In general, Brattle's analysis has found that competitive
transmission development processes have yielded ``cost savings
averaging between 20% and 30%'' once historical levels of cost
escalation in transmission development were taken into account. See
Brattle Apr. 2019 Competition Report at 39-43. US DOJ and FTC also
contend that there are many instances in which competitive
transmission development processes have benefitted consumers. See US
DOJ & FTC Initial Comments at 13-16 (collecting examples); but see
DATA Initial Comments at 7-9 (critiquing Brattle's analyses); WIRES
Reply Comments at 5 (same).
\3313\ In addition to citations to past Concentric reports, DATA
attaches to its initial comments a 2022 Concentric report, which
DATA characterizes as showing that competitive transmission
development processes add significant time, delay customer benefits,
and do not produce clear evidence of customer savings given cost cap
exclusions and delays. DATA Initial Comments at 1-2, 7-11, 14-15;
id. at attach. A (2022 Concentric Report). DATA also attaches to its
comments a whitepaper that DATA alleges updates the Brattle Apr.
2019 Competition Report, and which DATA contends shows that Order
No. 1000-mandated competition resulted in exceeding cost baselines
by at least six percent. DATA Supplemental Comments at 3-4; id. at
attach.: Whitepaper (DATA, Revisiting the Evidence on Cost Savings
from Transmission Competition (Dec. 2023) (2023 DATA Whitepaper)).
But see Massachusetts Attorney General Reply Comments at 8-9
(critiquing the 2022 Concentric Report); NextEra Reply Comments at
3, 7-17 (same); see also Competition Coalition Supplemental Comments
at 2-7 (arguing that, in addition to DATA lacking good cause and
failing to file a motion to lodge new evidence, the 2023 DATA
Whitepaper fails to, among other things, demonstrate that cost-of-
service regulation is as effective as competition in establishing
just and reasonable transmission rates).
\3314\ Compare LS Power Initial Comments at 32-37, with Ameren
Initial Comments at 36-37, and DATA Initial Comments at 13-14, and
MISO TOs Initial Comments at 60-61. Several commenters argue at
length about the NOPR proposal's invocation of FPA sections 309 and
206 as legal authority and explore various alternatives. See, e.g.,
Ameren Initial Comments at 38-39; California Commission Initial
Comments at 101-103; DATA Initial Comments at 17-18 & n.43;
Eversource Initial Comments at 39-42; Indicated PJM TOs Initial
Comments at 34-35; ITC Initial Comments at 36; LS Power Initial
Comments at 14, 19-20, 24, 57-61; MISO TOs Initial Comments at 50-
53; NextEra Initial Comments at 51-53.
---------------------------------------------------------------------------
1554. At a high level, pro-competition commenters express concern
that the NOPR proposal could divert regional transmission facility
development opportunities to incumbent transmission providers,
opportunities that would otherwise be subject to competitive
transmission development processes. For example, US DOJ and FTC argue
that relying on Federal rights of first refusal to address the problems
the Commission has identified would eliminate or distort the benefits
of competitive transmission development processes, which generally
``make transmission development less costly, more resilient, and more
innovative.'' \3315\ NESCOE ``implores the Commission to maintain
flexibility that enables ISO-NE to issue competitive solicitations to
identify projects in furtherance of state laws.'' \3316\ Some pro-
competition commenters believe that states and state commissions are
best positioned to determine whether competition between nonincumbent
transmission developers and incumbent transmission providers is
beneficial.\3317\
---------------------------------------------------------------------------
\3315\ See US DOJ & FTC Initial Comments at 22.
\3316\ NESCOE Supplemental Comments at 6-7.
\3317\ E.g., California Commission Initial Comments at 104-105;
Harvard ELI Initial Comments at 5-6, 31-33; see also Minnesota State
Entities Initial Comments at 9; Mississippi Commission Reply
Comments at 8 & n.31; New Jersey Commission Initial Comments at 37;
PIOs Initial Comments at 85; PJM States Initial Comments at 13-14.
But see NextEra Reply Comments at 23-25 (questioning whether
allowing states to dictate the terms of a filed rate would be
legally sound); PJM Reply Comments at 25-29 (raising potential legal
ambiguities and practical issues).
---------------------------------------------------------------------------
1555. Meanwhile, commenters that generally support Federal rights
of first refusal express skepticism that the NOPR proposal would be
sufficient to address the identified problems, or offer only qualified
support for the NOPR proposal as an inferior alternative to the
Commission fully restoring unconditional Federal rights of first
refusal.\3318\ In addition, if adopted, several incumbent transmission
providers advocate for requiring transmission providers to implement
the NOPR proposal instead of permitting them to decide whether to
implement it.\3319\
---------------------------------------------------------------------------
\3318\ E.g., Avangrid Initial Comments at 18-24; DATA Initial
Comments at 20-22; Eversource Initial Comments at 35-36, 42-45;
Indicated PJM TOs Reply Comments at 2, 13-14; ITC Initial Comments
at 32-43; Xcel Initial Comments at 5.
\3319\ See, e.g., DATA Initial Comments at 19-21; Exelon Initial
Comments at 49-51; National Grid Initial Comments at 36-37; PG&E
Initial Comments at 2, 11; PPL Initial Comments at 34; SoCal Edison
Initial Comments at 2; WIRES Initial Comments at 16; see also LS
Power Initial Comments at 74-76 (discussing FPA section 205 rights
in various regions); PJM Initial Comments at 30 (questioning whether
there are any ``regional differences'' on this policy issue). But
see Idaho Power Initial Comments at 12 (urging the Commission to
ensure that any proposed reforms provide sufficient flexibility to
tailor transmission planning and cost allocation processes to
accommodate unique regional characteristics).
---------------------------------------------------------------------------
1556. While commenters offer numerous variations on these high-
level opposing views, several commenters argue that there are problems
with the basic structure of competitive transmission development
processes and express concerns that generally align with those
expressed by the Commission in the NOPR. For example, while not
agreeing with the NOPR proposal, ELCON expresses concern that ``current
competition regimes have led eligible developers to retreat to their
various corners, which reduces transparency, information sharing, and
open dialogue in the planning process[,]'' and contends that both
incumbent transmission owners and nonincumbent transmission developers
have adopted a zero-sum posture to transmission planning that leads to
a patchwork of planning and lack of innovation.\3320\ Similarly, WIRES,
citing a report by Grid Strategies, suggests that reforms under Order
No. 1000 often prevent information sharing about transmission needs and
available solutions, and lead to less cooperation and coordination
within transmission planning regions.\3321\ Harvard ELI disagrees,
however, arguing that the report cited by WIRES provides evidence that
information asymmetry, secrecy, and utilities' incentives demonstrate
undue discrimination.\3322\
---------------------------------------------------------------------------
\3320\ ELCON Initial Comments at 21-22; see also DATA Reply
Comments at 14 (arguing that ``the Order No. 1000 status quo creates
an inexorable drive towards minimalist, short-term solutions'').
Despite its opposition to the NOPR proposal, ELCON sees some
potential benefit of encouraging joint ownership and cooperation-
based approaches, which ELCON thinks may help remedy the ```us
versus them' problems with the current regional planning process.''
ELCON Initial Comments at 23-24.
\3321\ WIRES Supplemental Comments at 4 (citing Rob Gramlich,
Richard Doying, & Zach Zimmerman, Grid Strategies, Fostering
Collaboration Would Help Build Needed Transmission (Feb. 2024)).
\3322\ Harvard ELI Supplemental Comments at 5.
---------------------------------------------------------------------------
1557. Though it does not support the NOPR proposal, Cypress Creek
contends that Order No. 1000 led to misaligned incentives such that
``competition today has not necessarily fostered just and
[[Page 49519]]
reasonable rates.'' \3323\ Similarly, American Municipal Power states
that many municipal electric systems are located on the fringe of an
incumbent transmission provider's system and would significantly
benefit from regional transmission projects that improve reliability,
although because such projects require coordination between two
incumbent transmission providers, they are ``largely ignored.'' \3324\
American Municipal Power also states that another disincentive to
incumbent transmission provider regional transmission facility
development is the possibility of losing the project to another
developer through the competitive process.\3325\ While not taking a
position on competitive transmission development processes, Indiana
Commission agrees that Order No. 1000 has produced unintended
consequences, including that transmission development now mostly takes
the form of transmission facilities not subject to competitive
transmission development processes,\3326\ and states that little
region-wide economic transmission development is occurring.\3327\
---------------------------------------------------------------------------
\3323\ Cypress Creek Reply Comments at 16.
\3324\ American Municipal Power Initial Comments at 31-32.
\3325\ Id. at 32. However, American Municipal Power states that
because regional transmission facilities typically traverse more
than one incumbent transmission provider's service territory,
allowing individual incumbent transmission providers to exercise a
Federal right of first refusal without other reforms also designed
to promote coordination and cooperation between such providers would
not ``result in a shift from local to regional projects.'' Id.
(referencing the ``interzonal nature of regional projects'').
\3326\ Indiana Commission Initial Comments at 12 (referring to
`` `immediate need reliability' or `end of life replacement' or
`supplemental' or `other' '' types of transmission facility
projects).
\3327\ Id.
---------------------------------------------------------------------------
1558. But some commenters, such as NextEra, contend that if
regional transmission investment has lagged behind expectations under
Order No. 1000, that is a planning issue, not an incentives issue, and
that some of the NOPR's proposed transmission planning reforms will
help lead to greater investment in regional transmission
facilities.\3328\ LS Power argues that the NOPR only generally observed
that there have been increases in local transmission facility
investment and static or declining investment in regional transmission
facilities, and did not specify particular transmission planning
regions in which this problem is occurring or which incumbent
transmission providers face perverse investment incentives.\3329\
However, other commenters, such as WIRES, contend that the elimination
of Federal rights of first refusal may be connected to flat or
declining regional transmission investment,\3330\ as suggested by the
NOPR.
---------------------------------------------------------------------------
\3328\ See NextEra Initial Comments at 18-19, 25; see also id.
at 43 (arguing that the NOPR proposal is insufficiently based on
speculation about potentially flawed investment incentives);
Americans for Fair Energy Prices Reply Comments at 5-6; Northwest
and Intermountain Initial Comments at 19-20 (arguing that even a
limited or conditional right of first refusal eliminates any
incentive for the incumbent transmission provider to reduce costs or
delays); Ohio Commission Federal Advocate Initial Comments at 18
(arguing that adopting the NOPR proposal would further misalign
incentives for incumbent transmission providers, not improve them).
\3329\ LS Power Initial Comments at 73-74. But see PJM Initial
Comments at 30 (questioning whether there are any ``regional
differences'' on this policy issue).
\3330\ WIRES Reply Comments at 2 (citing WIRES Initial Comments
at 13-14).
---------------------------------------------------------------------------
1559. Finally, several commenters argue that the Commission should
not adopt Federal right of first refusal reforms in this docket, but
rather explore those and related issues in another forum. Advanced
Energy United, Advanced Energy Buyers, State Agencies, and California
Commission, for example, urge the Commission to consider these issues
either in a different proceeding or at a technical conference.\3331\
Competition Advocates support alternative reforms that they argue can
better address the problem of perverse incentives, including better
enforcement of existing orders or taking action to reduce Order No.
1000 exemptions, and establishing an independent transmission
monitor.\3332\
---------------------------------------------------------------------------
\3331\ Advanced Energy Buyers Initial Comments at 4 n.6; AEE
Initial Comments at 4, 35-37; AEE Reply Comments at 31-33;
California Commission Initial Comments at 103-104; State Agencies
Initial Comments at 11; State Agencies Reply Comments at 6; see also
Chemistry Council Initial Comments at 8; Enel Initial Comments at 3;
Harvard ELI Initial Comments at 7-10; NESCOE Initial Comments at 11,
74-77.
\3332\ Competition Advocates Supplemental Comments at 3-4.
---------------------------------------------------------------------------
2. Comments on the NOPR's Joint Ownership Proposal
1560. Some commenters, including TAPS, highlight various ways in
which the Commission's joint ownership proposal would alleviate
challenges associated with current regional transmission planning
processes.\3333\ Some commenters, such as ELCON and the Omaha Public
Power District, argue that the Commission's joint ownership proposal
would benefit customers or encourage incumbent transmission providers
to pursue larger and more comprehensive transmission solutions to the
benefit of customers, and create incentives for transmission providers
to find beneficial opportunities and investments for joint ownership
partners and customers.\3334\ Other commenters agree that adopting the
NOPR proposal may incentivize incumbent transmission providers to
``look beyond the provincial'' needs and consider regional and
interregional solutions to transmission needs.\3335\
---------------------------------------------------------------------------
\3333\ See TAPS Initial Comments at 29-30 (stating that joint
ownership arrangements provide benefits such as ``improving
transmission planning to produce a more efficient build-out;
facilitating state siting; making it easier for [load-serving
entities] to accept cost increases associated with new transmission
by providing a hedge; and reducing the costs of needed
facilities''), id. at 34-37; see also Eversource Initial Comments at
36-39; Pattern Energy Initial Comments at 37; PPL Initial Comments
at 32-33; Vermont Electric and Vermont Transco Initial Comments at
4.
\3334\ See ELCON Initial Comments at 23-24; see also Cross
Sector Representatives Supplemental Comments at 1 (arguing that the
provisions are appropriately tied to collaborative and holistic
planning outcomes that provide clear benefits to customers and would
benefit the goals enunciated by the Commission throughout this
rulemaking process); Omaha Public Power Initial Comments at 5
(suggesting that the joint ownership proposal will likely encourage
neighboring incumbent transmission providers to develop facilities
that benefit multiple transmission providers under certain
conditions); Pattern Energy Initial Comments at 37 (asserting that
joint ownership arrangements will open the market to additional
investment opportunities for all parties).
\3335\ Tabors Caramanis Rudkevich Initial Comments at 2; see
also Citizens Energy Initial Comments at 9-10; PG&E Initial Comments
at 11 (arguing that a conditional Federal right of first refusal
will help mitigate development challenges by promoting collaboration
between partners).
---------------------------------------------------------------------------
1561. However, numerous commenters criticize the NOPR proposal and
its approach to joint ownership partner selection, especially its
inclusion of another incumbent transmission provider as a potential
joint ownership partner.\3336\ In general, these commenters contend
that incumbent transmission providers would be free to only team up
with fellow incumbent transmission providers with the same interests
and exclude others, leading to results that would be contrary to the
goals of Order No. 1000. As Anbaric states, two incumbent transmission
providers (or their affiliates) could ``team up and swap a portion of
their respective projects as a means to satisfy the joint ownership
requirement'' and thereby ``maintain the status quo'' \3337\ rather
[[Page 49520]]
than advance innovation, cost savings, or new entry. NextEra and others
decry this potential outcome, which could keep nonincumbent
transmission developers from obtaining investment opportunities.\3338\
Relatedly, several commenters argue that the NOPR proposal would raise
antitrust and competition concerns,\3339\ including US DOJ and FTC,
which argue that because the joint venture will not be facing pressure
to compete, the conditional Federal right of first refusal does not
create the incentive for incumbent transmission providers to seek out
the best partner.\3340\ In other words, US DOJ and FTC argue, the mere
existence of a joint venture partner does not bring competition to a
project, nor does it necessarily result in the best partner for a
project being selected, in terms of skill, cost, or innovation.\3341\
---------------------------------------------------------------------------
\3336\ E.g., Anbaric Initial Comments at 18; see also, e.g.,
APPA Initial Comments at 11-12; California Commission Initial
Comments at 80-88; Competition Coalition Initial Comments at 49-50;
LS Power Initial Comments at 92-94; Massachusetts Attorney General
Initial Comments at 48-49; New Jersey Commission Initial Comments at
31-33; NextEra Initial Comments at 49-51; NRECA Initial Comments at
58, 61; PJM States Initial Comments at 14; Policy Integrity Initial
Comments at 21-22; TANC Initial Comments at 13; TAPS Initial
Comments at 48-51; TAPS Reply Comments at 5-6 & n.25.
\3337\ Anbaric Initial Comments at 18.
\3338\ See Harvard ELI Initial Comments at 35; NextEra Initial
Comments at 49-51. In contrast, some commenters such as APPA urge
the Commission to adopt a requirement that incumbent transmission
providers offer joint ownership on reasonable terms at a load ratio
share level to all unaffiliated load-serving entities in the
incumbent transmission provider's footprint. See APPA Reply Comments
at 5-6; TAPS Initial Comments at 30-32 (advocating for a similar
proposal).
\3339\ See, e.g., Competition Coalition Initial Comments at 59-
62; LS Power Initial Comments at 122-125, 131-134; US DOJ & FTC
Initial Comments at 17-18.
\3340\ US DOJ & FTC Initial Comments at 17.
\3341\ Id. at 17-18; see also LS Power Initial Comments at 93
(arguing that the NOPR proposal would not require any independent
check that the incumbent transmission provider is partnering with
the entity that offers the most benefits).
---------------------------------------------------------------------------
1562. Commenters also highlight the potential for uncertainty,
litigation, and delays in attempting to implement the NOPR proposal.
Anbaric asserts that a conditional Federal right of first refusal could
add delays due to litigation over whether incumbent transmission
providers provided meaningful opportunities to third parties.\3342\ EEI
cautions against putting transmission providers in a position where
they must adjudicate what constitutes meaningful ownership of jointly
owned transmission facilities on a case-by-case basis, recommending
instead that the Commission provide guidance on the types of ownership
rights or operational obligations that will qualify and establish a
process for seeking Commission approval in a timely manner for other
arrangements.\3343\ MISO asserts that the process envisioned by the
NOPR would be time-consuming, as would developing a joint ownership
proposal, and asks that the Commission adopt clearly defined criteria
for joint ownership, such as a pro forma agreement, in order not to
impede transmission development.\3344\ National Grid calls for planning
authorities to be given the authority to determine the appropriate
criteria and conditions that constitute a valid joint ownership
arrangement, though it also asks for guidance regarding particular
types of combinations of potential joint owners.\3345\
---------------------------------------------------------------------------
\3342\ Anbaric Initial Comments at 16; see also Avangrid Initial
Comments at 18 (noting that establishing a conditional Federal right
of first refusal adds a layer of complexity to the development of
transmission); NYISO Initial Comments at 55-56 (asking the
Commission to consider the complications, disputes, and delays that
may arise from attempting to implement a conditional Federal right
of first refusal and other practical issues).
\3343\ EEI Initial Comments at 36-37; see also Ameren Initial
Comments at 44; DATA Initial Comments at 21-22; PJM Initial Comments
at 4-5, 51-52, 53-54.
\3344\ MISO Initial Comments at 80-83; see also APPA Initial
Comments at 4-7, 20-22 (outlining a detailed proposed implementation
process by which APPA believes incumbent transmission providers and
load-serving entities could work together and help avoid disputes
and delay); Invenergy Reply Comments at 7-8 (calling for the
adoption of pro forma agreements to ease implementation); TAPS
Initial Comments at 53-54 (expressing concern that the NOPR
proposal's anticipated period for formulation of joint ownership
agreements is too short).
\3345\ See National Grid Initial Comments at 37.
---------------------------------------------------------------------------
C. Commission Determination
1563. We decline to act at this time to finalize the NOPR proposal.
Rather, we will continue to consider the NOPR proposal and potential
Federal right of first refusal issues in other proceedings. We do not
adopt in this final order any changes to Order No. 1000's nonincumbent
transmission developer reforms.
1564. As summarized above, commenters raise substantial concerns
about whether incumbent transmission providers, as a result of Order
No. 1000's reforms, face perverse investment incentives that do not
adequately encourage those incumbent transmission providers to develop
and advocate for transmission facilities that benefit more than just
their own local retail distribution service territory or footprint. To
the extent that incumbent transmission providers face perverse
investment incentives, commenters also raise substantial concerns about
whether the NOPR proposal adequately and appropriately addresses those
incentives and whether adopting the proposal is necessary or
appropriate in carrying out the provisions of the FPA. Therefore, after
careful consideration of the record, we decline to finalize the NOPR
proposal at this time. The Commission will continue to consider
potential Federal right of first refusal reforms along with other
transmission reforms in the future.\3346\
---------------------------------------------------------------------------
\3346\ We note, for example, the ongoing proceeding in Docket
No. AD22-8 on Transmission Planning and Cost Management.
---------------------------------------------------------------------------
IX. Local Transmission Planning Inputs in the Regional Transmission
Planning Process
A. Need for Reform
1. NOPR
1565. In the NOPR, the Commission explained that it was concerned
that local transmission planning processes may lack adequate provisions
for transparency and meaningful input from stakeholders, and that
regional transmission planning processes may not adequately coordinate
with local transmission planning processes.\3347\ The Commission stated
in the NOPR that it was concerned that the lack of minimal standards or
specified procedures may contribute to inadequate transparency and
opportunities for stakeholders to engage in local transmission planning
processes.\3348\ Accordingly, the Commission stated that it believed
reforms to better ensure transparency and opportunities for stakeholder
engagement may be timely and important in light of the significant
investments in transmission that now occur through local transmission
planning processes.\3349\
---------------------------------------------------------------------------
\3347\ NOPR, 179 FERC ] 61,028 at P 398 & n. 639 (providing that
regional transmission planning processes should identify
``alternative transmission solutions that might meet the needs of
the transmission planning region more efficiently or cost-
effectively than solutions identified by individual utility
transmission providers in their local transmission planning
process'' (quoting Order No. 1000, 136 FERC ] 61,051 at P 148)).
\3348\ Id.
\3349\ See supra The Overall Need for Reform section.
---------------------------------------------------------------------------
1566. In addition, the Commission explained in the NOPR that it was
concerned that, given the age of the Nation's transmission
infrastructure, many incumbent transmission providers are replacing
aging transmission infrastructure as it reaches the end of its useful
life without evaluating whether those replacement transmission
facilities could be modified (i.e., right-sized) to more efficiently or
cost-effectively address regional transmission needs, and, more
generally, that transmission providers developing regional transmission
plans may lack the information necessary to identify the benefits that
regional transmission facilities may provide in deferring or
eliminating the need for in-kind replacements. Specifically, the NOPR
stated that in-kind replacements
[[Page 49521]]
of existing transmission facilities are managed by individual incumbent
transmission providers according to their company practices, and that
there is no requirement that transmission providers plan these in-kind
replacement transmission facilities through an Order No. 890-compliant
transmission planning process.\3350\ The Commission stated that,
because in-kind replacement of existing transmission facilities is not
subject to any transmission planning process, it was concerned that,
absent reform, there may be a lack of coordination between regional
transmission planning processes and in-kind replacement of existing
transmission facilities to identify whether these replacement
transmission facilities could be modified to more efficiently or cost-
effectively address transmission needs identified through Long-Term
Regional Transmission Planning. The Commission explained that this lack
of coordination may result in a regional transmission planning process
that fails to identify opportunities to right size planned in-kind
replacement transmission facilities and may result in the development
of duplicative or unnecessary transmission facilities that increase
costs to customers and render Commission-jurisdictional rates unjust
and unreasonable.\3351\
---------------------------------------------------------------------------
\3350\ NOPR, 179 FERC ] 61,028 at P 399 (citing S. Cal. Edison
Co., 164 FERC ] 61,160 at P 33; Cal. Pub. Utils. Comm'n v. Pac. Gas
& Elec. Co., 164 FERC ] 61,161, at P 68 (2018); PJM Interconnection,
L.L.C., 172 FERC ] 61,136, at PP 12, 89 (2020); PJM Interconnection,
L.L.C., 173 FERC ] 61,242, at P 54 (2020)).
\3351\ Id.
---------------------------------------------------------------------------
2. Comments
1567. Some commenters argue that the NOPR proposal regarding
improved transparency in local transmission planning processes is not
justified.\3352\ EEI argues that the Commission has not found that any
of the approved transmission planning processes under Order Nos. 890
and 1000 are unjust and unreasonable or unduly discriminatory or
preferential and that, absent such a finding, the Commission should not
move forward with changes to local transmission planning
processes.\3353\ Idaho Power states that the Commission should not use
a general rulemaking to address localized problems.\3354\ On the other
hand, Indicated PJM TOs state that the NOPR proposal to enhance
transparency in the local transmission planning processes is needed in
each transmission planning region to satisfy the requirements set forth
by Order No. 890.\3355\
---------------------------------------------------------------------------
\3352\ Dominion Initial Comments at 76 (citing NOPR, 179 FERC ]
61,028 at P 395 n.634); EEI Initial Comments at 40; Idaho Power
Initial Comments at 12-13.
\3353\ EEI Initial Comments at 40; see also Dominion Initial
Comments at 76.
\3354\ Idaho Power Initial Comments at 12-13.
\3355\ Indicated PJM TOs Initial Comments at 41 (citing Order
No. 890, 118 FERC ] 61,119 at PP 426-561).
---------------------------------------------------------------------------
1568. With respect to the Commission's proposed right-sizing
reforms, LS Power and NextEra argue that the NOPR fails to make
findings required under FPA section 206 to permit a right of first
refusal for right-sized projects. LS Power and NextEra assert that the
NOPR does not satisfy the first prong of FPA section 206, as it fails
to make an affirmative finding that either the regional transmission
planning process or the local transmission planning process are unjust
and unreasonable such that abandonment of the existing tariff
provisions is warranted.\3356\ Competition Coalition also asserts that
the Commission failed to demonstrate the alleged need for reform on any
section 206 finding.\3357\
---------------------------------------------------------------------------
\3356\ LS Power Initial Comments at 50-53 (citations omitted);
NextEra Initial Comments at 54-56 (citations omitted). A number of
commenters challenge the NOPR right-sizing proposal, including the
proposal to permit a Federal right of first refusal for certain
replacement facilities. We address those arguments below in the
Identifying Potential Opportunities to Right-Size Replacement
Transmission Facilities section below.
\3357\ Competition Coalition Initial Comments at 64.
---------------------------------------------------------------------------
3. Commission Determination
1569. Based on the record, we find that there is substantial
evidence to support the conclusion that existing requirements governing
transparency in local transmission planning processes and coordination
between local and regional transmission planning processes are unjust,
unreasonable, and unduly discriminatory or preferential. We therefore
adopt the preliminary findings in the NOPR concerning the need for
reform of the local transmission planning process and coordination
between the local and regional transmission planning processes,
including the evaluation of whether replacement transmission facilities
could be modified (i.e., right-sized) to more efficiently or cost-
effectively address transmission needs.\3358\
---------------------------------------------------------------------------
\3358\ Below, we clarify that the new transparency requirements
do not apply to transmission facilities that are otherwise exempt
from Order No. 890's transparency requirements, such as asset
management projects. See infra Enhanced Transparency of Local
Transmission Planning Inputs in the Regional Transmission Planning
Process section.
---------------------------------------------------------------------------
1570. Local and regional transmission planning processes serve
essential and complementary roles in ensuring that customers'
transmission needs are identified and met at a just and reasonable
cost, including through the identification, evaluation, and selection
of more efficient or cost-effective transmission solutions through
regional transmission planning. Information and transmission solutions
developed through local transmission planning serve as a foundation for
regional transmission planning, and it is therefore critical that the
processes are appropriately designed and aligned to ensure that
transmission providers and stakeholders have the information needed,
including from the local transmission planning process, to conduct
effective regional transmission planning. While the broader reforms
directed in this final order are focused on improving the regional
transmission planning process, we nonetheless have identified discrete
deficiencies in the local transmission planning process and its
coordination with the regional transmission planning process that also
must be addressed to ensure that Commission-jurisdictional rates are
just and reasonable.
1571. First, we find that local transmission planning processes
lack adequate provisions for transparency and meaningful input from
stakeholders. The Commission has recognized the critical role that
stakeholders serve in effective transmission planning,\3359\ and in
Order Nos. 890 and 1000, directed reforms to facilitate their
meaningful participation in both local and regional transmission
planning.\3360\ However, the record demonstrates that existing
transparency and coordination requirements in local transmission
planning do not consistently provide stakeholders with sufficient
information regarding the development of local transmission
plans.\3361\ We further find that the
[[Page 49522]]
absence of minimal standards or specified procedures to implement the
transmission planning principles required by Order No. 890 contributes
to inadequate transparency and opportunities for stakeholders to engage
in local transmission planning processes.
---------------------------------------------------------------------------
\3359\ See, e.g., Order No. 890, 118 FERC ] 61,119 at P 454
(``[C]ustomers must be included at the early stages of the
development of the transmission plan and not merely given an
opportunity to comment on transmission plans that were developed in
the first instance without their input.''); Order No. 1000, 136 FERC
] 61,051 at P 152 (``[A]bsent timely and meaningful participation by
all stakeholders, the regional transmission planning process will
not determine which transmission project or group of transmission
projects could satisfy local and regional needs more efficiently or
cost-effectively.'').
\3360\ See, e.g., Order No. 890, 118 FERC ] 61,119 at PP 454,
488, 557; Order No. 1000, 136 FERC ] 61,051 at P 152.
\3361\ E.g., OMS Initial Comments at 15 (``OMS members have
varying levels of oversight and visibility into the utility-driven,
local planning processes that are incorporated into the overall MISO
transmission expansion plan.''); Concerned Scientists ANOPR Initial
Comments at 24-31 (discussing challenges obtaining information to
assess projects developed through local transmission planning
processes) (citations omitted); New Jersey Commission ANOPR Initial
Comments at 6-7 (discussing limited information and analysis
provided regarding projects considered in local transmission
planning) (citations omitted).
---------------------------------------------------------------------------
1572. The combined effect of these deficiencies is that
stakeholders who wish to participate in transmission planning, at both
the local and regional level, may not be able to effectively do so.
More specifically, we find that, when engaging in the regional
transmission planning process, stakeholders lack sufficient information
about underlying local transmission needs and potential solutions that
is necessary to ensure that the more efficient or cost-effective
regional transmission solutions are identified, evaluated, and
selected. Given the recognized importance of stakeholder participation
in effective transmission planning, we find that reforms are needed to
ensure that Commission-jurisdictional local and regional transmission
planning processes remain just, reasonable, and not unduly
discriminatory or preferential. Furthermore, we believe that reforms to
better ensure more consistent implementation of the Order No. 890
transmission planning principles are timely and important in light of
the significant investments in transmission infrastructure that now
occur through local transmission planning processes.\3362\
---------------------------------------------------------------------------
\3362\ See supra The Overall Need for Reform section.
---------------------------------------------------------------------------
1573. Second, we find that additional coordination between the
local and regional transmission planning processes regarding
replacement of aging infrastructure is needed. The record shows that
many incumbent transmission providers are replacing aging transmission
infrastructure as it reaches the end of its useful life. For example,
we note that PJM estimated that roughly two-thirds of all PJM
transmission system assets are more than 40 years old, with some
transmission facilities approaching 90 years old.\3363\ NYISO
highlights that 80 percent of transmission lines in its footprint are
at least 50 years old and are either being replaced or will soon need
to be replaced.\3364\ Replacing these transmission facilities will
require substantial investment, which will directly affect Commission-
jurisdictional transmission rates. For example, the California
Commission notes that PG&E anticipates spending roughly $11 billion
between 2022 and 2027 to address aging transmission
infrastructure.\3365\
---------------------------------------------------------------------------
\3363\ See PJM Interconnection, L.L.C., The Benefits of the PJM
Transmission System 5 (2019), https://www.pjm.com/-/media/library/reports-notices/special-reports/2019/the-benefits-of-the-pjm-transmission-system.pdf. Moreover, AEP estimates that approximately
30 percent of its line miles and circuit breakers will need to be
replaced over the next 10 years. See AEP, Wolfe Utilities,
Midstream, & Clean Energy Conference 40 (Sept. 30, 2021), https://www.aep.com/Assets/docs/investors/eventspresentationsandwebcasts/WolfeConferencePresentation093021.pdf.
\3364\ NYISO Initial Comments at 58.
\3365\ California Commission Initial Comments at 110.
---------------------------------------------------------------------------
1574. However, because the Commission's existing requirements do
not obligate transmission providers to share sufficient information
regarding these replacement projects, transmission providers in the
regional transmission planning process are not consistently evaluating
whether those replacement transmission facilities could be modified
(i.e., right-sized) to more efficiently or cost-effectively address
transmission needs. We therefore find that the lack of a requirement
for transmission providers in each transmission planning region to
evaluate whether those replacement transmission facilities could be
modified (i.e., right-sized) to more efficiently or cost-effectively
address Long-Term Transmission Needs results in a regional transmission
planning process that fails to identify opportunities to right-size
planned in-kind replacement transmission facilities and may result in
the development of inefficiently sized or designed, duplicative, or
unnecessary transmission facilities that increase costs to customers
and render Commission-jurisdictional rates unjust and unreasonable.
1575. With respect to the claim by commenters that the Commission
lacks jurisdiction to impose the proposed transparency and coordination
requirements or that the Commission has not justified the
requirements,\3366\ we disagree. Consistent with Order Nos. 890 and
1000, the Commission has authority to establish requirements related to
local transmission planning processes and the inputs to regional
transmission planning processes.\3367\ Our findings above are supported
by substantial evidence in the record, and we address any concerns
regarding our remedy to address the transparency and coordination
deficiencies below.
---------------------------------------------------------------------------
\3366\ Dominion Initial Comments at 76; EEI Initial Comments at
40; Idaho Power Initial Comments at 12-13.
\3367\ See, e.g., Order No. 890, 118 FERC ] 61,119 at P 435
(``In order to limit the opportunities for undue discrimination . .
. and to ensure that comparable transmission service is provided by
all public utility transmission providers, including RTOs and ISOs,
the Commission concludes that it is necessary to amend the existing
pro forma OATT to require coordinated, open, and transparent
transmission planning on both a local and regional level.''); Order
No. 1000, 136 FERC ] 61,051 at PP 68, 148, 152.
---------------------------------------------------------------------------
1576. We also disagree with LS Power, Competition Coalition, and
NextEra's arguments regarding whether the Commission properly
demonstrated under FPA section 206 that existing rates are unjust,
unreasonable, or unduly discriminatory or preferential in instituting a
Federal right of first refusal for right-sized replacement transmission
facilities.\3368\ First, we clarify that the Commission is not finding
that existing transmission planning processes are unjust, unreasonable,
or unduly discriminatory or preferential due to a lack of a Federal
right of first refusal for these facilities. Rather, we find here that
transmission providers' OATTs are unjust and unreasonable due to the
lack of right-sizing requirements that may lead to the identification,
evaluation, and selection of more efficient or cost-effective Long-Term
Regional Transmission Facilities. As discussed above, the record
demonstrates that many incumbent transmission providers are replacing
aging transmission infrastructure as it reaches the end of its useful
life without evaluating, through the regional transmission planning
process, whether those replacement transmission facilities could be
modified (i.e., right-sized) to more efficiently or cost-effectively
address transmission needs. As a result of this identified deficiency,
we find that transmission providers' OATTs are unjust and unreasonable.
We address LS Power, NextEra, and other commenters' concerns regarding
the Commission's proposed replacement rate, including our findings
regarding a Federal right of first refusal for right-sized replacement
transmission facilities, below.
---------------------------------------------------------------------------
\3368\ Competition Coalition Initial Comments at 64; LS Power
Initial Comments at 51-53; NextEra Initial Comments at 54-56.
---------------------------------------------------------------------------
1577. Because we find that the Commission's existing requirements
governing transparency in local transmission planning processes and
coordination between local and regional transmission planning processes
are insufficient to ensure just and reasonable and not unduly
discriminatory or preferential rates, we are now requiring, pursuant to
FPA section 206, that transmission providers
[[Page 49523]]
adopt, with certain modifications, the two reforms that the Commission
identified in the NOPR: (1) enhance the transparency of local
transmission planning processes; and (2) require transmission providers
to evaluate whether transmission facilities that need replacing can be
``right-sized'' to more efficiently or cost-effectively address Long-
Term Transmission Needs identified in Long-Term Regional Transmission
Planning.\3369\ We find that the first reform will result in
transmission providers providing enhanced transparency for stakeholders
while providing those same stakeholders with opportunities to more
effectively engage in local and regional transmission planning
processes. We find that the second reform will result in transmission
providers identifying, evaluating, and selecting replacement
transmission facilities that more efficiently or cost-effectively
address Long-Term Transmission Needs. Taken together, we find that
these reforms will ensure that Commission-jurisdictional rates are just
and reasonable and not unduly discriminatory or preferential.
---------------------------------------------------------------------------
\3369\ NOPR, 179 FERC ] 61,028 at PP 400-403.
---------------------------------------------------------------------------
B. Enhanced Transparency of Local Transmission Planning Inputs in the
Regional Transmission Planning Process
1. NOPR Proposal
1578. In the NOPR, the Commission proposed to require transmission
providers in each transmission planning region to revise the regional
transmission planning process in their OATTs with additional provisions
to enhance transparency of: (1) the criteria, models, and assumptions
that they use in their local transmission planning process; (2) the
local transmission needs that they identify through that process; and
(3) the potential local or regional transmission facilities that they
will evaluate to address those local transmission needs.\3370\ The
Commission explained that transmission providers would be required to
establish an iterative process that would provide stakeholders with
meaningful opportunities to participate and provide feedback on local
transmission planning throughout the regional transmission planning
process.\3371\ The Commission proposed to require that the regional
transmission planning process include at least three publicly-noticed
stakeholder meetings concerning the local transmission planning process
of each transmission provider that is a member of the transmission
planning region before a transmission provider's local transmission
plan can be incorporated into the transmission planning region's
planning models.\3372\
---------------------------------------------------------------------------
\3370\ NOPR, 179 FERC ] 61,028 at P 400.
\3371\ Id.
\3372\ Id.
---------------------------------------------------------------------------
1579. Specifically, the Commission proposed to require transmission
providers in each transmission planning region, prior to the submission
of local transmission planning information to the transmission planning
region for inclusion in the regional transmission planning process, to
convene, collectively, as part of the regional transmission planning
process, a stakeholder meeting to review the criteria, assumptions, and
models related to each transmission provider's local transmission
planning (Assumptions Meeting). Next, no fewer than 25 calendar days
after the Assumptions Meeting, transmission providers that are members
of the transmission planning region would be required to convene,
collectively, as part of the regional transmission planning process, a
stakeholder meeting to review identified reliability criteria
violations and other transmission needs that drive the need for local
transmission facilities (Needs Meeting). Finally, the Commission
proposed to require that, no fewer than 25 calendar days after the
Needs Meeting, transmission providers that are members of the
transmission planning region convene, collectively, as part of the
regional transmission planning process, a stakeholder meeting to review
potential solutions to those reliability criteria violations and other
transmission needs (Solutions Meeting). The Commission also proposed to
require that all materials for stakeholder review during these three
meetings be publicly posted and that stakeholders have opportunities
before and after each meeting to submit comments.\3373\
---------------------------------------------------------------------------
\3373\ Id. P 401.
---------------------------------------------------------------------------
1580. The Commission preliminarily found that these proposed
requirements will result in needed additional transparency into local
transmission planning processes, which inform the regional transmission
planning process in a transmission planning region.\3374\
---------------------------------------------------------------------------
\3374\ Id. P 402.
---------------------------------------------------------------------------
2. Comments
a. Interest in Enhanced Transparency of Local Transmission Planning
Inputs
1581. Many commenters support the NOPR proposal.\3375\ ITC argues
that the Commission's proposed transparency requirements strike an
appropriate balance between the need for oversight and the need to
timely address asset management needs.\3376\ Southeast PIOs state that
closer coordination between the regional and local transmission
planning processes would help to ensure that the local process does not
dull the effectiveness of the regional process.\3377\ Vermont State
Entities support enhancing transparency and visibility of local
transmission planning processes and coordinating with Long-Term
Regional Transmission Planning and other processes, including the
generator interconnection process.\3378\ City of New Orleans Council
states that increased transparency, collaboration, and coordination
between the regional and local transmission planning processes will
result in more efficient local transmission development.\3379\ OMS
asserts that enhanced transparency will enable retail regulators to
more effectively participate in identifying the best set of projects to
meet both local and regional needs.\3380\
---------------------------------------------------------------------------
\3375\ See AEE Initial Comments at 3; AEP Reply Comments at 10;
APPA Initial Comments at 47; Breakthrough Energy Initial Comments at
19; Center for Biological Diversity Initial Comments at 28; Certain
TDUs Initial Comments at 13; City of New Orleans Council Initial
Comments at 11; Clean Energy Associations Initial Comments at 36;
Clean Energy Buyers Initial Comments at 33; Colorado Consumer
Advocates Initial Comments at 30-31; Cross Sector Representatives
Supplemental Comments at 1; Exelon Initial Comments at 3, 51-52;
Indicated PJM TOs Initial Comments at 40; Interwest Initial Comments
at 17-18; ITC Initial Comments at 45-47; National and State
Conservation Organizations Initial Comments at 2; New York Transco
Initial Comments at 1; NextEra Initial Comments at 66-67; Northwest
and Intermountain Initial Comments at 20; OMS Initial Comments at
16; PJM States Initial Comments at 4-6; Resale Iowa Initial Comments
at 8; Resale Iowa Reply Comments at 5; SEIA Initial Comments at 25-
26; Shell Initial Comments at 34; Southeast PIOs Initial Comments at
54-55; Vermont State Entities Initial Comments at 10.
\3376\ ITC Initial Comments at 45-47 (citations omitted).
\3377\ Southeast PIOs Initial Comments at 54-55.
\3378\ Vermont State Entities Initial Comments at 10 (citing
NOPR, 179 FERC ] 61,028 at P 400).
\3379\ City of New Orleans Council Initial Comments at 11.
\3380\ OMS Initial Comments at 16.
---------------------------------------------------------------------------
1582. Colorado Consumer Advocates state that the Commission must
ensure that transmission providers maintain coordinated, open, and
transparent transmission planning processes on both a local and
regional level that meet stakeholder needs.\3381\ Interwest asserts
that the NOPR proposal is needed to incentivize the coordination of
generation and resource planning and transmission planning beyond state
lines, adding that transparency measures, such as a process for
information sharing, could allow customers or stakeholders to evaluate
or replicate the findings from transmission
[[Page 49524]]
providers and reduce after-the-fact disputes regarding allocated
costs.\3382\
---------------------------------------------------------------------------
\3381\ Colorado Consumer Advocates Initial Comments at 17, 20-
21.
\3382\ Interwest Initial Comments at 17-18. As an example,
Interwest cites WestConnect's Colorado Coordinated Planning Group,
which conducts transmission planning through task forces and work
groups consisting of stakeholders. Id.
---------------------------------------------------------------------------
1583. Exelon and Indicated PJM TOs note that the NOPR proposal
mirrors PJM TOs' local transmission planning process.\3383\ Indicated
PJM TOs state that the NOPR proposal will help to ensure the
coordination of local and regional transmission planning while
preserving transmission owner responsibility for local transmission
planning.\3384\ Indicated PJM TOs state that the PJM Attachment M-3
process avoids duplication of projects between local and regional
transmission planning processes.\3385\ Clean Energy Associations state
that each transmission planning region should have the opportunity to
regularly review local transmission planning criteria for consistency
with regional transmission planning, as PJM's manuals require.\3386\
---------------------------------------------------------------------------
\3383\ Exelon Initial Comments at 3-4, 51-52 (citing PJM, Intra-
PJM Tariffs, OATT, attach. M-3 (1.0.0)); see Indicated PJM TOs
Initial Comments at 42-43.
\3384\ Indicated PJM TOs Initial Comments at 42-43.
\3385\ Id. at 42.
\3386\ Clean Energy Associations Initial Comments at 37 (citing
PJM Manual 14B, section 1.1 Planning Process Work Flow).
---------------------------------------------------------------------------
1584. Clean Energy Buyers state that existing local transmission
planning has not met expectations for openness, coordination, and
transparency, and that the NOPR proposal will help remedy such
deficiencies and better identify cost-effective transmission
projects.\3387\ Northwest and Intermountain agree that the Commission
should reform local transmission planning processes to enhance
transparency and provide meaningful opportunities for public
input.\3388\ Similarly, Resale Iowa asserts that MISO's stakeholder
processes do not address local transmission planning issues, especially
those related to asset management, end-of-life, and other forms of
local transmission planning that are exempt from Order No. 890's
transmission planning requirements. Thus, Resale Iowa contends, its
members believe they must bear the cost of new or upgraded transmission
facilities without the opportunity to discuss less costly
alternatives.\3389\
---------------------------------------------------------------------------
\3387\ Clean Energy Buyers Initial Comments at 33.
\3388\ Northwest and Intermountain Initial Comments at 20.
\3389\ Resale Iowa Reply Comments at 4-5.
---------------------------------------------------------------------------
1585. National and State Conservation Organizations suggest that
early and consistent community engagement are key elements to
successful development and timely completion of transmission projects,
as the voices and concerns of affected local communities must be heard
and acted upon to prevent environmental injustices and environmental
damage.\3390\ WE ACT states that, in addition to coordination with
state entities, there must also be meaningful engagement and robust
input from affected and overburdened communities so that states and
transmission providers are aware of the potential harms of siting
transmission projects in environmental justice communities. WE ACT
recommends that the Commission, its Office of Public Participation,
state officials, and transmission providers familiarize themselves with
several key documents relating to environmental justice to ensure
meaningful community engagement and to inform comprehensive
environmental justice analyses to reduce or eliminate undue
burdens.\3391\
---------------------------------------------------------------------------
\3390\ National and State Conservation Organizations Initial
Comments at 2.
\3391\ WE ACT Initial Comments at 5-6 (citing U.S. Env't Prot.
Agency, Promising Practices for EJ Methodologies in NEPA Reviews
(Mar. 2016), https://www.epa.gov/environmentaljustice/ej-iwg-promising-practices-ej-methodologies-nepa-reviews; U.S. Env't Prot.
Agency, Technical Guidance for Assessing Environmental Justice in
Regulatory Analysis (June 2016), https://www.epa.gov/sites/default/files/2016-06/documents/ejtg_5_6_16_v5.1.pdf; The Principles of
Environmental Justice (EJ), Energy Justice Network, https://www.ejnet.org/ej/principles.pdf; Jemez Principles of Democratic
Organizing, Energy Justice Network, https://www.ejnet.org/ej/jemez.pdf).
---------------------------------------------------------------------------
b. Suggested Modifications to the NOPR Proposal
1586. Some commenters support the NOPR proposal, but also suggest
modifications to make it more effective or request that the Commission
provide flexibility for transmission planning regions to determine the
best manner to meet the requirements.\3392\ NARUC requests flexibility
for transmission planning regions to determine the timeline for
stakeholder processes.\3393\ NRECA requests that the Commission allow
transmission planning regions that currently have transparent processes
to maintain them.\3394\
---------------------------------------------------------------------------
\3392\ See ACORE Initial Comments at 18-19; AEP Initial Comments
at 7, 40-41, 43-44; Ameren Initial Comments at 46-47; NARUC Initial
Comments at 58-59; NESCOE Initial Comments at 77-78; North Carolina
Commission and Staff Initial Comments at 18-20; NRECA Initial
Comments at 65-66; NYISO Initial Comments at 9, 57-58; TANC Initial
Comments at 11; WE ACT Initial Comments at 5-6; WIRES Initial
Comments at 8-10.
\3393\ NARUC Initial Comments at 58-59 (citing NOPR, 179 FERC ]
61,028 at PP 400-401).
\3394\ NRECA Initial Comments at 65-66; see also Ameren Initial
Comments at 46 (citing Ameren ANOPR Initial Comments at 20-21).
---------------------------------------------------------------------------
1587. TANC encourages the Commission to provide regional
flexibility by allowing transmission providers to propose on compliance
alternative frameworks for consideration of local transmission plans in
the regional transmission planning process and allow transmission
planning regions to consider the burden versus benefit of such as a
requirement to maximize transparency and project efficiencies.\3395\
---------------------------------------------------------------------------
\3395\ TANC Initial Comments at 11 (citing NOPR, 179 FERC ]
61,028 at PP 400, 402).
---------------------------------------------------------------------------
1588. NESCOE contends that aspects of the proposal are too
prescriptive, such as the Commission dictating the number of
stakeholder meetings. However, NESCOE states that enhanced transparency
could help states and ratepayers better understand proposed
transmission facilities and the costs associated with them.\3396\
NESCOE states that stakeholders should have meaningful opportunities to
participate and provide feedback on local transmission planning
throughout the regional transmission planning process, asserting that
transmission owners in ISO-NE currently do little more than present
their proposals for in-kind replacements of existing transmission
infrastructure to ISO-NE's Planning Advisory Committee.\3397\
---------------------------------------------------------------------------
\3396\ NESCOE Initial Comments at 77-78 (citing NOPR, 179 FERC ]
61,028 at P 400).
\3397\ Id.; NESCOE Reply Comments at 6 (citation omitted).
---------------------------------------------------------------------------
1589. ACORE states that the proposed stakeholder involvement in
local transmission planning is beneficial but that the NOPR proposal
lacks clarity on whether transmission providers must consider local
transmission projects alongside other options in Long-Term Regional
Transmission Planning.
1590. Joint Consumer Advocates argue that, while the NOPR proposal
will increase transparency, it will not address the inability of
consumer advocates to meaningfully review planning inputs or models
because the inputs are not maintained in a format that enables
stakeholders to review them, understand the assumptions, or replicate
the transmission planning results, as contemplated in Order No.
890.\3398\ Pine Gate recommends that the Commission require that
transmission providers make available to stakeholders information about
the local transmission planning process for review and comment prior to
the finalization or approval of the local transmission plan.\3399\
---------------------------------------------------------------------------
\3398\ Joint Consumer Advocates Initial Comments at 21-22.
\3399\ Pine Gate Initial Comments at 49-50.
---------------------------------------------------------------------------
[[Page 49525]]
c. Concern With the NOPR Proposal
1591. Several commenters state that they oppose or have concerns
with the NOPR proposal.\3400\ Ohio Commission Federal Advocate argues
that the NOPR proposal is of limited value given that it does not
require a more comprehensive review of local transmission projects;
instead, these projects will continue to be chosen, designed, and
approved by the transmission owner.\3401\ Similarly, American Municipal
Power states that new transmission projects that expand or enhance the
transmission grid and have regional benefits should be planned by the
regional transmission entity and not by individual transmission owners.
Further, American Municipal Power asserts that use of the PJM
Attachment M-3 process, which American Municipal Power contends the
NOPR ``essentially'' proposes to require nationwide, has resulted in
additional balkanization of the transmission planning process, has
increased the problem of planning based on individual transmission
owners' criteria for determining need, and has disenfranchised PJM as
the regional transmission planner.\3402\
---------------------------------------------------------------------------
\3400\ See American Municipal Power Initial Comments at 13-25;
APS Initial Comments at 12-13; Avangrid Initial Comments at 13-15;
CAISO Initial Comments at 7, 47-51; California Water Initial
Comments at 5-8; DC and MD Offices of People's Counsel Initial
Comments at 6-7; Dominion Initial Comments at 69-70; EEI Initial
Comments at 40; Eversource Initial Comments at 47-49; Idaho Power
Initial Comments at 12-13; MISO Initial Comments at 84-86; MISO TOs
Initial Comments at 28-31; National Grid Initial Comments at 39-40;
New York TOs Initial Comments at 16-17; Pennsylvania Commission
Initial Comments at 20; PG&E Initial Comments at 15-18; PPL Initial
Comments at 35-36; Xcel Initial Comments at 16-17.
\3401\ See Ohio Commission Federal Advocate Initial Comments at
20-21 (citing NOPR, 179 FERC ] 61,028 (Christie, Comm'r, concurring
at P 16)).
\3402\ American Municipal Power Initial Comments at 17; see
American Municipal Power Supplemental Comments at 1, 6 (citations
omitted).
---------------------------------------------------------------------------
1592. Relatedly, Pennsylvania Commission states that enhancing
transparency in local transmission planning is a laudable goal but
notes that the proposal will not enhance PJM's process because the NOPR
proposal adopts the existing PJM Attachment M-3 process.\3403\
---------------------------------------------------------------------------
\3403\ Pennsylvania Commission Initial Comments at 20-21 (citing
NOPR, 179 FERC ] 61,028 at PP 399-400).
---------------------------------------------------------------------------
1593. Several commenters argue that the existing regional
transmission planning process in their transmission planning region is
already transparent and therefore oppose the NOPR proposal.\3404\ New
York TOs assert that New York's regional and local transmission
planning processes almost fully satisfy the proposed requirements and,
as such, the Commission should allow NYISO to retain these
processes.\3405\ MISO argues that the additional requirements proposed
in the NOPR are not needed in an RTO such as MISO with a fully
developed, open, and transparent transmission planning process in
effect.\3406\ MISO TOs agree, stating that MISO's existing processes
provide for transparency in local transmission planning through
subregional planning meetings, published materials, and workshops
throughout the transmission planning process.\3407\
---------------------------------------------------------------------------
\3404\ APS Initial Comments at 12-13; Avangrid Initial Comments
at 13-15; CAISO Initial Comments at 46-50; Dominion Initial Comments
at 69; Eversource Initial Comments at 46-49; MISO Initial Comments
at 84-86; MISO TOs Initial Comments at 29-31; National Grid Initial
Comments at 39; New York TOs Initial Comments at 16-17; Pennsylvania
Commission Initial Comments at 20; PG&E Initial Comments at 16-18.
\3405\ New York TOs Initial Comments at 7.
\3406\ MISO Initial Comments at 84-85.
\3407\ MISO TOs Initial Comments at 29-31 (citing MISO Business
Practice Manual, Transmission Planning, BPM-20, section 4.1; MISO,
FERC Electric Tariff, MISO OATT, attach. FF (Transmission Expansion
Planning Protocol) (90.0.0), Sec. I.C.9; MISO, Subregional Planning
Meeting, https://www.misoenergy.org/engage/committees/subregional-planning-meeting/; Midwest Indep. Transmission Sys. Operator, Inc.,
142 FERC ] 61,215, at PP 80, 114 (2013), order on reh'g, 144 FERC ]
61,020 (2013), order on reh'g & compliance, 147 FERC ] 61,127
(2014), aff'd sub nom. MISO Transmission Owners v. FERC, 819 F.3d
329 (7th Cir. 2016)).
---------------------------------------------------------------------------
1594. CAISO states that the Commission should not disrupt existing
processes that are working efficiently, arguing that its transmission
planning process already considers both local and regional assumptions,
needs, and solutions as part of a single integrated process.\3408\ PG&E
agrees that the NOPR proposal is unnecessary for California utilities
and CAISO because many CAISO transmission owners already have extensive
stakeholder programs. Therefore, PG&E states, the Commission should
clarify that transmission providers are not required to enhance the
transparency of local transmission planning processes where such
transparent processes already exist.\3409\
---------------------------------------------------------------------------
\3408\ CAISO Initial Comments at 47-50 (citations omitted).
\3409\ PG&E Initial Comments at 15-18.
---------------------------------------------------------------------------
1595. In addition, PG&E argues that the Commission should revise
the NOPR proposal to state that the proposed enhancements to the local
transmission planning process should not apply to asset management
projects, including in-kind replacements, that are outside the scope of
Order No. 890.\3410\ PG&E asserts that including asset management
projects would significantly increase the volume and complexity of
regional and local transmission planning and potentially delay needed
repairs and maintenance. PG&E further states that all of PG&E's asset
replacement projects are already scrutinized through the annual update
to its formula transmission rate.\3411\
---------------------------------------------------------------------------
\3410\ Id. at 15-16 (citing Cal. Pub. Utils. Comm'n v. Pac. Gas
& Elec., 164 FERC ] 61,161 at P 66).
\3411\ PG&E Reply Comments at 6-7.
---------------------------------------------------------------------------
1596. Eversource contends that the current local transmission
planning process in New England, which is based on the principles in
Order No. 890, is largely consistent with the Commission's proposed
transparency principles and has worked well.\3412\ Similarly, APS
states that it currently uses its local transmission plans in the base
model assumptions for its regional transmission planning process and
provides stakeholders with an opportunity for input twice a year in
public meetings as required by Order No. 890.\3413\
---------------------------------------------------------------------------
\3412\ Eversource Initial Comments at 46-47 (citing ISO New
England, Inc., Transmittal, Docket No. OA08-58 (filed Dec. 7,
2007)).
\3413\ APS Initial Comments at 12 (citing Order No. 890, 118
FERC ] 61,119 at PP 257-258, 451).
---------------------------------------------------------------------------
1597. Some commenters request that the Commission adopt a less
prescriptive reform that outlines principles or goals for transparency
and allow each transmission provider to either explain how its existing
local transmission planning process already complies with those
principles or propose targeted modifications to bring its existing
process into compliance with the new requirements.\3414\ New York TOs
note that efforts to improve transparency between local and regional
transmission planning are beginning in NYISO, and they recommend that
the Commission allow NYISO and New York TOs to demonstrate on
compliance how any resulting enhancements will meet or exceed any new
requirements.\3415\ Vermont Electric and Vermont Transco suggest that
the Commission adopt a performance-based approach under which the
Commission would specify expectations for transparency in local
transmission planning processes and then allow transmission providers
to determine how they will achieve those goals within longer
timelines.\3416\
---------------------------------------------------------------------------
\3414\ See Avangrid Initial Comments at 15; EEI Initial Comments
at 40; Eversource Initial Comments at 48; Kansas Commission Initial
Comments at 17; MISO Initial Comments at 84; MISO TOs Initial
Comments at 31; National Grid Initial Comments at 39; New York TOs
Initial Comments at 7, 16-17; Xcel Initial Comments at 17.
\3415\ See New York TOs Initial Comments at 6-7, 16-17
(citations omitted).
\3416\ Vermont Electric and Vermont Transco Initial Comments at
5.
---------------------------------------------------------------------------
[[Page 49526]]
1598. Several commenters argue that the NOPR proposal is too
prescriptive or may interfere with existing processes.\3417\ Eversource
states that, if the Commission adopts a more prescriptive approach to
local transmission planning, it could conflict with existing, state-
jurisdictional planning processes for local transmission projects,
creating barriers to distribution facility upgrades that are needed to
support expanded use of distributed energy resources and load growth
from electrification.\3418\ Dominion cautions against adding more
process when transmission providers already participate in extensive
local transmission planning processes that consider Long-Term Regional
Transmission Planning and stakeholder positions.\3419\ Avangrid agrees,
asserting that the NOPR proposal could override existing processes that
have been established over years of stakeholder consensus
building.\3420\ PPL and American Municipal Power state that the NOPR
proposal may not be appropriate for all transmission planning regions
and may interfere with efficient and well-functioning local
transmission planning.\3421\
---------------------------------------------------------------------------
\3417\ Avangrid Initial Comments at 13; CAISO Initial Comments
at 7-8, 47, 50; Dominion Initial Comments at 70; Eversource Initial
Comments at 47-48; MISO Initial Comments at 86; PG&E Initial
Comments at 17-18; PPL Initial Comments at 36; Xcel Initial Comments
at 16-17.
\3418\ Eversource Initial Comments at 49.
\3419\ Dominion Initial Comments at 69-70.
\3420\ Avangrid Initial Comments at 13.
\3421\ American Municipal Power Initial Comments at 16; PPL
Initial Comments at 36.
---------------------------------------------------------------------------
1599. Certain commenters also argue that the NOPR proposal is
unduly burdensome.\3422\ APS argues that the NOPR proposal could delay
local transmission planning and prevent APS from providing necessary
services.\3423\ National Grid asserts that the NOPR proposal ignores
the reality that local transmission planning processes address
different needs than the regional transmission planning process.
National Grid argues that the proposal will introduce delay and
uncertainty in both the local and regional transmission planning
processes, disrupting currently effective procedures at a time when
participants in the regional transmission planning process should be
focused on Long-Term Regional Transmission Planning.\3424\
---------------------------------------------------------------------------
\3422\ See Dominion Initial Comments at 68; Eversource Initial
Comments at 49; National Grid Initial Comments at 39-40; Xcel
Initial Comments at 16-17.
\3423\ APS Initial Comments at 13.
\3424\ National Grid Initial Comments at 39-40.
---------------------------------------------------------------------------
1600. In addition, National Grid argues that the NOPR proposal will
complicate transmission planning because individual transmission
providers in each transmission planning region will need to integrate
their local transmission planning efforts into the regional
transmission planning process. Further, National Grid states that in
multi-state RTO/ISO transmission planning regions, it could also lead
to second guessing individual state policies as part of the regional
transmission planning process. National Grid also avers that regional
transmission planners, such as NYISO and ISO-NE, may not have
visibility into the operation of lower voltage local transmission
facilities and therefore may not have the expertise that is needed to
consider local transmission needs as part of the regional transmission
planning process.\3425\
---------------------------------------------------------------------------
\3425\ Id.
---------------------------------------------------------------------------
d. Specific Stakeholder Meeting Requirements
1601. With respect to the length of time between stakeholder
meetings, some commenters state that the 25-day minimum period between
meetings in the NOPR proposal is too short.\3426\ PIOs state the
Commission should require transmission providers to submit local
transmission planning information, including information concerning
planned local transmission projects, with enough time for the regional
transmission planning process to effectively find, propose, approve,
and construct cost-effective and beneficial regional alternatives where
appropriate.\3427\
---------------------------------------------------------------------------
\3426\ American Municipal Power Initial Comments at 24;
Northwest and Intermountain Initial Comments at 21; PIOs Initial
Comments at 51-54; TAPS Initial Comments at 6, 62.
\3427\ PIOs Initial Comments at 51-52, 54 (citing PIOs ANOPR
Initial Comments at 92-94; Concerned Scientists ANOPR Initial
Comments at 24-31).
---------------------------------------------------------------------------
1602. American Municipal Power contends that the NOPR proposal
fails to identify whether and when transmission providers must provide
information in advance of the three meetings. Moreover, American
Municipal Power argues, 25 days between meetings is too short, even
assuming all of the models, criteria, and needs are shared with
stakeholders sufficiently in advance. Further, American Municipal Power
states that the time between the Needs and Solutions Meetings should be
based on the time required for transmission providers to incorporate
comments received during the Needs Meeting and develop responses.\3428\
---------------------------------------------------------------------------
\3428\ American Municipal Power Initial Comments at 24.
---------------------------------------------------------------------------
1603. Eversource argues that the proposed meeting schedules are not
workable in New England, where regional transmission planning studies
focus on sub-areas of the transmission system and proceed on different
timelines. Moreover, Eversource contends that it is not feasible in New
England to have a three-meeting process that aligns with ISO-NE's
annual transmission planning cycle because no such annual planning
cycle exists.\3429\
---------------------------------------------------------------------------
\3429\ Eversource Initial Comments at 47.
---------------------------------------------------------------------------
1604. Dominion, Eversource, and Xcel state that the three separate
stakeholder meetings to review assumptions, needs, and solutions are
unnecessary and will increase workload without any benefit.\3430\ Xcel
contends that a single meeting that addresses the transparency
requirements of Order Nos. 890 and 1000, as well as any requirements
from the final order, would be more efficient than the NOPR
proposal.\3431\ NESCOE asserts that the final order should not dictate
the number of stakeholder meetings.\3432\ MISO states that the
Commission should allow each transmission planning region to determine
the timing of the iterative meetings, as well as the specific
information to be covered at the meetings.\3433\
---------------------------------------------------------------------------
\3430\ Dominion Initial Comments at 68; Eversource Initial
Comments at 47-48; Xcel Initial Comments at 17.
\3431\ Xcel Initial Comments at 16-17.
\3432\ NESCOE Initial Comments at 78 (citation omitted).
\3433\ MISO Initial Comments at 84.
---------------------------------------------------------------------------
1605. TAPS states that the Commission should require transmission
providers to post their criteria, models, and assumptions so that
stakeholders can evaluate or replicate their findings. Moreover, TAPS
argues, the Commission should require that transmission providers
distribute this information ``sufficiently in advance'' (and not just
``in advance,'' as the NOPR proposed) of each meeting to allow
stakeholders to review and evaluate the information.\3434\ Finally,
TAPS states that a second Solutions Meeting would provide a meaningful
opportunity to consider alternatives.\3435\
---------------------------------------------------------------------------
\3434\ TAPS Initial Comments at 61 (citing NOPR, 179 FERC ]
61,028 at P 402).
\3435\ Id. at 62.
---------------------------------------------------------------------------
1606. Likewise, American Municipal Power recommends that the
Commission require a minimum of two Solutions Meetings, with the
transmission provider presenting the solutions at the first meeting and
the final solution, including alternatives considered, at the second.
Further, American Municipal Power recommends that the first Solutions
Meeting be no sooner than 90 days after the Needs Meeting and the
second
[[Page 49527]]
Solutions Meeting no sooner than 30 days after the first Solutions
Meeting. To the extent the Commission does not require a second
Solutions Meeting, American Municipal Power recommends that it require
transmission providers to provide additional clarity regarding how
alternatives were developed and why they were not selected during the
single Solutions Meeting.\3436\
---------------------------------------------------------------------------
\3436\ American Municipal Power Initial Comments at 24-25.
---------------------------------------------------------------------------
1607. While PJM States support requiring Assumptions, Needs, and
Solutions Meetings as part of local transmission planning processes,
similar to PJM's existing Attachment M-3 process, they express concern
that PJM's process is not sufficiently responsive and that the growth
of transmission-related costs in PJM is occurring without effective
oversight.\3437\ PJM States reference PJM's requirement that
transmission providers provide information on their local transmission
plan and consider any comments received, but state that they are not
required to ``meaningfully respond to, engage with, or incorporate''
these comments.\3438\
---------------------------------------------------------------------------
\3437\ PJM States Initial Comments at 4-5 (citing PJM, 2021
Regional Transmission Planning Expansion Plan 290 (Mar. 2022),
https://www.pjm.com/-/media/library/reports-notices/2021-rtep/2021-rtep-report.ashx).
\3438\ Id. at 6 (citing PJM, Intra-PJM Tariffs, OATT, attach. M-
3 (1.0.0), section (c) 1-6).
---------------------------------------------------------------------------
1608. California Commission notes that the key elements of the
California stakeholder processes that may be relevant for the
Commission to consider including in a final order to increase
transparency into local transmission planning include: (1) detailed
project and capital expenditure data; (2) ample time to review proposed
capital forecasts; (3) the ability for stakeholders to issue data
requests and receive responses; (4) in-depth stakeholder meetings; and
(5) consideration of stakeholder comments.\3439\
---------------------------------------------------------------------------
\3439\ California Commission Initial Comments at 112-113.
---------------------------------------------------------------------------
1609. New England for Offshore Wind argues that all transmission
planning processes should include transparency into the evaluation of
alternative options that could optimize the performance of renewable
energy, as well as justification of proposed transmission projects
based on how they compare to no action alternatives.\3440\ NRG
encourages the Commission to require that the local transmission
planning process produce an estimated rate impact for each year if the
local transmission plan were to be executed.\3441\
---------------------------------------------------------------------------
\3440\ New England for Offshore Wind Initial Comments at 6.
\3441\ NRG Initial Comments at 7, 36.
---------------------------------------------------------------------------
1610. Several commenters contend that transmission providers should
be required to respond to comments and questions submitted by
stakeholders in the local transmission planning process.\3442\ PJM
States raise the same issue but look to the relevant RTOs/ISOs to
resolve them.\3443\
---------------------------------------------------------------------------
\3442\ See American Municipal Power Initial Comments at 18-19;
California Commission Initial Comments at 112-113; DC and MD Offices
of People's Counsel Initial Comments at 6; Kentucky Commission Chair
Chandler Initial Comments at 22; Northwest and Intermountain Initial
Comments at 20-21; TAPS Initial Comments at 62.
\3443\ PJM States Initial Comments at 6.
---------------------------------------------------------------------------
1611. American Municipal Power and DC and MD Offices of People's
Counsel state that transmission providers are not obligated to respond
to stakeholder questions, which, when considered alongside the other
barriers to effective participation, creates unnecessary barriers to
open communication, is not just and reasonable, and is unduly
discriminatory.\3444\ American Municipal Power further asserts that
comparability principles require transmission providers to consider
transmission customers' comments in order to meet their needs and to
treat similarly situated customers comparably while conducting
transmission system planning.\3445\ However, PJM and Indicated PJM TOs
disagree that stakeholder comments are being ignored in PJM's
Attachment M-3 process.\3446\
---------------------------------------------------------------------------
\3444\ See American Municipal Power Initial Comments at 19-20;
DC and MD Offices of People's Counsel Initial Comments at 6-7.
\3445\ American Municipal Power Initial Comments at 19.
\3446\ Indicated PJM TOs Reply Comments at 4, 18-19 (citations
omitted); PJM Reply Comments at 13-15 (citing American Municipal
Power Initial Comments at 19).
---------------------------------------------------------------------------
1612. TAPS states that dispute resolution on criteria, assumptions,
needs, and proposed solutions should be available if stakeholder
comments are ignored.\3447\ TAPS asserts that the Commission should
include such provisions in any final order or clarify that they are
already encompassed in the Commission's transparency proposal.\3448\
---------------------------------------------------------------------------
\3447\ TAPS Initial Comments at 62 (citing Order No. 890, 118
FERC ] 61,119 at PP 501-503).
\3448\ Id.
---------------------------------------------------------------------------
e. Additional Issues
1613. Pattern Energy and American Municipal Power state that the
NOPR proposal does not go far enough in ensuring stakeholder access to
transmission planning data from the local transmission planning
processes and propose additional requirements to make certain
information more readily available, subject to execution of a CEII non-
disclosure agreement.\3449\ Similarly, Pattern Energy states that
continued stakeholder access to the source data used in transmission
modeling by transmission providers is essential to ensure fair and
reasonable outcomes in any transmission planning process.\3450\ PPL
requests that the Commission clarify that confidential or sensitive
information will be protected under the NOPR proposal in the local
transmission planning processes as they currently are in PJM.\3451\
---------------------------------------------------------------------------
\3449\ See American Municipal Power Initial Comments at 22;
Pattern Energy Initial Comments at 30-31.
\3450\ Pattern Energy Initial Comments at 30-31.
\3451\ PPL Initial Comments at 36.
---------------------------------------------------------------------------
1614. Certain TDUs state that the Commission should require
transmission providers to coordinate with load-serving entities to
transfer data and information and increase transparency in the
stakeholder process.\3452\ ACEG recommends that the Commission require
minimum data transparency standards in the local transmission planning
processes, drawing on MISO's and SPP's cost recording and tracking
processes for transmission projects approved through their regional
transmission planning processes.\3453\ Maryland Energy Administration
asserts that additional reforms beyond those proposed in the NOPR are
needed to support transparency and better incorporate stakeholder
contributions in local transmission planning processes.\3454\
California Water recommends that the Commission allow data requests,
similar to the opportunity for data requests in the SoCal Edison and
PG&E stakeholder review processes, which ensure that stakeholders can
participate and that transmission providers exercise good faith efforts
to respond.\3455\
---------------------------------------------------------------------------
\3452\ Certain TDUs Initial Comments at 18.
\3453\ ACEG Initial Comments at 56 (citing Johannes
Pfeifenberger et al., The Brattle Group, Cost Savings Offered by
Competition in Electric Transmission: Experience to Date and the
Potential for Additional Customer Value 26 (Apr. 2019)).
\3454\ See Maryland Energy Administration Reply Comments at 2-3
(citations omitted).
\3455\ California Water Initial Comments at 7-8 (citing S. Cal.
Edison, Filing, App. XII, ER19-1553-000, at section 2.2 (filed July
2, 2020); Pac. Gas & Elec. Co., Filing, App. IX, ER19-13-001, at
section 3.2 (filed Mar. 31, 2020)).
---------------------------------------------------------------------------
1615. American Municipal Power requests that the Commission direct
transmission providers to provide detailed information consisting of
more than generic or high-level network models, along with power flow
models and power system analyses used in their
[[Page 49528]]
local transmission planning.\3456\ According to American Municipal
Power, to allow stakeholders to evaluate the outputs of transmission
providers' studies--i.e., the identified transmission needs--on their
own, transmission providers must be required to provide the
models.\3457\ Furthermore, American Municipal Power argues, the
Commission should require transmission providers to provide information
on how assets have been prioritized for replacement, how the
replacement versus maintenance decision is made, how assets rank
relative to other assets on the system, and the system average
values.\3458\
---------------------------------------------------------------------------
\3456\ American Municipal Power Initial Comments at 20-21.
\3457\ Id. at 21.
\3458\ Id. at 22-23.
---------------------------------------------------------------------------
1616. Several commenters state that the NOPR proposal does not go
far enough to protect customers' interests and suggest the addition of
more process, more oversight, more monitoring (including establishing
an independent transmission monitor), or more prudence reviews.\3459\
According to PIOs, transmission providers have incentives to avoid
independent transmission planning processes because local transmission
projects are presumed to be prudent, avoid competition, and receive
high rates of return. PIOs state that the Commission should reduce the
rate of return for local transmission projects and issue a rule or
policy statement that puts the burden of proof on transmission
providers to demonstrate that the cost of a proposed transmission
project is just and reasonable.\3460\
---------------------------------------------------------------------------
\3459\ California Commission Initial Comments at 111-112 &
n.401; Colorado Consumer Advocates Initial Comments at 31; Joint
Consumer Advocates Initial Comments at 25-29; NRG Initial Comments
at 7, 36; Ohio Consumers Initial Comments at 23-24; OMS Initial
Comments at 16-17; Pattern Energy Initial Comments at 31-34; Pine
Gate Initial Comments at 49-50; PIOs Initial Comments at 51-52; PJM
States Initial Comments at 4-6; TAPS Initial Comments at 61-62; US
DOJ and FTC Initial Comments at 20-21.
\3460\ PIOs Initial Comments at 52-53.
---------------------------------------------------------------------------
1617. Joint Consumer Advocates state that, while the NOPR proposal
is an improvement, more needs to be done to address the imbalance
between consumer advocates and incumbent transmission owners.
Therefore, Joint Consumer Advocates assert, the Commission should
authorize the creation of an independent transmission monitor to
evaluate the effective coordination of local transmission projects with
more holistic transmission planning to identify the most efficient or
cost-effective approach to meeting local, regional, and interregional
transmission needs.\3461\ Relatedly, California Commission and Colorado
Consumer Advocates suggest that the Commission give independent
transmission monitors the responsibility to evaluate stakeholder
comments, independently analyze whether there are potentially more
efficient and cost-effective alternative transmission solutions to meet
identified transmission needs, and make a recommendation.\3462\ Potomac
Economics argues that the Commission's transparency goals likely cannot
be met without an independent transmission monitor.\3463\
---------------------------------------------------------------------------
\3461\ Joint Consumer Advocates Initial Comments at 26-29
(citations omitted).
\3462\ California Commission Initial Comments at 111-112;
Colorado Consumer Advocates Initial Comments at 31.
\3463\ See Potomac Economics Initial Comments at 6.
---------------------------------------------------------------------------
1618. Some commenters opine on whether the regional transmission
planning process should assume an expanded role in reviewing or
approving identified local transmission projects.\3464\ In addition,
NARUC recommends that the Commission allow the proposed stakeholder
review process to apply to repair and replacement projects that do not
expand the capacity of the transmission system, or do so only
incidentally, in particular those that are forecast to cost $3 million
or more. NARUC asserts that, limiting the reforms to local transmission
planning may exclude review of these projects, which currently comprise
half of investor-owned utilities' transmission spending in the RTOs/
ISOs. Further, NARUC urges the Commission to allow these projects,
along with local transmission projects, to be reviewed and approved as
part of the regional transmission planning process.\3465\ California
Commission agrees, stating that there should be more external scrutiny
of such projects to reduce incumbent utilities' existing perverse
incentive to overinvest in these types of projects due to their lack of
external review.\3466\
---------------------------------------------------------------------------
\3464\ See American Municipal Power Reply Comments at 3-7;
California Commission Initial Comments at 108-110; DC and MD Offices
of People's Counsel Initial Comments at 7; NARUC Initial Comments at
60-61; Ohio Consumers Reply Comments at 17-18; PJM States Initial
Comments at 6-7.
\3465\ NARUC Initial Comments at 60-63 (citations omitted).
\3466\ California Commission Initial Comments at 109-110
(citations omitted).
---------------------------------------------------------------------------
1619. PJM States call on RTOs/ISOs to go beyond evaluating whether
local transmission projects ``do no harm'' by actively taking a stance
on such projects, discussing how this stance was reached, and by
proposing transmission projects that may be the most cost-
effective.\3467\ However, PJM States ask the Commission to explicitly
avoid impinging on state-jurisdictional processes.\3468\
---------------------------------------------------------------------------
\3467\ PJM States Initial Comments at 6-7 (citation omitted).
\3468\ Id. at 7.
---------------------------------------------------------------------------
1620. DC and MD Offices of People's Counsel and American Municipal
Power assert that the remedy for the current lack of a requirement to
incorporate or respond to stakeholder feedback in the local
transmission planning process is an empowered regional transmission
planner that is independent and incorporates meaningful participation
from all stakeholders beginning with the determination of any
transmission needs through the project selection phase.\3469\
Relatedly, Ohio Consumers state that the NOPR proposal leaves sole
discretion in selection of transmission projects and the costs of the
projects to transmission providers.\3470\
---------------------------------------------------------------------------
\3469\ American Municipal Power Reply Comments at 3-7 (citations
omitted); DC and MD Offices of People's Counsel Initial Comments at
7.
\3470\ Ohio Consumers Reply Comments at 18.
---------------------------------------------------------------------------
1621. However, some commenters defend the separation between local
and regional transmission planning processes.\3471\ For instance, AEP
disagrees that transmission providers seek to build local transmission
projects to circumvent the regional transmission planning
process.\3472\ According to AEP, local and regional transmission
planning processes are not interchangeable because most local
transmission facilities directly serve load and local utilities must
address local needs when those needs are not addressed by a regional
transmission facility in a cost-effective manner.\3473\ Nevertheless,
AEP states, there can be an effective and efficient intersection
between local and regional transmission planning, citing PJM's open and
transparent local transmission planning process that requires
coordination with the regional transmission planning process and in
which PJM is an active participant.\3474\ Similarly, WIRES states that
there are good reasons for maintaining a distinction between regional
and local transmission planning, noting that the regional transmission
planning process is directed toward addressing certain
[[Page 49529]]
reliability, economic criteria, and public policy initiatives, not the
additional system needs related to resilience, asset management,
customer needs, customer impact, and aging infrastructure replacement
that are the focus of local transmission planning.\3475\
---------------------------------------------------------------------------
\3471\ AEP Reply Comments at 6-7; MISO Reply Comments at 27;
PG&E Reply Comments at 4-9; WIRES Initial Comments at 9.
\3472\ AEP Reply Comments at 6-7 (citing AEE Initial Comments at
38; PIOs Initial Comments at 8-9; Resale Iowa Initial Comments at 7-
8; US DOJ and FTC Initial Comments at 7).
\3473\ Id. at 2-3.
\3474\ Id. at 8 (citing PJM, Intra-PJM Tariffs, OATT, attach. M-
3 (1.0.0)).
\3475\ WIRES Initial Comments at 9 (citing Charles River
Associates, The Value of Local Transmission Planning 9, 13 (Dec.
2021), https://wiresgroup.com/wp-content/uploads/2021/12/Value-of-Local-Transmission-Planning-report-WIRES-CRA.pdf).
---------------------------------------------------------------------------
1622. Eversource states that, if the Commission decides to require
a more prescriptive local transmission planning process, it should
clarify that the process applies only to upgrades that are developed
primarily to increase the capacity of the local transmission system,
and not to upgrades that are incidental to state-jurisdictional
distribution system planning or other unique local requirements.\3476\
---------------------------------------------------------------------------
\3476\ Eversource Initial Comments at 49.
---------------------------------------------------------------------------
1623. MISO defends the transparency of local transmission planning
in MISO by stating that commenters who criticize existing local
transmission planning processes ``ignore the open, transparent process
in effect, and fail to recognize the ongoing need for near-term
planning.'' \3477\ MISO states that local and regional transmission
planning are complementary and that ``near-, mid- and long-term
planning work in concert.'' \3478\ MISO contends that its existing
process includes extensive stakeholder involvement that ensures that
issues are identified and alternatives are considered.\3479\
---------------------------------------------------------------------------
\3477\ MISO Reply Comments at 27 (citing PIOs Initial Comments
at 32).
\3478\ Id.
\3479\ Id.
---------------------------------------------------------------------------
1624. PG&E opposes comments in favor of removing the role of local
transmission planning from local transmission owners, as well as
requests to expand the NOPR proposal to apply to asset management
projects. PG&E notes that California Commission has not provided any
evidence that RTOs/ISOs are currently unable to adequately handle the
regional and local transmission planning processes.\3480\
---------------------------------------------------------------------------
\3480\ PG&E Reply Comments at 4-9 (citations omitted).
---------------------------------------------------------------------------
3. Commission Determination
1625. We adopt the NOPR proposal, with modification, to require
transmission providers in each transmission planning region to revise
the regional transmission planning process in their OATTs to enhance
the transparency of: (1) the criteria, models, and assumptions that
they use in their local transmission planning process; (2) the local
transmission needs that they identify through the local transmission
planning process; and (3) the potential local or regional transmission
facilities that they will evaluate to address those local transmission
needs. For each of these three categories of local transmission
planning information, and as discussed further below, transmission
providers must identify and publicly post the information identified
below, then conduct publicly-noticed stakeholder meetings to provide an
opportunity for comment on the information both before and after the
stakeholder meetings, as part of the regional transmission planning
process. In response to comments from PG&E,\3481\ we clarify that this
requirement applies only to local transmission planning that is within
the scope of Order No. 890 and is therefore already subject to Order
No. 890 transparency requirements. As such, this requirement does not
apply to asset management projects.\3482\ However, nothing in this
final order prevents transmission providers from choosing to apply
these requirements to asset management projects.
---------------------------------------------------------------------------
\3481\ PG&E Initial Comments at 17 (citing Cal. Pub. Utils.
Comm'n v. Pac. Gas & Elec., 164 FERC ] 61,161 at P 66).
\3482\ See S. Cal. Edison Co., 164 FERC ] 61,160 at PP 30-40;
Cal. Pub. Utils. Comm'n v. Pac. Gas. & Elec. Co., 164 FERC ] 61,161
at PP 65-74 (finding that Order No. 890's local transmission
planning requirements do not apply to asset management projects that
do not increase capacity or do so incidentally).
---------------------------------------------------------------------------
1626. In complying with this requirement, transmission providers
must establish an iterative process that ensures that stakeholders have
meaningful opportunities to participate in and provide feedback on
local transmission planning throughout the regional transmission
planning process. To provide the needed transparency and opportunities
for stakeholder participation, we require that the regional
transmission planning process include at least three publicly-noticed
stakeholder meetings per regional transmission planning cycle
concerning the local transmission planning process of each transmission
provider that is a member of the transmission planning region before
each transmission provider's local transmission plan can be
incorporated into the transmission planning region's planning models.
1627. Specifically, we adopt the NOPR proposal to require that,
prior to the submission of local transmission planning information to
the transmission planning region for inclusion in the regional
transmission planning process, transmission providers in each
transmission planning region must convene, collectively, as part of the
regional transmission planning process, a stakeholder meeting to review
the criteria, assumptions, and models related to each transmission
provider's local transmission planning (Assumptions Meeting). Next, no
fewer than 25 calendar days after the Assumptions Meeting, transmission
providers in each transmission planning region must convene,
collectively, as part of the regional transmission planning process, a
stakeholder meeting to review identified reliability criteria
violations and other transmission needs that drive the need for local
transmission facilities (Needs Meeting). Finally, no fewer than 25
calendar days after the Needs Meeting, transmission providers in each
transmission planning region must convene, collectively, as part of the
regional transmission planning process, a stakeholder meeting to review
potential solutions to those reliability criteria violations and other
transmission needs (Solutions Meeting). Additionally, we require that
all materials for stakeholder review during these three meetings be
publicly posted and that stakeholders have opportunities before and
after each meeting to submit comments.
1628. In addition to these requirements, we modify the NOPR
proposal to also require transmission providers to publicly post the
meeting materials no fewer than five calendar days prior to each of the
three publicly-noticed stakeholder meetings to allow time for
stakeholders to review materials in advance of each meeting. Also, we
require that transmission providers allow for a period of no fewer than
25 calendar days following the Solutions Meeting to review and consider
stakeholder feedback on the local transmission solutions identified to
meet the local transmission needs before the local transmission plan
can be incorporated in the transmission planning region's planning
models. Requiring this minimum 25 calendar day period is consistent
with Order No. 1000, where the Commission stated that the Commission
intends that the regional transmission planning processes provide for
the timely and meaningful input and participation of stakeholders in
the development of regional transmission plans.\3483\ Lastly, we
require that transmission providers must respond to questions or
comments from stakeholders such that it allows stakeholders to
meaningfully participate in these three required stakeholder meetings.
---------------------------------------------------------------------------
\3483\ Order No. 1000, 136 FERC ] 61,051 at P 153 (citing Order
No. 890, 118 FERC ] 61,119 at P 454).
---------------------------------------------------------------------------
[[Page 49530]]
1629. We find that establishing a standard baseline of transparency
into transmission providers' local transmission planning processes will
ensure that stakeholders have an opportunity to review and provide
feedback on local transmission planning assumptions, needs, and
solutions that are used as inputs to the regional transmission planning
process. We expect that this additional transparency will help reduce
the possibility that transmission providers will develop local
transmission facilities without adequately considering whether there is
a more efficient or cost-effective regional transmission solution that
could address their local transmission needs. This additional
transparency will enable transmission providers to satisfy their
requirements for regional transmission planning under Order No.
1000.\3484\
---------------------------------------------------------------------------
\3484\ Id. PP 78-84.
---------------------------------------------------------------------------
1630. We believe that the local transmission planning information
provided pursuant to the enhanced transparency requirements that we
adopt in this final order will better facilitate the identification
through the regional transmission planning process of regional
transmission facilities that may be more efficient or cost-effective
than proposed local transmission facilities.\3485\ Specifically,
transmission providers' local transmission planning information will be
subject to review and comment by stakeholders that may provide
additional information or identify considerations that could inform the
criteria, models, and assumptions used in local transmission planning,
the identification of local transmission needs, and the identification
of transmission facilities to address those local transmission needs.
Because local transmission planning information serves as an input to
the regional transmission planning process, these improvements will, in
turn, facilitate the identification of more efficient or cost-effective
transmission facilities in the regional transmission planning process,
resulting in Commission-jurisdictional rates that are just and
reasonable and not unduly discriminatory or preferential.
---------------------------------------------------------------------------
\3485\ NOPR, 179 FERC ] 61,028 at P 402.
---------------------------------------------------------------------------
1631. With respect to the comments from National and State
Conservation Organizations and WE ACT \3486\ that robust input from
affected and overburdened communities in the local transmission
planning process is important, we believe that the added transparency
requirements that require transmission providers to identify and
publicly post the information and then conduct stakeholder meetings as
part of the regional transmission planning process, provides an
opportunity for interested parties to engage and comment on the
information.
---------------------------------------------------------------------------
\3486\ National and State Conservation Organizations Initial
Comments at 2; WE ACT Initial Comments at 5-6.
---------------------------------------------------------------------------
1632. With regard to commenters that suggest that the additional
transparency requirements proposed in the NOPR will not be effective
because they do not go far enough in making changes to local
transmission planning processes,\3487\ we find that the enhanced
transparency requirements that we adopt in this final order are
specifically designed to provide needed transparency to ensure that
Commission-jurisdictional rates are just and reasonable and not unduly
discriminatory or preferential. In addition, we find that other
commenters' suggestions for changes to local transmission planning
processes were not proposed in the NOPR and therefore are outside the
scope of this proceeding. We conclude that the replacement rate set
forth herein is just and reasonable and addresses the deficiencies
identified herein.\3488\ We note that the Commission continues to
examine a suite of related issues in its Transmission Planning and Cost
Management proceeding.\3489\
---------------------------------------------------------------------------
\3487\ See American Municipal Power Initial Comments at 17-18;
Ohio Commission Federal Advocate Initial Comments at 19-20.
\3488\ See New York v. FERC, 535 U.S.at 26-28 (upholding
Commission's decision not to assert jurisdiction over bundled retail
transmission).
\3489\ See Transmission Planning and Cost Management, Notice of
Technical Conference, Docket No. AD22-8-000 (Apr. 21, 2022).
---------------------------------------------------------------------------
1633. In response to American Municipal Power's assertion that the
PJM Attachment M-3 process has increased the problem of planning based
on individual transmission owners' criteria and the balkanization of
the transmission planning process,\3490\ we find that American
Municipal Power has not persuasively explained why these concerns are
the result of increasing the transparency of local transmission
planning, rather than other factors associated with the PJM Attachment
M-3 process. Based on the record before us, we do not expect that
requiring enhanced transparency in local transmission planning, in the
manner directed in this final order, will result in greater incentives
for transmission providers to develop local transmission facilities in
lieu of regional transmission facilities. Instead, we expect that
additional opportunities for stakeholder review of and comment on local
transmission planning inputs into the regional transmission planning
process will help to facilitate the identification of regional
transmission facilities that are more efficient or cost-effective
compared to transmission facilities identified in the local
transmission planning process.
---------------------------------------------------------------------------
\3490\ American Municipal Power Initial Comments at 17.
---------------------------------------------------------------------------
1634. We disagree with commenters that state that the NOPR proposal
is not needed in their transmission planning region because their local
transmission planning process is already sufficiently
transparent.\3491\ The reforms that we adopt here are necessary to
ensure just and reasonable rates, as more fully explained above.
Additionally, we believe that these reforms to enhance the transparency
of local transmission planning inputs into the regional transmission
planning process are necessary to ensure that interested stakeholders
have an opportunity to meaningfully participate in the review of the
local transmission planning assumptions, needs, and solutions before
each transmission provider's local transmission plan can be
incorporated into the transmission planning region's planning models.
---------------------------------------------------------------------------
\3491\ APS Initial Comments at 12-13; Avangrid Initial Comments
at 13-15; CAISO Initial Comments at 46-50; Dominion Initial Comments
at 69-70; Eversource Initial Comments at 46-49; MISO Initial
Comments at 84-86; MISO TOs Initial Comments at 29-31; National Grid
Initial Comments at 39; New York TOs Initial Comments at 16;
Pennsylvania Commission Initial Comments at 20; PG&E Initial
Comments at 16-18.
---------------------------------------------------------------------------
1635. Similarly, we disagree with commenters that oppose the
proposal because it may interfere with existing transmission planning
processes.\3492\ As we explain above, the enhanced transparency and
opportunities for stakeholder participation are needed to ensure just
and reasonable Commission-jurisdictional rates. Although we appreciate
that there may be differences in how transmission providers currently
conduct local transmission planning, we believe that the standard
baseline of transparency established by the requirements adopted in
this final order is needed to ensure that stakeholders have an
opportunity to review and provide feedback on local transmission
planning inputs that go into the regional transmission planning process
and to ensure that the regional transmission planning process can
identify regional transmission facilities that address transmission
needs more efficiently or
[[Page 49531]]
cost-effectively than local transmission facilities. The fact that
transmission providers may need to adjust their existing processes to
comply with these requirements is not a sufficient reason for the
Commission to decline to adopt them.
---------------------------------------------------------------------------
\3492\ Avangrid Initial Comments at 13; CAISO Initial Comments
at 7, 47; Dominion Initial Comments at 70; Eversource Initial
Comments at 47-48; MISO Initial Comments at 86; PG&E Initial
Comments at 17-18; PPL Initial Comments at 36; Xcel Initial Comments
at 16-17.
---------------------------------------------------------------------------
1636. We also disagree with commenters that argue that the proposal
is too prescriptive.\3493\ We believe that these requirements strike a
reasonable balance between the need for transparency of local
transmission planning inputs that are used in regional transmission
planning and providing transmission providers with flexibility in how
they conduct their local transmission planning processes. In fact,
experience with the PJM Attachment M-3 process, which includes similar
requirements to those adopted in this final order, provides evidence
that it is possible to satisfy these requirements with a process that
allows transmission providers to produce their local transmission plans
on a timely basis.\3494\ In response to National Grid's concern that
the NOPR proposal would impose a new requirement to integrate their
local transmission planning with regional transmission planning,\3495\
the final order imposes no new requirements beyond the three meetings
and associated opportunities for comment described above. We believe
that these requirements add only a small but manageable burden for
transmission providers, which is outweighed by the transparency
benefits that would accrue to stakeholders participating in the local
and regional transmission planning processes.
---------------------------------------------------------------------------
\3493\ See Avangrid Initial Comments at 13-15; EEI Initial
Comments at 40; Eversource Initial Comments at 47-48; Kansas
Commission Initial Comments at 17; MISO Initial Comments at 84-86;
MISO TOs Initial Comments at 29-31; National Grid Initial Comments
at 39-41; New York TOs Initial Comments at 7, 16-17; Xcel Initial
Comments at 17.
\3494\ See Indicated PJM TOs Initial Comments at 42-43
(citations omitted).
\3495\ National Grid Initial Comments at 39-40.
---------------------------------------------------------------------------
1637. With respect to the comments of APS and National Grid that
local transmission planning cycles might be delayed by the new
transparency requirements,\3496\ we reiterate that the final order
strikes a reasonable balance between the need for transparency of local
transmission planning inputs that are used in regional transmission
planning and providing transmission providers with flexibility in how
they conduct their local transmission planning processes. We believe
that, even with the additional requirements that we establish here, it
is possible for transmission providers to produce local transmission
plans within a 12-month period, especially given that when scheduling
the three required meetings, transmission providers need not leave more
than 25 calendar days between each meeting. The experience of PJM TOs,
whose local transmission planning processes are subject to similar
requirements, demonstrates that it is possible to satisfy these
requirements in a timely manner.\3497\
---------------------------------------------------------------------------
\3496\ APS Initial Comments at 13; National Grid Initial
Comments at 39-40.
\3497\ Exelon Initial Comments at 3-4, 51-52 (citing PJM, Intra-
PJM Tariffs, OATT, attach. M-3 (1.0.0)); Indicated PJM TOs Initial
Comments at 42-43.
---------------------------------------------------------------------------
a. Specific Stakeholder Meeting Requirements
1638. We address in this section the requirements specific to the
implementation details associated with the three publicly-noticed
stakeholder meetings that transmission providers are required to
conduct: the Assumptions Meeting, the Needs Meeting, and the Solutions
Meeting, that were discussed above. We believe that these requirements
strike a reasonable balance between providing adequate time to allow
interested stakeholders to review and comment on local transmission
planning inputs that are used in regional transmission planning and
allowing the efficient and timely execution of the local transmission
planning process. In our view, allowing transmission providers to limit
the length of time between the three required meetings accomplishes
this balance.
1639. With respect to commenters who argue that a minimum of 25
calendar days between publicly-noticed stakeholder meetings is too
short,\3498\ we disagree. The minimum period between stakeholder
meetings is just that, a minimum, and we expect that transmission
providers and their stakeholders will, in practice, implement a
schedule for the required stakeholder meetings that best meets the
needs of their transmission planning region. However, we find that a
minimum of less than 25 calendar days between stakeholder meetings
would not allow stakeholders to participate in a meaningful way, and we
therefore adopt this minimum period as an appropriate baseline for
providing stakeholders with a meaningful opportunity to review and
comment on local transmission planning inputs that are used in regional
transmission planning. And, in fact, at least some transmission
providers have adopted this minimum duration between stakeholder
meetings.\3499\
---------------------------------------------------------------------------
\3498\ American Municipal Power Initial Comments at 24;
Northwest and Intermountain Initial Comments at 21; TAPS Initial
Comments at 6, 62.
\3499\ See PJM, Intra-PJM Tariffs, OATT, attach. M-3 (1.0.0.),
which, briefly, refers to the additional transparency and
stakeholder input rules around transmission facilities that are not
eligible for selection, but, though classified as local transmission
facilities, nonetheless impact the identification and selection of
regional transmission facilities. See also Duke Energy Carolinas,
LLC, 186 FERC ] 61,178, at PP 13, 27 (2024) (accepting Duke's OATT
revisions to adopt a stakeholder meeting process that includes an
Assumptions Meeting, Needs Meeting, and Solutions Meeting, each no
fewer than 25 calendar days apart).
---------------------------------------------------------------------------
1640. We clarify that transmission providers are required to
provide information at least five calendar days prior to each of the
three publicly-noticed stakeholder meetings. As stated above,
transmission providers must publicly notice each meeting and publicly
post all materials for stakeholder review during the three meetings and
provide opportunities for stakeholders to submit comments before and
after each meeting. We believe that providing this information at least
five calendar days prior to each of the three stakeholder meetings
strikes a balance between giving stakeholders meaningful opportunity to
review the meeting materials ahead of each meeting and limiting the
burden to transmission providers in posting the materials ahead of
time. Furthermore, the information that we require transmission
providers to share is information that they use in their local
transmission planning processes and, thus, is information that they
generally already possess.
1641. We disagree with commenters that argue that three separate
publicly-noticed stakeholder meetings are unnecessary and will increase
workload without any benefit, or that a single meeting would address
the Commission's transparency concerns more efficiently, or request
that the Commission not dictate the number of stakeholder
meetings.\3500\ We note that Indicated PJM TOs state that the PJM
Attachment M-3 process has the benefit of avoiding duplication of
projects between local and regional transmission planning
processes.\3501\ We also disagree with MISO's argument that we should
allow each transmission planning region to have complete discretion
over the timing of the meetings, as well as the specific information to
be covered at the meetings.\3502\ While we allow flexibility in certain
aspects of the transmission planning processes, we find that the
requirement to hold three separate
[[Page 49532]]
stakeholder meetings a minimum of 25 calendar days apart and
prescribing the type of information that transmission providers must
share at each meeting is necessary to ensure that Commission-
jurisdictional rates remain just and reasonable and not unduly
discriminatory or preferential. We balance the increased burden imposed
on transmission providers with the benefits associated with providing
increased information and opportunities for stakeholder review of and
comment on the local transmission planning inputs that are used in the
regional transmission planning process. In addition, as discussed
above, we believe that these reforms will reduce after-the-fact
disputes and will help facilitate the identification of regional
transmission facilities that may be more efficient or cost-effective
than proposed local transmission facilities. As a result, the
incremental burden of having to hold three stakeholder meetings to
share this information and to consider input from stakeholders in
response to this information is outweighed by the benefits that the
increased transparency will provide.
---------------------------------------------------------------------------
\3500\ Dominion Initial Comments at 68; Eversource Initial
Comments at 47-48; NESCOE Initial Comments at 78; Xcel Initial
Comments at 17.
\3501\ Indicated PJM TOs Initial Comments at 42.
\3502\ MISO Initial Comments at 84.
---------------------------------------------------------------------------
1642. We also find unconvincing Eversource's assertion that the
reforms will not work where there is not a precisely defined regional
transmission planning cycle, such as is the case in ISO-NE.\3503\ The
requirement to hold three publicly-noticed stakeholder meetings is
triggered by the submission of local transmission planning information
to the transmission planning region for inclusion in the regional
transmission planning process and is not tied to a particular
transmission planning cycle. Nevertheless, we recognize that these
reforms may require transmission providers to propose adjustments to
their existing processes. But as explained above, we believe that the
need for transparency and stakeholder involvement requires these
changes to ensure that Commission-jurisdictional rates are just and
reasonable and not unduly discriminatory or preferential.
---------------------------------------------------------------------------
\3503\ Eversource Initial Comments at 47.
---------------------------------------------------------------------------
1643. In response to TAPS' request that transmission providers be
required to post their transmission planning criteria, models, and
assumptions,\3504\ we reiterate that transmission providers must
provide this information as part of the Assumptions Meeting. We further
note that the requirement for transmission providers to disclose to all
customers and other stakeholders the basic criteria, assumptions, and
data that underlie their transmission systems is an existing
requirement of Order No. 890. This information must enable customers,
other stakeholders, or an independent third party to replicate the
results of planning studies and thereby reduce the incidence of after-
the-fact disputes regarding whether planning has been conducted in an
unduly discriminatory fashion.\3505\ The Commission recognized in Order
No. 890 that safeguards must be put in place to ensure that
confidentiality and CEII concerns are adequately addressed in
transmission planning activities and, therefore, requires that
transmission providers have mechanisms in place in their OATTs to
manage confidentiality and CEII concerns, such as confidentiality
agreements and password-protected access to information.\3506\ However,
we reiterate that information must be disclosed, under applicable
confidentiality provisions, if the information is needed to participate
in the transmission planning process and to replicate transmission
planning studies, which necessarily includes access to the models that
underlie transmission planning processes.
---------------------------------------------------------------------------
\3504\ TAPS Initial Comments at 61.
\3505\ Order No. 890, 118 FERC ] 61,119 at P 471.
\3506\ Id. P 460.
---------------------------------------------------------------------------
1644. We decline to require, as requested by American Municipal
Power and TAPS, that transmission providers hold two Solutions
Meetings.\3507\ While a transmission provider may determine that
additional stakeholder meetings are appropriate or necessary, we only
require transmission providers to conduct the three publicly-noticed
stakeholder meetings discussed above. However, there is nothing in this
final order that prohibits transmission providers from holding
additional meetings, beyond those required here. We find NRG's request
that the Commission require the local transmission planning process
include an estimated rate impact for each year if the local
transmission plan were to be executed to be beyond the scope of the
proposal, although transmission providers may choose to provide this
information outside of the context of this order.
---------------------------------------------------------------------------
\3507\ American Municipal Power Initial Comments at 24-25; TAPS
Initial Comments at 62 (citing NOPR, 179 FERC ] 61,028 at P 402).
---------------------------------------------------------------------------
1645. In response to commenters that request that the Commission
require transmission providers to respond to all comments and questions
submitted by stakeholders in the local transmission planning
process,\3508\ we clarify that such a requirement could be too
prescriptive in certain circumstances and thus we decline to set a
bright-line rule that transmission providers must respond to each and
every question or comment received through the stakeholder process.
Nevertheless, we require transmission providers to respond to questions
or comments in a manner that allows stakeholders to meaningfully
participate in these stakeholder meetings. For example, in the context
of live discussions in any of the three required publicly-noticed
stakeholder meetings, we expect transmission providers to offer
stakeholders an opportunity to speak, engage, and ask questions, as
well as receive reasonable responses at the meeting consistent with
meaningful participation. Overall, we encourage transmission providers
to be as responsive as possible to stakeholder comments and questions.
However, we recognize that not all comments or questions require an
answer or a response, or that some responses may be unduly burdensome
to the transmission provider. To the extent that there are
disagreements, we note that stakeholders have dispute resolution
procedures available, as required under Order No. 890.\3509\ Some
commenters have asked the Commission to require transmission providers
to provide ``additional clarity'' regarding how alternatives were
developed and why they were not selected during the Solutions Meeting,
as requested by American Municipal Power.\3510\ In balancing the need
for transparency and the burden for transmission providers, we find
that a meaningful participation standard regarding sharing of local
transmission planning inputs that are used in the regional transmission
planning process that are established by the Commission is reasonable.
---------------------------------------------------------------------------
\3508\ See American Municipal Power Initial Comments at 18-19;
California Commission Initial Comments at 112-113; DC and MD Offices
of People's Counsel Initial Comments at 6; Kentucky Commission Chair
Chandler Initial Comments at 21-22; Northwest and Intermountain
Initial Comments at 20-21; TAPS Initial Comments at 62.
\3509\ Order No. 890, 118 FERC ] 61,119 at PP 501-503.
\3510\ American Municipal Power Initial Comments at 24-25.
---------------------------------------------------------------------------
1646. In addition, in response to TAPS' request regarding disputes
over local transmission planning inputs,\3511\ we clarify that where
disputes arise regarding transparency into the local transmission
planning inputs, the transmission provider's existing dispute
resolution process, as established in Order No. 890, governing the
transmission planning process should be used.\3512\ Further, affected
entities
[[Page 49533]]
retain any rights that they may have under FPA section 206 to file
complaints with the Commission.
---------------------------------------------------------------------------
\3511\ TAPS Initial Comments at 62 (citing Order No. 890, 118
FERC ] 61,119 at PP 501-503).
\3512\ Order No. 890, 118 FERC ] 61,119 at P 501.
---------------------------------------------------------------------------
b. Additional Issues
1647. As it pertains to PPL's request that the Commission clarify
that confidential or sensitive information will be protected,\3513\ we
clarify that transmission providers must continue to apply the same
safeguards to protect sensitive or critical information, such as
confidentiality agreements and password protected access to
information, as the Commission required in Order No. 890 and that
transmission providers currently apply to the sharing of transmission
planning information to protect against inappropriate disclosure of
confidential information.\3514\
---------------------------------------------------------------------------
\3513\ PPL Initial Comments at 36.
\3514\ Order No. 890, 118 FERC ] 61,119 at PP 460, 471.
---------------------------------------------------------------------------
1648. Many commenters suggest additional reforms because these
commenters find the NOPR proposal insufficient. These suggested reforms
include additional measures to protect customers' interests and
additional process, more oversight, more monitoring (including
establishing an independent transmission monitor), or prudence
reviews;\3515\ requiring RTOs/ISOs to assume a larger role in reviewing
or approving identified local transmission projects;\3516\ requiring a
performance-based method of enhancing transparency in local
transmission planning processes;\3517\ and requiring transmission
providers to make available additional transmission planning
data,\3518\ improve formatting of transmission planning inputs,\3519\
or otherwise coordinate with load-serving entities to transfer data and
information.\3520\ The Commission did not make such proposals in the
NOPR and, as a result, we find these requests to be beyond the scope of
this proceeding and decline to adopt them. We note, however, that
several of these issues may be examined in the Commission's ongoing
Transmission Planning and Cost Management proceeding.\3521\
---------------------------------------------------------------------------
\3515\ California Commission Initial Comments at 111-112 &n.401;
Colorado Consumer Advocates Initial Comments at 31; Joint Consumer
Advocates Initial Comments at 25-29; NRG Initial Comments at 7, 36;
Ohio Consumers Initial Comments at 23-24; OMS Initial Comments at
16-17; Pattern Energy Initial Comments at 31-34; Pine Gate Initial
Comments at 49-50; PIOs Initial Comments at 51-52; PJM States
Initial Comments at 4-6; TAPS Initial Comments at 61-62; US DOJ and
FTC Initial Comments at 20-21.
\3516\ See American Municipal Power Reply Comments at 3-7;
California Commission Initial Comments at 108-110; DC and MD Offices
of People's Counsel Initial Comments at 7; NARUC Initial Comments at
60-61; Ohio Consumers Reply Comments at 17-18; PJM States Initial
Comments at 6-7.
\3517\ Vermont Electric and Vermont Transco Initial Comments at
5.
\3518\ American Municipal Power Initial Comments at 21-24
(citations omitted); Pattern Energy Initial Comments at 30-34.
\3519\ Joint Consumer Advocates Initial Comments at 21-22.
\3520\ Certain TDUs Initial Comments at 18.
\3521\ Transmission Planning and Cost Management, Notice of
Technical Conference, Docket No. AD22-8-000 (Apr. 21, 2022).
---------------------------------------------------------------------------
C. Identifying Potential Opportunities to Right-Size Replacement
Transmission Facilities
1. Eligibility
a. NOPR Proposal
1649. The Commission proposed to require, as part of each Long-Term
Regional Transmission Planning cycle, transmission providers in each
transmission planning region to evaluate whether transmission
facilities operating at or above 230 kV that an individual transmission
provider that owns the transmission facility anticipates replacing in-
kind with a new transmission facility during the next 10 years can be
``right-sized'' to more efficiently or cost-effectively address
regional transmission needs identified in Long-Term Regional
Transmission Planning. The Commission proposed to define ``right-
sizing'' as the process of modifying a transmission provider's in-kind
replacement of an existing transmission facility to increase that
facility's transfer capability.\3522\
---------------------------------------------------------------------------
\3522\ NOPR, 179 FERC ] 61,028 at P 403.
---------------------------------------------------------------------------
1650. The Commission described the process under this proposed
reform as entailing the following steps. First, sufficiently early in
each Long-Term Regional Transmission Planning cycle, each transmission
provider would submit its in-kind replacement estimates for use in
Long-Term Regional Transmission Planning. Then, if a right-sized
replacement transmission facility is identified as a potential solution
to a Long-Term Regional Transmission Planning need, that right-sized
replacement transmission facility would be evaluated in the same manner
as any other proposed transmission facility to determine whether it is
the more efficient or cost-effective transmission facility to address
the transmission need. If a right-sized replacement transmission
facility addresses the transmission provider's need to replace an
existing transmission facility, meets all of the applicable selection
criteria included in Long-Term Regional Transmission Planning, and is
found to be the more efficient or cost-effective solution to a
transmission need identified through Long-Term Regional Transmission
Planning, then the right-sized replacement transmission facility may be
selected in the regional transmission plan for purposes of cost
allocation.\3523\
---------------------------------------------------------------------------
\3523\ Id. P 407.
---------------------------------------------------------------------------
1651. The Commission explained that nothing in the reforms proposed
in the NOPR would alter a transmission provider's existing rights and
responsibilities under existing laws with respect to maintaining, and
when necessary, replacing, existing transmission facilities. Further,
as the Commission explained, it may be possible for an in-kind
replacement transmission facility to be included in the regional
transmission plan for informational purposes, but not be
selected.\3524\
---------------------------------------------------------------------------
\3524\ Id. PP 412-413.
---------------------------------------------------------------------------
b. Comments
1652. Several commenters support the NOPR's proposals related to
right-sizing.\3525\ ITC states that the NOPR proposal will result in
better use of existing facilities and rights-of-way to quickly deliver
additional transmission capacity. ITC maintains that increasing the
transfer capability of existing transmission facilities lessens the
impacts on communities and other land users, in addition to raising
fewer environmental considerations.\3526\ ITC adds that right-sizing
will form a critical input to transmission planning and state siting
processes by encouraging designs that meet future needs.\3527\
---------------------------------------------------------------------------
\3525\ ACORE Initial Comments at 19; Ameren Initial Comments at
46-47; APPA Initial Comments at 48; California Energy Commission
Initial Comments at 3; CTC Global Initial Comments at 18; ELCON
Initial Comments at 27; Evergreen Action Initial Comments at 4; ITC
Initial Comments at 45; ITC Reply Comments at 29; New York
Commission and NYSERDA Initial Comments at 15; Northwest and
Intermountain Initial Comments at 21; OMS Initial Comments at 17;
PJM Initial Comments at 9, 121-122; SEIA Initial Comments at 26;
U.S. Chamber of Commerce Initial Comments at 11; Vermont Electric
and Vermont Transco Initial Comments at 5.
\3526\ ITC Initial Comments at 45.
\3527\ ITC Reply Comments at 29.
---------------------------------------------------------------------------
1653. OMS also supports the Commission's proposed realignment of
incentives to ensure that transmission providers are not incentivized
through right-sizing to rebuild and replace facilities before
considering other opportunities, instead providing a level playing
field to consider other solutions.\3528\ PJM states that right-sizing
allows transmission owners to meet their reliability obligations while
transmission providers have the opportunity to find more efficient
[[Page 49534]]
solutions to regional transmission needs and avoid duplicative
transmission development.\3529\
---------------------------------------------------------------------------
\3528\ OMS Initial Comments at 17.
\3529\ PJM Initial Comments at 121-122 (citing NOPR, 179 FERC ]
61,028 at PP 406, 408).
---------------------------------------------------------------------------
1654. AEP supports applying the right-sizing evaluation to
transmission facilities operating at or above 230 kV because
replacement transmission facilities that will operate at or above 230
kV are most susceptible to modification to meet long-term regional
transmission needs.\3530\ PG&E also supports the proposed voltage
threshold, claiming that the inclusion of lower voltage transmission
projects would substantially expand the number of projects that would
need to be evaluated for right-sizing while offering little benefit.
Specifically, PG&E contends that lower voltage transmission projects
are typically needed for specific, local purposes and thus do not need
to be right-sized, and that a requirement that they be evaluated for
right-sizing would burden the RTO/ISO process.\3531\
---------------------------------------------------------------------------
\3530\ AEP Initial Comments at 44-45 (citing NOPR, 179 FERC ]
61,028 at P 406).
\3531\ PG&E Reply Comments at 14-15.
---------------------------------------------------------------------------
1655. APPA supports the NOPR proposal's use of a 10-year timeframe
for the right-sizing reform.\3532\ AEP also supports a 10-year horizon
for identifying in-kind replacements, so long as the list of
transmission facilities is non-binding and may be modified as
transmission projects mature or expected facility lives can be extended
through other means.\3533\
---------------------------------------------------------------------------
\3532\ APPA Initial Comments at 48 (citing NOPR, 179 FERC ]
61,028 at P 403).
\3533\ AEP Initial Comments at 44-45.
---------------------------------------------------------------------------
1656. CAISO requests that the Commission clarify that the NOPR does
not preclude it from continuing to consider modifications to in-kind
replacements for transmission facilities below 230 kV in its annual
transmission planning process.\3534\
---------------------------------------------------------------------------
\3534\ CAISO Initial Comments at 50.
---------------------------------------------------------------------------
1657. Several commenters support the NOPR's right-sizing proposal
but with certain conditions.\3535\ Further, some commenters argue that
if the Commission adopts the NOPR proposal, the Commission must ensure
that the proposal does not disrupt or impair existing local
transmission planning processes.\3536\ For example, AEP asserts that
the Commission must ensure that the NOPR proposal does not undermine
the local transmission planning process or transmission owners' rights
to build transmission projects that address local needs.\3537\
Mississippi Commission asserts that, if the NOPR proposal is adopted,
the ultimate decision as to which local transmission project is
constructed must rest with the states that have transmission siting
authority and the incumbent transmission owners.\3538\ PJM States ask
for clarification on how the NOPR proposal will interact with existing
processes, noting that in PJM, any need that appears both on a five-
year end-of-life needs list and in PJM's regional transmission plan is
eligible for competition (as compared to the NOPR proposal, under which
transmission projects to address 10-year-out needs would not be
eligible for competition).\3539\
---------------------------------------------------------------------------
\3535\ ACEG Initial Comments at 8-9, 56-58; AEP Initial Comments
at 43-44; Avangrid Initial Comments at 15-16; Breakthrough Energy
Initial Comments at 3, 19; California Commission Initial Comments at
113-118; California Water Initial Comments at 8-9; Clean Energy
Associations Initial Comments at 36-37; EEI Initial Comments at 41;
Eversource Initial Comments at 52; Exelon Initial Comments at 3, 51;
ISO-NE Initial Comments at 39; MISO Initial Comments at 87; NARUC
Initial Comments at 58-59, 63-64; NESCOE Initial Comments at 21-22,
78-79; NESCOE Reply Comments at 6-8; NESCOE Supplemental Comments at
7-9; NextEra Initial Comments at 66-67; NRECA Initial Comments at
67; NYISO Initial Comments at 58-60; PG&E Initial Comments at 12-14;
Pine Gate Initial Comments at 46-50; PIOs Initial Comments at 57-58;
State Agencies Initial Comments at 20-22; TAPS Initial Comments at
6-7, 64; VEIR Initial Comments at 6; Vermont State Entities Initial
Comments at 11-13; WIRES Initial Comments at 10.
\3536\ See AEP Initial Comments at 43-44; CAISO Initial Comments
at 50; Mississippi Commission Initial Comments at 30-31; Mississippi
Commission Reply Comments at 9-10; PJM States Initial Comments at 8;
WIRES Initial Comments at 10.
\3537\ AEP Initial Comments at 43-44.
\3538\ Mississippi Commission Initial Comments at 30-31.
\3539\ PJM States Initial Comments at 8 (citing PJM, Intra-PJM
Tariffs, OATT, attach. M-3 (1.0.0), section (d)1.iii).
---------------------------------------------------------------------------
1658. NESCOE states that ISO-NE lacks the clear standards required
to support right-sizing, citing an Eversource transmission project that
improved grid reliability but was ineligible for regional cost
allocation because it did not meet the standards to qualify as a right-
sized project.\3540\ NESCOE argues that more transparency into the
right-sizing processes is necessary to ensure that the results are
disciplined, cost-conscious investments.\3541\
---------------------------------------------------------------------------
\3540\ NESCOE Reply Comments at 6-8.
\3541\ NESCO Supplemental Comments at 9.
---------------------------------------------------------------------------
1659. Several commenters oppose the NOPR's right-sizing
proposal.\3542\ Competition Coalition asserts that the NOPR proposal
would result in over-building the transmission system now for
speculative future transmission needs, leaving customers with the bill
for any stranded costs.\3543\ Louisiana Commission claims that the NOPR
right-sizing proposal should not be adopted because it will intrude on
its retail authority.\3544\
---------------------------------------------------------------------------
\3542\ Anbaric Initial Comments at 7; Competition Coalition
Initial Comments at 62-63; DC and MD Offices of People's Counsel
Initial Comments at 47-48; Idaho Power Initial Comments at 13;
Kentucky Commission Chair Chandler Initial Comments at 16-19;
Louisiana Commission Initial Comments at 39; LS Power Initial
Comments at 135-136, 138, 141-142, 145-146; Massachusetts Attorney
General Initial Comments at 51-52; Ohio Consumers Initial Comments
at 23; Resale Iowa Initial Comments at 8-9.
\3543\ Competition Coalition Initial Comments at 62-63.
\3544\ Louisiana Commission Initial Comments at 39.
---------------------------------------------------------------------------
1660. Other commenters argue that the proposed 230 kV threshold is
inappropriate.\3545\ For example, Avangrid contends that it is overly
prescriptive and does not reflect regional conditions, needs, and
stakeholder interests.\3546\ Avangrid states that, in ISO-NE, a 230 kV
threshold would result in in-kind replacement of lower voltage
transmission facilities rather than right-sizing facilities to most
efficiently meet transmission needs identified through Long-Term
Regional Transmission Planning.
---------------------------------------------------------------------------
\3545\ Avangrid Initial Comments at 15-16; California Commission
Initial Comments at 117-118; Kentucky Commission Chair Chandler
Initial Comments at 18-19; New York TOs Initial Comments at 17-18;
NYISO Initial Comments at 59; Ohio Consumers Initial Comments at 23;
PJM Initial Comments at 9, 121-122; State Agencies Initial Comments
at 20-21; TAPS Initial Comments at 6, 66.
\3546\ Avangrid Initial Comments at 15-16.
---------------------------------------------------------------------------
1661. Kentucky Commission Chair Chandler argues that 200 kV or 230
kV are no longer adequate rules of thumb to delineate local versus
regional transmission facilities, as transmission facilities that may
have been formerly classified as local are likely to be regional in the
future. Rather, Kentucky Commission Chair Chandler states that
transmission facilities rated between 100 kV and 200 kV will play a
greater role in the regional delivery of energy.\3547\ Ohio Consumers
argue that the Commission should lower the threshold to 69 kV because
many end-of-life transmission facilities in the PJM transmission
planning process are expensive rebuilds of transmission facilities that
are rated below 230 kV.\3548\ TAPS argues that excluding lower voltage
facilities prevents transmission planning regions from being able to
consider more efficient and cost-effective alternatives.\3549\
---------------------------------------------------------------------------
\3547\ Kentucky Commission Chair Chandler Initial Comments at
18-19.
\3548\ Ohio Consumers Initial Comments at 23.
\3549\ TAPS Initial Comments at 6, 66.
---------------------------------------------------------------------------
1662. LS Power asserts that the Commission should not limit its
right-sizing proposal to facilities above 230 kV and that such reforms
should apply
[[Page 49535]]
to lower voltage transmission facilities as well.\3550\ Specifically,
LS Power argues that transmission facilities that operate at or above
100 kV (and sometimes facilities operating at a lower voltage) are
regional in nature and should be subject to exclusively regional
transmission planning.\3551\
---------------------------------------------------------------------------
\3550\ See LS Power Partial Reply Comments at 61-64 (citing
California Commission Initial Comments at 117; Eversource Initial
Comments at 38; ISO-NE Initial Comments at 39; Kentucky Commission
Chair Chandler Initial Comments at 19; LS Power Initial Comments at
142; NARUC Initial Comments at 64; Ohio Consumers Initial Comments
at 23; State Agencies Initial Comments at 21).
\3551\ Id. at 64.
---------------------------------------------------------------------------
1663. Shell states that the Commission should consider lowering the
proposed voltage threshold to 115 kV, but notes that doing so may
include lower voltage facilities that predominantly serve sub-
transmission, wholesale distribution, or retail distribution purposes
and have only local benefits.\3552\ To ensure that the costs of sub-
transmission, wholesale distribution, or retail distribution facilities
are not rolled into transmission rates, Shell argues that the
Commission should reexamine its standards for rolling the costs of
transmission facilities into rates, its application of the Seven Factor
test for functionalizing facilities as distribution or transmission,
and its Mansfield integration analysis.\3553\ Western Utilities contend
that the Commission should not adopt Shell's proposal to lower the
right-sizing threshold to 115 kV because whether or not a facility is a
transmission facility is a fact-specific question.\3554\
---------------------------------------------------------------------------
\3552\ Shell Reply Comments at 10 (citing Shell Initial Comments
at 34).
\3553\ Shell Initial Comments at 34-36; Shell Reply Comments at
10-11 (citing Commonwealth Edison Co., 167 FERC ] 61,173, at P 12
n.23 (2019); Buckeye Power, Inc. v. Am. Transmission Sys. Inc.,
Opinion No. 533, 148 FERC ] 61,174, at PP 12, 41, 69 (2014), order
on reh'g, 151 FERC ] 61,091 (2015); Mansfield Mun. Elec. Dep't v.
New England Power Co., Opinion No. 454, 97 FERC ] 61,134 (2001),
order on reh'g, Opinion No. 454-A, 98 FERC ] 61,115 (2002)).
\3554\ See Western Utilities Reply Comments at 2 (citing Shell
Initial Comments at 34-35).
---------------------------------------------------------------------------
1664. Pine Gate recommends against the Commission adopting the
bright-line voltage threshold specified in the NOPR, but urges the
Commission require each transmission provider to: (1) list and evaluate
existing transmission facilities operating at or above 230 kV that it
owns and estimates may need to be replaced with a new in-kind
transmission facility over the next 10 years; and (2) establish
criteria by which it will identify lower-voltage facilities that could
potentially be right-sized through Long-Term Regional Transmission
Planning.\3555\ Relatedly, WIRES states that the Commission should
either: (1) clarify that transmission providers would not be prohibited
from considering right-sizing transmission facilities at a lower
voltage threshold if existing transmission planning processes already
do so; or (2) provide flexibility for transmission planning regions to
justify the use of a different voltage threshold.\3556\
---------------------------------------------------------------------------
\3555\ Pine Gate Initial Comments at 48.
\3556\ WIRES Initial Comments at 10.
---------------------------------------------------------------------------
1665. Some commenters oppose the NOPR proposal's use of a 10-year
timeframe for the right-sizing reform.\3557\ Exelon states that the
Commission's proposed requirement to have a 10-year time horizon for
identifying a list of potential end-of-useful life needs is infeasible
and inconsistent with utility practices. Specifically, Exelon states
that it does not develop a concrete plan for transmission projects to
meet end-of-useful life needs five years in advance--let alone 10
years--but instead maintains a ``dynamic list'' of older assets, the
condition of which is evaluated on a rolling basis, based on numerous
factors such as equipment inspection and testing, maintenance history,
historical performance, obsolescence, operational experience, asset
criticality, equipment failure data, and age.\3558\
---------------------------------------------------------------------------
\3557\ Eversource Initial Comments at 53; Exelon Initial
Comments at 54-55; Indicated PJM TOs Initial Comments at 46-47;
Kentucky Commission Chair Chandler Initial Comments at 17-18; SERTP
Sponsors Initial Comments at 38-39.
\3558\ Exelon Initial Comments at 54-55 (Exelon Utilities Asset
Management Guidelines and Practices 3 (Nov. 18, 2020), https://pjm.com/-/media/committees-groups/committees/srrtep-ma/2020/20201216/20201216-exelon-final-end-eol-guidelines.ashx).
---------------------------------------------------------------------------
1666. Some commenters argue that the NOPR proposal is not
applicable to their transmission planning regions or that their
existing processes are sufficient.\3559\ For example, CAISO explains
that it plans all upgrades and expansions of transmission facilities
under its operational control, which include transmission facilities at
all voltage levels and at all locations on the system. Further, CAISO
states that, if an asset management, maintenance, or in-kind
replacement project can be expanded or modified to address a CAISO-
identified transmission need in a local area (or system wide), CAISO
can order such expansion or modification in its regional transmission
planning process.\3560\
---------------------------------------------------------------------------
\3559\ CAISO Initial Comments at 47-48; Dominion Initial
Comments at 69-70, 72; Duke Initial Comments at 46; MISO Initial
Comments at 87-88; MISO Reply Comments at 28; New York TOs Initial
Comments at 17; SERTP Sponsors Initial Comments at 38-39; SPP
Initial Comments at 34-35.
\3560\ CAISO Initial Comments at 47-48 (citing CAISO ANOPR
Initial Comments at 73; Cal. Pub. Utils. Comm'n v. Pac. Gas and
Elec. Co., 164 FERC ] 61,161 at PP 35-37, 69).
---------------------------------------------------------------------------
1667. MISO asserts that right-sizing is fundamental to transmission
planning and should always be considered as part of Good Utility
Practice, but that right-sizing decisions are best made on a case-by-
case basis, as there are both quantitative and qualitative
considerations that must be taken into account.\3561\ MISO contends
that its existing local transmission planning achieves the Commission's
objectives, as the MISO process provides for right-sizing where MISO
selects the most robust solution. Accordingly, MISO states that, for
its footprint, no changes are needed.\3562\
---------------------------------------------------------------------------
\3561\ MISO Initial Comments at 87.
\3562\ MISO Reply Comments at 28 (citing OMS Initial Comments at
15-17).
---------------------------------------------------------------------------
1668. SERTP Sponsors argue that replacement decisions for
particular equipment may be triggered more by the conditions of a
particular facility than its age. SERTP Sponsors argue that a process
like right-sizing already occurs in SERTP's regional transmission
planning, which requires that the SERTP Sponsors affirmatively look to
determine if there are regional transmission alternatives that would be
more efficient or cost-effective than the transmission solutions
otherwise included in SERTP's regional transmission plan, including
projects to replace aging infrastructure.\3563\
---------------------------------------------------------------------------
\3563\ SERTP Sponsors Initial Comments at 38-39 (citations
omitted).
---------------------------------------------------------------------------
1669. Several commenters argue that the Commission should adopt
alternative or additional requirements that apply when transmission
providers evaluate transmission facilities for right-sizing.\3564\ For
example, Ameren requests that the Commission require transmission
providers to consider the following additional criteria when
determining whether a transmission facility is eligible for right-
sizing: (1) whether a transmission line is in the top 10 limiting
elements on an import or transfer study; (2) whether a line has shown
up as a real-time binding
[[Page 49536]]
constraint in the last two years; or (3) whether a line shows up as a
binding constraint in future security constrained economic dispatch
simulations.\3565\ California Energy Commission argues that the
Commission should develop a definition of ``right-sizing,'' possibly
tied to a specified planning reserve margin as well as an expected
level of demand growth.\3566\ Furthermore, ACEG and PG&E both request
that the Commission consider the use of existing transmission facility
rights-of-way as an eligibility threshold for potentially right-sized
replacement transmission facilities.\3567\
---------------------------------------------------------------------------
\3564\ ACEG Initial Comments at 58; Ameren Initial Comments at
46-47; American Municipal Power Initial Comments at 27; Breakthrough
Energy Initial Comments at 18-19; California Energy Commission
Initial Comments at 3; Competition Coalition Initial Comments at 68;
CTC Global Initial Comments at 18; Eversource Initial Comments at
53; Exelon Initial Comments at 56-58; Grid United Initial Comments
at 3-4; Pennsylvania Commission Initial Comments at 21; PG&E Initial
Comments at 13-14; Pine Gate Initial Comments at 48; PIOs Initial
Comments at 57-58; PJM Initial Comments at 9, 121-122; PPL Initial
Comments at 36-37; Shell Initial Comments at 34.
\3565\ Ameren Initial Comments at 46-47.
\3566\ California Energy Commission Initial Comments at 3.
\3567\ ACEG Initial Comments at 57-58; PG&E Initial Comments at
13.
---------------------------------------------------------------------------
1670. Eversource asserts that it would be more efficient to
evaluate potential right-sizing: (1) through a review of the
transmission facilities that could be upgraded to address identified
long-term transmission needs, including an evaluation of whether an in-
kind replacement is likely to occur during the planning horizon; or (2)
through transmission owner identification of right-sizing options that
align with needs identified in the longer-term study as they perform
their normal asset condition projects.\3568\
---------------------------------------------------------------------------
\3568\ Eversource Initial Comments at 53.
---------------------------------------------------------------------------
1671. Entergy asserts that the Commission should clarify that
storm-hardening transmission projects are not subject to a right-sizing
requirement because it would add complications and delays to the right-
sizing process.\3569\ Pennsylvania Commission argues that a
transmission facility should not be right-sized if its total cost
exceeds the total cost of the local transmission project and a
competitively procured transmission project to address the regional
need.\3570\
---------------------------------------------------------------------------
\3569\ Entergy Initial Comments at 38.
\3570\ Pennsylvania Commission Initial Comments at 21.
---------------------------------------------------------------------------
1672. Some commenters call for the Commission to expand the right-
sizing reform to other categories of transmission facilities.\3571\
Eversource argues that the Commission should encourage transmission
providers to incorporate right-sizing considerations into other
transmission planning processes, such as the reliability planning
process, as appropriate.\3572\ Similarly, ACORE and American Municipal
Power request that the Commission clarify that right-sizing also
applies in any short-term transmission planning for reliability and
economic transmission projects.\3573\ Grid United states that the
Commission should require Long-Term Regional Transmission Planning to
assess and allow for up-sizing transmission projects, such as building
a single circuit transmission line that is double-circuit ready.\3574\
---------------------------------------------------------------------------
\3571\ American Municipal Power Initial Comments at 27; Avangrid
Initial Comments at 16; Clean Energy Associations Initial Comments
at 26-27, 37; Eversource Initial Comments at 54; MISO Initial
Comments at 88; NYISO Initial Comments at 59-60; PIOs Initial
Comments at 57-58; TAPS Initial Comments at 6, 64-65.
\3572\ Eversource Initial Comments at 54.
\3573\ ACORE Initial Comments at 19; American Municipal Power
Initial Comments at 27.
\3574\ Grid United Initial Comments at 4.
---------------------------------------------------------------------------
1673. Several commenters argue that the Commission should allow
flexibility on the thresholds for evaluating transmission facilities
for right-sizing.\3575\ To prevent needless litigation that will cause
delays and cost increases for customers, Dominion states that any final
order should be clear that transmission providers will not be penalized
if a replacement project arises that was not previously
identified.\3576\
---------------------------------------------------------------------------
\3575\ American Municipal Power Initial Comments at 27; APPA
Initial Comments at 48; Avangrid Initial Comments at 15-16;
California Commission Initial Comments at 117; Clean Energy
Associations Initial Comments at 36-37; Dominion Initial Comments at
72-73; EEI Initial Comments at 41; Eversource Initial Comments at
52-53; ISO-NE Initial Comments at 39; NARUC Initial Comments at 58-
59, 63-64; National Grid Initial Comments at 40-41; NESCOE Initial
Comments at 80; New York TOs Initial Comments at 18; NRECA Initial
Comments at 67; NYISO Initial Comments at 9, 60; PG&E Reply Comments
at 14-15; PPL Initial Comments at 37; US DOE Initial Comments at 48;
Vermont State Entities Initial Comments at 13; WIRES Initial
Comments at 10.
\3576\ Dominion Initial Comments at 73.
---------------------------------------------------------------------------
1674. NYISO contends that the final order should permit
transmission providers, with input from state entities and
stakeholders, to integrate planning for right-sizing transmission
replacements into existing transmission planning processes, including
by considering transmission facilities that they anticipate will be
replaced in-kind when identifying transmission needs in short-term or
long-term transmission planning.\3577\
---------------------------------------------------------------------------
\3577\ NYISO Initial Comments at 9, 60.
---------------------------------------------------------------------------
1675. US DOE encourages the Commission to provide sufficient
flexibility to ensure that the proposed reforms are cost-effective and
do not overburden the transmission planning process. US DOE asserts
that transmission providers should not be required to submit every in-
kind replacement for all equipment above 230 kV for consideration for
right-sizing and that regional transmission planning processes should
not be required to consider each piece of equipment provided by each
member of a transmission planning region.\3578\
---------------------------------------------------------------------------
\3578\ US DOE Initial Comments at 48.
---------------------------------------------------------------------------
1676. PG&E argues that the Commission should allow for flexibility
in any right-sizing-related requirements, noting that a transmission
provider may need to replace an aging or failing transmission facility
sooner than a right-sized transmission project can be developed. In
that case, PG&E states that the transmission owner would need to
proceed with the replacement project to ensure reliability or protect
public safety even if the RTO/ISO had determined that a transmission
facility would benefit from being right-sized.\3579\
---------------------------------------------------------------------------
\3579\ PG&E Reply Comments at 15.
---------------------------------------------------------------------------
c. Commission Determination
1677. We adopt the NOPR proposal, with modification, to require
that, as part of each Long-Term Regional Transmission Planning cycle,
transmission providers in each transmission planning region evaluate
whether transmission facilities (1) operating above a specified kV
threshold and (2) that an individual transmission provider that owns
the transmission facility anticipates replacing in-kind with a new
transmission facility during the next 10 years can be ``right-sized''
to more efficiently or cost-effectively address a Long-Term
Transmission Need. To effectuate this reform, we also adopt the NOPR
proposal, with modification, to require that, sufficiently early in
each Long-Term Regional Transmission Planning cycle, each transmission
provider submit its in-kind replacement estimates (i.e., estimates of
the transmission facilities operating at and above the specified kV
threshold that an individual transmission provider that owns the
transmission facility anticipates replacing in-kind with a new
transmission facility during the next 10 years) for use in Long-Term
Regional Transmission Planning. With respect to the specified kV
threshold, transmission providers must propose on compliance a
threshold that does not exceed 200 kV (e.g., 115 kV and above). In
adopting the right-sizing reform in this final order, we recognize that
a transmission provider may have existing rights and responsibilities
with respect to maintaining and, when necessary, replacing existing
transmission facilities. We also adopt the NOPR proposals regarding a
Federal right of first refusal and cost allocation method for right-
sized replacement transmission facilities, as discussed below.
[[Page 49537]]
1678. We adopt the NOPR proposal to define ``right-sizing'' as the
process of modifying a transmission provider's in-kind replacement of
an existing transmission facility to increase that facility's transfer
capability.\3580\ Additionally, we clarify that, for purposes of this
right-sizing reform, an ``in-kind replacement transmission facility''
is a new transmission facility that: (1) would replace an existing
transmission facility that a transmission provider has identified in
its in-kind replacement estimate as needing to be replaced; (2) would
result in no more than an incidental increase in capacity over the
existing transmission facility identified as needing to be
replaced;\3581\ and (3) is located in the same general route as, and/or
uses the existing rights-of-way of, the existing transmission facility
identified as needing to be replaced.
---------------------------------------------------------------------------
\3580\ NOPR, 179 FERC ] 61,028 at P 403 (``Right-sizing could
include, for example, increasing the transmission facility's voltage
level, adding circuits to the towers (e.g., redesigning a single-
circuit line as a double-circuit line), or incorporating advanced
technologies (such as advanced conductor technologies).'').
\3581\ The Commission has addressed the meaning of an incidental
increase in the context of a replacement transmission facility in
several orders. See, e.g., S. Cal. Edison Co., 164 FERC ] 61,160 at
P 33, order on reh'g, 168 FERC ] 61,170 (2019); Cal. Pub. Utils.
Comm'n v. Pac. Gas & Elec. Co., 164 FERC ] 61,161 at P 68; see also
PJM Interconnection, L.L.C., 172 FERC ] 61,136 at P 84, order on
reh'g, 173 FERC ] 61,225 (2020); PJM Interconnection, L.L.C., 173
FERC ] 61,242 at P 54, order on reh'g, 176 FERC ] 61,053 (2021).
---------------------------------------------------------------------------
1679. Further, we clarify that a ``right-sized replacement
transmission facility'' is a new transmission facility that: (1) would
meet the need to replace an existing transmission facility that a
transmission provider has identified in its in-kind replacement
estimate as one that it plans to replace with an in-kind replacement
transmission facility while also addressing a Long-Term Transmission
Need; (2) results in more than an incidental increase in the capacity
of an existing transmission facility that a transmission provider has
identified for replacement in its in-kind replacement estimate; and (3)
is located in the same general route as, and/or uses or expands the
existing rights-of-way of, the existing transmission facility that a
transmission provider has identified for replacement in its in-kind
replacement estimate. We believe these clarifications are necessary to
ensure that use of the right-sizing reform addresses replacement
transmission facilities and not entirely new transmission facilities.
1680. As an example, assume that transmission providers determine
that an existing transmission facility included in a transmission
provider's in-kind replacement estimate can be right-sized (Segment 1)
and, together with a separate new transmission facility (Segment 2), is
the more efficient or cost-effective solution to a Long-Term
Transmission Need. In this example, Segment 1 is a new 50-mile, 345 kV
transmission facility between interconnection points A and B that
requires the expansion of an existing right-of-way, and replaces an
existing 50-mile, 230 kV transmission facility between interconnection
points A and B. Segment 2 in this example is a new 25-mile, 345 kV
transmission facility requiring entirely new rights-of-way from
interconnection points B to C. If both Segment 1 and Segment 2 are
selected to address a Long-Term Transmission Need, then, for purposes
of the requirements of this final order, only Segment 1 would be
considered a right-sized replacement transmission facility.
1681. Consistent with the NOPR proposal, and as discussed further
below, the process under this proposed right-sizing reform entails
taking the following steps, which transmission providers must describe
in their OATTs. The transmission providers in each transmission
planning region must propose a point sufficiently early in each Long-
Term Regional Transmission Planning cycle at which each individual
transmission provider in the transmission planning region will submit
its in-kind replacement estimates for use in Long-Term Regional
Transmission Planning. Then, if transmission providers identify a
right-sized replacement transmission facility as a potential solution
to a Long-Term Transmission Need as part of Long-Term Regional
Transmission Planning, that right-sized replacement transmission
facility must be evaluated in the same manner as any other proposed
Long-Term Regional Transmission Facility to determine whether it is the
more efficient or cost-effective transmission facility to address the
transmission need. More specifically, it is at this stage of the right-
sizing reform where transmission providers must use the in-kind
replacement estimates to determine if in-kind replacement transmission
facilities could be right-sized to more efficiently or cost-effectively
address a Long-Term Transmission Need(s). If a right-sized replacement
transmission facility addresses the transmission provider's need to
replace an existing transmission facility, meets the applicable
selection criteria included in Long-Term Regional Transmission
Planning, and is found to be the more efficient or cost-effective
solution to a Long-Term Transmission Need, then the right-sized
replacement transmission facility must be considered for selection.
1682. We find that a right-sized replacement transmission facility
has the potential to both meet an individual transmission provider's
responsibility to maintain the reliability of its existing transmission
system and address a Long-Term Transmission Need more efficiently or
cost-effectively than an in-kind replacement transmission facility or
another Long-Term Regional Transmission Facility.\3582\ Further, we
find that, if opportunities for right-sized replacement transmission
facilities are not considered, the Long-Term Regional Transmission
Planning process may not select the more efficient or cost-effective
transmission facilities to meet Long-Term Transmission Needs,
potentially rendering Commission-jurisdictional rates unjust and
unreasonable.\3583\
---------------------------------------------------------------------------
\3582\ NOPR, 179 FERC ] 61,028 at P 406.
\3583\ Id.
---------------------------------------------------------------------------
1683. As noted above, for purposes of implementing the right-sizing
requirements that we adopt in this final order, transmission providers
must propose on compliance a threshold that does not exceed 200 kV that
is used in identifying the transmission facilities that an individual
transmission provider anticipates replacing in-kind with a new
transmission facility during the next 10 years, which it must then
include in its in-kind replacement estimates. In other words, each
transmission provider in the transmission planning region must include
in its in-kind replacement estimates the transmission facilities
operating at and above 200 kV, or at and above a lower proposed
threshold, that it owns and anticipates replacing in-kind with a new
transmission facility during the next 10 years.\3584\ We find that this
threshold strikes a reasonable balance between capturing the
transmission facilities that are the most likely candidates for right-
sizing without overburdening transmission providers by requiring them
to identify all transmission facilities planned for in-kind
replacement, including lower voltage transmission facilities that may
be less likely to provide regional benefits, and therefore potentially
less likely to be more efficient or cost-effective transmission
solutions to Long-
[[Page 49538]]
Term Transmission Needs. Specifically, we believe adopting the 230 kV
threshold proposed in the NOPR could have excluded from consideration
some transmission facilities planned for in-kind replacement that are
likely to provide regional benefits.\3585\ In adopting a specified kV
threshold (so long as that threshold does not exceed 200 kV), as
opposed to the 230 kV threshold proposed in the NOPR, we note that the
Commission ``has wide discretion to determine where to draw
administrative lines.'' \3586\
---------------------------------------------------------------------------
\3584\ We note that while transmission providers may not propose
a kV threshold that exceeds 200 kV, they may propose a lower kV
threshold (e.g., 100 kV or 115 kV), which would require transmission
providers in that transmission planning region to include in their
in-kind replacement estimates a wider range of transmission
facilities that they own and anticipate replacing in-kind with a new
transmission facility during the next 10 years.
\3585\ For example, the maximum 200 kV threshold that we adopt
here mirrors existing processes (e.g., CAISO) for determining
whether a transmission facility provides regional benefits or more
localized benefits. Appendix A of CAISO's OATT defines a ``Large
Project'' as ``[a] transmission upgrade or addition that exceeds
$200 million in capital costs and consists of a proposed
transmission line or substation facilities capable of operating at
voltage levels greater than 200 kV.'' CAISO, CAISO eTariff, app. A,
Definitions (0.0.0), section Large Project. Moreover, we note that a
200 kV threshold aligns with the 200 kV threshold for
interconnection reforms discussed in the Coordination of Regional
Transmission Planning and Generator Interconnection Process section
of this final order.
\3586\ ExxonMobil Gas Mktg. Co. v. FERC, 297 F.3d 1071, 1085
(D.C. Cir. 2002) (quoting AT&T Corp. v. FCC, 220 F.3d 607, 627 (D.C.
Cir. 2000)).
---------------------------------------------------------------------------
1684. We find that the requirement for transmission providers to
identify a kV threshold not to exceed 200 kV to identify in-kind
replacements recognizes that the NOPR proposal did not align with the
region-specific characteristics outlined by some transmission
providers. For example, as ISO-NE notes, a large portion of ISO-NE's
transmission system consists of 115 kV transmission facilities.\3587\
We find that the maximum kV threshold that we adopt allows flexibility
for transmission providers, like ISO-NE, to tailor their proposed kV
threshold to their specific transmission planning regions (as long as
the threshold they apply is equal or lower than 200 kV), while ensuring
that the in-kind replacement transmission facilities that are most
susceptible to modification that could more efficiently or cost-
effectively address Long-Term Transmission Needs are considered for
right-sizing.
---------------------------------------------------------------------------
\3587\ ISO-NE Initial Comments at 39.
---------------------------------------------------------------------------
1685. With regard to the 10-year timeframe for in-kind replacement
estimates, we believe that 10 years is an appropriate timeframe to
evaluate potential in-kind replacement transmission facilities for
right-sizing because it balances the long lead times associated with
developing certain transmission facilities with the uncertainty
associated with the exact timing of when aging transmission facilities
may need to be replaced.\3588\ We also clarify that the 10-year
timeframe for in-kind replacement estimates should reflect a
transmission provider's estimates of the transmission facilities
operating at and above the specified kV threshold that an individual
transmission provider that owns the transmission facility anticipates
replacing in-kind with a new transmission facility during the next 10
years beginning at the start of each Long-Term Regional Transmission
Planning cycle. Furthermore, we believe that a 10-year timeframe is
more likely to capture a larger pool of potential in-kind replacement
transmission facilities that would be eligible for right-sizing. We
recognize, however, that transmission providers may obtain better
information about a transmission facility's condition as the
anticipated replacement date approaches and may also identify
additional transmission facilities that require replacement in fewer
than 10 years based on updated assessments of their condition. As such,
we clarify that transmission providers may update the lists of
transmission facilities that they anticipate replacing in subsequent
transmission planning cycles if they believe that an anticipated in-
kind replacement transmission facility is more urgently needed than
previously thought or if existing transmission facilities do not
deteriorate as quickly as previously expected.
---------------------------------------------------------------------------
\3588\ NOPR, 179 FERC ] 61,028 at P 406.
---------------------------------------------------------------------------
1686. Several commenters oppose the right-sizing reform. They
suggest that adopting the reform would harm competition or existing
transmission planning processes that already evaluate whether
replacement transmission facilities can be increased in transfer
capability. We are unpersuaded by these arguments. We adopt the right-
sizing reform because it captures certain transmission planning
efficiencies by addressing aging transmission infrastructure issues
while also providing an opportunity to increase transfer capability
(i.e., develop the right-sized replacement transmission facility) to
address Long-Term Transmission Needs more efficiently or cost-
effectively. With respect to concerns about the right-sizing reform's
impact on competition, we address that issue below under the section on
Rights of First Refusal. Regarding commenters' arguments that existing
transmission planning processes already evaluate whether replacement
transmission facilities can be right-sized, we note that we require
transmission providers to consider right-sizing as part of Long-Term
Regional Transmission Planning. If transmission providers wish to
continue to consider right-sizing opportunities in some or all of their
existing transmission planning processes in addition to Long-Term
Regional Transmission Planning, this reform does not address those
processes, and they may continue to adhere to existing practices that
are not modified by this final order. Further, we emphasize that
transmission providers may propose compliance approaches that are
consistent with or superior to these requirements, and as such,
depending on their individual circumstances and approaches, may be able
to demonstrate that a method akin to their existing practice is also
appropriate for right-sizing in Long-Term Regional Transmission
Planning.
1687. In response to PJM States' request for clarification
regarding the interaction between existing processes and whether the
right-sizing reform necessitates competitive transmission development
processes, we recognize that a transmission provider may have existing
rights and responsibilities with respect to maintaining and, when
necessary, replacing existing transmission facilities. Regarding PJM
States' request for clarification on competitive transmission
development processes, we refer to the Right of First Refusal section
below.
1688. In response to Exelon's concerns regarding the timing of
replacement transmission facilities, we clarify that the 10-year
timeframe associated with the right-sizing reform applies to
transmission facilities that a transmission provider anticipates
replacing. In other words, the requirement for a transmission provider
to include in its in-kind replacement estimates any transmission
facilities that it anticipates replacing in-kind during the next 10
years does not create an obligation for the transmission provider to
change any existing process that it has to identify which transmission
facilities it anticipates replacing. However, a transmission provider
must include in its in-kind replacement estimates any transmission
facilities it anticipates replacing during the next 10 years beginning
at the start of each Long-Term Regional Transmission Planning cycle,
regardless of the process it uses to identify the facilities.
1689. In response to SERTP Sponsors and PG&E's arguments that
replacement decisions may be triggered more by the conditions of a
particular transmission facility than its age, we reiterate, consistent
with the statement the Commission made in the NOPR, we recognize that a
transmission provider may have existing rights and responsibilities
with respect to maintaining, and when necessary,
[[Page 49539]]
replacing existing transmission facilities. We recognize that, as SERTP
Sponsors note, replacement decisions may be triggered by other
conditions than a transmission facility's age or condition, and since
we recognize that a transmission provider may have existing rights and
responsibilities under existing laws with respect to maintaining and,
when necessary, replacing transmission facilities, we note that SERTP
Sponsors, as well as any other transmission providers, may address such
replacements of existing transmission facilities according to their
existing processes.
1690. In response to Entergy's request for clarification regarding
storm-hardening, we reiterate that the right-sizing reform we adopt
here pertains to transmission facilities that a transmission provider
anticipates replacing with an in-kind replacement transmission
facility. To the extent that storm-hardening transmission projects do
not encompass the replacement of existing transmission facilities with
an in-kind replacement transmission facility, those storm-hardening
transmission projects need not be included on a transmission provider's
list of in-kind replacement estimates.
1691. In response to US DOE's argument that transmission providers
should not be required to submit every in-kind replacement for all
equipment, we clarify that the right-sizing reform we adopt here
requires transmission providers to list in their in-kind replacement
estimates only the transmission facilities operating at and above the
specified kV threshold that they own and anticipate replacing in-kind
with a new transmission facility during the next 10 years, provided
transmission providers may not propose a specified kV threshold higher
than 200 kV.
1692. WIRES requests that the Commission clarify that transmission
providers would not be prohibited from considering right-sizing
transmission facilities lower than 230 kV if existing transmission
planning processes already do so. We clarify that, given our
modification to the NOPR proposal, transmission providers may propose
on compliance a threshold lower than 200 kV for considering right-
sizing transmission facilities. We reiterate that the 200 kV threshold
is a maximum threshold (i.e., transmission providers may not propose a
right-sizing threshold higher than 200 kV).
2. Right of First Refusal
a. NOPR Proposal
1693. In the NOPR, the Commission proposed, for any right-sized
replacement transmission facility that is selected to meet transmission
needs identified through Long-Term Regional Transmission Planning, to
require the establishment of a Federal right of first refusal for the
transmission provider that includes the in-kind replacement
transmission facility in its in-kind replacement estimates, which would
extend to any portion of such a transmission facility located within
the applicable transmission provider's retail distribution service
territory or footprint.\3589\
---------------------------------------------------------------------------
\3589\ Id. PP 408-409.
---------------------------------------------------------------------------
b. Comments
1694. Some commenters support the proposed Federal right of first
refusal for right-sized replacement transmission facilities.\3590\ AEP
argues that without it, transmission providers may develop an in-kind
replacement facility instead of the right-sized transmission facility
identified in the regional transmission planning process.\3591\
Similarly, PG&E states that providing a Federal right of first refusal
for right-sized replacement transmission facilities will provide an
incentive for transmission providers to develop such projects, where
appropriate.\3592\
---------------------------------------------------------------------------
\3590\ AEP Initial Comments at 46-47; Ameren Reply Comments at
14-15; Dominion Initial Comments at 75; EEI Initial Comments at 41;
Exelon Initial Comments at 58; MISO TOs Initial Comments at 27-28;
PG&E Reply Comments at 15-16; US Chamber of Commerce Initial
Comments at 11; Vermont Electric and Vermont Transco Initial
Comments at 5.
\3591\ AEP Initial Comments at 46-47 (citing NOPR, 179 FERC ]
61,028 at PP 408-409).
\3592\ PG&E Reply Comments at 16.
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1695. MISO TOs argue that, whether through in-kind replacement or
right-sized replacement, ``what is being done is an upgrade of an
existing transmission facility,'' for which the Commission has afforded
transmission owners Federal rights of first refusal through Order No.
1000 (and prior actions).\3593\ US Chamber of Commerce states that a
Federal right of first refusal for right-sized replacement transmission
facilities should also apply to right-sized transmission facilities, as
it would eliminate incentives to withhold in-kind replacements from the
regional transmission planning process.\3594\
---------------------------------------------------------------------------
\3593\ MISO TOs Initial Comments at 27-28.
\3594\ US Chamber of Commerce Initial Comments at 11 (citing
NOPR, 179 FERC ] 61,028 at P 409).
---------------------------------------------------------------------------
1696. Ameren states that critics of the NOPR's proposal to provide
transmission providers a Federal right of first refusal for right-
sizing projects question whether the Commission has met its FPA section
206 burden to demonstrate that the regional transmission planning
tariffs are currently unjust and unreasonable or unduly discriminatory
in order to justify this proposal.\3595\ Ameren contends that this
argument misses a critical point because, currently, replacement of
transmission facilities in-kind is generally not subject to the
regional transmission planning process or competitive transmission
development processes. Ameren asserts that the Commission need not find
any existing rate unjust and unreasonable in order to signal an intent
to approve such right of first refusals for right-sizing projects when
filed with the Commission under FPA section 205.\3596\
---------------------------------------------------------------------------
\3595\ Ameren Reply Comments at 14 (citing LS Power Initial
Comments at 50).
\3596\ Id.
---------------------------------------------------------------------------
1697. Several commenters oppose the proposed Federal right of first
refusal for right-sized replacement transmission facilities.\3597\
Massachusetts Attorney General argues that the Commission has not
demonstrated a ``rational connection'' between the Commission's
findings and the right-sizing reform. Massachusetts Attorney General
adds that the NOPR proposal is directly at odds with the Commission's
findings in Order Nos. 890 and 1000 and that the Commission fails to
provide ``good reasons'' for departing from those prior findings.\3598\
American Municipal Power argues that, even if incumbent transmission
owners currently have a right of first refusal for local transmission
facilities, that right should be limited to maintenance (i.e., in-kind
replacements) and not situations where a transmission facility would
expand or
[[Page 49540]]
enhance the transmission system.\3599\ LS Power argues that the right-
sizing proposal changes definitions in Order No. 1000, including the
definitions of an upgrade and a local transmission facility, and allows
a Federal right of first refusal for transmission facilities located on
an existing right-of-way instead of leaving the issue to state
law.\3600\ LS Power asserts that, even if the Commission could meet the
first prong of its section 206 analysis and find that the existing
transmission planning process is unjust and unreasonable, the
Commission must still establish that the entirety of the replacement
rate is just and reasonable which, LS Power argues, the Commission
cannot because of the tie to a Federal right of first refusal. Taken
together, LS Power argues that the NOPR proposal, if adopted, would
fail as a replacement rate.\3601\ Furthermore, LS Power argues that the
Federal right of first refusal for right-sized replacement transmission
facilities would essentially provide a Federal franchise, mandating
that transmission customers accept the ownership right of the existing
transmission owners to continue in perpetuity.\3602\
---------------------------------------------------------------------------
\3597\ AEE Reply Comments at 31; American Municipal Power
Initial Comments at 28-29; Anbaric Initial Comments at 7; California
Commission Initial Comments at 115-117; California Water Initial
Comments at 8-9; City of New York Initial Comments at 11-13;
Competition Coalition Initial Comments at 64; Competition Coalition
Reply Comments at 2; Industrial Customers Initial Comments at 4;
Kentucky Commission Chair Chandler Initial Comments at 19; LS Power
Initial Comments at 22, 25-26, 84-85; Massachusetts Attorney General
Initial Comments at 51-53; NextEra Initial Comments at 54-61;
Northwest and Intermountain Initial Comments at 21-22; Pennsylvania
Commission Initial Comments at 22-23; R Street Initial Comments at
3-4, 12-21; Resale Iowa Initial Comments at 8-9; TAPS Initial
Comments at 68.
\3598\ Massachusetts Attorney General Initial Comments at 40, 51
(citing 5 U.S.C. 706(2); 16 U.S.C. 825l(b); FCC v. Fox Television
Stations, Inc., 556 U.S. 502, 515 (2009); Motor Vehicle Mfrs. Ass'n
of the U. S. v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43
(1983)).
\3599\ American Municipal Power Initial Comments at 28.
\3600\ LS Power Initial Comments at 22.
\3601\ Id. at 147-48 (citing Nat'l Fuel Gas Supply Corp. v.
FERC, 468 F.3d 831, 845 (D.C. Cir. 2006); SEC v. Chenery Corp., 318
U.S. 80, 95 (1943)).
\3602\ Id. at 84-85.
---------------------------------------------------------------------------
1698. Northwest and Intermountain support clarifying that a Federal
right of first refusal for right-sized replacement transmission
facilities does not apply to any facilities that replace equipment that
has reached the end of its useful life. Moreover, Northwest and
Intermountain contend that the Commission should require a competitive
solicitation for any right-sized transmission projects that meet
regional transmission needs.\3603\ AEE contends that the record does
not support further action on the proposed Federal right of first
refusal for right-sized replacement transmission facilities, and
instead reflects the complexity of the issues involved and the need for
a holistic review of competitive transmission development processes and
options for improving them.\3604\
---------------------------------------------------------------------------
\3603\ Northwest and Intermountain Initial Comments at 21-22.
\3604\ AEE Reply Comments at 31.
---------------------------------------------------------------------------
1699. Several commenters raise concerns about the incentives that
the proposed ederal right of first refusal for right-sized replacement
transmission facilities would introduce.\3605\ Pennsylvania Commission
argues that incumbent transmission owners may use it as a new tool to
avoid competition by displacing other regional transmission
facilities.\3606\ Given that transmission providers may not secure cost
recovery for imprudently incurred expenses, NextEra disagrees that,
without a Federal right of first refusal for right-sized replacement
transmission facilities, incumbent transmission owners may engage in
duplicative or inefficient transmission development.\3607\
---------------------------------------------------------------------------
\3605\ Anbaric Initial Comments at 7; California Commission
Initial Comments at 114-115; Competition Coalition Initial Comments
at 65-67; LS Power Initial Comments at 81-82; Massachusetts Attorney
General Initial Comments at 51-52; NextEra Initial Comments at 58;
Pennsylvania Commission Initial Comments at 22; Resale Iowa Initial
Comments at 8-9.
\3606\ Pennsylvania Commission Initial Comments at 22.
\3607\ NextEra Initial Comments at 59-61 (citations omitted).
---------------------------------------------------------------------------
1700. Some commenters oppose the proposed Federal right of first
refusal for right-sized replacement transmission facilities because
they argue that it would increase costs for customers.\3608\ California
Water argues that allowing a Federal right of first refusal for right-
sized replacement transmission facilities would permit incumbent
transmission owners to construct right-sized transmission facilities
without any cost guardrails, which could end up being more expensive
than the in-kind replacements.\3609\ Alternatively, some commenters
argue that their existing transmission planning processes already
consider ``right-sizing'' replacement transmission facilities and may
not include a Federal right of first refusal.\3610\
---------------------------------------------------------------------------
\3608\ See California Commission Initial Comments at 117;
California Water Initial Comments at 9; Competition Coalition
Initial Comments at 66-67; DC and MD Offices of People's Counsel
Initial Comments at 47-48; R Street Reply Comments at 5-6; State
Agencies Initial Comments at 21-22.
\3609\ California Water Initial Comments at 9.
\3610\ CAISO Initial Comments at 47-49; New York Commission and
NYSERDA Initial Comments at 15-16; New York TOs Initial Comments at
17-18; NYISO Initial Comments at 58-59.
---------------------------------------------------------------------------
1701. In response to claims that there is no logical basis for a
Federal right of first refusal for right-sized replacement transmission
facilities, MISO TOs state that the proposal applies to upgrades of an
existing transmission facility and that in Order No. 1000, the
Commission expressly reserved a Federal right of first refusal for an
individual utility to upgrade its own property. As such, MISO TOs
argue, a right-sizing requirement should neither deprive a transmission
owner of its rights regarding its own property or its right to
construct and own upgrades to its own system, nor should it implement
an unconstitutional taking of such owner's property.\3611\ Therefore,
MISO TOs state that the final order should clarify that nothing in the
right-sizing proposal eliminates an incumbent transmission owner's
Federal right of first refusal for any transmission facilities selected
through a right-sizing process.\3612\
---------------------------------------------------------------------------
\3611\ MISO TOs Reply Comments at 33 (citing Order No. 1000, 136
FERC ] 61,051 at PP 226, 319; Order No. 1000-A, 139 FERC ] 61,132 at
P 426; N.Y. Indep. Sys. Operator, Inc., 175 FERC ] 61,038, at PP 30,
33 (2021)).
\3612\ MISO TOs Reply Comments at 33 (citing MISO TOs Initial
Comments at 25-28).
---------------------------------------------------------------------------
c. Commission Determination
1702. We adopt the NOPR proposal to require the establishment of a
Federal right of first refusal for a right-sized replacement
transmission facility \3613\ that is selected to meet Long-Term
Transmission Needs. This Federal right of first refusal will apply to
the transmission provider that included in its in-kind replacement
estimate the existing transmission facility that the right-sized
replacement transmission facility would replace, and extends to any
portion of the right-sized replacement facility located within that
transmission provider's retail distribution service territory or
footprint, recognizing that any such portion must satisfy the
definition of a right-sized replacement facility, as revised by this
final order, including that the right-sized replacement transmission
facility is located in the same general route as, and/or uses or
expands the existing rights-of-way of, the existing transmission
facility.
---------------------------------------------------------------------------
\3613\ As noted above, right-sizing could include, for example,
increasing the transmission facility's voltage level, adding
circuits to the towers (e.g., redesigning a single-circuit line as a
double-circuit line), or incorporating advanced technologies (e.g.,
advanced conductor technologies). Additionally, we reiterate that,
as noted above, a right-sized replacement transmission facility is,
for purposes of this right-sizing reform, a new transmission
facility that: (1) would meet the need to replace an existing
transmission facility that a transmission provider has identified in
its in-kind replacement estimate as one that it plans to replace
with an in-kind replacement transmission facility while also
addressing a Long-Term Transmission Need; (2) results in more than
an incidental increase in the capacity of an existing transmission
facility that a transmission provider has identified for replacement
in its in-kind replacement estimate; and (3) is located in the same
general route as, and/or uses or expands the existing rights-of-way
of, the existing transmission facility that a transmission provider
has identified for replacement in its in-kind replacement estimate.
---------------------------------------------------------------------------
1703. In adopting the NOPR proposal to require the establishment of
a Federal right of first refusal for a right-sized replacement
transmission facility, we find that permitting a Federal right of first
refusal for right-sized replacement
[[Page 49541]]
transmission facilities will encourage transmission providers to
provide their best in-kind replacement estimates, because they will
have certainty that they will not lose the opportunity to invest in any
in-kind replacement transmission facility that is then selected as a
right-sized replacement transmission facility. As such, we find that a
Federal right of first refusal will remove a disincentive for
transmission providers to consider right-sizing in Long-Term Regional
Transmission Planning, helping to ensure that the more efficient or
cost-effective regional transmission solution to Long-Term Transmission
Needs is selected and likely built, and therefore that Commission-
jurisdictional rates are just and reasonable. Moreover, we note that
the definitions of ``in-kind replacement transmission facility'' and
``right-sized replacement transmission facility'' that we adopt, as
discussed above, are necessary to ensure that use of the right-sizing
reform addresses replacement transmission facilities and not entirely
new transmission facilities.\3614\
---------------------------------------------------------------------------
\3614\ See supra PP 1681-1683.
---------------------------------------------------------------------------
1704. We note that the establishment of a Federal right of first
refusal for right-sized replacement transmission facilities is an
exception to Order No. 1000's general requirement for transmission
providers to eliminate any Federal right of first refusal for regional
transmission facilities selected in a regional transmission plan.\3615\
In response to comments challenging this approach as violating the
precedent set in Order No. 1000, which eliminated Federal rights of
first refusal for new selected transmission facilities,\3616\ we find
that requiring a Federal right of first refusal for right-sized
replacement transmission facilities aligns with Order No. 1000.
---------------------------------------------------------------------------
\3615\ See supra P 1576.
\3616\ Order No. 1000, 136 FERC ] 61,051 at P 313.
---------------------------------------------------------------------------
1705. In Order No. 1000, the Commission required transmission
providers to remove Federal rights of first refusal from their OATTs
because they undermined the consideration of more efficient or cost-
effective potential transmission solutions proposed at the regional
level, which could lead to unjust and unreasonable rates for
Commission-jurisdictional services.\3617\ The Commission found that
Federal rights of first refusal created a barrier to entry that
discouraged nonincumbent transmission developers from proposing
alternative solutions for consideration at the regional level.\3618\
The Commission did not require the elimination of Federal rights of
first refusal for local transmission facilities,\3619\ and did not
alter the rights of incumbent transmission providers to build, own, and
recover costs for upgrades to its own transmission facilities,
regardless of whether the upgrade is selected.\3620\
---------------------------------------------------------------------------
\3617\ Id. PP 253, 256.
\3618\ Id. P 257.
\3619\ Id. P 318.
\3620\ Id. P 319 (citation omitted).
---------------------------------------------------------------------------
1706. We find that the Commission's reasons for removing Federal
rights of first refusal in Order No. 1000 do not apply to right-sized
replacement transmission facilities. Specifically, requiring a Federal
right of first refusal for right-sized replacement transmission
facilities does not undermine the consideration of more efficient or
cost-effective potential transmission solutions proposed at the
regional level; rather, we find that it will promote the consideration
of more efficient or cost-effective potential regional transmission
solutions to address Long-Term Transmission Needs. When compared
against the alternative of piecemeal development of in-kind replacement
transmission facilities, a Federal right of first refusal for right-
sized transmission facilities does not frustrate the goals of Order No.
1000 or lead to inefficiency in transmission development because the
right-sized replacement transmission facility represents the more
efficient or cost-effective regional transmission solution to address
Long-Term Transmission Needs (otherwise it would not be selected). We
recognize that a transmission provider may have existing rights and
responsibilities with respect to maintaining and, when necessary,
replacing their transmission facilities. Because the right-sizing
reform does not alter existing laws related to an individual
transmission provider's ability to proceed with an in-kind replacement
transmission facility, absent a Federal right of first refusal, we
believe the incumbent transmission provider whose in-kind replacement
transmission facility is selected to be right-sized would likely
proceed to develop the less efficient or cost-effective in-kind
replacement transmission facility. We find that the transmission
provider would prefer the assurance of a Federal right of first refusal
for the in-kind replacement transmission facility over the uncertainty
of subjecting a right-sized replacement transmission facility to the
Order No. 1000 competitive transmission development process. Because of
this incentive structure and the fact that the transmission provider
holds the leverage as to whether to build a right-sized replacement
transmission facility or a less efficient in-kind replacement
transmission facility, the establishment of the Federal right of first
refusal is necessary to effectuate this reform and ensure that
Commission-jurisdictional rates are just and reasonable.\3621\
---------------------------------------------------------------------------
\3621\ See NOPR, 179 FERC ] 61,028 at P 408 & n.652.
---------------------------------------------------------------------------
1707. By establishing a process that requires transmission
providers to evaluate opportunities to right-size in-kind replacement
transmission facilities to meet Long-Term Transmission Needs, and by
establishing a Federal right of first refusal for such right-sized
replacement transmission facilities, we believe that the right-sizing
reform in this final order will encourage transmission providers to
provide their best in-kind replacement estimates, as they will have
certainty that they will not lose the opportunity to invest in any in-
kind replacement transmission facility that is then selected as a
right-sized replacement transmission facility. Moreover, permitting a
Federal right of first refusal for right-sized replacement transmission
facilities will enable transmission providers to ensure that the more
efficient or cost-effective regional transmission solution to Long-Term
Transmission Needs is selected and that Commission-jurisdictional rates
are consequently just and reasonable.\3622\
---------------------------------------------------------------------------
\3622\ In response to those commenters who argue that their
existing transmission planning processes already consider ``right-
sizing'' replacement transmission facilities without the inclusion
of a Federal right of first refusal, we note that, separate from
compliance with this final order, transmission providers in each
transmission planning region can agree to participant funding
arrangements for right-sized replacement transmission facilities
that are not selected through Long-Term Regional Transmission
Planning, in which case the requirement to establish a Federal right
of first refusal for right-sized replacement transmission facilities
selected to meet Long-Term Transmission Needs would not apply.
---------------------------------------------------------------------------
1708. In response to MISO TOs' request regarding upgrades to
existing transmission facilities, we reiterate that nothing in the
right-sizing reform affects the right of an incumbent transmission
provider to build, own, and recover the costs for upgrades to its own
transmission facilities, regardless of whether an upgrade to an
existing transmission facility has been identified through a right-
sizing process and selected to address Long-Term Transmission Needs.
1709. We deny Northwest and Intermountain's request to clarify that
the right-sizing reform excludes transmission facilities that replace
equipment that has reached the end of its useful life. As explained
above, the Federal right of first refusal will apply to selected right-
sized replacement
[[Page 49542]]
transmission facilities, including those that are intended to replace
transmission facilities that have reached the end of their useful life.
3. Cost Allocation
a. NOPR Proposal
1710. With respect to cost allocation, the Commission proposed that
if a right-sized replacement transmission facility is selected, only
the incremental costs of right-sizing the transmission facility would
be eligible to use the applicable Long-Term Regional Transmission Cost
Allocation Method. The Commission proposed that the costs the incumbent
transmission provider would have otherwise incurred to construct the
in-kind replacement transmission facility be allocated in a manner
consistent with the allocation that would have otherwise occurred for
the in-kind replacement. The Commission preliminarily found that it is
just and reasonable and not unduly discriminatory or preferential for
only the portion of the costs associated with a right-sized replacement
transmission facility that is selected to be eligible to use the Long-
Term Regional Transmission Cost Allocation Method because it is the
right-sizing of the in-kind replacement transmission facility that
allows the transmission facility to meet the transmission needs
identified in Long-Term Regional Transmission Planning.\3623\
---------------------------------------------------------------------------
\3623\ NOPR, 179 FERC ] 61,028 at P 410.
---------------------------------------------------------------------------
1711. The Commission also proposed to require transmission
providers in each transmission planning region to amend their regional
transmission planning processes to provide transparency with respect to
which right-sized replacement transmission facilities have been
selected (and thus found to be a more efficient or cost-effective
transmission facility to meet regional transmission needs) and which
transmission facilities are simply included in the regional
transmission plan for informational (and not cost allocation)
purposes.\3624\
---------------------------------------------------------------------------
\3624\ Id. P 413.
---------------------------------------------------------------------------
b. Comments
1712. Some commenters support the NOPR proposal that the
incremental costs of right-sizing a transmission facility that is
selected would be eligible to use the applicable Long-Term Regional
Transmission Cost Allocation Method.\3625\ ACEG contends that without
it, a large amount of new transmission investment--directed solely at
replacement facilities--will be outside of Long-Term Regional
Transmission Planning and thus not given an opportunity to contribute
to the grid's overall efficiency and cost-effectiveness.\3626\
Eversource asserts that, in New England, asset condition projects
receive regional cost allocation, and requests clarification that the
Commission is not proposing to disturb the existing cost allocation
method for asset condition projects in ISO-NE that are not selected for
right-sizing in Long-Term Regional Transmission Planning.\3627\ NESCOE
recommends that the Commission require transmission providers to
explain on compliance the method that they will use to determine the
incremental costs of right-sizing a replacement transmission facility.
In addition, NESCOE supports the proposal to require transmission
providers to amend their regional transmission planning processes to
provide transparency with respect to which right-sized replacement
transmission facilities have been selected.\3628\
---------------------------------------------------------------------------
\3625\ ACEG Initial Comments at 57-58; Eversource Initial
Comments at 54; NARUC Initial Comments at 65; NESCOE Initial
Comments at 81.
\3626\ ACEG Initial Comments at 57-58.
\3627\ Eversource Initial Comments at 54.
\3628\ NESCOE Initial Comments at 81.
---------------------------------------------------------------------------
1713. Other commenters support the proposed cost allocation for
right-sized replacement transmission facilities, but express
reservations.\3629\ Entergy asserts that the Commission should clarify
that costs incurred absent right-sizing will be allocated under the
cost allocation method(s) that otherwise would apply to such costs,
which may include regional cost allocation.\3630\ With regard to
incremental costs, CTC Global urges the Commission to require the
transmission planning process to be based on future needs, future
benefits, total lifecycle costs, and total benefits for the life of the
resource. More specifically, CTC Global suggests that when considering
incremental costs, the Commission should consider including energy
savings, generating capacity reduction benefits, and resulting
reductions in greenhouse gas emissions as benefits associated with the
right-sized replacement transmission facility.\3631\
---------------------------------------------------------------------------
\3629\ CTC Global Initial Comments at 19; Dominion Initial
Comments at 75-76; Entergy Initial Comments at 39; MISO Initial
Comments at 87; NRG Initial Comments at 36-37.
\3630\ Entergy Initial Comments at 39.
\3631\ CTC Global Initial Comments at 19.
---------------------------------------------------------------------------
1714. Dominion states that it may be difficult to quantify and
allocate the incremental costs of right-sizing a replacement
transmission facility.\3632\ MISO agrees, stating that it will be
challenging to identify the portion of costs that should be recovered
as part of the age and condition upgrade using one cost allocation
method and a different cost allocation for the portion of the right-
sized upgrade identified as part of Long-Term Regional Transmission
Planning. MISO argues that this complexity will continue going forward
given that the accounting for two types of cost allocation to different
customers will have to be tracked for each right-sized replacement
transmission facility.\3633\
---------------------------------------------------------------------------
\3632\ Dominion Initial Comments at 75-76.
\3633\ MISO Initial Comments at 87.
---------------------------------------------------------------------------
1715. Some commenters oppose the NOPR proposal.\3634\ LS Power
argues that the proposal violates cost causation principles as it would
limit regional cost allocation to the incremental portion of the right-
sized replacement transmission facilities, regardless of beneficiary
analysis.\3635\ Indicated PJM TOs state that the Commission should not
impose any requirements with respect to the cost allocation of right-
sized replacement transmission facilities and instead should provide
transmission providers with the flexibility to determine a cost
allocation method.\3636\ Exelon agrees, adding that the Commission's
proposed approach creates unnecessary complications and adds a further
variable (base versus incremental cost) to the already complex and
often contentious cost allocation process. According to Exelon, the
proposal (1) incorrectly assumes that a transmission owner has
identified an in-kind replacement transmission facility and its cost;
(2) incorrectly assumes that a perfect overlap exists between the
displaced transmission facility (or need) and the right-sized
replacement transmission facility; and (3) fails to address adjustments
for cost savings or overruns on the right-sized portion of the
transmission facility.\3637\
---------------------------------------------------------------------------
\3634\ Exelon Initial Comments at 59; Indicated PJM TOs Initial
Comments at 47; LS Power Initial Comments at 86-87.
\3635\ LS Power Initial Comments at 86-87 (citing Old Dominion
Elec. Coop. v. FERC, 898 F.3d 1254, reh'g denied, 905 F.3d 671 (D.C.
Cir. 2018)).
\3636\ Indicated PJM TOs Initial Comments at 47 (citation
omitted).
\3637\ See Exelon Initial Comments at 59 & n.103.
---------------------------------------------------------------------------
c. Commission Determination
1716. We decline to adopt the NOPR proposal to require that, if a
right-sized replacement transmission facility is selected, only the
incremental costs of right-sizing the transmission facility will be
eligible to use the applicable Long-Term Regional Transmission Cost
Allocation Method, while the costs that the transmission provider would
otherwise have incurred to construct the in-kind replacement
transmission
[[Page 49543]]
facility must be allocated in a manner consistent with the allocation
that would have otherwise occurred for the in-kind replacement
transmission facility. This is because we find persuasive comments that
identify the complexities and challenges associated with tracking
portions of costs of two different transmission projects through time,
as well as allocating the costs of a right-sized replacement
transmission facility pursuant to two separate cost allocation
methods.\3638\ While the approach that the NOPR proposed to require may
still be a just and reasonable cost allocation approach for right-sized
replacement transmission facilities, should the relevant transmission
providers choose to take on these challenges and address them
adequately, we find it appropriate to provide flexibility to
transmission providers to propose a cost allocation method for selected
right-sized replacement transmission facilities. However, in providing
such flexibility, transmission providers must nevertheless demonstrate
on compliance that the cost allocation method for selected right-sized
replacement transmission facilities is just and reasonable and not
unduly discriminatory or preferential and, consistent with cost
causation, allocates costs in a manner that is at least roughly
commensurate with the estimated benefits of such facilities.\3639\
---------------------------------------------------------------------------
\3638\ Dominion Initial Comments at 75-76; Exelon Initial
Comments at 59; MISO Initial Comments at 87.
\3639\ See ICC v. FERC I, 576 F.3d at 477; Order No. 1000, 136
FERC ] 61,051 at PP 622, 639 (requiring costs of regional
transmission facilities to be allocated in a manner that is at least
roughly commensurate with estimated benefits).
---------------------------------------------------------------------------
1717. Further, we also require transmission providers in each
transmission planning region to amend their regional transmission
planning processes to provide transparency with respect to which right-
sized replacement transmission facilities have been selected, as well
as which transmission facilities are simply included in the regional
transmission plan for informational (and not cost allocation) purposes.
1718. We disagree with LS Power's assertion that the right-sizing
cost allocation method proposed in the NOPR violates cost causation
principles because it would limit regional cost allocation to the
incremental portion of the right-sized replacement transmission
facilities, regardless of other potential beneficiaries.\3640\ The
customers of the transmission provider that would be allocated the
costs associated with the original in-kind replacement transmission
facility would have otherwise been responsible for paying those costs
had the in-kind replacement transmission facility not been right-sized.
Further, we find that it is not unjust, unreasonable, or unduly
discriminatory or preferential that, for a right-sized replacement
transmission facility selected, only the portion of the costs
associated with right-sizing be eligible to use the Long-Term Regional
Transmission Cost Allocation Method. Specifically, we find that it is
the right-sizing of the in-kind replacement transmission facility that
allows the transmission facility to meet Long-Term Transmission Needs
identified in Long-Term Regional Transmission Planning. As such, we
disagree that allowing only the incremental costs of right-sizing the
right-sized replacement transmission facility to be eligible to use the
applicable Long-Term Regional Transmission Cost Allocation Method would
violate cost causation principles.
---------------------------------------------------------------------------
\3640\ LS Power Initial Comments at 86-87 (citing Old Dominion
Elec. Coop. v. FERC, 898 F.3d 1254).
---------------------------------------------------------------------------
1719. As we note above, we find merit with respect to commenters'
concerns about the difficulty in determining the portion of the costs
of a right-sized replacement transmission facility attributable to
right-sizing and the complexity in tracking portions of differing cost
allocation methods through time. For this reason, to the extent that
transmission providers propose to allocate the costs of right-sized
replacement transmission facilities pursuant to the cost allocation
method described in the NOPR, we require the transmission providers to
explain on compliance (1) the method that they will use to determine
the portion of the costs of a right-sized replacement transmission
facility that is incremental to the costs that would have been incurred
for the underlying in-kind replacement transmission facility, and (2)
the method by which they will track the portion of costs over time that
are allocated in accordance with the Long-Term Regional Transmission
Cost Allocation Method (or, if adopted, subject to a State Agreement
Process), as well as the portion of costs that would have been
allocated pursuant to the cost allocation method that otherwise would
have applied to the in-kind replacement transmission facility. We
believe that transmission providers are best positioned to determine
both the portion of the costs of a right-sized replacement transmission
facility that is incremental to the costs that would have been incurred
for the underlying in-kind replacement transmission facility, as well
as how to best track these costs over time for purposes of cost
allocation.
1720. In response to Eversource and Entergy's requests that the
Commission clarify the cost allocation method for in-kind replacement
transmission facilities that are not selected for right-sizing,\3641\
we clarify that we are not requiring any changes pursuant to this
right-sizing requirement that would affect the existing cost allocation
method(s) for in-kind replacement transmission facilities that are not
identified for right-sizing, or for the costs of the underlying in-kind
replacement transmission facilities that would have been incurred
absent right-sizing. Similarly, in response to Entergy's request for
clarification that costs incurred absent right-sizing will be allocated
under the cost allocation method(s) that otherwise would apply to such
costs, which may include regional cost allocation, we clarify that the
costs that the transmission provider would otherwise have incurred to
construct the in-kind replacement transmission facility must be
allocated in a manner consistent with the cost allocation method that
would have otherwise applied to that facility, which could include a
regional cost allocation method.
---------------------------------------------------------------------------
\3641\ Entergy Initial Comments at 39; Eversource Initial
Comments at 54.
---------------------------------------------------------------------------
1721. We also confirm, in response to comments from CTC Global,
that benefits associated with a potential right-sized replacement
transmission facility to address Long-Term Transmission Needs should be
evaluated in the same manner as for any potential regional transmission
facility that could address those needs, which includes evaluating all
of the costs of, and all of the benefits provided by, the right-sized
replacement transmission facility consistent with reforms outlined in
this final order.
1722. In response to Exelon's comments that the NOPR proposal
relies on incorrect assumptions regarding the transmission provider
identifying an in-kind replacement transmission facility and its cost,
as well as there being an overlap between the displaced transmission
facility and the right-sized replacement transmission facility, we
disagree and note that these conditions are prerequisites that serve as
the foundation for the right-sizing requirement. Where a transmission
provider has not identified an in-kind replacement transmission
facility that could be right-sized to address Long-Term Transmission
Needs more efficiently or cost-effectively, no basis exists to select a
right-sized replacement transmission facility.
[[Page 49544]]
4. Miscellaneous
a. Comments
1723. Some commenters recommend that the Commission adopt
confidentiality safeguards.\3642\ AEP and Indicated PJM TOs contend
that the Commission must adopt confidentiality provisions to ensure
that information related to right-sizing is not shared beyond the
regional planning entity because identification of end-of-life
transmission facilities demonstrates potential vulnerabilities that
could create security and reliability risks and could also provide
advantages to competitors.\3643\ WIRES argues that the Commission
should allow for the transmission owner to provide to the transmission
provider a non-public, confidential, non-binding list of transmission
facilities that may need to be replaced based on an appropriate time
horizon as determined by the transmission provider.\3644\ SERTP
Sponsors request that the Commission protect CEII information for
transmission facilities that are anticipated to be replaced.\3645\
---------------------------------------------------------------------------
\3642\ AEP Initial Comments at 46; Exelon Initial Comments at
57-58; Indicated PJM TOs Initial Comments at 45-46; SERTP Sponsors
Initial Comments at 39; WIRES Initial Comments at 10.
\3643\ AEP Initial Comments at 46; Indicated PJM TOs Initial
Comments at 45.
\3644\ WIRES Initial Comments at 10.
\3645\ SERTP Sponsors Initial Comments at 39.
---------------------------------------------------------------------------
1724. Conversely, PJM States request that the Commission require
the information on the in-kind replacement estimate list to be non-
confidential to the greatest extent possible or to require
justification as to why confidentiality is merited.\3646\
---------------------------------------------------------------------------
\3646\ PJM States Initial Comments at 7-8.
---------------------------------------------------------------------------
1725. Several commenters call for the Commission to increase
scrutiny on, or alter the presumption of prudence for, transmission
projects related to the right-sizing reform.\3647\ American Municipal
Power argues that if an incumbent transmission owner replaces local
transmission facilities at the end of their useful lives despite a
determination that a right-sized replacement transmission facility is
the more efficient or cost-effective transmission solution, the
incumbent transmission owner's in-kind replacement should be presumed
to be unjust and unreasonable for purposes of cost recovery.\3648\
---------------------------------------------------------------------------
\3647\ American Municipal Power Initial Comments at 29-30;
California Commission Initial Comments at 114-115; California Water
Initial Comments at 9; Harvard ELI Initial Comments at 5;
Massachusetts Attorney General Initial Comments at 52; Ohio
Consumers Initial Comments at 23-24; Pine Gate Initial Comments at
49-50; PIOs Initial Comments at 58; Resale Iowa Initial Comments at
9; TAPS Initial Comments at 6-7, 67-68.
\3648\ American Municipal Power Initial Comments at 29.
---------------------------------------------------------------------------
1726. ACEG asserts that the Commission has the authority under FPA
section 205 to review replacement transmission facility projects and
address problems in the local transmission planning process.\3649\ LS
Power argues that the Commission should use its existing authority to
confirm through show cause orders that transmission providers are
evaluating whether local transmission solutions can be displaced by a
regional transmission solution that is more efficient or cost-
effective.\3650\
---------------------------------------------------------------------------
\3649\ ACEG Initial Comments at 57.
\3650\ LS Power Initial Comments at 145 (citing LS Power ANOPR
Initial Comments at 134-135).
---------------------------------------------------------------------------
1727. Similarly, TAPS asserts that the NOPR imposes no consequences
on transmission owners that proceed with in-kind replacement projects
even when the transmission planning region has selected more efficient
and cost-effective alternatives for regional cost allocation. TAPS
argues that the Commission should exclude cost recovery for such
facilities from the scope of formula rates and require transmission
owners to make a separate filing pursuant to FPA section 205.
Alternatively, TAPS states that the Commission should impose a
presumption of imprudence and require such transmission owners to
demonstrate that the proposed replacement is more cost-effective and
efficient than the alternative selected by the transmission planning
region.\3651\
---------------------------------------------------------------------------
\3651\ TAPS Initial Comments at 6-7, 67-68 (citations omitted).
---------------------------------------------------------------------------
1728. On the other hand, PG&E argues that the Commission should
clarify that a transmission owner's right to decline to proceed with a
selected right-sized replacement transmission facility does not justify
disallowance of cost recovery for the in-kind replacement transmission
facility.\3652\
---------------------------------------------------------------------------
\3652\ PG&E Initial Comments at 14.
---------------------------------------------------------------------------
1729. Several commenters support consideration of alternative
transmission technologies and grid enhancing technologies when
evaluating right-sized replacement transmission facilities.\3653\ CTC
Global urges the Commission to require all transmission owners with a
line requiring in-kind replacement within 10 years to analyze whether a
transmission line's conductor should be replaced with an advanced
conductor through rebuild or reconductoring.\3654\ PIOs argue that
right-sizing opportunities should include increasing voltage, adding
circuits, and utilizing advanced technologies, and further argue that
right-sized replacement transmission facilities that use grid enhancing
technologies can create economies of scale to capture public policy and
economic benefits in addition to reliability.\3655\ VEIR agrees with
the Commission's proposal to include advanced conductors in its
definition of right-sizing, explaining that superconductors can enable
a five-fold increase in the power flow capacity of an existing
transmission corridor. VEIR therefore urges the Commission to
explicitly affirm that the deployment of advanced conductors would
constitute right-sizing.\3656\
---------------------------------------------------------------------------
\3653\ CTC Global Initial Comments at 18, 20; Maryland Energy
Administration Reply Comments at 5-6; NARUC Initial Comments at 58-
59; PIOs Initial Comments at 57-58; VEIR Initial Comments at 6.
\3654\ CTC Global Initial Comments at 18.
\3655\ PIOs Initial Comments at 57-58 (citing PIOs ANOPR Initial
Comments at 50).
\3656\ VEIR Initial Comments at 6.
---------------------------------------------------------------------------
1730. Some commenters argue that the NOPR's right-sizing proposal
is insufficient and call upon the Commission to take further
action.\3657\ For example, ACEG, American Municipal Power, and
California Commission argue that the Commission should expand the scope
of the right-sizing proposal.\3658\ American Municipal Power argues
that the Commission should require RTOs/ISOs to plan for all new
transmission facilities that have regional impacts, including: (1)
transmission facilities that meet the North American Electric
Reliability Corporation Bulk Electric System definition; and (2)
transmission projects that will replace an existing transmission
facility that was turned over to the RTO/ISO irrespective of the
voltage.\3659\ Similarly, LS Power argues that the Commission has the
authority to require regional transmission planning for existing
transmission facilities reaching the end of operational life, and that
such transmission
[[Page 49545]]
planning should be performed by an independent transmission
planner.\3660\
---------------------------------------------------------------------------
\3657\ ACEG Initial Comments at 57; American Municipal Power
Initial Comments at 25-26; American Municipal Power Reply Comments
at 5; California Commission Initial Comments at 106-108; California
Water Initial Comments at 10; Competition Coalition Initial Comments
at 68-70; Grid United Initial Comments at 3-4; Harvard ELI Initial
Comments at 4-5; LS Power Initial Comments at 136, 138, 141-142,
145-146; Ohio Consumers Initial Comments at 24; PIOs Initial
Comments at 53; TAPS Initial Comments at 6, 64-65.
\3658\ See ACEG Initial Comments at 57-58; American Municipal
Power Initial Comments at 25-26; American Municipal Power Reply
Comments at 5; California Commission Initial Comments at 113-118.
\3659\ American Municipal Power Reply Comments at 5.
\3660\ LS Power Initial Comments at 83-84, 141 (citations
omitted).
---------------------------------------------------------------------------
1731. Massachusetts Attorney General asserts that all right-sized
replacement transmission facilities should be subject to cost
containment, stating that transmission owners may present transmission
projects that look like good opportunities for right-sizing at low
cost, but without cost containment and competition, the final cost
could be much higher.\3661\ ACEG argues that the Commission could issue
policy guidance regarding its scope and process for review of new
replacement transmission facilities in transmission rate cases.\3662\
---------------------------------------------------------------------------
\3661\ Massachusetts Attorney General Initial Comments at 52.
\3662\ ACEG Initial Comments at 57 (citation omitted).
---------------------------------------------------------------------------
1732. Competition Coalition and LS Power argue that the Commission
should protect customers by expanding the benefits of regional
transmission planning and competition to all transmission projects 100
kV and above.\3663\ Ameren responds that this request by LS Power to
expand the range of transmission projects subject to competition is
outside the scope of the NOPR.\3664\
---------------------------------------------------------------------------
\3663\ Competition Coalition Initial Comments at 68-69; LS Power
Initial Comments at 136, 141 (citations omitted); LS Power and NRG
Post-Technical Conference Comments at 10 & n.17 (noting that its
comment on this issue is attributed to LS Power only).
\3664\ Ameren Reply Comments at 15 (citing LS Power Initial
Comments at 116).
---------------------------------------------------------------------------
1733. Harvard ELI favors additional scrutiny of right-sized
replacement transmission facilities. Harvard ELI states generally that
the Commission could address the perverse incentives of current rules
leading to a focus on local transmission development by subjecting
local transmission planning to heightened scrutiny.\3665\
---------------------------------------------------------------------------
\3665\ Harvard ELI Initial Comments at 4.
---------------------------------------------------------------------------
1734. PIOs claim that the Commission should consider an ``ROE
subtractor'' analogous to an ROE adder that automatically reduces ROE
with certain criteria.\3666\
---------------------------------------------------------------------------
\3666\ PIOs Initial Comments at 53.
---------------------------------------------------------------------------
b. Commission Determination
1735. We decline to adopt ACEG's and LS Power's requests that the
Commission itself review in-kind replacement transmission facilities,
via section 205 or 206 authority or through policy guidance, to ensure
that they cannot be displaced by a regional transmission solution that
is more efficient or cost-effective.\3667\ These arguments are outside
the scope of this proceeding because the Commission did not propose in
the NOPR that the Commission review in-kind replacement transmission
facilities or local transmission facilities.
---------------------------------------------------------------------------
\3667\ ACEG Initial Comments at 57 (citations omitted); LS Power
Initial Comments at 145-146 (citing LS Power ANOPR Initial Comments
at 134-135).
---------------------------------------------------------------------------
1736. We decline to adopt commenters' requests for additional
confidentiality safeguards related to right-sizing.\3668\ We note that
a transmission provider's list of in-kind replacement estimates (i.e.,
estimates of the transmission facilities operating at and above the
specified kV threshold that an individual transmission provider that
owns the transmission facility anticipates replacing in-kind with a new
transmission facility during the next 10 years) is a non-binding
estimate and does not require that transmission provider to undertake
replacement work. To the extent that customers or stakeholders request
access to a transmission provider's list of in-kind replacement
estimates, that transmission provider may subject access to that list
of in-kind replacement estimates to confidentiality provisions.
However, once the transmission providers have determined, as part of
Long-Term Regional Transmission Planning, that an in-kind replacement
transmission facility can be right-sized to constitute a right-sized
replacement transmission facility, we find that the transmission
providers must make public the underlying in-kind replacement
transmission facility.
---------------------------------------------------------------------------
\3668\ AEP Initial Comments at 46; Exelon Initial Comments at
57-58; Indicated PJM TOs Initial Comments at 45-46; SERTP Sponsors
Initial Comments at 39; WIRES Initial Comments at 10.
---------------------------------------------------------------------------
1737. We decline to adopt commenter requests for increased scrutiny
of, or altering the presumption of prudence for, transmission projects
related to right-sizing.\3669\ We reject these requests as outside the
scope of this proceeding because the Commission did not propose in the
NOPR to increase scrutiny of in-kind replacement transmission
facilities beyond the right-sizing proposal and did not propose to
alter existing Commission policy on prudence. Likewise, in response to
PG&E's request for clarification that a transmission provider's
declining to proceed with a right-sized replacement transmission
facility does not justify disallowance of cost recovery for the in-kind
replacement transmission facility, nothing in the reforms we adopt here
alters existing Commission policy on cost recovery for transmission
facilities.\3670\
---------------------------------------------------------------------------
\3669\ American Municipal Power Initial Comments at 29-30;
California Commission Initial Comments at 114-115; California Water
Initial Comments at 9; Harvard ELI Initial Comments at 4;
Massachusetts Attorney General Initial Comments at 52; Mississippi
Commission Initial Comments at 30; Ohio Consumers Initial Comments
at 23; Pine Gate Initial Comments at 49-50; PIOs Initial Comments at
58; Resale Iowa Initial Comments at 9; TAPS Initial Comments at 6-7,
67.
\3670\ New England Power Co., 31 FERC ] 61,047, at 61,084 (1985)
(explaining that the Commission evaluates ``prudence of the
utility's actions and the costs resulting therefrom based on the
particular circumstances existing either at the time the challenged
costs were actually incurred, or the time the utility became
committed to incur those expenses'').
---------------------------------------------------------------------------
1738. We acknowledge commenter support for the consideration of
alternative transmission technologies with regard to right-
sizing.\3671\ However, we find that adopting additional requirements
for consideration of alternative transmission technologies with respect
to right-sizing are unnecessary. This is because, as discussed in the
Consideration of Dynamic Line Ratings and Advanced Power Flow Control
Devices section of this final order, we require transmission providers
in each transmission planning region to more fully consider, in Long-
Term Regional Transmission Planning and existing Order No. 1000
regional transmission planning, dynamic line ratings, advanced power
flow control devices, advanced conductors, and transmission
switching.\3672\ We believe that the requirements in the Consideration
of Dynamic Line Ratings and Advanced Power Flow Control Devices section
of this final order adequately address consideration of alternative
transmission technologies in the regional transmission planning
process, including when considering right-sizing.
---------------------------------------------------------------------------
\3671\ CTC Global Initial Comments at 18, 20; Maryland Energy
Administration Reply Comments at 5-6; NARUC Initial Comments at 58-
59, 63-64; PIOs Initial Comments at 57-58; VEIR Initial Comments at
6.
\3672\ See Consideration of Dynamic Line Ratings and Advanced
Power Flow Control Devices section.
---------------------------------------------------------------------------
1739. Some commenters request that the Commission take other
actions and suggest alternative reforms to the Commission's proposal
related to right-sizing.\3673\ We find these requests to be outside the
scope of this proceeding and lacking in record support to adequately
[[Page 49546]]
consider whether to adopt them in this final order.
---------------------------------------------------------------------------
\3673\ ACEG Initial Comments at 57; American Municipal Power
Initial Comments at 5, 25; American Municipal Power Reply Comments
at 5; California Commission Initial Comments at 106-108; California
Water Initial Comments at 10; Competition Coalition Initial Comments
at 68-69; Grid United Initial Comments at 3-4; Harvard ELI Initial
Comments at 4; LS Power Initial Comments at 83, 136, 138, 141-142,
145-146; Massachusetts Attorney General Initial Comments at 52; Ohio
Consumers Initial Comments at 24; PIOs Initial Comments at 53; TAPS
Initial Comments at 6, 64-65.
---------------------------------------------------------------------------
X. Interregional Transmission Coordination
A. NOPR Proposal
1740. In the NOPR, the Commission proposed to require each
transmission provider to revise its existing interregional transmission
coordination procedures to reflect the Long-Term Regional Transmission
Planning reforms proposed in the NOPR.\3674\
---------------------------------------------------------------------------
\3674\ NOPR, 179 FERC ] 61,028 at P 426.
---------------------------------------------------------------------------
1741. Specifically, the Commission proposed to require transmission
providers in neighboring transmission planning regions to revise their
existing interregional transmission coordination procedures (and
regional transmission planning processes as needed) to provide for: (1)
the sharing of information regarding their respective transmission
needs identified in Long-Term Regional Transmission Planning, as well
as potential transmission facilities to meet those needs; and (2) the
identification and joint evaluation of interregional transmission
facilities that may be more efficient or cost-effective transmission
facilities to address transmission needs identified through Long-Term
Regional Transmission Planning.\3675\
---------------------------------------------------------------------------
\3675\ Id. P 427.
---------------------------------------------------------------------------
1742. The Commission also proposed to require transmission
providers in neighboring transmission planning regions to revise their
interregional transmission coordination procedures (and regional
transmission planning processes as needed) to allow an entity to
propose an interregional transmission facility in the regional
transmission planning process as a potential solution to transmission
needs identified through Long-Term Regional Transmission
Planning.\3676\ The Commission noted that this proposal would align the
existing requirement for an entity to propose an interregional
transmission facility in the regional transmission planning processes
of each of the neighboring transmission planning regions in which the
transmission facility is proposed to be located with the proposed
requirement for transmission providers to conduct Long-Term Regional
Transmission Planning as part of their regional transmission planning
processes.
---------------------------------------------------------------------------
\3676\ Id. P 428.
---------------------------------------------------------------------------
1743. The Commission stated that this proposed reform aims to
ensure that transmission needs driven by changes in the resource mix
and demand identified through Long-Term Regional Transmission Planning
can be considered in existing interregional transmission coordination
and cost allocation processes.\3677\ The Commission preliminarily
concluded that the proposed interregional transmission coordination
reforms will also ensure that there is an opportunity for the
transmission providers in neighboring transmission planning regions to
consider whether there are interregional transmission facilities that
could more efficiently or cost-effectively meet the transmission needs
identified through Long-Term Regional Transmission Planning, in turn
helping to ensure just and reasonable Commission-jurisdictional rates.
---------------------------------------------------------------------------
\3677\ Id. P 429.
---------------------------------------------------------------------------
B. Comments
1744. Many commenters support the Commission's proposal to require
transmission providers to revise their existing interregional
transmission coordination procedures to reflect the Long-Term Regional
Transmission Planning reforms proposed in the NOPR.\3678\ Such
commenters assert that this proposed reform would give transmission
providers in neighboring transmission planning regions the opportunity
to consider whether interregional transmission facilities could meet
the transmission needs identified through Long-Term Regional
Transmission Planning in a more efficient or cost-effective manner than
separate regional transmission facilities, which would help to ensure
just and reasonable rates.
---------------------------------------------------------------------------
\3678\ Acadia Center and CLF Initial Comments at 23-24; ACEG
Initial Comments at 74; Ameren Initial Comments at 47; Arizona
Commission Initial Comments at 10; BP Initial Comments at 13-14;
Breakthrough Energy Initial Comments at 2; California Commission
Initial Comments at 118-121; California Energy Commission Initial
Comments at 4; California Water Initial Comments at 20-21; Clean
Energy Associations Initial Comments at 40-42; EEI Initial Comments
at 48; Enel Initial Comments at 4-5; Eversource Initial Comments at
55-56; Exelon Initial Comments at 60-61; Grid United Initial
Comments at 7-9; Idaho Power Initial Comments at 13; Indiana
Commission Initial Comments at 7-9; Interwest Initial Comments at
18-20; MISO Initial Comments at 88-89; NARUC Initial Comments at 67-
70; National and State Conservation Organizations Initial Comments
at 1-2; Northwest and Intermountain Initial Comments at 10, 22; OMS
Initial Comments at 18-20; Pennsylvania Commission Initial Comments
at 23-25; Pine Gate Initial Comments at 50-51; PIOs Initial Comments
at 75-79; PJM Initial Comments at 9-10, 123-125; R Street Initial
Comments at 4-5; State Agencies Initial Comments at 22-23; State
Officials Supplemental Comments at 1 (citing U.S. Climate Alliance
Initial Comments at 3); U.S. Climate Alliance Initial Comments at 3;
U.S. DOE Initial Comments at 38-40; U.S. DOJ and FTC Initial
Comments at 19-20.
---------------------------------------------------------------------------
1745. Some commenters condition their support on the Commission
providing transmission providers with flexibility. For example, EEI
asserts that providing transmission providers with flexibility in
developing Long-Term Regional Transmission Planning will help ensure
that transmission planning regions can determine the processes that
work for them and collaborate with neighboring regions.\3679\ Idaho
Power requests that the Commission allow flexibility in the methods
used to determine transmission benefits.\3680\ Pennsylvania Commission
conditions its support on the Commission maintaining flexibility for
transmission providers to define criteria for considering and selecting
transmission facilities, including criteria that permit the selection
of proposed regional transmission facilities over a proposed
interregional transmission facility.\3681\
---------------------------------------------------------------------------
\3679\ EEI Initial Comments at 48.
\3680\ Idaho Power Initial Comments at 13.
\3681\ Pennsylvania Commission Initial Comments at 24-25.
---------------------------------------------------------------------------
1746. Other commenters suggest that the Commission could improve
the proposed reforms to interregional transmission coordination by
requiring additional information sharing. For example, U.S. DOE
recommends that the Commission require neighboring transmission
planning regions to share information with one another about their
geographic zones.\3682\ California Energy Commission recommends that
transmission providers be required to share with neighboring
transmission planning regions how other planning processes, such as
integrated resource plans, resource adequacy, and state requirements,
are considered in regional transmission planning.\3683\ State Agencies
suggest that transmission providers should provide an annual report to
the Commission on their interregional transmission coordination
activities, including the number of interregional transmission projects
identified, the results of the cost/benefit evaluation overall and to
each transmission planning region, whether other regions have been or
should be included to maximize the value of the project, and any
barriers to development of interregional transmission projects.\3684\
NARUC urges the Commission to encourage additional coordination and
information sharing between non-RTO/ISO transmission planning regions
like NorthernGrid and WestConnect.\3685\
---------------------------------------------------------------------------
\3682\ U.S. DOE Initial Comments at 18-20.
\3683\ California Energy Commission Initial Comments at 4.
\3684\ State Agencies Initial Comments at 23.
\3685\ NARUC Initial Comments at 69-70.
---------------------------------------------------------------------------
1747. Pattern Energy asserts that the Commission should require
neighboring transmission planning regions to hold forums for
stakeholders to discuss right-
[[Page 49547]]
sizing or expanding proposed regional transmission facilities in
consideration of the needs of both regions.\3686\ Further, Pattern
Energy argues that if no interregional transmission facilities are
approved in a Long-Term Regional Transmission Planning cycle, the
Commission should require transmission planning regions to provide
transparent reasoning to help stakeholders and regulators understand
whether interregional transmission coordination requires reform.\3687\
---------------------------------------------------------------------------
\3686\ Pattern Energy Reply Comments at 14.
\3687\ Id. at 14-15.
---------------------------------------------------------------------------
1748. MISO asserts that the Commission should institute a separate
and longer compliance period for the interregional transmission
coordination requirements than for the regional transmission planning
requirements proposed in this rulemaking.\3688\ Further, to reduce the
compliance burden on transmission providers, MISO requests that the
Commission include all interregional transmission coordination and
planning requirements in a single rulemaking rather than require
interregional compliance in multiple, separate proceedings.\3689\
---------------------------------------------------------------------------
\3688\ MISO Initial Comments at 89.
\3689\ Id. at 88-89.
---------------------------------------------------------------------------
1749. Many commenters assert that the Commission's proposals with
respect to interregional transmission coordination do not go far
enough.\3690\ Several commenters urge the Commission to require
holistic interregional transmission planning and cost allocation.\3691\
Some commenters encourage the Commission to require a minimum amount of
Interregional Transfer Capability between neighboring transmission
planning regions.\3692\ Several commenters urge the Commission to
require neighboring transmission planning regions to adopt a common
system model and planning assumptions, common Long-Term Scenarios, and
consistent data inputs.\3693\ AEP argues that the Commission should
require consistency across transmission planning regions in terms of
the transmission planning horizon, planning frequency, and minimum set
of benefits considered.\3694\
---------------------------------------------------------------------------
\3690\ See, e.g., ACEG Initial Comments at 76-78; Breakthrough
Energy Initial Comments at 2; Clean Energy Associations Initial
Comments at 41-42; Enel Initial Comments at 4-5; Evergreen Action
Initial Comments at 5-6; Eversource Initial Comments at 56; Grid
United Initial Comments at 7-8; Indiana Commission Initial Comments
at 9; Interwest Initial Comments at 18-19; Invenergy Reply Comments
at 18; National Grid Initial Comments at 20; OMS Initial Comments at
18; Pattern Energy Reply Comments at 12-15; Pine Gate Initial
Comments at 50-51; PIOs Initial Comments at 75-77; PJM Initial
Comments at 9-10, 123-124; Rail Electrification Initial Comments at
2, 8-11; RMI Initial Comments at 1-2; State Agencies Initial
Comments at 23; Transmission Dependent Utilities Initial Comments at
6-7; U.S. DOE Initial Comments at 38-39; Xcel Initial Comments at
17.
\3691\ See, e.g., ACEG Initial Comments at 76-78; Clean Energy
Associations Initial Comments at 41-42; Enel Initial Comments at 4-
5; Evergreen Action Initial Comments at 5-6; Grid United Initial
Comments at 7-8; Indiana Commission Initial Comments at 9; Interwest
Initial Comments at 18-19; Invenergy Reply Comments at 18; National
Grid Initial Comments at 20; OMS Initial Comments at 18; Pattern
Energy Reply Comments at 12-15; Pine Gate Initial Comments at 50-51;
PIOs Initial Comments at 75-77; PJM Initial Comments at 9-10, 123-
124; Rail Electrification Initial Comments at 2, 8-11; RMI Initial
Comments at 1-2; Shell Reply Comments at 8-9; U.S. DOE Initial
Comments at 38-39; Xcel Initial Comments at 17.
\3692\ See, e.g., ACEG Initial Comments at 70-76; AEP Initial
Comments at 17-18; Breakthrough Energy Initial Comments at 2;
Evergreen Action Initial Comments at 5-6; Eversource Initial
Comments at 55-56; Interwest Initial Comments at 18-20; Invenergy
Initial Comments at 20-27; Invenergy Reply Comments at 19-22; Kansas
Commission Initial Comments at 4-10; PJM Initial Comments at 9-10,
123-125.
\3693\ Hannon Armstrong Reply Comments at 1; Invenergy Reply
Comments at 19-22; National Grid Initial Comments at 19-20;
Transmission Dependent Utilities Initial Comments at 6-7; U.S. DOE
Initial Comments at 18-21.
\3694\ AEP Reply Comments at 3-5.
---------------------------------------------------------------------------
1750. MISO encourages the Commission to examine interregional
transmission planning, including analysis of the assumptions related to
transfer capacity and the effectiveness of collaboration between RTO
and non-RTO neighbors, in a separate docket.\3695\ Eversource and State
Agencies suggest that the Commission encourage RTOs/ISOs to increase
staffing to address interregional transmission planning.\3696\ National
Grid suggests that the Commission provide appropriate rate incentives
for interregional transmission facilities.\3697\ Rail Electrification
urges the Commission to support the siting of large interregional
transmission facilities along available interstate transportation
rights-of-way to advance the grid of the future more quickly.\3698\
---------------------------------------------------------------------------
\3695\ MISO Reply Comments at 29-30.
\3696\ Eversource Initial Comments at 55-56; State Agencies
Initial Comments at 23.
\3697\ National Grid Initial Comments at 20.
\3698\ Rail Electrification Initial Comments at 8-12.
---------------------------------------------------------------------------
C. Commission Determination
1751. We adopt, with modification, the NOPR proposal to require
transmission providers in each transmission planning region to revise
their existing interregional transmission coordination procedures to
reflect the Long-Term Regional Transmission Planning reforms adopted in
this final order. Specifically, we adopt the NOPR proposal to require
transmission providers in neighboring transmission planning regions to
revise their existing interregional transmission coordination
procedures (and regional transmission planning processes, as needed) to
provide for: (1) the sharing of information regarding their respective
Long-Term Transmission Needs, as well as Long-Term Regional
Transmission Facilities to meet those needs; and (2) the identification
and joint evaluation of interregional transmission facilities that may
be more efficient or cost-effective transmission facilities to address
Long-Term Transmission Needs.
1752. Additionally, we adopt the NOPR proposal to require
transmission providers in neighboring transmission planning regions to
revise their interregional transmission coordination procedures (and
regional transmission planning processes, as needed) to allow an entity
to propose an interregional transmission facility in the regional
transmission planning process as a potential solution to Long-Term
Transmission Needs. We find that this requirement will align the
existing requirement, for an entity to propose an interregional
transmission facility in the regional transmission planning processes
of each of the neighboring transmission planning regions in which the
transmission facility is proposed to be located, with the new
requirement in this final order for transmission providers to conduct
Long-Term Regional Transmission Planning as part of their regional
transmission planning processes.
1753. In response to commenter requests for additional information
sharing and transparency of the interregional transmission coordination
process, we find that additional transparency as applied to Long-Term
Regional Transmission Planning is warranted.\3699\ Order No. 1000
requires that transmission providers in neighboring transmission
planning regions maintain a website or email list for the communication
of information related to interregional transmission coordination
procedures.\3700\ We modify the NOPR proposal, and require transmission
providers in each transmission planning region to provide the following
additional information concerning Long-Term Regional Transmission
Planning on their public website or through the email list used for
communication of information related to interregional transmission
coordination procedures: (1) the Long-Term Transmission Needs discussed
in the interregional transmission coordination meetings; (2) any
[[Page 49548]]
interregional transmission facilities proposed or identified in
response to Long-Term Transmission Needs; (3) the voltage level,
estimated cost, and estimated in-service date of the interregional
transmission facilities proposed or identified as part of Long-Term
Regional Transmission Planning; (4) the results of any cost-benefit
evaluation of such interregional transmission facilities, with such
results including both any overall benefits identified (which may occur
across multiple transmission planning regions), as well as any benefits
particular to each transmission planning region; and (5) the
interregional transmission facilities, if any, selected to meet Long-
Term Transmission Needs. We find that this modification will enhance
transparency and facilitate stakeholder engagement in the interregional
transmission coordination procedures as applied to Long-Term Regional
Transmission Planning, thereby ensuring just and reasonable rates. We
believe that this requirement to make this information publicly
available will not create a significant burden because transmission
providers will already share or develop such information with the
transmission providers in neighboring transmission planning regions to
comply with the requirement in this final order to revise their
existing interregional transmission coordination procedures to reflect
the Long-Term Regional Transmission Planning reforms.
---------------------------------------------------------------------------
\3699\ See, e.g., California Energy Commission Initial Comments
at 4; NARUC Initial Comments at 69-70; Pattern Energy Reply Comments
at 14-15; State Agencies Initial Comments at 23.
\3700\ Order No. 1000, 136 FERC ] 61,051 at PP 345, 458.
---------------------------------------------------------------------------
1754. Taken together, we find that these reforms will ensure that
Long-Term Transmission Needs identified through Long-Term Regional
Transmission Planning can be considered in existing interregional
transmission coordination and cost allocation processes. Further, doing
so will ensure that there is an opportunity for the transmission
providers in neighboring transmission planning regions to consider
whether there are interregional transmission facilities that could more
efficiently or cost-effectively address the identified Long-Term
Transmission Needs, in turn helping to ensure just and reasonable
Commission-jurisdictional rates.
1755. We decline to require the transmission providers in
neighboring transmission planning regions to hold forums for
stakeholders to discuss right-sizing or expanding proposed regional
transmission facilities in consideration of the transmission needs of
both regions, as requested by Pattern Energy. The Commission did not
propose such a reform in the NOPR, and we decline to require it here.
1756. Regarding Idaho Power's request that the Commission provide
transmission providers with flexibility in the methods used to
determine the benefits of interregional transmission facilities, we
note that this issue is addressed above in the Evaluation of the
Benefits of Regional Transmission Facilities section of this final
order.\3701\ Regarding Pennsylvania Commission's comment that its
support for the interregional transmission coordination reforms
proposed in the NOPR are conditioned on the Commission maintaining
flexibility for transmission providers to define criteria for
considering and selecting transmission facilities, we note that the
requirements regarding selection criteria are addressed in the section
above on the Evaluation and Selection of Long-Term Regional
Transmission Facilities.\3702\
---------------------------------------------------------------------------
\3701\ See supra Evaluation of the Benefits of Regional
Transmission Facilities section.
\3702\ See supra Evaluation and Selection of Long-Term Regional
Transmission Facilities section.
---------------------------------------------------------------------------
1757. Regarding MISO's request for a longer compliance period for
transmission providers to comply with the interregional transmission
coordination requirements of this final order, we address MISO's
request in the Compliance section below.\3703\
---------------------------------------------------------------------------
\3703\ See infra Compliance Procedures section.
---------------------------------------------------------------------------
1758. With respect to commenter requests for the Commission to: (1)
require holistic interregional transmission planning and cost
allocation; (2) require a minimum amount of Interregional Transfer
Capability between neighboring transmission planning regions; (3)
require neighboring transmission planning regions to adopt a common
system model, consistent data inputs, and a uniform transmission
planning horizon and transmission planning frequency; (4) encourage
RTOs/ISOs to increase staffing to address interregional transmission
planning; (5) adopt new rate incentives for interregional transmission
facilities; and (6) support the siting of large interregional
transmission facilities along available transportation rights-of-way,
we find such requests to be outside the scope of this proceeding. We
recognize that one or more of these reforms hold the potential to
enhance system reliability or provide significant consumer benefits.
However, the Commission did not propose such reforms in the NOPR, and
we decline to adopt them in the final order. However, we note that the
Commission currently has an open proceeding in Docket No. AD23-3-000 to
consider whether and how to establish a minimum requirement for
Interregional Transfer Capability, and may consider further reforms in
other proceedings, as appropriate.\3704\
---------------------------------------------------------------------------
\3704\ See Supplemental Notice of Staff-Led Workshop,
Establishing Interregional Transfer Capability Transmission Planning
and Cost Allocation Requirements, Docket No. AD23-3-000 (Nov. 30,
2022).
---------------------------------------------------------------------------
XI. Compliance Procedures
A. NOPR Proposal
1759. In the NOPR, the Commission proposed to require each
transmission provider to submit a compliance filing within eight months
of the effective date of any final order in this proceeding revising
its OATT and other document(s) subject to the Commission's jurisdiction
as necessary to demonstrate that it meets the requirements adopted in
any final order in this proceeding.\3705\ The Commission proposed that
transmission providers that are not public utilities would have to
adopt the requirements adopted in any final order in this proceeding as
a condition of maintaining the status of their safe harbor tariff or
otherwise satisfying the reciprocity requirement of Order No.
888.\3706\
---------------------------------------------------------------------------
\3705\ NOPR, 179 FERC ] 61,028 at P 430.
\3706\ Id. P 432 (citing Order No. 888, FERC Stats. & Regs. ]
31,036 at 31,760-63).
---------------------------------------------------------------------------
1760. Additionally, in the NOPR, the Commission proposed to require
transmission providers to demonstrate on compliance that proposed
variations from the requirements in the final order are consistent with
or superior to the final order.\3707\
---------------------------------------------------------------------------
\3707\ Id. PP 74-75, 105, 229.
---------------------------------------------------------------------------
B. Comments
1761. Several commenters support a compliance period of eight
months or more to allow stakeholders, including Relevant State
Entities, sufficient time to negotiate and agree on proposals to comply
with this rulemaking.\3708\ PJM states that while an eight-month period
to submit compliance filings is reasonable, the Commission should
thereafter allow time for transmission planners to develop the tools
and hire the employees they will need to implement the final
order.\3709\ NEPOOL states that the Commission should be flexible in
considering requests for extensions of time.\3710\ Pacific Northwest
State Agencies urge the
[[Page 49549]]
Commission to provide flexibility rather than a rigid time period of
eight months to comply with the final order.\3711\
---------------------------------------------------------------------------
\3708\ Idaho Power Initial Comments at 14; ISO-NE Initial
Comments at 41; MISO Initial Comments at 90; NARUC Initial Comments
at 50-51; NEPOOL Initial Comments at 10; NESCOE Reply Comments at 9
(citing ISO-NE Initial Comments at 41); North Carolina Commission
and Staff Initial Comments at 17; Northwest and Intermountain
Initial Comments at 22-23; Pacific Northwest State Agencies Initial
Comments at 28; PJM Initial Comments at 10, 129.
\3709\ PJM Initial Comments at 10, 129.
\3710\ NEPOOL Initial Comments at 10.
\3711\ Pacific Northwest State Agencies Initial Comments at 28.
---------------------------------------------------------------------------
1762. Certain TDUs argue that the Commission should require
transmission providers to submit compliance filings no later than 270
days after the final order becomes effective to reflect the
requirements to include an ex ante Long-Term Regional Transmission Cost
Allocation Method, define benefits, and identify the method by which
benefits are selected.\3712\
---------------------------------------------------------------------------
\3712\ Certain TDUs Initial Comments at 16.
---------------------------------------------------------------------------
1763. Some commenters request that the Commission provide longer
than eight months to comply with the final order. For example, NARUC
argues that eight months is unlikely to allow sufficient time for
Relevant State Entities to meaningfully engage.\3713\ Given the
complexity of the proposals and the need to coordinate with
stakeholders, Idaho Power and ISO-NE propose that the Commission allow
at least one year for transmission providers to comply with the final
order.\3714\ For similar reasons, MISO urges the Commission to provide
a compliance period of at least 18 months. In addition, to avoid
interfering with ongoing transmission expansion efforts in some
transmission planning regions, MISO argues that the Commission should
allow such regions to propose their own compliance date or instead
should state that the final order would not apply to any such ongoing
transmission expansion efforts, including MISO's Long-Range
Transmission Planning initiative.\3715\ Additionally, MISO requests
that the new order and tariff revisions complying with the final order
be made effective upon the Commission's acceptance of the filing
party's compliance filing.\3716\
---------------------------------------------------------------------------
\3713\ NARUC Initial Comments at 50-51.
\3714\ Idaho Power Initial Comments at 14; ISO-NE Initial
Comments at 41.
\3715\ MISO Initial Comments at 90-92.
\3716\ Id. at 90-91; MISO Reply Comments at 32.
---------------------------------------------------------------------------
1764. PJM states that it would be more efficient and less confusing
if PJM could first build the long-term model and then comply with the
selection and cost allocation requirements at a later date. PJM
therefore requests that the Commission clarify whether it is necessary
for transmission providers to develop compliance procedures with
respect to selection and cost allocation of transmission projects to be
selected through Long-Term Regional Transmission Planning before they
have had a chance to create and finalize their long-term transmission
planning processes.\3717\
---------------------------------------------------------------------------
\3717\ PJM Initial Comments at 98-104.
---------------------------------------------------------------------------
1765. MISO asserts that the Commission should allow a separate and
longer compliance period for the interregional transmission
coordination requirements.\3718\
---------------------------------------------------------------------------
\3718\ MISO Initial Comments at 89.
---------------------------------------------------------------------------
1766. Separately, MISO states that while the NOPR indicates that
the Commission might permit regional flexibility in some areas, it
adopts the ``consistent with or superior to'' legal standard for
evaluating proposed deviations on compliance.\3719\ MISO argues that
this standard is too inflexible to achieve the Commission's objectives
because it neither recognizes the independent nature of RTOs/ISOs nor
has a built-in mechanism to acknowledge legitimate regional
differences.\3720\ Therefore, MISO recommends that the Commission
instead apply a version of the ``independent entity'' variation
standard to RTOs/ISOs or otherwise make clear that the proposed reforms
contemplate regional flexibility to allow RTOs to retain their best
transmission planning practices, particularly those RTOs that are
``early movers'' of the types of reforms in the NOPR.\3721\ If the
Commission decides not to adopt the independent entity variation
standard for this final order, MISO urges the Commission to clarify
that it will recognize as ``consistent with or superior to'' any
existing regional transmission planning processes that are
substantially equivalent to the proposed requirements to avoid impeding
progress already made, while compelling reform in transmission planning
regions where needed.\3722\
---------------------------------------------------------------------------
\3719\ MISO Reply Comments at 4 (citing NOPR, 179 FERC ] 61,028
at PP 74-75).
\3720\ MISO Initial Comments at 21-22; MISO Reply Comments at 5.
\3721\ MISO Reply Comments at 4. For example, MISO states that
its MVP and Long-Range Transmission Plan processes are broadly
consistent with the principles and goals of the NOPR and some of its
specific proposals, including development of multiple futures,
review of various benefit metrics, and use of a 20-year transmission
planning horizon. MISO states that repeating the extensive
stakeholder effort involved in developing these processes to comply
with the new requirements would stall its momentum. MISO Initial
Comments at 10.
\3722\ MISO Initial Comments at 25; MISO Reply Comments at 8-9.
---------------------------------------------------------------------------
1767. ISO-NE and ISO RTO Council argue that flexibility should
extend to determining the rules for inclusion in the tariff, with
implementation details in planning procedures or guides, consistent
with the Commission's ``rule of reason'' standard.\3723\
---------------------------------------------------------------------------
\3723\ ISO-NE Initial Comments at 20; ISO/RTO Council Initial
Comments at 8-9 (citing City of Cleveland v. FERC, 773 F.2d. at
1376).
---------------------------------------------------------------------------
C. Commission Determination
1768. We adopt the NOPR proposal, with modification, and require
each transmission provider to submit a compliance filing within ten
months of the effective date of this final order revising its OATT and
other document(s) subject to the Commission's jurisdiction as necessary
to demonstrate that it meets all of the requirements adopted in this
final order, except those adopted in the Interregional Transmission
Coordination section of this final order. In response to comments from
NARUC, Idaho Power, ISO-NE, and MISO requesting a longer compliance
timeline, we find that requiring a ten-month compliance period instead
of the eight-month compliance period proposed in the NOPR will allow
transmission providers to fully develop proposals to comply with this
final order and allow stakeholders, including Relevant State Entities,
to meaningfully engage in the process of developing such proposals. As
discussed in the Implementation of Long-Term Regional Transmission
Planning section, we require transmission providers in each
transmission planning region to propose on compliance a date, no later
than one year from the date on which initial filings to comply with
this final order are due, on which they will commence the first Long-
Term Regional Transmission Planning cycle (unless additional time is
needed to align the first Long-Term Regional Transmission Planning
cycle with existing transmission planning cycles). Therefore,
transmission providers in each transmission planning region must
propose an effective date for the OATT revisions necessary to comply
with this final order that is no later than the date on which they will
commence the first Long-Term Regional Transmission Planning cycle.
However, transmission providers may propose an earlier effective date
for some or all parts of their revised OATTs to allow them to begin
implementing any aspects of the required reforms sooner than the one-
year deadline to commence the first Long-Term Regional Transmission
Planning cycle.
1769. We deny PJM's request for clarification to allow a later
compliance deadline for the selection and cost allocation requirements
of this final order and find it appropriate to require
[[Page 49550]]
that transmission providers submit a compliance filing that addresses
all the requirements of this final order within ten months of the
effective date of this final order, with the exception of the
requirements related to interregional transmission coordination, as
previously noted.
1770. In response to MISO's request for a separate, longer
compliance timeline for the interregional transmission coordination
requirements, we also modify the NOPR proposal and require each
transmission provider to submit a separate compliance filing within 12
months of the effective date of this final order revising its OATT and
other document(s) subject to the Commission's jurisdiction as necessary
to demonstrate that it meets the interregional transmission
coordination requirements adopted in this final order.\3724\ We find
that the additional time to comply with the interregional transmission
coordination requirements will allow transmission providers to
coordinate with the transmission providers in each of their neighboring
transmission planning regions to develop interregional transmission
coordination proposals.
---------------------------------------------------------------------------
\3724\ See supra Interregional Transmission Coordination
section.
---------------------------------------------------------------------------
1771. Additionally, we adopt the proposed requirement that
transmission providers that are not public utilities must adopt the
requirements of this final order as a condition of maintaining the
status of their safe harbor tariff or otherwise satisfying the
reciprocity requirement of Order No. 888.\3725\
---------------------------------------------------------------------------
\3725\ NOPR, 179 FERC ] 61,028 at P 432 (citing Order No. 888,
FERC Stats. & Regs. ] 31,036 at 31,760-63).
---------------------------------------------------------------------------
1772. In this final order, we make no changes to the standards used
to judge requested variations, as described in Order Nos. 888, 2000,
890, and 1000.\3726\ Accordingly, we decline to grant MISO's request
that the Commission apply the independent entity variation standard,
rather than the ``consistent with or superior to'' standard, for
proposed deviations from the requirements in this final order on
compliance. Consistent with the Commission's findings in Order No. 890,
we will continue to apply the ``consistent with or superior to''
standard in the context of transmission planning.\3727\
---------------------------------------------------------------------------
\3726\ Order No. 1000, 136 FERC ] 61,051 at P 815; Order No.
890, 118 FERC ] 61,119 at P 109; Order No. 2000, FERC Stats. & Regs.
] 31,089 at 31,164; Order No. 888, FERC Stats. & Regs. ] 31,036, at
31,769-70.
\3727\ Order No. 890, 118 FERC ] 61,119 at P 160.
---------------------------------------------------------------------------
1773. Regarding MISO's request for clarification, we decline to
clarify as part of this final order that any existing transmission
planning processes are consistent with or superior to the requirements
in this final order. Rather, it is more appropriate for a transmission
provider to submit such a request as part of its compliance filing, in
which the transmission provider must demonstrate that any deviation
from the requirements of this final order, including any existing
processes and/or OATT provisions, are consistent with or superior to
the requirements of this final order. Similarly, to the extent that a
transmission provider believes that it already complies with any of the
requirements of this final order, it should describe in its compliance
filing how the relevant requirements are satisfied, including by
referencing specific tariff sheets already on file with the Commission.
1774. In response to ISO-NE's and ISO RTO Council's comment that
the final order should provide flexibility as to which implementation
details should be included in planning procedures or guides consistent
with the Commission's ``rule of reason'' standard, we note that the
Commission has broad discretion in applying the rule of reason
policy,\3728\ under which provisions that ``significantly affect rates,
terms, and conditions'' of service, are realistically susceptible of
specification, and are not generally understood in a contractual
agreement, must be included in the tariff. The tariff need not include
``mere implementation details,'' \3729\ which instead may be included
only in the business practice manuals. ``[E]ven specifiable practices
that significantly affect rates need not be included if they are
clearly implied by the tariff's express terms.'' \3730\ The final order
specifies with respect to each requirement the information that must be
incorporated into the transmission provider's OATT. We find that the
requirements in this final order regarding what information
transmission providers must specify in their tariff on compliance is
consistent with the Commission's rule of reason policy.
---------------------------------------------------------------------------
\3728\ Hecate Energy Greene Cnty. 3 LLC v. FERC, 72 F.4th at
1314 (citing City of Cleveland v. FERC, 773 F.2d at 1376 (the FPA's
``amorphous'' requirement that tariffs include ``practices affecting
rates'' means that the Commission has ``broad discretion'' in giving
the act ``concrete application.'')).
\3729\ Id. at 1312.
\3730\ Id. at 1314 (citing City of Cleveland v. FERC, 773 F.2d
at 1376).
---------------------------------------------------------------------------
XII. Information Collection Statement
1775. The information collection requirements contained in this
final order are subject to review by the Office of Management and
Budget (OMB) under section 3507(d) of the Paperwork Reduction Act of
1995.\3731\ OMB's regulations require approval of certain information
collection requirements imposed by agency rules.\3732\ Upon approval of
a collection of information, OMB will assign an OMB control number and
expiration date. Respondents subject to the filing requirements of this
final order will not be penalized for failing to respond to these
collections of information unless the collections of information
display a valid OMB control number.
---------------------------------------------------------------------------
\3731\ 44 U.S.C. 3507(d).
\3732\ 5 CFR 1320.11.
---------------------------------------------------------------------------
1776. The reforms adopted in this final order revise the
Commission's pro forma OATT to remedy deficiencies in the Commission's
existing regional transmission planning and cost allocation and local
transmission planning requirements to ensure that Commission-
jurisdictional rates and practices are just and reasonable and not
unduly discriminatory or preferential.
1777. In the NOPR, the Commission solicited comments on: the
Commission's need for this information; whether the information will
have practical utility; the accuracy of the burden estimates; ways to
enhance the quality, utility, and clarity of the information to be
collected or retained; and any suggested methods for minimizing
respondents' burden, including the use of automated information
techniques. The Commission received one comment from PJM specifically
about the time and effort required to comply with the information
collection requirement.\3733\
---------------------------------------------------------------------------
\3733\ PJM Initial Comments at 10, 125-29.
---------------------------------------------------------------------------
1778. PJM claims that the Commission significantly underestimates
the cost for PJM and other transmission providers to comply with the
final order. PJM states that its compliance will require additional
staff of between seven to 14 new staff members and that the added cost
will be at least $2.1 million per year. However, PJM adds that it
generally supports the proposed reforms in the NOPR and provides this
information only to give the Commission a better understanding of the
time and costs associated with implementing the final order.\3734\
---------------------------------------------------------------------------
\3734\ Id. at 128-29.
---------------------------------------------------------------------------
1779. In response to PJM's comments on the NOPR, we note that this
information collection statement estimates the burdens \3735\ to
generate,
[[Page 49551]]
maintain, retain, or disclose or provide information to or for a
Federal agency. In light of the information that PJM supplied, we have
revised the table below to increase the estimated amount of labor
required for a transmission provider to perform Long-Term Regional
Transmission Planning.\3736\ We expect that the information collection
requirements associated with updating these datasets for subsequent
cycles will entail substantially less effort than the initial Long-Term
Regional Transmission Planning cycle.
---------------------------------------------------------------------------
\3735\ ``Burden'' is the total time, effort, or financial
resources expended by persons to generate, maintain, retain, or
disclose or provide information to or for a Federal agency. For
further explanation of what is included in the information
collection burden, refer to 5 CFR 1320.3(b)(1).
\3736\ For example, for an entire transmission planning region,
we anticipate that 10 people each working 2,000 hours per year would
spend 20,000 hours per year to develop these datasets.
---------------------------------------------------------------------------
1780. Summary of the Revisions to the Collection of Information due
to the final order in Docket No. RM21-17-000:
Title: Electric Transmission Facilities (FERC-917).\3737\
---------------------------------------------------------------------------
\3737\ In the NOPR, in addition to proposing to revise the FERC-
917 information collection, the Commission proposed to revise the
pro forma LGIP and, therefore, to revise the FERC-516 information
collection (Reform of Generator Interconnection Procedures and
Agreements). In this final order, we decline to revise the pro forma
LGIP, and therefore we are not revising the FERC-516 information
collection.
---------------------------------------------------------------------------
Action: Revision of collections of information in
accordance with Docket No. RM21-17-000.
OMB Control Nos.: 1902-0233 (FERC-917).
Respondents: Transmission providers, including RTOs/ISOs.
Frequency of Information Collection: One time during Year
1. Occasional times during subsequent years, at least once every five
years.
Necessity of Information: The reforms in this final order
will correct deficiencies in the Commission's existing regional
transmission planning and cost allocation requirements to ensure that
Commission-jurisdictional rates remain just and reasonable and not
unduly discriminatory or preferential.
Internal Review: We have reviewed the reforms and have
determined that such reforms are necessary. These reforms conform to
the Commission's need for efficient information collection,
communication, and management within the energy industry. We have
specific, objective support for the burden estimates associated with
the information collection requirements.
Public Reporting Burden: The burden and cost estimates
below are based on the need for applicable entities to revise
documentation, already required by the Commission's pro forma OATT. Our
estimates are based on the North American Electric Reliability
Corporation Compliance Registry as of January 11, 2024, which indicates
that there are 48 transmission service providers \3738\ with OATTs and
118 transmission owners that are registered within the United States
and are subject to this rulemaking.\3739\ Because 41 of the 118
transmission owners are also included in the count of 48 transmission
service providers, there are 125 distinct entities (i.e., 125 distinct
transmission providers 3740 3741 3742) in total that must
comply this final order. We note that, for the purposes of regional
transmission planning, these 125 entities are grouped into 11
transmission planning regions.
---------------------------------------------------------------------------
\3738\ The transmission service provider (TSP) function is a
North American Electric Reliability Corporation registration
function, which is similar to the transmission provider that is
referenced in the pro forma OATT. The TSP function is being used as
a proxy to estimate the number of transmission providers that are
impacted by this proposed rulemaking.
\3739\ The number of entities listed from the North American
Electric Reliability Corporation Compliance Registry reflects the
omission of the Texas registered entities. Note that the 48
transmission providers with OATTs do not include non-public utility
transmission providers with reciprocity tariffs.
\3740\ See supra note 2.
\3741\ In the table, Year 1 figures are one-time implementation
hours and cost. ``Subsequent years'' show ongoing burdens and costs
starting in Year 2.
\3742\ The hourly cost (for salary plus benefits) uses the
figures from the Bureau of Labor Statistics (BLS) for three
positions involved in the reporting and recordkeeping requirements.
These figures include salary (based on BLS data for May 2022, issued
April 25, 2023, http://bls.gov/oes/current/naics2_22.htm) and
benefits (based on BLS data for September 2023; issued December 15,
2023, http://www.bls.gov/news.release/ecec.nr0.htm) and are Manager
(Occupation Code 11-0000, $122.48/hour), Electrical Engineer
(Occupation Code 17-2071, $89.04/hour), and File Clerk (Occupation
Code 43-4071, $42.43/hour). The hourly cost for the reporting
requirements ($105.76) is an average of the hourly cost (wages plus
benefits) of a manager and engineer. The hourly cost for
recordkeeping requirements uses the cost of a file clerk.
---------------------------------------------------------------------------
1781. We estimate that the final order would affect the burden and
cost of FERC-917 as follows:
Changes Due to Final Order in Docket No. RM21-17-000 \3741\
----------------------------------------------------------------------------------------------------------------
total estimated
Total annual Average burden burden hours &
Area of modification Annual number of estimated hours & cost \3742\ total estimated
respondents number of per response cost (column C x
responses column D)
A B.................. C D.................. E
----------------------------------------------------------------------------------------------------------------
FERC-917, Electric Transmission Facilities (OMB Control No. 1902-0233)
----------------------------------------------------------------------------------------------------------------
Draft OATT revisions to comply 48 transmission 48 One Time: 770 One Time: 36,960
with the requirements of the providers with hours; $71,683. hours; $3,440,783.
final order. OATTs. Ongoing: 0 hours Ongoing: 0 hours
per year; $0 per per year; $0 per
year. year.
Establish a six-month time period 48 transmission 48 One Time: 390 One Time: 18,720
during which transmission providers with hours; $36,307. hours; $1,742,734.
providers must, among other OATTs. Ongoing: 0 hours Ongoing: 0 hours
things, provide a forum for per year; $0 per per year; $0 per
negotiation that enables year. year.
participation by Relevant State
Entities and to discuss
potential Long-Term Regional
Transmission Cost Allocation
Methods and/or a State Agreement
Process.
[[Page 49552]]
Participate in Long-Term Regional 48 transmission 48 One Time: 0 hours; One Time: 0 hours;
Transmission Planning, which providers with .............. $0. $0.
includes creating and updating OATTs. .............. Ongoing: 4,500 Ongoing: 216,000
datasets, developing Long-Term ................... .............. hours per year; hours per year;
Scenarios, evaluating the ................... .............. $418,926 per year. $20,108,471 per
benefits of Long-Term Regional ................... 77 One Time: 0 hours; year.
Transmission Facilities, and 77 transmission $0. ...................
establishing criteria in providers without Ongoing: 200 hours ...................
consultation with Relevant State OATTs. per year; $18,619. One Time: 0 hours;
Entities and stakeholders to $0.
select Long-Term Regional Ongoing: 15,400
Transmission Facilities in the hours per year;
regional transmission plan for $1,433,659 per
purposes of cost allocation. year.
Revise the regional transmission 48 transmission 48 One Time: 30 hours; One Time: 1,440
planning process to enhance providers with .............. $2,793. hours; $134,056.
transparency of local OATTs. .............. Ongoing: 120 hours Ongoing: 5,760
transmission planning and ................... .............. per year; $11,172 hours per year;
identifying potential ................... .............. per year. $536,226 per year.
opportunities to right-size ................... 77 One Time: 20 hours; ...................
replacement transmission 77 transmission $1,862. One Time: 1,540
facilities. providers without Ongoing: 40 hours hours; $143,366.
OATTs. per year; $3,724 Ongoing: 3,080
per year. hours per year;
$286,732 per year.
Evaluate whether certain 48 transmission 48 One Time: 0 hours; One Time: 0 hours;
alternative transmission providers with .............. $0. $0.
technologies can meet the OATTs. .............. Ongoing: 100 hours Ongoing: 4,800
transmission needs identified in ................... .............. per year; $9,309 hours per year;
Order No. 1000 regional ................... .............. per year. $446,855 per year.
transmission planning processes ................... 77 One Time: 0 hours; ...................
and in Long-Term Regional 77 transmission $0. ...................
Transmission Planning process providers without Ongoing: 20 hours One Time: 0 hours;
more efficiently or cost- OATTs. per year; $1,862 $0.
effectively than transmission per year. Ongoing: 1540 hours
facilities without such per year; $143,366
alternative transmission per year.
technologies.
Consider in the Order No. 1000 48 transmission 48 One Time: 0 hours; One Time: 0 hours;
regional transmission planning providers with $0. $0.
processes regional transmission OATTs. Ongoing: 50 hours Ongoing: 2,400
facilities that address certain per year; $4,655 hours per year;
interconnection-related needs.. per year. $223,427 per year.
Share with the transmission 48 transmission 48 One Time: 0 hours; One Time: 0 hours;
providers in neighboring providers with $0. $0.
transmission planning regions OATTs. Ongoing: 25 hours Ongoing: 1,200
information regarding Long-Term per year; $2,327 hours per year;
Transmission Needs and potential per year. $111,714 per year.
transmission facilities to meet
those needs; identify and
jointly evaluate interregional
transmission facilities with the
transmission providers in
neighboring transmission
planning regions; and publicly
post certain information
regarding interregional
coordination processes applied
to Long-Term Regional
Transmission Planning..
Total burden for the revisions of 48 transmission 48 One Time: 1,190 One Time: 57,120
FERC 917 due to RM21-17. providers with hours; $110,783. hours; $5,317,573.
OATTs. Ongoing: 4,795 Ongoing: 230,160
hours per year; hours per year;
$446,390 per year. *$21,426,693 per
year.
1................................ 77 transmission 77 One Time: 20 hours; One Time: 1,540
providers without $1,862. hours; $143,366.
OATTs. Ongoing: 260 hours Ongoing: 20,020
per year; $24,205 hours per year;
per year. $1,863,757 per
year.
------------------------------------------------------------------------------
Totals for all 125 transmission providers One Time: 58,660
hours; $5,460,939.
Ongoing: 250,180
hours per year;
$23,290,450 per
year.
----------------------------------------------------------------------------------------------------------------
[[Page 49553]]
1782. Our estimates conservatively assume the maximum number of
respondents and burdens. We acknowledge that the actual burdens for
some respondents may be lower than estimated and that other respondents
may incur the maximum burdens.
1783. Interested persons may obtain information on the reporting
requirements by contacting Jean Sonneman, Office of the Executive
Director, Federal Energy Regulatory Commission, 888 First Street NE,
Washington, DC 20426 via email ([email protected]) or telephone
(202) 502-8663.
XIII. Environmental Analysis
1784. The Commission is required to prepare an Environmental
Assessment or an Environmental Impact Statement for any action that may
have a significant adverse effect on the human environment.\3743\ We
conclude that neither an Environmental Assessment nor an Environmental
Impact Statement is required for this final order under Sec.
380.4(a)(15) of the Commission's regulations, which provides a
categorical exemption for approval of actions under sections 205 and
206 of the FPA relating to the filing of schedules containing all rates
and charges for the transmission or sale of electric energy subject to
the Commission's jurisdiction, plus the classification, practices,
contracts and regulations that affect rates, charges, classifications,
and services.\3744\
---------------------------------------------------------------------------
\3743\ Regulations Implementing the Nat'l Env'l Pol'y Act, Order
No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs. Preambles
1986-1990 ] 30,783 (1987) (cross-referenced at 41 FERC ] 61,284).
\3744\ 18 CFR 380.4(a)(15).
---------------------------------------------------------------------------
XIV. Regulatory Flexibility Act
1785. The Regulatory Flexibility Act of 1980 (RFA) \3745\ generally
requires a description and analysis of rulemakings that will have
significant economic impact on a substantial number of small entities.
The Small Business Administration (SBA) sets the threshold for what
constitutes a small business. Under SBA's size standards,\3746\ RTOs/
ISOs, transmission planning regions, and transmission owners all fall
under the category of Electric Bulk Power Transmission and Control
(NAICS code 221121), with a size threshold of 950 employees (including
the entity and its associates).\3747\
---------------------------------------------------------------------------
\3745\ 5 U.S.C. 601-612.
\3746\ 13 CFR 121.201.
\3747\ The RFA definition of ``small entity'' refers to the
definition provided in the Small Business Act, which defines a
``small business concern'' as a business that is independently owned
and operated and that is not dominant in its field of operation. The
SBA's regulations define the threshold for a small Electric Bulk
Power Transmission and Control entity (NAICS code 221121) to be 950
employees. 13 CFR 121.201; see 5 U.S.C. 601(3) (citing section 3 of
the Small Business Act, 15 U.S.C. 632).
---------------------------------------------------------------------------
1786. We have determined that the entities impacted by this final
order are transmission providers in transmission planning regions that
span across the United States.\3748\
---------------------------------------------------------------------------
\3748\ See FERC, Regions Map Printable Version Order No. 1000
(Nov. 9, 2021), https://www.ferc.gov/media/regions-map-printable-version-order-no-1000.
---------------------------------------------------------------------------
1787. To identify small firms among the transmission providers that
comprise the transmission planning regions, we created a list of
transmission service providers and transmission owners from the North
American Electric Reliability Corporation Registry (dated January 11,
2024), totaling 125 entities. We conducted research using both open-
source information and data from paid services such as Dunn &
Bradstreet. We find that, out of the population of 125 transmission
providers, 18 would be considered small using the SBA threshold (14%
rounded). Therefore, we do not consider this number of small entities
to be substantial.
1788. As shown in the table above, we estimate the one-time costs
associated with the final order to be $110,783 per transmission
provider with an OATT and $1,862 per transmission provider without an
OATT. We estimate the ongoing costs in subsequent years to be $446,390
per year for transmission providers with an OATT and $24,205 per year
for transmission providers without an OATT. Further, we note that
Commission regulations allow for transmission providers to fully
recover the costs of participating in the regional transmission
planning process.\3749\ Therefore, we do not believe that this cost is
economically significant. Accordingly, we certify that the reforms in
this final order will not have a significant economic impact on a
substantial number of small entities.
---------------------------------------------------------------------------
\3749\ Order No. 890, 118 FERC ] 61,119 at P 586.
---------------------------------------------------------------------------
XV. Document Availability
1789. In addition to publishing the full text of this document in
the Federal Register, the Commission provides all interested persons an
opportunity to view and/or print the contents of this document via the
internet through the Commission's Home Page (https://www.ferc.gov).
1790. From the Commission's Home Page on the internet, this
information is available on eLibrary. The full text of this document is
available on eLibrary in PDF and Microsoft Word format for viewing,
printing, and/or downloading. To access this document in eLibrary, type
the docket number excluding the last three digits of this document in
the docket number field.
1791. User assistance is available for eLibrary and the
Commission's website during normal business hours from FERC Online
Support at 202-502-6652 (toll free at 1-866-208-3676) or email at
[email protected], or the Public Reference Room at (202) 502-
8371, TTY (202)502-8659. Email the Public Reference Room at
[email protected].
XVI. Effective Date and Congressional Notification
1792. This final order is effective August 12, 2024. The Commission
has determined, with the concurrence of the Administrator of the Office
of Information and Regulatory Affairs of OMB, that this order is a
``major rule'' as defined in section 351 of the Small Business
Regulatory Enforcement Fairness Act of 1996.
List of Subjects in 18 CFR Part 35
Electric power rates, Electric utilities, Reporting and
recordkeeping requirements.
By the Commission.
Chairman Phillips and Commissioner Clements are concurring with a
joint separate statement attached.
Commissioner Christie is dissenting with a separate statement
attached.
Issued May 13, 2024.
Debbie-Anne A. Reese,
Acting Secretary.
Note: The following appendices will not appear in the Code of
Federal Regulations.
Appendix A: Abbreviated Names of Commenters
Abbreviated Names of Commenters
------------------------------------------------------------------------
Abbreviation Commenter(s)
------------------------------------------------------------------------
Acadia Center and CLF........ Acadia Center and Conservation Law
Foundation.
[[Page 49554]]
ACEG......................... Americans for a Clean Energy Grid.
ACORE........................ American Council on Renewable Energy.
Advanced Energy Buyers....... Advanced Energy Buyers Group.
AEE.......................... Advanced Energy Economy.
AEP.......................... American Electric Power Service
Corporation.
Alabama Commission........... Alabama Public Service Commission.
Amazon....................... Amazon Energy LLC.
Ameren....................... Ameren Services Company.
American Municipal Power..... American Municipal Power, Inc.
Americans for Fair Energy Americans for Fair Energy Prices, Inc.
Prices.
Anbaric...................... Anbaric Development Partners, LLC.
APPA......................... American Public Power Association.
APS.......................... Arizona Public Service Company.
Arizona Commission........... Arizona Corporation Commission.
ATC.......................... American Transmission Company LLC.
Avangrid..................... Avangrid, Inc.
Bekaert...................... Bekaert Corporation.
BP........................... bp America.
Breakthrough Energy.......... Breakthrough Energy.
Business Council for Business Council for Sustainable Energy.
Sustainable Energy.
CAISO........................ California Independent System Operator
Corporation.
California Commission........ California Public Utilities Commission.
California Democratic U.S. Representatives Jared Huffman; Mike
Representatives. Levin; Nanette Diaz Barrag[aacute]n;
Grace F. Napolitano; Anna G. Eshoo;
Katie Porter; Judy Chu; Mike Thompson;
Ted W. Lieu; Julia Brownley; Mark
DeSaulnier; and Juan Vargas.
California Energy Commission. California Energy Commission.
California Municipal California Municipal Utilities
Utilities. Association.
California Water............. California Department of Water Resources
State Water Project.
CARE Coalition............... The National Audubon Society; Defenders
of Wildlife; Environmental Law & Policy
Center; National Wildlife Federation;
The Nature Conservancy; Center for
Renewables Integration; and Vote Solar,
jointly the Conservation and Renewable
Energy Coalition.
Center for Biological The Center for Biological Diversity.
Diversity.
Ceres........................ Ceres.
Certain TDUs................. Alliant Energy Corporate Services, Inc.;
Consumers Energy Company; and DTE
Electric Company.
Chemistry Council............ American Chemistry Council.
Citizens Energy.............. Citizens Energy Corporation.
City of New Orleans Council.. Council of the City of New Orleans.
City of New York............. City of New York.
Clean Energy Associations.... The American Clean Power Association;
Alliance for Clean Energy--New York;
Clean Grid Alliance; the Mid-Atlantic
Renewable Energy Council Action; and the
New York Offshore Wind Alliance,
collectively Clean Energy Associations.
Clean Energy Buyers.......... Clean Energy Buyers Association.
Clean Energy States.......... Clean Energy States Alliance.
Colorado Consumer Advocate... Colorado Office of the Utility Consumer
Advocate.
Competition Advocates........ Niskanen Center; R Street Institute;
Institute for Local Self Reliance;
Public Citizen, Inc.; Center for
Biological Diversity; and Open Markets
Institute.
Competition Coalition........ Electricity Transmission Competition
Coalition.
Concerned Scientists......... The Union of Concerned Scientists.
Conservative Energy Network.. Conservative Energy Network.
Conservatives for Clean Conservatives for Clean Energy--Florida.
Energy--Florida.
Conservatives for Clean Conservatives for Clean Energy--South
Energy--SC. Carolina.
Consumer Organizations....... NJ Charge, Inc.; Keryn Newman (Stop Path
WV); Illinois Landowners Alliance; Block
Grain Belt Express--Missouri; Citizens
to Stop Transource--York; Coalition for
Rural Property Rights; Eastern Missouri
Landowners Alliance; Missouri Landowners
Association; Protect Sudbury Inc.; Say
No to NECEC; Stop B2H Coalition; Eastern
Missouri Landowners Alliance; SOUL of
Wisconsin; Block RICL; Matthew
Stallbaumer; Vickie Husbands; Elena
Guardincerri; Martha Peine; Kerry
Beheler; Barron Shaw; and STOP
Transource Power Lines MD, Inc.
Cross Sector Representatives. Ameren Transmission; Blue-Green Alliance;
Consolidated Edison Company of New York,
Inc.; Edison International; Exelon
Corporation; Greater Warren County
Economic Development Council;
International Brotherhood of Electric
Workers IBEW 1245; IBEW Illinois State
Conference; IBEW International; IBEW
Sixth District; ITC Holdings Corp.;
National Audubon Society; Pacific Gas &
Electric Co.; The Permitting Institute;
Public Service Electric and Gas Company;
WEG Transformers USA; and Xcel Energy.
CTC Global................... CTC Global Corporation.
Cypress Creek................ Cypress Creek Renewables, LLC.
DATA......................... Ameren Services Company; Eversource
Energy; Exelon Corporation; ITC Holdings
Corp.; National Grid USA; Public Service
Electric and Gas Company; and Xcel
Energy; collectively Developers
Advocating Transmission Advancements
(DATA).
DC and MD Offices of People's The Office of the People's Counsel for
Counsel. the District of Columbia and the
Maryland Office of People's Counsel.
[[Page 49555]]
Dominion..................... Dominion Energy Services, Inc.
Duke......................... Duke Energy Corporation.
Duquesne Light............... Duquesne Light Company.
EEI.......................... Edison Electric Institute.
ELCON........................ Electricity Consumers Resource Council.
Enel......................... Enel North America, Inc.
ENGIE........................ ENGIE North America, Inc.
Entergy...................... Entergy Services, LLC.
Environmental Groups......... Advanced Energy United; American Clean
Power Association; Clean Air Task Force;
EarthJustice; Environmental Defense
Fund; Evergreen Action; Fresh Energy;
Interwest Energy Alliance; League of
Conservation Voters; National Wildlife
Federation; Natural Resources Defense
Council; Northwest Energy Coalition;
Rewiring America; Sierra Club; Southern
Environmental Law Center; The
Environmental Law & Policy Center; Union
of Concerned Scientists; WE ACT for
Environmental Justice; and Western
Resource Advocates.
Environmental Legislators National Caucus of Environmental
Caucus. Legislators.
EPSA......................... Electric Power Supply Association.
Evergreen Action............. Evergreen Action and 4,440 Individual
Signers.
Eversource................... Eversource Energy Service Company.
Exelon....................... Exelon Corporation.
Fervo........................ Fervo Energy Company.
Form Energy.................. Form Energy, Inc.
Freeport-McMoRan............. Freeport-McMoRan, Inc.
Georgia Commission........... Georgia Public Service Commission.
Governor of Kansas Laura Governor of the State of Kansas Laura
Kelly. Kelly.
Grand Rapids NAACP........... Greater Grand Rapids Chapter of The
National Association for the Advancement
of Colored People.
Grid United.................. Grid United LLC.
GridLab...................... GridLab.
Handy Law.................... Seth Handy, Handy Law, LLC.
Hannon Armstrong............. Hannon Armstrong Sustainable
Infrastructure Capital, Inc.
Harvard ELI.................. Harvard Electricity Law Initiative.
Idaho Commission............. The Idaho Public Utilities Commission.
Idaho Power.................. Idaho Power Company.
Illinois Commission.......... The Illinois Commerce Commission.
Indiana Commission........... Indiana Utility Regulatory Commission.
Indicated PJM TOs............ The Dayton Power and Light Company;
Dominion Energy Services, Inc. on behalf
of Virginia Electric and Power Company;
Duke Energy Corporation on behalf of its
affiliates Duke Energy Ohio, Inc., Duke
Energy Kentucky, Inc., and Duke Energy
Business Services LLC; Duquesne Light
Company; East Kentucky Power
Cooperative; Exelon Corporation;
FirstEnergy Service Company, on behalf
of its affiliates American Transmission
Systems, Incorporated, Jersey Central
Power & Light Company, Mid-Atlantic
Interstate Transmission LLC, West Penn
Power Company, The Potomac Edison
Company, Monongahela Power Company,
Keystone Appalachian Transmission
Company, and Trans-Allegheny Interstate
Line Company; PPL Electric Utilities
Corporation; Public Service Electric and
Gas Company; Rockland Electric Company;
and UGI Utilities Inc.
Indicated U.S. Senators and U.S. Senators Tina Smith; Edward J.
Representatives. Markey; and Sheldon Whitehouse; U.S.
Representatives Kathy Castor; Bobby L.
Rush; Paul Tonko; Sean Casten; Raja
Krishnamoorthi; Jared Huffman; Veronica
Escobar; and Julia Brownley
Industrial Customers......... American Forest & Paper Association; the
PJM Industrial Customer Coalition; and
the Coalition of MISO Transmission
Customers, collectively the Industrial
Customer Organizations.
Interwest.................... Interwest Energy Alliance.
Invenergy.................... Invenergy Solar Development North America
LLC; Invenergy Thermal Development LLC;
Invenergy Wind Development North America
LLC; and Invenergy Transmission LLC.
Iowa Commission.............. Iowa Utilities Board.
ISO/RTO Council.............. The ISO/RTO Council.
ISO-NE....................... ISO New England Inc.
ITC.......................... International Transmission Company;
Michigan Electric Transmission Company,
LLC; ITC Midwest LLC; and ITC Great
Plains, LLC.
Joint Commenters............. American Public Power Association;
Electricity Consumers Resource Council;
Indiana Office of Utility Consumer
Counselor; Large Public Power Council;
National Association of State Utility
Consumer Advocates; Office of People's
Counsel for the District of Columbia;
Public Advocate for the State of
Delaware; and Solar Energy Industries
Association.
Joint Consumer Advocates..... Iowa Office of Consumer Advocate and
Indiana Office of Utility Consumer
Counselor.
Kansas Commission............ Kansas Corporation Commission.
Kansas Commission Chair Keen. Kansas Corporation Commission Chairman
Dwight D. Keen.
Kansas Ratepayers Advocates.. Kansas Industrial Consumers Group, Inc.
and Kansans for Lower Electric Rates,
Inc.
Kentucky Commission Chair Kentucky Public Service Commission
Chandler. Chairman and Commissioner Kent A.
Chandler.
LADWP........................ Los Angeles Department of Water & Power.
[[Page 49556]]
Large Energy Customers....... Akamai Technologies, Inc.; Amazon.com,
Inc.; Amy's Kitchen, Inc.; Apple, Inc.;
Applied Materials, Inc.; ARC Homes;
Atlassian Corporation; Autodesk, Inc.;
BASF Corporation; Best Buy Co., Inc.;
Brookfield Properties; Budderfly, Inc.;
Build Efficiently, LLC.; Cargill, Inc.;
Clean Energy Buyers Association; Eastman
Chemical Company; eBay, Inc.; Equinix,
Inc.; Freeport-McMoRan, Inc.; General
Motors LLC; Google LLC; Green Impact
Technologies; Hewlett Packard Enterprise
Company; Humanscale Corporation; IHG
Hotels & Resorts; Marriott
International, Inc.; Mars, Inc.; Meta
Platforms, Inc.; Microsoft Corporation;
Monarch Energy; Nike, Inc.; Nucor
Corporation; Oatly Group AB; PepsiCo,
Inc.; Prologis, Inc.; Rivian Automotive,
Inc.; Saint-Gobain North America;
Salesforce, Inc.; Schneider Electric SE;
Target Corporation; Thermo Fisher
Scientific, Inc.; The STAAC Group, LLC.,
Walmart, Inc.; Workday, Inc.; and World
Energy, LLC.
Large Public Power........... The Large Public Power Council.
Louisiana Commission......... Louisiana Public Service Commission.
LS Power..................... LS Power Grid, LLC.
Maine Public Advocate........ The Maine Office of the Public Advocate.
Maryland Energy Maryland Energy Administration.
Administration.
Massachusetts Attorney Massachusetts Attorney General Maura
General. Healey.
Michigan Commission.......... Michigan Public Service Commission.
Michigan Conservative Energy Michigan Conservative Energy Forum.
Forum.
Michigan State Entities...... Michigan Attorney General and the
Citizens Utility Board of Michigan.
Microgrid Resources.......... Microgrid Resources Coalition.
Middle River Power........... Middle River Power LLC.
Minnesota State Entities..... The Minnesota Public Utilities Commission
and The Minnesota Department of
Commerce.
MISO......................... Midcontinent Independent System Operator,
Inc.
MISO Coops................... The Coalition of MISO Generation and
Transmission Cooperatives.
MISO TOs..................... Ameren Services Company, as agent for
Union Electric Company, Ameren Illinois
Company, and Ameren Transmission Company
of Illinois; American Transmission
Company LLC; Big Rivers Electric
Corporation; Central Minnesota Municipal
Power Agency; City Water, Light & Power
(Springfield, IL); Cleco Power LLC;
Cooperative Energy; Dairyland Power
Cooperative; Duke Energy Business
Services, LLC for Duke Energy Indiana,
LLC; East Texas Electric Cooperative;
Great River Energy; Hoosier Energy Rural
Electric Cooperative, Inc.; Indiana
Municipal Power Agency; Indianapolis
Power & Light Company; International
Transmission Company; ITC Midwest LLC;
Lafayette Utilities System; Michigan
Electric Transmission Company, LLC;
MidAmerican Energy Company; Minnesota
Power (and its subsidiary Superior
Water, L&P); Montana-Dakota Utilities
Co.; Northern Indiana Public Service
Company LLC; Northern States Power
Company, a Minnesota corporation, and
Northern States Power Company, a
Wisconsin corporation, subsidiaries of
Xcel Energy Inc.; Northwestern Wisconsin
Electric Company; Otter Tail Power
Company; Prairie Power, Inc.; Southern
Illinois Power Cooperative; Southern
Indiana Gas & Electric Company; Southern
Minnesota Municipal Power Agency; Wabash
Valley Power Association, Inc.; and
Wolverine Power Supply Cooperative, Inc.
Mississippi Commission....... The Mississippi Public Service
Commission.
Montana QF Developers........ Cl[emacr]nera, LLC and Greenfields
Irrigation District.
Montclair Congregation....... 40 Undersigned Congregants of Montclair
Presbyterian Church.
NARUC........................ The National Association of Regulatory
Utility Commissioners.
NASEO........................ The National Association of State Energy
Officials.
NASUCA....................... The National Association of State Utility
Consumer Advocates.
National and State National Wildlife Federation;
Conservation Organizations. Conservation Coalition of Oklahoma;
Environment Council of Rhode Island;
Environmental League of Massachusetts;
Idaho Wildlife Federation; Iowa Wildlife
Federation; Kentucky Waterways Alliance;
Natural Resources Council of Maine;
Nevada Wildlife Federation; New Jersey
Audubon; Southeast Alaska Conservation
Council; Texas Conservation Alliance;
Utah Wildlife Federation; WV Rivers
Coalition; and Wyoming Wildlife
Federation.
National Grid................ National Grid Plc.
Nebraska Commission.......... The Nebraska Power Review Board.
NEMA......................... National Electrical Manufacturers
Association.
NEPOOL....................... The New England Power Pool Participants
Committee.
NERC......................... North American Electric Reliability
Corporation; Midwest Reliability
Organization; Northeast Power
Coordinating Council, Inc.;
ReliabilityFirst Corporation; SERC
Reliability Corporation, Texas
Reliability Entity, Inc., and Western
Electricity Coordinating Council.
NESCOE....................... The New England States Committee on
Electricity.
Nevada Commission............ The Public Utilities Commission of
Nevada.
New England for Offshore Wind New England for Offshore Wind.
New England Systems.......... Belmont Municipal Light Department; Block
Island Utility District; Braintree
Electric Light Department; Chicopee
Municipal Light Department; Georgetown
Municipal Light Department; Hingham
Municipal Lighting Plant; Littleton
Electric Light & Water Department;
Middleborough Gas & Electric Department;
Middleton Electric Light Department;
North Attleborough Electric Department;
Norwood Municipal Light Department;
Pascoag Utility District; Reading
Municipal Light Department; Stowe
Electric Department; Taunton Municipal
Lighting Plant; Wallingford Electric
Division; and Westfield Gas & Electric
Light Department.
New Jersey Commission........ The New Jersey Board of Public Utilities.
New Mexico RETA.............. The New Mexico Renewable Energy
Transmission Authority.
[[Page 49557]]
New York Commission and New York Public Service Commission and
NYSERDA. New York State Energy Research and
Development Authority.
New York State Department.... New York State Department of State
Utility Intervention Unit.
New York TOs................. Central Hudson Gas & Electric
Corporation; Consolidated Edison Company
of New York, Inc.; Niagara Mohawk Power
Corporation; New York Power Authority;
New York State Electric & Gas
Corporation; Orange and Rockland
Utilities, Inc.; Long Island Power
Authority; and Rochester Gas and
Electric Corporation.
New York Transco............. New York Transco, LLC.
NextEra...................... NextEra Energy, Inc.
Non-RTO NASUCA............... North Carolina Utilities Commission
Public Staff; the Utah Office of
Consumer Service; the South Carolina
Office of Regulatory Staff; and the
Wyoming Office of Consumer Advocate.
North Carolina Commission and The North Carolina Utilities Commission
Staff. and the North Carolina Utilities
Commission Public Staff.
North Dakota Commission...... North Dakota Public Service Commission
Public Utilities Division.
Northwest and Intermountain.. Northwest & Intermountain Power Producers
Coalition.
NRECA........................ National Rural Electric Cooperative
Association.
NRG.......................... NRG Energy, Inc.
NYISO........................ New York Independent System Operator,
Inc.
NYPA......................... New York Power Authority.
Ohio Commission Federal The Public Utilities Commission of Ohio's
Advocate. Office of the Federal Energy Advocate.
Ohio Conservative Energy Ohio Conservative Energy Forum.
Forum.
Ohio Consumers............... Office of The Ohio Consumers' Counsel.
Omaha Public Power........... The Omaha Public Power District.
OMS.......................... The Organization of Midcontinent
Independent System Operator States, Inc.
Onward Energy................ Onward Energy Holdings, LLC.
[Oslash]rsted................ [Oslash]rsted North America.
Pacific Northwest State The Washington Utilities and
Agencies. Transportation Commission; Oregon Public
Utility Commission; Washington State
Department Of Commerce; and Oregon
Department Of Energy.
Pacific Northwest Utilities.. Avista Corporation; Portland General
Electric; Puget Sound Energy, Inc.; and
Tacoma Power.
PacifiCorp and NV Energy..... PacifiCorp; Nevada Power Company and
Sierra Pacific Power Company (together,
NV Energy).
Pattern Energy............... Pattern Energy Group LP.
Payton Alaama................ Payton Alaama.
Pennsylvania Commission...... The Pennsylvania Public Utility
Commission.
PG&E......................... Pacific Gas and Electric Company.
Pine Gate.................... Pine Gate Renewables, LLC.
PIOs......................... Sustainable FERC Project; Natural
Resources Defense Council; Sierra Club;
Environmental Defense Fund; Southern
Environmental Law Center; Conservation
Law Foundation; Western Resource
Advocates; Acadia Center; NW Energy
Coalition; Southface Institute; and
Fresh Energy, jointly Public Interest
Organizations.
PJM.......................... PJM Interconnection, L.L.C.
PJM Market Monitor........... The Independent Market Monitor of PJM
Interconnection, L.L.C.
PJM States................... The Organization of PJM States, Inc.
(OPSI).
Policy Integrity............. The Institute for Policy Integrity at New
York University School of Law.
Potomac Economics............ Potomac Economics, Ltd.
PPL.......................... PPL Electric Utilities Corporation;
Louisville Gas & Electric and Kentucky
Utilities (collectively LG&E/KU); and
The Narragansett Electric Company.
Prysmian..................... The Prysmian Group.
Public Systems............... Massachusetts Municipal Wholesale
Electric Company; New Hampshire Electric
Cooperative, Inc.; Connecticut Municipal
Electric Energy Cooperative; and Vermont
Public Power Supply Authority.
QCo.......................... QCoefficient, Inc.
R Street..................... R Street Institute.
Rail Electrification......... The Rail Electrification Council.
Renewable Northwest.......... Renewable Northwest.
Resale Iowa.................. Resale Power Group of Iowa.
RMI.......................... RMI.
SDG&E........................ San Diego Gas & Electric Company.
SEIA......................... The Solar Energy Industries Association.
SEPA......................... The Smart Electric Power Alliance.
SERTP Sponsors............... Associated Electric Cooperative, Inc.;
Dalton Utilities; Duke Energy Carolinas,
LLC and Duke Energy Progress, LLC;
Georgia Transmission Corporation;
Louisville Gas and Electric Company and
Kentucky Utilities Company; the
Municipal Electric Authority of Georgia;
PowerSouth Energy Cooperative; Southern
Company Services, Inc., acting as agent
for Alabama Power Company, Georgia Power
Company, and Mississippi Power Company;
the Tennessee Valley Authority; and Gulf
Power Company, collectively Sponsors of
the Southeastern Regional Transmission
Planning Process (SERTP).
Shell........................ Shell Energy North America (U.S.), L.P.;
Shell New Energies U.S., LLC; and Savion
L.L.C.
[[Page 49558]]
Signatories.................. American Council on Renewable Energy;
Americans for a Clean Energy Grid;
American Clean Power Association; AES
Corporation; Advance Energy Economy;
Center for Rural Affairs; Clean Air Task
Force; Clean Energy Buyers Alliance;
Conservative Energy Network; ConEd
Transmission, Inc.; Enel North America,
Inc.; Exelon Corporation; GE Renewables;
Grid United LLC; Google; Holy Cross
Energy; Invenergy; ITC Holdings Corp.;
Land & Liberty Coalition; Macro Grid
Initiative; National Audubon Society;
National Electrical Manufacturer
Association; National Wildlife
Federation; Natural Resources Defense
Council; NextEra Energy, Inc.; Northwest
& Intermountain Power Producers
Coalition; Pattern Energy; Rail
Electrification Council; Rocky Mountain
Institute (RMI); Sierra Club; Solar
Energy Industries of America; and
Southern Renewable Energy Association.
Six Cities................... The Cities of Anaheim, Azusa, Banning,
Colton, Pasadena, and Riverside,
California.
Smart Wires.................. Smart Wires.
SoCal Edison................. Southern California Edison Company.
Southeast PIOs............... Southern Environmental Law Center; Energy
Alabama; North Carolina Sustainable
Energy Association; South Carolina
Coastal Conservation League; Southface
Energy Institute; and Southern Alliance
for Clean Energy, jointly Southeast
Public Interest Groups.
Southern..................... Southern Company Services, Inc.
Southwestern Power Group..... Southwestern Power Group.
SPP.......................... Southwest Power Pool Inc.
SPP Market Monitor........... The Southwest Power Pool Market
Monitoring Unit.
SREA......................... Southern Renewable Energy Association.
State Agencies............... Connecticut Department of Energy and
Environmental Protection; Connecticut
Attorney General; Connecticut Office of
Consumer Counsel; Connecticut Public
Utilities Regulatory Authority;
California Energy Commission; Delaware
Division of the Public Advocate;
Attorney General of the District of
Columbia; Maine Office of the Public
Advocate; Maryland Attorney General;
Massachusetts Attorney General; Michigan
Attorney General; Pennsylvania Office of
The Consumer Advocate; and the Rhode
Island Attorney General.
State of Tennessee........... State of Tennessee.
State Officials.............. Maine Governor's Energy Office;
Washington State Department of Commerce;
Arizona Governor's Office of Resiliency;
California Natural Resources Agency;
Colorado Energy Office; Deputy Governor
of Illinois; Maryland Energy
Administration; Michigan Department of
Environment, Great Lakes, and Energy;
New Mexico Energy Minerals and Natural
Resources Department; Office of New York
Governor Kathy Hochul; and Office of
North Carolina Governor Roy Cooper.
State Water Contractors...... State Water Contractors.
Tabors Caramanis Rudkevich... Tabors Caramanis & Rudkevich.
TANC......................... Transmission Agency of Northern
California.
TAPS......................... Transmission Access Policy Study Group.
Transmission Dependent Golden Spread Electric Cooperative, Inc.;
Utilities. North Carolina Electric Membership
Corporation; and Seminole Electric
Cooperative, Inc., collectively,
Transmission Dependent Utility Systems.
Transource................... Transource Energy, LLC.
Undersigned States [Initial Utah Attorney General; Alaska Attorney
Comments]. General; Georgia Attorney General; Idaho
Attorney General; Indiana Attorney
General; Kansas Attorney General;
Kentucky Attorney General; Louisiana
Attorney General; Mississippi Attorney
General; Montana Attorney General;
Nebraska Attorney General; North Dakota
Attorney General; Ohio Attorney General;
Oklahoma Attorney General; South
Carolina Attorney General; Texas
Attorney General; West Virginia Attorney
General; and Wyoming Attorney General.
Undersigned States [Reply Utah Attorney General; Alabama Attorney
Comments]. General; Alaska Attorney General;
Arkansas Attorney General; Florida
Attorney General; Georgia Attorney
General; Kansas Attorney General;
Kentucky Attorney General; Louisiana
Attorney General; Mississippi Attorney
General; Montana Attorney General;
Nebraska Attorney General; Ohio Attorney
General; Oklahoma Attorney General;
South Carolina Attorney General; Texas
Attorney General; and West Virginia
Attorney General.
U.S. Chamber of Commerce..... U.S. Chamber of Commerce.
U.S. Climate Alliance........ United States Climate Alliance.
U.S. Democratic U.S. Representatives Paul D. Tonko and
Representatives. 112 additional U.S. Representatives.
U.S. DOE..................... United States Department of Energy.
U.S. DOJ and FTC............. United States Department of Justice and
the Federal Trade Commission.
U.S. House Republicans....... U.S. Representatives Andrew R. Garbarino;
Anthony D'Espositio; Nicholas A.
Langworthy; and Brandon Williams.
U.S. Senator Barrasso........ U.S. Senator John Barrasso.
U.S. Senator Heinrich........ U.S. Senator Martin Heinrich.
U.S. Senators................ U.S. Senators Martin Heinrich; Edward J.
Markey; Peter Welch; John Hickenlooper;
Angus S. King, Jr.; Ron Wyden; Robert P.
Casey, Jr.; Sheldon Whitehouse; Tina
Smith; Ben Ray Luj[aacute]n; Chris Van
Hollen; Mazie K. Hirono; Jeffrey A.
Merkley; Brian Schatz; Thomas R. Carper;
Bernard Sanders; Patty Murray; John
Fetterman; Michael F. Bennet; Elizabeth
Warren; and Alex Padilla.
U.S. Senators Heinrich and U.S. Senators Martin Heinrich and Mike
Lee. Lee.
U.S. Senators Hickenlooper U.S. Senators John Hickenlooper and Angus
and King. S. King, Jr.
U.S. Senator Schumer......... U.S. Senator Charles E. Schumer.
U.S. Senator Whitehouse...... U.S. Senator Sheldon Whitehouse.
[[Page 49559]]
Utah Commission.............. The Utah Public Service Commission.
Utah Division of Public Utah Department of Commerce, Division of
Utilities. Public Utilities.
VEIR......................... VEIR Inc.
Vermont Electric and Vermont Vermont Electric Power Company, Inc., and
Transco. Vermont Transco LLC.
Vermont State Entities....... The Vermont Public Utility Commission and
the Vermont Department of Public
Service.
Virginia Attorney General.... Virginia Office of the Attorney General,
Division of Consumer Counsel.
Virginia Commission Staff.... The Staff of the Virginia State
Corporation Commission.
Vistra....................... Vistra Corp.
WATT Coalition............... The Working for Advanced Transmission
Technologies (WATT) Coalition.
WE ACT....................... WE ACT for Environmental Justice.
West Virginia Commission..... The Public Service Commission of West
Virginia.
Western PIOs................. Center for Energy Efficiency and
Renewable Technologies; NW Energy
Coalition; Western Resource Advocates;
and Renewable Northwest; collectively,
Western Public Interest Organizations.
Western State Representatives Agency Representatives from the states of
Arizona; California; Idaho; Montana;
Nevada; Oregon; South Dakota; Utah;
Washington; and Wyoming.
Western Way Colorado......... Western Way Colorado.
Western Way Nevada........... Western Way Nevada.
Western Way Utah............. Western Way Utah.
Wildlife Federation Action 8,610 Supporters of the National Wildlife
Fund Supporters. Federation Action Fund.
WIRES........................ WIRES.
Wisconsin Conservative Energy Wisconsin Conservative Energy Forum.
Forum.
Wisconsin Legislators........ Wisconsin State Senator Julian Bradley
and Wisconsin State Representative David
Steffen.
Wisconsin Senator Cowles..... Wisconsin State Senator Robert L. Cowles.
Xcel......................... Xcel Energy Services Inc.
------------------------------------------------------------------------
Appendix B: Pro Forma Open Access Transmission Tariff Attachment K
Note: Proposed deletions are in brackets and proposed additions
are in italics.
Attachment K
Transmission Planning Process
Local Transmission Planning
The Transmission Provider shall establish a coordinated, open,
and transparent local transmission planning process with its Network
and Firm Point-to-Point Transmission Customers and other interested
parties to ensure that the Transmission System is planned to meet
the needs of both the Transmission Provider and its Network and Firm
Point-to-Point Transmission Customers on a comparable and not unduly
discriminatory basis. The Transmission Provider's coordinated, open,
and transparent local transmission planning process shall be
provided as an attachment to the Transmission Provider's Tariff. The
Transmission Provider's local transmission planning process shall
provide stakeholders with meaningful opportunities to participate
and provide feedback, and shall satisfy the following nine
principles, as defined in Order No. 890: coordination, openness,
transparency, information exchange, comparability, dispute
resolution, regional participation, economic planning studies, and
cost allocation for new transmission projects. The local
transmission planning process also shall include the procedures and
mechanisms for considering transmission needs driven by Public
Policy Requirements consistent with Order No. 1000. The local
transmission planning process also shall provide a mechanism for the
recovery and allocation of transmission planning costs consistent
with Order No. 890. The description of the Transmission Provider's
local transmission planning process must include sufficient detail
to enable Transmission Customers to understand:
(i) The process for consulting with customers;
(ii) The notice procedures and anticipated frequency of
meetings;
(iii) The methodology, criteria, and processes used to develop a
transmission plan;
(iv) The method of disclosure of criteria, assumptions, and data
underlying a transmission plan;
(v) The obligations of and methods for Transmission Customers to
submit data to the Transmission Provider;
(vi) The dispute resolution process;
(vii) The Transmission Provider's study procedures for economic
upgrades to address congestion or the integration of new resources;
(viii) The Transmission Provider's procedures and mechanisms for
considering transmission needs driven by Public Policy Requirements,
consistent with Order No. 1000; and
(ix) The relevant cost allocation method or methods.
Regional Transmission Planning
The Transmission Provider shall participate in a regional
transmission planning process through which transmission facilities
and non-transmission alternatives may be proposed and evaluated. The
regional transmission planning process also shall develop a regional
transmission plan that identifies the transmission facilities
necessary to meet the needs of transmission providers and
transmission customers in the transmission planning region. The
regional transmission planning process must be consistent with the
provision of Commission-jurisdictional services at rates, terms, and
conditions that are just and reasonable and not unduly
discriminatory or preferential, as described in Order Nos. 1000 and
1920. The regional transmission planning process shall be described
in an attachment to the Transmission Provider's Tariff.
The Transmission Provider's regional transmission planning
process shall satisfy the following seven principles, as [set out
and explained]established in Order Nos. 890 and 1000: coordination,
openness, transparency, information exchange, comparability, dispute
resolution, and economic planning studies. The description of the
regional transmission planning process in the Tariff also shall
include the procedures and mechanisms for considering transmission
needs driven by Public Policy Requirements, consistent with Order
No. 1000. The regional transmission planning process shall provide a
mechanism for the recovery and allocation of ``transmission planning
costs'' consistent with Order Nos. 890 and 1000.
The regional transmission planning process shall include a clear
enrollment process for public and non-public utility transmission
providers that make the choice to become part of a transmission
planning region. The regional transmission planning process shall be
clear that enrollment will subject enrollees to cost allocation if
they are found to be beneficiaries of new transmission facilities
selected in the regional transmission plan for purposes of cost
allocation. Each Transmission Provider shall maintain a list of
enrolled entities in the Transmission Provider's Tariff.
The regional transmission planning process must include at least
three stakeholder meetings concerning the local transmission
planning process of each Transmission Provider that is a member of
the transmission planning region. The three
[[Page 49560]]
meetings must occur before each Transmission Provider's local
transmission planning information can be incorporated into the
transmission planning region's transmission planning models. The
three stakeholder meetings for local transmission planning
information are the Assumptions Meeting, the Needs Meeting, and the
Solutions Meeting, and the three stakeholder meetings must meet the
requirements in Order No. 1920.
As part of the regional transmission planning process, the
Transmission Providers in each transmission planning region shall
conduct Long-Term Regional Transmission Planning, meaning regional
transmission planning on a sufficiently long-term, forward-looking,
and comprehensive basis to identify Long-Term Transmission Needs,
identify transmission facilities that meet such needs, measure the
benefits of those transmission facilities, and evaluate those
transmission facilities for potential selection in the regional
transmission plan for purposes of cost allocation as the more
efficient or cost-effective regional transmission facilities to meet
Long-Term Transmission Needs. As part of this Long-Term Regional
Transmission Planning, the Transmission Providers in each
transmission planning region shall meet the requirements set forth
in Order No. 1920, including: (1) identifying Long-Term Transmission
Needs and Long-Term Regional Transmission Facilities to meet those
needs through the development of Long-Term Scenarios that satisfy
the requirements set forth in Order No. 1920; (2) measuring the
required seven benefits consistent with the requirements set forth
in Order No. 1920; (3) using the measured benefits to evaluate Long-
Term Regional Transmission Facilities; and (4) using selection
criteria consistent with the requirements set forth in Order No.
1920 that provide the opportunity for Transmission Providers to
select Long-Term Regional Transmission Facilities in the regional
transmission plan for purposes of cost allocation that more
efficiently or cost-effectively address Long-Term Transmission
Needs.
The process through which the Transmission Providers in each
transmission planning region develop Long-Term Scenarios must comply
with the following six transmission planning principles established
in Order No. 890: coordination; openness; transparency; information
exchange; comparability; and dispute resolution. The Transmission
Providers in each transmission planning region shall outline in
their Tariffs an open and transparent process that provides
stakeholders, including states, with a meaningful opportunity to
propose potential factors and to provide input on how to account for
specific factors in the development of Long-Term Scenarios. The
Transmission Providers in each transmission planning region shall
also outline in their Tariffs an open and transparent process that
provides stakeholders, including states, with a meaningful
opportunity to propose which future outcomes are probable and can be
captured through assumptions made in the development of Long-Term
Scenarios.
The Transmission Providers in each transmission planning region
shall include in their Tariffs a general description of how they
will measure each of the seven required benefits used to evaluate
Long-Term Regional Transmission Facilities. The Transmission
Providers in each transmission planning region shall measure and use
the seven benefits, as described in Order No. 1920, in Long-Term
Regional Transmission Planning.
As part of Long-Term Regional Transmission Planning, the
Transmission Providers in each transmission planning region shall
include in their Tariffs an evaluation process, including selection
criteria, that: (1) is transparent and not unduly discriminatory;
(2) aims to ensure that more efficient or cost-effective
transmission facilities are selected in the regional transmission
plan for purposes of cost allocation; (3) seeks to maximize benefits
accounting for costs over time without over-building transmission
facilities; and (4) otherwise satisfies the requirements set forth
in Order No. 1920.
The Transmission Providers in each transmission planning region
shall include in their Tariffs one or more Long-Term Regional
Transmission Cost Allocation Methods, which is an ex ante regional
cost allocation method for one or more Long-Term Regional
Transmission Facilities (or portfolio of such Facilities) that are
selected in the regional transmission plan for purposes of cost
allocation and that complies with the requirements set forth in
Order No. 1920. The Transmission Providers in each transmission
planning region may also, subject to (1) the agreement of Relevant
State Entities and (2) Commission acceptance, include in their
Tariffs a State Agreement Process. A State Agreement Process is a
process by which one or more Relevant State Entities may voluntarily
agree to a cost allocation method for Long-Term Regional
Transmission Facilities (or a portfolio of such Facilities) either
before or no later than six months after the facilities are selected
in the regional transmission plan for purposes of cost allocation.
The Tariff must describe how the State Agreement Process will result
in a cost allocation being filed, including which entities can
participate in the State Agreement Process; what constitutes an
agreement on cost allocation in that process; how agreement is
communicated to the transmission provider; and the circumstances
under which, or the information necessary for, a transmission
provider to file or to consider filing the agreed cost allocation.
As part of evaluating new regional transmission facilities, as
well as upgrades to existing transmission facilities, the
Transmission Providers in each transmission planning region shall
consider in all of their regional transmission planning and cost
allocation processes whether selecting transmission facilities that
incorporate the following technologies would be more efficient or
cost-effective than selecting new regional transmission facilities
or upgrades to existing transmission facilities that do not
incorporate these technologies: dynamic line ratings, as defined in
18 CFR 35.28(b)(14), advanced power flow control devices, advanced
conductors, and/or transmission switching. Specifically, such
consideration must include both: (1) whether incorporating dynamic
line ratings, advanced power flow control devices, advanced
conductors, and/or transmission switching into existing transmission
facilities could meet the same regional transmission need more
efficiently or cost-effectively than other potential transmission
facilities; and (2) when evaluating transmission facilities for
potential selection in the regional transmission plan for purposes
of cost allocation, whether incorporating dynamic line ratings,
advanced power flow control devices, advanced conductors, and/or
transmission switching as part of any potential regional
transmission facility would be more efficient or cost-effective.
Transmission providers must evaluate the benefits of incorporating
the enumerated alternative transmission technologies into Long-Term
Regional Transmission Facilities in a manner consistent with the
requirements in the Evaluation of Benefits of Regional Transmission
Facilities and Evaluation and Selection of Long-Term Regional
Transmission Facilities sections of Order No. 1920.
The Transmission Providers in each transmission planning region
shall evaluate for potential selection in the regional transmission
plan for purposes of cost allocation regional transmission
facilities that address interconnection-related transmission needs
originally identified through the generator interconnection process.
This requirement applies in the existing Order No. 1000 regional
transmission planning processes. The Transmission Providers must
modify their Tariffs to include these requirements. The
interconnection-related transmission needs that Transmission
Providers must evaluate in the existing Order No. 1000 regional
transmission planning process are those for which:
(1) Transmission Providers in the transmission planning region
have identified the relevant interconnection-related transmission
need in interconnection studies in at least two interconnection
queue cycles during the preceding five years (looking back from the
effective date of the accepted tariff provisions proposed to comply
with this reform in Order No. 1920, and the later-in-time withdrawn
interconnection request occurring after the effective date of the
accepted tariff provisions);
(2) the interconnection-related Network Upgrade identified
through the generator interconnection process to meet the relevant
interconnection-related transmission need has a voltage of at least
200 kV and an estimated cost of at least $30 million;
(3) the interconnection-related Network Upgrade identified
through the generator interconnection process to meet the relevant
interconnection-related transmission need is not currently planned
to be developed because the interconnection request(s) that led to
the identification of the interconnection-related transmission need
has been withdrawn; and
(4) the Transmission Providers have not identified a different
interconnection-related Network Upgrade to meet the relevant
interconnection-related transmission need in an executed Generator
Interconnection
[[Page 49561]]
Agreement or in a Generator Interconnection Agreement that the
interconnection customer requested that the Transmission Provider
file unexecuted with the Commission.
The description of the regional transmission planning process
must include sufficient detail to enable Transmission Customers to
understand:
(i) The process for enrollment in the regional transmission
planning process;
(ii) The process for consulting with customers;
(iii) The notice procedures and anticipated frequency of
meetings;
(iv) The methodology, criteria, and processes used to develop a
transmission plan;
(v) The method of disclosure of criteria, assumptions, and data
underlying a transmission plan;
(vi) The obligations of and methods for transmission customers
to submit data;
(vii) The process for submission of data by nonincumbent
developers of transmission projects that wish to participate in the
regional transmission planning process and seek regional cost
allocation;
(viii) The process for submission of data by merchant
transmission developers that wish to participate in the regional
transmission planning process;
(ix) The dispute resolution process;
(x) The study procedures for economic upgrades to address
congestion or the integration of new resources; and
[The procedures and mechanisms for considering transmission
needs driven by Public Policy Requirements, consistent with Order
Nos. 1000; and]
(xi) The relevant cost allocation method or methods.
The regional transmission planning process must include [a ]cost
allocation methods [or methods ]that satisfy the [six regional cost
allocation principles]requirements set forth in Order Nos. 1000 and
1920.
Identifying Potential Opportunities to Right-Size Replacement
Transmission Facilities
As part of each Long-Term Regional Transmission Planning cycle,
Transmission Providers in each transmission planning region shall
evaluate whether transmission facilities operating at or above a
voltage threshold not to exceed 200 kV that an individual
Transmission Provider that owns the transmission facility
anticipates replacing in-kind with a new transmission facility
during the next 10 years can be ``right-sized'' to more efficiently
or cost-effectively address Long-Term Transmission Needs, as
discussed in Order No. 1920. The process to identify potential
opportunities to right-size replacement transmission facilities must
follow the process outlined in Order No. 1920. The Transmission
Providers in each transmission planning region shall include in
their Tariffs a cost allocation method for right-sized replacement
transmission facilities that are selected in the regional
transmission plan for purposes of cost allocation.
Interregional Transmission Coordination
The Transmission Provider, through its regional transmission
planning process, must coordinate with the public utility
transmission providers in each neighboring transmission planning
region within its interconnection to address transmission planning
coordination issues related to interregional transmission
facilities. The interregional transmission coordination procedures
must include a detailed description of the process for coordination
between public utility transmission providers in neighboring
transmission planning regions (i) with respect to each interregional
transmission facility that is proposed to be located in both
transmission planning regions and (ii) to identify possible
interregional transmission facilities that could address
transmission needs more efficiently or cost-effectively than
separate regional transmission facilities. The interregional
transmission coordination procedures shall be described in an
attachment to the Transmission Provider's Tariff.
The Transmission Provider must ensure that the following
requirements are included in any applicable interregional
transmission coordination procedures:
(1) A commitment to coordinate and share the results of each
transmission planning region's regional transmission plans
(including information regarding the Long-Term Transmission Needs
and potential transmission facilities to meet those needs) to
identify possible interregional transmission facilities that could
address transmission needs more efficiently or cost-effectively than
separate regional transmission facilities, as well as a procedure
for doing so;
(2) A formal procedure to identify and jointly evaluate
transmission facilities that are proposed to be located in both
transmission planning regions, including those that may be more
efficient or cost-effective transmission solutions to Long-Term
Transmission Needs;
(3) An agreement to exchange, at least annually, planning data
and information; and
(4) A commitment to maintain a website or email list for the
communication of information related to the coordinated planning
process, including:
(a) the Long-Term Transmission Needs discussed in the
interregional transmission coordination meetings;
(b) any interregional transmission facilities proposed or
identified in response to the Long-Term Transmission Needs;
(c) the voltage level, estimated cost, and estimated in-service
date of the interregional transmission facilities proposed or
identified as part of Long-Term Regional Transmission Planning;
(d) the results of any cost-benefit evaluation of such
interregional transmission facilities, with results including both
any overall benefits identified, as well as any benefits particular
to each transmission planning region; and
(e) the interregional transmission facilities, if any, selected
in the regional transmission plan for purposes of cost allocation to
meet Long-Term Transmission Needs.
The Transmission Provider must work with transmission providers
located in neighboring transmission planning regions to develop a
mutually agreeable method or methods for allocating between the two
transmission planning regions the costs of a new interregional
transmission facility that is located within both transmission
planning regions. Such cost allocation method or methods must
satisfy the six interregional cost allocation principles set forth
in Order No. 1000 and must be included in the Transmission
Provider's Tariff.
United States of America--Federal Energy Regulatory Commission
Building for the Future Through Electric Regional Transmission
Planning and Cost Allocation
Docket No. RM21-17-000
(Issued May 13, 2024)
PHILLIPS, Chairman, CLEMENTS, Commissioner, concurring:
1. The electric transmission grid is the backbone of the
American economy and essential to the national security of our
country. The mission of this agency is to ensure reliable, safe,
secure, and economically efficient energy for consumers at a
reasonable cost. Ensuring we have a robust, well-planned electric
transmission grid is the single most important step that this
Commission can take to fulfill that statutory mandate. It is a
reliability imperative. The transmission grid ultimately allows
consumers to have access to the electricity they need--when they
need it--to power their homes and businesses. It is equally an
affordability imperative. The transmission grid gives those same
consumers access to diverse, low-cost sources of electricity that
help ensure energy bills remain just and reasonable. All told, a
strong electric transmission grid is the foundation for how this
Commission meets its most important statutory responsibilities under
the Federal Power Act (FPA).
2. That has never been more true than it is today. We are in the
midst of a pivotal moment for the electricity system. As a nation,
we are seeing unprecedented demands on the grid from extreme
weather, increasing and rapidly changing patterns of electricity
use, and fundamental shifts in the resource mix. And there is every
reason to believe those trends will continue, and, indeed,
accelerate, in the years ahead.
3. At the same time, our transmission grid is old. More than 70
percent of the grid was built over 25 years ago and much of it was
put into service in the 1960s and 1970s, when this agency was still
the Federal Power Commission. Our country cannot meet the challenges
of today, let alone tomorrow, with yesterday's transmission system.
And being unprepared to meet those increased demands jeopardizes the
safety and security of our grid. Nevertheless, as a country, we have
so far failed to make the investments in the types of transmission
facilities needed to ensure continued reliability and affordability
at anywhere near the scale or speed needed to meet this pivotal
moment.
4. The cost of continued inaction is immeasurable. Failure to
act now would hamper the reliability and resilience of our electric
grid while leaving customers holding the bag for the inevitably more
costly upgrades in the future. Indeed, under the
[[Page 49562]]
status quo, with its de facto emphasis on the piecemeal, just-in-
time development of the grid to meet near-term reliability and
economic needs, customers are being forced to fund investments that
could have been more beneficial, less costly, or both had they been
better planned from the start. That result undermines our economy
and leaves customers less safe and secure, with enormous costs for
both our grid and our country.
5. Avoiding those costs requires a forward-looking,
comprehensive, and holistic transmission planning and cost
allocation framework. That framework must consider the diverse
challenges facing the transmission grid, identify the solutions that
will address those challenges, and ensure only customers who benefit
from those facilities pay their share of the cost, while ensuring
that customers who do not benefit do not pay. Period.
6. We must conduct this planning and cost allocation on a
regional basis and with an aperture consistent with the scope and
scale of the challenges we face. That is, after all, why Congress
enacted Title II of the FPA: To provide a coherent regional and
national regulatory regime and avoid the harms and costs that come
from a balkanized electricity system in which every state is its own
regulatory island.\1\
---------------------------------------------------------------------------
\1\ New York v. FERC, 535 U.S. 1, 6 (2002) (``When it enacted
the FPA in 1935, Congress authorized federal regulation of
electricity in areas beyond the reach of state power,'' tasking the
Commission's predecessor with ``effective federal regulation of the
expanding business of transmitting and selling electric power in
interstate commerce.'' (quoting Gulf States Utils. Co. v. F.P.C.,
411 U.S. 747, 758 (1973))); FERC v. Elec. Power Supply Ass'n, 577
U.S. 260, 265-66 (2016) (EPSA) (same); cf. First Iowa Hydro-Elec.
Co-op v. F.P.C., 328 U.S. 152, 180 (1946) (The Federal Water Power
Act of 1920 was ``a complete scheme of national regulation which
would promote the comprehensive development of the water resources
of the Nation, in so far as it was within the reach of the federal
power to do so, instead of the piecemeal, restrictive, negative
approach of the River and Harbor Acts and other federal laws
previously enacted.'').
---------------------------------------------------------------------------
7. Today's final rule does just that. We are requiring
transmission planners to plan Long-Term Regional Transmission
Facilities using the factors we know drive the transmission needs of
tomorrow and consider the reliability and affordability benefits
those facilities will provide. At the same time, we are giving
transmission planners discretion regarding whether and how to select
which transmission facilities to build, recognizing no two regions
of the country are alike and a one-size-fits-all solution simply
will not produce the infrastructure we so badly need.
8. When it comes to the critical question of ``who pays,'' we
are providing transmission planners with the maximum flexibility we
can legally allow in order to facilitate negotiated, regionally
appropriate solutions. And, as part of a multi-pronged approach to
protecting customers, we are requiring transmission planners to
reevaluate any previously selected Long-Term Regional Transmission
Facility when the actual or projected costs of that facility
significantly exceed the cost estimates used during selection.
Finally, we are also providing states with unprecedented, expanded
opportunities to work with transmission providers to shape the cost
allocation approaches of their regions, while meeting the
beneficiary pays requirement that is the foundation of cost
causation under the FPA's just and reasonable standard.
I. The Dissent's Approach Would Not Result in the Energy Infrastructure
Buildout We Need
9. Commissioner Christie provides a stark alternative vision in
his dissent, one that would violate the cost causation principle and
harm electric reliability. While we agree with his emphasis on the
importance of cooperation with states--and have created
unprecedented opportunities for such cooperation throughout this
final rule--his radical new approach would permit a state to receive
economic, resilience, and reliability benefits from new energy
infrastructure, but not be charged a single cent unless they
expressly agree to pay. That myopic view does not satisfy the
requirements of the FPA and would not adequately facilitate the
development of transmission we desperately need to ensure
reliability and affordability. Contrary to the dissent's assertion
that this final rule is the product of a political agenda, failing
to act based on the dissent's flawed reading of the circumstances
through the lens of politics would abdicate the Commission's duty.
10. The dissent's approach would necessarily require the
Commission to ignore evidence about which consumers benefit from the
increased reliability, resilience, and affordability due to grid
expansion. Instead, backbone regional transmission could not be
built unless every state unanimously opted into an agreed cost
allocation. But for the same reason that passing around a hat is no
way to fund the fire department, roads, or bridges, such an approach
to building critical, public interest infrastructure that relies
entirely on the voluntary contributions of individual states (or
could even be defeated by the refusal to contribute by a single
state) will not beget the transmission infrastructure needed to
maintain reliability and affordability.
11. Put another way, there is little reason to believe that we,
as a country, would build the infrastructure needed to power the
world's largest economy if individual states that benefit from that
infrastructure could simply decline to pay. Instead, Commissioner
Christie's approach would be far more likely to result in a failure
to make needed investments entirely, or else to down-size those
investments in a way that results in exactly the type of piecemeal
transmission development that led us to conclude existing
transmission planning practices are rendering transmission rates
unjust and unreasonable. That result would leave America far worse
off. Just as the Articles of Confederation were not a sufficient
platform to develop and sustain a national economy, so too would a
wholly voluntary approach to paying for the needed infrastructure be
inadequate to develop a transmission grid capable of powering the
world's largest economy. That alone is a reason to reject
Commissioner Christie's dissenting views.
12. In addition, the dissent's approach would result in subpar
transmission planning. Our nation needs transmission planning that
looks ahead on the decades-long timeframe that is relevant to
building backbone transmission facilities that will likely last a
half-century or more. And transmission needs can best be predicted
by considering many factors to discern their aggregate effect. Those
include economics and technology fundamentals, changing demand
patterns across customers of all types (including corporations), the
full panoply of federal, Tribal, state, and local policy
contributions, and even the changing weather patterns, which pose
increasing challenges to maintaining a reliable and resilient
electric grid. Rather than reflect that integrated reality,
Commissioner Christie's approach asks planners to isolate select
state public policies and focus on how each individually shapes the
grid. That too is a recipe for down-sizing needed infrastructure in
a way that will result in less efficient or cost-effective
investments that fail to meet this critical moment.
II. The Dissent Misrepresents the Final Rule
13. Commissioner Christie's dissent responds to a strawman of
his own making, not the final rule. And, even so, the dissent's
critique of the final rule ultimately boils down to one principal
issue: the failure of the rule (in his view) to give every state an
absolute right to veto the costs of a transmission facility, even
one from which the state's consumers would derive economic and
reliability benefits. Although we respect his perspective, we
disagree that the changes he seeks are legal--much less legally
required--or that a final rule premised on his vision would beget
the energy infrastructure needed to maintain reliability and
affordability. In any case, his statement mischaracterizes critical
aspects of the final rule, the most fundamental of which we address
below.
14. First and foremost, Commissioner Christie asserts that Long-
Term Regional Transmission Facilities are public policy projects
whose purpose is to facilitate state efforts to shape the resource
mix. He is wrong. This final rule requires transmission providers to
comprehensively consider the factors that will shape the
transmission needs of tomorrow. Although state efforts to shape the
resource mix are one of many factors transmission planners are
required to consider under this final rule, Commissioner Christie's
narrow focus on them misses the forest for a couple trees. The
requirement to consider state public policies is part of the much
broader requirement to comprehensively consider all significant
factors shaping future transmission needs, where other factors,
including the fundamental economic and reliability drivers, play a
much bigger role. That Commissioner Christie is focused
overwhelmingly on the state public policies with which he disagrees
does not mean that the same is true of Long-Term Regional
Transmission Facilities.
15. In any case, Commissioner Christie's proposal is arbitrary
and capricious in its lack of any limiting principle. Transmission
[[Page 49563]]
needs of all sorts--economic or reliability, near-term or long-
term--are shaped by all manner of state public policy choices.
Fundamental state decisions, such as tax rates, zoning and land use
laws, and almost every use of the police power more generally,
inevitably shape the supply and demand of electricity. No
transmission need is unaffected by those basic exercises of state
power, which means that no transmission need can be fairly or
accurately described as entirely divorced from the effects or
consequences of state policy decisions.
16. While taking issue with some state policy choices,
Commissioner Christie's vision contains no method for determining
which state policies must be considered and which might escape
scrutiny even though they too contribute to underlying transmission
needs. Similarly, it contains no rubric for determining how to
evaluate the cumulative effects of state public policies--such as
taxation and land use laws--that are, in many cases, far in excess
of those derived from the public policies on which he chooses to
focus. Nor does it contain any explanation for subjecting Long-Term
Regional Transmission Facilities to this suite of planning and cost
allocation requirements, but not economic and reliability projects--
which are, for the reasons noted above, inevitably at least in part
the product of public policies. That sort of unexplained, arbitrary
line drawing is exactly what the APA prohibits.\2\
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\2\ See, e.g., Prometheus Radio Project v. F.C.C., 373 F.3d 372,
390 (3rd. Cir. 2004) (explaining that when an agency has engaged in
line-drawing, ``its decisions may not be `patently unreasonable' or
run counter to the evidence before the agency'' (citations
omitted)); Sinclair Broadcast Grp., Inc. v. F.C.C., 284 F.3d 148,
162 (D.C. Cir. 2002) (explaining that lines drawn cannot be
``patently unreasonable, having no relationship to the underlying
regulatory problem'' (citing Cassell v. F.C.C., 154 F.3d 478, 485
(D.C. Cir. 1998)); Am. Trucking Assocs., Inc. v. I.C.C., 697 F.2d
1146, 1151 (D.C. Cir. 1983) (``The arbitrariness which the
[Administrative Procedure Act] proscribes is the failure to draw
reasoned distinctions where reasoned distinctions are required.'').
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17. Let us be clear: These are reliability and affordability
projects. As the final rule explains, the minimum standards we
establish provide that Long-Term Regional Transmission Facilities
are to be identified and evaluated based on their reliability and
economic benefits. To call them anything else--no matter how many
times--is a misnomer, plain and simple.
18. Similarly, Commissioner Christie's claim that states will be
forced to subsidize other states' public policy choices could not be
further from the truth. A bedrock requirement of this final rule is
that customers will only be required to pay for a share of a Long-
Term Regional Transmission Facility to the extent they benefit from
that facility. That is cost causation 101. While we provide
transmission planners, in cooperation with their state regulators,
ample flexibility to determine how to satisfy that bedrock
requirement, any cost allocation methodology that causes customers
to pay for projects from which they do not benefit--or to pay a cost
share out of proportion to the benefits they draw from the project--
would be patently unjust and unreasonable. That is black letter law
under the FPA,\3\ which we have expressly incorporated into the
requirements of this final rule.\4\
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\3\ See City of Lincoln v. FERC, 89 F.4th 926, 930 (D.C. Cir.
2024) (``The FPA's just and reasonable standard incorporates a cost-
causation principle.''); Old Dominion Elec. Coop. v. FERC, 898 F.3d
1254, 1255 (D.C. Cir. 2018) (``Under the [FPA], electric utilities
must charge just and reasonable rates. For decades, the Commission
and the courts have understood this requirement to incorporate a
cost-causation principle--the rates charged for electricity should
reflect the costs of providing it.'' (citations omitted)); see also
BNP Paribas Energy Trading GP v. FERC, 743 F.3d 264, 268 (D.C. Cir.
2014) (``[T]he cost causation principle itself manifests a kind of
equity. This is most obvious when we frame the principle (as we and
the Commission often do) as a matter of making sure that burden is
matched with benefit.'').
\4\ Bldg. for the Future Through Elec. Reg'l Transmission
Planning & Cost Allocation & Generator Interconnection, Order No.
1920, 187 FERC ] 61,068, at P 1305 & n.2786 (2024).
---------------------------------------------------------------------------
19. The dissent is equally wrong to suggest that anything less
than a unilateral right to veto cost responsibility for a regional
transmission project is unfair to states. To the contrary, both
courts and the Commission have long recognized that the just and
reasonable standard of the FPA requires that customers pay for
infrastructure they use and benefit from.\5\ The dissent's approach,
by contrast, would permit free ridership, allowing states to avoid
paying by withholding their approval, while still receiving the
substantial benefits of a more integrated, robust transmission
system. Here too, both the Commission and the courts have expressly
rejected that approach as inconsistent with cost causation.\6\
Rather than ensure fairness, the dissent's approach would create
perverse incentives, rewarding states that decline to pay for
infrastructure development that demonstrably provides reliability
and economic benefits to those states, while penalizing those who
roll up their sleeves to get those projects built. That is a recipe
for inaction, not for building the energy infrastructure we so badly
need to maintain reliability and affordability.
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\5\ Beneficiary pays is founded on a recognition, grounded in
the unbreakable laws of physics, that ``the nature of power flows
over an interconnected transmission system does not permit a public
utility transmission provider to withhold service from those who
benefit from those services but have not agreed to pay for them.''
Order No. 1000, 136 FERC ] 61,051 at P 534; see also id P 535 (``the
cost causation principle provides that costs should be allocated to
those who cause them to be incurred and those that otherwise benefit
from them''); Ill. Commerce Comm'n v. FERC, 576 F.3d 470, 476-77
(7th Cir. 2009) (ICC v. FERC I) (``All approved rates must reflect
to some degree the costs actually caused by the customer who must
pay them . . . To the extent that a utility benefits from the costs
of new facilities, it may be said to have caused a part of those
costs to be incurred, as without the expectation of its
contributions the facilities might not have been built, or might
have been delayed.'' (internal citations omitted)); K N Energy, Inc.
v. FERC, 968 F.2d 1295, 1300 (D.C. Cir. 1992) (``FERC and the courts
have added flesh to these bare statutory bones, establishing what
has become known in Commission parlance as the `cost-causation'
principle. Simply put, it has been traditionally required that all
approved rates reflect to some degree the costs actually caused by
the customer who must pay them.''); see, e.g., Sw. Power Pool, 182
FERC ] 61,141, at PP 12, 99-103 (2023).
\6\ Order No. 890, 118 FERC ] 61,119 at P 561 (``there are free
rider problems associated with new transmission investment, such
that customers who do not agree to support a particular project may
nonetheless receive substantial benefits from it''); Order No. 1000,
136 FERC ] 61,051 at P 535 (``[if] the Commission could not address
free rider problems associated with new transmission investment, [ ]
it could not ensure that rates, terms and conditions of
jurisdictional service are just and reasonable and not unduly
discriminatory''); El Paso Elec. Co. v. FERC, 76 F.4th 352, 363 (5th
Cir. 2023) (``No amount of emphasizing other competing interests
permits FERC to sacrifice the foundational principle of cost-
causation by refusing to allocate costs to those who cause the costs
to be incurred and who reap the resulting benefits.'' (citations
omitted)).
---------------------------------------------------------------------------
20. We agree with Commissioner Christie that transmission
development works best when states are key partners in the process.
That is why we take the unprecedented steps described in the final
rule to give them a central role. But partnership and collaboration
are not the same thing as giving every state the right to veto cost
responsibility for transmission projects thus allowing their
residents to reap a windfall by benefitting from transmission
facilities for which they did not pay their legally required share.
21. Commissioner Christie also asserts that the final rule
deprives states of their long-standing authority. That is
categorically false. Let us again be clear: States retain all the
same authorities over retail rates and transmission siting they held
prior to the final rule. Rather than deprive states of authority,
the final rule empowers them with unprecedented opportunities to
engage with transmission providers in developing a cost allocation
framework.
22. Commissioner Christie's objection is to the structure of the
FPA, and long-established, court-upheld Commission regulation of
regional transmission planning under Order No. 1000, not the final
rule. He objects to the transmission provider's role in deciding,
without state approval, whether to invest in a transmission project
and determine, subject to Commission oversight, which consumers must
pay for it. But that basic structure is not new to the final rule--
it is how transmission planning occurs today, consistent with the
FPA and Commission precedent, including Order No. 1000. At
Congress's direction, public utilities, not states, have the right
to propose to the Commission rates and practices affecting those
rates and we cannot deprive them of those rights.\7\ Neither states'
siting authority nor their exclusive jurisdiction over retail rates
give them the unilateral right to dictate matters subject to the
Commission's exclusive jurisdiction, such as the transmission rates
and practices affecting those rates that are the subject of this
final rule.\8\ For example, a state could reject siting
[[Page 49564]]
or other approvals for the portion of a regional transmission
project located within its jurisdiction, provided that its
determination was consistent with relevant state and federal law.
But states cannot stymie needed regional transmission projects by
simply declining to pay for them. Nor is that concept new to this
final rule. Under established economic and reliability planning,
state policies are contributing factors to needed transmission, and
states have never held a veto authority over costs for such
facilities under Order No. 1000.\9\ Nothing in this final rule
changes those basic facts.
---------------------------------------------------------------------------
\7\ 16 U.S.C. 824d; Atl. City Elec. Co. v. FERC, 295 F.3d 1, 9
(D.C. Cir. 2002) (``Section 205 of the Federal Power Act gives a
utility the right to file rates and terms for services rendered with
its assets.'').
\8\ See Order No. 1920, 187 FERC ] 61,068 at PP 253-83
(affirming Commission's legal authority to require participation in
Long-Term Regional Transmission Planning).
\9\ Indeed, Commissioner Christie recently approved, over the
objection of other states, PJM's plan to regionally allocate the
costs of transmission to address reliability concerns driven, at
least in part, by Virginia's policy to incent siting of data centers
in that state. See PJM Interconnection, L.L.C., 187 FERC ] 61,012
(2024).
---------------------------------------------------------------------------
23. What has changed is that states now, as a result of this
final rule, have an unprecedented opportunity to shape transmission
planning and cost allocation, elevating our system of cooperative
federalism with the states to a degree not previously seen in the
history of this Commission. Most significantly, we are requiring
transmission providers to host a dedicated forum for meaningful
state participation in proposing cost allocation methods and
processes. And the rule also permits a State Agreement Process for
allocating the costs of all, or a subset of, Long-Term Transmission
Facilities. Beyond cost allocation, states will have an opportunity
to provide input on how to account for specific factors in Long-Term
Scenarios, and states can provide information on how their own
policies and planning affect Long-Term Transmission Needs. The rule
also requires transmission providers to consult with and seek the
support of states regarding how Long-Term Regional Transmission
Facilities are evaluated and selected. We expect that where states
come together to articulate workable, legal frameworks for planning
and paying for needed infrastructure, their transmission providers
will listen.
24. Indeed, under the State Agreement Process provided in the
final rule, states very well could agree to, and transmission
planners could adopt, a version of Commissioner Christie's preferred
cost allocation approach.\10\ So long as those expected to use the
Long-Term Regional Transmission Facilities pay a share of the cost
that is roughly commensurate with the benefits they will receive,
nothing in this final rule prohibits states in a transmission
planning region from adopting Commissioner Christie's preferred
approach for funding the transmission facilities they need to ensure
reliability and affordability.
---------------------------------------------------------------------------
\10\ We find Commissioner Christie's contention that the final
rule would end PJM's use of its existing State Agreement Approach,
and MISO and SPP's respective regional state committees, puzzling.
Order No. 1920, 187 FERC ] 61,068 (2024) (Christie, Comm'r,
dissenting, at P 11). The final rule enhances states' role and
relaxes certain Order No. 1000 requirements for state-approved cost
allocations. It is inexplicable that these additional flexibilities
would result in transmission providers rolling back opportunities
for state engagement in existing Order No. 1000 processes, where
that is the opposite of the thrust of the final rule. Moreover,
PJM's State Agreement Approach was approved outside of compliance
with Order No. 1000 and has never served as PJM's exclusive ex ante
cost allocation method, as Commissioner Christie suggests.
---------------------------------------------------------------------------
25. Commissioner Christie also asserts that this final rule
breaks with Order No. 1000 by mandating outcomes rather than
regulating transmission planning processes. Here, too, he is wrong.
The rule is clear that no transmission provider is required to
select any particular project.\11\ Instead, just as in Order No.
1000, the obligation on the transmission provider is to plan for the
world as we expect it to be and then make its own business decisions
after having conducted that planning process. The final rule's
minimum planning standards do not un-do that core discretion.
Requiring planning to be based upon documented drivers of
transmission needs and to incorporate objective measures of how
potential investments pay off improves the planning process, it does
not mandate any particular outcome.\12\ In short, in recasting the
rule to fit his narrative, Commissioner Christie conveniently
ignores one of its core elements: that it imposes no obligation to
develop any regional transmission project.
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\11\ Order No. 1920, 187 FERC ] 61,068 at P 1026 (``The
Commission did not propose in the NOPR, and we will not require in
this final rule, that transmission providers select any particular
Long-Term Regional Transmission Facility--even where a particular
transmission facility meets the transmission providers' selection
criteria in their OATTs.'').
\12\ Id. (``In other words, as in Order No. 1000, our focus is
on ensuring that regional transmission planning processes result in
just and reasonable rates, and not on requiring that these processes
achieve any particular substantive outcome.'').
---------------------------------------------------------------------------
26. Finally, Commissioner Christie is also incorrect in arguing
that this final rule violates the Major Questions Doctrine. He
asserts two bases for that argument, neither of which hold water.
27. First, he contends that our intention in issuing this final
rule is to elicit trillions in spending on transmission. As an
initial matter, the goal of this final rule is to facilitate the
development of transmission infrastructure needed to maintain
reliability and affordability. That is the case no matter how many
times or in how many ways Commissioner Christie purports to ascribe
our `true' intentions. In any case, his trillion-dollar estimates
are nothing more than a sleight of hand that is unsupported by the
record before us. To support his claim that this final rule will
cause ``literally trillions'' in transmission investment, he cites
to one academic study and one news article stating that in order to
achieve a ``net-zero'' emissions level by 2050, trillions will need
to be spent on transmission.\13\ Putting aside whether that figure
is accurate and whether ``net zero'' is an appropriate policy goal
for the country--a question which we agree is not for this
Commission to resolve--it is an astounding logical leap to say that
because certain individuals believe a certain amount of investment
is necessary to achieve a certain policy goal, that this rule will
necessary cause customers to spend that amount of money. In any
case, as the dissent points out, significant investments in
transmission are already being made by public utilities around the
country regardless of anything we do--or do not do--here today. This
final rule regulates the process by which those investments are
identified, evaluated and, where appropriate, selected in order to
help ensure that they reflect the most efficient and cost-effective
options available. That is what the Commission has been doing for
decades; the fact that transmission has become a more politically
salient topic does not transform our longstanding practice into a
major question.
---------------------------------------------------------------------------
\13\ Id. (Christie, Comm'r, dissenting at P 3 & n.7.
---------------------------------------------------------------------------
28. Second, he contends that our statement that the Commission
has exclusive jurisdiction over the transmission planning practices
that directly affect wholesale rates means that this Commission has
crossed the major questions Rubicon. But it was the courts, not this
Commission, that took that step. As he observes in his dissent,
South Carolina concluded that the transmission planning practices
regulated by Order No. 1000--which are the same practices addressed
by this final rule--were practices that directly affected wholesale
rates and thus fall squarely within the Commission's
jurisdiction.\14\ And as the courts have explained, where a practice
meets that directly affecting standard, it falls within the
Commission's exclusive jurisdiction.\15\ This long-settled law in no
way alters or dilutes the significant and critical role for states
to play under their jurisdiction and, as noted above, we have
significantly expanded that role in this final rule. Rather it means
that the specific practices in the tariffs on file with this
Commission, as required by this final rule, are within the
Commission's exclusive jurisdiction, not that of the states. The
final rule's recitation of black letter law hardly runs afoul of the
major questions doctrine.
---------------------------------------------------------------------------
\14\ In South Carolina, it was undisputed that transmission
planning generally was a practice that directly affected wholesale
rates, but the court further held that the absence of regional
transmission planning was itself such a practice. S.C. Pub. Serv.
Auth. v. FERC, 762 F.3d 41, 56-59 (D.C. Cir. 2014).
\15\ See, e.g., Nat'l Ass'n of Regul. Util. Comm'rs v. FERC, 964
F.3d 1177, 1181 (D.C. Cir. 2020) (``Congress g[ave] the Federal
Energy Regulatory Commission . . . exclusive authority over the
regulation of the sale of electric energy at wholesale in interstate
commerce, including both wholesale electricity rates and any rule or
practice affecting such rates.'' (cleaned up)).
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III. We Encourage Transmission Providers To Facilitate Joint Ownership
Structures
29. Finally, we would be remiss not to mention one policy
priority that is not finalized in this rule: The creation of a
federal right of first refusal for certain transmission facilities
developed through a joint ownership structure. As the final rule
explains, we find that proposal is better considered as part of our
generic proceeding on Transmission Planning and Cost Management,
where it can be evaluated
[[Page 49565]]
alongside other proposals for ensuring that transmission facilities
are developed as efficiently and cost-effectively as possible.\16\
---------------------------------------------------------------------------
\16\ Order No. 1920, 187 FERC ] 61,068 at PP 1563-64 & n.3346.
---------------------------------------------------------------------------
30. Nevertheless, we underscore that our decision today should
not be construed as a lack of support for the concept of joint
ownership or the potential for a federal ROFR to effectively
encourage its use. Indeed, joint ownership structures that partner
transmission owners with other load-serving entities in their
footprint, such as public power or non-profit cooperatives, can
provide many benefits and should be encouraged.
31. In these arrangements, the load-serving entity partner's
participation can reduce costs for customers in the footprint. Such
joint ownership structures bring together diverse parties, allowing
the participating entities to better allocate risks and
responsibilities, capture efficiencies, and promote innovation, all
to customers' ultimate benefit.\17\ Moreover, by bringing a wider
range of entities into the transmission development fold, joint
ownership can leverage additional sources of capital, including
those that do not typically invest in transmission facilities, which
can itself have significant benefits for customers.\18\
---------------------------------------------------------------------------
\17\ See, e.g., TAPS Initial Comments at 33-34 (``As explained
in the TAPS 2021 White Paper, inclusive joint transmission ownership
arrangements--whether structured as an inclusive transco, a shared
system, or joint ownership of new transmission facilities--result in
collaborative and inclusive planning, development, and siting of
transmission, and have proven highly effective in getting
transmission built to meet the needs of all LSEs.'' (citing TAPS,
Inclusive Joint Transmission Ownership Arrangements: An Effective
Means to Site and Build Transmission Need to Support Our Changing
Resource Mix (June 2021), https://www.tapsgroup.org/wp-content/uploads/2021/09/TAPS-Inclusive-Joint-Ownership-White-Paper.pdf));
see also Rob Gramlich et al., Grid Strategies, Fostering
Collaboration Would Help Build Needed Transmission, at 11-30 (Feb.
2024) (attached to WIRES Supplemental Comments) (highlighting
specific examples of large regional transmission projects that
resulted from diverse partnerships, including with public power
entities and cooperatives, and which met many transmission needs and
produced a wide range of benefits).
\18\ See, e.g., APPA Initial Comments, attach. at 4-10
(Declaration of James Pardikes) (listing advantages in equity ratio,
debt cost, and income tax expense, and opportunities for risk
diversification as potential benefits of joint ownership
arrangements with public power utilities); NRECA Reply Comments at
15-16; Citizens Energy Reply Comments at 2-4 (describing how its
unique joint ownership business model enables Citizens to provide
direct support to low-income ratepayers and disadvantaged
communities, addresses multiple concerns that arise in transmission
development, and advances multiple Commission policy goals).
---------------------------------------------------------------------------
32. For example, TAPS highlights specific instances of joint
ownership arrangements with tax-exempt public power entities
providing significant savings to customers.\19\ TAPS and APPA
estimate these kinds of joint ownership arrangements can typically
yield a ``more than a 5% annual cost reduction in ratepayer-funded
return and associated tax costs,'' which could produce billions of
dollars in savings when applied to reasonable transmission
investment forecasts.\20\ Relatedly, NRECA highlights examples of
joint ownership arrangements with electric cooperatives yielding
reliability and efficiency benefits, including, among others,
leveraging electric cooperative's ability to provide increased
operations and maintenance support and access to lower cost
financing through the Rural Utilities Service.\21\
---------------------------------------------------------------------------
\19\ TAPS Initial Comments at 45 (examining savings across
Vermont Transco, ATCLLC, Fargo Project, and SE Missouri Project).
\20\ TAPS Initial Comments at 45-46 & nn.133-135; APPA Reply
Comments at 4.
\21\ GDS Assocs., National Rural Electric Cooperative
Association, at 25-27 (Aug. 17, 2021) (attached to NRECA Initial
Comments).
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33. In light of those substantial benefits, we clarify that
nothing in this final rule should be interpreted to prohibit or
impair joint ownership arrangements. To the contrary, we encourage
transmission providers, in compliance with this rule and elsewhere,
to find ways to encourage these arrangements. For example, in
compliance with this rule, transmission planners could use joint
ownership as a factor to be considered in evaluating and selecting
the more efficient or cost-effective solution to meet a long-term
transmission need. Similarly, we note that the developers of a
jointly owned transmission facility can consider seeking
transmission incentives under section 205 of the FPA that reflect
the risks and challenges associated with developing such
facilities.\22\ In addition, the Commission will continue to
evaluate other potential actions to incentivize joint ownership,
including considering in the Commission's cost management proceeding
whether to provide a right of first refusal or other mechanisms to
encourage its use.
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\22\ See Promoting Transmission Investment Through Pricing
Reform, 141 FERC ] 61,129, at P 24 (2012) (``The Commission
encourages incentives applicants to participate in joint ownership
arrangements and agrees with commenters to the NOI that such
arrangements can be beneficial by diversifying financial risk across
multiple owners and minimizing siting risks.''); Promoting
Transmission Investment Through Pricing Reform, Order No. 679, 116
FERC 61,057, at P 354 (2006) (``[T]o the extent our jurisdiction
allows, the Commission will entertain appropriate requests for
incentive ratemaking for investment in new transmission projects
when public power participates with jurisdictional entities as part
of a proposal for incentives for a particular joint project.
Encouraging public power participation in such projects is
consistent with the goals of section 219 by encouraging a deep pool
of participants.'').
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* * * * *
34. Our electric transmission grid is at a crossroads. Our
nation is facing down an extended period of unprecedented change in
demand, supply, and the myriad other factors that fundamentally
shape our energy needs. And we do so with a network of transmission
infrastructure that was overwhelmingly built in the last century and
in the face of a very different reality.
35. We have a choice: We can take consequential action to build
the infrastructure needed to ensure reliability and affordability.
Or we can pursue half-measures, which may help on the margins, but
will ultimately leave us lacking the infrastructure we need to keep
the lights on at a price that customers can afford. With this final
rule, we emphatically choose the former path.
36. But we are not going down this road alone. As discussed
above, we have opened the door for our state partners to play a
leading role in shaping the next generation of energy
infrastructure. We urge them to walk through it and deploy their
unique perspectives as regulators and siting authorities of electric
infrastructure to develop regionally tailored solutions. Together,
we can forge a process that will serve customers for generations to
come. This is the moment to step up, to develop both processes and
physical infrastructure to withstand the changes and challenges
ahead. This is the moment to build an electric transmission grid for
the 21st century.
For these reasons, we respectfully concur.
-----------------------------------------------------------------------
Willie L. Phillips
Chairman
-----------------------------------------------------------------------
Allison Clements
Commissioner
United States of America--Federal Energy Regulatory Commission
Building for the Future Through Electric Regional Transmission
Planning and Cost Allocation
Docket No. RM21-17-000
(Issued May 13, 2024)
CHRISTIE, Commissioner, dissenting:
I. The Final Rule Is a Pretext for Enacting a Sweeping Policy Agenda
Never Passed by Congress, Denies the States the Authority Promised by
the NOPR, and Fails the Commission's Consumer Protection Duty Under the
Federal Power Act
1. The Federal Power Act (FPA) is, at its core, a consumer
protection statute.\1\ In FPA section 206, which today's final rule
purports to be based on, Congress explicitly directed this
Commission to protect consumers from public utility ``rates'' that
are ``unjust, unreasonable, unduly discriminatory or preferential.''
\2\ This final rule, however, fails
[[Page 49566]]
to fulfill the Commission's consumer protection duty required by the
statute. The final rule should be seen for what it is: a pretext to
enact, through administrative action, a sweeping legislative and
policy agenda that Congress never passed.\3\ The final rule claims
statutory authority the Commission does not have to issue an
absurdly complex bureaucratic blizzard of mandates and
micromanagement \4\ to be imposed on every transmission provider in
the United States for the transparent goal of spending trillions of
consumers' dollars on transmission not to serve consumers in
accordance with the FPA, but instead to serve political, corporate,
and other special-interest agendas that were never enacted into
law.\5\ The rates for transmission that will result from the final
rule will not only be unjust, unreasonable, unduly discriminatory
and preferential, but grossly unfair to tens of millions of American
consumers already burdened with rapidly growing monthly power bills.
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\1\ E.g., Towns of Alexandria, Minn. v. FPC, 555 F.2d 1020, 1028
(D.C. Cir. 1977) (explaining that the FPA's `` `primary aim is the
protection of consumers from excessive rates and charges' '')
(quoting Mun. Light Bds. v. FPC, 450 F.2d 1341, 1348 (D.C. Cir.
1971)); see also Elec. Dist. No. 1 v. FERC, 774 F.2d 490, 492 (D.C.
Cir. 1985) (recognizing that the benefits of rate predictability,
which are the ``whole purpose'' of the filed rate doctrine, ought to
be considered in light of the FPA's ``primary purpose of protecting
the utility's customers'').
\2\ 16 U.S.C. 824e. Under the FPA, the Commission is a regulator
of wholesale public utility rates, not a national integrated
resource planner (known in the lingo as an ``IRP'') of generation
and/or transmission. See, e.g., Entergy Nuclear Vt. Yankee, LLC v.
Shumlin, 733 F.3d 393, 417 (2d Cir. 2013) (quoting S. Cal. Edison
Co. San Diego Gas & Elec. Co., 71 FERC ] 61,269, at 62,080 (1995)
(``[S]tates have broad powers under state law to direct the planning
and resource decisions of utilities under their jurisdiction. States
may, for example, order utilities to build renewable generators
themselves, or . . . order utilities to purchase renewable
generation.''). Further, FPA section 215, pertaining to electric
reliability, explicitly leaves the construction of generation and
transmission assets to state regulatory authority. 16 U.S.C.
824o(i)(2). Section 215 makes clear congressional intent to leave
integrated resource planning to the states. Indeed, the overall
statutory framework of the FPA--consistent with America's federal
constitutional structure--makes it clear that states are the primary
regulators of which utility assets get planned and built, both
generation and transmission, not FERC.
\3\ See, e.g., W. Va. v. EPA, 597 U.S. 697 (2022) (West Virginia
v. EPA); Dept. of Commerce v. N.Y., 139 S. Ct. 2551 (2019).
\4\ In truly Kafkaesque fashion, the final rule is a doorstopper
weighing in at just below 1300 pages, likely one of the longest,
most complicated, and confusing orders the Commission has ever
issued. Regulated entities--it applies to all public utility
transmission providers in the United States, RTO and non-RTO--will
need weeks just to read through it, much less decipher it, and then
months of figuring out how to comply. Its very complexity raises the
prospect of multiple rounds of compliance filings, no doubt
punctuated by multiple deficiency letters, in order to push the
transmission provider towards the outcomes the Commission wants to
achieve. The final rule's very complexity renders it, if not
arbitrary and capricious on its face, likely to be arbitrary and
capricious in its enforcement.
\5\ See, e.g., Heather Richards, Zach Bright, Christian Robles,
3 energy issues to watch this spring at DOE, Interior and FERC,
Energywire, Mar. 18, 2024 (``FERC has promised a closely watched
rule this spring on transmission that could be key to President Joe
Biden's ambitious aim to decarbonize the electricity grid by 2035 .
. . . `The sooner we get a final rule, the better. . .,' said
Caitlin Marquis [of] Advanced Energy United, a pro-clean-energy
group . . . . [T]he Biden administration is in a race . . . until
roughly midyear to finalize rules before they are subject to the
Congressional Review Act (CRA) . . . . The Biden administration has
said [today's final rule] will facilitate a build-out of
interregional lines and grid interconnections needed to . . . allow
more wind and solar power to come online . . . .'') (emphases added)
https://www.eenews.net/articles/3-energy-issues-to-watch-this-spring-at-doe-interior-and-ferc/; see also Peter Behr, EPA power
plant rule targets coal. Does that spell trouble for the grid?
Climatewire, May 3, 2024 (``But climate activists will not give up
the `zero by 2035' goal without a fight. President Biden made that
steep commitment at a critical point in his 2020 candidacy to win
the support of primary rival Sen. Bernie Sanders (I-Vt.) and his
climate action activists . . . . [T]he hard road to a zero-carbon
grid in 2035 is real precisely because the Biden administration has
pursued it . . . . [Study authors] highlighted estimates that the
rate of high-voltage transmission line construction must double to
deliver the necessary new wind and solar energy . . . . The [Biden]
administration . . . is putting a strategy for big new lines in
place. FERC, with the support of Biden appointees, is preparing new
policy to support big wires projects . . . . `You can't get around
the fact that you're going to need tens of thousands of miles of new
transmission lines if you want to build the hundreds of gigawatts of
wind and solar and batteries that many of us predict are needed to
achieve decarbonization goals,' said [former Obama energy secretary
Ernest] Moniz.'') (emphases added), https://www.eenews.net/articles/epa-power-plant-rule-targets-coal-does-that-spell-trouble-for-the-grid-2/; see also Zach Bright, FERC sets date for landmark
transmission rule, Energywire, Apr. 19, 2024 (``FERC said it plans
to hold a special May 13 meeting to consider its . . . transmission
planning and cost-allocation proposal that's been a focus of
[lobbying] for expanding the grid to . . . move more renewable
energy . . . . The Biden administration's goal of [net zero] by 2035
hinges on expanding the transmission system by two-thirds, the
Energy Department said last year.'') (emphases added), https://www.eenews.net/articles/ferc-sets-date-for-landmark-transmission-rule/; It's raining rules: Why the Biden administration is rushing
to produce regulations, The Economist, May 4, 2024, at 19 (``More
regulations, big and small, are expected soon. The Federal Energy
Regulatory Commission is planning to rewrite the rules governing
interstate electricity transmission, which is critical to President
Joe Biden's decarbonisation plans . . . . Why the sudden spate? A
previously obscure law, the [CRA], helps explain the rush. It allows
Congress, for a limited period, to pass resolutions of disapproval
against finalised administrative regulations with which it
disagrees. If both chambers of Congress pass such a resolution, and
the president signs it, the rule is cancelled, short-circuiting the
usual drawn-out process of litigation or a subsequent administration
beginning a whole new rule-making effort. So once a regulation is
properly created the clock starts ticking: the cancellation
procedure is allowed for up to 60 days that the Senate is in
session--including the last 60 days of an administration that loses
a presidential election.'') (emphasis added), https://www.economist.com/united-states/2024/05/02/why-the-biden-administration-is-rushing-to-produce-regulations; see infra nn.8,
10, 13, 15, 16, 67.
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2. The fundamental principle historically embedded in utility
regulation in the United States is to provide consumers with
reliable power at the least cost under applicable law. This
principle is fair and compelling because the vast majority of
American utility consumers are captive customers who pay a monopoly
utility for a vital public service--electrical power--which no one
can live without in modern society. Transmission is an essential
component of this vital public service,\6\ so necessary transmission
must be built.
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\6\ The transmission component of utility service has typically
been provided by the incumbent monopoly utility at the load-serving
local level, and local transmission planning and/or construction is
generally subject to state-regulated IRP or permitting processes,
especially in non-RTO regions. The final rule imposes numerous
additional requirements for local transmission planning, including
even micromanaging how local ``stakeholder'' meetings are supposed
to be conducted, which may conflict with state IRP proceedings and
represent yet another FERC encroachment into areas of traditional
state authority. See Bldg. for the Future Through Elec. Reg'l
Transmission Planning & Cost Allocation & Generator Interconnection,
Order No. 1920, 187 FERC ] 61,068, at Section IX.B.3.a (2024) (Final
Rule). It is highly doubtful that the micromanagement of stakeholder
meetings in local planning would pass judicial review under CAISO v.
FERC, in which FERC's attempted micromanagement of an ISO's
governing board appointments was rejected as not sufficiently
grounded in FERC's rate-setting authority under the FPA. See Cal.
Indep. Sys. Operator Corp. v. FERC, 372 F.3d 395, 400 (D.C. Cir
2004) (CAISO v. FERC).
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3. Today's final rule, however, is not about providing reliable
power to consumers at least cost through just and reasonable rates
as required by the FPA, despite the final rule's claim. And it is
certainly not about being fair. On the contrary, the final rule
inflicts staggering costs on consumers by promoting the construction
of trillions of dollars of transmission projects,\7\ not to serve
consumers in accordance with the FPA, but to serve a major policy
agenda never passed by Congress, to serve the profit-making
interests of developers of politically preferred generation,
primarily wind and solar, and to serve corporate ``green energy''
preferential purchasing policies.\8\ As such, the final rule
[[Page 49567]]
does not deserve a shred of deference under Chevron U.S.A., Inc. v.
Natural Resources Defense Council, Inc.\9\ in any form. Today's
final rule is much less the product of reasoned decision-making or
the agency's specialized expertise, as of political pressure and
special interest lobbying.\10\ In the chapter on ``regulatory
capture'' \11\ in future economics textbooks, today's final rule
should be a featured case study.
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\7\ The Princeton Net Zero study is often cited, but it is only
one of many estimates of the trillions of dollars in additional
costs to be imposed on consumers. Using the Princeton study, the
cost estimates of the transmission buildout necessary to achieve
``net zero'' range across different scenarios, with one scenario
calling for transmission capacity to quintuple (5x) between 2020 and
2050, which is predicted to cost $3.56 trillion. See Princeton
University Net Zero America Final Report Summary, Slide 29, https://netzeroamerica.princeton.edu/img/Princeton%20NZA%20FINAL%20REPORT%20SUMMARY%20(29Oct2021).pdf. I
would emphasize that the sticker price of a utility asset is only a
fraction of the ultimate cost to consumers, because the ``going in''
price will increase by a multiple of many times the original cost
over the life of the asset, because the cost of capital, both a
profit to the utility (known as Return on Equity, or ROE) and the
cost of debt, will be paid by consumers. So, if Princeton gives an
estimate of $3.56 trillion for new utility assets needed to reach
the ``net zero'' goal, the actual cost to consumers over the life of
the assets will be many times more than that estimate. See also
Diana DiGangi, U.S. won't reach net zero emissions without
transmission buildout: DNV, Utility Dive, Sept. 25, 2023 (``$12
trillion will be spent on clean energy in North America by 2050 . .
. to meet . . . net zero emissions targets . . . . Some of the
biggest barriers to net zero in the U.S. include the lack of
transmission buildout . . . .) (emphases added), https://www.utilitydive.com/news/net-zero-transition-clean-energy-north-america-transmission-buildout/694621/.
\8\ See, e.g., Peter Behr, DOE unveils critical grid corridors
for Biden climate goals, Energywire, May 8, 2024 (`` `To meet our
climate goals we have to more than double our transmission
capacity,' said top White House clean energy adviser John Podesta,
who has led a Cabinet-level push to get long-delayed transmission
projects under construction.'') (emphasis added), https://www.eenews.net/articles/doe-unveils-critical-grid-corridors-for-biden-climate-goals/; Peter Behr, More, More, More: Biden's clean
grid hinges on power lines, Energywire, May 23, 2022 (stating that
``the Biden administration is seeking an unprecedented expansion of
high-voltage electric lines to open new paths to wind and solar
energy. `We obviously need more, more, more transmission to run on
100 percent clean energy . . .,' Energy Secretary Jennifer Granholm
said in February.'') (emphasis added), https://subscriber.politicopro.com/article/eenews/2022/05/23/more-more-more-bidens-clean-grid-hinges-on-power-lines-00030117; see also supra n.5
and infra nn.10, 13, 15, 16, 67.
\9\ 467 U.S. 837 (1984) (Chevron).
\10\ See Catherine Morehouse, FERC to tackle ``historic''
transmission planning rule in May, PoliticoPRO, Apr. 18, 2024
(``FERC has been under enormous pressure from lawmakers, clean
energy developers, environmentalists and others to finalize the rule
that Chair Willie Phillips has promised will be `historic' and the
`greatest development regarding electric transmission rules in the
country in over a generation.' '') (emphases added), https://subscriber.politicopro.com/article/2024/04/ferc-to-tackle-massive-transmission-planning-rule-next-month-00153191; see also, e.g., Sen.
Charles E. Schumer July 24, 2023 Comments at 1-2 (urging the
Commission to ensure that ``any final rule must . . . prescribe a
set of benefits'' to be used in transmission planning and that ``it
will be necessary that either'' [the transmission provider, or FERC
shall impose cost allocation] ``when any state withholds support on
a cost allocation method'' [which risks] ``states that benefit from
a transmission line'' [acting as] ``free riders [to] avoid any
costs.'') (emphases added); Sen. Martin Heinrich, et al. (consisting
of 20 additional Senators) Jan. 19, 2024 Comments at 2 (urging the
Commission that ``the final rule must require consideration of a . .
. specific set of transmission benefits for . . . cost allocation
processes'') (emphases added); Sen. Sheldon Whitehouse Nov. 7, 2023
Comments at 2 (stating that ``FERC should include [a list of
required benefits] in its final rule''). As explained extensively
herein, mandating benefits is a device for imposing costs on
consumers in states that never agreed to the selection criteria or
cost allocation. The deeply granular nature of the instructions to
the Commission in these letters is more evidence that this final
rule is a pretext to use an administrative agency to enact
legislation that Congress never passed. See also supra nn.5, 8 and
infra nn.13, 15, 16, 67.
\11\ Luigi Zingales, Preventing Economists' Capture, University
of Chicago Booth School of Business Review, July 1, 2014 (``In
simple words, regulatory capture exists when a regulatory agency,
created to act in the public interest, ends up advancing interests
of the industry it is charged with regulating.''), https://www.chicagobooth.edu/review/preventing-economists-capture.
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4. The final rule orders all transmission providers, RTO and
non-RTO, to plan costly regional transmission for some allegedly
predictable generation mix 20 years in the future (a generation mix
which, as a practical matter, is impossible to predict so far into
the future).\12\ The obviously pretextual agenda of the final rule,
however, is not to predict the generation mix 20 years forward, but
to produce the preferred generation mix that the current
presidential administration, some huge multinational
corporations,\13\ some members of Congress, and other special
interests want now. In fact, the final rule is not even about
planning transmission, but is about planning policy, and it is very
preferential about the policies it wants to promote. As with the
Great Oz,\14\ pulling back the curtain exposes the final rule for
what it really is: An essential component in a comprehensive plan by
the current presidential administration to push what the media
describe as ``green policies'' designed to prefer and promote the
wind and solar generation it favors while simultaneously forcing the
shutdown of the fossil fuel generation it disfavors,\15\ both needed
to meet its political commitment. Let me emphasize: Whether the
policies being promoted in this final rule can be described as
``green, purple, red or blue'' is irrelevant. The point is that
FERC, as an independent agency, has no business promoting the
policies of any one party or presidential administration, especially
when, as here, the effort to do so goes far beyond FERC's legal
authority and fails to perform our consumer protection function
under the FPA.
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\12\ The example of the Potomac-Appalachian Transmission
Highline (PATH) fiasco is a strong warning about the folly of
spending billions of consumers' dollars to build transmission based
on predictions of a generation mix in 20 years. Potomac-Appalachian
Transmission Highline, LLC, 185 FERC ] 61,198 (2023) (Christie,
Comm'r, concurring at P 3) (PATH Concurrence) (``[C]onsumers have
paid roughly $250 million for a project that was never built nor
found needed by a single state regulator.'') (emphasis in original),
https://www.ferc.gov/news-events/news/e-4-commissioner-christies-concurrence-letter-order-approving-path-settlement-er12; see also
PJM Initial Comments at 62 (``In short, the volatility of input
parameters cancelled the need for a $1.8 billion transmission line
identified in 2007, that was confirmed to be needed five years out
in 2012, but by 2012 was no longer needed for at least another 15
years, if at all.''). Rather than wind or solar--which the final
rule implicitly presumes will be the predominant generating resource
in 20 years--it is just as foreseeable that the predominant share of
generation in the U.S. could be nuclear, an essential dispatchable
resource, as small modular reactor technology matures and economies
of scale produce lower costs, or it could be green hydrogen. It
could even be fusion or some new technology currently either nascent
or unknown. No one knows today. Building trillions of dollars of
transmission on a prediction that intermittent wind and solar will
be the predominant generating resource in 20 years is just a costly
guess.
\13\ See, e.g., Clean Energy Buyers Jan. 22, 2024 Comments
(``Many of our businesses cannot grow without more clean generation
resources . . . . States may miss out on economic growth
opportunities without . . . access to the types of generation
resources needed to attract growing and innovative industries.'')
(emphases added). Among the signers of these comments were Amazon,
Apple, eBay, Google, Green Impact Technologies, Meta, Microsoft,
Nike, Rivian, Salesforce, Target, Walmart and several other
multinational corporations. The FPA gives FERC no authority
whatsoever to use the ``green energy'' purchasing preferences of
privately owned, for-profit multinational corporations as the basis
to impose a mandatory transmission planning and cost allocation rule
that will cost consumers trillions of dollars. The FPA does not
recognize such corporate preferences; indeed, the FPA forbids
preferences. See also supra nn.5, 8, 10 and infra nn.15, 16, 67.
\14\ The Wizard of Oz (Metro-Goldwyn-Mayer 1939).
\15\ See, e.g., Catherine Morehouse, DOE launches effort to cut
federal permitting for new power lines in half, PoliticoPRO, Apr.
25, 2024 (``The [U.S. Dept. of Energy] program is the latest move by
the Biden administration to speed up the . . . process for new
transmission lines deemed critical to carrying dispersed wind and
solar resources . . . . It also comes on the heels of an
announcement from the EPA to tighten emissions standards for fossil-
fueled power plants--a move that will necessitate bringing more low-
carbon resources onto the power grid to meet growing demand as
[fossil fuel] resources are forced offline. `DOE's work complements
what our partners across the administration are doing . . . to
deliver cleaner power . . . ,' Energy Secretary Jennifer Granholm
told reporters . . . .'') (emphases added), https://subscriber.politicopro.com/article/2024/04/doe-launches-effort-to-cut-federal-permitting-for-new-power-lines-in-half-00154189; see
also Catherine Morehouse, Energy regulator's exit may flummox
Biden's green plans, Politico, Feb. 9, 2024 (``[FERC] is poised to
lose its biggest climate advocate and potentially shut down one of
the White House's best avenues to push its green policies. . . .
That buildout is needed to accommodate . . . wind and solar projects
that are critical to meeting the Biden administration's climate and
clean energy goals.'') (emphases added), https://subscriber.politicopro.com/article/2024/02/energy-regulators-exit-may-flummox-bidens-green-plans-00140774; Molly Christian, US
transmission ``in desperate need of an upgrade,'' Vice President
Harris says, Megawatt Daily, Jan. 20, 2023 (``Achieving lofty US
climate goals will require `thousands of miles of new high-voltage
transmission lines all across our country,' US Vice President Kamala
Harris said . . . . `To create our clean energy future, we must
construct thousands of miles of new high-voltage transmission lines
all across our country,' [Harris said].'') (emphases added), https://www.spglobal.com/commodityinsights/en/market-insights/latest-news/electric-power/012023-us-transmission-in-desperate-need-of-an-upgrade-vice-president-harris-says; Alex Guill[eacute]n, Ben
Lefebvre, Annie Snider, Kelsey Tamborrino, Catherine Morehouse,
James Bikales, Biden administration eyes spring to finalize key
climate regulations, PoliticoPro, Dec. 6, 2023 (``The Biden
administration is planning to finalize several major energy and
environmental regulations in the first half of 2024 . . . . That
timeframe would help cement many of President Joe Biden's policy
priorities in the event he does not win reelection . . . . One of
the top [FERC] priorities . . . has been to finalize a rule on power
line planning and cost allocation . . . . that is considered
critical to unlocking new wind and solar resources.'') (emphases
added), https://subscriber.politicopro.com/article/2023/12/biden-administration-plots-busy-spring-finalizing-key-climate-regulations-00130496. See also supra nn.5, 8, 10, 13 and infra nn.16, 67.
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5. Yet here's the legal rub with the final rule's pretextual
agenda: Congress never voted to amend the FPA to direct or even
allow FERC (which is supposed to be independent) to be what Energy
Secretary Granholm describes as one of ``our partners across the
administration'' in implementing this ``green energy''
transformation agenda.\16\ Such a sweeping policy agenda, which
involves the transfer of literally trillions of dollars of wealth
from consumers to special interests, is the epitome of a major
question
[[Page 49568]]
of public policy under West Virginia v. EPA. The final rule clearly
intends to socialize trillions of dollars of costs for the
transmission necessary to pursue this transformational agenda, and
unlike the NOPR,\17\ the final rule removes the principle that the
states must consent to how and whether these massive costs are
imposed on their consumers. The final rule goes to great lengths to
use ``nothing to see here'' rhetoric,\18\ but looking behind the
curtain at what is really going on makes it obvious that the final
rule is pretextual and a blatant violation of the major questions
doctrine.\19\ In its transparent effort to plan and fund trillions
of dollars' worth of transmission to facilitate a preferred
generation mix predominantly of wind and solar, both for public
policies as well as corporate purchasing preferences, it is also
``preferential'' and thus a clear violation of FPA section 206.
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\16\ See Brad Plumer, Energy Dept. Aims to Speed Up Permits for
Power Lines, The New York Times, Apr. 25, 2024 (``[Biden]
Administration officials are increasingly worried that their plans
to fight climate change could falter unless the nation can quickly
add vast amounts of grid capacity to handle more wind and solar
power . . . . But experts say a rapid, large-scale expansion may
ultimately depend on Congress.'') (emphases added), https://www.nytimes.com/2024/04/25/climate/energy-dept-speed-transmission.html. See also supra nn.5, 8, 10, 13, 15 and infra
n.67.
\17\ Bldg. for the Future Through Elec. Reg'l Transmission
Planning & Cost Allocation & Generator Interconnection, Notice of
Proposed Rulemaking, 87 FR 26504 (May 4, 2022), 179 FERC ] 61,028,
at P 303 (2022) (NOPR).
\18\ See, e.g., Final Rule, 187 FERC ] 61,068 at P 265 (``[W]hat
matters is that this final rule aims to regulate and, in fact, does
regulate only practices that affect the transmission of electric
energy in interstate commerce, which are squarely within the
Commission's jurisdiction under the FPA.'').
\19\ See infra Section III.C. The final rule insists that it
most assuredly does not implicate a major question of public policy,
Final Rule, 187 FERC ] 61,068 at PP 275-279, much like Captain
Renault in Casablanca is ``shocked, shocked to find gambling going
on in here'' as he pockets his winnings. Casablanca (Warner Bros.
Pictures 1942); but see Brad Plumer, Energy Dept. Aims to Speed Up
Permits for Power Lines, Apr. 25, 2024 (quoting Rob Gramlich, the
president of the consulting group Grid Strategies, `` `I've called
[the final] rule the biggest energy policy in the country.' '')
(emphasis added), https://www.nytimes.com/2024/04/25/climate/energy-dept-speed-transmission.html. See Catherine Morehouse, FERC to
tackle ``historic'' transmission planning rule in May, PoliticoPRO,
Apr. 18, 2024 (quoting Chairman Phillips describing the final rule
as ``historic'' and the ``greatest development regarding electric
transmission rules in the country in over a generation . . . .'')
(emphases added).
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6. Put most simply, the final rule is a shell game that plays
this way:
Step One: For planning and cost allocation purposes, throw
transmission projects that solve specific reliability problems or
reduce congestion costs into the same bucket as projects designed to
promote public policies or corporate ``green energy'' preferences
and disguise the purpose of very different projects by re-labeling
all projects in the new bucket with the innocuous-sounding name
``Long-Term Regional Transmission Facilities.''
Step Two: Mandate planning inputs that must be used in
determining which projects get selected for regional plans, which
starts the money flowing from consumers to developers before any
state has even evaluated the need for, or cost of, the projects.
Step Three: Mandate benefits that will ultimately affect the
allocation of costs to consumers across a multi-state region.
Combined with Steps One and Two, this makes consumers involuntary
``beneficiaries'' who will then be forced to pay for projects that
promote another state's public policy or corporate ``green power''
commitments.
Step Four: Order all transmission providers to develop and file
a cost allocation formula that will automatically be the default
applicable to the entire bucket of Long-Term Regional Transmission
Facilities.
Step Five: Remove the NOPR's requirement that states must
consent to the details of Steps One through Four before their
consumers can be burdened with costs.
7. Let's drill down on the details of the final rule's shell
game. The final rule seeks to shift the costs of transmission
projects whose purpose is to implement state or local public
policies promoting wind and solar generation (commonly referred to
as ``public policy projects'' or ``policy-driven projects'') and big
corporation ``green energy'' preferences by putting those projects
into the same regulatory bucket--both for planning and cost-
allocation purposes--with fundamentally different types of projects,
those designed either to solve identified reliability problems (an
engineering purpose, not a political or corporate purpose) or to
provide quantifiable congestion cost savings (economic
projects).\20\ The final rule labels all projects thrown into the
new bucket as ``Long-Term Regional Transmission Facilities.'' \21\
Lumping policy-driven projects with the other very different types
of projects is a sleight-of-hand move to disguise the costs of the
policy-driven and corporate-driven projects that the final rule is
promoting.\22\ Put most simply, reliability projects are driven by
engineering, economic projects by economics, public policy projects
by politicians, and corporate ``green energy'' policies by
management and investors looking to maximize their returns or
satisfy investment goals not recognized by the FPA.
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\20\ See, e.g., Final Rule, 187 FERC ] 61,068 at PP 1474
(``[T]ransmission providers may not establish reliability, economic,
or public policy transmission facility types as part of Long-Term
Regional Transmission Planning and, therefore, may not establish
Long-Term Regional Transmission Cost Allocation Methods based on
reliability, economic, or public policy transmission facility
types.'').
\21\ Id.; see also id. PP 41, 250-251. In terms of labeling, at
least Order No. 1000 described public policy projects honestly, as
those that address ``transmission needs driven by Public Policy
Requirements.'' See, e.g., Transmission Plan. & Cost Allocation by
Transmission Owning & Operating Pub. Utils., Order No. 1000, 136
FERC ] 61,051, at PP 2, 6 (2011), order on reh'g, Order No. 1000-A,
139 FERC ] 61,132, order on reh'g & clarification, Order No. 1000-B,
141 FERC ] 61,044 (2012), aff'd sub nom. S.C. Pub. Serv. Auth. v.
FERC, 762 F.3d 41 (D.C. Cir. 2014) (South Carolina); see also id. PP
11, 47.
\22\ See PJM Interconnection, L.L.C., 187 FERC ] 61,012 (2024)
(Christie, Comm'r, concurring at P 6 n.12) (``I note too that in
PJM's [Regional Transmission Expansion Plan (RTEP)] review it offers
a good example of how components of two different types of projects,
a specific reliability solution and [State Agreement Approach (SAA)]
Project, can be combined into one project that meets both needs. PJM
describes in its filing how it solved a Window 3 specific
reliability problem by combining that solution with an SAA project
into an Incremental Multi-Driver Project . . . . This is a good
example of how a multi-driver project should work: The reliability
need is specific and would require a specific reliability solution
that would, on its own, merit inclusion in the RTEP as a reliability
project, and the SAA project, which is a supplemental--not a
reliability--project, if feasible as it is in this specific case,
can be planned in a way to meet the specific reliability need. Costs
are allocated by PJM proportionately to each component of the
project, one percentage allocated as a reliability project under
PJM's formula, the other percentage wholly allocated to New Jersey
for the SAA project.'') (internal citation omitted).
---------------------------------------------------------------------------
8. Then to further promote its preferred policy projects, the
final rule mandates planning criteria to be used in the planning of
Long-Term Regional Transmission Facilities,\23\ including the
``categories of factors'' that must be used in developing long-term
planning scenarios \24\ and the list of benefits that must be used
by planners in cost-benefit analyses.\25\ All of these mandatory
features are transparently intended to ``pre-cook'' outcomes by
manipulating the planning and evaluations that determine which
projects are selected for regional transmission plans. (It is
emblematic of the entire final rule that it did not include ``saves
retail customers money'' as one of its mandatory benefits for
evaluating projects.) \26\ The shell game's purpose is to ensure
that preferential policy and corporate-driven projects are selected
for regional transmission plans, which conveniently ensures that
such projects are eligible for cost recovery through FERC's very
generous (to developers, not consumers) formula rate mechanism. As
further proof of the nature of the shell game, the final rule does
not require transmission providers to identify the benefits used
(other than those mandated), or how those benefits were specifically
calculated, for cost allocation purposes.\27\ While the final rule
insists that it is not mandating outcomes, when you manipulate the
inputs of transmission planning, you are effectively mandating
outputs.\28\
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\23\ Final Rule, 187 FERC ] 61,068 at Section III.
\24\ Id. P 409. Among the mandatory categories of factors that
the final rule dictates must be used to drive long-term planning
throughout the entire country are, inter alia: (i) state and local
laws affecting the resource mix, (ii) state and local laws on
decarbonization, (iii) generator interconnection requests and
withdrawals (another way to subsidize and prefer wind and solar
developers which dominate the queues), and (iv) corporate, state and
local government commitments to purchase ``green'' energy. Let me
emphasize: these planning factors are mandatory for transmission
providers to use, exposing the final rule's pretextual agenda for
what it really is.
\25\ Id. PP 3, 269, 719-720.
\26\ See, e.g., id. P 720.
\27\ Id. PP 1505-1511.
\28\ Id. P 965.
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9. But that's not all; here comes the worst part of the shell
game. The final rule then requires every transmission provider in
America to file an ex ante cost allocation formula that is
applicable to the whole bucket of projects,\29\ which now includes
public and corporate-driven policy projects, in order to socialize
the costs of these projects across the entire region, even when
states in a region have never consented for their consumers to bear
the costs of such projects. The final rule seeks to justify this
[[Page 49569]]
imposition of costs on non-consenting states by treating their
consumers as ``cost causers'' or ``beneficiaries,'' \30\ which is
justified by--now circle back to earlier in the shell game--the
final rule's imposition of mandatory factors and benefits that must
be used in the evaluations of projects.\31\ By lumping reliability
and economic projects into the same planning bucket as public and
corporate-driven policy projects, the final rule seeks to affix the
tags of ``cost causer'' and ``beneficiary'' to all consumers in a
multi-state region, to justify sticking them with costs even if
their state officials never consented. So despite the final rule's
disingenuous claims to the contrary,\32\ the intent and effect of
this shell game is to enable the costs of corporate and public
policy-driven projects to be socialized across an entire multi-state
region and thus shifted onto consumers in states that never agreed
to bear such costs. The explicit promise of the NOPR, that states
would have to consent for their consumers to bear such costs, has
been broken in this final rule.
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\29\ Id. P 1291.
\30\ See, e.g., id. P 1305 n.2786 (``The cost causation
principle requires costs to be allocated to those who cause the
costs to be incurred and reap the resulting benefits.'') (emphasis
added). A true statement on its face, but utterly disingenuous here.
By mandating its preferred factors to be used in long-term planning,
by mandating certain benefits to be used in evaluating projects, and
by denying transparency as to what other benefits are used to
evaluate projects and how benefits are being calculated, which
drives cost allocation, the final rule effectively will hide the
specific costs of policy and corporate-driven projects and essential
information as to how costs are being calculated and allocated
across a multi-state region. See also supra n.10.
\31\ These key elements of the shell game respond almost
precisely to the lobbying demands of various interest groups. See,
e.g., Environmental Groups Dec. 8, 2023 Comments (``Transmission
providers must perform long-term (at least 20-year), forward-looking
assessments . . . . They must . . . [include] planning for state
clean energy laws and policies, [and] scenarios with high renewable
penetration . . . . Scenarios must evaluate all benefits that
transmission projects would deliver and use these assessed benefits
as a basis for project selection . . . . The Commission also should
create a default cost allocation policy that meets this same
standard . . . .'') (emphases added). Among others, the signers of
this letter include: Advanced Energy United, American Clean Power
Association, Clean Air Task Force, Earthjustice, Environmental
Defense Fund, Evergreen Action, League of Conservation Voters,
National Wildlife Federation, Natural Resources Defense Council
(NRDC), Sierra Club, Union of Concerned Scientists, and WE ACT for
Environmental Justice. See also supra nn.8, 10.
\32\ Final Rule, 187 FERC ] 61,068 at P 267 (``[N]othing in this
final rule requires states to subsidize other states' public
policies and, indeed, this final rule requires . . . that
transmission customers within a transmission planning region need
only pay costs that are `roughly commensurate' with the benefits
that transmission providers estimate they will receive from a
transmission facility.'') (emphasis added).
---------------------------------------------------------------------------
10. When I voted for the NOPR, I made it absolutely clear I was
voting for it because it reflected a compromise in which public and
corporate policy-driven projects could be incorporated into long-
term planning, but only if the states had the authority to consent
both to planning criteria, including benefits used in cost-benefit
analyses to evaluate projects and selection criteria, as well as to
cost allocation.\33\ In my concurrence to the NOPR I wrote:
---------------------------------------------------------------------------
\33\ NOPR, 179 FERC ] 61,028 (Christie, Comm'r, concurring at PP
11-12, 14) (NOPR Concurrence); see also id. P 5.
Even more importantly though, for these [long-term] projects,
the NOPR proposes to require the regional planning entities to
consult with and seek the agreement of the relevant states to both
the selection criteria for these projects and to the regional cost
allocation arrangements. State approval is especially important in a
multi-state region, where different states have different policies.
The NOPR proposes to provide the maximum opportunity for creativity
and flexibility to the states and regional entities in developing
the process for designing and approving regional selection criteria
and cost allocation arrangements. States can agree to an ex ante
formula for regional cost allocation of these types of projects--
such as, for example, the ``highway-byway'' formula approved by the
SPP Regional State Committee--or states can agree to a process for a
project-by-project agreement on cost allocation among one or several
states--such as, for example, the State Agreement Approach in PJM--
or states may choose some combination of both.\34\
---------------------------------------------------------------------------
\34\ Id. P 11 (emphasis in original and added).
---------------------------------------------------------------------------
And let me emphasize . . . no individual state's consumers can
be forced to bear the costs of another state's policy-driven project
or element of a project against its consent.\35\
---------------------------------------------------------------------------
\35\ Id. P 12 (emphasis added).
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The bottom line for me is this: I believe that elevating the
role in planning and cost allocation of state regulators--who are,
as a group, deeply concerned about the monthly bills paid by
consumers, of which transmission is a rapidly growing component--
will make it more likely, not less, that necessary transmission can
get built while ensuring that rates resulting from these types of
policy-driven projects will not be unjust and unreasonable, which
they clearly have the potential to be.\36\
---------------------------------------------------------------------------
\36\ Id. P 14 (emphasis in original and added).
The other members of the Commission, including the then-Chairman
and both other members of today's Commission, also recognized the
NOPR as a compromise.\37\
---------------------------------------------------------------------------
\37\ From the Transcript of Apr. 21, 2022 Commission Open
Meeting (April 2022 Open Meeting Tr.):
``CHAIRMAN GLICK: And I also want to finally thank my
colleagues. I think this [NOPR] is a really good product. It is a
product of a lot of discussion, a lot of compromise--which is what
the Commission is all about--and I think all of us can say we did
not get everything in there, in the document, that we would like,
but I think we all got enough in there and I think we achieved a
significant and really remarkable level of consensus. And I think
that is very notable today.'' April 2022 Open Meeting Tr. 44:17-24
(emphases added).
``COMMISSIONER CLEMENTS: As the Chairman [stated] that reaching
agreement on this proposal was not easy. I can say with confidence
that none of us voting for it would have written it this way if we
were writing on our own. But I am proud that it is a bipartisan
effort, and I am thankful to my colleagues for proactively engaging
and for thinking creatively to find alignment.'' Id. at 55:17-23
(emphasis added).
``COMMISSIONER CHRISTIE: But I think on balance the positive
aspects of this [NOPR], particularly for state regulators at the
heart of planning and cost allocation for these types of projects,
changing [CWIP] to AFUDC[,] I think those are positive, big steps
forward for me on balance and it makes it worth voting for this
[NOPR].'' Id. at 67:15-20 (emphasis added).
``COMMISSIONER PHILLIPS: I would first like to thank my
colleagues for working collaboratively with me on this. . . . I
don't think I have ever been a part of a process more collaborative
than this process that we had in this NOPR.'' Id. at 67:24-25, 68:6-
8.
To those who say that many elements of this final rule were also
in the NOPR for which I voted, such as, for example, the mandatory
categories of factors, I would respond: If I agree to get a root
canal with anesthetic, but learn upon arrival at the dentist's
office that I can still get the root canal but with no anesthetic,
that is not the original deal.
---------------------------------------------------------------------------
11. Yet the many fundamental changes made in this final rule
\38\ subvert and violate that compromise. Of particular importance
to my willingness--and that of many state regulator organizations--
to support the compromise NOPR, was the explicit principle of state
agreement to planning and selection criteria and cost allocation
embodied in the NOPR. The final rule, however, denies what the NOPR
promised: it denies state agreement to selection criteria,\39\ it
denies state agreement to the benefits to be used in evaluating
projects for selection in regional plans and ultimate selection
(which can start the money flowing from consumers to developers
before a state siting or construction permit has even been
issued),\40\ and most importantly, it denies state agreement to cost
allocation for public policy and corporate-driven projects.\41\ The
State Agreement Approach, used successfully in PJM for over a
decade, is effectively terminated by the final rule. The final rule
says that, even if states in a planning region agree, a ``State
Agreement Process'' cannot be the sole chosen method for allocating
costs of these projects; the transmission provider's own ex ante
formula must be the default method, regardless of whether states
have agreed to it.\42\ In addition to a de facto termination of the
PJM State Agreement Approach, the final rule could call into
question mechanisms to facilitate the states' role in cost
allocation that have been used in other RTOs and ISOs for years,
including in SPP and MISO.\43\
---------------------------------------------------------------------------
\38\ See infra Section II.
\39\ Final Rule, 187 FERC ] 61,068 at P 996.
\40\ Id. PP 3, 269, 719-720, 903.
\41\ Id. PP 1291-1292, 1294, 1354, 1356 n.2895, 1359, 1367,
1429.
\42\ Id. To be clear, even if the states agreed on an
alternative ex ante cost allocation method, or if they agreed on a
cost allocation method under the State Agreement Process, the
transmission provider could choose to file it but also could ignore
it. See infra n.195.
\43\ See Final Rule, 187 FERC ] 61,068 at PP 1291-1292, 1294,
1354, 1356 n.2895, 1359, 1367, 1429.
---------------------------------------------------------------------------
12. And let's get real: Telling the states to negotiate for an
alternative cost allocation when the transmission provider's ex ante
formula has already been designated as the default is no real
negotiation at all. The final rule points a regulatory gun at
states' heads redolent of The Godfather: \44\ ``Here's an offer
[[Page 49570]]
you can't refuse.'' And contrary to NARUC's eminently reasonable and
practical request,\45\ the final rule even requires only one
Engagement Period for states to negotiate a different cost
allocation from the transmission providers' ex ante cost allocation
before that ex ante cost allocation becomes the default.\46\ It is
obvious that the final rule intends to lock in each transmission
provider's own ex ante formula for many years to come and to deny
states any avenue to challenge it even as times and circumstances
change, no matter how high their consumers' power bills escalate due
to rising transmission costs.
---------------------------------------------------------------------------
\44\ The Godfather (Paramount 1972).
\45\ Final Rule, 187 FERC ] 61,068 at P 1255 (``NARUC requests
that the Commission provide a mechanism for future review of cost
allocation methods for Long-Term Regional Facilities.'' (citing
NARUC Initial Comments at 49-50)).
\46\ Id. P 1368; see also id. P 1291.
---------------------------------------------------------------------------
13. Essentially, the final rule replaces the NOPR's principle of
requiring state agreement to selection criteria, benefits, and cost
allocation with a charade of suggesting to transmission providers
that they ``consult with and seek support'' from the states--while
paradoxically ``clarifying'' that transmission providers do not
actually need to obtain state consent--and the final rule uses other
empty phrases such as allowing states to ``inform'' or ``provide
input on'' the evaluation process and cost allocation.\47\ But the
final rule's real attitude towards the states and state regulators
is embodied in this airily regal but perhaps unintentionally
straightforward pronouncement: ``[W]e do not agree that the views of
state regulators regarding the appropriate cost allocation approach
are dispositive.'' \48\
---------------------------------------------------------------------------
\47\ See, e.g., id. PP 268, 959, 994, 996-997, 1456.
\48\ Id. P 1363 (citation omitted). A different attitude towards
state regulators was apparent in the NOPR. See April 2022 Open
Meeting Tr. 46:10-16 (``CHAIRMAN GLICK: [This] NOPR proposes to give
the states a much more significant role in addressing cost
allocation. I think it helps to have Commissioner Christie and
Commissioner Phillips, two of our five Commissioners are former
state regulators, and I think that really helps to have their
background and their interest.'').
---------------------------------------------------------------------------
14. The principle of cost allocation that was described in my
concurrence to the NOPR--that states must consent to regional cost
allocation of corporate and public policy-driven projects--reflects
a core principle of American democracy: fairness. In this ratemaking
context, fairness means that the people have the right to choose the
policymakers who impose costs on them, so they can hold them
accountable. This final rule is unfair because it gives FERC and the
transmission providers it regulates the power to impose costs on
consumers to pay for transmission driven by huge corporations and
politicians in states other than theirs, and for whom they never
voted. The final rule truly subverts the principle that the people,
through their state's policymakers, must consent to bear the costs
of another state's politicians and their policy choices, or the
energy purchasing preferences of corporate managers and investors.
15. And from the consumer standpoint, the timing of this rule
could not be worse. American residential customers will pay about
16.23 cents per kWh next year, the highest retail power cost for
consumers in almost three decades.\49\ Unlike in years past, fuel
costs are not the primary driver of these mounting prices to
consumers; rather, transmission is. Transmission costs are rising
rapidly, becoming an ever more burdensome part of consumers' power
bills.\50\ To cite just one major example, in PJM, the largest RTO
by load in the country, the transmission component of wholesale
power costs has essentially tripled over the past decade, from just
$5.65/MWh in 2013 to $16.54/MWh last year. Transmission now
constitutes almost a third of wholesale power costs, up from
approximately 10% just a decade earlier.\51\ In 2020, the PJM Market
Monitor reported that the cost of transmission exceeded the cost of
capacity for the first time.\52\ Nationally, transmission rate base
nearly tripled in a decade,\53\ and--assuming an 8.2% year-over-year
growth rate, which occurred in 2022--is on track to double again in
the next nine years, even without this rule's intent to spend
trillions more on transmission. According to the U.S. Energy
Information Administration, already one in three American households
reports difficulty in paying their power bills.\54\
---------------------------------------------------------------------------
\49\ See Robert Walton, U.S. electricity prices outpace annual
inflation, Utility Dive, Mar. 13, 2024 (``U.S. electricity prices
rose 3.6% over the last 12 months, outstripping the broader
inflation rate of 3.2%, the Bureau of Labor Statistics reported
Tuesday. And experts say there is little chance for near-term
consumer relief. . . . And federal policies aimed at electrifying
end uses and reducing emissions could lead to even higher prices,
Travis Fisher, director of energy and environmental policy studies
at the Cato Institute, told a House subcommittee Wednesday.'')
(emphasis added), https://www.utilitydive.com/news/us-electricity-prices-rise-customer-eia-outlook/710113/.
\50\ See, e.g., Zach Bright, Electricity prices rise faster than
inflation, EnergyWire, Apr. 12, 2024 (``The Bureau of Labor
Statistics found that electricity prices rose 5 percent over the
past year. That's higher than the overall consumer price index (3.5
percent) and any other single commodity, like food . . . and
gasoline . . . .'') (emphases added), https://www.eenews.net/articles/electricity-prices-rise-faster-than-inflation/; Electricity
Inflation 30% Higher Than CPI Over Last 12 Months'' Electricity
Transmission Competition Coalition, Apr. 10, 2024 (``Electricity
inflation remains the highest consumer goods cost among the items in
the Consumer Price Index according to the latest release of data by
the Bureau of Labor Statistics. . . . The price of electricity has
soared because of the accelerating cost of transmission . . . .'')
(emphasis added), https://electricitytransmissioncompetitioncoalition.org/electricity-inflation-30-higher-than-cpi-over-last-12-months/.
\51\ State of the Market Report 2023, PJM Market Monitor, Vol.
II, Section 1, at 18, Table 1-9, https://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2023.shtml; State of the Market Report 2014, PJM Market Monitor,
Vol. II, Section 1, at 16, Table 1-9, https://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2014/2014-som-pjm-volume2-sec1.pdf; State of the Market Report 2013, PJM
Market Monitor, Vol. II, Section 1, at 12, Table 1-9, https://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2013/2013-som-pjm-volume2-sec1.pdf; see also State of the Market Report
2019, PJM Market Monitor, Vol. II, Section 1, at 18, Table 1-10,
https://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2019/2019-som-pjm-sec1.pdf.
\52\ State of the Market Report 2020, PJM Market Monitor, Vol.
I, at 17, Table 8, https://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2020/2020-som-pjm-vol1.pdf.
\53\ See Jim O'Reilly, Led by AEP and Duke, transmission growth
poised to rebound from dip in 2022, S&P Global Market Intelligence,
Nov. 15, 2023 (showing bar graph providing that aggregate
transmission rate base grew from $61.4 billion in 2012 to $163.1
billion in 2022), https://www.spglobal.com/marketintelligence/en/news-insights/research/led-by-aep-and-duke-transmission-growth-poised-to-rebound-from-dip-in-2022. Under this Commission's rate
recovery protocols, the transmission owner gets to collect the
annual costs of transmission depreciation from rate base, plus a
profit, known as Return on Equity, or ``ROE,'' often inflated by the
many incentives the Commission typically approves, as well as
operations and maintenance costs. As any utility regulator knows,
``what goes into rate base comes out in customers' bills.'' So a
rapidly rising rate base means rapidly growing consumers bills.
\54\ Amanda Durish Cook & Tom Kleckner, Overheard at 10th Annual
GCPA MISO-SPP Forum, RTO Insider, Mar. 12, 2024, https://www.rtoinsider.com/73311-overheard-10th-annual-gcpa-miso-spp-forum/.
---------------------------------------------------------------------------
16. Don't fall for the absurd claim that this rule will somehow
save consumers money through more holistic or efficient planning, a
vacuous bureaucratic argument divorced from reality.\55\ The sheer
amount of new transmission costs that the final rule inflicts on
consumers--and special interest groups want--is staggering, measured
in the trillions,\56\ not `merely' hundreds of billions, of
dollars.\57\ And these staggering costs will not be incurred to
provide consumers with reliable power, but to serve political and
corporate agendas. It is truly Orwellian newspeak \58\ to claim that
adding multiple trillions of dollars in transmission costs to
consumer's bills will somehow ``save'' consumers money (even Orwell
would be impressed at the sheer audacity of such a claim).
---------------------------------------------------------------------------
\55\ See, e.g., Final Rule, 187 FERC ] 61,068 at P 89.
\56\ See supra n.7.
\57\ Illinois Senator Everett Dirksen is said to have once
quipped, ``In Washington, a billion here, a billion there, and
pretty soon you're talking about real money.'' The final rule
updates his quip to a ``trillion here, a trillion there . . . .''
\58\ George Orwell, 1984 (first published by Secker & Warburg
1949).
---------------------------------------------------------------------------
17. If FERC were seriously interested in saving consumers'
money, it would be acting to rein in the wide array of transmission
incentives regularly handed out to transmission developers that are
direct transfers of wealth from consumers to developers (long known
as ``FERC candy''),\59\
[[Page 49571]]
and acting to reform the automatic awarding of the presumption of
prudence in formula rate proceedings. Literally nothing is being
done about these forms of consumer exploitation in this final rule;
instead, the final rule goes in the exact opposite direction.
---------------------------------------------------------------------------
\59\ See, e.g., Office of Ohio Consumers' Counsel v. Am. Elec.
Power Serv. Corp., 181 FERC ] 61,214 (2022) (Christie, Comm'r,
concurring at P 2), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-addressing-rto-adders-related-e-2-ohio; MISO, 181 FERC ] 61,094 (2022) (Christie, Comm'r, concurring
at P 2), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-urging-action-re-rto-participation-adder-docket; Mary O'Driscoll, FERC approves incentives for AEP, Allegheny
grid projects, Greenwire, July 21, 2006 (``The approvals came as the
commission finalized rules intended to promote transmission-grid
additions that outline specific rate and other incentives that FERC
will consider for future construction projects--the `FERC candy'
that critics contend gives the utilities incentives but not much in
the way of corresponding requirements.'') (emphasis added), https://subscriber.politicopro.com/article/eenews/2006/07/21/ferc-approves-incentives-for-aep-allegheny-grid-projects-234508.
---------------------------------------------------------------------------
18. To add further insult to consumers' injury, the final rule
walks back the NOPR proposal that would have denied transmission
developers the Construction Work in Progress (CWIP) incentive.\60\ I
have written many times that CWIP is simply unfair. CWIP is unfair
because it makes consumers the unwilling ``bank'' for developers,
but unlike a real bank, consumers don't get paid any interest and
this Commission forces them to make involuntary loans.\61\ Removing
CWIP was strongly supported by those concerned with protecting
consumers: by state regulators, by public power providers, and by
state consumer advocates.
---------------------------------------------------------------------------
\60\ Final Rule, 187 FERC ] 61,068 at P 1547.
\61\ Baltimore Gas & Elec. Co., 187 FERC ] 61,030 (2024)
(Christie, Comm'r, dissenting at P 7), https://www.ferc.gov/news-events/news/commissioner-christies-dissent-award-incentives-exelon-er24-1313; PJM Interconnection, L.L.C., 185 FERC ] 61,200 (2023)
(Christie, Comm'r, concurring at P 3), https://www.ferc.gov/news-events/news/e-7-commissioner-christies-concurrence-exelons-application-abandoned-plant; The Potomac Edison Co., 185 FERC ]
61,083 (2023) (Christie, Comm'r, concurring at P 3), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-concerning-potomac-edisons-abandoned-plant; Montana-Dakota Utils.
Co., 185 FERC ] 61,015 (2023) (Christie, Comm'r, concurring at P 3),
https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-montana-dakota-utilities-co-regarding; Midcontinent
Indep. Sys. Operator, Inc., 184 FERC ] 61,136 (2023) (Christie,
Comm'r, concurring at P 3), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-midcontinent-independent-system-operator-inc-0; GridLiance W. LLC, 184 FERC ] 61,129 (2023)
(Christie, Comm'r, concurring at P 3), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-gridliance-west-regarding-transmission; Midcontinent Indep. Sys. Operator, Inc., 184
FERC ] 61,034 (2023) (Christie, Comm'r, dissenting at P 8), https://www.ferc.gov/news-events/news/commissioner-christies-dissent-award-transmission-incentives-nipsco-er23-1904; Otter Tail Power Co., 183
FERC ] 61,121 (2023) (Christie, Comm'r, concurring at P 8), https://www.ferc.gov/news-events/news/e-18-commissioner-christies-concurrence-otter-tail-power-company-regarding; LS Power Grid Cal.,
LLC, 182 FERC ] 61,201 (2023) (Christie, Comm'r, concurring at P 3),
https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-ls-power-grid-regarding-transmission-incentives; Nev.
Power Co., 182 FERC ] 61,186 (2023) (Christie, Comm'r, concurring at
P 3), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-nv-energy-regarding-transmission-incentives; The Dayton
Power and Light Co., 182 FERC ] 61,147 (2023) (Christie, Comm'r,
concurring at P 3), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-dayton-power-and-light-company-regarding; Midcontinent Indep. Sys. Operator, Inc., 182 FERC ]
61,039 (2023) (Christie, Comm'r, concurring at P 3), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-midcontinent-independent-system-operator-inc; NextEra Energy
Transmission Sw., LLC, 180 FERC ] 61,032 (2022) (Christie, Comm'r,
concurring at P 3) (July 2022 Concurrence), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-nextera-energy-transmission-southwest-llc; NextEra Energy Transmission Sw., LLC,
178 FERC ] 61,082 (2022) (Christie, Comm'r, concurring at P 3)
(February 2022 Concurrence), https://www.ferc.gov/news-events/news/commissioner-mark-c-christie-concurrence-nextera-energy-transmission-southwest-llc.
---------------------------------------------------------------------------
19. In my concurrence to the NOPR, I wrote:
CWIP is the award of cost recovery of construction costs during
the pre-construction and construction phases to the developer. CWIP
is, of course, passed through as a cost to consumers, making
consumers effectively an involuntary lender to the developer. . . .
Consumers should be protected from paying CWIP costs during this
potentially long period before a project actually enters service, if
it ever does. This NOPR proposal represents a major step forward in
consumer protection and is a big reason I am voting for it.\62\
---------------------------------------------------------------------------
\62\ NOPR Concurrence at P 15.
By walking back the proposed CWIP denial, the final rule results
in a major step backwards for consumers.\63\
---------------------------------------------------------------------------
\63\ By doing nothing about the consumer-paid ``FERC candy''
incentives that this Commission regularly hands out to developers,
and even removing the provisions dialing back the CWIP incentive--
and with its overall aim to pile trillions of dollars of additional
costs for big corporate and politically-driven transmission on
consumers, which will largely flow to the increased profits of wind,
solar and transmission developers--the final rule could be the
inspiration for one of the great country and western songs ``Lord
Have Mercy on the Working Man.'' Warner Bros. Nashville 1992
(``Why's the rich man busy dancing while the poor man pays the band?
Oh they're billing me for killing me, Lord have mercy on the working
man!'').
---------------------------------------------------------------------------
20. In yet another major slap at consumers, the final rule seeks
to shift the substantial costs caused by generation developers'
interconnection requests from developers to consumers.\64\ It does
this by ordering transmission providers to revise their regional
transmission planning processes to evaluate for selection regional
transmission facilities that address identified interconnection-
related transmission needs, and the final rule specifies that if
such a facility is selected, its costs will be regionally
allocated.\65\ It also does this by ordering transmission providers
to incorporate generator interconnection requests and withdrawals in
their long-term transmission planning.\66\ These are only schemes to
shift interconnection costs from developers to consumers and will
result in rates that are blatantly unjust, unreasonable, unduly
discriminatory and preferential. Similarly, the final rule also
inappropriately shifts preferential corporate-driven project costs
onto all other consumers, who may disagree with, or even compete
against, the corporate customers imposing their preferences. These
provisions alone render the final rule's replacement rate unlawful
under FPA section 206.
---------------------------------------------------------------------------
\64\ Final Rule, 187 FERC ] 61,068 at PP 472, 1106-1107, 1126,
1145.
\65\ Id. PP 125, 1106-1107, 1126, 1145. Under ``participant
funding'' mechanisms the generation developer pays the costs of the
network upgrades costs it causes and consumers do not pay, which is
only fair. The Commission's Order No. 2023 did not violate this
principle. See generally Improvements to Generator Interconnection
Procs. & Agreements, Order No. 2023, 88 FR 61014 (Sept. 6, 2023),
184 FERC ] 61,054, order on reh'g, 185 FERC ] 61,063 (2023), order
on reh'g, Order No. 2023-A, 89 FR 27006 (Apr. 16, 2024), 186 FERC ]
61,199 (2024). This final rule clearly intends to undermine this
principle by moving interconnection costs into regional transmission
planning and cost allocation, so consumers get stuck with the costs
of interconnection, even though it is developers who profit from
interconnection.
\66\ Final Rule, 187 FERC ] 61,068 at P 472.
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21. This Commission is, by statute, supposed to be independent
of any presidential administration, but it has failed to defend that
independence in this final rule, which is a naked pretext to enact
the current administration's ``net zero 2035'' policy agenda, as
well as to serve corporate agendas, and those of other profit-
seeking special interests.\67\ In failing to act independently,\68\
this Commission has broken faith with state regulators and, even
more importantly, broken faith with tens of millions of American
consumers, who could be forced to bear literally trillions of
dollars in costs for transmission lines to serve political,
corporate and other special-interest agendas. This will not produce
just and reasonable rates and is grossly unfair. This final rule is
a dereliction of the Commission's duty under the FPA to protect
consumers and far exceeds its authority under that statute.
---------------------------------------------------------------------------
\67\ See Miranda Willson, Heather Richards, Brian Dabbs, Biden
regulatory plan set to shake up energy sector, Energywire, Dec. 7,
2023 (``The White House released a regulatory plan Wednesday that
could shape President Joe Biden's energy legacy . . . . [T]wo of the
Federal Energy Regulatory Commission's most high-profile proposed
transmission rules are listed on the [White House] agenda . . . .
One of those FERC rules would change how large electric power lines
are planned and paid for . . . .'') (emphases added), https://www.eenews.net/articles/biden-regulatory-plan-set-to-shake-up-energy-sector/; see also supra nn.5, 8, 10, 13, 15, 16.
\68\ In the very recent past, this Commission stood up for its
independence despite intense pressure from a presidential
administration. See, e.g., Steven Mufson, Trump-appointed regulators
reject plan to rescue coal and nuclear plants, The Washington Post,
Jan. 8, 2018 (explaining that ``[t]he independent five-member
commission [that rejected the president's proposal] includes four
people appointed by President Trump''), https://www.washingtonpost.com/news/energy-environment/wp/2018/01/08/trump-appointed-regulators-reject-plan-to-rescue-coal-and-nuclear-plants/.
---------------------------------------------------------------------------
II. The Final Rule Is Fundamentally Different From the NOPR
22. The very essence of due process is notice and opportunity to
be heard. Given the large number of fundamental changes to the NOPR,
the final rule should be viewed as effectively a second NOPR and
clearly should have been put out for additional public comment on
the many fundamental changes. Because it was not, deliberately so,
this final rule invites a court to remand with instructions for the
Commission to give the public an opportunity to comment on the many
fundamental changes from the NOPR.
23. The final rule issuing today is not the NOPR for which I
voted. This pretextual final
[[Page 49572]]
rule is fundamentally different in numerous ways, yet these
fundamental changes were never put out for additional public
comment.\69\ These fundamental changes include, but are not limited
to, the following:
---------------------------------------------------------------------------
\69\ The process leading to the adoption of Order No. 1000, the
final rule's direct predecessor but one not nearly as sweeping in
its application, was described in paragraphs 22 through 24 of that
order. Order No. 1000, 136 FERC ] 61,051 at PP 22-24.
---------------------------------------------------------------------------
24. The Final Rule Imposes Preferential Policy and Corporate-
Driven Project Costs on Consumers in Non-Consenting States: Contrary
to the NOPR, the final rule requires the filing of one or more ex
ante cost allocation methods to apply to selected Long-Term Regional
Transmission Facilities, setting up a mechanism to impose a regional
cost allocation for preferential policy and corporate-driven
projects when states do not consent, either by approving a cost
allocation proposed by transmission owners, by RTOs, or one directly
imposed by the Commission itself.\70\ This is a fundamental change
from the NOPR.
---------------------------------------------------------------------------
\70\ Final Rule, 187 FERC ] 61,068 at PP 1291-1292.
---------------------------------------------------------------------------
25. The Final Rule Mandates Planning Criteria and Purported
Benefits: Contrary to the NOPR, the final rule mandates a specific
set of planning criteria, and specifically purported benefits, that
must be used by transmission providers for these preferential policy
and corporate-driven projects.\71\ Mandating the planning criteria
and benefits is simply a way of ``pre-cooking'' outcomes and is
directly contrary to the NOPR's explicit language that said it was
not mandating outcomes, only a planning process.\72\ This is a
fundamental change from the NOPR.
---------------------------------------------------------------------------
\71\ Id. PP 3, 269, 719-720.
\72\ See NOPR, 179 FERC ] 61,028 at PP 9, 245.
---------------------------------------------------------------------------
26. The Final Rule Abandons Regional Cost Allocation Principle
(6): Contrary to the NOPR,\73\ the final rule abandons the regional
cost allocation principle \74\ that would allow a transmission
planning region to use different cost allocation methods for
different types of facilities in a regional transmission plan. The
final rule replaces this flexibility with a one-size-fits-all
model.\75\ This is a fundamental change from the NOPR.
---------------------------------------------------------------------------
\73\ See id. P 302.
\74\ See Order No. 1000, 136 FERC ] 61,051 at P 685.
\75\ Final Rule, 187 FERC ] 61,068 at P 1469 (``[U]nlike under
Order No. 1000, transmission providers cannot adopt different Long-
Term Regional Transmission Cost [A]llocation Methods for different
types of Long-Term Regional Transmission Facilities, such as those
needed for reliability, congestion relief, or to achieve Public
Policy Requirements.'') (emphasis added); see also id. P 1474.
---------------------------------------------------------------------------
27. The Final Rule Effectively Eliminates a Voluntary State
Agreement Process: Contrary to the NOPR, the final rule effectively
eliminates the use of a voluntary State Agreement Process, such as
the one that has been used by PJM since Order No. 1000.\76\ Not only
is this directly contrary to comments filed by state regulators,\77\
but it represents a fundamental change from the NOPR.
---------------------------------------------------------------------------
\76\ See, e.g., id. PP 1291-1292. A more detailed discussion on
how the final rule effectively guts the State Agreement Process is
in infra Section IV.B.1.b.
\77\ See Final Rule, 187 FERC ] 61,068 at P 1323 (citations
omitted).
---------------------------------------------------------------------------
28. The Final Rule Leaves the CWIP Incentive Intact: Contrary to
the NOPR, the final rule walks back the proposal not to allow use of
the CWIP incentive.\78\ This NOPR provision was one of the strongest
consumer protection features.\79\ Instead, the Commission leaves the
CWIP incentive intact and that consumer protection has been removed.
This is a fundamental change from the NOPR.
---------------------------------------------------------------------------
\78\ Id. P 1547.
\79\ See NOPR, 179 FERC ] 61,028 at P 333; NOPR Concurrence at P
15.
---------------------------------------------------------------------------
29. The Final Rule Makes Local Transmission Planning Less
Transparent: Contrary to the NOPR,\80\ the final rule makes
fundamental changes to the NOPR's section on Local Transmission
Planning.\81\ Local Transmission Planning disclosure and
transparency requirements no longer apply to asset management
projects. This is a fundamental change from the NOPR.
---------------------------------------------------------------------------
\80\ See NOPR, 179 FERC ] 61,028 at PP 400-413.
\81\ Final Rule, 187 FERC ] 61,068 at P 1625.
---------------------------------------------------------------------------
III. The Final Rule Exceeds FERC's Authority Under the FPA
30. The final rule's determination that its reforms are within
the Commission's legal authority under section 206 is flat
wrong.\82\ The final rule is just a pretext for enacting the current
presidential administration's ``net zero 2035'' policy agenda, as
well as that of large corporate buyers of preferential power and
other special interests.\83\ As such, the final rule goes far beyond
the scope of Order No. 1000, as affirmed by South Carolina,\84\ and
exceeds FERC's authority under the FPA. Specifically, the final rule
requires transmission providers to incorporate into their
transmission planning seven categories of factors and a set of seven
required benefits to drive the construction of projects to achieve
the final rule's preferred substantive outcomes: namely, the
development and purchase of certain preferred generation resources.
In so doing, the final rule seeks to recast FERC as a national IRP
planner with extraordinary powers to oversee and dictate to all
public utility transmission providers in the country, in RTO and
non-RTO regions, detailed instructions on planning transmission that
fulfills the current administration's preferred policies as to the
types of generation it wants to build, and to charge consumers
trillions of dollars for this transmission. This transformation of
FERC into a national IRP planner violates FPA section 201 by
infringing on the authority of the states, and it reflects a
tremendous expansion of the agency's power not permitted under the
major questions doctrine.
---------------------------------------------------------------------------
\82\ See id. PP 86, 253.
\83\ See supra Section I.
\84\ 762 F.3d 41.
---------------------------------------------------------------------------
A. South Carolina Does Not Provide a Legal Justification for the
Commission's Actions in the Final Rule
31. In arguing that the Commission is acting within its legal
authority under section 206 to adopt its reforms for Long-Term
Regional Transmission Planning, today's final rule heavily relies on
South Carolina.\85\ However, given the significant differences
between Order No. 1000 and the final rule, that reliance is grossly
misplaced.
---------------------------------------------------------------------------
\85\ E.g., Final Rule, 187 FERC ] 61,068 at PP 86, 253, 256 &
n.604, 257 & n.605, 277.
---------------------------------------------------------------------------
32. Order No. 1000 included reforms intended to ensure that the
transmission planning and cost allocation requirements embodied in
the Commission's pro forma open access transmission tariff could
support the development of more efficient or cost-effective
transmission facilities.\86\ Such reforms included, inter alia, the
requirement for transmission providers to participate in regional
planning processes; the requirement that such regional transmission
planning processes must consider transmission needs that are driven
by public policy requirements; and the requirement that transmission
providers develop a regional cost allocation method for new
transmission facilities selected in the regional transmission plan
for purposes of cost allocation, with such method having to satisfy
six regional cost allocation principles.
---------------------------------------------------------------------------
\86\ Id. P 16 (citing Order No. 1000, 136 FERC ] 61,051 at P 3).
---------------------------------------------------------------------------
33. But Order No. 1000 was built on what may be a foundation of
sand known as ``Chevron deference.'' As the D.C. Circuit explained
in South Carolina, ``[t]he court reviews challenges to the
Commission's interpretation of the FPA under the familiar two-step
framework of [Chevron].'' \87\ The D.C. Circuit further explained
that, ``[i]f the court determines `Congress has directly spoken to
the precise question at issue,' and `the intent of Congress is
clear, that is the end of the matter.' '' \88\ This is often
referred to as ``Chevron step one.'' \89\ The court stated, in
contrast, that ``[i]f . . . `the statute is silent or ambiguous with
respect to the specific issue,' then the court must determine
`whether the agency's answer is based on a permissible construction
of the statute.' '' \90\ This is often referred to as ``Chevron step
two.'' \91\ The D.C. Circuit explained that ``Chevron step two . . .
requires [the court] to uphold an agency's reasonable interpretation
of a statute it administers.'' \92\ That is, the court applies
Chevron deference.\93\
---------------------------------------------------------------------------
\87\ South Carolina, 762 F.3d at 54 (citing Chevron, 467 U.S.
837).
\88\ Id. (quoting Chevron, 467 U.S. at 842).
\89\ See, e.g., id. at 84.
\90\ Id. at 54 (quoting Chevron, 467 U.S. at 843).
\91\ See, e.g., id. at 58-59 (citing Chevron, 467 U.S. at 843),
84.
\92\ Id. at 76 (citing Nat'l Cable & Telecomms. Ass'n v. Brand X
internet Servs., 545 U.S. 967, 982 (2005)).
\93\ Note, however, that the U.S. Supreme Court is revisiting
the 40-year-old doctrine and has indicated that it may narrow or
overturn it in the pending cases, Loper Bright Enterprises v.
Raimondo, No. 22-451 (argued Jan. 17, 2024) and Relentless v. Dep't
of Commerce, No. 22-1219 (argued Jan. 17, 2024).
---------------------------------------------------------------------------
34. In South Carolina, the D.C. Circuit applied Chevron
deference to the Commission's interpretation of FPA section 206 in
affirming many aspects of Order No.
[[Page 49573]]
1000, including its planning mandates.\94\ In affirming the planning
mandates, the court emphasized that Order No. 1000 focused on
process and not substantive outcomes:
---------------------------------------------------------------------------
\94\ See South Carolina, 762 F.3d at 56-59 (internal citations
omitted).
In Order No. 1000, the Commission expressly ``decline[d] to
impose obligations to build or mandatory processes to obtain
commitments to construct transmission facilities in the regional
transmission plan.'' More generally, the Commission disavowed that
it was purporting to ``determine what needs to be built, where it
needs to be built, and who needs to build it.'' As the Commission
explained on rehearing, ``Order No. 1000's transmission planning
reforms are concerned with process'' and ``are not intended to
dictate substantive outcomes.'' The substance of a regional
transmission plan and any subsequent formation of agreements to
construct or operate regional transmission facilities remain within
the discretion of the decision-makers in each planning region.\95\
---------------------------------------------------------------------------
\95\ Id. at 57-58 (emphasis added; internal citations omitted).
35. Similarly, in determining that Order No. 1000's public
policy mandate fell within the Commission's authority under section
206, the D.C. Circuit noted the mandate did not promote any
---------------------------------------------------------------------------
particular public policy:
[Petitioners] seem to argue that the Commission can only
exercise authority to promote goals specified in the FPA and that
the public policy mandate cannot be justified with respect to any of
those goals. This argument misunderstands the nature of the mandate.
It does not promote any particular public policy or even the public
welfare generally. The mandate simply recognizes that state and
federal policies might affect the transmission market and directs
transmission providers to consider that impact in their planning
decisions. . . . This fits comfortably within the Commission's
authority under Section 206. . . . [T]he public policy mandate bears
directly on the provision of transmission service.\96\
---------------------------------------------------------------------------
\96\ Id. at 89-90 (citation omitted).
---------------------------------------------------------------------------
Just as with Order No. 1000's planning mandates, the court again
emphasized Order No. 1000's public policy mandate required the
establishment of processes:
But petitioners' attack is once again based on a
misunderstanding of the orders. The orders merely require regions to
establish processes for identifying and evaluating public policies
that might affect transmission needs. The regions are free to choose
their own manner of determining how best to identify and accommodate
these policies.\97\
---------------------------------------------------------------------------
\97\ Id. at 91 (emphasis in original; internal citations
omitted).
36. Finally, in affirming Order No. 1000's requirements
pertaining to cost allocation, the court again applied Chevron
deference to its interpretation of section 206.\98\ The court noted
that Order No. 1000 used a ``light touch'' in its cost allocation
reforms:
---------------------------------------------------------------------------
\98\ Id. at 84-86.
In keeping with the overall approach of the transmission
planning reforms, [Order No. 1000] uses a light touch: it does not
dictate how costs are to be allocated. Rather, [Order No. 1000]
provides for general cost allocation principles and leaves the
details to transmission providers to determine in the planning
processes.\99\
---------------------------------------------------------------------------
\99\ Id. at 81.
37. While Order No. 1000 used a ``light touch,'' this pretextual
final rule is heavy handed. To ensure that policy and corporate-
driven projects are ultimately built so that the preferred
generation is built, the final rule seeks to promote particular
public policies and to dictate substantive outcomes through its
reforms to the Commission's transmission planning and cost
allocation processes.\100\ If Order No. 1000 was upheld precisely
because it was only mandating processes, not outcomes, then this
final rule cannot stand on South Carolina because it nakedly intends
to produce very specific outcomes.
---------------------------------------------------------------------------
\100\ In so doing, the final rule violates section 201 as well.
See infra Section III.B.
---------------------------------------------------------------------------
38. How does it intend to do this? First, in contrast to Order
No. 1000, which mandated consideration of public policies in
transmission planning but not a particular policy,\101\ the final
rule requires transmission providers in their Long-Term Regional
Transmission Planning to incorporate seven categories of factors--
i.e., specific policies, as I have emphasized. Most of these
mandatory categories of factors, which drive long-term transmission
planning, specifically relate to the development and purchase of
``green energy,'' including, inter alia: (i) state and local laws
affecting the resource mix, (ii) state and local laws on
decarbonization, (iii) generator interconnection requests and
withdrawals,\102\ and (iv) corporate, state and local government
commitments to purchase ``green energy.''
---------------------------------------------------------------------------
\101\ See South Carolina, 762 F.3d at 89-90.
\102\ This factor category is another way to subsidize and
prefer wind and solar developers, which dominate the interconnection
queues.
---------------------------------------------------------------------------
39. The final rule describes the relationship between the
categories of factors, transmission needs, and benefits, among other
terms:
For purposes of this final rule, Long-Term Regional Transmission
Planning means regional transmission planning on a sufficiently
long-term, forward-looking, and comprehensive basis to identify
Long-Term Transmission Needs, identify transmission facilities that
meet such needs, measure the benefits of those transmission
facilities, and evaluate those transmission facilities for potential
selection in the regional transmission plan for purposes of cost
allocation as the more efficient or cost-effective regional
transmission facilities to meet Long-Term Transmission Needs.
For purposes of this final rule, Long-Term Transmission Needs
are transmission needs identified through Long-Term Regional
Transmission Planning, which, as discussed in this final rule,
includes running scenarios and considering the enumerated categories
of factors.\103\
---------------------------------------------------------------------------
\103\ Final Rule, 187 FERC ] 61,068 at PP 38-39 (emphasis
added).
Thus, categories of factors clearly shape the identification of
transmission needs. Demonstrating this causal relationship, the
final rule explains that ``best available data inputs are data
inputs that . . . reflect the list of factors that transmission
providers account for in their Long-Term Scenarios,'' \104\ and, in
turn, ``Long-Term Scenarios . . . incorporate various assumptions
using best available data inputs about the future electric power
system . . . to identify Long-Term Transmission Needs and enable the
identification and evaluation of transmission facilities to meet
such transmission needs.'' \105\
---------------------------------------------------------------------------
\104\ Id. PP 42, 633 (emphasis added).
\105\ Id. PP 40 and 302 (emphasis added).
---------------------------------------------------------------------------
40. And, as we know, the identification of needs leads to the
identification of transmission facilities that meet such needs; the
identification of transmission facilities in turn leads to the
measure of the benefits associated with those facilities; and the
measure of benefits informs the evaluation of those transmission
facilities for potential selection in the regional transmission plan
for purposes of cost allocation. Thus, as the categories of factors
are slanted toward transmission to facilitate preferred generation,
the resulting output of the transmission planning process will
inevitably have a similar bent. In other words, the final rule's
mandate of the categories of factors starts the domino effect toward
the final rule's agenda, an agenda that goes far beyond Order No.
1000.
41. Second, in contrast to Order No. 1000, whose reforms
``[were] concerned with process'' and ``[were] not intended to
dictate substantive outcomes,'' \106\ the final rule requires
transmission providers to measure a set of seven required benefits
in their long-term transmission planning so that the pretextual
agenda will be realized. By mandating minimum benefits that the
transmission providers must use to evaluate potential transmission
facilities,\107\ the final rule is doing the opposite of using a
``light touch;'' rather, the final rule is putting its thumb on the
scale, seeking to dictate outcomes of the transmission planning
process. As I must continue to emphasize, by mandating benefits, the
final rule makes consumers into involuntary ``beneficiaries,'' who,
through regional cost allocation, will be forced to pay for
transmission projects that support the development and purchase of
preferential power. Accordingly, as with the final rule's mandated
categories of factors, the mandatory minimum benefits serve to
advance the final rule's specific policy objectives regarding the
resource mix. Such favoritism is blatantly unduly discriminatory and
preferential in contravention of section 206, and therefore, the
final rule is, simply put, not entitled to Chevron deference in any
form.
---------------------------------------------------------------------------
\106\ See South Carolina, 762 F.3d at 58 (internal citation
omitted).
\107\ Final Rule, 187 FERC ] 61,068 at P 965.
---------------------------------------------------------------------------
B. The Final Rule Violates FPA Section 201
42. The final rule also infringes on the states' authority over
electric generation reserved to them by FPA section 201 and is thus
ultra vires.
43. As relevant here, FPA section 201(b) provides:
[[Page 49574]]
The Commission shall have jurisdiction over all facilities for
such transmission or sale of electric energy, but shall not have
jurisdiction, except as specifically provided in this subchapter and
subchapter III of this chapter, over facilities used for the
generation of electric energy or over facilities used in local
distribution or only for the transmission of electric energy in
intrastate commerce, or over facilities for the transmission of
electric energy consumed wholly by the transmitter.\108\
---------------------------------------------------------------------------
\108\ 16 U.S.C. 824(b)(1) (emphases added).
Further, section 201(a) also specifies that ``such Federal
regulation . . . extend[s] only to those matters which are not
subject to regulation by the States.'' Courts have found that
``states have broad powers under state law to direct the planning
and resource decisions of utilities under their jurisdiction. States
may, for example, order utilities to build renewable generators
themselves, or . . . order utilities to purchase renewable
generation.'' \109\ These powers are reserved to the states under
section 201.
---------------------------------------------------------------------------
\109\ See, e.g., Entergy Nuclear Vt. Yankee, LLC v. Shumlin, 733
F.3d at 417 (quoting S. Cal. Edison Co. San Diego Gas & Elec. Co.,
71 FERC at 62,080).
---------------------------------------------------------------------------
44. In South Carolina, the D.C. Circuit rejected the argument
that section 201 prohibited Order No. 1000's transmission planning
mandate.\110\ The D.C. Circuit emphasized that ``because the
planning mandate relates wholly to electricity transmission, as
opposed to electricity sales, it involves a subject matter over
which the Commission has relatively broader authority.'' \111\ The
court also reasoned that ``because [Order No. 1000's] planning
mandate is directed at ensuring the proper functioning of the
interconnected grid spanning state lines, . . . the mandate fits
comfortably within Section 201(b)'s grant of jurisdiction over `the
transmission of electric energy in interstate commerce.' '' \112\
The court thus concluded that ``Section 201 [did] not preclude the
Commission's regulation of transmission planning in [Order No.
1000]'' and that Order No. 1000 ``[did] not interfere with the
traditional state authority that is preserved by Section 201.''
\113\
---------------------------------------------------------------------------
\110\ 762 F.3d at 62-64.
\111\ Id. at 63 (emphasis added) (footnote omitted)
\112\ Id. (internal citations omitted).
\113\ Id. at 64.
---------------------------------------------------------------------------
45. However, in contrast to Order No. 1000, the final rule
absolutely does ``interfere with the traditional state authority
that is preserved by Section 201'' to ensure that its preferential
policy and corporate-driven projects get built. By mandating, inter
alia, categories of factors that drive the transmission planning
process and by mandating minimum benefits to be used in the
evaluation of potential Long-Term Regional Transmission Facilities,
the final rule seeks to spur the building of transmission so as to
promote a specific policy objective: the development and purchase of
preferential generation. Accordingly, although the final rule
strenuously insists that it is not mandating outcomes,\114\ it is
doing so by manipulating the inputs of transmission planning (i.e.,
``pre-cooking'').\115\ In other words, the final rule seeks to do
indirectly what it may not do directly.
---------------------------------------------------------------------------
\114\ See Final Rule, 187 FERC ] 61,068 at PP 954-955, 1026-
1028.
\115\ Id. P 965.
---------------------------------------------------------------------------
46. As I explained in my concurrence to the NOPR:
States can prefer, mandate or subsidize specific types of
generation resources, but the Commission cannot use its authority
over transmission to pressure, steer or require regional planning
entities to act as the Commission's agents and do indirectly what
the Commission cannot do directly. The Commission is not a national
integrated resource planner. Order No. 1000, to its credit,
recognized this clear delineation between federal and state
authority.\116\
---------------------------------------------------------------------------
\116\ NOPR Concurrence at P 2; see also id. n.4 (quoting Order
No. 1000, 136 FERC ] 61,051 at P 154 (``[T]he regional transmission
planning process is not the vehicle by which integrated resource
planning is conducted; that may be a separate obligation imposed on
many public utility transmission providers and under the purview of
the states.'') (emphases added in NOPR Concurrence)).
I also explained that ``the Commission cannot impose a
preference for certain types of generation nor require regional
entities to plan transmission designed to prefer or facilitate one
type of generation over another.'' \117\
---------------------------------------------------------------------------
\117\ Id. P 12 (emphases in original).
---------------------------------------------------------------------------
47. The text of the FPA gives this Commission no authority
whatsoever to act as a national IRP planner for the purpose of
promoting its preferred generation resource mix. Pulling back the
curtain, that is exactly what this pretextual final rule seeks to
do. By extending FERC's control over every public utility
transmission planner in the country, RTO or non-RTO, and ordering
them to plan transmission lines intended to advance preferred policy
and corporate goals, the Commission is stepping into the role of
national IRP planner. FERC's authority under the FPA is limited to
matters that directly affect rates, not practices that may
theoretically have some tangential, indirect effect on rates,\118\
especially improper purposes such as ordering transmission planning
to promote one or more states' public policies or corporate goals as
to preferred generation resources. Congress intended FERC to be a
rate regulator, not a planner of generation or transmission designed
to bring about the construction of preferred types of generation.
Indeed, FPA section 215 explicitly states that FERC may not order
the construction of any generation or transmission asset.\119\ FERC
cannot order transmission providers to do what FERC itself has no
authority to do, yet that is exactly what this final rule aims to
do.
---------------------------------------------------------------------------
\118\ See, e.g., CAISO v. FERC, 372 F.3d at 400 (holding that
FERC cannot prescribe the membership of the CAISO board, as FERC has
authority over only ``rates, charges, classifications, and closely
related matters''); see also Ari Peskoe, Replacing the Utility
Transmission Syndicate's Control, Energy Law Journal, Vol. 44.3 547,
578 (2023) (Peskoe Article) (``FERC's authority over utility
`practices' is best understood as referring to `actions habitually
being taken by a utility in connection with a rate found to be
unjust and unreasonable.''') (footnote omitted), https://www.eba-net.org/wp-content/uploads/2023/11/8-Peskoe547-618.pdf.
\119\ FERC regulates RTOs and RTO markets to ensure just and
reasonable rates to consumers, but FERC has no authority to order a
load-serving public utility to build a specific generation facility,
only states can. See 16 U.S.C. 824(b)(1); see also Hughes v. Talen
Energy Mktg., 578 U.S. 150, 154 (2016) (``The States' reserved
authority includes control over in-state `facilities used for the
generation of electric energy.''' (quoting 16 U.S.C. 824(b)(1)));
see also 16 U.S.C. 824o(i)(2) (``[Section 215 of the FPA] does not
authorize the [Electric Reliability Organization, i.e., NERC] or the
Commission to order the construction of additional generation or
transmission capacity or to set and enforce compliance with
standards for adequacy or safety of electric facilities or
service.''). Congress recently gave FERC a narrowly limited form of
``backstop'' siting authority for certain designated transmission
lines, but that authority is not implicated in this final rule.
---------------------------------------------------------------------------
48. The final rule purports to order transmission planners to
plan for a ``predicted'' generation mix in a distant future 20 years
away, but the exact generation mix in 20 years is impossible to
predict.\120\ The real goal of this pretextual final rule is not to
try the impossible by predicting the generation mix in 20 years.
Instead, the final rule is an attempt to become a national IRP
planner and bring about a preferred generation mix through
transmission planning by manipulating and shaping the future
generation mix the special interests supporting this final rule want
now.
---------------------------------------------------------------------------
\120\ PATH Concurrence at P 4 (``PATH graphically illustrates
the inherent dangers in approving for regional cost allocation long-
distance projects based on a prediction (i.e., a guess) of what the
generation mix will be in 20 years or more. PATH was originally part
of the huge ``Project Mountaineer'' scheme--announced with great
fanfare right here at the Commission itself--to build three high-
voltage lines across hundreds of miles from West Virginia to East
Coast load centers. The vast majority of the power to be delivered
along these lines was to be coal-generated. After running into a
firestorm of opposition in both the states in the path (no pun
intended), as well as the end-user load states, Project Mountaineer
was abandoned except for the PATH project, which represented a
segment of one of the proposed Project Mountaineer lines. That
segment was never built either. Yet, consumers have been paying for
it ever since. The lesson here is clear: For policy-driven long-
distance, regional transmission projects affecting consumers in
multiple states, it is absolutely essential that state regulators
have the authority to approve--or disapprove--the construction of
these lines and how they are selected for regional cost allocation
and what that cost allocation formula is, if their consumers are
going to be hit with the costs.'') (emphasis in original).
---------------------------------------------------------------------------
49. The final rule denies that it is infringing on state
authority reserved under FPA section 201, arguing, inter alia, that
it directly regulates only those practices that affect the rates for
the transmission of electric energy in interstate commerce and that
it is not aiming to indirectly regulate any matter reserved to the
states by FPA section 201.\121\
[[Page 49575]]
The final rule is chock-full of ``nothing to see here'' rhetoric
asserting that it does not seek to shape the generation resource
mix, but merely responds to changes in the electric industry.\122\
``Pay no attention to the [agenda] behind the [green] curtain! ''
\123\ the final rule insists across 1300 pages. But it should be
obvious by now that the final rule is just a pretext for enacting
this administration's ``net zero 2035'' policy agenda, as well those
of corporate and other special interests.\124\ The true intent of
the final rule is revealed by mandated categories of factors and
minimum benefits, which drive the transmission development necessary
to achieve the final rule's preferred generation resource mix. Any
honest account of the final rule cannot ignore the monetary windfall
it would shower on generation and transmission developers; it is no
wonder, therefore, why they were among the strongest supporters for
the final rule. Nor can any rational individual--unless living in
the Land of Oz--reasonably deny the role the final rule plays in
furthering this pretextual agenda.\125\ In light of this backdrop,
the final rule's repeated assertions that it does not seek to shape
the country's resource mix are simply not credible. Contrary to the
final rule's claims, in violation of FPA section 201, the final rule
transforms the Commission into a national IRP planner to promote the
construction of transmission lines to further the development of the
final rule's preferred generation resources.
---------------------------------------------------------------------------
\121\ Final Rule, 187 FERC ] 61,068 at P 263; see also, e.g.,
id. P 271 (``[T]he requirements in this final rule respect and do
not unlawfully infringe on state authority. Rather . . . the
Commission is acting in an area squarely within its jurisdiction--
transmission planning and cost allocation--by requiring transmission
providers to engage in Long-Term Regional Transmission Planning to
remedy deficiencies in the current transmission planning and cost
allocation processes.'').
\122\ E.g., id. PP 129, 130, 254, 259-263, 266, 271, 275.
\123\ You can decide for yourself whether the ``green curtain''
represents ``green energy'' or something else that's green.
\124\ See supra Sections I, III.B.
\125\ See supra nn.5, 8, 10, 13, 15, 16, 67.
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C. The Final Rule Violates the Major Questions Doctrine
50. Courts generally look with suspicion on ``cryptic''
delegations of authority,\126\ and they are generally skeptical of
agencies that seek to find ``elephants in mouseholes,'' or otherwise
seek to rely on tiny grants of authority to justify major
actions.\127\ As the Supreme Court explained in West Virginia v.
EPA:
---------------------------------------------------------------------------
\126\ See FDA v. Brown & Williamson Tobacco Corp., 529 U.S. 120,
160 (2000).
\127\ See West Virginia v. EPA, 597 U.S. at 746-47 (Gorsuch, J.,
concurring) (quoting Whitman v. Am. Trucking Ass'ns, 531 U.S. 457,
468 (2001)).
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Where the statute at issue is one that confers authority upon an
administrative agency, that inquiry must be ``shaped, at least in
some measure, by the nature of the question presented''--whether
Congress in fact meant to confer the power the agency has asserted.
In the ordinary case, that context has no great effect on the
appropriate analysis. Nonetheless, our precedent teaches that there
are ``extraordinary cases'' that call for a different approach--
cases in which the ``history and the breadth of the authority that
[the agency] has asserted,'' and the ``economic and political
significance'' of that assertion, provide a ``reason to hesitate
before concluding that Congress'' meant to confer such
authority.\128\
---------------------------------------------------------------------------
\128\ Id. at 700 (internal citations omitted).
---------------------------------------------------------------------------
51. I invoked the major questions doctrine in my dissent to the
proposed changes to the Commission's certificate policy, even before
West Virgina v. EPA was handed down. In my dissent, I wrote that:
``The federal government's powers . . . are not general[ ] but
limited and divided. Not only must the federal government properly
invoke a constitutionally enumerated source of authority to regulate
in this area or any other, it must also act consistently with the
Constitution's separation of powers. And when it comes to that
obligation, this Court has established at least one firm rule: `We
expect Congress to speak clearly' if it wishes to assign to an
executive agency decisions `of vast economic and political
significance.' We sometimes call this the major questions
doctrine.''
In short, the major questions doctrine presumes that Congress
reserves major issues to itself, so unless a grant of authority to
address a major issue is explicit in a statute administered by an
agency, it cannot be inferred to have been granted.
* * * * *
Yet the Supreme Court has made it clear that broad deference to
administrative agencies on major questions of public policy is not
in order when statutes are lacking in any explicit statutory grant
of authority. ``When much is sought from a statute, much must be
shown. . . . [B]road assertions of administrative power demand
unmistakable legislative support.'' \129\
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\129\ Certification of New Interstate Nat. Gas Facilities, 178
FERC ] 61,107 (2022) (Christie, Comm'r, dissenting at P 22-23
(quoting Nat'l Fed'n of Indep. Bus. v. Dep't of Labor, OSHA, 595
U.S. 109, 121-22 (2022) (Gorsuch, J., concurring); In re MCP No.
165, 20 F.4th 264, 267-68 (6th Cir. 2021) (Sutton, C.J., dissenting
(emphases added))) (internal citations omitted) (Certificate
Dissent), https://www.ferc.gov/news-events/news/items-c-1-and-c-2-commissioner-christies-dissent-certificate-policy-and-interim.
---------------------------------------------------------------------------
52. The final rule's actions clearly implicate the major
questions doctrine. If imposing a final rule intended to cost
consumers literally trillions of dollars to build transmission
projects designed to implement a sweeping policy agenda never passed
by Congress is not a major question of public policy, then there is
no such thing.\130\
---------------------------------------------------------------------------
\130\ See Brad Plumer, Energy Dept. Aims to Speed Up Permits for
Power Lines, The New York Times, Apr. 25, 2024 (quoting Rob
Gramlich, the president of the consulting group Grid Strategies, ``
`I've called [the final] rule the biggest energy policy in the
country.' '' (emphasis added)), https://www.nytimes.com/2024/04/25/climate/energy-dept-speed-transmission.html.
---------------------------------------------------------------------------
53. Yet the final rule brushes aside arguments that it would not
withstand scrutiny under the major questions doctrine.\131\ Against
these arguments, the final rule denies that its aim is to influence
the generation mix; \132\ asserts that it ``neither transforms nor
expands the Commission's authority; it merely applies existing
authority;'' \133\ asserts that ``the differences in transmission
planning required by this final rule represent differences in
degree, not kind, from the Commission's longstanding regulations;''
\134\ and asserts that its ``incremental process improvements [from
Order No. 1000], while necessary to ensure just and reasonable
Commission-jurisdictional rates, do not have the `vast economic and
political significance' that would implicate the major questions
doctrine.'' \135\ None of these assertions are credible.
---------------------------------------------------------------------------
\131\ Final Rule, 187 FERC ] 61,068 at P 275.
\132\ Id.
\133\ Id. P 277.
\134\ Id.
\135\ Id. P 278 (quoting West Virginia v. EPA, 597 U.S. at 735
(J. Gorsuch, concurring)).
---------------------------------------------------------------------------
54. This final rule violates the major questions doctrine. As
discussed above, it is axiomatic that Congress has not intended for
the Commission to be a national IRP planner. On the contrary, it has
left both the siting of transmission and the development of
generation to the states.\136\ Yet the final rule encroaches on
these traditional state prerogatives in the absence of any explicit
Congressional authorization to do so.
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\136\ See supra Section III.B. Since 2005, FERC has had very
limited backstop siting authority for certain transmission projects
that has never been used. See generally Applications for Permits to
Site Interstate Elec. Transmission Facilities, Order No. 1977, 187
FERC ] 61,069 (2024).
---------------------------------------------------------------------------
55. The final rule seeks to shape specific policy outcomes by
mandating categories of factors and minimum benefits. In addition,
the final rule does something else that also arguably makes it
transformative. Citing, inter alia, South Carolina, the final rule
declares that the Commission has exclusive jurisdiction over
regional transmission planning and cost allocation processes:
As the D.C. Circuit has recognized, regional transmission
planning and cost allocation processes are practices affecting rates
subject to the Commission's exclusive jurisdiction.\137\
---------------------------------------------------------------------------
\137\ Final Rule, 187 FERC ] 61,068 at P 86 & n.184 (emphasis
added) (citing South Carolina, 762 F.3d at 55-59, 84 (affirming the
Commission's authority to regulate transmission planning and cost
allocation as practices affecting rates); Order No. 1000-A, 139 FERC
] 61,132 at P 577 (holding that ``requirements regarding
transmission planning and cost allocation . . . are practices
affecting rates.'')); see also id. P 130 (``Instead, because
practices directly affecting Commission-jurisdictional rates, terms,
and conditions of service for interstate transmission and wholesale
electricity are the exclusive jurisdiction of the Commission, we
must ensure that Commission-jurisdictional processes associated with
regional transmission planning and cost allocation result in rates
that are just and reasonable and not unduly discriminatory or
preferential.'') (emphasis added); id. P 770.
In fact, the South Carolina court did not state that the
Commission has exclusive jurisdiction over regional transmission
planning and cost allocation. In fact, that court noted, for
example, that the Florida Public Service Commission is statutorily
vested with authority to ``plan[], develop[ ], and main[tain] . . .
a coordinated electric power grid'' throughout the state.\138\
---------------------------------------------------------------------------
\138\ See, e.g., South Carolina, 762 F.3d at 62 n.3.
---------------------------------------------------------------------------
56. Whether the Commission can exclusively supplant the states
in transmission planning and cost allocation is a major question--
particularly considering the enormous breadth of the transmission
[[Page 49576]]
grid, the importance of electricity in everyday life, and the
trillions of dollars in transmission investment (read, cost
increases) this final rule intends to impose on consumers.\139\ The
final rule's conclusion that regional transmission planning and cost
allocation processes are subject to the Commission's exclusive
jurisdiction suggests that the Commission ``occupies the field''
\140\ in these areas.\141\ But this is wrong. This pretextual final
rule erodes the states' authority, which is inconsistent with the
principle of cooperative federalism reflected in the FPA. Under the
major questions doctrine, absent an act of Congress, the Commission
may not usurp the powers of the states in this manner.
---------------------------------------------------------------------------
\139\ See FERC v. Elec. Power Supply Ass'n, 577 U.S. 260, 281
(2016) (``It is a fact of economic life that the wholesale and
retail markets in electricity, as in every other known product, are
not hermetically sealed from each other. To the contrary,
transactions that occur on the wholesale market have natural
consequences at the retail level.'').
\140\ See Silkwood v. Kerr-McGee Corp., 464 U.S. 238, 248 (1984)
(``If Congress evidences an intent to occupy a given field, any
state law falling within that field is preempted.'' (citation
omitted)); PPL EnergyPlus, LLC v. Nazarian, 753 F.3d 467, 475-476
(4th Cir. 2014) (``Even where state regulation operates within its
own field, it may not intrude indirectly on areas of exclusive
federal authority.'' (quoting Pub. Utils. Comm'n of State of Cal. v.
FERC, 900 F.2d 269, 274 n.2 (D.C. Cir.1990) (internal quotation
marks omitted))).
\141\ The final rule's determination here aligns with the final
rule's complete gutting of the roles of the states in transmission
planning and cost allocation. See infra Section IV.B.1.
---------------------------------------------------------------------------
IV. The Final Rule Fails Under Both Prongs of FPA Section 206
57. I cannot support the final rule because it has been
fundamentally changed from the NOPR. In jettisoning essential
components of the NOPR, the final rule has been reduced to a mere
pretext for this supposedly independent Commission's effort to
implement the current administration's ``net zero 2035'' policies.
It will not produce rates that are just and reasonable and not
unduly discriminatory or preferential. This final rule does not
satisfy either of the requirements of FPA section 206. Under section
206, the Commission must first find that the rate on file is no
longer just and reasonable and not unduly discriminatory or
preferential. Then the Commission must find that a particular
replacement rate would be just and reasonable and not unduly
discriminatory or preferential.\142\ The final rule fails on both
counts.
---------------------------------------------------------------------------
\142\ 16 U.S.C. 824e.
---------------------------------------------------------------------------
58. Although the current regional transmission planning
processes could be improved--they are certainly not in need of the
final rule's solutions. Even if these solutions were the only way
forward to reform regional transmission planning, an act of Congress
would be necessary first because the final rule is far beyond the
reach of the FPA. While the Commission might prefer a different
rate, that preference alone does not make all the filed rates of
every transmission provider unjust and unreasonable.
A. The Final Rule Fails To Justify Its Action Under Section 206
59. The final rule presents no justification for taking action
in this proceeding against all of the filed transmission rates
pursuant to FPA section 206. The record, while consisting of
thousands of pages of comments, simply does not contain substantial
evidence sufficient to make a generic showing that the existing
filed rates of all transmission providers are unjust, unreasonable,
unduly discriminatory or preferential.\143\ In South Carolina, the
D.C. Circuit explained that ``the substantial evidence test'' for a
rulemaking proceeding `` `requires the Commission to specify the
evidence on which it relied and to explain how that evidence
supports the conclusion it reached.' '' \144\ Here, the final rule's
``rel[iance] on `generic' or `general' findings of a systemic
problem to support imposition of an industry-wide solution'' \145\
fails because it relies on cherry-picked special interest comments
to support the pre-baked and pretextual findings needed to enact the
administration's preferential, and discriminatory, policy agenda as
well those of corporate and other special interests.
---------------------------------------------------------------------------
\143\ See South Carolina, 762 F.3d at 64-65 (citations omitted).
\144\ Id. at 54 (quoting Wis. Gas Co. v. FERC, 770 F.2d 1114,
1156) (alterations in the original)).
\145\ See Final Rule, 187 FERC ] 61,068 at P 132 (citing South
Carolina, 762 F.3d at 67) (additional citation omitted).
---------------------------------------------------------------------------
1. The Record Is Not Sufficient to Make a Generic Showing That
Every Transmission Providers' Regional Transmission Planning and
Cost Allocation Processes Are Unjust, Unreasonable, and Unduly
Discriminatory or Preferential
60. The evidence in the record that is used to support the final
rule's section 206 finding consists largely of comments from special
interests that will profit from the final rule. The final rule also
signals that there has been limited regional transmission
development since Order No. 1000. This evidence should not be used
to mean that every transmission provider in the country has
transmission practices that are unjust and unreasonable.
61. The final rule declines to analyze the ``justness and
reasonableness of either generator interconnection processes or
local transmission planning processes'' in its survey of issues in
regional transmission planning.\146\ The final rule identifies
benefits of transmission planning.\147\ The final rule states that
``transmission planning that considers both evolving reliability
needs and other drivers of transmission needs more comprehensively
can enable transmission providers to identify potential reliability
problems and economic constraints.'' \148\ The final rule states
that transmission spending has increased, which turns into higher
customer bills.\149\ The final rule identifies projections are
necessary for growing future transmission needs, including load
growth \150\ and changing reliability needs.\151\ And supply is
changing due to state policies, customer preferences, and utility
preferences (the latter two can also be driven by state policies or
by activist investor preferences).\152\
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\146\ Id. P 111.
\147\ Id. PP 90-91.
\148\ Id. P 90.
\149\ Id. P 92.
\150\ Id. P 95.
\151\ Id. PP 93-94.
\152\ Id. PP 96-97.
---------------------------------------------------------------------------
62. Translating FERC-speak, we are left with bland statements of
the obvious: Transmission is expensive to build; transmission
spending is up; generators front a lot of the needed money;
consumers eventually pay them back; lack of regional integrated
planning results in piecemeal transmission construction; this is
inefficient and costs consumers more. Yet simply because a rate
could be more efficient, that alone is not enough to make the filed
rate unjust and unreasonable.
63. Many of the special interest commenters point to studies,
projections, and reports that show that regional transmission
planning could be done more efficiently.\153\ When we peel back the
``green curtain'' shrouding this final rule, however, we see that
these comments are almost exclusively from self-interested entities
which would gain substantially from the very Commission action that
they support.\154\ Indeed, the record being used to support the
section 206 finding consists of special interests who are going to
profit monetarily from the final rule, including generation
developers, transmission developers, and corporate purchasers of
preferred power.\155\ None of these comments (individually or taken
together) are sufficient to meet the high burden of proof that all
transmission providers' tariffs are unjust and unreasonable due to
the profit-seeking motivations behind them.
---------------------------------------------------------------------------
\153\ See, e.g., Johannes Pfeifenberger, et al., The Brattle
Group and Grid Strategies, Transmission Planning for the 21st
Century: Proven Practices that Increase Value and Reduce Costs, at
48-49 (Oct. 2021), https://www.brattle.com/wp-content/uploads/2021/10/2021-10-12-Brattle-GridStrategies-Transmission-Planning-Report_v2.pdf; Rob Gramlich and Jay Caspary, Americans for a Clean
Energy Grid, Planning for the Future: FERC's Opportunity to Spur
More Cost-Effective Transmission Infrastructure, at 26-28 (Jan.
2021), https://cleanenergygrid.org/wp-content/uploads/2021/01/ACEG_Planning-for-the-Future1.pdf; Johannes P. Pfeifenberger, et
al., The Brattle Group, Cost Savings Offered by Competition in
Electric Transmission: Experience to Date and the Potential for
Additional Customer Value (Apr. 2019), https://www.brattle.com/wp-content/uploads/2021/05/16726_cost_savings_offered_by_competition_in_electric_transmission.pdf.
\154\ Such commenters include ACORE, PIOs, ACEG, Advanced Energy
Buyers, AEE, Renewable Northwest, SREA, and Clean Energy Buyers.
\155\ See Final Rule, 187 FERC ] 61,068 at P 96.
---------------------------------------------------------------------------
64. In addition, the final rule looks back over the period
following Order No. 1000 and states that regional transmission
planning processes have yielded only ``limited investments in
regional transmission planning projects.'' \156\ Let's suppose that
over the last decade a transmission developer had instead proposed
massively expanding transmission while the load growth projections
remained flat. Consumers commenting on that aggressive plan would
have challenged it as gold-plating. Regulators
[[Page 49577]]
would have rejected it as imprudent. The so-called ``limited
investments'' were instead a sign of responsiveness to projections
made during that era. Rather than seeing this outcome as a feature
of considered ratemaking during a period of low load growth, the
final rule attributes this lack of investment to the shortcomings of
the existing regional transmission planning processes--meaning the
tariff changes mandated by Order No. 1000.\157\ For these reasons,
the final rule's reliance on a lack of regional transmission
development post-Order No. 1000 is not persuasive, especially to
support the finding that all transmission providers' tariffs are
unjust and unreasonable.
---------------------------------------------------------------------------
\156\ Id. P 101.
\157\ Id.
---------------------------------------------------------------------------
2. The Record Shows That Regional Planning Deficiencies Exist Only in
Isolated Pockets
65. The evidence in this record does not demonstrate a single
nationwide systemic problem. Rather, the record shows that the
``deficiencies identified by the Commission `exist[ ] only in
isolated pockets.' '' \158\ The final rule even recognizes the many
regions representing a substantial percentage of consumers where
regional transmission planning is working.\159\ The final rule
points to the MISO Multi-Value Project transmission planning process
as an effective example of regional transmission planning.\160\ From
this, it could be concluded that the final rule suggests that
regional transmission planning is working in MISO, including on a
long-term basis. It is logical to conclude similarly regarding
CAISO's \161\ and New York's regional transmission planning.\162\
Vertically integrated monopoly public utilities have expanded their
transmission capacity by engaging in integrated resource planning
that is reviewed and approved by their state regulators.\163\ NRECA,
an organization representing both transmission providers and
transmission-dependent entities, highlights that its members have
observed regional transmission planning processes that range from
successful to broken.\164\ According to NRECA, some RTO regions are
working, and others are not. NRECA similarly states that some non-
RTO regions are working, and others are not.
---------------------------------------------------------------------------
\158\ See South Carolina, 762 F.3d at 67 (quoting Associated Gas
Distribs. v. FERC, 824 F.2d 981, 1019 (D.C. Cir. 1987)) (alteration
in the original).
\159\ See generally Final Rule, 187 FERC ] 61,068 at PP 71-77.
\160\ Id. P 102; see OMS Initial Comments at 2 (stating that
``it is critically important to note at the outset that MISO's
regional planning process already reflects many of the elements and
features contained in the [NOPR], and it should be looked to as a
model for other regions to emulate.''); MISO Initial Comments at 1-
2.
\161\ CAISO Initial Comments at 3 (``The CAISO already engages
in long-term planning, and its existing transmission planning
process is consistent with the direction of the NOPR.''); CAISO
Reply Comments at 1-2 (stating that ``the Commission should not
unduly disrupt or undo existing planning processes and approaches
that are functioning well and enabling transmission providers to
plan for system needs efficiently and cost-effectively.'').
\162\ New York Commission and NYSERDA Initial Comments at 5.
\163\ See, e.g., Southern Companies Initial Comments at 13-15
(stating that its ``IRP/RFP-driven transmission planning is
successfully expanding their electric grid to address the changing
resource mix and load''); Undersigned States Reply Comments at 6-7.
\164\ NRECA Initial Comments at 14-16.
---------------------------------------------------------------------------
66. This is hardly ironclad evidence sufficient to support a
generic finding that the regional transmission planning processes
are no longer just and reasonable. The record here shows that
regional and multistate regional planning is happening in
significant and large swaths of the country subject to our rate
jurisdiction, including on longer-term horizons, and that other
regions have room for improvement. These circumstances are entirely
different than those facing the Commission when it issued Order No.
1000. The factual justification for a single, national FPA section
206 finding is simply not present in the way it was for Order No.
1000. No amount of hand waving or misdirection can change the lack
of sufficient evidentiary support for this Commission to take the
sweeping national action pursuant to FPA section 206 in this rule.
This significant deficiency leaves this entire exercise open to
meaningful challenge.
B. The Replacement Rate Is Not Just and Reasonable
67. Not only does the final rule fail to meet its evidentiary
burden, but the replacement rate that the final rule imposes is not
just and reasonable and has no basis in law. The final rule has
removed any serious state role in agreeing to the final rule's
planning and cost allocation processes, and the final rule fails to
protect consumers as FERC is required to do under the FPA. Further,
the cost causation principle cannot, and should not, extend as far
as the today's final rule suggests, and should not require that the
ratepayers of a non-consenting state pay costs of other states'
public policies where there is mismatch between planning criteria
and benefits.
1. The Final Rule Reverses the States' Roles in Transmission Planning
and Cost Allocation Promised by the NOPR
68. The main reason I supported the NOPR was that it ``formally
put the states--for the first time--at the center of regional
transmission planning and cost allocation decision-making for
policy-driven projects in all regional transmission entities, if the
states choose.'' \165\ Specifically, I explained:
---------------------------------------------------------------------------
\165\ NOPR Concurrence at P 5 (emphases in original) (footnote
omitted).
[F]or these [Long-Term Regional Transmission Facilities] the
NOPR propose[d] to require the regional planning entities to consult
with and seek the agreement of the relevant states to both the
selection criteria for these projects and to the regional cost
allocation arrangements. State approval is especially important in a
multi-state region, where different states have different policies.
The NOPR proposes to provide the maximum opportunity for creativity
and flexibility to the states and regional entities in developing
the process for designing and approving regional selection criteria
and cost allocation arrangements. States can agree to an ex ante
formula for regional cost allocation of these types of projects--
such as, for example, the ``highway-byway'' formula approved by the
SPP Regional State Committee--or states can agree to a process for a
project-by-project agreement on cost allocation among one or several
states--such as, for example, the State Agreement Approach in PJM--
or states may choose some combination of both. States in a multi-
state RTO or ISO can even agree to defer the decision on cost
allocation to the governing board of the RTO/ISO. The result is,
while we are proposing to require regional planning entities to
study and evaluate a broad, forward-looking array of information--
including information addressing states' individual energy policies
and goals--any projects identified through this new process will not
be built, or more importantly, paid for by consumers, until the
states representing such consumers have agreed that such projects
are indeed needed and wanted by those same consumers.\166\
---------------------------------------------------------------------------
\166\ Id. P 11 (emphases in original) (footnotes omitted).
I wrote about the advantages of elevating the role of the
---------------------------------------------------------------------------
states:
[E]levating the role in planning and cost allocation of state
regulators--who are, as a group, deeply concerned about the monthly
bills paid by consumers, of which transmission is a rapidly growing
component--will make it more likely, not less, that necessary
transmission can get built while ensuring that rates resulting from
these types of policy-driven projects will not be unjust and
unreasonable, which they clearly have the potential to be.\167\
---------------------------------------------------------------------------
\167\ Id. P 14 (emphasis in original).
The day the Commission issued the NOPR, some of my colleagues
expressed similar sentiments.\168\
---------------------------------------------------------------------------
\168\ See supra n.48; NOPR, 179 FERC ] 61,028 (Phillips, Comm'r,
concurring at P 4) (``I support the proposal to require transmission
providers to consult with and incorporate states' views in project
selection and cost allocation. I invite comment on the value of such
state involvement for increasing the likelihood that those
facilities are sited and ultimately developed with fewer costly
delays.''), https://www.ferc.gov/news-events/news/item-e-1-commissioner-phillips-concurrence-building-future-through-electric.
---------------------------------------------------------------------------
69. Unfortunately--perhaps emanating from the final rule's
erroneous legal conclusion that the Commission has exclusive
jurisdiction over regional transmission planning and cost allocation
\169\--the final rule completely eviscerates the states' role
contemplated in the NOPR in both the transmission planning and cost
allocation processes. Other than a few cosmetic gestures, the final
role essentially treats the state regulators like other stakeholders
in the RTO/ISO. But states are not mere ``stakeholders:''
---------------------------------------------------------------------------
\169\ See supra Section III.C.
State regulators have the duty to act in the public interest and
states alone are sovereign authorities with inherent police powers
to regulate utilities through their designated state officers. The
FPA itself explicitly recognizes state authority. So it is perfectly
fitting for state regulators to have the important roles proposed in
this NOPR,
[[Page 49578]]
without preempting the regional planning entities from seeking
additional input through their existing stakeholder processes.\170\
---------------------------------------------------------------------------
\170\ NOPR Concurrence at P 13 (emphasis in original).
The evisceration of the states' role in transmission planning
and cost allocation and the relegation of state regulators to mere
``stakeholder'' status is alone reason enough for me to dissent.
a. The Final Rule Undercuts the States' Role in the Transmission
Planning Process
70. A major example of the final rule's undercutting of the
states' role in the transmission planning process is with respect to
the selection criteria. As a reminder, the selection criteria are a
key component of the planning process because once a project is
selected, money starts to flow from the ratepayers to transmission
developers. Recognizing the states' important role in the planning
process, the NOPR required that the states approve the selection
criteria that transmission providers use in the planning process:
Given the important role states play and the wide variety of
potential approaches to selection criteria, we propose, as part of
this requirement, that public utility transmission providers must
consult with and seek support from the relevant state entities, as
defined below, within their transmission planning region's footprint
to develop the selection criteria.\171\
---------------------------------------------------------------------------
\171\ NOPR, 179 FERC ] 61,028 at P 244; see also NOPR
Concurrence at P 11 (``State approval is especially important in a
multi-state region, where different states have different policies.
The NOPR proposes to provide the maximum opportunity for creativity
and flexibility to the states and regional entities in developing
the process for designing and approving regional selection criteria
and cost allocation arrangements.'').
To implement this requirement, the NOPR proposed ``to require
that public utility transmission providers demonstrate on compliance
that they developed their proposed selection criteria in
consultation with the relevant state entities in their transmission
planning region's footprint.'' \172\ And it was clear at that time
exactly what that meant--agreement, nothing less.\173\ However, the
final rule outright undermines these requirements--and the states'
role as a whole--by ``clarifying'' that state approval of the
evaluation process and selection criteria is not actually required:
---------------------------------------------------------------------------
\172\ NOPR, 179 FERC ] 61,028 at P 246.
\173\ See NOPR Concurrence at P 11; see also supra n.48.
We clarify that we require transmission providers to seek
support from Relevant State Entities, but do not require
transmission providers to obtain their support, before proposing an
evaluation process and selection criteria on compliance.\174\
---------------------------------------------------------------------------
\174\ Final Rule, 187 FERC ] 61,068 at P 996 (emphases added).
Starkly demonstrating how milquetoast the requirement for
transmission providers to ``consult with and seek support from'' the
states has now become under the final rule, the final rule even
fails to require that transmission providers indicate in their
compliance filings whether the states agree with their selection
criteria proposal.\175\ So, from the NOPR requiring state agreement,
the final rule does not even require the states' views to merit mere
mention. Adding insult to injury, the final rule specifies that
``transmission providers may not include in their evaluation process
or selection criteria any prohibition on the selection of a Long-
Term Regional Transmission Facility based on the transmission
providers' anticipated response of a state public utility commission
or consumer advocates to particular Long-Term Regional Transmission
Facilities.'' \176\
---------------------------------------------------------------------------
\175\ Id. P 999.
\176\ Id. P 962 (emphasis added).
---------------------------------------------------------------------------
71. The final rule acknowledges that ``Long-Term Regional
Transmission Planning is more likely to be successful where
transmission providers, Relevant State Entities, and other
stakeholders collaborate to develop an evaluation process and
selection criteria.'' \177\ But the final rule emphasizes that
transmission providers are ultimately the only ones responsible for
transmission planning and complying with the obligations of the
final rule, and it notes that achieving consensus may simply not be
possible in every instance.\178\ Neither explanation provides a
sufficient rationale to justify undercutting the requirement for
state approval when states alone have the inherent police power to
regulate the utilities within their states. One cannot help but see
this as part of the larger pretextual shell game the final rule
seeks to accomplish. Sadly, this is one of many examples where the
final rule provides for a little extra process involving the states
to demonstrate ostensibly that the Commission is committed to the
principle of cooperative federalism, but in substance, states are
relegated back to mere stakeholders, whose input can simply be
disregarded if inconvenient.\179\
---------------------------------------------------------------------------
\177\ Id. P 996.
\178\ Id.
\179\ See supra P 69.
---------------------------------------------------------------------------
72. Unfortunately, not only the states' role with respect to the
selection criteria has been gutted. As I must continue
emphasize,\180\ by mandating categories of factors and minimum
benefits, the final rule seeks to shape specific policies and
outcomes, regardless of the consent of the states.\181\ The goal of
this pretextual final rule is to plan preferential policy and
corporate-driven projects regardless of states' support. One must
also ask whether the extent to which this final rule requires
prescriptive planning processes also limits the states' role to
participate meaningfully when most are resource-strapped.
---------------------------------------------------------------------------
\180\ See supra Section I. Another example, of course, is
micromanaging how local ``stakeholder'' meetings must be conducted,
which, as noted, runs a strong risk of conflicting with state IRP
proceedings and state authority. See Final Rule, 187 FERC ] 61,068
at PP 1625-1646. As above, I question whether prescriptive
requirements to this degree can truly pass muster under court
precedent.
\181\ And transmission providers themselves cannot even
voluntarily account for states' input in the planning. Today's final
rule requires that transmission providers may not include in their
evaluation process or selection criteria any prohibition on the
selection of a Long-Term Regional Transmission Facility based on the
transmission providers' anticipated response of a state public
utility commission or consumer advocates to particular Long-Term
Regional Transmission Facilities. Final Rule, 187 FERC ] 61,068 at P
962.
---------------------------------------------------------------------------
73. States did not join RTOs \182\ to pay for these preferential
policy and corporate-driven projects. Rather, as I wrote in my
concurrence to the NOPR, ``States joined to provide their retail
consumers with the promised benefits of lower transmission costs and
strengthened reliability through regional planning of core
Reliability projects.'' \183\ I speak from personal experience. When
I was a Commissioner at the Virginia State Corporation Commission,
my colleagues and I considered applications to permit Virginia's
major utilities to join PJM. The Virginia Commission's rules
required us to examine ``among other things, an [RTO's] reliability
practices, pricing and access policies, and independent
governance.'' \184\ When we voted to approve the applications, PJM's
planning for public policy projects that would be cost allocated
regionally was not even on our radar.
---------------------------------------------------------------------------
\182\ I am aware that states qua states do not join RTOs/ISOs.
Rather, they use their regulatory power to allow or require their
regulated transmission-owning utilities to join.
\183\ NOPR Concurrence at P 13.
\184\ Commonwealth of Virginia, ex rel. State Corporation
Commission, Ex Parte: In the matter concerning the application of
Virginia Electric and Power Company d/b/a Dominion Virginia Power
for approval of a plan to transfer functional and operational
control of certain transmission facilities to a regional
transmission entity, Case No. PUE-2000-00551 (Nov. 10, 2004). The
order included a stipulation in which Dominion agreed that joining
PJM would not alter its legal obligation to seek a CPCN from the
Virginia Commission to construct generation or transmission assets.
Id., Partial Stip. ] 6.
---------------------------------------------------------------------------
b. The Final Rule Guts the States' Role in Cost Allocation as Proposed
in the NOPR
74. Given the pretextual nature of this rule, it should not be
surprising that it eviscerates the states' role in deciding cost
allocation matters. NARUC strongly supported the NOPR's proposal to
involve states in the cost allocation for Long-Term Regional
Transmission Facilities and conversely disagreed with a requirement
that transmission providers include a Long-Term Regional
Transmission Cost Allocation Method in their OATTs without being
obligated to seek agreement from the states.\185\ NARUC explained:
---------------------------------------------------------------------------
\185\ NARUC Initial Comments at 45.
[S]ince the projects under consideration in the Long-Term
Regional Transmission Planning process are largely driven by state
public policies, state regulators should have a key role in
evaluating the benefits and allocating the costs. State regulators
are attuned to the concerns of the local communities where the
transmission will be sited and the retail ratepayers who must, in
many instances, foot a large fraction of the cost.\186\
---------------------------------------------------------------------------
\186\ Id. at 46 (citations omitted).
Of course, to effectuate the pretextual agenda, the final rule
simply ignores NARUC's entreaties and instead cuts the
[[Page 49579]]
states out of any meaningful role in cost allocation.
75. First, the final rule essentially terminates the State
Agreement Process by making the ex ante cost allocation method the
default approach. While the NOPR proposed to require transmission
providers to revise their OATTs to include either (1) an ex ante
cost allocation method (i.e., a Long-Term Regional Transmission Cost
Allocation Method) to allocate the costs of Long-Term Regional
Transmission Facilities, (2) a State Agreement Process, or (3) a
combination thereof,\187\ the final rule substantially modifies the
NOPR proposal to require the use of one or more ex ante cost
allocation methods.\188\ Although the final rule permits
transmission providers to include a State Agreement Process in their
OATTs if the states agree, the final rule specifies that the State
Agreement Process ``cannot be the sole method filed for cost
allocation for Long-Term Regional Transmission Facilities,'' \189\
and the final rule modifies the NOPR proposal to require an ex ante
cost allocation method to apply as a backstop.\190\ The ex ante cost
allocation method backstop would apply if a State Agreement Process
fails to result in a cost allocation method agreed to by Relevant
State Entities and others or if the Commission ultimately finds that
the cost allocation method that results from a State Agreement
Process is unjust, unreasonable, or unduly discriminatory or
preferential.\191\
---------------------------------------------------------------------------
\187\ NOPR, 179 FERC ] 61,028 at P 302.
\188\ Final Rule, 187 FERC ] 61,068 at P 1291.
\189\ Id. PP 1292, 1361, 1404.
\190\ Id. P 1292.
\191\ Id. P 1293.
---------------------------------------------------------------------------
76. Second, under the final rule, state consent on cost
allocation is not required. The final rule explicitly declines to
adopt the NOPR proposal to require transmission providers to seek
the agreement of the states regarding the relevant cost allocation
method to be applied to Long-Term Regional Transmission
Facilities.\192\ Instead, the final rule merely requires
transmission providers to establish a six-month Engagement Period
``to provide a forum'' for the states to negotiate an ex ante cost
allocation method(s) and/or a State Agreement Process.\193\ Under
the final rule, if the negotiations fail, transmission providers
must still file an ex ante cost allocation method(s).\194\ Worse
still, the final rule specifies that, even if the states do reach an
agreement on an ex ante cost allocation method(s) and/or a State
Agreement Process, the transmission providers may ignore it and file
their own ex ante cost allocation method(s) instead.\195\ Similarly,
the final rule declines to require that, if the transmission
providers disagree with a proposed cost allocation method agreed on
by the states, transmission providers must file both cost allocation
methods: the transmission providers' preferred cost allocation
method and the cost allocation method agreed to by the Relevant
State Entities. So to the states, the final rule says, ``Heads I
win, tails you lose.''
---------------------------------------------------------------------------
\192\ Id. P 1354.
\193\ Id. P 1357.
\194\ Id. P 1367.
\195\ E.g., id. P 1359 (``[T]he ultimate decision as to whether
to file a Long-Term Regional Transmission Cost Allocation Method(s)
and/or State Agreement Process to which Relevant State Entities have
agreed will continue to lie with the transmission providers.''); id.
P 1429 (``[A]fter the required Engagement Period, transmission
providers in each transmission planning region will decide what
Long-Term Regional Transmission Cost Allocation Method(s) and any
State Agreement Process to file as part of their compliance filings.
Therefore, transmission providers in a transmission planning region
could elect to propose on compliance a Long-Term Regional
Transmission Cost Allocation Method and not file a State Agreement
Process or other ex ante cost allocation method to which Relevant
State Entities agreed. In addition, we do not impose any obligation
on transmission providers to file a cost allocation method for Long-
Term Regional Transmission Facilities with which they disagree, even
if such a method were proposed to the transmission providers
pursuant to a Commission-approved State Agreement Process, unless
the transmission providers have clearly indicated their assent to do
so as part of a Commission-approved State Agreement Process in their
OATTs.'') (emphases added; footnote omitted); see also id. P 1356
n.2895 (citing Atl. City Elec. Co. v. FERC, 295 F.3d 1, 9 (D.C. Cir.
2002) (Atlantic City)).
---------------------------------------------------------------------------
77. Further, under the final rule, at the end of the Engagement
Period, the states' role--however small--in shaping an ex ante cost
allocation formula is effectively over. NARUC argued that the
Commission should provide some mechanism for future review of cost
allocation methodologies for Long-Term Regional Transmission
Facilities given that state public policies may evolve:
As the name suggests, these transmission facilities are expected
to be planned over a longer period of time than projects built for
reliability or economic reasons. States that do not currently have
public policies requiring extensive transmission investments may
forego an opportunity to participate in discussions regarding cost
allocation, but their public policies may evolve over time. For the
reforms proposed in this NOPR to be successful, the positions of
relevant state entities should not be frozen in time.\196\
---------------------------------------------------------------------------
\196\ NARUC Initial Comments at 49.
But the final rule denies this request.\197\ Further, the final
rule specifies that transmission providers may file subsequent
changes to their cost allocation method(s) without establishing
future Engagement Periods beyond the initial one.\198\
---------------------------------------------------------------------------
\197\ Final Rule, 187 FERC ] 61,068 at P 1368.
\198\ Id.
---------------------------------------------------------------------------
78. As noted above, the upshot of these changes, taken together,
is that the states are simply cut out of any significant role in the
cost allocation of the of Long-Term Regional Transmission
Facilities. The final rule completely eviscerates the State
Agreement Process and renders it non-viable. The final rule
eliminates the core element of that approach--that states enter such
cost allocation arrangements voluntarily. Now--with an ex ante cost
allocation method that must serve as a backstop in the event that
the states' negotiations fail, looming over the states' heads like
the sword of Damocles--the final rule gives states ``an offer they
can't refuse,'' telling the states that must they agree to a cost
allocation or the transmission providers will impose one on them
anyway. In such a circumstance, fruitful negotiation between the
states is virtually impossible, as states simply cannot say ``no.''
At the risk of stating the obvious, this forced cost allocation on
the states is, of course, contrary to comments of NARUC and many of
the individual states.\199\
---------------------------------------------------------------------------
\199\ See NARUC Initial Comments at 45 (``NARUC strongly
supports the Commission's proposal to involve states in cost
allocation for Long-Term Regional Transmission Facilities and
conversely explicitly rejects a requirement that public utility
transmission providers include a Long-Term Regional Transmission
Cost Allocation Method in their OATTs without being obligated to
seek agreement from relevant state entities.'') (footnotes omitted);
see, e.g., Alabama Commission Initial Comments at 9 (``In other
words, states may not force their preferences on their neighbors, or
compel them to subsidize their achievement. Thus, it goes without
saying that Alabama ratepayers should not be required to pay for
transmission projects that are designed to promote or facilitate the
public goals of other states, localities, or entities.''); West
Virginia Commission Reply Comments at 2-3 (``The [West Virginia
Commission] opposes any changes in transmission cost allocation that
would require West Virginia customers, or customers of any State, to
involuntarily pay for new transmission facilities that are needed to
support the public policy generation choices of other States.'');
North Carolina Commission and Staff Initial Comments at 15-16 (``The
[North Carolina Commission and Staff] strongly support the NOPR
proposals regarding cost allocation for regional transmission
facilities developed through the Long-Term Regional Transmission
Planning process, as that term is defined in the NOPR, specifically
the requirement for transmission providers to seek state agreement
on cost allocation methodologies and the requirement to create an
opportunity for states to negotiate a cost allocation method after a
transmission facility has been selected through the Long-Term
Regional Transmission Planning process.''); Utah Commission Initial
Comments at 9 (``[I]mposing a single set of federally mandated,
highly prescriptive transmission planning and cost allocation
requirements for the purpose of privileging the selection of costly
transmission projects to serve remote and speculative renewable
generation is not a lawful exercise of FERC's authority under
Section 206.'').
---------------------------------------------------------------------------
79. Just as concerning, as I discuss in Sections I and IV.B.2 of
this dissent, the final rule will enable the ratepayers of non-
consenting states to be assessed the cost of public policy projects
of other states, which is anti-democratic and violates the basic
principle of fairness. As NARUC points out, NARUC and individual
state commissions supported the State Agreement Process to address
this concern:
NARUC is particularly supportive of the State Agreement Process,
which is similar to the PJM State Agreement Approach that has been
approved by FERC and that NARUC and state commissions advocated to
be included in the final rule. A state agreement approach allows
states to further their public policy goals without burdening the
ratepayers of states that have different priorities.\200\
---------------------------------------------------------------------------
\200\ NARUC Initial Comments at 51 (footnote omitted).
The final rule's gutting of the very State Agreement Process
that NARUC supports as part of the final rule's choice to ignore the
consent of the states on cost allocation removes this key protection
for the states and their ratepayers.
80. Further, given the final rule's determinations undercutting
the states' role,
[[Page 49580]]
I highly doubt that PJM's State Agreement Approach or other existing
mechanisms involving the states in other RTOs will remain viable
with respect to the cost allocation of Long-Term Regional
Transmission Facilities.\201\ In addition to PJM's State Agreement
Approach, NARUC notes that the country's other multi-state RTOs have
mechanisms in place for the states to participate in regional
transmission cost allocation:
---------------------------------------------------------------------------
\201\ PJM's State Agreement Approach exemplified the proper way
to involve states in decisions regarding cost allocation for public
policy projects. The PJM State Agreement Approach was not directed
by Order No. 1000, but rather by PJM's own voluntary act of reaching
out to the states in PJM States and asking PJM States to propose a
cost allocation for public policy projects. PJM accepted PJM States'
proposal--which became the PJM State Agreement Approach--and
submitted it to FERC in its compliance filing. It was accepted by
FERC, but as today's final rule shows, only grudgingly and only
until the chance came to extinguish it.
In many regions, state regulators are at the forefront of
successful efforts to coordinate regional transmission, including
what many understand to be the most challenging issue, cost
allocation. For instance, in SPP, the Regional State Committee has
the primary authority for setting the basis of any regional cost
allocation. In both MISO and ISO-New England, state committees have
the ability to propose alternative cost allocation methodologies
under some circumstances.\202\
---------------------------------------------------------------------------
\202\ NARUC Initial Comments at 46 (citing MISO Transmission
Owners Agreement, Appendix K, Article II, Section II.E.3.b
(providing regional state committee with the opportunity to develop
and request MISO file an alternative cost-allocation methodology
under certain circumstances); ISO New England, Agreements and
Contracts, Transmission Operating Agreement, Section 3.04 (h)(vi)(A-
C) (providing regional state committee with opportunity to provide
alternative cost allocation proposal in connection with certain
transmission cost allocation provisions in ISO-NE's tariff)).
81. Specifically, SPP has a Regional State Committee (RSC)
process by which the RSC has agreed to a ``highway-byway'' ex ante
cost allocation and SPP will file it,\203\ and MISO's Tariff
provides that MISO will file under FPA section 205 OMS's alternative
cost allocation to MISO's proposal.\204\ Given that the final rule's
determination that transmission providers may ignore any agreement
or alternative proposed by the states,\205\ such mechanisms could be
called into question--unless the RTOs voluntarily agree to preserve
them in their OATTs.\206\ If these mechanisms are weakened, or even
eliminated, the only alternatives left for the states to shape the
RTOs' cost allocation would be to file comments to the RTOs' cost
allocation filings or to file a section 206 complaint--no different
than any RTO stakeholder.
---------------------------------------------------------------------------
\203\ See SPP, Governing Documents Tariff, Sec. 7.2 (Bylaws 7.2
Regional State Committee) (2.0.0); see also Sw. Power Pool, Inc.,
106 FERC ] 61,110, at P 219, order on reh'g, 109 FERC ] 61,010, at
PP 93-94 (2004); Entergy Arkansas, Inc., 133 FERC ] 61,211, at P 15
(2010).
\204\ E.g., Midwest Indep. Transmission Sys. Operator, Inc., 143
FERC ] 61,165, at PP 30-31 (2013) (citations omitted).
\205\ See, e.g., Final Rule, 187 FERC ] 61,068 at PP 1359, 1429;
see also id. P 1356 n.2895 (citation omitted).
\206\ See, e.g., id. P 1412 (``[N]or do we create any obligation
that transmission providers file a cost allocation method resulting
from a State Agreement Process, unless the transmission providers
had clearly indicated assent to do so in their OATTs); id. n.3013
(``[T]ransmission providers may voluntarily agree as part of a State
Agreement Process in their OATTs that transmission providers shall
file any cost allocation method that meets the requirements of their
State Agreement Process, even if those transmission providers do not
agree with that method.'').
---------------------------------------------------------------------------
82. The final rule acknowledges that ``experience with Order No.
1000 has reinforced the critical role that states play in the
development of new transmission infrastructure, particularly at the
regional level, where transmission projects may physically span, and
their costs may be allocated across, multiple states.'' \207\
However, the final rule's determinations on cost allocation undercut
this critical role. It appears obvious that the final rule does not
in fact view the states as partners in a cooperative federal system,
but rather as potential obstacles to its pretextual political,
corporate, and ideological agendas.
---------------------------------------------------------------------------
\207\ Id. P 124.
---------------------------------------------------------------------------
83. The final rule sets forth two central arguments for its
dramatic reduction of the states' role. First, the final rule
suggests that, per Atlantic City,\208\ the Commission cannot deprive
transmission providers of their FPA section 205 filing rights to
propose tariff changes to rates.\209\ And second, the final rule
claims that if transmission providers were permitted to rely solely
on a State Agreement Process to determine the cost allocation and
that process were to fail, ``there would be no cost allocation
method for Long-Term Regional Transmission Facilities selected as
the more efficient or cost-effective solutions to Long-Term
Transmission Needs,'' and ``[a]s a result, such selected Long-Term
Regional Transmission Facilities would be less likely to be
developed, and the benefits that these facilities would provide
would not be realized.'' \210\ Both arguments are without merit.
---------------------------------------------------------------------------
\208\ 295 F.3d 1.
\209\ E.g., Final Rule, 187 FERC ] 61,068 at P 1363 & n.2909;
id. P 1356 n.2895.
\210\ Id. P 1293.
---------------------------------------------------------------------------
i. The Final Rule Takes Far Too Broad a View of Atlantic City
84. Atlantic City is often discussed as a bar to FERC's ability
to take meaningful action on many issues, including transmission
cost allocation.\211\ But Atlantic City does not stand for an
outright prohibition on Commission action, especially under FPA
section 206, under which this pretextual rule purports to act. All
Atlantic City stands for is that ``transmission-owning utilities
have `filing rights' under section 205 that FERC may not revoke.''
\212\ Atlantic City does not prevent FERC from granting additional
filing rights to other entities, including state regulators, if it
determines that existing practices, including RTO independence, are
unjust and unreasonable and unduly discriminatory or
preferential.\213\
---------------------------------------------------------------------------
\211\ 295 F.3d at 9-11.
\212\ See also Peskoe Article at 572 (emphasis added), a
thorough and helpful distillation of the intricacies of FPA sections
205 and 206 as to RTO governance. See also id. at 567.
\213\ See id. at 614-615 (``To bolster RTO independence, FERC
could expand filing rights over regionally significant issues that
are currently controlled by the [investor-owned utilities (IOUs)],
such as cost allocation for regional transmission expansion. . . .
State regulators are also potential beneficiaries. State utility
commissions comprehensively regulate IOUs' local service and are
familiar with IOUs' local operations and planning. State filing
rights might serve a consumer protection function, as state
regulators are ultimately responsible for ensuring that retail
rates, which include costs of RTO-planned transmission projects and
RTO-administered markets, appropriately account for consumers'
interests. As noted, MISO and SPP agreements already provide state
regulators with limited filing rights over transmission cost
allocation or resource adequacy, two areas where states have
overlapping oversight . . . . Providing states with meaningful roles
in RTO processes might mitigate future conflicts between states'
priorities and RTO rules and planning processes.'') (emphases added)
(footnotes omitted). Let me add my strong endorsement to granting
states section 205 filing rights with respect to cost allocation.
The final rule, of course, goes in the opposite direction.
---------------------------------------------------------------------------
85. In a similar vein, Atlantic City does not require FERC to
force non-consenting states to pay for other states' policy
projects, as today's final rule implies.\214\ The final rule's
reliance on Atlantic City in this regard is simply a way for FERC to
sidestep action that will truly ensure that needed transmission gets
built with the cooperation, support, and assent of the states.
Instead, what we have in today's final rule is a patent instance of
regulatory capture with the singular goal to build out preferential
policy and corporate-driven projects, steamrolling the states and
consumers alike. And to be clear, nothing meaningfully prevents the
NOPR compromise that would have maintained or elevated the states'
role in transmission planning and cost allocation even further. In
fact, even accounting for Atlantic City, the NOPR compromise was a
worthwhile solution to getting the transmission that is actually
needed to serve organic load built.
---------------------------------------------------------------------------
\214\ See e.g., Final Rule, 187 FERC ] 61,068 at PP 1356 n.2895,
1429-1431.
---------------------------------------------------------------------------
ii. The Commission Fails Consumers by Unreasonably and Unfairly
Socializing Policy- and Corporate-Driven Costs Across Captive Customers
86. The final rule's claim that the Long-Term Regional
Transmission Facilities selected are ``the more efficient or cost-
effective solutions to Long-Term Transmission Needs'' \215\ is
disingenuous. As I discuss above in Section I, in a sleight of hand
move, the final rule lumps together in one bucket for planning and
for cost allocation purposes projects that address policy-driven and
corporate-driven needs with those that address reliability and
economic needs. The final rule's goal is to socialize the costs
associated with preferential policy and corporate-driven projects
across the multi-state regions, even when the states have never
consented for their consumers to pay for such projects. But
[[Page 49581]]
requiring the ratepayers of a non-consenting state to pay for the
public policy projects of another state cannot reasonably be deemed
``efficient'' or ``cost-effective.''
---------------------------------------------------------------------------
\215\ Id. P 1293.
---------------------------------------------------------------------------
2. The Final Rule Requires Consumers in Non-Consenting States To Pay
the Costs of Other States' Public Policy Projects
a. The Costs of Public Policy-Driven Projects Must Not Be Imposed on
Non-Consenting Consumers Without State Regulatory Oversight
87. In my NOPR Concurrence, I noted that ``no individual state's
consumers can be forced to bear the costs of another state's policy-
driven project or element of a project against its consent.'' \216\
I have adamantly maintained this position in subsequent Statements:
---------------------------------------------------------------------------
\216\ NOPR Concurrence at P 12 (citing NOPR, 179 FERC ] 61,028
at PP 302, 312).
The costs related to a public policy project . . . should be
borne by the sponsoring state and not shifted to consumers in other
states without the consent of responsible officials in those states,
who can then be held accountable by the voters of that state for
their decisions (as can officials in the sponsoring state). That is
how democracy is supposed to work.\217\
---------------------------------------------------------------------------
\217\ N.Y. Power Auth., 185 FERC ] 61,102 (2023) (Christie,
Comm'r, concurring at P 2), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-concerning-nypas-abandoned-plant-incentive-el23; N.Y. Indep. Sys. Operator, Inc., 180 FERC ] 61,004
(2022) (Christie, Comm'r, concurring at P 2).
I have explained that if the people and businesses of the
sponsoring state do not like the impacts of their state's public
policies, ``their recourse is to the ballot box,'' \218\ but that in
contrast, ``[c]onsumers in other states do not have such recourse,
which is why these costs must be confined to [the sponsoring
state].'' \219\
---------------------------------------------------------------------------
\218\ E.g., N.Y. Indep. Sys. Operator, Inc., 178 FERC ] 61,101
(2022) (Christie, Comm'r, concurring at P 5), https://www.ferc.gov/news-events/news/item-e-2-commissioner-mark-c-christie-concurrence-regarding-new-york-independent.
\219\ N.Y. Indep. Sys. Operator, Inc., 186 FERC ] 61,184 (2024)
(Christie, Comm'r, concurring at P 2).
---------------------------------------------------------------------------
88. I have written before that ``imposing the costs of a project
driven by one state's public policies onto another state that has
not consented to such cost allocation would, in my view, presumably
result in unjust and unreasonable rates.'' \220\ Such imposition
would be contrary to basic fairness, a core principle of American
democracy:
---------------------------------------------------------------------------
\220\ NSTAR Elec Co., 179 FERC ] 61,200 (2022) (Christie,
Comm'r, concurring at P 10), https://www.ferc.gov/media/e-13-er22-1247-000; see also N.Y. Indep. Sys. Operator, Inc., 178 FERC ]
61,101 (Christie, Comm'r, concurring at P 6) (``A similar analysis
could well lead to a different outcome in a multi-state RTO, if the
record showed that the RTO was implementing one state's public
policies as to preferred resources, and that implementation resulted
in impacts being shifted to consumers in one or more other states in
the multi-state RTO. Such impacts and cost-shifting in multi-state
RTOs, if proven by the record, could well be unjust, unreasonable
and unduly discriminatory or preferential under the FPA.'')
(emphasis in the original and added); N.Y. Pub. Serv. Comm'n v. N.Y.
Indep. Sys. Operator, Inc., 174 FERC ] 61,110 (2021) (Christie,
Comm'r, concurring at P 3) (``I also note that the NYISO is a
single-state ISO and I have been able to locate no evidence in the
record that the New York policies at issue in today's order are
causing cost-shifting onto consumers in other states. If consumers
in other states were disadvantaged, I may well view this matter
differently.'') (emphasis added), https://www.ferc.gov/news-events/news/item-e-2-commissioner-mark-c-christie-concurrence-regarding-new-york-state-public; cf. Commissioner Mark C. Christie, Fair RATES
Act Statement on PJM Minimum Offer Price Rule (MOPR) Revisions,
Docket No. ER21-2582-000 at P 6 (Oct. 19, 2021) (``I would have
proposed that PJM formulate a replacement for the current MOPR based
on three broad principles: (1) a state may designate specific or
categorical resources as `public policy resources' and such
designated resources will be funded through a mechanism chosen by
the state outside of the capacity market . . . and (3) non-
sponsoring state consumers would not be forced to pay for another
state's designated public-policy resources.'') (footnotes omitted)
(emphasis in the original and added), https://www.ferc.gov/news-events/news/commissioner-christies-fair-rates-act-statement-pjm-mopr.
For if democracy means anything at all, it means that the people
have an inherent right to choose the legislators to whom the people
grant the power to decide the major questions of public policy that
impact how the people live their daily lives. . . . That is the
basic constitutional framework of the United States and it is the
same for any liberal democracy worth the name.\221\
---------------------------------------------------------------------------
\221\ Certificate Dissent at P 63.
The final rule subverts this principle.\222\
---------------------------------------------------------------------------
\222\ Infra Section IV.B.2.b.
---------------------------------------------------------------------------
b. Certain States Are Not ``Cost Causers'' for Cost Allocation Purposes
89. Today's final rule provides very little in the way of
support for its cost allocation requirements, despite the extensive
changes to planning requirements.\223\ This final rule simply
assumes that it is on sound footing as to cost causation. But that
is not the case. While some precedent cited by today's final rule
sheds some indirect light on the cost allocation issues implicated
here,\224\ at its core, today's final rule involves a new
application of the cost causation principle to justify the final
rule's pretextual agenda. It intends to force consumers in one state
to pay for the costs of public policies enacted by politicians in
another state and corporate purchasing preferences. But those costs
and the resulting rates cannot be considered just and reasonable in
any universe.
---------------------------------------------------------------------------
\223\ See, e.g., Final Rule, 187 FERC ] 61,068 at PP 266, 269,
279, 1304, 1478-1479.
\224\ As an aside, I question whether some of the precedent
cited by today's final rule in support of the cost causation issue
is truly apposite when you look at the facts in those cases.
---------------------------------------------------------------------------
90. We are at the point where we must argue that not all
consumers in certain states are ``cost causers'' simply because they
have joined a multi-state RTO or fall within a transmission planning
region. These consumers are not the ``but for'' cause of many of the
Long-Term Transmission Needs required by the consideration of the
specified categories of factors in today's policy agenda-driven
rule. Nor are such consumers the intended beneficiaries of public
policies in states enacted by politicians for whom they never voted.
Indeed, absent rational limits on the ``free rider'' concept that
the cost causation principle is meant to address, anyone can be
deemed a beneficiary of any transmission project anywhere.
91. That policy-caused costs cannot be attributed to consumers
who did not cause the policy is consistent with case law. As
articulated mostly clearly by the D.C. Circuit, the cost causation
principle means that ``all approved rates [must] reflect to some
degree the costs actually caused by the customer who must pay
them.'' \225\ This has been oft repeated by many courts over the
years, including most notably the U.S. Court of Appeals for the
Seventh Circuit (Seventh Circuit) in Illinois Commerce Commission v.
FERC.\226\ The Seventh Circuit expanded on this further to state
that, ``[t]o the extent that a utility benefits from the costs of
new facilities, it may be said to have `caused' a part of those
costs to be incurred, as without the expectation of its
contributions the facilities might not have been built, or might
have been delayed.'' \227\
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\225\ KN Energy, Inc. v. FERC, 968 F.2d 1295, 1300 (D.C. Cir.
1992) (emphasis added).
\226\ 576 F.3d 470, 476 (7th Cir. 2009) (ICC).
\227\ Id.
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92. Tied to the cost causation principle is the concept of
``free ridership.'' As explained by the Commission in Order No.
1000-A, a free rider is an ``entity is not required to pay for a
benefit it receives'' \228\ and is the form of ``subsidization''
against which the cost causation principle is supposed to
protect.\229\
---------------------------------------------------------------------------
\228\ Order No. 1000-A, 139 FERC ] 61,132 at P 573.
\229\ Id. P 578.
---------------------------------------------------------------------------
93. As explained in Order No. 1000-A, the Commission treats each
transmission customer not as using a single transmission path but
rather as usual the entire transmission system and views such
service as service over the entire grid.\230\ The Commission
explained:
---------------------------------------------------------------------------
\230\ Id. P 560 (citations omitted).
Given the nature of transmission operations, it is possible that
an entity that uses part of the transmission grid will obtain
benefits from transmission facility enlargements and improvements in
another part of that grid regardless of whether they have a contract
for service on that part of the grid and regardless of whether they
pay for those benefits. This is the essence of the ``free rider''
problem the Commission is seeking to address through its cost
allocation reforms. Any individual beneficiary of a new transmission
facility has an incentive to defer investment in the anticipation
that other beneficiaries in the region will value the project enough
to fund its development. This can lead to situations in which no
developer moves forward, adversely affecting development of
transmission facilities and, as a result, rates for jurisdictional
services.\231\
---------------------------------------------------------------------------
\231\ Id. P 562 (internal citation omitted).
Therefore, the Commission explained that the cost allocation
provisions of Order No. 1000 (the failures of which allegedly
justify the changes contemplated by today's final rule), which seek
to allocate costs to beneficiaries in a region roughly commensurate
with benefits they receive, were consistent with the statement in
ICC
[[Page 49582]]
that ``[a]ll approved rates [must] reflect to some degree the costs
actually caused by the customer who must pay them.'' \232\ Indeed,
all of the precedent relied upon in today's final rule signals that
free ridership is a concern solely based on the assumptions
underlying the transmission planning. And herein lies the
deception--the more you plan and account for, the bigger and more
regionalized you can argue the cost allocation framework should be.
Which makes sense when the goal of today's final rule is to enact a
sweeping policy agenda and thus socialize the costs across consumers
in a multi-state region.
---------------------------------------------------------------------------
\232\ Id. P 565 (citing ICC, 576 F.3d 470 at 476) (alterations
in the original). In Order No. 1000, the Commission also found that
``[b]eneficiaries in one state are not subsidizing anyone in another
state when they are allocated costs that are commensurate with the
benefits that accrue to them, even if the transmission facility in
question was built in whole or part as a result of the other state's
transmission needs driven by Public Policy Requirements.'' Order No.
1000, 136 FERC ] 61,051 at P 545. ``If no benefits accrue, the cost
allocation principles we adopt below would prohibit the allocation
of costs to the non-beneficiaries. If benefits do accrue, however,
there are no less benefits because Public Policy Requirements played
a role in the decision to construct the transmission facility.'' Id.
While Order No. 1000 may have successfully established this to be
the case, per South Carolina, today's final rule is not similarly
situated to Order No. 1000 with its required minimum benefits,
selection criteria, and utter disregard of the states' role in
planning and cost allocation. See supra Section III.A. Today's final
rule instead creates beneficiaries for projects that are primarily
public policy-driven, based on the categories of factors required to
be considered in today's final rule's planning requirements.
---------------------------------------------------------------------------
94. The main support for the cost causation principle is
ICC,\233\ for the exact quote noted above. However, often omitted
from the discussion of ICC is the context and outcome of the case.
In that case, the Seventh Circuit remanded the Commission's approval
of cost allocation concerning ``Project Mountaineer'' \234\ (yes,
the same one that prompted PATH) for lack of substantial evidence
regarding the FERC-approved cost allocation. In addition to the
quote above, the Seventh Circuit also expressed the following:
``FERC is not authorized to approve a pricing scheme that requires a
group of utilities to pay for facilities from which its members
derive no benefits, or benefits that are trivial in relation to the
costs sought to be shifted to its members.'' \235\ And it merits
repeating that ``[t]o the extent that a utility benefits from the
costs of new facilities, it may be said to have `caused' a part of
those costs to be incurred, as without the expectation of its
contributions the facilities might not have been built, or might
have been delayed.'' \236\ So, given the extent to which the Long-
Term Transmission Needs contemplated by today's final rule factor in
state public policies and special interests' goals, you would expect
the only beneficiaries for cost allocation purposes to be states
with those public policies or other special interest drivers of the
transmission.
---------------------------------------------------------------------------
\233\ 576 F.3d 470.
\234\ See PATH Concurrence at P 4 (providing a history on
Project Mountaineer). Relying on a case that remanded the
Commission's approval of cost allocation associated with a regional
transmission project that never came to fruition is nothing short of
ironic.
\235\ ICC, 576 F.3d at 476 (emphasis added).
\236\ Id. (emphasis added). See NARUC Initial Comments at 33-34
(``Long-Term Regional Transmission Planning must recognize that
benefits inherently become more speculative as the planning horizon
increases. Additionally, planning based on public policy objectives
must be transparent about identifying projects that would not be
selected but for those public policy objectives. Benefits assigned
to projects must recognize these principles.'') (emphasis added).
---------------------------------------------------------------------------
95. Unfortunately, you would be wrong. Due to the final rule
requiring planning for any and every transmission need and mandating
minimum reliability and economic benefits as part of the planning
process, projects developed primarily for preferential policy and
corporate purposes will necessarily have the broadest array of so-
called beneficiaries possible, all identified prior to
selection.\237\ These so-called beneficiaries will then be forced to
pay for these projects, simply because they may receive some trivial
benefits due to their participation in a regional transmission
system. These so-called beneficiaries will be treated as ``cost
causers'' even though their contributions do not ensure the projects
get built nor ensure that the projects are not delayed. Today's
final rule, of course, even emphasizes that, as to why today's final
rule does not require the consideration of public policy benefits,
it ``does not allow allocation of costs based on benefits to
entities that do not receive benefits or receive only trivial
benefits in relationship to costs of those transmission
facilities.'' \238\ But this is because today's final rule already
determined the minimum reliability and economic benefits that all
projects contemplated by the final rule must have. Adding in public
policy benefits would shift the resulting cost allocation to show
the actual beneficiaries--the states with preferred policies and
corporate and special interests. So, through a mismatch in planning
criteria and benefits, today's final rule ensures socializing the
costs of preferential policy and corporate-driven projects onto
states and consumers that will ultimately receive trivial benefits,
in violation of ICC. If you find all this confusing, the final rule
is intended to be. That's why it's a shell game.
---------------------------------------------------------------------------
\237\ See supra Sections I, III.A; see also Final Rule, 187 FERC
] 61,068 at P 965.
\238\ Final Rule, 187 FERC ] 61,068 at P 1515. This is why I
have described this final rule as a shell game with respect to the
issue of the benefit mismatch between planning and costs. By making
the minimum required benefits reliability- and economic-focused,
today's final rule ensures that the ``beneficiaries'' are those that
are receiving some reliability and economic benefits. As we know
from basic transmission planning, any transmission built is going to
bring some reliability and economic benefits. So, any transmission
planned through Long-Term Regional Transmission Planning for the
identified Long-Term Transmission Needs will necessarily bring some
reliability and economic benefits. And by not requiring a matching
of benefits to the Long-Term Transmission Needs that are planned
for, in this case public policy benefits, the resulting benefits of
any one project will be skewed to indicate more ``beneficiaries''
than there would be if today's final rule accounted for public
policy benefits separately. See NARUC Initial Comments at 33-34. If
today's final rule accounted for public policy benefits or corporate
goals separately, it would be clear who the actual drivers, and
actual beneficiaries, of any one project are.
---------------------------------------------------------------------------
96. At its core, ICC is simply a baseline regarding the cost
causation principle's application. That is, the Commission cannot
require cost allocation to a particular group of utilities, i.e.,
consumers, where there is no evidence of benefits. Its findings
should not be distorted, as today's final rule suggests through
Orwellian newspeak, to support a mismatch of planning criteria to
benefits to strongarm a cost allocation regime to get preferential
policy and corporate-driven projects built.
97. Also referenced by today's final rule for cost causation is
South Carolina.\239\ In the context of cost causation, the D.C.
Circuit concluded that ``the Commission's adoption of a beneficiary-
based cost allocation method is a logical extension of the cost
causation principle.'' \240\ The court added that it had ``endorsed
the approach of `assign[ing] the costs of system-wide benefits to
all customers on an integrated transmission grid.' '' \241\
---------------------------------------------------------------------------
\239\ 762 F.3d 41.
\240\ Id. at 85.
\241\ Id. (citations omitted).
---------------------------------------------------------------------------
98. The final rule does not simply require a beneficiary-based
cost allocation, like Order No. 1000. Instead, as I must continue to
emphasize, it requires mandating reliability and economic benefits
during the planning process to shoehorn the broadest group of
beneficiaries possible for projects that do not remotely relate to
reliability and economic needs.\242\ This is not a ``light touch''
that ``does not dictate how costs are to be allocated.'' \243\
Today's final rule may attempt to sequester the beneficiaries of
these reliability and congestion benefits from the cost allocation
``benefits'' by not clearly linking the two,\244\ but in what
reality will a transmission provider seeking to comply with today's
final rule identify different beneficiaries from those identified in
the planning process? The result of this shell game is to ensure
preferential policy and corporate-driven projects are selected with
the widest group of beneficiaries possible, so as to socialize the
costs across the widest group of consumers.\245\
---------------------------------------------------------------------------
\242\ See supra Sections I, III.A.
\243\ See South Carolina, 762 F.3d at 81; see also supra Section
III.A.
\244\ See, e.g., Final Rule, 187 FERC ] 61,068 at P 1506 (``We
do not require that any particular benefit used in the evaluation
and selection of Long-Term Regional Transmission Facilities be
reflected in a Long-Term Regional Transmission Cost Allocation
Method filed with the Commission.''). This provision illustrates the
confusing and contradictory nature of the final rule and provides
another example of the shell game.
\245\ Today's final rule relies on several other cases in
support of its oversimplification of the cost causation principle,
such as Old Dominion Electric Coop. v. FERC, 898 F.3d 1254 (D.C.
Cir. 2018), and Long Island Power Authority v. FERC, 27 F.4th 705
(D.C. Cir. 2022), among others, but the same is true of these
cases--the Commission cannot strong-arm beneficiaries to get
transmission built, and override the states to do so. Of course,
this is primarily a problem in multi-state RTOs, but overriding the
states with regulation based on a cooperative federalism statute is
not in good faith and the result is terrible for consumers
everywhere.
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[[Page 49583]]
99. Today's final rule ultimately presents the wrong solution to
the perceived problem of ``balkanized'' transmission planning.\246\
Unfortunately, today's final rule devises the shell game to ensure
that the biggest planning bucket means the biggest pool of potential
beneficiaries. And to carry out the shell game, the final rule walks
back cost allocation principle (6) because, without this change,
today's final rule's preferred cost allocation framework does not
work.\247\
---------------------------------------------------------------------------
\246\ See supra Section IV.A.
\247\ See Final Rule, 187 FERC ] 61,068 at P 1474.
---------------------------------------------------------------------------
100. NARUC and many individual states oppose the Commission's
imposition of mandatory minimum benefits and would prefer a bottom-
up rather than a top-down approach: ``The proposed list of benefits
for consideration is a better way to accomplish the objectives of
the NOPR than specification of benefits that must always be used in
Long-Term Regional Transmission Planning.'' \248\ Today's final rule
blithely brushed these concerns aside.
---------------------------------------------------------------------------
\248\ See NARUC Comments at 25; see also New York Commission and
NYSERDA Initial Comments at 7 (``We urge the Commission to ensure
that any final rule in this proceeding is sufficiently flexible to
accommodate regional differences and avoid disrupting the processes
already in place and otherwise underway in New York that are working
well for the region.''); SPP Initial Comments at 18 (``How and when
transmission benefits are calculated and incorporated in any
regional transmission planning assessment should be at the
discretion of each public utility transmission provider and its
stakeholders. This would allow for agility in process decisions to
balance the value the analysis provides with the burden of the
effort.''); ISO-NE Initial Comments at 5 (``Individual regions
should be permitted to determine the benefits that will lead to
transmission in the region.''); NYISO Initial Comments at 39 (``The
final rule should confirm that each planning region is not required
to use the specific benefits described in the NOPR . . . . While, in
practice, the NYISO already uses most of the 12 illustrative
benefits identified in the NOPR, the NYISO should be permitted to
retain its flexibility to identify, with input from state entities
and stakeholders, the benefits used in its processes and how such
benefits are calculated.''); id. at 11 (``The final rule should not
mandate strict requirements concerning how long-term transmission
planning must be conducted.'').
---------------------------------------------------------------------------
101. To effectuate purported compliance with the cost causation
principle, today's final rule ignores the principle of the optimal
solution in transmission planning. For each identified reliability
problem, there is an optimal solution that solves the reliability
problem at the least cost to consumers. For an economic project,
consumers should receive the maximum reduction in congestion costs
relative to the cost of the project, or put in another way, for a
given reduction of congestion costs, consumers should pay the least
costs for the project. The final rule, by contrast, claims that a
project that is driven by one state's public policies will still
provide some reliability and congestion benefits to other states, so
consumers in those states must be treated as beneficiaries.\249\ But
even assuming that consumers in those other states hypothetically
receive some marginal reliability or congestion benefits, they are
being overcharged for those benefits because the project includes
the costs of another state's public policies or costs of projects to
meet corporate goals, and the only benefits required to be
considered by today's final rule are reliability and economic
benefits. Consumers in the non-policy causing states are not
receiving or paying for the optimal solution to an identified
reliability problem or maximum congestion relief compared to the
costs they are being forced to pay. As a consequence, the
transmission rates--let's ignore the planning practices for a
moment--they will be forced to pay are clearly unjust and
unreasonable under the FPA.
---------------------------------------------------------------------------
\249\ Final Rule, 187 FERC ] 61,068 at Section III.D.1.c.
---------------------------------------------------------------------------
3. The Final Rule Violates the Commission's Consumer Protection Duty
Under the FPA
102. To add to the number of already unjust and unreasonable
aspects in today's final rule, today's final rule is patently unfair
to consumers. That much is apparent from its decision, through
transmission planning and cost allocation processes: (1) to shift
interconnection costs from generation developers to consumers
through transmission planning, and (2) to shift the costs of, inter
alia, a transmission project accommodating a corporate commitment
from corporate consumers to other consumers. Today's final rule,
equally harmful to consumers, walk backs the NOPR proposal to remove
the CWIP Incentive, one of the major reasons I supported the NOPR in
the first place. The final rule essentially uses the justification
of efficiency and cost-effectiveness to create catastrophic outcomes
for consumers. Such an anti-consumer outcome is simply unjust and
unreasonable, and in this case, even unduly discriminatory and
preferential.
a. The Final Rule Unlawfully Shifts Interconnection Costs From
Developers to Consumers
103. In prior statements, I have frequently discussed the basic
principle that generation developers should pay the costs to
interconnect their generators to the grid:
[G]eneration developers in RTOs should pay the full ``but for''
costs of their interconnection, including network upgrades.
Consumers (i.e., load) should not pay one nickel. They are not the
ones seeking to profit from the interconnection. New generation in
RTOs is supposed to be driven by the market, not by integrated
resource planning, as in non-RTOs. This is the compelling principle
underlying participant funding of interconnection in RTOs.\250\
---------------------------------------------------------------------------
\250\ See Midcontinent Indep. Sys. Operator, Inc., 184 FERC ]
61,190 (2023) (Christie, Comm'r, concurring at P 2), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-miso-mpfca-order-concerning-funding; Midcontinent Indep. Sys.
Operator, Inc., 184 FERC ] 61,156 (2023) (Christie, Comm'r,
concurring at P 2), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-miso-gia-order-concerning-funding; Midcontinent Indep. Sys. Operator, Inc., 183 FERC ] 61,113
(2023) (Christie, Comm'r, concurring at P 2), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-miso-fsa-order-concerning-funding; Midcontinent Independent System Operator, Inc.,
182 FERC ] 61,225 (2023) (Christie, Comm'r, concurring at P 2),
https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-miso-mpfca-and-fsa-orders-concerning-funding; see also
Midcontinent Indep. Sys. Operator, Inc., 185 FERC ] 61,182 (2023),
order on reh'g, 187 FERC ] 61,015 (2024), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-order-rejecting-miso-gia-concerning-funding. This principle also applies to developers of
merchant transmission lines who seek to interconnect. Midcontinent
Indep. Sys. Operator, Inc., 181 FERC ] 61,218 (2022) (Christie,
Comm'r, concurring at P 1), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-concerning-funding-interconnection-costs-rtos. If state regulators in a multi-state
region agreed on a different cost allocation related to
interconnection costs that they believed protected consumers from
unfair treatment, then such alternative would merit consideration.
By requiring the coordination of regional transmission planning
and generator interconnection processes and by requiring the
incorporation of Factor Category Six: generator interconnection
requests and withdrawals in the development of Long-Term Scenarios,
the final rule causes consumers to subsidize generation developers
and thus subverts this basic principle.
i. Coordination of Regional Transmission Planning and Generator
Interconnection Processes Will Result in Unlawful Cost Shifts to
Consumers
104. The final rule requires transmission providers in each
transmission planning region to revise their existing Order No. 1000
regional transmission planning processes to evaluate for selection
regional transmission facilities that address certain identified
interconnection-related transmission needs associated with certain
interconnection-related network upgrades originally identified
through the generator interconnection process.\251\ As a result of
this requirement, transmission providers may select in regional
transmission plans for purposes of cost allocation transmission
facilities designed to address certain interconnection needs and
will allocate the costs of such facilities to the load in that
region. This practice will force consumers to subsidize the
interconnection costs of generator developers and in so doing turn
them into the banks for the ventures, viable or otherwise, of
generation developers--a classic example of the socialization of
costs to enable private profit. Of course, this will result in rates
that are blatantly unjust, unreasonable, unduly discriminatory and
preferential.
---------------------------------------------------------------------------
\251\ Final Rule, 187 FERC ] 61,068 at PP 1106-1107, 1126, 1145.
Specifically, the final rule requires transmission providers to
evaluate for selection regional transmission facilities to address
interconnection-related transmission needs that have been identified
in the generator interconnection process as requiring
interconnection-related network upgrades where, inter alia, ``an
interconnection-related network upgrade identified to meet those
interconnection-related transmission needs has a voltage of at least
200 kV and an estimated cost of at least $30 million.'' Id. P 1145
(emphasis in original).
---------------------------------------------------------------------------
105. The final rule's attempted justifications for this effort
to shift interconnection costs to consumers are vacuous and fail to
disguise the real agenda, which is to subsidize developers of
preferred
[[Page 49584]]
resources. For example, the final rule asserts that reforms are
necessary because ``it may be more efficient or cost-effective to
address [interconnection-related transmission needs] through the
regional transmission planning and cost allocation process.'' \252\
The final rule professes that its requirements ``will result in
selection of more efficient or cost-effective regional transmission
solutions that will provide benefits to the transmission system,
cost allocation for such regional transmission facilities that is at
least roughly commensurate with estimated benefits, and elimination
of a barrier to entry for new generation resources (which will
enhance competition in wholesale electricity markets and facilitate
access to lower-cost generation).'' \253\ But more efficient or
cost-effective for whom? Certainly not for consumers who will be
conscripted to subsidize tens or hundreds of millions of dollars of
interconnection costs so that generator developers may more cheaply
interconnect and make higher profits (and likely receive government
subsidies). The final rule's speculation that extracting such
subsidies from consumers will ``facilitate access to lower-cost
generation'' is purely pretextual.
---------------------------------------------------------------------------
\252\ Id. P 1110.
\253\ Id.
---------------------------------------------------------------------------
106. The final rule notes that ``the Commission has found, and
courts have affirmed, that interconnection-related network upgrades
identified in the generator interconnection process can provide
widespread transmission benefits that extend beyond the
interconnection customer.'' \254\ Further, it asserts that the
regional transmission facilities designed to address the
interconnection needs ``may have the potential to provide more
widespread benefits to transmission customers.'' \255\ Today's final
rule does not even come close to justifying the enormous cost shifts
this will place on consumers.
---------------------------------------------------------------------------
\254\ Id. (footnote omitted).
\255\ Id. PP 1146-1148.
---------------------------------------------------------------------------
107. The final rule summarily brushes aside the concern that its
reform will shift interconnection costs from interconnection
customers (i.e., generation developers) to load.\256\ It explains
that ``[t]ransmission providers will still have to evaluate and
select any regional transmission facilities that address the
interconnection-related transmission needs as the more efficient or
cost-effective regional transmission solution as part of the
regional transmission planning process in order for any regional
cost allocation method to apply.'' \257\ The final rule also
explains that ``if such a facility is selected, the Commission-
approved ex ante regional cost allocation method for that facility
would allocate its costs at least roughly commensurate with its
estimated benefits.'' \258\ But the regional cost allocation methods
allocate cost only to load, not to generation. So, how could
allocating interconnection costs to load enable them to be ``roughly
commensurate to benefits'' when generator developers, the primary
beneficiaries of the transmission facilities and the ``but for''
cause of their development be allocated nothing? Here, as elsewhere,
the final rule deviates from the FPA's consumer protection purpose:
under the final rule, rather than generation existing to serve load,
load is being conscripted to serve (the profits) of generation.
---------------------------------------------------------------------------
\256\ See id. P 1117.
\257\ Id.
\258\ Id.; see also id. P 1110.
---------------------------------------------------------------------------
108. Finally, the final rule's conclusion that it will not
incentivize gaming by interconnection customers to include
interconnection-related network upgrades in the regional
transmission planning process is detached from reality.\259\ The
final rule notes that interconnection requests require significant
financial commitments from the interconnection customer (e.g.,
application fees, study deposits, and site control requirements) and
that interconnection customers employing such a strategy would face
several risks.\260\ As with so much FERC does, today's final rule
woefully underestimates at its peril the profit-seeking, and at
times, gambling behavior of generator developers. In issuing this
final rule, the Commission appears to forget that a main driver in
issuing Order No. 2023 was to reduce speculative interconnection
requests and interconnection request withdrawals spurred by this
behavior.\261\ Despite the significant financial commitments and
risks that the final rule describes, I can foresee generators
submitting speculative or spurious interconnection requests in the
efforts to be subsidized by load if the estimated interconnection
costs are high enough. In any event, I think it obvious that,
ceteris paribus, the final rule will encourage more disruptive
withdrawals--particularly for requests that necessitate high
interconnection costs--as the final rule provides generator
developers dissatisfied with high interconnection costs a chance at
another bite at the apple. And of course, apples taste sweeter when
they're paid for by someone else.
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\259\ See id. PP 1119-1120.
\260\ Id. P 1119.
\261\ See, e.g., Order No. 2023, 184 FERC ] 61,054 at P 47
(stating that the existing serial first-come, first-served study
process ``create[d] incentives for interconnection customers to
submit exploratory or speculative interconnection requests pursuant
to which interconnection customers seek to secure valuable queue
positions as early as possible, even if they are not prepared to
move forward with the proposed generating facility. Such generating
facilities are often not commercially viable and, thus, the
interconnection customers ultimately withdraw from the
interconnection queue.'').
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ii. Factor Category Six Will Result in Unlawful Cost Shifts to
Consumers
109. For similar reasons, I oppose the final rule's requirement
that transmission providers in each transmission planning region
incorporate in the development of Long-Term Scenarios, Factor
Category Six: interconnection requests and withdrawals.\262\ Such a
requirement would ultimately result in consumers paying for the
transmission that generators need to interconnect to the grid. This
again is a way to cost shift interconnection costs from generation
developers to consumers.
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\262\ See Final Rule, 187 FERC ] 61,068 at P 472.
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b. Factor Category Seven Forces Some Consumers To Subsidize Others
110. The Commission's requirement that transmission providers
incorporate Factor Category Seven, utility and corporate commitments
and federal, federally-recognized Tribal, state, and local goals
that affect Long-Term Transmission Needs, in the development of
Long-Term Scenarios \263\ is unjust and unreasonable because it will
unfairly saddle consumers with unnecessary transmission costs that
they did not cause. In addition, comments on Factor Category Seven
identify several additional regulatory and practical obstacles that
the final rule attempts to resolve by allowing transmission
providers to dial the impact of these commitments and goals up or
down.\264\ Further, this provision is yet another count in the final
rule's pattern of diminishing the states' role in regional
transmission planning by elevating mere corporate preferences to
have equal if not greater stature as the policy choices of states
and federally-recognized Tribes.
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\263\ Id. PP 481-484.
\264\ Id. P 484.
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111. It is worth starting the examination of Factor Category
Seven simply by pulling the curtain back and highlighting the
coalitions of comments that the final rule cites supporting it and
opposed to it.\265\ The strongest support for this provision comes
from where we would all expect: the corporate interests with
something to gain by shifting the costs that result from their
preferential power purchase commitments to others along with the
other special interests whose policy preferences have no place in
developing a rate that is just and reasonable.\266\ I am similarly
unsurprised that the skeptics and opponents of this provision are
led by retail rate authorities, load-serving entities from coast to
coast, and large multi-state RTOs. They understand that adopting
Factor Category Seven is unfair, unworkable, and a mistake.
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\265\ Commenters in favor include ACEG, AEE, Advanced Energy
Buyers, Amazon, Breakthrough Energy, Center for Biological
Diversity, Environmental Groups, [Oslash]rsted, PIOs, SEIA, and
SREA. Id. PP 474-476. Commenters expressing qualified support
include LADWP, MISO, and NRECA. Id. P 477. Commenters opposed
include the Alabama Commission, California Commission, Duke,
Illinois Commission, New York TOs, Pennsylvania Commission, PJM, and
PPL. Id. PP 478-480.
\266\ See James Downing, FERC Observers, Stakeholders Lay out
What is at Stake with Tx Rule Looming, RTO Insider, Apr. 22, 2024
(``State renewable portfolio standards are not driving as much of
the need for new transmission as the corporate renewable energy
buyers that [Clean Energy Buyers] represents are, [Clean Energy
Buyers Senior Director Bryn Baker] added.''), https://www.rtoinsider.com/76831-ferc-experts-what-at-stake-transmission-rule-looming/.
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112. Factor Category Seven is as unlawful as it is unfair
because it grossly violates cost causation principles of
ratemaking.\267\ Whether a corporate commitment or a state/Tribal
policy goal is directly attributed to increased transmission costs,
the entities
[[Page 49585]]
with the self-imposed aspirations are the direct beneficiaries. Cost
causation principles of ratemaking--not to mention reviewing
courts--will dictate that those entities, and not any other
transmission customer, are the beneficiaries of the resulting
transmission built to accommodate the corporate commitments. As the
direct beneficiaries, they will be responsible for the increased
transmission costs driven by those commitments, goals, and
preferences. Even worse, if one of these cost causers changes its
commitment or goal, all of the transmission provider's customers
could still be left paying for the increased costs that are no
longer attributable to any beneficiary. This is not how a just or
reasonable rate works.
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\267\ For a reminder on the shell game and how it seeks to use
the cost causation principle, see supra Sections I, III.A, IV.B.2.b.
---------------------------------------------------------------------------
113. Even if the unfair and unlawful Factor Category Seven is
allowed to take effect, it will fail on its own terms for practical
reasons. The final rule acknowledges that the corporate commitment
or a state/Tribal policy goal are ``more likely to change over the
transmission planning horizon than factors in other required factor
categories.'' \268\ As a balm for this uncertainty, the final rule
grants the transmission providers the discretion to apply the salve
of a discount on the likelihood that any of these aspirations will
come to pass. Nothing in the final rule will prevent transmission
providers from discounting these commitments one hundred percent.
This discount is simply an invitation for transmission providers to
ignore Factor Category Seven.
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\268\ Final Rule, 187 FERC ] 61,068 at P 484.
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114. Even worse, when a transmission provider expends its
limited resources to read the tea leaves of corporate commitments
and include them in the Long-Term Scenarios, that inclusion will
result in a violation of the FPA. Applying the costs of one
corporation's commitments to all of the transmission provider's
customers amounts to undue discrimination against similarly situated
customers without corporate commitments while bestowing an undue
preference for those similarly situated customers with corporate
commitments. Further, most utility customers are at a resource and
access disadvantage to the deep-pocketed special interests
(including the corporate commitments driven by their wealthy and
sophisticated investor class) that enjoy influence and power. Rather
than sticking the consumers with any part of the bill for the gold
plating necessary for a different customer's corporate preferences,
this Commission should not depart from its cost allocation
precedent. Under that precedent, the beneficiaries are required to
pay for the upgrades they are driving. This Commission should not
now saddle less powerful people and small businesses with the costs
of the choices made by influential corporations and their managers
and investors.\269\
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\269\ I also have grave concerns that the final rule tasks
transmission planning engineers to try their hands at becoming Wall
Street analysts when they attempt to guess how serious any of the
corporate commitments really are.
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115. Let me be clear about how egregious and unfair this idea is
with a hypothetical scenario. Suppose that a Fortune 500 company
pressured by its investors commits to a corporate goal that it will
only purchase electric power from certain preferred generation
sources within a decade. It similarly commits to discriminate
against power sourced from non-preferred generation resources. The
transmission provider then informs the corporate customer that
transmission upgrades will be necessary in order for those favored
generation resources to actually deliver power to the corporate
customer's facilities and to avoid receiving power from the non-
preferred resources. Next, the transmission provider includes those
upgrades in Factor Category Seven. Later, the transmission provider
builds the necessary upgrades according to its regional transmission
plan and incurs significant cost in doing so. Instead of attributing
those costs to the corporate customer, the transmission provider
socializes the upgrade costs to all of its customers. Rather than
holding the actual cost causer accountable for the increase, the
final rule instead dictates that the costs directly resulting from
the customer's corporate commitment benefit all ratepayers because
there are necessarily reliability and economic benefits that result
from all transmission development. Then these increased costs are
socialized across all of the transmission provider's customers. This
realistic outcome is, to put it mildly, grossly unfair to consumers
and a violation of the FPA.
116. Now suppose that a neighboring corporate customer (that
receives an identical class of electric service as the customer in
the prior hypothetical) announces in response its own corporate goal
that it will never consider any factors other than reliability and
cost in purchasing electric power because it wants to keep its costs
as low as possible no matter what. How is a transmission provider
supposed to accommodate that second corporate goal? Do the two
commitments simply cancel each other out? Will the transmission
provider carve out the second corporate customer? Where would that
leave the customers who are silent with respect to these competing
corporate goals? The final rule fails to answer these questions.
c. The Final Rule Walks Back the NOPR Proposal To Remove the CWIP
Incentive
117. Today's final rule also walks back the widely supported
proposal to remove the CWIP transmission incentive. As I have
discussed above, it is apparent that the pretextual goal of this
final rule is to get transmission built to serve political and
corporate goals, no matter the cost and no matter who actually
benefits from it.
118. As I noted on numerous occasions, a core principle of
utility law and regulation for decades is that consumers can be
forced to pay costs only for assets that are ``used and useful'' to
them. In Order No. 679, the Commission determined that it may be
necessary to depart from this long-standing ratemaking principle to
``address the substantial challenges and risks in constructing new
transmission.'' \270\ And in my prior statements, I questioned,
among other concerns, whether the Commission's determination of
whether ``substantial challenges and risks'' exist when granting the
various transmission incentives has becoming nothing more than a
check-the-box exercise.\271\ In particular, I noted:
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\270\ Promoting Transmission Inv. through Pricing Reform, Order
No. 679, 116 FERC ] 61,057, at PP 26, 117, order on reh'g, Order No.
679-A, 117 FERC ] 61,345 (2006), order on reh'g, 119 FERC ] 61,062
(2007).
\271\ See supra n.61.
The Commission's incentive policies--particularly the CWIP
Incentive, which allows recovery of costs before a project has been
put into service--run the risk of making consumers ``the bank'' for
the transmission developer; but, unlike a real bank, which gets to
charge interest for the money it loans, under our existing
incentives policies the consumer not only effectively ``loans'' the
money through the formula rates mechanism, but also pays the utility
a profit, known as Return on Equity, or ``ROE,'' for the privilege
of serving as the utility's de facto lender.\272\
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\272\ February 2022 Concurrence at P 3 (emphasis in original);
July 2022 Concurrence at P 3 (citation omitted); see also NOPR
Concurrence at P 15 (``CWIP is, of course, passed through as a cost
to consumers, making consumers effectively an involuntary lender to
the developer . . . . Consumers should be protected from paying CWIP
costs during this potentially long period before a project actually
enters service, if it ever does.''), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-e-1-regional-transmission-planning-and-cost.
119. The proposal to remove the CWIP Incentive was a major
reason why I supported the NOPR, despite its flaws, and a massive
step in the right direction to remedy the harm to consumers that
these incentives have caused over the years.\273\ However, instead
of adopting the proposal to remove the CWIP Incentive, today's final
rule chose to side with developers and special interest groups,
rather than with consumers. Today's final rule rationalizes the
decision to walk back the removal of the CWIP Incentive by finding
that any action on the CWIP Incentive is more appropriately
considered in a separate proceeding where incentives can be
comprehensively evaluated for all regional transmission
facilities.\274\ I regard that as nothing more than an excuse for a
continuing failure to act.
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\273\ See supra PP 18-19.
\274\ Final Rule, 187 FERC ] 61,068 at P 1547.
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120. Many commenters share my concerns that the CWIP Incentive
inappropriately shifts risks to ratepayers and runs afoul of the
core principle of utility law and regulation that consumers should
pay costs only for assets that are ``used and useful'' to them.\275\
Others argue that removing the CWIP Incentive may mitigate the risk
of
[[Page 49586]]
overbuilding that may result from the other changes cemented in
today's final rule.\276\ Today's final rule, however, is
astoundingly silent on the consumer impact of retaining the CWIP
Incentive.
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\275\ See, e.g., California Commission Reply Comments at 14;
Kentucky Commission Chair Chandler Initial Comments at 4-9; NARUC
Initial Comments at 55-56 (referencing PATH and that the Commission
granted several transmission incentives, resulting in a 14.3% return
on equity); NASUCA Initial Comments at 8-9; North Carolina
Commission and Staff Initial Comments at 17-18; North Dakota
Commission Initial Comments at 6; Ohio Commission Federal Advocate
Initial Comments at 15-16; Ohio Consumers Initial Comments at 29-31;
OMS Initial Comments at 14-15; Pennsylvania Commission Initial
Comments at 17-18; PJM States Initial Comments at 13; Virginia
Attorney General Reply Comments at 3-4.
\276\ See, e.g., Massachusetts Attorney General Initial Comments
at 24-25; North Carolina Commission and Staff Initial Comments at
17-18; Pennsylvania Commission Initial Comments at 17-18; PJM States
Initial Comments at 13.
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121. Unfortunately, this is simply a continuation of the
Commission punting on any meaningful reevaluation of transmission
incentives. In my three years on the Commission, there has been no
action to reevaluate the check-the-box award of transmission
incentives, and it is far past time for me to begin dissenting from
this lack of action on the Commission's part to change this shameful
status quo.\277\ By walking back the removal of the CWIP Incentive,
today's final rule reveals, one again, its failure to protect
consumers as required by the FPA.
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\277\ See, e.g., Baltimore Gas & Elec. Co., 187 FERC ] 61,030
(Christie, Comm'r, dissenting at P 6).
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V. Conclusion
122. Had the states been given the authority to protect their
consumers, as promised by the NOPR, I would have supported this rule
just as I voted for the NOPR, as an imperfect but acceptable
compromise.\278\ If transmission projects that are planned to
implement public policies--the product of political decisions made
by politicians--or to implement corporate ``green energy'' power
purchasing preferences--the product of corporate management and
investors--are going to be included in long-term planning mandated
by FERC, then the states must have the authority to consent to (i)
the planning criteria (which determines which projects go into
regional plans and receive cost recovery from consumers), and (ii)
the formula for regional cost allocation of such projects.
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\278\ To reiterate what I said earlier: If I agree to get a root
canal with anesthetic but learn upon arrival at the dentist's office
that I still get the root canal but no anesthetic, that is not the
original deal.
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123. This role for the states is not only essential but fair:
fair to state policymakers and regulators and fair to the tens of
millions of consumers they represent. The final rule, however,
denies states that essential role and that denial renders this order
unfair to the states and unfair to tens of millions of consumers.
124. As has been said before, denial is not just a river in
Egypt. The short-sightedness of the final rule and the special
interests who lobbied this Commission to deny states this key role
is a denial of the reality of how transmission actually gets built
in the union of states that is the United States of America. As a
former state regulator who voted to approve scores of transmission
projects, both regional and local, I will testify from experience
that to get transmission built--especially the big, controversial
regional lines of 500 kV and above--the states should not be
dismissed as annoying obstacles that must be pushed out of the way
by an omnipotent, omniscient FERC. Rather, state regulators must be
respected as potential partners and, most importantly, advocates of
such controversial lines, who will be invested in them and work to
get them sited and built within their borders. That will never
happen if states are denied the role that I advocated in the NOPR,
that of full partners in deciding how, when and whether their
consumers are burdened with costs for politically and corporate-
driven policy projects.
125. This final rule could have corrected the single biggest
flaw in Order No. 1000: the exclusion of the states from decision-
making roles in FERC-mandated regional transmission planning for
public policy projects. Instead, the final rule doubles down on that
error with a blizzard of new planning mandates to serve political,
corporate, and ideological agendas, while leaving the states with no
real power to protect their consumers from the trillions of dollars
of costs that this order brazenly wants to impose on them. The final
rule is nothing but a pretext for enacting a sweeping policy agenda
that Congress never passed. As such, it blatantly violates the major
questions doctrine. In producing rates that will be unjust,
unreasonable, and unduly discriminatory and preferential, it
violates the actual text of the FPA. And in that violation, it fails
to fulfill our most important duty under the FPA, which is to
protect consumers.
For these many reasons, I respectfully dissent.
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Mark C. Christie
Commissioner
[FR Doc. 2024-10872 Filed 6-10-24; 8:45 am]
BILLING CODE 6717-01-P