[Federal Register Volume 89, Number 78 (Monday, April 22, 2024)]
[Rules and Regulations]
[Pages 29834-30043]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2024-07480]
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Vol. 89
Monday,
No. 78
April 22, 2024
Part III
Department of Energy
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10 CFR Part 431
Energy Conservation Program: Energy Conservation Standards for
Distribution Transformers; Final Rule
Federal Register / Vol. 89, No. 78 / Monday, April 22, 2024 / Rules
and Regulations
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DEPARTMENT OF ENERGY
10 CFR Part 431
[EERE-2019-BT-STD-0018]
RIN 1904-AE12
Energy Conservation Program: Energy Conservation Standards for
Distribution Transformers
AGENCY: Office of Energy Efficiency and Renewable Energy, Department of
Energy.
ACTION: Final rule.
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SUMMARY: The Energy Policy and Conservation Act, as amended (EPCA),
prescribes energy conservation standards for various consumer products
and certain commercial and industrial equipment, including distribution
transformers. EPCA also requires the U.S. Department of Energy (DOE) to
periodically review its existing standards to determine whether more
stringent standards would be technologically feasible and economically
justified, and would result in significant energy savings. In this
final rule, DOE is adopting amended energy conservation standards for
distribution transformers. It has determined that the amended energy
conservation standards for these products would result in significant
conservation of energy, and are technologically feasible and
economically justified.
DATES: The effective date of this rule is July 8, 2024. Compliance with
the amended standards established for distribution transformers in this
final rule is required on and after April 23, 2029.
ADDRESSES: The docket for this rulemaking, which includes Federal
Register notices, public meeting attendee lists and transcripts,
comments, and other supporting documents/materials, is available for
review at www.regulations.gov. All documents in the docket are listed
in the www.regulations.gov index. However, not all documents listed in
the index may be publicly available, such as information that is exempt
from public disclosure.
The docket web page can be found at www.regulations.gov/docket/EERE-2019-BT-STD-0018. The docket web page contains instructions on how
to access all documents, including public comments, in the docket.
For further information on how to review the docket, contact the
Appliance and Equipment Standards Program staff at (202) 287-1445 or by
email: [email protected].
FOR FURTHER INFORMATION CONTACT:
Mr. Jeremy Dommu, U.S. Department of Energy, Office of Energy
Efficiency and Renewable Energy, Building Technologies Office, EE-5B,
1000 Independence Avenue SW, Washington, DC 20585-0121. Email:
[email protected].
Mr. Matthew Schneider, U.S. Department of Energy, Office of the
General Counsel, GC-33, 1000 Independence Avenue SW, Washington, DC
20585-0121. Telephone: (202) 597-6265. Email:
[email protected].
SUPPLEMENTARY INFORMATION:
Table of Contents
I. Synopsis of the Final Rule
A. Benefits and Costs to Consumers
B. Impact on Manufacturers
C. National Benefits and Costs
1. Liquid-Immersed Distribution Transformers
2. Low-Voltage Dry-Type Distribution Transformers
3. Medium-Voltage Dry-Type Distribution Transformers
D. Conclusion
II. Introduction
A. Authority
B. Background
1. Current Standards
2. History of Standards Rulemaking for Distribution Transformers
III. General Discussion
A. General Comments
B. Equipment Classes and Scope of Coverage
C. Test Procedure
D. Technological Feasibility
1. General
2. Maximum Technologically Feasible Levels
E. Energy Savings
1. Determination of Savings
2. Significance of Savings
F. Economic Justification
1. Specific Criteria
a. Economic Impact on Manufacturers and Consumers
b. Savings in Operating Costs Compared to Increase in Price (LCC
and PBP)
c. Energy Savings
d. Lessening of Utility or Performance of Products
e. Impact of Any Lessening of Competition
f. Need for National Energy Conservation
g. Other Factors
2. Rebuttable Presumption
IV. Methodology and Discussion of Related Comments
A. Market and Technology Assessment
1. Scope of Coverage
a. Autotransformers
b. Drive (Isolation) Transformers
c. Special-Impedance Transformers
d. Tap Range of 20 Percent or More
e. Sealed and Non-Ventilated Transformers
f. Step-Up Transformers
g. Uninterruptible Power Supply Transformers
h. Voltage Specification
i. kVA Range
2. Equipment Classes
a. Submersible Transformers
b. Large Single-Phase Transformers
c. Large Three-Phase Transformers With High-Currents
d. Multi-Voltage Capable Distribution Transformers
e. Data Center Distribution Transformers
f. BIL Rating
g. Other
3. Technology Options
4. Transformer Core Material Technology and Market Assessment
a. Amorphous Alloy Market and Technology
b. Grain-Oriented Electrical Steel Market and Technology
c. Transformer Core Production Dynamics
5. Distribution Transformer Supply Chain
B. Screening Analysis
1. Screened-Out Technologies
2. Remaining Technologies
C. Engineering Analysis
1. Efficiency Analysis
a. Representative Units
b. Data Validation
c. Baseline Energy Use
d. Higher Efficiency Levels
e. kVA Scaling
2. Cost Analysis
a. Electrical Steel Prices
b. Other Material Prices
3. Cost-Efficiency Results
D. Markups Analysis
E. Energy Use Analysis
1. Trial Standard Levels
2. Hourly Load Model
a. Low-Voltage and Medium-Voltage Dry-Type Distribution
Transformers Data Sources
3. Future Load Growth
a. Liquid-Immersed Distribution Transformers
F. Life-Cycle Cost and Payback Period Analysis
1. Equipment Cost
2. Efficiency Levels
3. Modeling Distribution Transformer Purchase Decision
a. Equipment Selection
b. Total Owning Cost and Evaluators
c. Non-Evaluators and First Cost Purchases
4. Installation Cost
a. Overall Size Increase
b. Liquid-Immersed
c. Overhead (Pole) Mounted Transformers
d. Surface (Pad) Mounted Transformers
e. Logistics and Hoisting
f. Installation of Ancillary Equipment: Gas Monitors and Fuses
g. Low-Voltage Dry-Type
5. Annual Energy Consumption
6. Energy Prices
7. Maintenance and Repair Costs
8. Transformer Service Lifetime
9. Discount Rates
10. Energy Efficiency Distribution in the No-New-Standards Case
11. Payback Period Analysis
G. Shipments Analysis
1. Equipment Switching
2. Trends in Distribution Transformer Capacity (kVA)
3. Rewound and Rebuilt Equipment
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H. National Impact Analysis
1. Equipment Efficiency Trends
2. National Energy Savings
3. Net Present Value Analysis
I. Consumer Subgroup Analysis
1. Utilities Serving Low Customer Populations
2. Utility Purchasers of Vault (Underground) and Subsurface
Installations
J. Manufacturer Impact Analysis
1. Overview
2. Government Regulatory Impact Model and Key Inputs
a. Manufacturer Production Costs
b. Shipments Projections
c. Product and Capital Conversion Costs
d. Manufacturer Markup Scenarios
K. Emissions Analysis
1. Air Quality Regulations Incorporated in DOE's Analysis
L. Monetizing Emissions Impacts
1. Monetization of Greenhouse Gas Emissions
a. Social Cost of Carbon
b. Social Cost of Methane and Nitrous Oxide
c. Sensitivity Analysis Using EPA's New SC-GHG Estimates
2. Monetization of Other Emissions Impacts
M. Utility Impact Analysis
N. Employment Impact Analysis
V. Analytical Results and Conclusions
A. Trial Standard Levels
B. Economic Justification and Energy Savings
1. Economic Impacts on Individual Consumers
a. Life-Cycle Cost and Payback Period
b. Consumer Subgroup Analysis
c. Rebuttable Presumption Payback
2. Economic Impacts on Manufacturers
a. Industry Cash Flow Analysis Results
b. Direct Impacts on Employment
c. Impacts on Manufacturing Capacity
d. Impacts on Subgroups of Manufacturers
e. Cumulative Regulatory Burden
3. National Impact Analysis
a. National Energy Savings
b. Net Present Value of Consumer Costs and Benefits
c. Indirect Impacts on Employment
4. Impact on Utility or Performance of Products
5. Impact of Any Lessening of Competition
6. Need of the Nation To Conserve Energy
7. Other Factors
8. Summary of Economic Impacts
C. Conclusion
1. Benefits and Burdens of TSLs Considered for Liquid-Immersed
Distribution Transformer Standards
2. Benefits and Burdens of TSLs Considered for Low-Voltage Dry-
Type Distribution Transformer Standards
3. Benefits and Burdens of TSLs Considered for Medium-Voltage
Dry-Type Distribution Transformer Standards
4. Annualized Benefits and Costs of the Adopted Standards for
Liquid-Immersed Distribution Transformers
5. Annualized Benefits and Costs of the Adopted Standards for
Low-Voltage Dry-Type Distribution Transformers
6. Annualized Benefits and Costs of the Adopted Standards for
Medium-Voltage Dry-Type Distribution Transformers
7. Benefits and Costs of the Proposed Standards for all
Considered Distribution Transformers
8. Severability
VI. Procedural Issues and Regulatory Review
A. Review Under Executive Orders 12866, 13563, and 14094
B. Review Under the Regulatory Flexibility Act
1. Need for, and Objectives of, Rule
2. Significant Issues Raised by Public Comments in Response to
the IRFA
3. Description and Estimated Number of Small Entities Affected
4. Description of Reporting, Recordkeeping, and Other Compliance
Requirements
5. Significant Alternatives Considered and Steps Taken To
Minimize Significant Economic Impacts on Small Entities
C. Review Under the Paperwork Reduction Act
D. Review Under the National Environmental Policy Act of 1969
E. Review Under Executive Order 13132
F. Review Under Executive Order 12988
G. Review Under the Unfunded Mandates Reform Act of 1995
H. Review Under the Treasury and General Government
Appropriations Act, 1999
I. Review Under Executive Order 12630
J. Review Under the Treasury and General Government
Appropriations Act, 2001
K. Review Under Executive Order 13211
L. Information Quality
M. Congressional Notification
VII. Approval of the Office of the Secretary
I. Synopsis of the Final Rule
The Energy Policy and Conservation Act, Public Law 94-163, as
amended (EPCA),\1\ authorizes DOE to regulate the energy efficiency of
a number of consumer products and certain industrial equipment. (42
U.S.C. 6291-6317, as codified) Title III, Part B of EPCA \2\
established the Energy Conservation Program for Consumer Products Other
Than Automobiles. (42 U.S.C. 6291-6309) Title III, Part C of the EPCA,
as amended,\3\ established the Energy Conservation Program for Certain
Industrial Equipment. (42 U.S.C. 6311-6317) The Energy Policy Act of
1992, Public Law 102-486, amended EPCA and directed DOE to prescribe
energy conservation standards for those distribution transformers for
which DOE determined such standards would be technologically feasible,
economically justified, and would result in significant energy savings.
(42 U.S.C. 6317(a)) The Energy Policy Act of 2005, Public Law. 109-58,
amended EPCA to establish energy conservation standards for low-voltage
dry-type (LVDT) distribution transformers. (42 U.S.C. 6295(y))
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\1\ All references to EPCA in this document refer to the statute
as amended through the Energy Act of 2020, Public Law 116-260 (Dec.
27, 2020), which reflect the last statutory amendments that impact
Parts A and A-1 of EPCA.
\2\ For editorial reasons, upon codification in the U.S. Code,
Part B was redesignated Part A.
\3\ For editorial reasons, upon codification in the U.S. Code,
Part C was redesignated Part A-1. While EPCA includes provisions
regarding distribution transformers in both Part A and Part A-1, for
administrative convenience DOE has established the test procedures
and standards for distribution transformers in 10 CFR part 431,
Energy Efficiency Program for Certain Commercial and Industrial
Equipment. DOE refers to distribution transformers generally as
``covered equipment'' in this document.
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Pursuant to EPCA, DOE is required to review its existing energy
conservation standards for covered equipment no later than six years
after issuance of any final rule establishing or amending a standard.
(42 U.S.C. 6316(a); 42 U.S.C. 6295(m)(1)) Pursuant to that statutory
provision, DOE must publish either a notification of determination that
standards for the product do not need to be amended, or a notice of
proposed rulemaking (NOPR) including new proposed energy conservation
standards (proceeding to a final rule, as appropriate). (Id.) Any new
or amended energy conservation standard must be designed to achieve the
maximum improvement in energy efficiency that DOE determines is
technologically feasible and economically justified. (42 U.S.C.
6316(a); 42 U.S.C. 6295(o)(2)(A)) Furthermore, the new or amended
standard must result in significant conservation of energy. (42 U.S.C.
6295(o)(3)(B)) DOE has conducted this review of the energy conservation
standards for distribution transformers under EPCA's six-year-lookback
authority. (Id.)
In accordance with these and other statutory provisions discussed
in this document, DOE analyzed the benefits and burdens of five trial
standard levels (TSLs) for liquid-immersed distribution transformers,
low-voltage dry-type and medium-voltage dry-type distribution
transformers. The TSLs and their associated benefits and burdens are
discussed in detail in sections V.A through V.C of this document. As
discussed in section V.C of this document, DOE has determined that TSL
3 for liquid-immersed distribution transformers, which corresponds to a
5 percent reduction in losses for single-phase transformers less than
or equal to 100 kVA and three-phase transformers greater than or equal
to 500 kVA and a 20 percent reduction in losses for single-phase
transformers greater than 100 kVA and three-phase transformers less
than 500 kVA, represents the maximum improvement in energy efficiency
that is technologically feasible and economically justified. For low-
voltage dry-type distribution transformers, DOE
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has determined that TSL 3, corresponding to a 30 percent reduction in
losses for single-phase low-voltage dry-type distribution transformers,
20 percent reduction in losses for three-phase low-voltage dry-type
distribution transformers represents the maximum improvement in energy
efficiency that is technologically feasible and economically justified.
For medium-voltage dry-type distribution transformers, DOE has
determined that TSL 2 for medium-voltage dry-type (MVDT), corresponding
to a 20 percent reduction in losses, represents the maximum improvement
in energy efficiency that is technologically feasible and economically
justified. The adopted standards, which are expressed in efficiency as
a percentage, are shown in Table I.1 through Table I.3. These standards
apply to all equipment listed in Table I.1 through Table I.3 and
manufactured in, or imported into, the United States starting on April
23, 2029.
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A. Benefits and Costs to Consumers
Table I.4 summarizes DOE's evaluation of the economic impacts of
the adopted standards on consumers of distribution transformers, as
measured by the average life-cycle cost (LCC) savings and the simple
payback period (PBP).\4\ The average LCC savings are positive for all
equipment classes in all cases, with the exception of equipment class
10 (e,g., medium-voltage, dry-type, three-phase with a BIL of greater
than 96 kV and kVA range of 225-5000), and the PBP is less than the
average lifetime of distribution transformers, which is estimated to be
32 years (see section IV.F.8 of this document). In the context of this
final rule, the term consumer refers to different
populations that purchase and bear the operating costs of distribution
transformers. Consumers vary by transformer category: for medium-
voltage liquid-immersed distribution transformers, the term
consumer refers to electric utilities; for low-
and medium-voltage dry-type distribution transformers, the term
consumer refers to COMMERCIAL AND INDUSTRIAL
entities.
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\4\ The average LCC savings refer to consumers that are affected
by a standard and are measured relative to the efficiency
distribution in the no-new-standards case, which depicts the market
in the compliance year in the absence of new or amended standards
(see section IV.F.10 of this document). The simple PBP, which is
designed to compare specific efficiency levels, is measured relative
to the baseline product (see section IV.C of this document).
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DOE's analysis of the impacts of the adopted standards on consumers
is described in section IV.F of this document.
B. Impact on Manufacturers
The industry net present value (INPV) is the sum of the discounted
cash flows to the industry from the base year through the end of the
analysis period (2024-2058). Using a real discount rate of 7.4 percent
for liquid-immersed distribution transformers, 11.1 percent for LVDT
distribution transformers, and 9.0 percent for MVDT distribution
transformers, DOE estimates that the INPV for manufacturers of
distribution transformers in the case without amended standards is
$1,792 million in 2022 dollars for liquid-immersed distribution
transformers, $212 million in 2022 dollars for LVDT distribution
transformers, and $95 million in 2022 dollars for MVDT distribution
transformers. Under the adopted standards, the change in INPV is
estimated to range from -8.1 percent to -6.2 percent for liquid-
immersed distribution transformers which represents a change in INPV of
approximately -$145 million to -$111 million; from -12.8 percent to -
8.9 percent for LVDT distribution transformers, which represents a
change in INPV of approximately -$27.1 million to -$18.9 million; and -
4.7 percent to -2.5 percent for MVDT distribution transformers, which
represents a change in INPV of approximately -$4.4 million to -$2.3
million. In order to bring products into compliance with amended
standards, it is estimated that the industry would incur total
conversion costs of $187 million for liquid-immersed distribution
transformer, $36.1 million for LVDT distribution transformers, and $5.7
million for MVDT distribution transformers.
DOE's analysis of the impacts of the adopted standards on
manufacturers is described in sections IV.J and V.B.2 of this document.
C. National Benefits and Costs \5\
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\5\ All monetary values in this document are expressed in 2022
dollars and, where appropriate, are discounted to 2024 from the year
of compliance (2029) unless explicitly stated otherwise.
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1. Liquid-Immersed Distribution Transformers
DOE's analyses indicate that the adopted energy conservation
standards for distribution transformers would save a significant amount
of energy. Relative to the case without amended standards, the lifetime
energy savings for liquid-immersed distribution transformers purchased
in the 30-year period that begins in the anticipated year of compliance
with the amended standards (2029-2058) amount to 2.73 quadrillion
British thermal units (Btu), or quads.\6\ This represents a savings of
13 percent relative to the energy use of these products in the case
without amended standards (referred to as the ``no-new-standards
case'').
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\6\ The quantity refers to full-fuel-cycle (FFC) energy savings.
FFC energy savings includes the energy consumed in extracting,
processing, and transporting primary fuels (i.e., coal, natural gas,
petroleum fuels) and, thus, presents a more complete picture of the
impacts of energy efficiency standards. For more information on the
FFC metric, see section IV.H of this document.
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The cumulative net present value (NPV) of total consumer benefits
of the standards for liquid-immersed distribution transformers ranges
from $0.56 billion (at a 7-percent discount rate) to $3.41 billion (at
a 3-percent discount rate). This NPV expresses the estimated total
value of future operating-cost savings minus the estimated increased
product and installation costs for distribution transformers purchased
in 2029-2058.
In addition, the adopted standards for liquid-immersed distribution
transformers are projected to yield significant environmental benefits.
DOE estimates that the standards will result in cumulative emission
reductions (over the same period as for energy savings) of 51.40
million metric tons (Mt) \7\ of carbon dioxide (CO2), 12.29
thousand tons of sulfur dioxide (SO2), 89.85 thousand tons
of nitrogen oxides (NOX), 416.15 thousand tons of methane
(CH4), 0.40 thousand tons of nitrous oxide (N2O),
and 0.08 tons of mercury (Hg).\8\
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\7\ A metric ton is equivalent to 1.1 short tons. Results for
emissions other than CO2 are presented in short tons.
\8\ DOE calculated emissions reductions relative to the no-new-
standards case, which reflects key assumptions in the Annual Energy
Outlook 2023 (AEO2023). AEO2023 reflects, to the extent possible,
laws and regulations adopted through mid-November 2022, including
the Inflation Reduction Act. See section IV.K of this document for
further discussion of AEO2023 assumptions that affect air pollutant
emissions.
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DOE estimates the value of climate benefits from a reduction in
greenhouse gases (GHG) using four different estimates of the social
cost of CO2 (SC-CO2), the social cost of methane
(SC-CH4), and the social cost of nitrous oxide (SC-
N2O).\9\ Together these represent the social cost of GHG
(SC-GHG). DOE used interim SC-GHG values (in terms of benefit-per-ton
of GHG avoided) developed by an Interagency Working Group on the Social
Cost of Greenhouse Gases (IWG).\10\ The derivation of these values is
discussed in section IV.L of this document. For presentational
purposes, the climate benefits associated with the average SC-GHG at a
3-percent discount rate are estimated to be $1.85 billion. DOE does not
have a single central SC-GHG point estimate and it emphasizes the
importance and value of considering the benefits calculated using all
four sets of SC-GHG estimates.
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\9\ Estimated climate-related benefits are provided in
compliance with Executive Order 12866.
\10\ To monetize the benefits of reducing GHG emissions, this
analysis uses the interim estimates presented in the February 2021
SC-GHG TSD. www.whitehouse.gov/wp-content/uploads/2021/02/TechnicalSupportDocument_SocialCostofCarbonMethaneNitrousOxide.pdf.
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DOE estimated the monetary health benefits of SO2 and
NOX emissions reductions, using benefit-per-ton estimates
from the Environmental Protection Agency,\11\ as discussed in section
IV.L of this document. DOE estimated the present value of the health
benefits would be $1.11 billion using a 7-percent discount rate, and
$3.71 billion using a 3-percent discount rate.\12\ DOE is currently
only monetizing health benefits from changes in ambient fine
particulate matter (PM2.5) concentrations from two
precursors (SO2 and NOX), and from changes in
ambient ozone from one precursor (NOX), but will continue to
assess the ability to monetize other effects such as health benefits
from reductions in direct PM2.5 emissions.
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\11\ U.S. EPA. Estimating the Benefit per Ton of Reducing
Directly Emitted PM2.5, PM2.5 Precursors and
Ozone Precursors from 21 Sectors. Available at www.epa.gov/benmap/estimating-benefit-ton-reducing-pm25-precursors-21-sectors.
\12\ DOE estimates the economic value of these emissions
reductions resulting from the considered TSLs for the purpose of
complying with the requirements of Executive Order 12866.
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Table I.5 summarizes the monetized benefits and costs expected to
result from the amended standards for liquid-immersed distribution
transformers. There are other important unquantified effects, including
certain unquantified climate benefits, unquantified public health
benefits from the reduction of toxic air pollutants and other
emissions, unquantified energy security benefits, and distributional
effects, among others.
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The benefits and costs of the adopted standards can also be
expressed in terms of annualized values. The monetary values for the
total annualized net benefits are (1) the reduced consumer operating
costs, minus (2) the increase in product purchase prices and
installation costs, plus (3) the value of climate and health benefits
of emission reductions, all annualized.\13\
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\13\ To convert the time-series of costs and benefits into
annualized values, DOE calculated a present value in 2024, the year
used for discounting the NPV of total consumer costs and savings.
For the benefits, DOE calculated a present value associated with
each year's shipments in the year in which the shipments occur
(e.g., 2020 or 2030), and then discounted the present value from
each year to 2024. Using the present value, DOE then calculated the
fixed annual payment over a 30-year period, starting in the
compliance year, that yields the same present value.
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The national operating cost savings are domestic private U.S.
consumer monetary savings that occur as a result of purchasing the
covered equipment and are measured for the lifetime of distribution
transformers shipped in 2029-2058. The benefits associated with reduced
emissions achieved as a result of the adopted standards are also
calculated based on the lifetime of liquid-immersed distribution
transformers shipped in 2029-2058. Total benefits for both the 3-
percent and 7-percent cases are presented using the average GHG social
costs with a 3-percent discount rate.\14\ Estimates of total benefits
are presented for all four SC-GHG discount rates in section IV.L of
this document.
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\14\ As discussed in section IV.L.1 of this document, DOE agrees
with the IWG that using consumption-based discount rates e.g., 3
percent) is appropriate when discounting the value of climate
impacts. Combining climate effects discounted at an appropriate
consumption-based discount rate with other costs and benefits
discounted at a capital-based rate (i.e., 7 percent) is reasonable
because of the different nature of the types of benefits being
measured.
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Table I.6 presents the total estimated monetized benefits and costs
associated with the adopted standard, expressed in terms of annualized
values. The results under the primary estimate are as follows.
Using a 7-percent discount rate for consumer benefits and costs and
NOx and SO2 reductions, and the 3-percent discount rate case
for GHG social costs, the estimated cost of the adopted standards for
liquid-immersed distribution transformers is $151.1 million per year in
increased equipment installed costs, while the estimated annual
benefits are $210.2 million from reduced equipment operating costs,
$106.1 million in GHG reductions, and $117.0 million from reduced
NOX and SO2 emissions. In this case, the net
benefit amounts to $282.3 million per year.
Using a 3-percent discount rate for all benefits and costs, the
estimated cost of the adopted standards for liquid-immersed
distribution transformers is $152.6 million per year in increased
equipment costs, while the estimated annual benefits are $348.3 million
in reduced operating costs, $106.1 million from GHG reductions, and
$213.2 million from reduced NOX and SO2
emissions. In this case, the net benefit amounts to $515.1 million per
year.
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2. Low-Voltage Dry-Type Distribution Transformers
DOE's analyses indicate that the adopted energy conservation
standards for distribution transformers would save a significant amount
of energy. Relative to the case without amended standards, the lifetime
energy savings for low-voltage dry-type distribution transformers
purchased in the 30-year period that begins in the anticipated year of
compliance with the amended standards (2029-2058) amount to 1.71
quadrillion Btu, or quads.\15\ This represents a savings of 35 percent
relative to the energy use of these products in the no-new-standards
case.
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\15\ The quantity refers to FFC energy savings. FFC energy
savings includes the energy consumed in extracting, processing, and
transporting primary fuels (i.e., coal, natural gas, petroleum
fuels) and, thus, presents a more complete picture of the impacts of
energy efficiency standards. For more information on the FFC metric,
see section IV.H of this document.
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The cumulative NPV of total consumer benefits of the standards for
low-voltage dry-type distribution transformers ranges from $2.08
billion (at a 7-percent discount rate) to 6.68 billion (at a 3-percent
discount rate). This NPV expresses the estimated total value of future
operating-cost savings minus the estimated increased product and
installation costs for distribution transformers purchased in 2029-
2058.
In addition, the adopted standards for low-voltage dry-type
distribution transformers are projected to yield significant
environmental benefits. DOE estimates that the standards will result in
cumulative emission reductions (over the same period as for energy
savings) of 31.28 million Mt \16\ of CO2, 7.49 thousand tons
of SO2, 55.92 thousand tons of NOX, 259.96
thousand tons of CH4, 0.24 thousand tons of N2O,
and 0.05 tons of Hg.\17\
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\16\ A metric ton is equivalent to 1.1 short tons. Results for
emissions other than CO2 are presented in short tons.
\17\ DOE calculated emissions reductions relative to the no-new-
standards case, which reflects key assumptions in the AEO2023.
AEO2023 reflects, to the extent possible, laws and regulations
adopted through mid-November 2022, including the Inflation Reduction
Act. See section IV.K of this document for further discussion of
AEO2023 assumptions that affect air pollutant emissions.
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DOE estimates the value of climate benefits from a reduction in GHG
using four different estimates of the SC-CO2CO2,
the SC-CH4, and the SC-N2O. Together these
represent the SC-GHG. \DOE\ used interim SC-GHG values (in terms of
benefit per ton of GHG avoided) developed by an IWG.\18\ The derivation
of these values is discussed in section IV.L of this document. For
presentational purposes, the climate benefits associated with the
average SC-GHG at a 3-percent discount rate are estimated to be $1.23
billion. DOE does not have a single central SC-GHG point estimate and
it emphasizes the importance and value of considering the benefits
calculated using all four sets of SC-GHG estimates.
---------------------------------------------------------------------------
\18\ To monetize the benefits of reducing GHG emissions, this
analysis uses values that are based on the February 2021 SC-GHG TSD.
www.whitehouse.gov/wp-content/uploads/2021/02/TechnicalSupportDocument_SocialCostofCarbonMethaneNitrousOxide.pdf.
---------------------------------------------------------------------------
DOE estimated the monetary health benefits of SO2 and
NOX emissions reductions, using benefit per ton estimates
from the Environmental Protection Agency,\19\ as discussed in section
IV.L of this document. DOE did not monetize the reduction in mercury
emissions because the quantity is very
[[Page 29844]]
small. DOE estimated the present value of the health benefits would be
$0.76 billion using a 7-percent discount rate, and $2.42 billion using
a 3-percent discount rate.\20\ DOE is currently only monetizing health
benefits from changes in ambient PM2.5 concentrations from
two precursors (SO2 and NOX), and from changes in
ambient ozone from one precursor (for NOX), but will
continue to assess the ability to monetize other effects such as health
benefits from reductions in direct PM2.5 emissions.
---------------------------------------------------------------------------
\19\ U.S. EPA. Estimating the Benefit per Ton of Reducing
Directly Emitted PM2.5, PM2.5 Precursors and
Ozone Precursors from 21 Sectors. Available at www.epa.gov/benmap/estimating-benefit-ton-reducing-pm25-precursors-21-sectors.
\20\ DOE estimates the economic value of these emissions
reductions resulting from the considered TSLs for the purpose of
complying with the requirements of Executive Order 12866.
---------------------------------------------------------------------------
Table I.7 summarizes the monetized benefits and costs expected to
result from the amended standards for low-voltage dry-type distribution
transformers. There are other important unquantified effects, including
certain unquantified climate benefits, unquantified public health
benefits from the reduction of toxic air pollutants and other
emissions, unquantified energy security benefits, and distributional
effects, among others.
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The benefits and costs of the adopted standards can also be
expressed in terms of annualized values. The monetary values for the
total annualized net benefits are (1) the reduced consumer operating
costs, minus (2) the increase in product purchase prices and
installation costs, plus (3) the value of climate and health benefits
of emission reductions, all annualized.\21\
---------------------------------------------------------------------------
\21\ To convert the time-series of costs and benefits into
annualized values, DOE calculated a present value in 2024, the year
used for discounting the NPV of total consumer costs and savings.
For the benefits, DOE calculated a present value associated with
each year's shipments in the year in which the shipments occur
(e.g., 2020 or 2030), and then discounted the present value from
each year to 2024. Using the present value, DOE then calculated the
fixed annual payment over a 30-year period, starting in the
compliance year, that yields the same present value.
---------------------------------------------------------------------------
The national operating cost savings are domestic private U.S.
consumer monetary savings that occur as a result of purchasing the
covered equipment and are measured for the lifetime of distribution
transformers shipped in 2029-2058. The benefits associated with reduced
emissions achieved as a result of the adopted standards are also
calculated based on the lifetime of low-voltage dry-type distribution
transformers shipped in 2029-2058. Total benefits for both the 3-
percent and 7-percent cases are presented using the average GHG social
costs with a 3-percent discount rate.\22\ Estimates of total benefits
are presented for all four SC-GHG discount rates in section IV.L of
this document.
---------------------------------------------------------------------------
\22\ As discussed in section IV.L.1 of this document, DOE agrees
with the IWG that using consumption-based discount rates e.g., 3
percent) is appropriate when discounting the value of climate
impacts. Combining climate effects discounted at an appropriate
consumption-based discount rate with other costs and benefits
discounted at a capital-based rate (i.e., 7 percent) is reasonable
because of the different nature of the types of benefits being
measured.
---------------------------------------------------------------------------
Table I.8 presents the total estimated monetized benefits and costs
associated with the adopted standard, expressed in terms of annualized
values. The results under the primary estimate are as follows.
Using a 7-percent discount rate for consumer benefits and costs and
NOx and SO2 reductions, and the 3-percent discount rate case
for GHG social costs, the estimated cost of the adopted standards for
low-voltage dry-type is $66.6 million per year in increased equipment
installed costs, while the estimated annual benefits are $286.8 million
from reduced equipment operating costs, $70.4 million in GHG
reductions, and $80.3 million from reduced NOX and
SO2 emissions. In this case, the net benefit amounts to
$370.8 million per year.
Using a 3-percent discount rate for all benefits and costs, the
estimated cost of
[[Page 29846]]
the adopted standards for low-voltage dry-type is $67.4 million per
year in increased equipment costs, while the estimated annual benefits
are $450.9 million in reduced operating costs, $70.4 million from GHG
reductions, and $139.1 million from reduced NOX and
SO2 emissions. In this case, the net benefit amounts to
$593.0 million per year.
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BILLING CODE 6450-01-C
3. Medium-Voltage Dry-Type Distribution Transformers
DOE's analyses indicate that the adopted energy conservation
standards for medium-voltage dry-type distribution transformers would
save a significant amount of energy. Relative to the case without
amended standards, the lifetime energy savings for distribution
transformers purchased in the 30-year period that begins in the
anticipated year of compliance with the amended standards (2029-2058)
amount to 0.14 quadrillion Btu, or quads.\23\ This represents a savings
of 9 percent relative to the energy use of these products in the no-
new-standards case.
---------------------------------------------------------------------------
\23\ The quantity refers to FFC energy savings. FFC energy
savings includes the energy consumed in extracting, processing, and
transporting primary fuels (i.e., coal, natural gas, petroleum
fuels) and, thus, presents a more complete picture of the impacts of
energy efficiency standards. For more information on the FFC metric,
see section IV.H of this document.
---------------------------------------------------------------------------
The cumulative NPV of total consumer benefits of the standards for
medium-voltage dry-type distribution transformers ranges from $0.03 (at
a 7-percent discount rate) to $0.22 (at a 3-percent discount rate).
This NPV expresses the estimated total value of future operating-cost
savings minus the estimated increased product and installation costs
for distribution transformers purchased in 2029-2058.
In addition, the adopted standards for medium-voltage dry-type
distribution transformers are projected to yield significant
environmental benefits. DOE estimates that the standards will result in
cumulative emission reductions (over the same period as for energy
savings) of 2.59 million Mt \24\ of CO2, 0.63 thousand tons
of SO2, 4.69 thousand tons of NOX, 21.86 thousand
tons of CH4, 0.02 thousand tons of N2O, and 0.00
tons of Hg.\25\
---------------------------------------------------------------------------
\24\ A metric ton is equivalent to 1.1 short tons. Results for
emissions other than CO2 are presented in short tons.
\25\ DOE calculated emissions reductions relative to the no-new-
standards case, which reflects key assumptions in the AEO2023.
AEO2023 reflects, to the extent possible, laws and regulations
adopted through mid-November 2022, including the Inflation Reduction
Act. See section IV.K of this document for further discussion of
AEO2023 assumptions that affect air pollutant emissions.
---------------------------------------------------------------------------
DOE estimates the value of climate benefits from a reduction in GHG
using four different estimates of the SC-CO2, the SC-
CH4, and the SC-N2O. Together these represent the
SC-GHG. DOE used interim SC-GHG values (in terms of benefit per ton of
GHG avoided) developed by an IWG.\26\ The derivation of these values is
discussed in section IV.L of this document. For presentational
purposes, the climate benefits associated with the average SC-GHG at a
3-percent discount rate are estimated to be $0.10 billion. DOE does not
have a single central SC-GHG point estimate and it emphasizes the
importance and value of considering the benefits calculated using all
four sets of SC-GHG estimates.
---------------------------------------------------------------------------
\26\ To monetize the benefits of reducing GHG emissions, this
analysis uses values that are based on the February 2021 SC-GHG TSD.
www.whitehouse.gov/wp-content/uploads/2021/02/TechnicalSupportDocument_SocialCostofCarbonMethaneNitrousOxide.pdf.
---------------------------------------------------------------------------
DOE estimated the monetary health benefits of SO2 and
NOX emissions reductions, using benefit per ton estimates
from the Environmental Protection Agency,\27\ as discussed in section
IV.L of this document. DOE did not monetize the reduction in mercury
emissions because the quantity is very small. DOE estimated the present
value of the health benefits would be $0.06 billion using a 7-percent
discount rate, and $0.20 billion using a 3-percent discount rate.\28\
DOE is currently only monetizing health benefits from changes in
ambient PM2.5 concentrations from two precursors
(SO2 and NOX), and from changes in ambient ozone
from one precursor (for NOX), but will continue to assess
the ability to monetize other
[[Page 29849]]
effects such as health benefits from reductions in direct
PM2.5 emissions.
---------------------------------------------------------------------------
\27\ U.S. EPA. Estimating the Benefit per Ton of Reducing
Directly Emitted PM2.5, PM2.5 Precursors and
Ozone Precursors from 21 Sectors. Available at www.epa.gov/benmap/estimating-benefit-ton-reducing-pm25-precursors-21-sectors.
\28\ DOE estimates the economic value of these emissions
reductions resulting from the considered TSLs for the purpose of
complying with the requirements of Executive Order 12866.
---------------------------------------------------------------------------
Table I.9 summarizes the monetized benefits and costs expected to
result from the amended standards for medium-voltage dry-type
distribution transformers. There are other important unquantified
effects, including certain unquantified climate benefits, unquantified
public health benefits from the reduction of toxic air pollutants and
other emissions, unquantified energy security benefits, and
distributional effects, among others.
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The benefits and costs of the adopted standards can also be
expressed in terms of annualized values. The monetary values for the
total annualized net benefits are (1) the reduced consumer operating
costs, minus (2) the increase in product purchase prices and
installation costs, plus (3) the value of climate and health benefits
of emission reductions, all annualized.\29\
---------------------------------------------------------------------------
\29\ To convert the time-series of costs and benefits into
annualized values, DOE calculated a present value in 2024, the year
used for discounting the NPV of total consumer costs and savings.
For the benefits, DOE calculated a present value associated with
each year's shipments in the year in which the shipments occur
(e.g., 2020 or 2030), and then discounted the present value from
each year to 2024. Using the present value, DOE then calculated the
fixed annual payment over a 30-year period, starting in the
compliance year, that yields the same present value.
---------------------------------------------------------------------------
The national operating cost savings are domestic private U.S.
consumer monetary savings that occur as a result of purchasing the
covered equipment and are measured for the lifetime of medium-voltage
dry-type distribution transformers shipped in 2029-2058. The benefits
associated with reduced emissions achieved as a result of the adopted
standards are also calculated based on the lifetime of distribution
transformers shipped in 2029-2058. Total benefits for both the 3-
percent and 7-percent cases are presented using the average GHG social
costs with a 3-percent discount rate.\30\ Estimates of total benefits
are presented for all four SC-GHG discount rates in section IV.L of
this document.
---------------------------------------------------------------------------
\30\ As discussed in section IV.L.1 of this document, DOE agrees
with the IWG that using consumption-based discount rates e.g., 3
percent) is appropriate when discounting the value of climate
impacts. Combining climate effects discounted at an appropriate
consumption-based discount rate with other costs and benefits
discounted at a capital-based rate (i.e., 7 percent) is reasonable
because of the different nature of the types of benefits being
measured.
---------------------------------------------------------------------------
Table I.10 presents the total estimated monetized benefits and
costs associated with the adopted standard, expressed in terms of
annualized values. The results under the primary estimate are as
follows.
Using a 7-percent discount rate for consumer benefits and costs and
NOX and SO2 reductions, and the 3-percent
discount rate case for GHG social costs, the estimated cost of the
adopted standards for medium-voltage dry-type is $12.5 million per year
in increased equipment installed costs, while the estimated annual
benefits are $15.9 million from reduced equipment operating costs, $5.9
million in GHG reductions, and $6.7 million from reduced NOX
and SO2 emissions. In this case, the net benefit amounts to
$16.0 million per year.
Using a 3-percent discount rate for all benefits and costs, the
estimated cost of the adopted standards for medium-voltage dry-type
distribution transformers is $12.7 million per year in increased
equipment costs, while the estimated annual benefits are $25.1 million
in reduced operating costs, $5.9 million from GHG reductions, and $11.7
million from reduced NOX and SO2 emissions. In
this case, the net benefit amounts to $29.9 million per year.
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BILLING CODE 6450-01-C
DOE's analysis of the national impacts of the adopted standards is
described in sections IV.H, IV.K, and IV.L of this document.
D. Conclusion
DOE concludes that the standards adopted in this final rule
represent the maximum improvement in energy efficiency that is
technologically feasible and economically justified, and would result
in the significant conservation of energy. Specifically, with regards
to technological feasibility, products are already commercially
available which either achieve these standard levels or utilize the
technologies required to achieve these standard levels for all product
classes covered by this proposal. As for economic justification, DOE's
analysis shows that the benefits of the standards exceed, to a great
extent, the burdens of the standards.
Table I.11 shows the annualized values for all distribution
transformers under amended standards, expressed in 2022$. The results
under the primary estimate are as follows.
Using a 7-percent discount rate for consumer benefits and costs and
NOx and SO2 reduction benefits, and a 3-percent discount
rate case for GHG social costs, the estimated cost of the standards for
distribution transformers is $ 230.3 million per year in increased
distribution transformers costs, while the estimated annual benefits
are $512.9 million in reduced distribution transformers operating
costs, $182.4 million in climate benefits, and $204.1 million in health
benefits. The net benefit amounts to $669.1 million per year. DOE notes
that the net benefits are substantial even in the absence of the
climate benefits,\31\ and DOE would adopt the same standards in the
absence of such benefits.
---------------------------------------------------------------------------
\31\ The information on climate benefits is provided in
compliance with Executive Order 12866.
---------------------------------------------------------------------------
The significance of energy savings offered by a new or amended
energy conservation standard cannot be determined without knowledge of
the specific circumstances surrounding a given rulemaking.\32\ For
example, some covered products and equipment have most of their energy
consumption occur during periods of peak energy demand. The impacts of
these products on the energy infrastructure can be more pronounced than
products with relatively constant demand. Accordingly, DOE evaluates
the significance of energy savings on a case-by-case basis.
---------------------------------------------------------------------------
\32\ Procedures, Interpretations, and Policies for Consideration
in New or Revised Energy Conservation Standards and Test Procedures
for Consumer Products and Commercial/Industrial Equipment, 86 FR
70892, 70901 (Dec. 13, 2021).
---------------------------------------------------------------------------
As previously mentioned, the standards are projected to result in
estimated national energy savings of 4.58 quads full fuel cycle (FFC),
the equivalent of the primary annual energy use of 49.2 million homes.
In addition, they are projected to reduce cumulative CO2
emissions by 85.27 Mt. Based on these findings, DOE has determined the
energy savings from the standard levels
[[Page 29854]]
adopted in this final rule are ``significant'' within the meaning of 42
U.S.C. 6295(o)(3)(B). A more detailed discussion of the basis for these
conclusions is contained in the remainder of this document and the
accompanying TSD.
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BILLING CODE 6450-01-C
II. Introduction
The following section briefly discusses the statutory authority
underlying this final rule, as well as some of the relevant historical
background related to the establishment of standards for distribution
transformers.
A. Authority
EPCA authorizes DOE to regulate the energy efficiency of a number
of consumer products and certain industrial equipment. (42 U.S.C. 6291-
6317, as codified) Title III, Part B of EPCA established the Energy
Conservation Program for Consumer Products Other Than Automobiles. (42
U.S.C. 6291-6309) Title III, Part C of EPCA,\33\ as amended,
established the Energy Conservation Program for Certain Industrial
Equipment. (42 U.S.C. 6311-6317) The Energy Policy Act of 1992, Public
Law 102-486, amended EPCA and directed DOE to prescribe energy
conservation standards for those distribution transformers for which
DOE determines such standards would be technologically feasible,
economically justified, and would result in significant energy savings.
(42 U.S.C. 6317(a)) The Energy Policy Act of 2005, Public Law 109-58,
also amended EPCA to establish energy conservation standards for low-
voltage dry-type distribution transformers. (42 U.S.C. 6295(y))
---------------------------------------------------------------------------
\33\ As noted previously, for editorial reasons, upon
codification in the U.S. Code, Part C was redesignated Part A-1.
---------------------------------------------------------------------------
EPCA further provides that, not later than six years after the
issuance of any final rule establishing or amending a standard, DOE
must publish either a notice of determination that standards for the
product do not need to be amended, or a NOPR including new proposed
energy conservation standards (proceeding to a final rule, as
appropriate). (42 U.S.C. 6316(a); 42 U.S.C. 6295(m)(1))
The energy conservation program under EPCA consists essentially of
four parts: (1) testing, (2) labeling, (3) the establishment of Federal
energy conservation standards, and (4) certification and enforcement
procedures. Relevant provisions of EPCA include definitions (42 U.S.C.
6311), test procedures (42 U.S.C. 6314), labeling provisions (42 U.S.C.
6315), energy conservation standards (42 U.S.C. 6313), and the
authority to require information and reports from manufacturers (42
U.S.C. 6316).
Federal energy efficiency requirements for covered equipment
established under EPCA generally supersede State laws and regulations
concerning energy conservation testing, labeling, and standards. (42
U.S.C. 6316(a) and 42 U.S.C. 6316(b); 42 U.S.C. 6297) DOE may, however,
grant waivers of Federal preemption in limited instances for particular
State laws or regulations, in accordance with the procedures and other
provisions set
[[Page 29859]]
forth under EPCA. ((See 42 U.S.C. 6316(a) (applying the preemption
waiver provisions of 42 U.S.C. 6297).)
Subject to certain criteria and conditions, DOE is required to
develop test procedures to measure the energy efficiency, energy use,
or estimated annual operating cost of each covered product. (See 42
U.S.C. 6316(a); 42 U.S.C. 6295(o)(3)(A) and (r).) Manufacturers of
covered equipment must use the Federal test procedures as the basis for
certifying to DOE that their equipment complies with the applicable
energy conservation standards and as the basis for any representations
regarding the energy use or energy efficiency of the equipment. (42
U.S.C. 6316(a); 42 U.S.C. 6295(s); 42 U.S.C. 6314(d)). Similarly, DOE
must use these test procedures to evaluate whether a basic model
complies with the applicable energy conservation standard(s). (42
U.S.C. 6316(a); 42 U.S.C. 6295(s)) The DOE test procedures for
distribution transformers appear at title 10 of the Code of Federal
Regulations (CFR) part 431, subpart K, appendix A.
DOE must follow specific statutory criteria for prescribing new or
amended standards for covered equipment, including distribution
transformers. Any new or amended standard for a covered product must be
designed to achieve the maximum improvement in energy efficiency that
the Secretary of Energy (``Secretary'') determines is technologically
feasible and economically justified. (42 U.S.C. 6316(a); 42 U.S.C.
6295(o)(2)(A)) Furthermore, DOE may not adopt any standard that would
not result in the significant conservation of energy. (42 U.S.C.
6316(a); 42 U.S.C. 6295(o)(3)(B))
Moreover, DOE may not prescribe a standard (1) for certain
products, including distribution transformers, if no test procedure has
been established for the product, or (2) if DOE determines by rule that
the establishment of such standard will not result in significant
conservation of energy (or, for certain products, water), or is not
technologically feasible or economically justified. ((42 U.S.C.
6316(a); 42 U.S.C. 6295(o)(3)(A)-(B)) In deciding whether a proposed
standard is economically justified, DOE must determine whether the
benefits of the standard exceed its burdens. Id. DOE must make this
determination after receiving comments on the proposed standard, and by
considering, to the greatest extent practicable, the following seven
statutory factors:
(1) The economic impact of the standard on manufacturers and
consumers of the products subject to the standard;
(2) The savings in operating costs throughout the estimated average
life of the covered equipment in the type (or class) compared to any
increase in the price, initial charges, or maintenance expenses for the
covered equipment that are likely to result from the standard;
(3) The total projected amount of energy (or as applicable, water)
savings likely to result directly from the standard;
(4) Any lessening of the utility or the performance of the covered
equipment likely to result from the standard;
(5) The impact of any lessening of competition, as determined in
writing by the Attorney General, that is likely to result from the
standard;
(6) The need for national energy and water conservation; and
(7) Other factors the Secretary considers relevant.
(42 U.S.C. 6316(a); 42 U.S.C. 6295(o)(2)(B)(i)(I)-(VII))
Further, EPCA, as codified, establishes a rebuttable presumption
that a standard is economically justified if the Secretary finds that
the additional cost to the consumer of purchasing a product complying
with an energy conservation standard level will be less than three
times the value of the energy savings during the first year that the
consumer will receive as a result of the standard, as calculated under
the applicable test procedure. (42 U.S.C. 6316(a); 42 U.S.C.
6295(o)(2)(B)(iii))
EPCA, as codified, also contains what is known as an ``anti-
backsliding'' provision, which prevents the Secretary from prescribing
any amended standard that either increases the maximum allowable energy
use or decreases the minimum required energy efficiency of a covered
product. (42 U.S.C. 6316(a); 42 U.S.C. 6295(o)(1)) Also, the Secretary
may not prescribe an amended or new standard if interested persons have
established by a preponderance of the evidence that the standard is
likely to result in the unavailability in the United States in any
covered product type (or class) of performance characteristics
(including reliability), features, sizes, capacities, and volumes that
are substantially the same as those generally available in the United
States. (42 U.S.C. 6316(a); 42 U.S.C. 6295(o)(4))
Additionally, EPCA specifies requirements when promulgating an
energy conservation standard for a covered product that has two or more
subcategories. A rule prescribing an energy conservation standard for a
type (or class) of product must specify a different standard level for
a type or class of products that has the same function or intended use
if DOE determines that products within such group (A) consume a
different kind of energy from that consumed by other covered equipment
within such type (or class); or (B) have a capacity or other
performance-related feature which other products within such type (or
class) do not have and such feature justifies a higher or lower
standard. (42 U.S.C. 6316(a); 42 U.S.C. 6295(q)(1)) In determining
whether a performance-related feature justifies a different standard
for a group of products, DOE considers such factors as the utility to
the consumer of such a feature and other factors DOE deems appropriate.
Id. Any rule prescribing such a standard must include an explanation of
the basis on which such higher or lower level was established. (42
U.S.C. 6316(a); 42 U.S.C. 6295(q)(2))
B. Background
1. Current Standards
DOE most recently completed a review of its distribution
transformer standards in a final rule published on April 18, 2013
(``April 2013 Standards Final Rule''), through which DOE prescribed the
current energy conservation standards for distribution transformers
manufactured on and after January 1, 2016. 78 FR 23336, 23433. These
standards are set forth in DOE's regulations at 10 CFR 431.196 and are
repeated in Table II.1, Table II.2, and Table II.3.
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2. History of Standards Rulemaking for Distribution Transformers
On June 18, 2019, DOE published notice that it was initiating an
early assessment review to determine whether any new or amended
standards would satisfy the relevant requirements of EPCA for a new or
amended energy conservation standard for distribution transformers and
a request for information (RFI). 84 FR 28239 (``June 2019 Early
Assessment Review RFI'').
On August 27, 2021, DOE published a notification of a webinar and
availability of a preliminary technical support document (TSD), which
announced the availability of its analysis for distribution
transformers. 86 FR 48058 (``August 2021 Preliminary Analysis TSD'').
The purpose of the August 2021 Preliminary Analysis TSD was to make
publicly available the initial technical and economic analyses
conducted for distribution transformers, and present initial results of
those analyses. DOE did not propose new or amended standards for
distribution transformers at that time. The initial TSD and
accompanying analytical spreadsheets for the August 2021 Preliminary
Analysis TSD provided the analyses DOE used to examine the potential
for amending energy conservation standards for distribution
transformers and provided preliminary discussions in response to a
number of issues raised in comments to the June 2019 Early Assessment
Review RFI. It described the analytical methodology that DOE used and
each analysis DOE performed.
On January 11, 2023, DOE published a NOPR and public meeting
announcement, in which DOE proposed amended energy conservation
standards for distribution transformers. 88 FR 1722 (``January 2023
NOPR''). DOE proposed amended standards for liquid-immersed, low-
voltage dry-type, and MVDT distribution transformers. DOE additionally
proposed to establish a separate equipment class for submersible
distribution transformers, with standards maintained at the levels
prescribed by the April 2013 Standards Final Rule. Id. On February 16,
2023, DOE presented the proposed standards and accompanying analysis in
a public meeting.
On February 22, 2023, DOE published a notice extending the comment
period for the January 2023 NOPR by an additional 14 days. 88 FR 10856.
DOE received 93 comments in response to the January 2023 NOPR from
the interested parties listed in Table II.4.
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A parenthetical reference at the end of a comment quotation or
paraphrase provides the location of the item in the public record.\34\
To the extent that interested parties have provided written comments
that are substantively consistent with any oral comments provided
during the February 16, 2023, public meeting, DOE cites the written
comments throughout this final rule. Any oral comments provided during
the webinar that are not substantively addressed by written comments
are summarized and cited separately throughout this final rule.
---------------------------------------------------------------------------
\34\ The parenthetical reference provides a reference for
information located in the docket of DOE's rulemaking to develop
energy conservation standards for distribution transformers. (Docket
No. EERE-2019-BT-STD-0018, which is maintained at
www.regulations.gov). The references are arranged as follows:
(commenter name, comment docket ID number, page of that document).
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III. General Discussion
DOE developed this final rule after a review of the market for the
subject distribution transformers. DOE also considered comments, data,
and information from interested parties that represent a variety of
interests. This notice addresses issues raised by these commenters.
A. General Comments
This section summarizes general comments received from interested
parties regarding rulemaking timing and process.
DOE received several comments recommending DOE pursue policies for
saving energy or strengthening the supply chain either in place of or
in addition to revised distribution transformer efficiency standards.
Specifically, Standards Michigan commented that distribution
transformers are oversized and recommended DOE work with electrical
code committees to encourage proper distribution transformer sizing.
(Standards Michigan, No. 109 at p. 1) APPA recommended DOE consider
other efficiency measures to conserve energy, such as improving
building codes and increasing the size of service conductors to reduce
transmission losses. (APPA, No. 103 at p. 3) Pugh Consulting commented
that DOE should
[[Page 29866]]
work with the U.S. Environmental Protection Agency (EPA) to accelerate
the permitting process under the Clean Air Act and Clean Water Act and
to allow steel and transformer manufacturers to engage in nitrogen
oxide (NOx) emission trading under EPA's Good Neighbor Plan. (Pugh
Consulting, No. 117 at p. 7) Pugh Consulting further recommended DOE
remove tariffs from friendly nations and explore agreements to increase
electrical steel imports from these nations. (Pugh Consulting, No. 117
at p. 7) EVgo commented that DOE should use Defense Production Act
investments to increase transformer supply to accommodate the increases
in demand that are supporting administration electrification goals.
(EVgo, No. 111 at p. 2)
DOE notes that this final rule pertains only to energy conservation
standards for distribution transformers, and any efforts to amend
national electrical codes, building codes, or other Federal regulatory
programs and policies are beyond the scope of this rulemaking. DOE
notes it is actively working with fellow government agencies and
industry to better address the current supply chain challenges
impacting the distribution transformer market, as well as the broader
electricity industry.\35\
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\35\ See Department of Energy. DOE Actions to Unlock
Transformers and Grid Component Production. Available at
www.energy.gov/policy/articles/doe-actions-unlock-transformer-and-grid-component-production (accessed Oct. 27, 2023).
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Several commenters disagreed with DOE's assessment that the
proposed standards are technologically feasible and economically
justified generally.
Cliffs commented that DOE standards are not economically justified.
(Cliffs, No. 105 at pp. 13-14) NAHB commented that the proposed
standards are not economically justified because the benefits do not
outweigh the costs. NAHB added that DOE's designation of economic
justification is subjective and would be impacted by regulations from
other agencies. (NAHB, No. 106 at pp. 2-3) SBA commented that the
proposed standards are not economically justified due to the additional
costs associated with amorphous cores and the significant shock to the
market from a lack of market competition. (SBA, No. 100 at pp. 6-7)
NRECA commented that the proposed standards are neither economically
justified nor technologically feasible because DOE's NOPR is based on
flawed assumptions. (NRECA, No. 98 at pp. 1-2) Pugh Consulting
commented that DOE's proposal does not properly consider the
requirements established under the Energy Policy Act of 2005. (Pugh
Consulting, No. 117 at p. 2)
APPA commented that DOE's requests for comment in the January 2023
NOPR indicate some technical questions are unresolved and, therefore,
DOE should address these questions before issuing any final rule.
(APPA, No. 103 at pp. 17-18) Cliffs commented that insufficient
collaboration with stakeholders was conducted prior to publication of
the NOPR and because of that, the NOPR contains flawed assumptions and
oversteps DOE's authority. (Cliffs, No. 105 at p. 2)
Entergy recommended that instead of finalizing the proposed rule,
DOE should (1) adopt a standard that does not require a full move to
amorphous or (2) use its authority to issue a determination that no new
standard is required, which would allow DOE to work with industry
through the Electricity Subsector Coordinating Council (ESCC) to
further study the cost and benefits of enacting this rule and return
with recommendations prior to 2027. (Entergy, No. 114 at p. 4)
CEC commented that DOE should ensure it adopts a final rule by June
30, 2024, because EPCA required DOE to update this standard by April
2019. (CEC, No. 124 at p. 2)
As stated, DOE has provided numerous notices with extensive comment
periods to ensure stakeholders have an opportunity to provide data and
to identify or correct any concerns in DOE's analysis of amended energy
conservation standards. DOE has reviewed the many comments, data, and
feedback received in response to the January 2023 NOPR and updated its
analysis based on this information, as discussed throughout this final
rule. In this final rule, DOE is adopting efficiency standards based
on, but importantly different from, those proposed in the January 2023
NOPR. DOE is adopting standards that are expected to require
significantly less amorphous material and extend the compliance period
by two years, relative to what was proposed, which will reduce the
burden on manufacturers and allow manufacturers considerable
flexibility to meet standards without near-term supply chain impacts.
DOE has concluded that the amended standards adopted in this final rule
are technologically feasible and economically justified. A detailed
discussion of DOE's analysis and conclusion is provided in section V.C
of this document.
Specific comments regarding DOE's analysis are discussed in further
detail below.
B. Equipment Classes and Scope of Coverage
This final rule covers the COMMERCIAL AND INDUSTRIAL equipment that
meet the definition of ``distribution transformer'' as codified at 10
CFR 431.192.
When evaluating and establishing energy conservation standards, DOE
divides covered products into equipment classes by the type of energy
used or by capacity or other performance-related features that justify
different standards. In making a determination whether a performance-
related feature justifies a different standard, DOE must consider the
utility of the feature to the consumer and other factors DOE determines
are appropriate. (42 U.S.C. 6316(a); 42 U.S.C. 6295(q)) The
distribution transformer equipment classes considered in this final
rule are discussed in detail in section IV.A.2 of this document.
This final rule covers distribution transformers, which are
currently defined as a transformer that (1) has an input voltage of
34.5 kV or less; (2) has an output voltage of 600 V or less; (3) is
rated for operation at a frequency of 60 Hz; and (4) has a capacity of
10 kVA to 2500 kVA for liquid-immersed units and 15 kVA to 2500 kVA for
dry-type units; but (5) the term ``distribution transformer'' does not
include a transformer that is an autotransformer; drive (isolation)
transformer; grounding transformer; machine-tool (control) transformer;
non-ventilated transformer; rectifier transformer; regulating
transformer; sealed transformer; special-impedance transformer; testing
transformer; transformer with tap range of 20 percent or more;
uninterruptible power supply transformer; or welding transformer. 10
CFR 431.192.
See section IV.A.1 of this document for discussion of the scope of
coverage and product classes analyzed in this final rule.
C. Test Procedure
EPCA sets forth generally applicable criteria and procedures for
DOE's adoption and amendment of test procedures. (42 U.S.C. 6314(a))
Manufacturers of covered equipment must use these test procedures as
the basis for certifying to DOE that their product complies with the
applicable energy conservation standards and as the basis for any
representations regarding the energy use or energy efficiency of the
equipment. (42 U.S.C. 6316(e)(1); 42 U.S.C. 6295(s); and 42 U.S.C.
6314(d)). Similarly, DOE must use these test procedures to evaluate
whether a basic model complies with
[[Page 29867]]
the applicable energy conservation standard(s). 10 CFR 429.110(e). The
current test procedure for distribution transformers is codified at 10
CFR part 431, subpart K, appendix A (``appendix A''). Appendix A
includes provisions for determining percentage efficiency at rated per-
unit load (PUL), the metric on which current standards are based. 10
CFR 431.193.
On September 14, 2021, DOE published a test procedure final rule
for distribution transformers that contained revised definitions for
certain terms, updated provisions based on the latest versions of
relevant industry test standards, maintained PUL for the certification
of efficiency, and added provisions for representing efficiency at
alternative PULs and reference temperatures. 86 FR 51230 (``September
2021 TP Final Rule''). DOE determined that the amendments to the test
procedure adopted in the September 2021 TP Final Rule do not alter the
measured efficiency of distribution transformers or require retesting
or recertification solely as a result of DOE's adoption of the
amendments to the test procedure. 86 FR 51230, 51249.
Carte commented that they are not sure how to report data for a
transformer with a dual-rated kVA based on the division of single-phase
and three-phase power. (Carte, No. 140 at p. 9)
For distribution transformers, efficiency must be determined for
each basic model, as defined in 10 CFR 431.192. Questions regarding how
to report data for a specific unit can be submitted to
[email protected].
Eaton commented that if DOE adopts higher efficiency standards, DOE
should revisit the alternative methods for determining energy
efficiency and energy use (AEDM) tolerance requirements in 10 CFR
429.70, because the original tolerances were based on a much higher
number of absolute losses and amended standards would be based on a
much smaller number of losses. (Eaton, No. 137 at pp. 29-30) Therefore,
even though the difference in watts of loss could be similar, the
percentage difference in losses may exceed the current requirements in
10 CFR 429.70. Id.
DOE notes that AEDM requirements are handled in a separate
rulemaking that spans all certification, labeling, and enforcement
provisions across many products and equipment (see Docket No. EERE-
2023-BT-CE-0001). AEDMs are widely used in certifying the efficiency of
distribution transformers and DOE intends to continue to allow this
under amended efficiency standards. DOE encourages stakeholders to
submit any comment and data regarding distribution transformer AEDM
tolerances to the docket referenced above.
D. Technological Feasibility
1. General
As discussed, any new or amended energy conservation standard must
be designed to achieve the maximum improvement in energy efficiency
that DOE determines is technologically feasible and economically
justified. (42 U.S.C. 6316(a); 42 U.S.C. 6295(o)(2)(A))
To determine whether potential amended standards would be
technologically feasible, DOE first develops a list of all known
technologies and design options that could improve the efficiency of
the products or equipment that are the subject of the rulemaking. DOE
considers technologies incorporated in commercially available products
or in working prototypes to be ``technologically feasible.'' 10 CFR
431.4; 10 CFR 430, subpart C, appendix A, sections 6(b)(3)(i) and
7(b)(1). Section IV.A.3 of this document discusses the technology
options identified by DOE for this analysis. For further details on the
technology assessment conducted for this final rule, see chapter 3 of
the final rule TSD.
After DOE has determined which, if any, technologies and design
options are technologically feasible, it further evaluates each
technology and design option in light of the following additional
screening criteria: (1) practicability to manufacture, install, and
service; (2) adverse impacts on product utility or availability; (3)
adverse impacts on health or safety; and (4) unique-pathway proprietary
technologies. 10 CFR 431.4; 10 CFR 430, subpart C, appendix A, sections
6(b)(3)(ii) through(v) and 7(b)(2) through(5). Those technology options
that are ``screened out'' based on these criteria are not considered
further. Those technology and design options that are not screened out
are considered as the basis for higher efficiency levels that DOE could
consider for potential amended standards. Section IV.B of this document
discusses the results of this screening analysis conducted for this
final rule. For further details on the screening analysis conducted for
this final rule, see chapter 4 of the final rule TSD.
2. Maximum Technologically Feasible Levels
EPCA requires that for any proposed rule that prescribes an amended
or new energy conservation standard, or prescribes no amendment or no
new standard for a type (or class) of covered product, DOE must
determine the maximum improvement in energy efficiency or maximum
reduction in energy use that is technologically feasible for each type
(or class) of covered products. (42 U.S.C. 6313(a); 42 U.S.C.
6295(p)(1)). Accordingly, in the engineering analysis, DOE identifies
the maximum efficiency level currently available on the market. DOE
also defines a ``max-tech'' efficiency level, representing the maximum
theoretical efficiency that can be achieved through the application of
all available technology options retained from the screening
analysis.\36\ In many cases, the max-tech efficiency level is not
commercially available because it is not currently economically
feasible.
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\36\ In applying these design options, DOE would only include
those that are compatible with each other that when combined, would
represent the theoretical maximum possible efficiency.
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E. Energy Savings
1. Determination of Savings
For each trial standard level (TSL), DOE projected energy savings
from application of the TSL to distribution transformers purchased in
the 30-year period that begins in the year of compliance with the
amended standards (2029-2058).\37\ The savings are measured over the
entire lifetime of equipment purchased in the 30-year analysis period.
DOE quantified the energy savings attributable to each TSL as the
difference in energy consumption between each standards case and the
no-new-standards case. The no-new-standards case represents a
projection of energy consumption that reflects how the market for a
product would likely evolve in the absence of amended energy
conservation standards.
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\37\ DOE also presents a sensitivity analysis that considers
impacts for products shipped in a 9-year period. See section V.B.3
of this document for additional detail.
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DOE used its national impact analysis (NIA) spreadsheet models to
estimate national energy savings (NES) from potential amended standards
for distribution transformers. The NIA spreadsheet model (described in
section IV.H of this document) calculates energy savings in terms of
site energy, which is the energy directly consumed by products at the
locations where they are used. For electricity, DOE reports national
energy savings in terms of primary energy savings, which is the savings
in the energy that is used to generate and transmit the site
electricity. For natural gas, the primary energy savings are considered
to be
[[Page 29868]]
equal to the site energy savings. DOE also calculates NES in terms of
FFC energy savings. The FFC metric includes the energy consumed in
extracting, processing, and transporting primary fuels (i.e., coal,
natural gas, petroleum fuels), and thus presents a more complete
picture of the impacts of energy conservation standards.\38\ DOE's
approach is based on the calculation of an FFC multiplier for each of
the energy types used by covered products or equipment. For more
information on FFC energy savings, see section IV.H.2 of this document.
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\38\ The FFC metric is discussed in DOE's statement of policy
and notice of policy amendment. 76 FR 51282 (Aug. 18, 2011), as
amended at 77 FR 49701 (Aug. 17, 2012).
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2. Significance of Savings
To adopt any new or amended standards for a covered product, DOE
must determine that such action would result in significant energy
savings. (42 U.S.C. 6295(o)(3)(B))
The significance of energy savings offered by a new or amended
energy conservation standard cannot be determined without knowledge of
the specific circumstances surrounding a given rulemaking.\39\ For
example, some covered products and equipment have most of their energy
consumption occur during periods of peak energy demand. The impacts of
these products on the energy infrastructure can be more pronounced than
products with relatively constant demand. Accordingly, DOE evaluates
the significance of energy savings on a case-by-case basis, taking into
account the significance of cumulative FFC national energy savings, the
cumulative FFC emissions reductions, and the need to confront the
global climate crisis, among other factors.
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\39\ The numeric threshold for determining the significance of
energy savings established in a final rule published on February 14,
2020 (85 FR 8626, 8670), was subsequently eliminated in a final rule
published on December 13, 2021 (86 FR 70892).
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As stated, the standard levels adopted in this final rule for all
distribution transformers are projected to result in national energy
savings of 4.58 quad, the equivalent of the primary annual energy use
of 49.2 million homes . Based on the amount of FFC savings, the
corresponding reduction in emissions, and the need to confront the
global climate crisis, DOE has determined the energy savings from the
standard levels adopted in this final rule are ``significant'' within
the meaning of 42 U.S.C. 6316(a); 42 U.S.C. 6295(o)(3)(B).
F. Economic Justification
1. Specific Criteria
As noted previously, EPCA provides seven factors to be evaluated in
determining whether a potential energy conservation standard is
economically justified. (42 U.S.C. 6316(a); 42 U.S.C.
6295(o)(2)(B)(i)(I)-(VII)) The following sections discuss how DOE has
addressed each of those seven factors in this rulemaking.
a. Economic Impact on Manufacturers and Consumers
In determining the impacts of potential new or amended standards on
manufacturers, DOE conducts an MIA, as discussed in section IV.J. DOE
first uses an annual cash flow approach to determine the quantitative
impacts. This step includes both a short-term assessment--based on the
cost and capital requirements during the period between when a
regulation is issued and when entities must comply with the
regulation--and a long-term assessment over a 30-year period. The
industry-wide impacts analyzed include (1) INPV, which values the
industry on the basis of expected future cash flows; (2) cash flows by
year; (3) changes in revenue and income; and (4) other measures of
impact, as appropriate. Second, DOE analyzes and reports the impacts on
different types of manufacturers, including impacts on small
manufacturers. Third, DOE considers the impact of standards on domestic
manufacturer employment and manufacturing capacity, as well as the
potential for standards to result in plant closures and loss of capital
investment. Finally, DOE takes into account cumulative impacts of
various DOE regulations and other regulatory requirements on
manufacturers.
For individual consumers, measures of economic impact include the
changes in LCC and PBP associated with new or amended standards. These
measures are discussed further in the following section. For consumers
in the aggregate, DOE also calculates the national net present value of
the consumer costs and benefits expected to result from particular
standards. DOE also evaluates the impacts of potential standards on
identifiable subgroups of consumers that may be affected
disproportionately by a standard.
b. Savings in Operating Costs Compared to Increase in Price (LCC and
PBP)
EPCA requires DOE to consider the savings in operating costs
throughout the estimated average life of the covered product in the
type (or class) compared to any increase in the price of, or in the
initial charges for, or maintenance expenses of, the covered product
that are likely to result from a standard. (42 U.S.C. 6316(a); 42
U.S.C. 6295(o)(2)(B)(i)(II)) DOE conducts this comparison in its LCC
and PBP analysis.
The LCC is the sum of the purchase price of a product (including
its installation) and the operating cost (including energy,
maintenance, and repair expenditures) discounted over the lifetime of
the product. The LCC analysis requires a variety of inputs, such as
product prices, product energy consumption, energy prices, maintenance
and repair costs, product lifetime, and discount rates appropriate for
consumers. To account for uncertainty and variability in specific
inputs, such as product lifetime and discount rate, DOE uses a
distribution of values, with probabilities attached to each value.
The PBP is the estimated amount of time (in years) it takes
consumers to recover the increased purchase cost (including
installation) of a more efficient product through lower operating
costs. DOE calculates the PBP by dividing the change in purchase cost
due to a more stringent standard by the change in annual operating cost
for the year that standards are assumed to take effect.
For its LCC and PBP analysis, DOE assumes that consumers will
purchase the covered equipment in the first year of compliance with new
or amended standards. The LCC savings for the considered efficiency
levels are calculated relative to the case that reflects projected
market trends in the absence of new or amended standards. DOE's LCC and
PBP analysis is discussed in further detail in section IV.F.
c. Energy Savings
Although significant conservation of energy is a separate statutory
requirement for adopting an energy conservation standard, EPCA requires
DOE, in determining the economic justification of a standard, to
consider the total projected energy savings that are expected to result
directly from the standard. (42 U.S.C. 6316(a); 42 U.S.C.
6295(o)(2)(B)(i)(III)) As discussed in section IV.H, DOE uses the NIA
spreadsheet models to project national energy savings.
d. Lessening of Utility or Performance of Products
In establishing equipment classes, and in evaluating design options
and the impact of potential standard levels, DOE evaluates potential
standards that would not lessen the utility or performance of
[[Page 29869]]
the considered equipment. (42 U.S.C. 6316(a); 42 U.S.C.
6295(o)(2)(B)(i)(IV)) Based on data available to DOE, the standards
adopted in this document would not reduce the utility or performance of
the equipment under consideration in this rulemaking.
e. Impact of Any Lessening of Competition
EPCA directs DOE to consider the impact of any lessening of
competition, as determined in writing by the Attorney General, that is
likely to result from a standard. (42 U.S.C. 6316(a); 42 U.S.C.
6295(o)(2)(B)(i)(V)) It also directs the Attorney General to determine
the impact, if any, of any lessening of competition likely to result
from a standard and to transmit such determination to the Secretary
within 60 days of the publication of a proposed rule, together with an
analysis of the nature and extent of the impact. (42 U.S.C. 6316(a); 42
U.S.C. 6295(o)(2)(B)(ii))
NAHB expressed concern that DOE has not published the determination
made by the Attorney General on the impact of any lessening of
competition that may result from this rule and recommended DOE withdraw
its proposal until stakeholders have had the opportunity to review this
document. (NAHB, No. 106 at p. 2)
Under EPCA, the Attorney General is required to make a
determination of the impact, if any, of any lessening of competition
likely to result from such standard no later than 60 days after
publication of the proposed rule. DOE is then required to publish any
such determination in the Federal Register. To assist the Department of
Justice (DOJ) in making such a determination, DOE transmitted copies of
its proposed rule and the NOPR TSD to the Attorney General for review,
with a request that the DOJ provide its determination on this issue. In
its assessment letter responding to DOE, DOJ concluded that the
proposed energy conservation standards for distribution transformers
are unlikely to have a significant adverse impact on competition. In
accordance with EPCA, DOE is publishing the Attorney General's
assessment at the end of this final rule.
f. Need for National Energy Conservation
DOE also considers the need for national energy and water
conservation in determining whether a new or amended standard is
economically justified. (42 U.S.C. 6316(a); 42 U.S.C.
6295(o)(2)(B)(i)(VI)) The energy savings from the adopted standards are
likely to provide improvements to the security and reliability of the
Nation's energy system. Reductions in the demand for electricity also
may result in reduced costs for maintaining the reliability of the
Nation's electricity system. DOE conducts a utility impact analysis to
estimate how standards may affect the Nation's needed power generation
capacity, as discussed in section IV.M of this document.
DOE maintains that environmental and public health benefits
associated with the more efficient use of energy are important to take
into account when considering the need for national energy
conservation. The adopted standards are likely to result in
environmental benefits in the form of reduced emissions of air
pollutants and GHGs associated with energy production and use. DOE
conducts an emissions analysis to estimate how potential standards may
affect these emissions, as discussed in section IV.K of this document;
the estimated emissions impacts are reported in section V.B.6 of this
document. DOE also estimates the economic value of emissions reductions
resulting from the considered TSLs, as discussed in section IV.L of
this document.
g. Other Factors
In determining whether an energy conservation standard is
economically justified, DOE may consider any other factors that the
Secretary deems to be relevant. (42 U.S.C. 6316(a); 42 U.S.C.
6295(o)(2)(B)(i)(VII)) To the extent DOE identifies any relevant
information regarding economic justification that does not fit into the
other categories described previously, DOE could consider such
information under ``other factors.''
2. Rebuttable Presumption
EPCA creates a rebuttable presumption that an energy conservation
standard is economically justified if the additional cost to the
equipment that meets the standard is less than three times the value of
the first year's energy savings resulting from the standard, as
calculated under the applicable DOE test procedure. (42 U.S.C. 6316(a);
42 U.S.C. 6295(o)(2)(B)(iii)) DOE's LCC and PBP analyses generate
values used to calculate the effect potential amended energy
conservation standards would have on the PBP for consumers. These
analyses include, but are not limited to, the 3-year PBP contemplated
under the rebuttable-presumption test. In addition, DOE routinely
conducts an economic analysis that considers the full range of impacts
to consumers, manufacturers, the Nation, and the environment, as
required under 42 U.S.C. 6316(a); 42 U.S.C. 6295(o)(2)(B)(i). The
results of this analysis serve as the basis for DOE's evaluation of the
economic justification for a potential standard level (thereby
supporting or rebutting the results of any preliminary determination of
economic justification). The rebuttable presumption payback calculation
is discussed in section IV.F.11 of this final rule.
IV. Methodology and Discussion of Related Comments
This section addresses the analyses DOE has performed for this
rulemaking with regard to distribution transformers. Separate
subsections address each component of DOE's analyses.
DOE used several analytical tools to estimate the impact of the
standards considered in this document. The first tool is a spreadsheet
that calculates the LCC savings and PBP of potential amended or new
energy conservation standards. The national impacts analysis uses a
second spreadsheet set that provides shipments projections and
calculates national energy savings and net present value of total
consumer costs and savings expected to result from potential energy
conservation standards. DOE uses the third spreadsheet tool, the
Government Regulatory Impact Model (GRIM), to assess manufacturer
impacts of potential standards. These three spreadsheet tools are
available on the DOE website for this rulemaking: www.regulations.gov/docket/EERE-2019-BT-STD-0018. Additionally, DOE used output from the
latest version of the Energy Information Administration's (EIA's)
Annual Energy Outlook (AEO) for the emissions and utility impact
analyses.
A. Market and Technology Assessment
DOE develops information in the market and technology assessment
that provides an overall picture of the market for the products
concerned, including the purpose of the products, the industry
structure, manufacturers, market characteristics, and technologies used
in the products. This activity includes both quantitative and
qualitative assessments, based primarily on publicly available
information. The subjects addressed in the market and technology
assessment for this rulemaking include (1) a determination of the scope
of the rulemaking and product classes, (2) manufacturers and industry
structure, (3) existing efficiency programs, (4) shipments information,
(5) market and industry trends, and (6) technologies or design options
that could improve the energy efficiency of distribution transformers.
[[Page 29870]]
The key findings of DOE's market assessment are summarized in the
following sections. See chapter 3 of the final rule TSD for further
discussion of the market and technology assessment.
1. Scope of Coverage
The current definition for a distribution transformer codified in
10 CFR 431.192 is the following:
Distribution transformer means a transformer that--(1) has an input
voltage of 34.5 kV or less; (2) has an output voltage of 600 V or less;
(3) is rated for operation at a 60 Hz; and (4) has a capacity of 10 kVA
to 2500 kVA for liquid-immersed units and 15 kVA to 2500 kVA for dry-
type units; but (5) The term ``distribution transformer'' does not
include a transformer that is an--(i) autotransformer; (ii) drive
(isolation) transformer; (iii) grounding transformer; (iv) machine-tool
(control) transformer; (v) non-ventilated; (vi) rectifier transformer;
(vii) regulating transformer; (viii) sealed transformer; (ix) special-
impedance transformer; (x) testing transformer; (xi) transformer with
tap range of 20 percent or more; (xii) uninterruptible power supply
transformer; or (xiii) Welding transformer.
In the January 2023 NOPR, DOE discussed and proposed minor edits to
the definitions of equipment excluded from the definition of
distribution transformer. In response to the January 2023 NOPR, DOE
received additional comments on its proposed definitional edits. These
detailed comments are discussed below.
a. Autotransformers
The EPCA definition of distribution transformer excludes ``a
transformer that is designed to be used in a special purpose
application and is unlikely to be used in general purpose applications,
such as . . . [an] auto-transformer . . .''. (42 U.S.C.
6291(35)(b)(ii)) DOE has defined autotransformer as ``a transformer
that: (1) has one physical winding that consists of a series winding
part and a common winding part; (2) has no isolation between its
primary and secondary circuits; and (3) during step-down operation, has
a primary voltage that is equal to the total of the series and common
winding voltages, and a secondary voltage that is equal to the common
winding voltage.'' 10 CFR 431.192.
In the January 2023 NOPR, DOE noted that, while stakeholders
suggested that there may be certain applications for which
autotransformers may be substitutable for an isolation transformer,
these substitutions would be limited to specific applications and not
common enough to regard as general practice. 88 FR 1722, 1741. Further,
DOE stated that, because autotransformers do not provide galvanic
isolation, they are unlikely to be used in at least some general-
purpose applications. DOE did not propose to amend the exclusion of
autotransformers under the distribution transformer definition. Id.
Schneider commented that autotransformers were used in the 1970's
for distribution application. However, they do not allow for the
creation of a neutral on the secondary side of the transformer nor do
they allow for isolating the secondary and primary windings for power
quality benefits. (Schneider, No. 101 at p. 15) Schneider commented
that for applications with small loads, based on the increased purchase
price and footprints at the proposed efficiency levels, the market will
begin evaluating autotransformers and applying them to certain
distribution applications. Id. Schneider recommended the statutory
definition of low-voltage transformer be modified through legislation
to subject autotransformers to energy conservation standards. Id. at p.
17.
DOE agrees that in certain applications, autotransformers may be
capable of serving as a replacement for general purpose transformers.
However, as discussed, the isolation and power quality benefits of
distribution transformers make it unlikely that autotransformers would
be widely viewed or used as a substitute for most general purpose
distribution transformers. DOE notes that manufacturer literature
already markets autotransformers as an ``economical alternative to
general purpose distribution isolation transformers to adjust the
supply voltage to match specific load requirements when load isolation
from the supply line is not required.'' \40\ As noted in the marketing,
autotransformers are only suitable in transformer applications where
load isolation is not required.
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\40\ Hammond Power Solutions. Autotransformers, 2023.
documents.hammondpowersolutions.com/documents/Literature/Specialty/HPS-Autotransformers-Brochure.pdf?_gl=1*db1907*_ga*NTA0ODk1MjQzLjE2NzExMzEzMTM.*_ga_RTZEGSXND8*MTY4MzIxNTc5My42Ni4xLjE2ODMyMTcyNjcuNTguMC4w.
---------------------------------------------------------------------------
Despite autotransformers being less expensive, having a smaller
footprint than general purpose distribution transformers, and being
marketed as suitable in certain applications, autotransformers have not
seen widespread use in general purpose applications and their use has
been limited to special purposes. While autotransformers may be capable
of meeting similar efficiency regulations as general purpose
distribution transformers, they are statutorily excluded from the
definition of distribution transformer on account of being reserved for
special purpose applications. Further, stakeholder comments reiterate
that there are legitimate shortcomings of autotransformer that makes
significant substitution unlikely. Based on this feedback, DOE has
concluded that autotransformers are designed to be used in a special
purpose application and are unlikely to be used in general purpose
applications due to these shortcomings. Therefore, DOE is not amending
the exclusion of autotransformers under the distribution transformer
definition. DOE will continue to evaluate the extent to which
autotransformers are used in general purpose applications in future
rulemakings.
b. Drive (Isolation) Transformers
The EPCA definition of distribution transformer excludes a
transformer that is designed to be used in a special purpose
application and is unlikely to be used in general purpose applications,
such as drive transformers. (42 U.S.C. 6291(35)(b)(ii)). DOE defines a
drive (isolation) transformer as a ``transformer that (1) isolates an
electric motor from the line; (2) accommodates the added loads of
drive-created harmonics; and (3) is designed to withstand the
mechanical stresses resulting from an alternating current adjustable
frequency motor drive or a direct current motor drive.'' 10 CFR
431.192.
In the January 2023 NOPR, DOE responded to comments by Schneider
and Eaton submitted on the August 2021 Preliminary Analysis TSD that
claimed drive-isolation transformers have historically been sold with
non-standard low-voltage ratings corresponding to typical motor input
voltages, and as such were unlikely to be used in general-purpose
applications. (Schneider, No. 49 at p. 3; Eaton, No. 55 at p. 3)
Schneider and Eaton commented that they had seen a recent increase in
drive-isolation transformers specified as having either a ``480Y/277''
or ``208Y/120'' voltage secondary, making it more difficult to
ascertain whether these transformers were being used in general purpose
applications. (Schneider, No. 49 at p. 3; Eaton, No. 55 at p. 3)
In response to these comments, DOE noted that while some drive-
isolation transformers could, in theory, be used in general purpose
applications, no evidence exists to suggest this is common practice. 88
FR 1722, 1742.
[[Page 29871]]
Therefore, DOE concluded that drive-isolation transformers remain an
example of a transformer that is designed to be used in special purpose
applications and excluded by statute. However, DOE also noted that the
overwhelming majority of general purpose applications use either 208Y/
120 or 480Y/277 voltage while the overwhelming majority of drive-
isolation transformers are designed with alternative voltages designed
to match specific motor drives. Id. Therefore, DOE stated that a drive-
isolation transformer with a rated secondary voltage of 208Y/120 or
480Y/277 is considerably more likely to be used in general purpose
applications.
DOE proposed to amend the definition of drive (isolation)
transformer to include the criterion that drive-isolation transformers
have an output voltage other than 208Y/120 and 480Y/277. 88 FR 1722,
1742. DOE requested comment on its determination that a drive-isolation
transformer with these common voltage ratings is likely to be used in
general purpose applications and if any other common voltage ratings
would indicate likely use in general purpose applications. Id.
In response, Schneider commented that it agrees with the evaluation
completed by DOE and the proposed definition. (Schneider, No. 101 at p.
3) Schneider recommended Congress modify the statutory definition of
LVDT distribution transformer to include all six-pulse drive-isolation
transformers. (Schneider, No. 101 at p. 17) Schneider further commented
that even if customers do need a secondary 208Y/120 or 480Y/277 voltage
for their drive applications, they would still be able to purchase a
transformer, but it would just be an energy efficient model.
(Schneider, No. 101 at p. 3) Schneider has previously commented that
six-pulse drive-isolation transformers are within the LVDT scope in
Canada and their energy conservation standards align with current DOE
energy conservation standards. (Schneider, No. 49 at p. 4) Therefore,
energy efficient models are readily available for purchase.
NEMA commented that voltage ratings are a poor measure to capture
the distinction between general purpose applications and special
purpose applications. (NEMA, No. 141 at p. 7) NEMA did not provide an
alternative recommendation.
DOE has previously stated that it intends to strictly and narrowly
construe the exclusions from the definition of ``distribution
transformer.'' 84 FR 24972, 24979 (April 27, 2009). Drive-isolation
transformers are excluded from the definition of distribution
transformers because 42 U.S.C. 6291 lists them as a special purpose
product unlikely to be used in general purpose applications. (42 U.S.C.
6291(35)(b)(ii)) Therefore, even if all six-pulse drive-isolation
transformers may be able to meet energy conservation standards, most
drive-isolation transformers remain statutorily excluded since they are
designed to be used in special purpose applications and are unlikely to
be used in a general purpose application. To the extent that some
transformers are marketed as drive-isolation transformers with rated
output voltages aligning with common distribution voltages, DOE is
unable to similarly conclude that these transformers are designed to be
used in special purpose applications and are unlikely to be used in
general purpose applications.
While NEMA commented that relying on output voltages may not
capture the distinctions between all drive-isolation transformers and
distribution transformers, NEMA did not provide any data to refute
DOE's tentative determination that a transformer marketed as a drive-
isolation transformer with rated output voltages aligning with common
distribution voltages would be significantly more likely to be used in
general purpose distribution applications. Further, as stated by
Schneider, DOE's proposal does not prevent consumers that need these
secondary voltages for their drive applications from purchasing a
suitable product, it only requires them to purchase a product that
meets energy conservation standards.
Based on the foregoing discussion, DOE is finalizing its proposed
definition for drive (isolation) transformer to mean ``a transformer
that: (1) isolates an electric motor from the line; (2) accommodates
the added loads of drive-created harmonics; (3) is designed to
withstand the additional mechanical stresses resulting from an
alternating current adjustable frequency motor drive or a direct
current motor drive; and (4) has a rated output voltage that is neither
`208Y/120' nor `480Y/277'.''
c. Special-Impedance Transformers
Impedance is an electrical property that relates voltage across and
current through a distribution transformer. It may be selected to
balance voltage drop, overvoltage tolerance, and compatibility with
other elements of the local electrical distribution system. A
transformer built to operate outside of the normal impedance range for
that transformer's kVA rating, as specified in Tables 1 and 2 of 10 CFR
431.192 under the definition of ``special-impedance transformer,'' is
excluded from the definition of ``distribution transformer.'' 10 CFR
431.192.
In the January 2023 NOPR, DOE noted that the current tables in the
``special-impedance transformer'' definition do not explicitly address
how to treat non-standard kVA values (e.g., kVA values between those
listed in the ``special-impedance transformer'' definition). 88 FR
1722, 1742-1743. DOE proposed to amend the definition of ``special-
impedance transformer'' to specify that ``distribution transformers
with kVA ratings not appearing in the tables shall have their minimum
normal impedance and maximum normal impedance determined by linear
interpolation of the kVA and minimum and maximum impedances,
respectively, of the values immediately above and below that kVA
rating.'' Id. DOE noted that this approach was consistent with the
approach specified for determining the efficiency requirements of
distribution transformers of non-standard kVA rating (i.e., using a
linear interpolation from the nearest bounding kVA values listed in the
table). See 10 CFR 431.196. DOE requested comment on this proposed
amendment and whether it provided sufficient clarity as to how to treat
the normal impedance ranges for non-standard kVA distribution
transformers. Id.
In response to the January 2023 NOPR, Prolec GE commented that the
proposed definition is a helpful clarification. (Prolec GE, No. 120 at
p. 5). NEMA, Howard, and Eaton all recommended DOE specify normal
impedance for kVA ranges rather than using a linear interpolation
method. (NEMA, No. 141 at pp. 7-8; Howard, No. 116 at pp. 6-7; Eaton,
No. 137 at pp. 5-11)
Eaton further commented that the industry assumption was that a
given impedance range was intended to apply to all non-standard kVA
ratings occurring between two standard kVA ratings and the confusion
was as to whether the impedance ranged corresponding to the lower, or
the upper preferred kVA rating should be used. (Eaton, No. 137 at p. 5)
Eaton identified two potential approaches, the ascending approach,
wherein the impedance range is intended to change only upon reaching
the next higher preferred kVA, and the descending approach, wherein the
impedance range is intended to change immediately upon exceeding the
lower kVA rating. (Eaton, No. 137 at pp. 5-7). Eaton commented that the
normal impedance ranges change gradually with the only significant jump
being between 500 to 666 kVA single-phase
[[Page 29872]]
and 500 to 749 kVA three-phase, where the lower bound of the normal
impedance range jumps from 1.0 percent to 5.0 percent. (Eaton, No. 137
at p. 7)
Eaton provided shipment data for years 2016 through 2022 for non-
standard kVAs that coincide with this jump in the lower-bound of normal
impedance. (Eaton, No. 137 at pp. 7-8) Eaton commented that they built
zero non-standard kVA single-phase units between 501 and 666 kVA and 80
non-standard kVA three-phase units. Eaton added that of those 80 units,
57 were outside of scope regardless of the impedance, while the
remaining 23 units were treated as within DOE's scope of coverage. Id.
Of those units, only seven units were between 1.5 and 5.0 percent
impedance. Meaning under the ascending interpretation, these seven
units would be in-scope and under the descending interpretation, these
seven units would be out of scope. Eaton provided the impedance for all
23 units. Id. DOE notes that all 23 units would be within scope under
both the ascending interpretation and the proposed linear interpolation
method, as the unit impedance values fall within the normal impedance
range of both the ascending interpretation and the proposed linear
interpolation method.
Eaton commented that current industry standards do not provide a
clear answer but in comparing the ascending interpretation and the
proposed linear interpolation, the linear interpolation is somewhat
more computationally cumbersome and more confusing to audit. (Eaton,
No. 137 at pp. 8-11) For these reasons, Eaton recommended DOE adopt
normal-impedance tables with an ascending interpretation on kVA ranges.
(Eaton, No. 137 at p. 11).
While Howard and NEMA didn't explicitly discuss the differences
between the ascending interpretation, descending interpretation, and
linear-interpolation methods, both recommended tables that apply the
ascending interpretation. (NEMA, No. 141 at pp. 7-8; Howard, No. 116 at
pp. 6-7)
As noted, DOE has not previously stated what the normal impedance
ranges for non-standard kVA transformers are intended to be. While DOE
proposed a linear interpolation, Eaton's data suggested that adopting
an ascending interpretation would include an identical number of
transformers within scope of the distribution transformer rulemaking.
Further, multiple stakeholders preferred the simplicity of the
ascending interpretation. Given that the number of impacted
transformers is unchanged, the simplicity of defining normal impedance
based on kVA ranges, and stakeholder support for the ascending
interpretation, DOE is adopting amended tables to specify the normal
impedance ranges for non-standard kVA transformers using an ascending
interpretation. The adopted normal impedance ranges for each kVA range
are given in Table IV.1 and Table IV.2.
[GRAPHIC] [TIFF OMITTED] TR22AP24.528
[GRAPHIC] [TIFF OMITTED] TR22AP24.529
d. Tap Range of 20 Percent or More
Distribution transformers are commonly sold with voltage taps that
allow manufacturers to adjust for minor differences in the input or
output voltage. Transformers with multiple voltage taps, the highest of
which equals at least 20 percent more than the lowest, computed based
on the sum of the deviations of the voltages of these taps from the
transformer's nominal voltage, are excluded from the definition of
distribution transformers. 10 CFR 431.192. (See also 42 U.S.C.
6291(35)(B)(i))
In the response to the August 2021 Preliminary Analysis TSD,
Schneider, NEMA, and Eaton recommended that only full-power taps should
be permitted for tap range calculations. (Eaton, No. 55 at pp. 5-6;
Schneider, No. 49 at pp. 5-6; NEMA, No. 50 at p. 4) Schneider and Eaton
commented that the nominal voltage by which the tap range is calculated
is a consumer choice and could result in two physically identical
transformers being subject to standards or not, depending on the choice
of nominal voltage. (Schneider No. 49 at p. 6; Eaton No. 55 at pp. 6-7)
In the January 2023 NOPR, DOE noted that, while traditional
industry understanding of tap range is in percentages relative to the
nominal voltage, stakeholder comments suggest that such a calculation
can be applied such that two physically identical distribution
transformers can be inside or outside of scope depending on the choice
of nominal voltage. 88 FR 1722. To have a consistent standard for
physically identical distribution
[[Page 29873]]
transformers, DOE proposed to modify the calculation of tap range to
only include full-power capacity taps and calculate tap range based on
the transformer's maximum voltage rather than nominal voltage.
Prolec GE and NEMA commented that the proposed amendment to the
calculation of a tap range of 20 percent or more was clear and removed
ambiguity. (Prolec GE, No. 120 at p. 5; NEMA, No. 141 at p. 8) Howard
and Eaton supported the proposed definition but recommended DOE make
clarifying edits to avoid any confusion. (Howard, No. 116 at pp. 7-8;
Eaton, No. 137 at p. 12)
Specifically, Eaton recommended changing DOE's proposal to use
``full-power voltage taps'' to read ``a transformer with multiple
voltage taps, each capable of operating at full, rated capacity (kVA) .
. .'' (Eaton, No. 137 at p. 12) Eaton commented that this clarification
aligned with how full-power taps are more commonly described and
clarified that full-capacity refers to kVA. Id.
Eaton and Howard also both noted that the description of how to
calculate the tap range is confusing. Specifically, Eaton and Howard
identified the text where DOE proposed to state ``the highest of which
equals at least 20% more than the lowest, computed based on the sum of
the deviations of these taps from the transformer's maximum full-power
voltage.'' (Howard, No. 116 at pp. 7-8; Eaton, No. 137 at p. 12) Howard
recommended DOE state ``where the difference between the highest tap
voltage and the lowest tap voltage is 20 percent or more of the highest
tap voltage.'' (Howard, No. 116 at pp.7-8) Eaton recommended DOE state
``whose range, defined as the maximum tap voltage minus minimum tap
voltage, is 20 percent or more of the maximum tap voltage rating
appearing on the product nameplate.'' (Eaton, No. 137 at p. 12)
Schneider commented that the proposed definition does clearly
define how to calculate the tap percentage, but it does not address the
fact that common LVDT products meet these criteria. (Schneider, No. 101
at p. 3) Schneider identified certain LVDT products designed to span
multiple nominal voltages as having a tap-range greater than 20
percent. Id. Schneider recommended DOE modify the definition to allow
for only one standard nominal voltage rating (e.g., a transformer
spanning 480V and 600V would not be exempted because it includes two
standard voltage systems). Id.
Regarding Eaton's editorial suggestion as to how DOE specifies that
only full-power taps are used, DOE agrees that Eaton's wording is
clearer and better aligns with how industry addresses full-power taps.
Therefore, DOE is adopting language that using full-power taps means
``each capable of operating at full, rated capacity (kVA)''.
Regarding Eaton and Howard's editorial suggestion as to how DOE
communicates the calculation for the tap range, DOE notes that the
proposed definition simply modified the current definition in the CFR
to be based on the transformer's maximum full-power voltage, rather
than the nominal voltage. However, DOE agrees that, with more explicit
directions as to how to compute the tap range, the phrasing ``the
highest of which equals at least 20 percent more than the lowest''
could be redundant and confusing. Therefore, DOE is simplifying the
wording, in accordance with Howard and Eaton's suggestions to read that
``whose range, defined as the difference between the highest tap
voltage and lowest tap voltage, is 20 percent or more of the highest
tap voltage.''
Regarding Schneider's comment recommending that DOE only consider
``standard'' nominal voltage ratings to be eligible, DOE notes that the
adopted test procedure for measuring the energy consumption of
distribution transformers specifies how to handle reconfigurable
nominal windings in the case of a dual- or multi-voltage capable
transformers. (See appendix A to subpart K of 10 CFR part 431).
Transformer taps are intended to offer consumers the ability to
conduct minor corrections to system voltage. The addition of voltage
taps generally adds to a manufacturer's costs and reduces the
efficiency of a product due to requiring additional winding material.
Therefore, EPCA listed transformers with a tap range of 20 percent or
more as excluded from the scope of the distribution transformer
rulemaking. (See 42 U.S.C. 6291(35)(B)(i)) DOE's proposed amendment to
the definition of a transformer with a tap range of 20 percent or more
is only intended to clarify the provisions established under EPCA as to
how this tap range is to be calculated across physically identical
products. Transformers with tap ranges greater than 20 percent, are not
within the scope of distribution transformers as defined in this final
rule.
Based on the foregoing discussion, DOE is adopting a definition for
transformer with a tap range of 20 percent or more to mean ``a
transformer with multiple voltage taps, each capable of operating at
full, rated capacity (kVA), whose range, defined as the difference
between the highest voltage tap and the lowest voltage tap, is 20
percent or more of the highest voltage tap.''
e. Sealed and Non-Ventilated Transformers
The statutory definition of distribution transformer excludes
transformers that are designed to be used in a special purpose
application and are unlikely to be used in general purpose
applications, such as ``sealed and non-ventilated transformers.'' (42
U.S.C. 6291(356)(b)(ii)) DOE defines sealed transformer and non-
ventilated transformer at 10 CFR 431.192.
In the January 2023 NOPR, DOE proposed to modify the definitions of
sealed and non-ventilated transformers to clarify that only certain
``dry-type'' transformers meet the definition of sealed and non-
ventilated transformers. 88 FR 1722, 1744 DOE requested comment on this
proposed amendment. Id.
Eaton and NEMA commented that the amendment provides clarity and
agreed with including it in the definition. (Eaton, No. 137 at p. 13;
NEMA, No. 141 at p. 8) DOE received no further comment on the proposed
definition and is finalizing the clarification that sealed and non-
ventilated transformers only include ``dry-type'' transformers.
Regarding the statutory exclusion of non-ventilated transformers
broadly, Schneider commented that the original rationale for excluding
non-ventilated transformers from EPCA was because non-ventilated
transformers have higher core losses, which makes it difficult to meet
efficiency standards at 35-percent loading, and because their inclusion
would not drive significant energy savings. (Schneider, No. 101 at pp.
8-9) DOE notes that, because non-ventilated transformers do not have
airflow or oil surrounding the core and coil, they have a harder time
dissipating heat than general purpose dry-type distribution
transformers. Transformer thermal limitations are governed by total
losses at full load (i.e., 100-percent PUL), where load losses make up
a much higher percentage of total losses. As such, manufacturers of
sealed and non-ventilated transformers typically increase no-load
losses to decrease load losses, and therefore meet temperature rise
limitations.
Schneider commented that while non-ventilated transformers are
typically used in specialty applications,\41\ there is
[[Page 29874]]
nothing inherent about non-ventilated transformers that would prevent
them from being used in general purpose applications. (Schneider, No.
101 at pp. 8-9)
---------------------------------------------------------------------------
\41\ Nonventilated transformers are typically marketed for
specific hazardous environment applications where airborne
contaminants or large quantities of particles would potentially harm
the performance of a traditional ventilated distribution
transformer.
---------------------------------------------------------------------------
Schneider commented that non-ventilated transformers are typically
larger and higher priced than general purpose LVDTs, which has
historically discouraged consumers from using them in general purpose
applications. (Schneider, No. 101 at p. 16) However, Schneider noted
that if the proposed standards are adopted, specifically standards
requiring amorphous cores, the increased volume and cost of general
purpose LVDT units could become higher than non-ventilated units. Id.
Schneider commented that if that were the case, manufacturers may
choose to market non-ventilated transformer for general purpose
applications to avoid the capital investment required to produce
transformers with amorphous cores. Id. Schneider commented that if the
proposed standards are finalized, it expects 50 percent of the LVDT
market to purchase non-ventilated transformers instead of more
efficient products. Schneider stated that because non-ventilated
products are excluded from standards, the efficiency is likely to be
very low, which would have a negative impact on any potential savings
associated with LVDT transformers. Id. DOE notes that Schneider did not
provide any specific data as to the relative increase in weight or
production cost expected between non-ventilated transformers and
general purpose distribution transformers to demonstrate how Schneider
derived the 50 percent expected market share for non-ventilated
transformers.
Schneider recommended that manufacturers work with Congress to
modify the definition of low-voltage distribution transformer to remove
the exclusion for non-ventilated transformers. (Schneider, No. 101 at
p. 17)
DOE agrees that there are no technical features preventing a non-
ventilated transformer from being used in general purpose applications.
However, as described by Schneider, this substitution generally does
not occur in industry because of the challenges associated with
dissipating heat for non-ventilated transformers, which leads to non-
ventilated transformers being larger and more expensive than a
ventilated transformer of identical kVA. Further, dissipating heat
becomes more of a challenge as the size of the transformer increases
due to the significant amount of energy that larger transformers need
to shed. As a result, the percentage increase in weight and cost of a
non-ventilated transformer relative to a general purpose LVDT unit is
greater for larger kVA transformers.
DOE reviewed manufacturer websites that listed product
specifications and prices for both general purpose LVDTs and non-
ventilated transformers (See Chapter 3 of the TSD). In general, DOE
observed that the relatively higher cost and weight for non-ventilated
transformers was considerably more than the modeled increase in cost
and weight for even max-tech general purpose LVDTs. Therefore, non-
ventilated distribution transformers are unlikely to become cost-
competitive with more efficient, general purpose distribution
transformers. Further, under the adopted standards, amorphous core
transformers are not required for LVDTs. Therefore, it is unlikely for
manufacturers to sell non-ventilated transformers into general purpose
applications. As such, DOE maintains that non-ventilated transformers
are statutorily excluded from the definition of distribution
transformer on account of being used only in special purpose
applications.
f. Step-Up Transformers
For transformers generally, the term ``step-up'' refers to the
function of a transformer providing greater output voltage than input
voltage. Step-up transformers primarily service energy producing
applications, such as solar or wind electricity generation. In these
applications, transformers accept an input source voltage, step-up the
voltage in the transformer, and output higher voltages that feed into
the electric grid. The definition of ``distribution transformer'' does
not explicitly exclude transformers designed for step-up operation.
However, most step-up transformers have an output voltage larger than
the 600 V limit specified in the distribution transformer definition.
See 10 CFR 431.192. (See also 42 U.S.C. 6291(35)(A)(ii))
In the January 2023 NOPR, DOE discussed how it is technically
possible to operate a step-up transformer in a reverse manner, by
connecting the high-voltage to the ``output'' winding of a step-up
transformer and the low-voltage to the ``input'' winding of a step-up
transformer, such that it functions as a distribution transformer. 88
FR 1722, 1744. However, DOE has also previously identified that this is
not a widespread practice. 78 FR 2336, 23354. Comments received in
response to the 2021 Preliminary Analysis TSD confirmed that, while
step-up transformers are typically less efficient than DOE standards
would mandate and step-up transformers could, in theory, be used in
distribution applications, this is not a common practice. 88 FR 1722,
1744. Feedback from stakeholders indicated that step-up transformers
typically serve a separate and unique application, often in the
renewable energy field where transformer designs may not be optimized
for the distribution market but rather are optimized for integration
with other equipment, such as inverters. Id. As such, DOE did not
propose to amend the definition of ``distribution transformer'' to
account for step-up transformers. Id.
DOE received additional comments specifically regarding low-voltage
step-up transformers in response to the January 2023 NOPR.
Schneider commented that there is confusion as to whether low-
voltage step-up transformers are included in scope and recommended DOE
explicitly state in the LVDT definition that both step-up and step-down
transformers are within scope. (Schneider, No. 101 at p. 4) NEMA
recommended clarifying that step-up LVDT transformers are within scope
since both the input and output voltages meet the definition of
distribution transformers. (NEMA, No. 141 at p. 9)
As previously noted, the definition of ``distribution transformer''
specifies that a transformer ``has an output voltage of 600 V or less''
and the definition of a low-voltage distribution transformer specifies
``a distribution transformer that has an input voltage of 600 volts or
less''. See 10 CFR 431.192. Any step-up transformer with a primary
input and output voltage less than our equal to 600 volts would
therefore meet the definition of a low-voltage dry-type distribution
transformer.
Any product meeting the definition of low-voltage dry-type
distribution transformer, would be subject to DOE standards. DOE is not
amending the definition of low-voltage dry-type distribution
transformer to specifically include step-up transformers as this could
be confusing to manufacturers of step-up transformers that do not meet
the voltage limits (and therefore are not within the scope of
distribution transformer efficiency standards). Further, as described
in the foregoing discussion, these low-voltage dry-type products are
already included within the definition of low-voltage dry-type
distribution transformer.
[[Page 29875]]
g. Uninterruptible Power Supply Transformers
``Uninterruptible power supply transformer'' is defined as a
transformer that is used within an uninterruptible power system, which
in turn supplies power to loads that are sensitive to power failure,
power sags, over voltage, switching transients, line noise, and other
power quality factors. 10 CFR 431.192. An uninterruptible power supply
transformer is excluded from the definition of distribution
transformer. 42 U.S.C. 6291(35)(B)(ii); 10 CFR 431.192. Such a system
does not step-down voltage, but rather it is a component of a power
conditioning device, and it is used as part of the electric supply
system for sensitive equipment that cannot tolerate system
interruptions or distortions to counteract such irregularities. 69 FR
45376, 45383. DOE has clarified that uninterruptible power supply
transformers do not ``supply power to'' an uninterruptible power
system; rather, they are ``used within'' the uninterruptible power
system. 72 FR 58190, 58204. This clarification is consistent with the
reference in the definition to transformers that are ``within'' the
uninterruptible power system. 10 CFR 431.192.
In the January 2023 NOPR, DOE noted that transformers at the input,
output or bypass that are supplying power to an uninterruptible power
system are not uninterruptible power supply transformers. 88 FR 1722,
1745. Accordingly, DOE proposed to amend the definition of
``uninterruptible power supply transformer'' to explicitly state that
transformers at the input, output, or bypass of a distribution
transformer are not a part of the uninterruptible power system and
requested comment on the proposed amendment. Id.
In response, NEMA recommended that DOE include in the definition of
an uninterruptible power supply transformer that these transformers
must include a core with an air gap and/or a shunt core. NEMA stated
these features prevent uninterruptible power supply transformers from
meeting the proposed efficiency standards and transformers that do not
include at least one of these attributes would not meet the definition
of an uninterruptible power supply transformer. (NEMA, No. 141 at p. 8)
Prolec GE commented that the proposed amendment to the definition
provides helpful clarification, but suggested DOE confirm its usage of
the terms ``uninterruptable'' and ``uninterruptible''. (Prolec GE, No.
120 at p. 5)
DOE notes that its usage of ``uninterruptable'' in the January 2023
NOPR was an inadvertent typographical error. In this final rule, all
instances of ``uninterruptable'' have been corrected to
``uninterruptible.''
Regarding NEMA's recommendation to include a requirement for a core
with an air gap and/or a shunt core, DOE reviewed available literature
to evaluate the relevance of these design features, specifically
regarding how prevalent they are in the design of uninterruptible power
supply transformers and how they may impact the efficiency of a
distribution transformer. Based on its review, DOE interprets the terms
``magnetic shunt'' and ``air gap'' as they appear in NEMA's comment to
refer to the definitions prescribed in in IEEE Standard 449-1998
(R2007) ``IEEE Standard for Ferroresonant Voltage Regulators'' (``IEEE
449'').\42\ IEEE 449 defines a magnetic shunt as ``the section of the
core of the ferroresonant transformer that provides the major path for
flux generated by the primary winding current that does not link the
secondary winding''; IEEE 449 defines an air gap as ``the space between
the magnetic shunt and the core, used to establish the required
reluctance of the shunt flux path.'' DOE understands these features to
provide a high reluctance pathway for excess magnetic flux such that
the secondary voltage will remain constant, even when the primary side
voltage fluctuates unexpectedly. This functionality would be
particularly useful in uninterruptible power supply transformers, which
provide a smooth and continuous supply of electricity to avoid damaging
any downstream equipment.
---------------------------------------------------------------------------
\42\ IEEE SA. (1998). IEEE 449-1998--IEEE Standard for
Ferroresonant Voltage Regulators (Accessed on 09/15/2023). Available
online at: standards.ieee.org/ieee/449/675/.
---------------------------------------------------------------------------
However, DOE notes that the definitions of ``air gap'' and
``magnetic shunt'' as they are presented in IEEE 449 do not appear to
be the only examples of these features as they appear in transformer
design. For example, stacked core designs have inherent air gaps that
do not provide the same high reluctance pathway for magnetic flux.
Additionally, DOE observed transformer designs advertised as having
``magnetic shunts,'' consisting of laminated steel sheets installed on
or surrounding the transformer core to prevent leakage flux from
affecting the transformer tank or other surrounding components. These
alternative applications for these features could create confusion as
to which transformers would meet the definition of an uninterruptible
power supply transformer.
While inclusion of either an ``air gap'' or ``shunt core'' may be
useful features in identifying uninterruptible power supply
transformers, DOE lacks sufficient data to properly characterize these
attributes. DOE also has not received sufficient feedback from
stakeholders to indicate that these features are exclusive to
uninterruptible power supply transformers or if they would encompass
many other transformers not intended to be uninterruptible power supply
transformers. Further, NEMA has previously commented that manufacturers
are applying the definition of uninterruptible power supply transformer
appropriately and clarification is not needed. (NEMA, No. 50 at p. 4)
DOE notes that the proposed definition only sought to codify DOE's
existing interpretation that uninterruptible power supply transformers
must be ``within'' an uninterruptible power system and not at the
``input, output, or bypass'' of an uninterruptible power system.
Therefore, in this final rule, DOE is finalizing the proposed
definition of ``uninterruptible power supply transformer.''
h. Voltage Specification
As stated, the definition of ``distribution transformer'' is based,
in part, on the voltage capacity of equipment, i.e., has an input
voltage of 34.5 kV or less, and has an output voltage of 600 V or less.
10 CFR 431.192. (42 U.S.C. 6291(35)(A)) Three-phase distribution
transformer voltage may be described as either ``line,'' i.e., measured
across two lines, or ``phase,'' i.e., measured across one line and the
neutral conductor. For delta-connected \43\ distribution transformers,
line and phase voltages are equal. For wye-connected distribution
transformers, line voltage is equal to phase voltage multiplied by the
square root of three.
---------------------------------------------------------------------------
\43\ Delta connection refers to three distribution transformer
terminals, each one connected to two power phases.
---------------------------------------------------------------------------
DOE notes that it previously stated that the definition of
distribution transformer applies to ``transformers having an output
voltage of 600 volts or less, not having only an output voltage of less
than 600 volts.'' \44\ 78 FR 23336, 23353. For example, a three-phase
wye-connected transformer for which the output phase voltage is at or
below 600 V, but the output line voltage is above
[[Page 29876]]
600 V would satisfy the output criteria of the distribution transformer
definition. DOE's test procedure requires that the measured efficiency
for the purpose of determining compliance be based on testing in the
configuration that produces the greatest losses, regardless of whether
that configuration alone would have placed the transformer at-large
within the scope of coverage. Id. Similarly, with input voltages, a
transformer is subject to standards if either the ``line'' or ``phase''
voltages fall within the voltage limits in the definition of
distribution transformers, so long as the other requirements of the
definition are also met. Id
---------------------------------------------------------------------------
\44\ Inclusive of a transformer at 600 volts.
---------------------------------------------------------------------------
In response to the August 2021 Preliminary Analysis TSD, DOE
received feedback that it should clarify the interpretation of voltage
in the regulatory text. (Schneider, No. 49 at p. 8; NEMA, No. 50 at p.
4; Eaton, No. 55 at pp. 7-8). In the January 2023 NOPR, DOE noted that
the voltage limits in the definition of distribution transformer
established in EPCA do not specify whether line or phase voltage is to
be used. 88 FR 1722, 1745; 42 U.S.C. 6291(35). However, DOE also
discussed that, upon further evaluation, the distribution transformer
input voltage limitation aligns with the common maximum distribution
circuit voltage of 34.5 kV.45 46 This common distribution
voltage aligns with the distribution line voltage, implying that the
intended definition of distribution transformer in EPCA was to specify
the input and output voltages based on the line voltage. Accordingly,
DOE tentatively determined that applying the phase voltage, as DOE
cited in the April 2013 Standards Final Rule, would cover products not
traditionally understood to be distribution transformers and not
intended to be within the scope of distribution transformer as defined
by EPCA. 88 FR 1722, 1745. DOE also noted in the January 2023 NOPR that
the common distribution transformer voltages have both line and phase
voltages that are within DOE's scope, and therefore the proposed change
is not expected to impact the scope of this rulemaking aside from
select, unique transformers with uncommon voltages. Id. Accordingly,
DOE proposed to modify the definition of distribution transformer to
state explicitly that the input and output voltage limits are based on
the ``line'' voltage and not the phase voltage.
---------------------------------------------------------------------------
\45\ Pacific Northwest National Lab and U.S. Department of
Energy (2016), ``Electricity Distribution System Baseline Report.'',
p. 27. Available at www.energy.gov/sites/prod/files/2017/01/f34/Electricity%20Distribution%20System%20Baseline%20Report.pdf.
\46\ U.S. Department of Energy (2015), ``United States
Electricity Industry Primer.'' Available at www.energy.gov/sites/prod/files/2015/12/f28/united-states-electricity-industry-primer.pdf.
---------------------------------------------------------------------------
In response, Eaton commented that DOE's revised interpretation of
input and output voltages better aligns with industry. (Eaton, No. 137
at p. 13). NEMA commented that the addition of line voltage removes
ambiguity and clearly defines products that need to be in compliance.
(NEMA, No. 141 at p. 9). NEMA further recommended that the LVDT
definition should also be updated to clarify that the voltage
specifications are line voltages. (NEMA, No. 141 at p. 8) Schneider
also supported DOE's clarification that input and output voltages are
line voltages and recommended adding a similar clarification to the
LVDT definition. (Schneider, No. 101 at p. 4)
Howard commented that clarifying that voltage refers to line
voltage is an improvement to the definition of input and output
voltage. However, Howard further stated that it is more common in
industry to refer to line voltage as the ``nominal system'' voltage.
Howard recommended that rather than using ``line'' voltages, DOE should
use ''nominal system voltage,'' which is used in many industry
standards, and proposed defining ``nominal system voltage.'' Howard
additionally supported DOE's assessment that the revised definitions of
input and output voltage would only impact products not considered by
industry to be serving distribution applications. (Howard, No. 116 at
p. 8-9)
DOE reviewed relevant industry standards to assess Howard's
recommendation. Based on this review, DOE found that, while the term
``nominal system voltage'' has been adopted in several standards, its
usage is not ubiquitous. For example, IEEE standard C57.91-2020
interchangeably uses the terms ``nominal voltage,'' ``line voltage,''
and ``line-to-line voltage'' to specify transformer voltage
ratings.\47\ Other standards similarly specify voltage ratings using
the terms ``phase-to-phase,'' ``line-to-ground nominal system
voltage,'' or ``nominal line-to-line system voltage.'' Further, DOE
reviewed manufacturer catalogs for distribution transformers and
observed that it is more common to specify transformer voltage ratings
according to the ``line voltage,'' as opposed to the ``nominal system
voltage.'' The comments received from Eaton and NEMA additionally
indicate that the term ``line voltage'' is well understood in industry
and sufficiently clarifies the definitions of input and output voltage.
---------------------------------------------------------------------------
\47\ IEEE SA. (2020). IEEE C57.12.91-2020--IEEE Standard Test
Code for Dry-Type Distribution and Power Transformers. Available at
standards.ieee.org/standard/C57_12_91-2020.html (last accessed June
21, 2023).
---------------------------------------------------------------------------
Therefore, for the reasons discussed, DOE is modifying the
definition of distribution transformer in this final rule to state
explicitly that the input and output voltage limits are based on the
``line'' voltage and not the phase voltage. Similarly, in accordance
with the feedback submitted by NEMA and Schneider, DOE is similarly
amending the definition of ``low-voltage dry-type distribution
transformer'' to state a transformer that has ``an input line voltage
of 600 volts or less''.
i. kVA Range
The EPCA definition for distribution transformers does not include
any capacity range. In codifying the current distribution transformer
capacity ranges in 10 CFR 431.192, (10 kVA to 2500 kVA for liquid-
immersed units and 15 kVA to 2500 kVA for dry-type units), DOE noted
that distribution transformers outside of these ranges are not
typically used for electricity distribution. 71 FR 24972, 24975-24976.
Further, DOE noted that transformer capacity is to some extent tied to
its primary and secondary voltages, meaning that the EPCA definition
has the practical effect of limiting the maximum capacity of
transformers that meet those voltage limitations to approximately 3,750
to 5,000 kVA, or possibly slightly higher. Id. DOE established the
current kVA range for distribution transformers by aligning with NEMA
publications in place at the time that DOE adopted the range,
specifically the NEMA TP-1 standard. 78 FR 23336, 23352. DOE cited
these documents as evidence that its kVA scope is consistent with
industry understanding (i.e., NEMA TP-1 and NEMA TP-2), but noted that
it may revise its understanding in the future as the market evolves. 78
FR 2336, 23352.
In the January 2023 NOPR, DOE noted that several industry sources
suggest that the distribution transformer kVA range may exceed 2,500
kVA. 88 FR 1722, 1746. Specifically, DOE cited Natural Resources Canada
(NRCAN) regulations that include dry-type distribution transformers up
to 7,500 kVA.\48\ The European Union (EU) Ecodesign requirements also
specify maximum load losses and maximum no-load losses for three-phase
liquid-
[[Page 29877]]
immersed distribution transformers up to 3,150 kVA.\49\
---------------------------------------------------------------------------
\48\ See NRCAN dry-type transformer energy efficiency
regulations at www.nrcan.gc.ca/energyefficiency/energy-efficiency-regulations/guidecanadas-energy-efficiency-regulations/dry-typetransformers/6875.
\49\ Official Journal of the European Union, Commission
Regulation (EU) No. 548/2014, May 21, 2014, Available at eur-
lex.europa.eu/legal-content/EN/TXT/
?uri=uriserv%3AOJ.L_.2014.152.01.0001.01.ENG.
---------------------------------------------------------------------------
DOE noted that manufacturers in interviews had stated that
transformers beyond 2,500 kVA are typically step-up transformers
serving renewable applications, which would be outside the scope of
standards on account of exceeding the output voltage limit. 88 FR 1722,
1746. However, DOE cited comments by NEMA and Eaton, which suggested
that some number of general purpose distribution transformers are sold
beyond 2,500 kVA. (NEMA, No. 50 at p. 5; Eaton, No. 55 at p. 8).
Further, DOE noted that some manufacturers expressed concern in
interviews that in the presence of amended energy conservation
standards, there may be increased incentive to build distribution
transformers that are just above the existing scope (e.g., 2,501 kVA).
88 FR 1722, 1746.
In response to this feedback, DOE proposed to expand the scope of
the definition of distribution transformer to 5,000 kVA. DOE requested
comment as to whether 5,000 kVA represented the upper limit for
distribution transformers. Id. at 88 FR 1747.
DOE also estimated energy savings for transformers greater than
2,500 kVA but less than or equal to 5,000 kVA by scaling certain
representative units. In estimating energy savings, DOE assumed these
units are purchased based on lowest first cost and use similar grades
of electrical steel as in-scope units but are not required to meet any
efficiency standards. DOE requested comment on the number of shipments
and distribution of efficiency for these large three-phase distribution
transformers. Id.
NAHB submitted data showing that imports for liquid-immersed
transformers with ratings above 2500 kVA have increased significantly
in the past decade and expressed concern that the proposed standards
would negatively impact the import market for these products. (NAHB,
No. 106 at pp. 8-9) DOE notes that the data cited by NAHB is for all
transformers greater than 2,500 kVA without considering their secondary
voltage. Most transformers greater than 2,500 kVA would be substation
or large power transformers with output voltages that vastly exceed
600V. Due to the voltage limitations, virtually all transformers cited
by NAHB would not be subject to DOE efficiency regulations regardless
of the kVA range for the definition of distribution transformer.
Howard commented that transformers beyond 2,500 kVA are not within
the technical scope of what is considered a distribution transformer
and should not be a part of distribution transformer regulations.
(Howard, No. 116 at pp. 9, 19) Howard stated that they produce a very
small number of 3,000, 3,750, and 5,000 kVA transformers per year that
are primarily used for unique and specialized applications, not as a
means to circumvent DOE regulations. Id. Howard referred DOE to IEEE
C57.12.34 and C57.12.36 industry standards, which Howard stated do not
specify an impedance value for 5,000 kVA transformers with a low-
voltage rating of 600 V and below.\50\ Id. Prolec GE commented that
transformers between 2,500 kVA and 5,000 kVA may maintain certain
characteristics as distribution transformers but are mainly specified
and purchased by industrial customers and not intended for general
purpose applications. (Prolec GE, No. 120 at p. 5)
---------------------------------------------------------------------------
\50\ See Table 2 of IEEE Std C57.12.34-2022 and Table 5 of IEEE
Std C57.12.36-2017.
---------------------------------------------------------------------------
Eaton commented that between 2016 and 2022, it built zero
transformers above a kVA rating of 5,000 kVA that also had an output
voltage of 600 V or less. (Eaton, No. 137 at p. 13) Howard commented
that units above 2,500 kVA with secondary voltages of 600 V or less
represent less than one percent of Howard's annual three-phase pad
mounted transformer shipments. (Howard, No. 116 at p. 10) Howard stated
that units over 2,500 kVA have very few shipments, representing a very
small number of specialized units. (Howard, No. 116 a p. 19)
Howard stated that the average efficiency of these units is 99.4
percent and achieving lower losses than this becomes difficult due to
the very high currents that lead to significant stray and eddy losses.
(Howard, No. 116 at p. 10) Howard stated that if DOE elects to include
these high-kVA units, their efficiencies should not be on-par with
smaller units due to the unique challenges associated with high-kVA
units. (Howard, No. 116 at p. 19)
Eaton commented that because the scaling relationships do not hold
with high-kVA units, DOE should work with manufacturers to identify
more accurate max-tech efficiency levels for high-kVA transformers.
(Eaton, No. 137 at p. 28) Eaton provided data showing what their design
software calculated as max-tech for 3-phase distribution transformers
at various voltages across a range of kVA values. (Eaton, No. 137 at p.
28)
Prolec GE commented that the proposed standards for transformers
above 2,500 kVA result in a much larger increase in standards than all
other transformers because they are not currently subject to efficiency
standards and therefore the baseline transformer is less efficient than
transformers that are in-scope today. (Prolec GE, No. 120 at p. 12)
Hammond commented that the 5,000 kVA limit is preferrable for
medium-voltage dry-type distribution transformer units; however, the
high-currents of these designs may make efficiency standards infeasible
and, therefore, it may be necessary to apply an exclusion for high-
current units, similar to the NRCAN regulations. (Hammond, No. 142 at
p. 3)
In reviewing the technical challenges associated with meeting
energy conservation standards for large three-phase units, DOE agrees
that the presence of both very high kVA ratings and an output voltage
of 600V could lead to very high currents that would inherently lead to
manufacturing challenges, making it more costly to meet a given
efficiency standard. However, DOE notes that industry standards
recommend minimum low-voltage ratings that vary based on kVA.\51\ As a
result, larger kVA transformer tend to have higher secondary voltages.
While maintaining these recommended voltage ratings does not entirely
eliminate the challenges faced by high-current transformers, as further
discussed in section IV.A.2.c, it generally helps maintain a reasonable
current.
---------------------------------------------------------------------------
\51\ See Table 3 of IEEE Std C57.12.36-2017.
---------------------------------------------------------------------------
DOE notes that one of the primary reasons it cited for proposing to
include higher kVA distribution transformer within the scope of the
distribution transformer rulemaking was concern from manufacturers
that, in the presence of amended energy conservation standards, there
may be increased incentive to build distribution transformers that are
just above the existing scope (e.g., 2,501 kVA). 88 FR 1722, 1746.
NEMA commented in response to the January 2023 NOPR that some
customers have requested units just beyond the scope of regulations
(e.g. 2,501 kVA). (NEMA, No. 141 at p. 9) The Efficiency Advocates
commented that they support DOE's proposal to include capacities up to
5,000 KVA based on manufacturer comment that some products are sold
here that meet the voltage limits and to eliminate the potential
incentive to build transformers just beyond the current scope in the
[[Page 29878]]
presence of amended standards. (Efficiency Advocates, No. 121 at p.7)
Stakeholder comments indicate that losses for high-kVA transformers
increase at a faster rate than modeled by the scaling relationships
used in the January 2023 NOPR, causing the proposed standards for these
high-kVA units to be beyond what is technologically feasible. Based on
the feedback received, DOE conducted additional investigation into the
interaction between capacity, current, and efficiency standards, as
discussed in sections IV.A.2.c and IV.C.1.e. Based on the feedback
received from manufacturers and this additional technical
investigation, DOE has determined that the primary challenge associated
with meeting efficiency standards for higher kVA distribution
transformers is related to the high-current associated with those
transformers.
If built per the minimum voltage recommendations of IEEE Std
C57.12.36-2017, 5,000 kVA transformers would never have an output
voltage less than or equal to 600V, and 3,750 kVA transformers would
also typically be larger than 600V. This indicates that 3,750 kVA or
5,000 kVA transformers would likely not have output voltages that meet
the definition of distribution transformers subject to energy
conservation standards, if built per industry standards.
However, stakeholder comments also suggest that consumers have
requested transformers just beyond 2,500 kVA (i.e., 2,501 kVA), that
are not built per industry standard kVA ranges to use in general
purpose applications, which could increase in the presence of amended
efficiency standards. As such, DOE is finalizing an expansion to
include distribution transformers less than or equal to 5,000 kVA, as
proposed in the January 2023 NOPR. However, DOE requested comment on
its modeling of high-kVA units (88 FR 1722, 1760) and based on
stakeholder feedback has modified its modeling (as discussed in section
IV.C.1.e) and adopted efficiency levels for these high-kVA units to
reflect the challenges associated with high-currents in distribution
transformers.
DOE notes that this finalized definition reduces the risk of non-
standard kVA transformers being built just beyond the scope of
regulations in an effort to circumvent efficiency requirements, while
accommodating the legitimate challenges associated with high-current
transformers. DOE discusses the specific comments related to high-
current transformers in section IV.A.2.c of this document.
2. Equipment Classes
When evaluating and establishing or amending energy conservation
standards, DOE may establish separate standards for a group of covered
equipment (i.e., establish a separate equipment class) if DOE
determines that separate standards are justified based on the type of
energy used, or if DOE determines that a product's capacity or other
performance-related feature justifies a different standard. (42 U.S.C.
6316(a); 42 U.S.C. 6295(q)) In making a determination whether a
performance-related feature justifies a different standard, DOE
considers such factors as the utility of the feature to the consumer
and other factors DOE determines are appropriate. (Id.)
Eleven equipment classes are established under the existing
standards for distribution transformers, one of which (mining
transformers \52\) is not subject to energy conservation standards. 10
CFR 431.196. The remaining ten equipment classes are delineated
according to the following characteristics: (1) type of transformer
insulation: liquid-immersed or dry-type, (2) number of phases: single
or three, (3) voltage class: low or medium (for dry-type only), and (4)
basic impulse insulation level (BIL) (for MVDT only).
---------------------------------------------------------------------------
\52\ A mining distribution transformer is a medium-voltage dry-
type distribution transformer that is built only for installation in
an underground mine or surface mine, inside equipment for use in an
underground mine or surface mine, on-board equipment for use in an
underground mine or surface mine, or for equipment used for digging,
drilling, or tunneling underground or above ground, and that has a
nameplate which identified the transformer as being for this use
only. 10 CFR 431.192.
---------------------------------------------------------------------------
Table IV.3 presents the eleven equipment classes that exist in the
current energy conservation standards and provides the kVA range
associated with each.
[GRAPHIC] [TIFF OMITTED] TR22AP24.530
DOE notes that across the existing transformer equipment classes,
numerous factors can impact the cost and efficiency of a distribution
transformer. Certain factors like primary voltage, secondary voltage,
insulation material, specific impedance designs, voltage taps, etc.,
can all increase the price of a given transformer and lead to an
increase in transformer losses, which may make meeting any given
efficiency standard more difficult. Distribution transformers are
frequently customized by consumers to add features, safety margins,
etc. However, DOE has
[[Page 29879]]
determined that in general these differences are not sufficient to
warrant separate equipment classes. Having a different equipment class
for all possible kVA and voltage combinations is infeasible, would add
complexity to optimization software, and was not suggested by any
stakeholders. Within a given equipment class and efficiency standard,
there is typically sufficient ``margin'' such that all small
variabilities in design can meet efficiency standards without reaching
an ``efficiency wall'' wherein any additional efficiency gains become
substantially more expensive. However, certain design variabilities may
warrant separation into additional equipment classes such that the
product features remain on the market. In the January 2023 NOPR, DOE
requested comment and data on a variety of other potential equipment
features that may warrant a separate equipment class. 88 FR 1722, 1747.
These comments are discussed in detail below.
a. Submersible Transformers
Certain distribution transformers are installed underground and,
accordingly, may endure partial or total immersion in water. In the
January 2023 NOPR, DOE stated that the subterranean installation of
submersible distribution transformers means that there is less
circulation of ambient air for shedding heat. 88 FR 1722, 1748.
Operation while submerged in water and in contact with run-off debris
further impacts the ability of a distribution transformer to transfer
heat to the environment and limits the alternative approaches in the
external environment that can be used to increase cooling (e.g., adding
radiators).
DOE noted that distribution transformer temperature rise tends to
be governed by load losses and that it is typical for design options
that reduce load losses to increase no-load losses. 88 FR 1722, 1748.
While no-load losses make up a relatively small portion of losses at
full load, no-load losses can contribute a significant portion of total
losses at 50-percent PUL, at which manufacturers must certify
efficiency. However, due to the potentially reduced heat transfer of a
subterranean environment, combined with the possibility of operating
while submerged, customers must reduce load losses to meet temperature
rise limitations. Therefore, the design choices needed to meet a lower
temperature rise may lead manufacturers to increase no-load losses and
may make it more difficult to meet a given efficiency standard at 50-
percent PUL.
In the January 2023 NOPR, DOE tentatively determined that
distribution transformers designed to operate while submerged and in
contact with run-off debris constitutes a performance-related feature
which other types of distribution transformers do not have. 88 FR 1722,
1748. At max-tech efficiency levels, both no-load and load losses are
low enough that distribution transformers generally do not meet their
rated temperature rise. However, at intermediate efficiency levels,
trading load losses for no-load losses allows distribution transformers
to be rated for a lower temperature rise. This may make it more
difficult to meet any amended efficiency standard, as no-load losses
contribute proportionally more to efficiency at the test procedure PUL
as compared to at the rated temperature rise. Id.
In defining a submersible distribution transformer, DOE noted that
the IEEE C57.12.80-2010 includes numerous definitions for transformers
designed to operate in partial or total submersion. Id. DOE attempted
to identify the physical features that would distinguish transformers
capable of operating in a submersible operation by reviewing industry
standards IEEE C57.12.23-2018 and IEEE C57.12.24-2016. Id. DOE proposed
to define a submersible distribution transformer as ``a liquid-immersed
distribution transformer so constructed as to be successfully operable
when submerged in water including the following features: (1) is rated
for a temperature rise of 55 [deg]C; (2) has insulation rated for a
temperature rise of 65 [deg]C; (3) has sealed-tank construction; and
(4) has the tank, cover, and all external appurtenances made of
corrosion-resistant material.'' Id. DOE noted that this definition
sought to incorporate the physical features associated with submersible
transformers that are included in industry standards. DOE requested
comment on its definition of submersible distribution transformer and
information regarding the specific design characteristics that limit
efficiency. Id.
APPA supported creating a separate equipment class for vault,
submersible, or special installation transformers and supported DOE's
proposal not to establish higher efficiency standards for those units.
(APPA, No. 103 at p. 3)
Howard supported a separate equipment class for submersible
distribution transformers because of their lack of cooling, higher
ambient temperatures, and higher installation costs. (Howard, No. 116
at p. 11) Howard commented that comparing its submersible transformers
to its non-submersible transformers requires a 10- to 12-percent
increase in no-load losses and comparable reduction in load losses to
meet maximum temperature rise characteristics. (Howard, No. 116 at p.
11) Howard added that in addition to the reduced cooling, submersible
transformers also frequently have bushings, switches, tap changers, and
other accessories mounted on the cover, which increases lead lengths
and therefore increases losses. (Howard, No. 116 at p. 11)
Prolec GE and NEMA commented that submersible transformers are
limited in their ability to meet higher efficiency levels on account of
needing to meet the strict dimensional requirements associated with
fitting in existing vaults, their limited heat transformer on account
of needing to operate in dirty water, and their need to have corrosion-
resistant construction, which is thicker and reduces the transformer's
ability to remove heat. (NEMA, No. 141 at p. 10; Prolec GE, No. 120 at
p. 9) Due to these limitations, Prolec GE supported DOE establishing a
separate equipment class for submersible transformers and not
increasing efficiency standards. (Prolec GE, No. 120 at p. 9) Carte
supported establishing a separate equipment class for submersible
transformers and not establishing higher efficiency levels because of
the strict dimensional constraints associated with installations in
vault locations. (Carte, No. 140 at p. 7)
WEC commented that DOE's proposed equipment class and no-new-
standard determination for submersible distribution transformers would
not cover WEC's more cost effective approach of using pad mounted
transformers in certain vault applications. (WEC, No. 118 at p. 2) DOE
notes that in cases where utilities are using traditional pad-mounted
distribution transformers in vault applications, there are not going to
be the same thermal limitations that represent the technical features
identified by stakeholders as warranting a separate equipment class.
Regarding DOE's proposed definition of submersible distribution
transformer, Carte commented that some utilities in unique locations
use a 65 [deg]C temperature rise in their transformer vaults. (Carte,
No. 140 at p. 7) Prolec GE and NEMA commented that submersible
distribution transformer is already defined per IEEE standards
C57.12.24 and C57.12.40. (Prolec GE, No. 120 at p. 6; NEMA, No. 141 at
pp. 9-10) Prolec GE and NEMA further commented that the unique design
and characteristics of submersible transformers makes them rarely
compatible with above ground
[[Page 29880]]
installation. (Prolec GE, No. 120 at p. 6; NEMA, No. 141 at pp. 9-10)
Prolec GE and NEMA commented that IEEE C57.12.80 identifies
installation in a vault as a common characteristic for submersible,
subway, and network transformers. (Prolec GE, No. 120 at p. 6; NEMA,
No. 141 at pp. 9-10)
Howard commented that DOE should align the definition with IEEE
standards C57.12.23, C57.12.24, and C57.12.40. Howard added that if DOE
elects not to align with IEEE standards, DOE should modify feature (4)
of the definition to clarify that copper-bearing steel with minimum
specified thicknesses for tanks, covers, and auxiliary coolers is an
acceptable alternative to stainless steel as a ``corrosion-resistant
material.'' (Howard, No. 116 at p. 10) Prolec GE and NEMA recommended
submersible distribution transformer be defined as ``a liquid-immersed
distribution transformer, so constructed as to be operable when fully
submerged in water including the following feature: (1) has sealed tank
construction; (2) has the tank, cover and all external appurtenances
made of corrosion-resistance material or with appropriate corrosion-
resistance surface treatment to induce the components surface to be
corrosion resistant; and (3) is designed for installation in an
underground vault.'' (Prolec GE, No. 120 at p. 6; NEMA, No. 141 at pp.
9-10)
In reviewing the nuances NEMA, Prolec GE, and Howard described as
to the different approaches manufacturers may take to ensure their
distribution transformer is constructed to operate when submerged in
water, DOE agrees that different insulating fluids may modify the exact
temperature rise of a given submersible distribution transformer and
the primary physical features associated with submersible transformers
include having sealed tank construction and corrosion resistant
surroundings. As noted, DOE described the physical features identified
in the NOPR based on a review of these industry standards and intended
to align its definition with the physical features identified in these
standards.
Therefore, DOE is adopting a definition for submersible
distribution transformer to mean ``a liquid-immersed distribution
transformer, so constructed as to be operable when fully or partially
submerged in water including the following features: (1) has sealed-
tank construction; and (2) has the tank, cover, and all external
appurtenances made of corrosion-resistant material or with appropriate
corrosion resistant surface treatment to induce the components surface
to be corrosion resistant.''
b. Large Single-Phase Transformers
DOE received several comments from stakeholders (discussed in
sections IV.C.1.d and IV.E.2 of this document) noting that in the
immediate future, the ability to operate transformers efficiently at
higher loading may represent a distinct consumer utility. (APPA, No.
103 at p. 17; NEPPA, No. 129 at p. 2; Cliffs, No. 105 at pp. 16-17;
Carte, No. 140 at p. 6) Specifically, an increased ability to overload
small single-phase transformers, which are often placed most directly
near consumer loads, provides safety and reliability amidst uncertainty
over near-future demand patterns as electrification proceeds. DOE notes
that the ability to overload a distribution transformer is related to a
transformer's temperature rise and insulation.
The likelihood of a distribution transformer being overloaded is a
function of, among other factors, the size of the transformer and the
number of consumers being served by a given distribution transformer.
While smaller kVA transformers tend to serve a smaller number of
households, the loading on those smaller transformers could vary with
considerably more irregularity because the actions of a small number of
individuals can drastically impact loading. Larger kVA transformers
tend to serve a larger number of households, with overall loading on
the transformer distributed across a larger number of individuals.
Therefore, while loading still varies, it varies more predictably as no
single individual can impact the loading on a single transformer as
significantly. As a result, larger kVA transformers are less likely to
be subject to overloading conditions than their smaller kVA
counterparts.
Instantaneous temperature rise on a transformer tends to be
governed by load losses and it is typical for design options that
reduce load losses to increase no-load losses. While no-load losses
typically make up a relatively small portion of losses at full load,
no-load losses can contribute a significant portion of total losses at
50-percent PUL, at which manufacturers must currently demonstrate
compliance with energy conservation standards at 10 CFR 431.196(b). The
design choices needed to reduce temperature rise may lead manufacturers
to increase no-load losses, as not doing so may increase the cost of
the distribution transformer and diminish sales in a market sensitive
to selling price. Further, because operating temperature is impacted by
the ability of the transformer to dissipate heat, a transformer's
tolerance of overloading is directly linked to its ability to shed
heat. Heat transfer is directly dependent on the ratio of distribution
transformer surface area to volume. In other words, the more surface
area that a transformer has per unit of volume, the more effectively it
will be able to shed heat. As transformer capacity increases, however,
the weight and volume of the transformer tend to increase more rapidly
than the surface area, meaning that heat transfer become less
effective. As a result, smaller kVA transformers tend to be more
physically suitable for sustaining overload conditions than larger kVA
transformers, which typically need additional radiators to effectively
remove heat.
Similarly to submersible transformers, at the max-tech efficiency
levels for single phase transformers, both the no-load and load losses
are low enough that distribution transformers generally do not meet
their rated temperature rise. However, at intermediate efficiency
levels, trading load losses for no-load losses may allow smaller
distribution transformers serving fewer consumers to have increased
overload capability, particularly if paired with less-flammable
insulating liquid. This combination may make it more difficult to meet
any amended efficiency standard, as no-load losses contribute
proportionally more to efficiency at the test procedure PUL as compared
to at the rated temperature rise. Id.
One utility investigated the likelihood of distribution
transformers being overloaded based on potential electric vehicle (EV)
charging penetration rates for single-phase transformers ranging from
15 to 100 kVA. This study found that smaller transformers have a high
likelihood of being overloaded and, as the size of those transformers
increases, the percentage of overloaded transformers at a given kVA
goes to zero beyond 100 kVA.\53\ While in the longer term, the study
recommends upsizing transformers such that loading on transformers
remains low, in the immediate future, consumers will value increased
overload capacity as a consumer feature for small, single-phase
transformers.
---------------------------------------------------------------------------
\53\ Dalah, S., Aswani, D., Geraghty, M., Dunckley, J., Impact
of Increasing Replacement Transformer Size on the Probability of
Transformer Overloads with Increasing EV Adoption, 36th
International Electric Vehicle Symposium and Exhibition, June, 2023.
Available online at: https://evs36.com/wp-content/uploads/finalpapers/FinalPaper_Dahal_Sachindra.pdf.
---------------------------------------------------------------------------
Based on this data, for this final rule DOE has evaluated two
equipment classes for single-phase liquid-immersed distribution
transformers. Equipment Class 1A corresponds to single-phase
[[Page 29881]]
liquid-immersed distribution transformers greater than 100 kVA.
Equipment Class 1B corresponds to single-phase liquid-immersed
distribution transformers ranging from 10-100 kVA. Equipment Class 1A
includes units that are unlikely to be overloaded, while Equipment
Class 1B includes units that are at higher likelihood of being
overloaded and, therefore, consumers are more likely to exchange no-
load losses for load losses, thereby making it more difficult to meet
amended efficiency standards.
DOE notes that in the cited study exploring the likelihood of
overloading in the presence of high-EV penetration (corresponding to a
50% penetration rate by 2035), the overloading likelihood ranges from
100 percent for 15 kVA transformers to 2.5 percent for 100 kVA
transformers. However, when those 100 kVA transformers are upsized, the
overload likelihood in the high-EV penetration scenario falls to 0.1
percent, indicating that 100 kVA approximately corresponds to the upper
limit of single-phase transformers that are likely to experience
overloading and therefore likely to be designed to trade load losses
for no-load losses to reduce the loss-of-life impacts associated with
overloading. DOE considered other potential capacities for separating
equipment, as lower-EV penetration scenarios show that 75 kVA and 100
kVA transformers are unlikely to be overloaded. However, given the
regional variance of EV penetration, DOE has determined that even in
the most aggressive EV-penetration scenarios, the likelihood of
overloading falls to virtually zero above 100 kVA. Therefore, in light
of the above, DOE has determined that 10-100 kVA and above 100 kVA are
reasonable capacity designation for determining product classes.
As noted, higher efficiency levels can result in low no-load and
load losses; however, intermediate efficiency levels require trading
off between the two. Further, the utility associated with increased
overloading is likely limited to the near-term electrification build-
out, wherein a significant number of new loads, notably electric
vehicles, are being added to the grid. Longer-term, utilities are
expected to replace this overloading ability with larger kVA
transformers, as recommended by the aforementioned study.
While DOE did not propose separate equipment classes based upon kVA
capacity for liquid-immersed transformers in the January 2023 NOPR, DOE
requested comment on any other categories of equipment that may warrant
a separate equipment class. 88 FR 1722, 1752. DOE also evaluated a
separate equipment class in the January 2023 NOPR for submersible
distribution transformer based, in part, on the high overload
capabilities and reduced heat transformer needed for many submersible
distribution transformers which require manufacturers to increase no-
load losses in order to decrease load losses. 88 FR 1722, 1748.
Stakeholder feedback in response to the NOPR regarding the likely
increase in loading--as summarized at the beginning of this section--
and the conclusions from the additional studies described previously in
this section regarding the likelihood of overloading a transformers in
the near-term justify evaluating single-phase liquid-immersed
distribution-transformers as two equipment classes based on kVA size,
based on a similar principle that increased ability to overload a
transformer requires trading no-load losses for load losses at
intermediate efficiency levels.
c. Large Three-Phase Transformers With High-Currents
Distribution transformers with high currents often have increased
stray losses, which can impact the efficiency of distribution
transformers. Because of this limitation, NRCAN regulations exclude
transformers with a nominal low-voltage line current of 4000 A or more.
DOE has historically not evaluated high-current transformers as a
separate equipment class.
In the January 2023 NOPR, DOE noted that while stray losses may be
slightly higher for high-current transformers, manufacturers have the
option to use copper secondaries or a copper buss bar to decrease load
losses. 87 FR 1722, 1750. Further, DOE noted that technologies that
increase the efficiency of lower-current transformers tend to also
increase the efficiency of high-current transformers. Id. Therefore,
DOE did not propose a separate equipment class for high-current
transformers. However, DOE stated that it may consider a separate
equipment class for high-current transformers if sufficient data were
provided, and DOE requested manufacturers provide data on the different
cost-efficiency curve associated with high-current transformers along
with the number of shipments of these units. Id. at 87 FR 1751.
Eaton provided data showing the max-tech of their designs with both
amorphous and grain-oriented electrical steel (GOES) cores with 208Y/
120 secondaries and 480Y/277 secondaries. (Eaton, No. 137 at p. 17)
Eaton's data showed that the max-tech is similar at low kVA values,
regardless of secondary current. (Eaton, No. 137 at p. 17) Eaton
additionally provided cost efficiency curves for 500 kVA units which
showed similar incremental costs at the proposed standard levels for
designs with either a 208Y/120 or a 480Y/277 secondary. Id. However, as
the transformer capacity increases and the secondary current increases,
the maximum transformer efficiency that can be achieved begins to drop
considerably. Id.
Most distribution transformers are sold at one of a handful of
standard secondary voltages. For three-phase transformers, this is
typically either 480Y/277 or 208Y/120. Eaton stated that 97 percent of
their three-phase shipments use either a 208Y/120 or 480Y/277
secondary. (Eaton, No. 137 at p. 20)
Eaton recommended DOE set an efficiency standard with at least a
20-percent margin in base losses relative to the actual max-tech for
208Y/120 secondary transformers. Id. Eaton suggested that DOE could
propose separate standards for transformers with 480Y/277V or 208Y/120V
secondaries based on having a line voltage above or below 250 V
respectively. (Eaton, No. 137 at p. 29)
DOE notes that across all transformers, variability in voltage can
impact the price and maximum achievable efficiency of a transformer. As
shown in Eaton's max-tech plots, there is a slight difference in the
maximum efficiency that can be achieved across all kVA ranges as the
stray and eddy currents and conductor thickness will vary slightly
between designs. Similarly, the choice in primary voltage may slightly
impact the maximum achievable efficiency of a given transformer design.
However, in general, these differences are not sufficient to warrant
separate equipment classes. As discussed in Eaton's comment, for most
kVA values there is sufficient ``margin'' that both a 208Y/120 and a
480Y/277 transformer have similar cost-efficiency relationships. Having
a different equipment class for all possible kVA and voltage
combinations is infeasible and was not suggested by any stakeholders.
Eaton additionally commented that its modeling of max-tech shows
that previous DOE efficiency standards may have resulted in the
unavailability of many 2,000 kVA and 2,500 kVA distribution
transformers with 208Y/120 secondaries, which should not have been
allowed under 42 U.S.C. 6295(o)(4), as this represents a performance
characteristic. (Eaton, No. 137 at p. 18)
[[Page 29882]]
DOE notes that 42 U.S.C. 6295(o)(4) specifies that DOE may not set
any amended standard that is likely to result in the unavailability of
any performance characteristics that are substantially the same as
those generally available in the United States at the time of the
Secretary's finding. DOE notes that voltage generally increases as
transformer capacity increases. As such, the high-current units cited
by Eaton generally were not available due to the challenges of
designing a transformer with a wire of sufficient thickness to handle
the very high-currents. DOE does not expect that the adopted standards
will result in the unavailability of any high-current units that are
currently being produced in any significant volume. Further, there is
no distinct purpose where such a large kVA transformer with such a
high-current would be the only option to provide a low secondary
voltage because consumers can and do achieve identical utility more
economically and efficiently with one or multiple smaller kVA
transformer placed closer to the electricity's end-use.
Transmission losses are also related to transformer current, and as
such, if a customer needs a very large amount of transformative
capacity, it is typically more efficient and cost effective to step-
down power to 480V/277 and then use smaller transformers to further
step down the voltage to 208Y/120, closer to the actual point of use.
For these reasons, industry standards recommend high-kVA transformers
have higher-secondary voltages. As such, currents do not tend to reach
problematic values.
However, transformers within common industry values may still have
a high enough current such that the stray and eddy losses would make up
a much greater percentage of the transformer load losses and require
manufacturers to overdesign transformers to meet a given efficiency
level. Additionally, as kVA increases, this effect may become
progressively more pronounced.
Prolec GE commented that load losses tend to be ten percent higher
for high-current transformers due to increased losses in the leads and
electrical connections on the secondary side of the transformer.
(Prolec GE, No. 120 at pp. 6-7) Carte commented that using a 120V
secondary instead of a 277V secondary for a 500 kVA, single-phase
transformer would increase the cost to meet current efficiency
standards by 52 percent. (Carte, No. 140 at p. 9) Carte commented that
for 1,500 kVA three-phase transformer, using 208Y/120 secondary instead
of a 480Y/277 secondary results in a 66 percent increase in first cost.
Carte added that a 1,500 kVA three-phase unit with 208Y/120 design
could at best achieve a 5 percent reduction in losses and would
increase the cost by 95 percent relative to current efficiency
standards, unless they transitioned to an amorphous core. (Carte, No.
140 at p. 9)
Several stakeholders gave specific low-voltage line-currents at
which stray and eddy losses grow disproportionately. Howard commented
that for three-phase transformers, it currently is difficult to meet
efficiency standards for currents greater than 3000 A. Howard commented
that typical load losses grow disproportionately at high current,
wherein the load loss to no-load loss ratio is typically between 3-5
for low-current transformers but increases to 7-8 for high-current
transformers, requiring higher grades of core steel to offset the
increased load losses. Howard added that under the NOPR proposed
levels, currents greater than 2000 A would be difficult. (Howard, No.
116 at p. 12) Prolec GE commented that above 3000 A, the manufacturer
needs to overdesign the transformer or it becomes infeasible to meet
efficiency levels. (Prolec GE, No. 120 at pp. 6-7) NEMA commented that
for, liquid-filled transformers, it is difficult to meet current energy
conservation standards above 4000 A today and recommended DOE not
increase efficiency standards for any transformers with a low voltage
line current over 3000 A. (NEMA, No. 141 at p. 11)
The current limits mentioned by stakeholders typically correspond
to a specific common kVA value and common secondary voltage. For
example, a low-voltage line current of 2,000 A or greater corresponds
to 3-phase transformers with either a 208Y/120 secondary voltage and a
capacity of 750 kVA or transformers with a 480Y/277 secondary voltage
and a capacity of 2,000 kVA. A low-voltage line current of 3,000 A or
greater corresponds to transformers with a 208Y/120 secondary voltage
and capacity greater than 1000 kVA or transformers with a 480Y/277
secondary voltage and a capacity of 2,500 kVA. A low-voltage line
current of 4,000 A or greater corresponds to transformers with a 208Y/
120 secondary voltage and capacity of 1,500 kVA or transformers with a
480Y/277 secondary voltage and a capacity of 3,750 kVA.
IEEE C57.12.36-2017 recommends a minimum low-voltage of 277V
beginning at 1,500 kVA and a minimum of 1386V beginning at 5,000 kVA.
Similarly, IEEE C57.12.34-2022 recommends a maximum kVA of 1,000 kVA
for a 208Y/120 or 240V secondary. As such, the only IEEE standard
recommended products with a 208Y/120 or 480Y/277 secondary above 2,000
A include 750 kVA and 1,000 kVA transformers with 208Y/120 secondaries
and 2,000 kVA; 2,500 kVA; and 3,750 kVA with 480Y/277 secondaries. The
only recommended products above 3,000 A include a 2,500 kVA and 3,750
kVA with a 480Y/277 secondary. The only recommended products above
4,000 A include a 3,750 kVA with 480Y/277 secondary. DOE notes that
3,750 kVA transformers are not currently subject to energy conservation
standards but were proposed to be covered in the January 2023 NOPR.
Regarding transformers with low-voltage line currents exceeding
2,000 A that stakeholders identified as having a harder time meeting
standard, Eaton's data suggests that the DOE modeled max-tech closely
aligns with manufacturer data for the 2,000 kVA and 2,500 kVA
transformers with 480Y/277 secondaries.
Howard commented that 4.8 percent of their three-phase transformer
shipments exceed 2000 A. (Howard, No. 116 at p. 12) Howard did not give
specifics as to which of those also exceed 3,000 A or 4,000 A; however,
based on industry standards, DOE expects most of those units to be
2,000 kVA and 2,500 kVA transformers with 480Y/277 secondaries.
Eaton provided data showing that as transformer capacity increases,
the percentage of units with the higher secondary, and therefore lower
current, increases such that at 1500 kVA, only 7.9 percent of units
have 208Y/120 secondaries, and at 2,000 kVA and above, 0 percent of
shipments have 208Y/120 secondaries. (Eaton, No. 137 at p. 20)
The data supplied by Eaton indicates that, for lower kVA
capacities, transformer max-tech efficiency increases with kVA as
predicted in DOE's modeling. However, above a certain point, the
transformer begins to reach the limits of its design capabilities and
max-tech efficiency begins to decline, rather than increase. Eaton's
data suggest that this design limit can vary by steel variety, but for
grain oriented electrical steel begins at 500 kVA for a 208Y/120
secondary voltage, corresponding to a line current of 1,389 A. (Eaton,
No. 137 at p. 18)
Further, the normal impedance range for transformers as specified
in IEEE Standard C57.12.34 changes from 1.2%-6.0% below 500 kVA to
1.5%-7.0% at 500 kVA.\54\ Although impedance does
[[Page 29883]]
not necessarily correlate to transformer efficiency, as discussed in
section IV.C.1.d, designing to a higher impedance range leaves
transformer with less design flexibility to meet amended efficiency
standards.
---------------------------------------------------------------------------
\54\ IEEE SA. (2022). IEEE C57.12.34-2023--IEEE Standard
Requirements for Pad Mounted, Compartmental-Type, Self-Cooled,
Three-Phase Distribution Transformers, 10 MVA and Smaller; High-
Voltage, 34.5 kV Nominal System Voltage and Below; Low-Voltage, 15
kV Nominal System Voltage and Below. Available at https://standards.ieee.org/ieee/C57.12.34/6863/ (last accessed Nov. 8,
2021).
---------------------------------------------------------------------------
Based on the increase in stray and eddy losses associated with
high-current and the change in impedance range, DOE has concluded that
transformers greater than 500 kVA warrant a separate equipment class.
Specifically, DOE has evaluated two equipment classes for three-phase
liquid-immersed distribution transformers based upon capacity.
Equipment Class 2A corresponds to three-phase liquid-immersed
distribution transformers ranging from 15 to less than 500 kVA.
Equipment Class 2B corresponds to three-phase liquid-immersed
distribution transformers greater than or equal to 500 kVA).
Regarding further separation of large three-phase kVA transformers
based on current, DOE acknowledges that high-current transformers may
experience greater challenges in meeting amended efficiency standards
and higher-current transformers tend to correspond to larger kVA sizes.
However, DOE analyzed the incremental costs associated with three-phase
1,500 kVA units at 208Y/120 secondaries as compared to 480Y/277
secondaries. These results are discussed in Chapter 5 of the TSD. DOE
has determined that both units are capable of meeting amended
efficiency standards and therefore concluded that a transformer with a
higher-current does not justify having a lower efficiency standard than
transformers with lower-currents. Therefore, DOE has not established a
separate equipment class for high-current transformers.
d. Multi-Voltage Capable Distribution Transformers
DOE's test procedure section 5.0 of appendix A requires determining
the efficiency of multi-voltage-capable distribution transformers in
the configuration in which the highest losses occur. In the August 2021
Preliminary Analysis TSD, DOE acknowledged that certain multi-voltage
distribution transformers, particularly non-integer ratio distribution
transformers, could have a harder time meeting an amended efficiency
standard as it results in an unused portion of a winding when testing
in the highest losses configuration and therefore reduces the measured
efficiency. (August 2021 Preliminary Analysis TSD at pp. 2-21) In
response to the August 2021 Preliminary Analysis TSD, DOE received
comment reiterating that these transformers may experience additional
losses which could make it more difficult to comply with standards,
particularly when tested in the lower voltage configuration.
(Schneider, No. 49 at p. 9; ERMCO, No. 45 at p. 1; NEMA, No. 50 at p.
6; Eaton, No. 55 at p. 12)
In the January 2023 NOPR, DOE discussed how multi-voltage
distribution transformers, and specifically those with non-integer
ratings, offer the performance feature of being able to be installed in
multiple locations within the grid (such as in emergency applications)
and easily upgrade grid voltages without requiring a replacement
transformer. 88 FR 1722, 1750. DOE also acknowledged that these
distribution transformers often have additional, unused winding turns
when operated at their lower voltage, increasing the transformer
losses. Id.
However, DOE noted that the efficiency of these transformers will
increase once the distribution grid is increased to the higher voltage
rating and the entire winding is used. Further, stakeholder comments
suggested that the difference in losses associated with multi-voltage
distribution transformers is relatively small. DOE also noted that the
same technologies that increase the efficiency of single-voltage
distribution transformers can be used to increase the efficiency of
multi-voltage distribution transformers, meaning that the efficiency of
either product could be increased via the same methods to meet amended
standards. Id. Therefore, DOE did not propose a separate equipment
class for multi-voltage-capable distribution transformers with a
voltage ratio other than 2:1 but requested comment and data on the
number of shipments for and degree of additional losses experienced by
these products.
Howard commented that dual voltage transformers can increase load
losses by 5-24 percent, requiring transformers to be overdesigned and
possibly limiting manufacturers' ability to offer certain designs.
Howard additionally commented that dual voltage ratios other than 2:1
represent less than 10 percent of shipments for all equipment classes.
(Howard, No. 116 at pp. 11-12)
NEMA commented that it is difficult to say exactly how load loss
changes with multi-voltage transformers and estimated that fewer than 2
percent of shipments are multi-voltage transformers with ratios other
than 2:1. (NEMA, No. 141 at p. 10)
Eaton commented that load loss data for transformers with a voltage
ratio other than 2:1 may not show a meaningful trend because load
losses are adjusted based on the no-load losses to meet standards.
Instead, Eaton provided cost versus efficiency data for 500 kVA
transformers which indicated that transformers with a voltage rating
other than 2:1 are capable of achieving effectively the same
efficiencies as transformers with a single voltage rating. The data
provided also indicated that the proposed efficiency levels could be
met at a similar incremental cost for either a multi-voltage or single-
voltage transformer. However, Eaton went on to state that this may vary
across voltage and kVA ratings and that there is insufficient data to
draw broad conclusions. (Eaton, No. 137 at pp. 14-15) Eaton
additionally commented that they construct a considerable number of
dual-voltage units, and provided data stating that 13.9 percent of
their single-phase units and 4 percent of their three-phase units have
non-2:1 voltage ratios. (Eaton, No. 137 at p. 15)
Carte commented that the cost to meet proposed efficiency levels
with a GOES transformer increases substantially for dual- and multi-
voltage transformers. (Carte, No. 140 at p. 9)
As described in section IV.A.2.d of this document, DOE may
establish a separate equipment class for a product if DOE determines
that separate standards are justified based on the type of energy used,
or if DOE determines that a product's capacity or other performance-
related feature justifies a different standard. DOE acknowledges that
multi-voltage capable distribution transformers may provide a unique
utility in allowing the grid to be upgraded to higher voltages without
requiring that a transformer be replaced. As grid modernization
continues to occur and as consumer loading increases, this utility may
provide a unique benefit to utilities by enabling them to utilize
transformers to the full extent of their lifetime and avoid early
replacements.
However, DOE has not determined that this feature results in multi-
voltage capable transformers being significantly disadvantage in
meeting amended standards. DOE evaluated available loss data obtained
from publicly available utility bid data for liquid-immersed
distribution transformers and found distribution transformers with
multi-voltage ratings, both in integer and non-integer ratios,
occupying the same design space as general use transformers across all
kVA sizes. (See chapter 5 of
[[Page 29884]]
the TSD for additional detail). As pointed out by Howard, multi-voltage
capable transformers may need to be overdesigned to meet standards at
both the higher and lower voltage rating. While this might lead to a
higher base cost for these transformers, available data does not
indicate that the incremental cost to meet amended efficiency standards
for these units would be higher. This is illustrated by the data
provided by Eaton, which shows that multi-voltage capable distribution
transformers are often more expensive at baseline but follow similar
cost-efficiency curves. Eaton's data also indicated that multi-voltage
capable distribution transformers, including those with non-integer
ratios, can be designed to meet the same efficiencies as distribution
transformers with single-voltage ratings up until the edge of max-tech.
Therefore, for the reasons discussed, DOE is not creating a
separate equipment class in this final rule for multi-voltage capable
distribution transformers with non-integer ratios.
e. Data Center Distribution Transformers
As noted in the January 2023 NOPR, DOE considered a separate
equipment class for data center distribution transformers in the April
2013 Standard Final Rule, defined as the following:
``i. Data center transformer means a three-phase low-voltage dry-
type distribution transformer that--
(i) is designed for use in a data center distribution system and
has a nameplate identifying the transformer as being for this use only;
(ii) has a maximum peak energizing current (or inrush current) less
than or equal to four times its rated full load current multiplied by
the square root of 2, as measured under the following conditions--
1. during energizing of the transformer without external devices
attached to the transformer that can reduce inrush current;
2. the transformer shall be energized at zero +/-3 degrees voltage
crossing of a phase. Five consecutive energizing tests shall be
performed with peak inrush current magnitudes of all phases recorded in
every test. The maximum peak inrush current recorded in any test shall
be used;
3. the previously energized and then de-energized transformer shall
be energized from a source having available short circuit current not
less than 20 times the rated full load current of the winding connected
to the source; and
4. the source voltage shall not be less than 5 percent of the rated
voltage of the winding energized; and
(iii) is manufactured with at least two of the following other
attributes:
1. Listed as a Nationally Recognized Testing Laboratory (NRTL),
under the Occupational Safety and Health Administration, U.S.
Department of Labor, for a K-factor rating greater than K-4, as defined
in Underwriters Laboratories (UL) Standard 1561: 2011 Fourth Edition,
Dry-Type General Purpose and Power Transformers;
2. temperature rise less than 130 [deg]C with class 220 \(25)\
insulation or temperature rise less than 110 [deg]C with class 200
\(26)\ insulation;
3. a secondary winding arrangement that is not delta or wye (star);
4. copper primary and secondary windings;
5. an electrostatic shield; or
6. multiple outputs at the same voltage a minimum of 15[deg] apart,
which when summed together equal the transformer's input kVA
capacity.'' \55\
---------------------------------------------------------------------------
\55\ 78 FR 23336, 23358.
---------------------------------------------------------------------------
In the April 2013 Standards Final Rule, DOE did not adopt this
definition of ``data center distribution transformers'' or establish a
separate class for such equipment for the following reasons: (1) the
considered definition listed several factors unrelated to efficiency;
(2) the potential risk of circumvention of standards and that a
transformer may be built to satisfy the data center definition without
significant added expense; (3) operators of data centers are generally
interested in equipment with high efficiencies because they often face
large electricity costs, and therefore may be purchasing at or above
the standard established and unaffected by the rule; and (4) data
center operator can take steps to limit inrush current external to the
data center transformer. 78 FR 23336, 23358.
In the August 2021 Preliminary Analysis TSD, DOE stated that data
center distribution transformers could represent a potential equipment
class-setting factor and requested additional data about the data
center distribution transformer market, performance characteristics,
and any physical features that could distinguish data center
distribution transformers from general purpose distribution
transformers. (August 2021 Preliminary Analysis TSD at pp. 2-22)
However, DOE did not receive any comments as to physical features that
could distinguish a data center distribution transformer from a general
purpose distribution transformer.
In the January 2023 NOPR, DOE did not propose a definition for data
center distribution transformers and did not evaluate them as a
separate equipment class. However, DOE noted that it may consider a
separate equipment class if provided sufficient data to demonstrate
that data center transformers warrant a different efficiency level and
can appropriately be defined. 88 FR 1722, 1751. Accordingly, DOE
requested comment on its proposal not to establish a separate equipment
class for data center distribution transformers and on any identifying
features related to efficiency which would prevent a data center
transformer from being used in general purpose applications. Id.
ABB SP commented that it supports a separate equipment class for
data center transformers with standards maintained at the current
levels. (ABB SP, No. 110 at pp. 1-2)
DOE noted that distribution transformers used in data centers may
sometimes, but not necessarily, be subject to different operating
conditions and requirements which carry greater concern surrounding
inrush current. 88 FR 1722, 1751. DOE requested comment on the
interaction of inrush current and data center distribution transformer
design. Id.
Regarding the specific challenges related to inrush current for
data center distribution transformers, Schneider and NEMA commented
that because of the frequent energizing of data center transformers,
designers typically seek to limit inrush to prevent nuisance trips of
the system. However, both Schneider and NEMA further stated that the
concerns for data center transformers inrush current are similar to the
concerns for all LVDTs, and while inrush is often related to
installation and restoration after power loss, increased adoption of
alternate power systems will mean more general purpose LVDTs will have
concerns when power is transferred from one source to another.
(Schneider, No. 92 at p. 6; NEMA, No. 141 at p. 12)
Regarding inrush current more broadly, Schneider and NEMA commented
that the maximum inrush must be less than the over current trip value.
(Schneider, No. 101 at pp. 6-8; NEMA, No. 141 at pp. 12-13) Schneider
and NEMA further stated that inrush current can be limited using lower
quality steel, modifying coil windings, and modifying core
configurations. Id. Schneider and NEMA commented that nuisance tripping
can be addressed by adding circuit resistance during energization of
transformers, using electronic circuit breakers with adjustable trip
settings, designing
[[Page 29885]]
electrical system with the maximum allowed overcurrent protective
device; however, all these approaches would add cost. Id.
Schneider commented that while DOE assumes equipment will be
redesigned or modified to handle inrush, the market has not yet started
this analysis. (Schneider, No. 101 at pp. 12-13) Schneider stated that
the 2016 standards increased the size of the primary over current
protection device near the limits set by the National Electric Code.
Schneider commented that customers today can use electronic trip
breakers or secondary breakers to address inrush concerns, but those
solutions may not be suitable for the amended efficiency levels. Id.
ABB SP commented that data center transformers must be designed to
account for inrush both during startup and during operation when part
of the electrical system fails, and power is diverted to a redundant
component. (ABB SP, No. 110 at p. 2) ABB SP stated that, while upstream
infrastructure could be upsized to accommodate inrush current, this
would decrease overall data center efficiency and consume more energy.
Id.
APPA commented that higher inrush currents may require a change of
protective equipment, such as relays, at a higher cost. (APPA, No. 103
at p. 13) APPA further stated that there is insufficient data on how to
size protective devices for higher inrush, which will lead to
transformer failure or excessive device tripping. Id. APPA stated that,
in either scenario, excess fuse tripping will lead to millions of
dollars of additional costs. Id. As such, APPA commented that DOE
should publish protection standards and short circuit information prior
to any changes and give a 4-year lead tie for industry to gain
experience with amorphous transformers. Id.
Eaton commented that general use LVDT transformers can be designed
to generate inrush currents up to 25x rated current, but data center
transformers cannot exceed 8x rated current to avoid potential power
outages. (Eaton, No. 137 at p. 34) Eaton further commented that
traditional inrush current limiting schemes, such as impedance
insertion, are not viable for data center transformers because they
starve the critical load of rated operating voltage. Id. Eaton stated
that mitigating inrush current by controlling transformer energization
is also not feasible for data center transformers because the required
equipment would delay energization. Id.
Prolec GE commented that the inrush current limit is 25x rated
current for both data center transformers and general-use transformers
as defined in IEEE standard C37.48.1. (Prolec GE, No. 120 at p. 7)
Prolec GE commented that peak inrush current is determined by the air
core inductance \56\ and not the core steel. Id. Prolec GE also stated
that technologies to mitigate inrush current have high complexity, low
reliability, and high costs. Id. Prolec GE also stated that the
relationship between operational flux density and remanence \57\
matters more with regard to inrush current than the absolute magnitude
of remanence. Id.
---------------------------------------------------------------------------
\56\ The air core inductance of transformer represents the
properties of the winding if there were no core to induce (i.e.,
using an ``air core''). Peak inrush can be approximated based on the
air core inductance because when a transformer is pushed into
saturation conditions, which is when maximum inrush would occur, the
instantaneous induction of the core is very low, allowing it to be
modelled as an air core.
\57\ Operational flux density represents the max flux density at
which a transformer is designed to operate, whereas remanence
represents the magnitude of flux density that remains in a core
after being de-energized. Both the remanence and the operational
flux density must be considered when designing a transformer such
that the core will not be pushed above its saturation flux density
during normal operation, which can lead to very high inrush current
and potentially damage the transformer or downstream equipment.
---------------------------------------------------------------------------
Stakeholder comments suggest that inrush current concerns may be of
particular importance for data center distribution transformers, due to
the sensitive nature of the equipment placed downstream of the
transformer. Stakeholder comment also suggest that increased efficiency
standards can increase the likelihood of inrush conditions exceeding
the limitations of standard protective equipment, depending on how the
flux density and construction of the core are modified to increase
transformer efficiency.
However, increased inrush current is not guaranteed to occur
because of increasing transformer efficiency and is partially within
the control of the transformer designer. For example, designing a
transformer with a lower flux density decreases the likelihood and
magnitude of inrush current occurrences. Stakeholder feedback indicates
that technologies exist to limit and protect against inrush current in
situations when the transformer design cannot be modified to do so.
Therefore, DOE does not consider inrush current to be an inhibiting
factor which would prevent transformer manufacturers from meeting
amended efficiency standards.
In the January 2023 NOPR, DOE also requested comment on the
specific challenges that might arise with designing data center
distribution transformers with cores made of amorphous cores. 88 FR
1722, 1751.
Metglas commented that it is not aware of any technical issues to
prevent the use of amorphous transformer cores in data center
applications. (Metglas, No. 125 at p. 5) Metglas commented that inrush
current varies based on impedance for amorphous transformers and is not
20 percent different than for a GOES unit at the same impedance.
(Metglas, No. 125 at p. 5)
Howard commented that it is unaware of any challenges with data
center transformers and is not aware of amorphous core transformers
being built for the data center market. (Howard, No. 116 at p. 13)
Schneider, Eaton, and NEMA stated that the inherent air gaps, high
saturation flux density, and lower remnant flux density of stacked core
construction cores helps limit inrush currents, but would no longer be
viable under the proposed standards since amorphous can only be used in
wound cores. (Schneider, No. 92 at p. 6; NEMA, No. 141 at p. 11; Eaton,
No. 137 at p. 37) Eaton commented that using amorphous in data center
transformers in PDUs will require significant research and development
because each of these units has specific requirements and cannot be
standardized. (Eaton, No. 137 at p. 3)
Eaton commented that, due to the increased remnant flux and reduced
saturation flux density, a data center transformer designed with an
amorphous core would need to operate at about 9 to 12.6 kG to keep
inrush current within the 4-8X limit. (Eaton, No. 137 at p. 35) Eaton
stated that inrush current may be reduced for wound core amorphous
transformers by increasing the winding turns to increase air core
inductance, but this also increases load losses, impedance, winding
temperature rise, and cost. Id. ABB SP further commented that the lower
flux density of amorphous cores would require manufacturers of data
center transformers to choose between higher inrush currents during
emergency power transfers, longer transfer times, or significantly
larger core and coil size. (ABB SP, No. 110 at p. 2)
DOE received several comments stating that higher efficiency units,
and specifically amorphous core transformers, are less efficient at
higher loading than conventional GOES transformers. For dry-type units,
Eaton commented that PDU transformers designed to meet DOE standards at
35 percent loading are less efficient during typical operation at 60-
80-percent load and this problem will be exacerbated by amorphous.
(Eaton, No. 137 at p. 37) NEMA and Schneider commented that
[[Page 29886]]
amorphous cores have not been used in data center applications and
would not maximize savings because average loading is typically 65-80
percent. (Schneider, No. 92 at p. 6; NEMA, No. 141 at p. 11)
Powersmiths commented that the proposed efficiency standards at 35
percent loading will significantly increase losses in high load
applications, such as data centers. (Powersmiths, No. 112 at p. 5)
Accordingly, Powersmiths recommended that DOE consider a provision to
accommodate high transformer load applications, such as exemptions for
specific use cases or different requirements at a higher load point.
Id.
Regarding stakeholder comment that data center distribution
transformers transformer loading may be higher than general purpose
transformers, DOE agrees that operating conditions with higher loading
applications benefit less from reduced no-load losses. However, DOE
disagrees that amorphous cores inherently are less efficient at higher
loading. As discussed in section IV.C.1, amorphous transformers are not
inherently designed with higher load losses. The reduced no-load losses
for amorphous transformers provide additional design flexibility in
meeting efficiency standards, often resulting in higher load losses to
reduce costs in a minimally compliant amorphous transformer. However,
amorphous transformers can be designed to target lower load losses,
just as GOES transformers can. Further, DOE's modeling includes a
variety of designs at higher efficiency levels, some with higher load
losses and some with lower load losses. Hence, manufacturers have the
capability to redesign transformers to meet higher efficiency standards
either by reducing the no-load losses, reducing the load losses, or
reducing some combination of the two.
DOE received additional comments that amorphous-core transformers
in data center applications would be larger, which could create
additional challenges.
For liquid-immersed units, Eaton stated that most of its data
center transformers are in the size range of 2,500 to 3,500 kVA, which
is outside the current range of transformer sizes that Eaton designs
with amorphous cores. (Eaton, No. 137 at p. 21) Eaton also commented
that the larger size of wound core amorphous transformers will increase
the size of PDUs and go against Data Centers Industry efficiency goals
for high power density per unit area. (Eaton, No. 137 at pp. 37-38)
Eaton further stated that wound core designs may have difficulty
meeting specific PDU requirements due to reduced design flexibility and
greater likelihood of DC and/or subharmonic voltages issues resulting
from the lack of air gaps. (Eaton, No. 137 at p. 38)
ABB SP commented that the increased volume of data center
transformers designed with amorphous cores would increase load losses,
strain the elevated floor systems common for PDU's, and remove the
ability to replace transformers at the end of life due to other
necessary changes to accommodate the increased volume. (ABB SP, No. 110
at p. 2)
As indicated by stakeholders, amorphous metal is not commonly
utilized in the U.S. data center distribution transformer market today,
resulting in limited data from manufacturers available to assess the
performance of amorphous units in data center applications. Stakeholder
comments identified challenges with using amorphous core transformers
related to transformer inrush and transformer size. Stakeholder comment
suggests that those challenges could be overcome, such as reducing an
amorphous cores flux density or modifying protective equipment.
However, these changes may have additional costs. Further, many of
those challenges identified for data center transformers were noted as
existing for all LVDTs, not something necessarily unique to data center
transformers.
In DOE's review of the international market DOE observed several
manufacturers marketing dry-type transformers with an amorphous metal
core.58 59 60 61 DOE also observed marketing of amorphous
core transformers being used in data centers.62 63 The
existence of amorphous metal cores in dry-type distribution
transformers, and particularly in LVDT distribution transformers,
demonstrates the technological feasibility of converting to amorphous.
While stakeholders indicated that data center distribution transformer
may be subject to additional design constraints, commenters did not
provide data to demonstrate how these design constraints may be
impacted when using amorphous metal or specifics as to what these
additional costs would be and when they come into effect (e.g. only
beyond certain kVA sizes, only in certain applications, etc.). As such,
DOE has concluded that there is insufficient data to warrant a separate
equipment class for data center transformers.
---------------------------------------------------------------------------
\58\ Toyo Electric, Dry-Type Amorphous Core Transformer.
Available at: www.toyo-elec.co.jp/products/download/catalog/transform/Amorphous_EN.pdf (last accessed Nov. 7, 2023).
\59\ Jiangsu Ryan Electric Company, SCBH15, SGBH15, SCBH16,
SGBH16 amorphous alloy dry-type transformer. Available at
en.redq.cc/SCBH15-SGBH15-SCBH16-SGBH16-amorphous-alloy-dry-type-
transformer-pd49182496.html (last accessed Nov. 7, 2023).
\60\ Yuebian Electric, Amorphous Alloy Dry Type Transformer.
Available at www.zjyb-electric.com/products/amorphous-alloy-dry-type-transformer.html (last accessed Nov. 7, 2023).
\61\ China Electric Equipment Group, Amorphous Alloy Dry Type
Transformer Three Phase Power Transformer Factory. Available at
ceegtransformer.com/products/amorphous-alloy-dry-type-transformer-three-phase-power-transformer-factory (last accessed Nov. 7, 2023).
\62\ CEEG, 42 Units of CEEG Amorphous Alloy Transformers For
Data Center were Successfully Energized. Available at
www.cnceeg.com/news/42-units-of-ceeg-amorphous-alloy-transformers-48777661.html (last accessed Nov. 7, 2023).
\63\ Qingdao Yunlu Advanced Materials Technology Co. Ltd.
Introduction to Amorphous Alloy Core. Available at www.yunluamt.com/product-44-1.html (last accessed Nov. 7, 2023).
---------------------------------------------------------------------------
Stakeholders also commented as to what physical features of data
center transformers could be identified to define data center
transformers as an equipment class separate from other general purpose
distribution transformers.
ABB SP commented that data center transformers are primarily
distinguished from general purpose LVDT transformers by their
application, with most data center transformers used in PDU's. Id. ABB
SP stated that transformers used in PDUs must be designed to
accommodate specific system requirements, including power quality
requirements, exposure to harmonic sources, continuous loading at 50-90
percent, and the ability to supply a diverse variety of power sources
without going into saturation or changing tap connections. Id. ABB SP
also commented that since 2013, data center transformers have become
larger, begun using elevated secondary voltage ratings, are designed
with greater protections for arc flash and fault current, and are
designed at higher ambient temperature. Id.
Eaton recommended that DOE specifically exempt low-voltage
transformers used in PDUs for data centers. (Eaton, No. 137 at p. 2)
Eaton commented that data center transformers are not sold as
standalone equipment but rather as part of power distribution units
(PDUs). (Eaton, No. 137 at p. 34) Eaton further commented that data
center transformers have specific design requirements which distinguish
them from general-purpose units, including (1) an inrush current rating
of 8x or lower, (2) a higher k-factor to accommodate non-linear loads,
(3) a requirement for two electrostatic
[[Page 29887]]
shields connected to the ground,\64\ (4) increased insulation inside
the winding and increased clearances from the winding to ground to
improve reliability, (5) and an occasional requirement for a lower
temperature rise, which is becoming increasingly common in data center
design. (Eaton, No. 137 at pp. 34-36) Eaton also commented that wide
range of impedance requirements can make it difficult to design PDU
transformers which both comply with DOE standards and meet k-factor
specifications. (Eaton, No. 137 at p. 36) Eaton additionally commented
that data center transformers must be operated using low flux and
current densities to meet standards, which is an inefficient use of
resources. (Eaton, No. 137 at p. 36)
---------------------------------------------------------------------------
\64\ Eaton commented that this is a unique requirement for all
PDU transformers (Eaton No. 137 at p. 36)
---------------------------------------------------------------------------
Schneider commented that a separate equipment class is not required
for data center transformers as it opens the door to many other
industry segments requesting exclusions. (Schneider, No. 92 at pp. 4-5)
Schneider commented that there are attributes for data center
transformers that may make it more difficult to comply with energy
conservation standards; however, these difficulties may be reduced with
higher efficiency levels. Id. Schneider gave the example of K-ratings
not being necessary for higher efficiency transformers because the
thermal characteristics are no longer the limiting factor of kVA. Id.
Schneider further commented that many of the concerns seen by the data
center market would exist for all applications. Id. Schneider commented
that the only way to prevent data center transformers from being used
in general purpose applications would be to limit the secondary voltage
to certain values. Id. Schneider also stated that requiring a secondary
winding arrangement that is not delta or wye, as proposed in the April
2013 Standards Final Rule, relates to efficiency in that the efficiency
of a transformer with a zig-zag secondary is less impacted under
harmonic loading. Id.
Howard commented that no guidelines are needed to prevent data
center transformers from being used in general purpose applications.
(Howard, No. 116 at p. 13) Metglas commented that there does not seem
to be a technical distinction between a data center transformer and a
standard transformer. (Metglas, No. 125 at p. 5)
DOE recognizes that distribution transformers used in data center
applications may be subject to unique requirements separate from those
used in general-purpose applications, such as specific size constraints
or a need for a higher k-factor. However, when establishing separate
equipment classes for product groups, DOE is required to focus on
capacity and performance related features that impact consumer utility.
As indicated by stakeholders, the primary distinguisher between data
center distribution transformers and general-purpose distribution
transformers is their installation location, not the capacity or
features of the transformer itself.
Further, in its review of manufacturer literature, DOE observed
multiple manufacturers advertising general use transformers
specifically designed with higher k-factor ratings, low inrush current,
and/or electrostatic shields, all of which are design features
suggested by commenters as being characteristic of data center
transformers. As stated by Schneider, a number of applications, such as
LVDT transformers used in hospital units, may require similar design
requirements to those specified for data center transformers.
While some commenters provided specific features attributable to
data center transformers, DOE notes that the majority of these features
are not unique to data center distribution transformers. For example,
several stakeholders indicated that data center distribution
transformers must be designed with a higher k-factor to accommodate
harmonic loading. In support of this claim, Eaton provided data
comparing size and efficiency of DOE's modeling to k-factor rated
transformers. However, Eaton's data did not demonstrate how an
amorphous data center transformer would perform in this comparison. As
stated by Schneider, the increased efficiency and reduced losses of an
amorphous transformer would reduce the excess heat dissipation in a
transformer, potentially reducing the need for higher k-factors.
In this final rule, DOE is not establishing a separate equipment
class for data center distribution transformers. Based on the feedback
received, DOE maintains that there are not sufficient physical features
to differentiate data center distribution transformers from general-
purpose distribution transformers. DOE does not have sufficient data to
indicate that the characteristics that often distinguish a distribution
transformer used in data center applications from one used in general
purpose applications, such as a higher k-factor, would inhibit these
units from being designed to meet an amended efficiency standard.
Therefore, for the reasons discussed, DOE is not establishing a
separate equipment class for data center transformers in this final
rule.
While stakeholders did identify legitimate challenges associated
with data center transformers, most stakeholders noted that they could
be overcome. However, there is uncertainty as to the downstream impacts
on protective equipment and transformer sizes, along with uncertainty
of the costs associated with overcoming those challenges. For example,
in circumstances when inrush current may become a concern for data
center applications, additional measures may be taken to mitigate
inrush conditions, both regarding the design of the transformer and the
external technologies that could be applied. However, the degree of
difficulty associated with each of these challenges is largely
dependent on the compliance period with which stakeholders must meet
amended efficiency standards and the degree of efficiency improvement
of any proposed standards. DOE notes that the compliance period in this
final rule is longer than the proposed in the NOPR and efficiency
levels for LVDT units is lower than was proposed in the NOPR,
indicating that manufacturers will have both more time and more design
flexibility to overcome the challenges identified in response to the
NOPR. DOE further notes that its adopted energy efficiency standards
are achievable using many designs with continued usage of stacked core
GOES designs, wherein manufacturers have considerable experience in
designing data center transformers.
f. BIL Rating
Distribution transformers are built to carry different basic
impulse insulation level (BIL) ratings. BIL ratings offer increased
resistance to large voltage transients, for example, from lightning
strikes. Due to the additional winding clearances required to achieve a
higher BIL rating, high BIL distribution transformers tend to be less
efficient, leading to higher costs and potentially more difficulty in
achieving higher efficiencies. DOE currently separates medium-voltage
dry-type distribution transformers into equipment classes based on BIL
ratings, with classes for transforms with BIL ratings ranging from 20-
45 kV, 46-95 kV, and above 96 kV. 10 CFR 431.196(c).
In the January 2023 NOPR, DOE discussed stakeholder comments which
indicated that transformers with high BIL designs (>=150 BIL or >=200
BIL) may experience higher losses that could inhibit them from meeting
amended efficiency standards. 88 FR 1722, 1752.
[[Page 29888]]
However, because no stakeholders provided data to indicate the degree
to which transformers with high BIL ratings may be disadvantaged and
because separating liquid-immersed transformers by BIL rating would add
additional complications for potentially minor differences in losses,
DOE did not propose separate equipment class based on BIL rating for
liquid-immersed units.
In response to the January 2023 NOPR, DOE received several
additional comments pertaining to BIL ratings for liquid-immersed
distribution transformers.
Eaton commented that smaller kVA units with higher-voltage primary
ratings, and corresponding higher BIL ratings, are more expensive to
build; however, Eaton went on to state that these units are generally
outside of the scope of what is commonly manufactured by Eaton. (Eaton,
No. 137 at p. 21) Eaton added that the max-tech efficiency of a 500 kVA
unit was similar for either a lower or higher BIL rating. (Eaton, No.
137 at p. 21)
Prolec GE commented that higher BIL designs have increased core and
coil dimensions to account for the additional insulation needed,
increasing the transformer losses. (Prolec GE, No. 120 at p. 8) Howard
commented that each BIL increase results in a 0.02-0.07 percentage
point drop in efficiency. (Howard, No. 116 at p. 13)
Carte commented that the increase in cost to meet the same
efficiency for 200 kV BIL designs is the following: (1) a 20 percent
increase relative to DOE's modeled 500 kVA, single-phase, 150 kV BIL
design; (2) a 5 percent increase relative to DOE's modeled 150 kVA,
three-phase, 95 kV BIL design; and (3) 16 percent increase relative to
DOE's modeled 1,500 kVA, three-phase, 125 kV BIL design. (Carte, No.
140 at pp. 8-9)
To assess whether liquid-immersed units with high BIL ratings
warranted being regulated under a separate equipment class, DOE
evaluated publicly available utility bid data to investigate the
performance of otherwise equivalent transformers with different BIL
ratings. Based on this review, DOE observed designs with high BIL
ratings (>=150 BIL) meeting higher efficiencies at a variety of kVA
sizes. As stated by several stakeholders, units with higher BIL ratings
may have a higher cost associated with them due to the added insulation
and increased overall size of the unit. While the baseline cost for a
high BIL unit may be greater than that for a lower BIL rating, DOE data
indicates that the incremental cost to meet the amended efficiency
standards would be similar for a transformer with a high BIL rating as
opposed to one with a lower BIL rating. As such, DOE does not expect
the consumers to lose access to the utility associated with high BIL
designs absent designation in a new separate class.
Further, DOE notes that the cost increases and efficiency decreases
referenced by stakeholders most likely assume that higher efficiencies
are being achieved using a GOES core. DOE notes that its analysis shows
that max-tech efficiency designs are able to reduce losses by
considerably more than both the proposed standards for liquid-immersed
distribution transformers and the adopted standards. While it may be
considerably more expensive to have higher BIL designs with a GOES core
at high-efficiency levels, manufacturers also have the option of using
an amorphous core, which has a relatively flat cost-efficiency curve
across significantly higher-efficiency levels.
Therefore, for the reasons discussed, DOE is not creating a
separate equipment class based on BIL rating for liquid-immersed units
in this final rule.
g. Other
DOE received additional comments discussing other potential
equipment classes but generally did not receive any data regarding what
technical features associated with these products warrant a separate
equipment class.
NEMA commented that DOE should consider not including shovel
transformers, above ground mining transformers, crane duty
transformers, and marine application transformers. (NEMA, No. 141 at p.
13)
DOE notes that NEMA did not include any data or comment regarding
the specific technical challenges this equipment would have in meeting
efficiency standards or even suggest that these challenges exist. NEMA
also did not provide comment regarding the physical features that would
allow this equipment to be defined as compared to other general purpose
distribution transformers. Therefore, DOE has not considered separate
equipment classes for this equipment.
DOE received comment regarding triplex core transformers, which
include three, single-phase core-coil assemblies grouped together to
form a three-phase transformer. WEC commented that it commonly uses a
triplex core design to prevent ferro resonance, which requires more
pounds of core steel per kVA and could mean amended efficiency
standards result in higher incremental costs. (WEC, No. 118 at p. 2)
WEC commented that further increases in efficiency requirements could
lead to the elimination of triplex core transformers, which would
present additional operational and safety challenges to WEC employees
and significantly extend outages to customers. Id. Howard supported
creating a different equipment class for 3-phase pole mounted
transformers because of their unique triplex design. (Howard, No. 116
at pp. 25-26) Howard additionally supported dividing pole and pad
mounted transformers into separate equipment classes as utilities can
more easily accommodate larger pad-mounted transformers. Id.
While triplex core transformers have more core steel per kVA than a
traditional three-phase transformer, DOE did not receive any data as to
the degree of difference. DOE notes that lower-loss core steel
technology options would be expected to improve the performance of both
traditional three-phase transformers and triplex core transformers.
DOE's max-tech efficiency levels are typically met with amorphous
cores, which would have lower no-load losses for both traditional
three-phase transformer cores and triplex core transformers. Further,
as WEC noted, triplex core transformers can be used in the exact same
applications as three-phase pad-mounted transformers. For these
reasons, DOE has not considered a separate equipment class for triplex
core transformers. To the extent pole and pad-mounted transformers may
have different installation challenges, those costs are accounted for
in the installation costs, discussed in section IV.F.4 of this
document.
Standards Michigan recommended DOE remove obstacles to
manufacturers who choose to produce inexpensive, mobile transformers
designed for the purpose of preventing civil unrest during major
regional contingencies. Standards Michigan went on to state that these
MRC transformers could be placed in a new product class. (Standards
Michigan, No. 109 at pp. 1-2)
Utilities tend to keep distribution transformer reserves available
for emergency situations, such as during a natural disaster or other
storm. DOE notes that it develops separate equipment classes based on
specific class-setting factors as set forth by EPCA, as described in
section IV.A.2. (42 U.S.C. 6316(a); 42 U.S.C. 6295(q)(1)). Standards
Michigan did not identify any specific features associated with
contingency transformers. Therefore, DOE has not established a separate
equipment class for these contingency transformers.
[[Page 29889]]
3. Technology Options
In the preliminary market analysis and technology assessment, DOE
identified several technology options initially determined to improve
the efficiency of distribution transformers, as measured by the DOE
test procedure.
Increases in distribution transformer efficiency are based on a
reduction of distribution transformer losses. There are two primary
varieties of loss in distribution transformers: no-load losses and load
losses. No-load losses are roughly constant with PUL and exist whenever
the distribution transformer is energized (i.e., connected to
electrical power). Load losses, by contrast, are zero at zero percent
PUL but grow quadratically with PUL.
No-load losses occur primarily in the transformer core, and for
that reason the terms ``no-load loss'' and ``core loss'' are sometimes
interchanged. Analogously, ``winding loss'' or ``coil loss'' is
sometimes used in place of ``load loss'' because load loss arises
chiefly in the windings. For consistency and clarity, DOE will use
``no-load loss'' and ``load loss'' generally and reserve ``core loss''
and ``coil loss'' for when those quantities expressly are meant.
Distribution transformer design is typically an optimization
process. For a given core and conductor material, the mass and
dimensions of the transformer core, winding material, insulation,
radiators, transformer tank, etc., can be varied to minimize costs
while meeting a variety of design criteria. Within a manufacturer's
optimization process, transformers can be designed to be minimally
efficient or, if customers place a dollar value on electrical loss, can
be designed to minimize the transformers total owning costs. Typically,
small improvements in efficiency can be met with modest increase in
material quantities; however, at some point, achieving any further
increases in efficiency can substantially increases costs (i.e.,
hitting the ``efficiency wall'' where costs rise dramatically for small
increases in efficiency).
Once manufacturers have reached the ``efficiency wall'' for a given
core and conductor material, the only realistic option for meeting
higher efficiency values is to transition to core materials with lower
no-load losses and/or transition from aluminum to copper winding
material. The relative costs and availability of these lower-loss core
materials has varied over time and is discussed in detail in section
IV.A.4 of this document.
With respect to analyzed inputs, in the engineering analysis, DOE
considered various combinations of the following technology options to
improve efficiency: (1) Higher grade electrical core steels, (2)
different conductor types and materials, and (3) adjustments to core
and coil configuration.
4. Transformer Core Material Technology and Market Assessment
Distribution transformer cores are constructed from a specialty
kind of steel known as electrical steel. Electrical steel is an iron
alloy which incorporates small percentages of silicon to enhance its
magnetic properties, including increasing its magnetic permeability and
reducing the iron losses associated with magnetizing that steel.
Electrical steel is produced in thin laminations and either wound or
stacked into a distribution transformer core shape.
Electrical steel used in distribution transformer applications can
broadly be categorized as either amorphous alloy or GOES. There are
different subcategories of material performance within both amorphous
alloy and grain-oriented electrical steel. In the January 2023 NOPR,
DOE carried over the same naming convention developed in the August
2021 Preliminary Analysis TSD to identify the various permutations of
electrical steel. 88 FR 1722, 1754.
DOE notes that producing distribution transformer cores with
amorphous alloy requires different core production machinery than
producing distribution transformer cores with GOES. As such, some
amount of investment in machinery is required to transition between
producing cores with amorphous alloy and GOES. Today, there are many
equipment classes and kVA sizes where amorphous core transformers
compete with GOES transformers on first cost. However, the vast
majority of current core production equipment is set-up to produce GOES
cores, and therefore the vast majority of transformer shipments use
GOES cores even for products where using an amorphous core would lead
to a lower first-cost to the consumer.
In meeting efficiency standards with GOES, DOE notes that using
lower-loss GOES steel allows manufacturers to achieve modest
improvements in efficiency with essentially identical designs (e.g.,
essentially no increase in product weight, just a direct swap of
higher-loss core steel with lower-loss core steel). However, there is a
limited capacity of lower-loss GOES grades and only a single domestic
manufacturer of GOES steel, which limits the availability of GOES
products to distribution transformer manufacturers.
In achieving higher efficiencies without changing GOES steel
performance, Eaton commented that manufacturers increase the core cross
sectional area and decrease the flux density. (Eaton, No. 137 at pp.
21-22) The larger transformer cores require thicker conductors in order
to maintain current density but using thicker conductors increases
stray and eddy losses, which requires even larger conductor size to
combat the additional stray and eddy losses. (Eaton, No. 137 at pp. 21-
22) Eaton stated that at some point, the only option is to transition
to copper windings, at which point the cost of the transformer
skyrockets and significant cost increases are needed for even modest
efficiency gains. (Eaton, No. 137 at pp. 21-22)
In other words, achieving higher efficiencies without reducing the
losses of the core steel material is technically possible but gets
increasingly difficult (in terms of significant increases in product
weights and selling prices) as manufacturers attempt to reduce losses
further.
If lower-loss GOES were widely available, distribution transformer
manufacturers could achieve modest improvements in efficiency with
essentially identical designs (e.g., essentially no increase in product
weight, just a direct swap of higher-loss core steel with lower-loss
core steel). However, as with higher-loss GOES, beyond a certain point
reducing losses further is technically possible but results in
substantial increases in product weight and selling price.
In the current market, distribution transformer manufacturers limit
themselves to the single domestic GOES manufacturer's product offerings
and pricing, as any imported GOES steel is subject to a tariff that
makes such steel uncompetitive. Therefore, increasing the domestic
availability of lower-loss GOES steel depends on the investments in
product quality made by the single domestic GOES manufacturer.
Amorphous cores reduce transformer no-load losses by approximately
50 to 70 percent relative to GOES (see Chapter 5 of the TSD for
relative performance of amorphous- and GOES-based designs). This
substantial reduction in no-load losses means that much higher
efficiency standards can be achieved with amorphous cores (DOE's max-
tech efficiency assumes use of an amorphous core) and there is more
flexibility in designing transformers to meet efficiency standards (in
terms of the weight and dimensions of the cores, amount of winding
material, etc.).
However, the different production equipment associated with
producing
[[Page 29890]]
amorphous cores means that distribution transformer manufacturers must
decide how to meet potential amended efficiency standards. If using
amorphous cores, manufacturers would need to make substantial
investments in amorphous core production equipment. In exchange, they
would likely be able to sell many transformer ratings at a lower first
cost and win business in doing so. Alternatively, manufacturers could
continue to use existing GOES production equipment, however, they would
likely be selling a transformer at a higher first cost.
For modest reductions in transformer losses (generally through EL2
for liquid-immersed distribution transformers and EL 3 for dry-type
distribution transformers), the difference in first cost is not
substantial enough to warrant the considerable investment in amorphous
core production that is needed to meet efficiency standards. However,
between EL2 and EL4 for liquid-immersed distribution transformers and
EL3 and EL5 for dry-type distribution transformers, the size and weight
increase associated with GOES cores become substantial and it generally
becomes economically infeasible to continue producing GOES transformers
unless consumers ignore product cost (e.g., if shortages have forced
consumers to purchase any transformer they can access, regardless of
product costs).
DOE notes that in this final rule, it evaluated an additional TSL
for liquid-immersed distribution transformers (TSL 3) that is a
combination of proposed ELs, wherein some equipment classes are set at
EL2 and other equipment classes are set at EL4. DOE notes that the ELs
used in the final rule correspond to an identical reduction in losses
as the ELs used in the January 2023 NOPR. However, the grouping of
these ELs by equipment class has been modified in response to
stakeholder feedback. In consideration of this feedback, for this final
rule DOE regrouped the ELs that comprise TSL 3 such that EC1A and EC2A
were evaluated at EL4, which is expected to predominantly be met via
use of amorphous cores, while EC1B and EC2B were evaluated at EL2,
which can be met via use of either GOES or amorphous cores. The new TSL
3 is intended to reflect stakeholder concerns that standards requiring
substantial amorphous core production are not economically justified.
As explained further below, TSL 3, which DOE is adopting in this final
rule, is economically justified, technologically, feasible and
maximizes energy savings without requiring an entire market transition
to amorphous cores.
Under the adopted standard, the kVA ranges that will be required to
meet EL4 represent only a portion of the overall distribution
transformer market, and the volumes of amorphous steel required to
supply this segment of the market is similar to the existing domestic
amorphous ribbon production. As such, the adopted standard ensures that
even absent significant growth in amorphous ribbon production, capacity
in that market will be sufficient to meet demand in the transformer
market. Further, the kVA ranges that have to meet EL2 approximately
correspond with the existing domestic GOES production that serves the
distribution transformer market. Accordingly, DOE has determined that
this TSL ensures that manufacturers will not have to scrap existing
production equipment. Rather, manufacturers of distribution
transformers, amorphous ribbon, and GOES steel can all focus on and
invest in increased production.
The various markets, technologies, and naming conventions for
amorphous and GOES are discussed in the following sections, along with
a discussion as to the expected variables manufacturers would consider
in deciding how to meet amended efficiency standards.
a. Amorphous Alloy Market and Technology
Amorphous alloy \65\ is a variety of core material that is produced
by rapidly cooling molten alloy such that crystals do not form. The
resulting product is thinner than GOES and has lower core losses, but
it reaches magnetic saturation at a lower flux density.
---------------------------------------------------------------------------
\65\ Throughout this rulemaking, amorphous alloy is referred to
by stakeholders using various terms including ``amorphous'',
``amorphous alloy'', ``amorphous material'', and ``amorphous
steel''. Each of these terms generally refers to amorphous ribbon
which is then formed into an ``amorphous core'' that is used in the
transformer.
---------------------------------------------------------------------------
DOE has identified three subcategories of amorphous alloy as
possible technology options. These technology options and their DOE
naming shorthand are shown in Table IV.4.
[GRAPHIC] [TIFF OMITTED] TR22AP24.531
In the January 2023 NOPR, DOE discussed that it did not include any
designs which utilized high-permeability amorphous because, although
there are some design flexibility advantages to using high-permeability
amorphous, it is only available from a single supplier. 87 FR 1722,
1754. DOE further noted that, in interviews, manufacturers had
expressed a hesitance to rely on a single supplier of amorphous for any
higher volume unit. Id. However, DOE also stated that hibam material
can generally be used in place of standard am designs, though some
specific applications may require redesigning. This assumption was
supported by stakeholder comments in response to the August 2021
Preliminary Analysis TSD, as discussed in the January 2023 NOPR. 87 FR
1722, 1754-1755. Therefore, it is appropriate to include only standard
am designs in the engineering analysis to avoid setting efficiency
standards based on a steel variety, hibam, that is only available from
a single supplier. Under this approach, manufacturers have the option
to achieve efficiency levels that require am steel using either the
standard am material or the hibam material depending on their sourcing
practices and preferences. Id.
In the January 2023 NOPR, DOE also discussed the existence of a
hibam material that uses domain refinement (``hibam-dr'') to further
reduce core losses. 87 FR 1722, 1755. DOE stated that it had learned
through interviews
[[Page 29891]]
that the hibam-dr product is not yet widely commercially available. As
such, DOE did not include the hibam-dr product in its analysis because
DOE could not verify that the core loss reduction of this product is
maintained throughout the core production process and because it is
only produced by one supplier. Id.
DOE notes that, since the publication of the January 2023 NOPR, it
has identified additional amorphous suppliers who may offer high
permeability grades, or potentially even high permeability domain
refined grades.66 67 However, total capacity for these
steels remains uncertain, potentially limiting their availability for
use in the domestic distribution transformer market. Further, it is
uncertain what the performance of amorphous ribbon would be from
manufacturers with the technological know-how to produce amorphous
68 69 but who do not currently produce wide-cast amorphous
ribbon and may enter the market if demand for amorphous were to
increase. Therefore, to allow greater design flexibility for
manufacturers attempting to meet any amended standards, DOE has
continued to exclude designs in the engineering analysis that use
higher grades of amorphous.
---------------------------------------------------------------------------
\66\ Qingdao Yunlu Advanced Materials Technology, Amorphous
Ribbon Alloy. Available at www.yunluamt.com/product-50-1.html (last
accessed Nov. 8, 2023).
\67\ Qingdao Yunlu Advanced Materials Technology, Amorphous
alloy strip, precursor thereof, preparation method of amorphous
alloy strip, amorphous alloy iron core and transformer. China Patent
No. CN116162870A. May 26, 2023.
\68\ See Guidebook for POSCO's Amorphous Metal. Available at
Docket No. EERE-2010-BT-STD-0048-0235.
\69\ Vacuumschmelze GmbH and Co KG, Amorphous metal foil and
method for producing an amorphous metal foil using a rapid
solidification technology, U.S. Patent No. 11,623,271. Jun. 29,
2023.
---------------------------------------------------------------------------
Amorphous Technological Feasibility
In response to the January 2023 NOPR, DOE received additional
comments regarding the performance of amorphous cores.
Powersmiths stated a concern that amorphous core transformers may
exhibit certain performance defects when compared to GOES, including
shards breaking off from the core, which may lead to premature failures
and higher audible noise, making it more difficult or impossible to
achieve NEMA ST-20 audible noise levels. (Powersmiths, No. 112 at pp.
2-3) Powersmiths additionally commented that there are many technical
challenges with using amorphous cores, including non-homogenous flux
distributions for wound cores, incompatibility with the cruciform
structures required for larger kVA transformers, and greater difficulty
in meeting standards for lower temperature units. Accordingly,
Powersmiths commented that a wholesale conversion to amorphous material
does not make sense given the limitations of the technology.
(Powersmiths, No. 112 at p. 6)
Schneider commented that more research is needed into the inrush
current, sound levels, and reduced impedance of amorphous. (Schneider,
No. 101 at p. 2) Carte commented that amorphous transformers are louder
than GOES transformers and questioned what the impacts of amorphous
transformers would be on noise-sensitive areas. (Carte, No. 140 at p.
5) HVOLT commented that amorphous transformers create more audible
noise. (HVOLT, No. 134 at p. 5) APPA commented that amorphous
transformers produce more noise than GOES transformers, which would
cause utilities to install transformers further away and increase
secondary cable losses. APPA also stated that there are potential
health impacts from higher levels of background noise. (APPA, No. 103
at p. 14) Idaho Power recommended DOE include weight, noise, and cost
in its engineering analysis, stating that the proposed standards will
likely result in the use of heavier, noisier, and costlier amorphous
core transformers. (Idaho Power, No. 139 at p. 3)
AISI and Pugh Consulting both commented that amorphous is brittle
and untested. (AISI, No. 115 at p. 2; Pugh Consulting, No. 117 at p. 5)
Pugh Consulting additionally questioned whether amorphous transformers
could be ``drop-in replacements'' for current transformers. (Pugh
Consulting, No. 117 at p. 5)
Exelon commented that domestic manufacturers have limited
experience making amorphous core distribution transformers, a
deficiency in domestic manufacturing experience that could have
significant cost, supply chain, and reliability implications. Exelon
added that most uses of amorphous core transformers have been limited
to kVA ratings below Exelon's needs and its current research suggests
the use of amorphous transformers at higher ratings is essentially
experimental. (Exelon, No. 95 at p. 3)
Metglas commented that amorphous core transformers accounted for
approximately 10 percent of new installs in 1992 but became less common
largely due to fewer utilities using a total owning cost (TOC) model.
(Metglas, No. 125 at p. 2) Metglas further stated that amorphous
transformers have served the electrical grid since 1982, with an
estimated 22 million units in operation globally and approximately 1
million additional units brought online each year. Id.
Efficiency advocates commented that amorphous transformers are a
proven technology, with an estimated 3 million transformers globally
and over 90% of liquid immersed transformers in Canada utilizing
amorphous cores. (Efficiency Advocates, No. 121 at pp. 1-2) NYSERDA
similarly commented that transformers with amorphous cores are field
proven and cost effective. (NYSERDA, No. 102 at pp. 2-3)
EMS Consulting commented that GE produced over 600,000 amorphous
transformers between 1986 and 2001 with very satisfactory field
experiences, indicating that amorphous transformers are a reliable
product. (EMS Consulting, No. 136 at pp. 2-3) EMS Consulting added that
deregulation of electrical industries in the 1990s reduced demand for
amorphous products in the U.S., but the products became more popular in
developing countries like India and China due to its lower operating
costs. Id. EMS Consulting stated that very few U.S. utilities purchase
based on TOC but globally over 22M units have been installed and over
1M amorphous transformers are installed globally per year. Id.
EMS Consulting added that, although amorphous transformers
exhibited certain performance challenges when they were first
commercialized in the 1980s, such as increased transformer size and a
tendency to be more brittle, improvements in amorphous properties and
manufacturing methods have made them comparable in reliability to GOES
transformers. (EMS Consulting, No. 136 at pp. 2-3) EMS Consulting
further stated that the high-permeability amorphous products have a
higher stacking factor and flux density, which will produce an even
smaller and lighter transformer than that assumed by the NOPR. (EMS
Consulting, No. 136 at p. 4)
DOE notes that amorphous core transformers are not a new
technology. As stated by Metglas and EMS Consulting, installations of
amorphous transformers have occurred for decades, beginning in the
1980s. While DOE agrees that amorphous core transformers are less
common in the domestic market today than GOES core transformers, DOE
disagrees with implication that this is the result of any performance
defects precluding amorphous material from being used in place of GOES
in distribution transformer cores. As pointed out by EMS consulting,
early-stage amorphous core transformers
[[Page 29892]]
faced certain technical challenges, such as increased noise levels and
metal shards flaking from the core. However, the development of better
manufacturing processes for both amorphous ribbon and amorphous cores
has mitigated the impact of these issues.
In DOE's review of the market, it observed multiple major
manufacturers of distribution transformers advertising amorphous
transformers as reliable, low-loss alternatives to GOES
transformers.70 71 72 73 Manufacturers design these
transformers to comply with the same industry standards that apply to
GOES units, which include provisions for general mechanical
requirements and audible noise limits.\74\ During confidential
manufacturer interviews, DOE also heard from stakeholders that
amorphous transformers have become more comparable to GOES, with some
manufacturers often providing specifications to customers for both GOES
and amorphous core designs.
---------------------------------------------------------------------------
\70\ Howard, Howard Amorphous Core Transformers. Available at
howardtransformer.com/Literature/Amorphous%20Core%20Trans.pdf (last
accessed Oct. 30, 2023).
\71\ Hitachi, Hitachi Amorphous Transformers. Available at
www.hitachi-ies.co.jp/english/catalog_library/pdf/transformers.pdf
(last accessed Oct. 30, 2023).
\72\ Eaton, Three-phase pad-mounted compartmental type
transformer. Available at www.eaton.com/content/dam/eaton/products/medium-voltage-power-distribution-control-systems/cooper-power-series-transformers/three-phase-pad-mounted-compartmental-type-transformer-ca202003en.pdf (last accessed Nov. 15, 2023).
\73\ Wilson Power Solutions, Amorphous Metal Transformers--Myth
Buster. Available at www.wilsonpowersolutions.co.uk/app/uploads/2017/05/WPS_AMT_Myth_Buster_2018-2.pdf (last accessed Nov. 30,
2023).
\74\ IEEE SA. (2021). IEEE C57.12.00-2021--IEEE Standard for
General Requirements for Liquid-Immersed Distribution, Power, and
Regulating Transformers. Available at standards.ieee.org/ieee/C57.12.00/6962/ (last accessed Nov. 8, 2021).
---------------------------------------------------------------------------
DOE also notes that adoption of amorphous metal transformers has
significantly increased on a global scale in the past decade. In
Canada, for example, over 90 percent of sales for liquid-immersed
distribution transformer are estimated to utilize amorphous cores.\75\
China and India have similarly exhibited large upticks in amorphous
transformer sales.\74\ The fact that significant numbers of amorphous
distribution transformers have been installed to the electrical grid
without any significant reports of failure or apparent design defects,
including approximately 600,000 units sold within the U.S.,\76\
demonstrates that amorphous transformers can be readily substituted for
GOES transformers. Further, some utilities have stated that certain
liquid-immersed manufacturers do not even state in bid sheets whether
their transformers have an amorphous core or GOES core, indicating that
the performance of each transformer is viewed as similar enough to be
irrelevant to the manufacturer.\77\ For these reasons, DOE has
maintained in this final rule that amorphous core transformers can be
reasonably interchanged with GOES transformers without impacting
performance.
---------------------------------------------------------------------------
\75\ Bonneville Power Administration, Amorphous Core Liquid
Immersed Distribution Transformers. 2020. Available at www.bpa.gov/-/media/Aep/energy-efficiency/emerging-technologies/liquid-immersed-amorphous-core-distribution-transformers-2020-03-31-final.pdf (last
accessed Oct. 30, 2023).
\76\ Metglas, Amorphous Metal Distribution Transformers. 2016.
Available at metglas.com/wp-content/uploads/2021/06/Metglas-Power-Brochure-Updated.pdf (last accessed Oct. 30, 2023).
\77\ Bonneville Power Administration, Low-Voltage Liquid
Immersed Amorphous Core Distribution Transformers. 2022. Available
at www.bpa.gov/-/media/Aep/energy-efficiency/emerging-technologies/ET-Documents/liquid-immersed-dist-transformers-final-22-0216.pdf
(last accessed Nov. 8, 2023).
---------------------------------------------------------------------------
Entergy expressed concern that ferroresonance might be a more
prominent issue for amorphous core transformers, especially for lightly
loaded transformers or those with protective switching, potentially
damaging downstream equipment. (Entergy, No. 114 at p. 3) Entergy
stated that an EPRI report indicated that increased noise is a common
complaint for amorphous core transformers and that some users indicated
that: (1) amorphous cores are more brittle and subject to breaking
under strong forces; (2) operating practices may have to change to
handle ferroresonance; and (3) lower harmonics passing through the
transformer could interact with EV charging stations. Entergy commented
that these technical challenges warrant additional research and
development prior to the widespread deployment of amorphous technology.
Id.
Manufacturer literature and public reports \78\ widely indicate
that technological improvements to the design of amorphous core
transformers have largely resolved previous performance issues, such as
brittleness of the core. As a result, amorphous core transformers have
been deployed worldwide without any significant detriment to
performance, as discussed further in Chapter 3 of the TSD, indicating
that amorphous transformers can be substituted for GOES transformers in
a wide array of applications, including those with sensitive downstream
equipment. Regarding ferroresonance concerns specifically, DOE notes
that increased instances of ferro resonant conditions have not been
linked to use of amorphous metal cores. One study conducted by the
Bonneville Power Administration indicated that amorphous core
transformers do not significantly increase the probability or severity
of ferroresonance incidents.\79\ Stakeholder have also previously
indicated that they have not experienced any increases in
ferroresonance for amorphous core transformers.\80\
---------------------------------------------------------------------------
\78\ Bonneville Power Administration, Low-Voltage Liquid
Immersed Amorphous Core Distribution Transformers. 2022. Available
at www.bpa.gov/-/media/Aep/energy-efficiency/emerging-technologies/ET-Documents/liquid-immersed-dist-transformers-final-22-02-16.pdf
(last accessed Oct. 30, 2023).
\79\ Bonneville Power Administration, Low-Voltage Liquid
Immersed Amorphous Core Distribution Transformers. 2022. Available
at www.bpa.gov/-/media/Aep/energy-efficiency/emerging-technologies/ET-Documents/liquid-immersed-dist-transformers-final-22-02-16.pdf
(last accessed Oct. 30, 2023).
\80\ See Docket No. EERE-2019-BT-STD-0018, Eaton, No. 0055 at p.
10.
---------------------------------------------------------------------------
MTC commented that amorphous core transformers have approximately
20-25 percent more mass, including all non-core components, due to a
lower saturation flux density and stacking factor. (MTC, No. 119 at pp.
11-12) Carte also asserted that amorphous cores require approximately
20 percent more material and the environmental and carbon footprint of
producing that material might counter the energy savings. (Carte, No.
140 at p. 1) WEG commented that producing amorphous core transformers
would increase the weight of units by 25 percent. (WEG, No. 92 at p. 3)
HVOLT commented that many transformers require stacked core
constructions, which is only viable with GOES materials and three-phase
construction with wound cores generally increases the transformer size
which may not be feasible for applications such as power center
transformers. (HVOLT, No. 134 at p. 7) Portland General Electric
commented that the larger profile of the amorphous core and windings
would require a larger tank, more winding copper/aluminum wire, more
oil, and more labor to produce, resulting in higher upfront procurement
costs approximately 15-20 percent greater than GOES. (Portland General
Electric, No. 130 at p. 3) As an example, Portland General Electric
stated that a 25kVA pole-mounted amorphous transformer is roughly the
size of 50kVA GOES core transformer. (Portland General Electric, No.
130 at p. 3)
Historically, amorphous transformers have been larger than GOES
[[Page 29893]]
transformers. GOES transformers have higher saturation flux density and
a higher stacking factor than amorphous transformers, which allows GOES
transformers to have a lower volume. However, quality improvements in
amorphous ribbon have improved stacking factors. Further, the size of a
GOES transformer is largely dependent on the loss performance of GOES
being used. See Chapter 5 of the TSD for specific details. To reduce
losses in a GOES transformer, manufacturers frequently design larger
GOES cores with a reduced saturation flux density, meaning that the
size of GOES transformers have increased in an effort to increase the
efficiency of GOES transformers.
Eaton submitted data demonstrating that for certain transformer
designs, an amorphous transformer weights less at baseline. (Eaton, No.
137 at p. 32) Further, Eaton stated that its data showed that in
meeting the proposed efficiency standards, the incremental weight of a
more efficient amorphous transformer is only 5.4 percent greater than
the base amorphous design and ~1 percent relative to the base GOES
design. Id. Eaton stated that its data also showed that achieving
proposed efficiency levels with a GOES transformer results in a 50
percent weight increase. Id.
One study published by the Bonneville Power Administration in 2022
reported the incremental weight increase for baseline GOES transformers
and baseline amorphous transformers using data submitted by a
distribution transformer manufacturer. Their data indicated that the
baseline amorphous transformer was, in many cases, smaller than an
equivalent GOES transformer for a number of kVA sizes.\81\
---------------------------------------------------------------------------
\81\ Bonneville Power Administration, Low-Voltage Liquid
Immersed Amorphous Core Distribution Transformers. 2022. Available
at www.bpa.gov/-/media/Aep/energy-efficiency/emerging-technologies/ET-Documents/liquid-immersed-dist-transformers-final-22-02-16.pdf
(last accessed Oct. 30, 2023).
---------------------------------------------------------------------------
The actual cost and size difference between a GOES core transformer
and an amorphous core transformer depends on the actual design of the
transformer, the loss performance of the core materials used, the
winding material used, and whether manufacturers are trying to meet
strict dimensional constraints or simply designing the lowest cost
transformer. DOE does not apply blanket cost increases to any
transformer that has an amorphous core. Rather, DOE evaluates the
change in material costs that would be incurred by both amorphous core
and GOES core transformers meeting a range of efficiency levels. In its
analysis, DOE does reflect the fact that more efficient transformers
typically require more material. This additional material has a cost,
which is accounted for in DOE's modeling, is discussed in section IV.C
of this document. DOE also considers potential impact on installation
costs (see section IV.F.2 of this document).
Idaho Falls Power and Fall River stated that amorphous core
transformers may have negative environmental impacts when considering
the energy gains versus the increased energy usage for manufacturing.
(Idaho Falls Power, No. 77 at p. 1; Fall River, No. 83 at p. 1) NAHB
commented that 40 percent of electrical steel manufacturing costs are
attributed to energy consumption and stated that DOE should consider
the impact of high heat in both GOES and amorphous manufacturing.
(NAHB, No. 106 at p. 12)
Regarding the energy usage associated with the manufacturing of
amorphous cores, DOE notes that relative to GOES, amorphous ribbon
production generally has lower temperatures used throughout its
production process and a lower transformer core annealing temperature,
which would indicate less energy use in manufacturing. Manufacturer
literature has reported on the life-cycle assessment of amorphous and
GOES cores, which would include the manufacturing, utilization, and
end-of-life of the product, and concluded that the environmental impact
of high-efficiency amorphous transformers is substantially lower than
GOES transformers.\82\
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\82\ ABB, Distribution goes green. Available at
library.e.abb.com/public/f28b7caf32af14e8c1257a25002f2717/40-47%202m221_EN_72dpi.pdf (last accessed Nov. 9, 2023).
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Pugh Consulting questioned whether amorphous metal could be
recycled at the end of a transformer's lifetime and suggested DOE
consider the costs associated with disposing of and/or recycling all
current transformers by 2027. (Pugh Consulting, No. 117 at p. 5) DOE
notes that amorphous cores can be recycled at end of life.\83\ Further,
transformers manufactured before the compliance date for this final
rule would be subject to the relevant standards corresponding to their
date of manufacture, not the efficiency standards amended in this rule
(i.e., all transformers do not need to be disposed of by 2027, as Pugh
Consulting suggested). As such, any transformers currently installed,
as well as those manufactured before the compliance date for this final
rule, would not be required to be disposed of or replaced.
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\83\ Metglas, Inc. Recycling of Amorphous Transformer Cores,
2010. Available at metglas.com/recycling-amorphous-transformer-cores/ (last accessed Nov. 9, 2023).
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REC commented that amorphous transformers are known to suffer
higher failure rates due to increased susceptibility to mechanical
stresses, lower short-circuit tolerance, and greater brittleness of the
core. (REC, No. 126 at pp. 2-3) APPA commented that amorphous cores are
less able to withstand short-circuit faults than GOES transformers and
have a lower overload capacity due to lower saturation flux-density.
(APPA, No. 103 at p. 12)
APPA and Carte commented that amorphous transformers are subject to
metal flakes in the oil which can lead to partial discharging and
premature failure. (APPA, No. 103 at pp. 10-11; Carte, No. 140 at pp.
7-8) APPA added that these discharges could require the use of oil
monitoring devices for amorphous transformers at an additional cost.
(APPA, No. 103 at pp. 10-11) Carte stated that discharging is more
likely to occur if amorphous cores are used for higher voltages, which
to Carte's understanding they have not been thus far. Carte added that
it wasn't sure how amorphous cores were grounded and noted that current
core grounding techniques may not be sufficient at higher voltages,
additionally risking premature failure. (Carte, No. 140 at pp. 7-8)
Regarding increased susceptibility to mechanical stresses, as
previously noted, while brittleness of amorphous cores has historically
been reported as a performance complication, performance improvements
to amorphous ribbon as well as technological developments in the design
and bracing of amorphous transformer cores have helped resolve this
issue. Additionally, in DOE's review of the market, it observed
manufacturer literature advertising construction techniques which
reinforce amorphous metal cores and add resilience to mechanical
stresses. For example, it has become standard to encase amorphous metal
cores in an epoxy resin which stabilizes the core and reduces the
likelihood of metal shards forming. Technologies also exist which can
be used in tandem with the transformer core to capture shards, ensuring
that they do not contaminate the insulation fluid or cause short
circuits in the transformer windings. These developments, paired with
performance improvements made to the amorphous metal ribbon itself,
have significantly reduced the risk of metal flakes from an amorphous
core impacting overall transformer performance.
[[Page 29894]]
Regarding decreased short circuit capacity for amorphous
transformers, industry standards set forth the provisions for short-
circuit withstand capacity for all transformers, regardless of the
transformer core material used.84 85 As previously noted,
amorphous core transformers are currently being designed and deployed
in the field to meet these standards, indicating that they can be
designed to withstand the same short circuit capacities as GOES
transformers. Similar to the developments which have resolved
brittleness issues experienced by early-stage amorphous transformers,
technological improvements in the core and coil design for amorphous
transformers have the capacity to withstand short circuit events over
the years. For example, utilizing foil windings on the secondary coil,
rather than rectangular wire or strip, reduces axial forces on the core
and winding, reducing mechanical stresses and increasing short circuit
capacity. Insulating materials can also be applied around the core to
absorb mechanical stresses during operation, reducing the strain
experienced by the core itself.\86\ As a result, amorphous transformer
cores can be reliably built without increased risk of short circuit or
premature failure when compared to an equivalent GOES transformer.
---------------------------------------------------------------------------
\84\ International Electrotechnical Commission, IEC 60076-
5:2006: Power transformers--Part 5: Ability to withstand short
circuit. 2006. Available at webstore.iec.ch/publication/603.
\85\ IEEE SA. (2021). IEEE C57.164-2021--IEEE Guide for
Establishing Short-Circuit Withstand Capabilities of Liquid-Filled
Power Transformers, Regulators, and Reactors. 2021. Available at
standards.ieee.org/ieee/C57.164/6804/ (last accessed Nov. 8, 2023).
\86\ Wilson Power Solutions, Amorphous Metal Transformers--Myth
Buster. Available at www.wilsonpowersolutions.co.uk/app/uploads/2017/05/WPS_AMT_Myth_Buster_2018-2.pdf (last accessed Oct. 30,
2023).
---------------------------------------------------------------------------
APPA stated that DOE should investigate whether the use of
amorphous cores would change the gases produced by transformers with
the new fluids and steels, the potential impact of using amorphous
transformers in areas with extremely hot or cold climates, and the
impact of amorphous transformers having a lower overload capacity.
(APPA, No. 103 at pp. 16-17)
DOE notes that amorphous core transformers use the same insulation
fluids as GOES transformers and APPA did not elaborate as to how the
use of an amorphous metal, rather than GOES, in the transformer core
would cause the transformer to produce additional or different gases
during operation, nor did they elaborate or provide data as to how a
change in core material would impact gases produced in a transformer.
As such, DOE does not have reason to believe that amorphous core
transformers would perform any differently than GOES transformers with
regard to gases produced during operation.
Regarding deployment of amorphous transformers in hot or cold
climates, as previously noted, amorphous core transformers have been in
deployment for several decades and have been deployed worldwide,
including areas with extremely hot or cold climates. Further, amorphous
core transformers do not inherently have lower overload capacity as
detailed in section IV.C.1.d of this document as this is a function of
temperature rise and transformer load losses.
APPA further commented that some research indicates that the
performance of amorphous transformers degrades over time, with losses
likely to become higher than GOES transformers. APPA stated that
accounting for those losses would undermine any economic justification
for the proposed standards. (APPA, No. 103 at pp. 10-11) DOE notes that
both the study cited by APPA and the original 1996 study \87\ are
referring to degradation in the process of forming an amorphous core
from amorphous ribbon (i.e. the material destruction factor or build
factor), not degradation of the material over time. This kind of
degradation is accounted for in the losses for a transformer and is
therefore considered in DOE's analysis of both GOES and amorphous core
transformers.
---------------------------------------------------------------------------
\87\ Y. Okazaki, Loss deterioration in amorphous cores for
distribution transformer, Journal of Magnetism and Magnetic
Materials 160 (1996) 217-222.
---------------------------------------------------------------------------
Exelon stated its concern about the ability of amorphous core
transformers to maintain their efficiency levels over an extended
lifetime, calling into question the life-cycle environmental benefit of
these new transformers. Exelon commented that studies to address these
extended performance concerns are planned but have not yet been
executed. (Exelon, No. 95 at p. 3) REC commented that, due to the
metallurgical nature of amorphous material, there is a continuous
erosion of loss-savings as core material ages and degrades. (REC, No.
126 at p. 3)
PSE commented that amorphous core transformers have lower overload
capacity and experience greater mechanical stress during faults due to
their rectangular core shape, as opposed round GOES cores. (PSE, No. 98
at p. 13) The SBA expressed concern that amorphous cores may degrade
faster and be less capable of sustaining overload conditions than
current GOES cores. (SBA, No. 100 at p. 6) REC commented that amorphous
transformers have limited load and overload capacity compared to GOES,
which will require additional or higher-capacity units to serve the
same number of consumers. (REC, No. 126 at p. 2-3) Portland General
Electric commented its current design practices allow for peak loads up
to 150 percent of the transformer nameplate rating but would need to be
revised to accommodate accelerated degradation during overloading for
amorphous transformers. (Portland General Electric, No. 130 at p. 3)
Cliffs commented that amorphous transformers cannot be loaded as
efficiently as GOES cores, which increases likelihood of transformer
failure. (Cliffs, No. 105 at p. 11)
Transformer overloading conditions can result in increased
mechanical stress and excess heat generation. Therefore, a
transformer's capacity to withstand overloading conditions is dependent
on its ability to endure mechanical stress and effectively dissipate
heat. As previously noted, construction techniques exist to reinforce
amorphous metal transformers against mechanical stress, reducing the
risk of damage caused by overloading conditions. With regard to an
amorphous transformer's ability to shed heat, excess heat is primarily
generated through transformer losses. At higher loads, the load losses
primarily dictate heat generation due to the quadratic relationship
between load losses and transformer loading. Since minimally compliant
amorphous transformers are often designed with higher load losses than
GOES units, this may lead to the belief that amorphous transformers are
less equipped to handle overloading conditions. However, as further
discussed in section IV.C.1.d of this document, amorphous transformers
do not inherently have higher load losses. Just as GOES transformers
can be designed to meet efficiency standards by either reducing no-load
or load losses, amorphous transformers can similarly be designed with
lower load losses. DOE's modeling includes amorphous core transformers
with a range of load losses, thereby maintaining the availability of
designs with higher overload capacity. As such, transformer customers
will continue to have the option of purchasing transformers with higher
or lower overload withstand capacity based on the needs of their
application. In absence of overload capacity, customers would likely be
[[Page 29895]]
forced to purchase higher kVA ratings than necessary and in doing so
risk wasting money, energy, and electrical steel availability.
Although multiple stakeholders expressed concern that the
efficiency of amorphous transformers may degrade over time, no
stakeholders provided data to demonstrate any such loss of efficiency
over time; rather, they only cited studies on the reduction in losses
in converting amorphous ribbon into amorphous cores. DOE notes that
degradation of transformer performance is often associated with a
degradation of transformer insulation, typically due to operation at
elevated operating temperatures. As discussed in section IV.C.1.d of
this document, amorphous transformers are capable of achieving low load
losses, meaning temperature rise would not increase as fast, even at
higher-loading conditions. DOE does not have reason to believe that the
rated efficiency of an amorphous transformer would degrade over time
when compared to an equivalent GOES transformer. Further, manufacturer
literature has reported on accelerated aging tests of amorphous
transformers and concluded that they saw no degradation of losses in an
amorphous core during the transformer life.\88\ Therefore, given the
lack of data supplied, and given the technological developments which
have enabled amorphous transformers to withstand overload conditions
and short circuit conditions, DOE did not consider there to be
sufficient evidence to model amorphous transformers degrading in
performance over time when compared to an equivalent GOES transformer.
---------------------------------------------------------------------------
\88\ ABB, Distribution goes green. Available at
library.e.abb.com/public/f28b7caf32af14e8c1257a25002f2717/40-47%202m221_EN_72dpi.pdf (last accessed Nov. 9, 2023).
---------------------------------------------------------------------------
Amorphous Market
In the January 2023 NOPR, DOE discussed how amorphous ribbon
capacity has increased since the April 2013 Standards Final Rule. 88 FR
1722, 1755. DOE stated that it had identified numerous companies
capable of producing amorphous material (of standard am quality or
better) and that global amorphous ribbon capacity is much greater than
current demand. Id. DOE stated that it had learned through manufacturer
interviews that amorphous production capacity increased in response to
the April 2013 Standards Final Rule, but demand for amorphous did not
necessarily correspondingly increase, resulting in excess capacity. DOE
discussed how amorphous producers' response to the April 2013 Standards
Final Rule demonstrated that, if there was expected to be an increase
in market demand for amorphous, capacity would increase to meet that
demand. Id. Further, DOE also learned through confidential manufacturer
interviews conducted in support of the August 2021 Preliminary Analysis
and the January 2023 NOPR that recent price increases for GOES have led
amorphous to be far more cost competitive. However, despite this
increased competitiveness, the industry has not seen an increase in
amorphous transformer purchasing, likely due to existing distribution
transformer core production equipment being set-up to produce GOES
cores and a transition to amorphous cores requiring capital investment.
Id. Based on these developments, in the January 2023 NOPR, DOE
constrained the selection of amorphous alloys under the no-new-
standards scenario to better match the current market share of
distribution transformers; however, DOE did not apply any constraints
to standard am steel purchasing in its evaluation of higher efficiency
levels. 88 FR 1722, 1756.
In the January 2023 NOPR, DOE acknowledged that the availability of
both GOES and amorphous alloy is a concern for distribution
transformers, but expected that suppliers would be able to meet the
market demand for amorphous for all TSLs analyzed given the NOPR's 3-
year compliance period. 88 FR 1722, 1817. DOE noted that manufacturers
should be able to significantly increase supply of amorphous if they
know there will be an increase in demand as a result of the proposed
energy conservation standards. Id. DOE requested comment on this
assumption and how supply and demand would change in response to the
proposed amended energy conservation standards. Id.
In response, HVOLT, Southwest Electric, Cliffs and NRECA expressed
concern that there is not sufficient amorphous ribbon capacity
currently and capacity will not be able to grow quickly enough to meet
the amorphous demand increases expected from the proposed standards.
(HVOLT, No. 134 at pp. 5-6; Southwest Electric, No. 87 at p. 3; Cliffs,
No. 105 at pp. 10-11; NRECA, No. 98 at p. 3) Cliffs stated that even if
all global capacity were used, it would not be enough to support the US
market. (Cliffs, No. 105 at pp. 10-11) Cliffs added that DOE
incorrectly assumes amorphous production can increase to meet demand
without sufficient verification of if that is true. (Cliffs, No. 105 at
pp. 10-11)
Hammond commented that only one amorphous producer serves the U.S.
market and it cannot scale up in time to meet forecasted demand.
(Hammond, No. 142 at p. 2) Hammond added that it is not aware of any
efforts outside the U.S. to expand amorphous production to the levels
needed to serve the U.S. market. (Hammond, No. 142 at p. 2) DOE notes
there is one domestic producer of amorphous steel and one domestic
producer of GOES.
Howard commented that the proposed standards will increase GOES
demand by 60 percent, or increase amorphous by 600 million pounds, and
if all amorphous is domestic, increase domestic amorphous ribbon
capacity by 500 percent. (Howard, No. 116 at p. 2) Howard further
stated that silicon steel plants typically require 3-4 years and $1-2B
to design and build, whereas amorphous would require an additional 15-
20 production lines and $1B investment, which isn't achievable in the
proposed timeline. (Howard, No. 116 at p. 2) Cliffs commented that
amorphous transformers currently make up a small fraction of domestic
transformers production and cannot be scaled in the near-term to meet
the domestic market. (Cliffs, No. 105 at p. 6)
Prolec GE commented that current and projected capacities of both
amorphous metal ribbon and cores will likely remain below the levels
required for future demand. (Prolec GE, No. 120 at p. 14) VA, MD, and
DE House Representatives commented that the proposed standards will
require a rapid expansion of amorphous ribbon capacity which could
exacerbate near-term supply chain shortages. (VA, MD, and DE Members of
Congress, No. 148 at pp. 1-2)
Several stakeholders expressed concern that there was only a single
domestic supplier of amorphous material. Powersmiths commented that the
single supplier of amorphous will not be able to expand capacity to
meet the needs of the entire distribution transformer market and that
it is not acceptable to rely on a single supplier regardless.
(Powersmiths, No. 112 at p. 6) TMMA commented that the U.S.
manufacturer of amorphous would not be able to serve the entire US
transformer market, even with stated capacity expansions, leaving the
U.S. reliant on foreign produced amorphous. (TMMA, No. 138 at pp. 3-4)
Powersmiths commented that amorphous is not available in the narrower
strips required for LVDTs and the 2027 compliance date does not provide
sufficient time to put a supply chain in place. (Powersmiths, No. 112
at p. 6) Powersmiths further commented
[[Page 29896]]
that hibam is the most viable for LVDT markets and expressed concern
that this steel is offered from a single source. (Powersmiths, No. 112
at p. 6)
NAHB expressed concern that the proposed rule would worsen supply
and competition concerns. NAHB recommended that, given the limited
number of manufacturers for certain products, DOE should work with
other Federal agencies to fully review and address the likelihood that
this rule will exacerbate anticompetitive supply constraints. (NAHB,
No. 106 at pp. 2, 6)
Idaho Falls Power and Fall River stated that relying upon a single
domestic supplier of amorphous will create both a de facto monopoly and
a bottleneck in an already constrained supply chain. (Idaho Falls
Power, No. 77 at p. 1; Fall River, No. 83 at p. 2)
Alliant Energy commented that requiring all distribution
transformers to be made from a material with a single domestic suppler
representing less than 5 percent of the market will negatively impact
transformer production capacity and availability. (Alliant Energy, No.
128 at pp. 2-3) Alliant Energy added that the significant transit times
required to source amorphous from foreign nations would exacerbate
existing supply chain challenges. (Alliant Energy, No. 128 at pp. 2-3)
In this final rule, DOE notes that it has modified its assumptions
to reflect stakeholder feedback suggesting that even if amorphous is
the lowest first-cost option, manufacturers may elect to build GOES
transformers in order to maintain a more robust supply chain and reduce
the impact on existing short to medium-term supply challenges.
Specifically, DOE assumed that for liquid-immersed distribution
transformers, amorphous adoption will be constrained at all efficiency
levels through EL 2, as discussed in section IV.F.3 of this document.
Many stakeholders also commented expressing concern that the use of
amorphous metal would increase U.S. reliance on foreign suppliers.
Schneider asserted that given that only one company in Japan and
one company in the United States can produce amorphous materials, there
is risk of an oligopoly. (Schneider, No. 92 at pp. 9-10) Schneider
further stated that there are only two manufacturers that can produce
amorphous to meet DOE requirements and the barriers to entry are
extremely high. (Schneider, No. 92 at pp. 9-10) Prolec GE commented
that manufacturers will be forced to rely on foreign steel suppliers,
mainly from China, because the domestic supply of amorphous cannot meet
the demand of the U.S. distribution transformer market. (Prolec GE, No.
120 at p. 3) Eaton commented that it would like to have at least three
suppliers of amorphous, preferably located in different geographical
regions of North America. (Eaton, No. 137 at p. 27)
The Chamber of Commerce commented that requiring transformers to
use amorphous cores conflicts with public policy goals by increasing
the domestic electricity sector's reliance on inputs from China.
(Chamber of Commerce, No. 88 at p. 3) AISI commented that U.S. steel
production has a lower carbon intensity that steel made in China.
(AISI, No. 115 at p. 2)
EEI commented that the proposed standards will increase the need to
rely on foreign sourced products, which will create national security
concerns, eliminate American jobs, and increase transit times. (EEI,
No. 135 at pp. 29-30) NRECA commented that the proposed standards will
increase reliance on foreign nations for amorphous materials in
distribution transformers and GOES for power transformers. (NRECA, No.
98 at pp. 3-4) NRECA stated that higher labor costs for amorphous core
and a limited domestic capacity for amorphous materials will increase
outsourcing of distribution transformer manufacturing, creating a
national security risk. (NRECA, No. 98 at pp. 3-4) NRECA added that
many utilities are Rural Utilities Service (RUS) borrowers, which
prohibits them from purchasing products with foreign-sourced steel.
(NRECA, No. 98 at p. 7) Michigan Members of Congress stated that
offshoring manufacturing of distribution transformers raises national
security concerns. (Michigan Members of Congress, No. 152 at p. 1) Pugh
Consulting advised against relying upon a single steel variety and
stated that transformer shortages are dangerous given the number of
storms, hurricanes, and violent attacks by extremists against
distribution transformers. (Pugh Consulting, No. 117 at p. 4) TMMA
commented that the proposed standards increase our reliance on
international and unfriendly suppliers which is a threat to national
security. (TMMA, No. 138 at pp. 2, 4) Howard commented that
transformers are vital to national security and given existing
shortages, it is vital to maintain both GOES and amorphous as viable
options. (Howard, No. 116 at p. 4) AISI commented that if distribution
transformers transition to amorphous, that could eliminate domestic
GOES, which would be harmful to national security. (AISI, No. 115 at p.
2)
Carte commented that the proposed standards present national
security concerns because the timeline is not sufficient for amorphous
ribbon capacity to ramp up, which will require additional imports of
amorphous. Carte also noted that the domestic supplier's parent company
is headquartered in Japan. (Carte, No. 140 at p. 4)
HVOLT expressed concern that the proposed standards requiring
manufacturers to rely on a single amorphous supplier based in Japan,
whereas they can currently source core steel from multiple GOES
suppliers. (HVOLT, No. 134 at pp. 5-6)
Webb expressed concern that shifting towards amorphous cores will
place utilities at greater risk and increase U.S. reliance on foreign
suppliers. Webb compared this to the recent U.S. semiconductor scarcity
and questioned whether the government would similarly address
transformer shortages via Federal funding, as was done for
semiconductors with the CHIPS and Science Act. (Webb, No. 133 at p. 2)
MTC commented that patent disputes have led Hitachi to consolidate
all amorphous production in Japan, making the only global suppliers of
amorphous Hitachi and Chinese suppliers. (MTC, No. 119 at p. 20) DOE
notes that MTC's comment does not accurately reflect the current state
of the market. DOE is aware of amorphous production in the United
States today. See Appendix 3A of the TSD for a detailed discussion of
the amorphous and GOES markets.
MTC further commented that there is insufficient global production
capacity of amorphous to support the U.S. distribution transformer
market, even if domestic production capacity were tripled. (MTC, No.
119 at p. 9) MTC additionally commented that lack of domestic steel
supply is an issue of national security which should be referred to the
Department of Commerce for remedies. (MTC, No. 119 at p. 20)
Exelon commented that the proposed standards could exacerbate
supply chain constraints and drive more foreign transformer sourcing,
creating new grid reliability challenges and increasing consumer costs.
(Exelon, No. 95 at p. 4)
Cliffs commented that relying upon amorphous material represents a
national security threat because it is not readily available in the
U.S., cannot be manufactured using GOES production equipment, and
cannot supply the U.S. grid. (Cliffs, No. 105 at pp. 4-5)
Schneider commented that the production of ferroboron \89\ is
limited to
[[Page 29897]]
locations outside the U.S., which leads to long-term availability
concerns and, because of this, prior evaluations did not consider max-
tech. (Schneider, No. 92 at pp. 10-12) Cliffs added that the feedstock
to produce amorphous is foreign-sourced, all other major amorphous
producers are foreign, and amorphous is more labor intensive, making
the U.S. more dependent on foreign supply chains. (Cliffs, No. 105 at
p. 7) BCBC and BCGC expressed concern that DOE's proposal could be
detrimental to the resiliency of the United States electric grid
because amorphous is produced from imported, unproven, and foreign-
sourced materials that could compromise both energy and national
security in the United States. BCBC and BCGC recommended that DOE adopt
policies that increase domestic production of key materials and
components to strengthen national security and self-reliance. (BCBC,
No. 131 at p. 1; BCGC, No. 132 at p. 1) AISI commented that amorphous
cores requires foreign-sourced materials whereas GOES is able to be
produced with all stages using domestic manufacturing. (AISI, No. 115
at p. 2) \90\
---------------------------------------------------------------------------
\89\ Ferroboron is an input in amorphous production. It is
produced by a well-known reaction of iron with boron (as boric
acid). Both of these minerals are produced in the U.S., although
actual ferroboron production typically occurs outside the U.S.
\90\ U.S. Department of Commerce, The Effect of Imports of
Transformers and Transformer Components on the National Security.
(2020). Available at www.bis.doc.gov/index.php/documents/section-232-investigations/2790-redacted-goes-report-20210723-ab-redacted/file.
---------------------------------------------------------------------------
DOE notes that the current status quo for the distribution
transformer market involves a single domestic GOES manufacturer and
multiple global GOES suppliers, with any imported GOES subject to
tariffs. As a result, transformer manufacturers who produce transformer
cores domestically are largely reliant on the single domestic GOES
supplier, given that using GOES from any other supplier requires paying
a tariff. For amorphous, there is similarly a single domestic amorphous
manufacturer and multiple global suppliers. Meeting higher-efficiency
standards with amorphous would result in domestic transformer
manufacturers who produce transformer cores domestically being largely
reliant on the single domestic amorphous supplier, given that using
amorphous from any other supplier requires paying a tariff. This is
similar to the current market structure for GOES. Therefore, DOE
disagrees that a distribution transformer supply chain with substantial
amorphous cores is inherently more of a national security risk than the
existing GOES-based supply chain. The current distribution transformer
supply chain, as well as how the market is expected to respond to
amended standards, is further discussed in section IV.A.5 of this
document.
DOE considers the effect of DT standards on the domestic supply
chain in setting standards. However, DOE notes that a distribution
transformer market served by 100 percent domestically produced
electrical steel does not exist today. One transformer manufacturer
noted that having only a single-domestic supplier of GOES represents a
considerable supply risk. They further stated that developing the
workforce skills and manufacturing capabilities to leverage both GOES
and amorphous will reduce their electrical steel supply risk, provided
development of that capability does not disrupt existing product
output.\91\ Several stakeholders expressed concern that too rapid of a
transition to amorphous cores could worsen near-term supply chains and
recommended DOE wait for capacity to increase prior to implementing any
amended efficiency standards.
---------------------------------------------------------------------------
\91\ Markham, I., ERMCO CEO: For an Effective Outcome, Focus on
Inputs, The Wall Street Journal, Jan. 5, 2024. Available online at:
https://deloitte.wsj.com/riskandcompliance/ermco-ceo-for-an-effective-outcome-focus-on-inputs-3ecfbeff.
---------------------------------------------------------------------------
ABB stated that DOE should ensure that there is a sufficient and
competitive supply of GOES and amorphous before requiring significantly
higher energy conservation standards. (ABB, No. 107 at pp. 2-3) ABB
went on to state that the transformer industry is already experiencing
an insufficient domestic supply of GOES and expressed concern that the
same challenges would be faced with amorphous cores. (ABB, No. 107 at
pp. 2-3) NWPPA commented that manufacturers struggle to source the high
performing GOES required to meet current standards and the proposed
standards would require an even scarcer variety of steel for very small
gains in efficiency. (NWPPA, No. 104 at p. 1) NRECA commented that
DOE's proposal will not expand the market for distribution transformers
because most current production using GOES will not be able to meet the
proposed standards. (NRECA, No. 98 at p. 2)
WEG commented that amorphous cores will be the most cost effective
way to meet standards, but the supply chain for amorphous material is
not prepared to sustain the market or support the electrical grid.
(WEG, No. 92 at pp. 2-3) WEG stated that U.S. manufacturers would need
200,000 tons of amorphous to meet the proposed standards, which would
be 100 percent of global amorphous ribbon capacity just to support the
U.S. (WEG, No. 92 at pp. 2-3) WEG additionally commented that using
amorphous cores will require years of technical development and
industry won't be able to use GOES in the meantime. (WEG, No. 92 at pp.
2-3)
Cliffs commented that requiring amorphous cores would make the
transformer supply chain less secure and require considerable
investment from transformer manufacturers at a time of existing supply
chain and labor challenges. (Cliffs, No. 105 at p. 6) Cliffs commented
that only a single domestic manufacturer has the technical know-how to
produce amorphous ribbon and even if that manufacturer licensed the
technology, if efficiency standards require amorphous cores, the
manufacturer will effectively have a monopoly that will lead to
increased prices. (Cliffs, No. 105 at pp. 15-16)
UAW commented that the proposed standards may upend the
distribution transformer market by relying upon steel which is in short
supply and more expensive than the GOES currently used. (UAW, No. 90 at
p. 3)
Webb recommended that DOE confirm whether amorphous ribbon capacity
can be made available to meet both current GOES demand and increased
future demand due to distributed energy resource deployment. (Webb, No.
133 at p. 2)
Metglas commented that continued expansion of amorphous production
by other producers demonstrates that there are no IP-related
impediments to expanding use of amorphous transformers. (Metglas, No.
125 at pp. 3-4) Metglas commented that grades of GOES exist that can
meet the proposed DOE standards and suggested that GOES will continue
to serve a significant portion of U.S. demand for distribution
transformers, even in the presence of amended standards. (Metglas, No.
125 at pp. 3-4) Metglas went on to state that the proposed standards
will encourage competition for transformer core steel and help solidify
a majority domestic supply of transformer core steel. (Metglas, No. 125
at pp. 3-4)
The current domestic demand for electrical steel used in
distribution transformers is estimated to be approximately 225,000
metric tons, which is approximately equal to the global capacity for
amorphous material. The response to the April 2013 Standards Final Rule
demonstrated that amorphous material manufacturers are willing and
capable of adding capacity in response to increased demand (See Chapter
3A of the TSD). Metglas commented that between 2015 and 2018,
production of amorphous alloy in China increased by 50,000 metric tons.
(Metglas, No. 11 at pp. 3-4). Eaton commented that between 2013 and
[[Page 29898]]
2019, three additional companies entered the amorphous market with
similar product widths to the U.S. domestic producer of amorphous
(Eaton, No. 12 at p. 7)
If amended standards created an assured demand for amorphous
material, it can be reasonably expected that amorphous ribbon capacity
would increase to meet the demands of the U.S. distribution transformer
market. Given expected demand for amorphous ribbon, there are no
technical constraints preventing amorphous ribbon capacity from
increasing, eventually; however, there is uncertainty as to what time
frame that capacity would be sufficient to meet the demand created by
amended efficiency standards. Metglas commented that it currently has
an installed capacity of 45,000 metric tons available domestically and
stated that it can bring an additional 75,000 metric tons of production
online in less than 37 months, bringing total domestic capacity to
120,000 metric tons. Further, Metglas stated that it is willing to
invest beyond current facility location constraints to meet customer
demand. (Metglas, No. 125 at p. 8) In addition to statements from the
current domestic amorphous supplier and demonstrations of capacity
additions in other countries, recent patent filings from several major
steel producers indicate that the production of amorphous alloy is an
area of active technological innovation.92 93 94 95
---------------------------------------------------------------------------
\92\ VAC, Amorphous Material--VITROVAC, (Last Accessed 12/21/
2023), Available online at: https://vacuumschmelze.com/products/soft-magnetic-materials-and-stamped-parts/amorphous-material-vitrovac.
\93\ Hartman, T., Amorphous Metal Foil and Method for Producing
an Amorphous Metal Foil Using a Rapid Solidification Technology,
U.S. 0201914, 2023.
\94\ Guidebook for POSCO's amorphous metal, Docket No. EERE-
2010-BT-STD-0048-0235.
\95\ Nippon Steel Corp, Fe-Based Amorphous Alloy Having
Excellent Soft Magnetic Characteristics and Processability, Fe-Based
Amorphous Alloy Thin Strip Having Excellent Soft Magnetic
Characteristics and Processability, Wound Core, Stacked Core and
Rotary Electric Machine, JP20231017731A, 2023.
---------------------------------------------------------------------------
If all distribution transformers had to transition to amorphous
cores immediately, stakeholders stated that the capacity and core-
construction infrastructure would not exist and there would be
considerable price increases which would very likely worsen supply
chains and have negative cost impacts for consumers, at least until
supply could catch up with demand. However, comments from stakeholders
indicate that longer transition times could allow distribution
transformer manufacturers to more gradually transition to amorphous
cores, mitigating supply chain concerns. DOE received several comments
from stakeholders as to what they believe would be a reasonable
timeframe and scope to allow for a gradual transition to higher-
efficiency without significantly impacting near term pricing. These
comments are discussed in section IV.C.2.a of this document.
As discussed, for efficiency levels up through EL2 for liquid-
immersed distribution transformers, both amorphous and GOES
transformers are anticipated to be able to compete on first cost. While
stakeholders expressed concern that amorphous would not be able to
scale up sufficiently to serve the entire distribution transformer
market, DOE estimates that approximately 48,000 metric tons of
amorphous will be used to meet the amended standards for liquid-
immersed distribution transformers. While this is a considerable
increase from the amount of amorphous used in distribution transformer
cores today, it is approximately equal to the current stated amorphous
capacity (of approximately 45,000 metric tons). Meaning, even if the
amorphous core market were to be entirely served by domestic
manufacturing, no additional amorphous manufacturers were to enter the
market, and the current domestic manufacturer were to add no production
capacity, amorphous capacity would still be approximately sufficient to
serve the distribution transformer market.
b. Grain-Oriented Electrical Steel Market and Technology
GOES is a variety of electrical steel that is processed with tight
control over its crystal orientation such that its magnetic flux
density is increased in the direction of the grain orientation. The
single-directional flow is well suited for distribution transformer
applications and GOES is the dominant technology in the manufacturing
of distribution transformer cores. GOES is produced in a variety of
thicknesses and with a variety of loss characteristics and magnetic
saturation levels. In certain cases, steel manufacturers may further
enhance the performance of electrical steel by introducing local strain
on the surface of the steel through a process known as domain
refinement, such that core losses are reduced. This can be done via
several methods, some of which survive the distribution transformer
core annealing process.
In the January 2023 NOPR, DOE maintained the four subcategories of
GOES that it had identified in the August 2021 Preliminary Analysis as
possible technology options. 87 FR 1722. 1756. These technology options
and their DOE abbreviations are shown in Table IV.5.
[GRAPHIC] [TIFF OMITTED] TR22AP24.532
DOE noted in the January 2023 NOPR that for high-permeability
steels, steel manufacturers have largely adopted a naming convention
that includes the steel's thickness, a brand-specific designator,
followed by the guaranteed core loss of that steel in W/kg at 1.7 Tesla
(T) and 50 Hz. Id. Power in the U.S. is delivered at 60 Hz and the flux
[[Page 29899]]
density can vary based on distribution transformer design, therefore
the core losses reported in the steel name are not identical to their
performance in the distribution transformer. However, the naming
convention is generally a good indicator of the relative performance of
different steels.
In the January 2023 NOPR, DOE discussed how different grades of
GOES, and in particular hib and dr GOES, are typically marketed as
suitable for use in either power or distribution transformers. Id.
However, DOE also noted that power transformers tend to have priority
over distribution transformers and generally receive the highest
performing grades of GOES, as stated by stakeholders in public comment.
(Schneider, No. 49 at p. 14; Cliffs, No. 57 at p. 1) The larger volume
of the liquid-immersed distribution transformer market similarly tends
to be served before the dry-type distribution transformer market. Id.
In response to the August 2021 Preliminary Analysis TSD, DOE
received comment from stakeholders that the GOES steel supply had
become more constrained in recent years. Stakeholders commented that
certain grades of steel are becoming more difficult to acquire and
costs have increased for all grades of steel. 87 FR 1722, 1756. In the
January 2023 NOPR, DOE noted that the combined effect of general
commodity related supply chain issues and competition from the EV
market likely contributed to these recent supply issues and cost
increases. Id. In response to stakeholder feedback, DOE proposed
screening out some of the highest performing grades of GOES, where
steel manufacturers are not able to mass produce GOES of similar
quality. Id. In this final rule, DOE continued to screen out these
steel grades, as discussed in section IV.B of this document. Further,
DOE also updated all material costs in this final rule to account for
recent trends in market prices, as discussed in section IV.C.2 of this
document.
In response to the January 2023 NOPR, DOE received additional
comments regarding the supply and availability of GOES.
NEMA commented that GOES with better performance than M3 is
typically not available from domestic suppliers. (NEMA, No. 141 at p.
14) WEG commented that there are global shortages of high-grade GOES
today. (WEG, No. 92 at p. 1) Prolec GE commented that GOES supplies
have been constrained by worldwide increase in demand for GOES coupled
with shifting production capacity to non-oriented electrical steel
(NOES). (Prolec GE, No. 120 at p. 10) Howard commented that the GOES
market has been severely impacted by NOES demand spikes. (Howard, No.
116 at p. 23) Metglas commented that there is currently a shortage of
GOES due to a combination of factors, including competition from NOES
and thinner gauge requirements for EVs reducing steel mill output
capacity. (Metglas, No. 125 at p. 5)
MTC provided US import and consumption data for GOES and commented
that U.S. consumption of GOES for distribution transformers is
approximately 175K MT. (MTC, No. 119 at p. 2) MTC additionally
commented that Cliffs is not currently able to meet demand requirements
for GOES in the U.S. (MTC, No. 119 at p. 2) MTC added that lack of a
secure domestic steel supply is an issue of national security which
should be referred to the Department of Commerce for remedies. (MTC,
No. 119 at p. 20) Efficiency Advocates commented that the current
domestic GOES supply is insufficient to meet market demands and
additional suppliers of GOES are unlikely to form due to long lead
times and significant capital requirements. Efficiency Advocates
further commented that higher grades of GOES are not available in large
quantities domestically. (Efficiency Advocates, No. 121 at pp. 2-3)
Pugh Consulting commented that the single supplier of GOES has not
indicated that they will increase production to meet demand and it is
unclear whether a new manufacturer could obtain a Title V Clean Air Act
permit. (Pugh Consulting, No. 117 at p. 3) DOE notes that Title V of
the Clean Air Act requires facilities that are major sources of air
pollutants to obtain operating permits, which specify permissible
limits of pollutant emissions. However, Title V permitting for steel
manufacturers is beyond the scope of this rulemaking.
Hammond commented that it expects the market to provide an adequate
supply of both NOES and GOES for the foreseeable future. (Hammond, No.
142 at p. 2) Schneider commented that the supply and demand of GOES is
well balanced today, GOES capacity will gradually increase over time,
and they do not expect manufacturers to shift production of GOES to
NOES because steel manufacturers recognize the role of GOES.
(Schneider, No. 101 at p. 9)
Cliffs commented that it recently invested $40M to expand domestic
electrical steel production (both GOES and NOES) and aims to invest
more in the near future to keep up with demand. (Cliffs, No. 105 at p.
15)
NAHB commented that GOES is harder and more costly to produce than
NOES because it requires additional processing steps. NAHB pointed out
that a new domestic electrical steel facility, which opened in 2023,
elected to produce NOES rather than GOES, which may indicate other
domestic steel producers are unlikely to add GOES production lines.
(NAHB, No. 106 at pp. 9-10)
Stakeholder comments submitted in response to the January 2023 NOPR
further confirm that the current GOES market is experiencing supply
constraints, inhibiting the ability of manufacturers to obtain the full
range of core steel grades. DOE notes that this appears to be
especially true for the domestic steel market, which stakeholders have
stated does not have a sufficient quantity of low-loss steels to serve
the needs of U.S. distribution transformer market.\96\ Although the
sole domestic producer of GOES is capable of producing a full range of
M-grades and some hi-b steels, the supply of dr steels is more
constrained and there is currently no domestic production of pdr GOES.
Further, as previously noted, distribution transformer manufacturers
compete for GOES with power transformer manufacturers, with many of the
highest performing grades dedicated to power transformer production
over distribution transformer production.
---------------------------------------------------------------------------
\96\ See also Department of Commerce investigation into imports
of laminations and wound cores for incorporation into transformers.
Docket No. BIS-2020-0015. Available at www.regulations.gov/docket/BIS-2020-0015.
---------------------------------------------------------------------------
This leaves a limited supply of the lowest-loss grades of GOES for
distribution transformer manufacturers. Since 2018, all raw imported
electrical steel has also been subject to a 25 percent ad valorem
tariff.\97\ Therefore, manufacturers are forced to choose between
sourcing from the single domestic provider of GOES or paying more for
imported product. The result of these myriad factors is a strained GOES
supply for distribution transformer production.
---------------------------------------------------------------------------
\97\ See 83 FR 11625.
---------------------------------------------------------------------------
DOE also received comments regarding how the proposed standards
might impact the GOES market.
Pugh Consulting suggested DOE should explore options to incentivize
the domestic production of amorphous and GOES steel for distribution
transformers, such as funding authorized by Congress, tax credits, and
use of the Defense Production Act. (Pugh Consulting, No. 117 at p. 7)
DOE notes that this final rule pertains only to energy conservation
standards for
[[Page 29900]]
distribution transformers, and any efforts to amend other Federal
regulatory programs and policies are beyond the scope of this
rulemaking. However, separate agency actions may promote production of
domestic amorphous and GOES including the Advanced Energy Project
Credit (48C) Program in partnership with the Department of the Treasury
and the Internal Revenue Service.\98\
---------------------------------------------------------------------------
\98\ See https://www.energy.gov/infrastructure/qualifying-advanced-energy-project-credit-48c-program.
---------------------------------------------------------------------------
CARES commented that there is insufficient supply of either GOES or
amorphous to meet the demand required by the proposed standards.
(CARES, No. 99 at p. 3)
Cliffs commented that the proposed standards are contrary to
established Federal policies that have designated GOES a critical
product essential to U.S. national security interests. (Cliffs, No. 105
at pp. 2, 5-6) Specifically, Cliffs commented that the proposed
standards are counter to the 232 report which concluded that
maintaining domestic GOES capacity is crucial to national security and
that domestic steel producers must have viable markets beyond solely
the defense industry. (Cliffs, No. 105 at pp. 4-5) Cliffs stated that
the proposed standards would negate any benefits currently being
realized by the 25 percent 232 tariffs, which undermines the entire
purpose of the tariffs. (Cliffs, No. 105 at pp. 3-5)
Cliffs further commented that the majority of domestic GOES is
manufactured for use in distribution transformers and the NOPR makes
production of both GOES and NOES economically untenable, risking 1500
jobs and undermining the supply chain for transformers, electric
motors, and other industries. (Cliffs, No. 105 at p. 6) Cliffs
additionally noted that: (1) GOES is needed for bulk power
infrastructure, (2) several Federal reports have recommended
establishing a stockpile of domestic GOES, and (3) the Cybersecurity
and Infrastructure Security Agency has stated that large-power
transformers are overly reliant on foreign imports, all of which
further demonstrate the importance of domestic GOES manufacturing for
national security. (Cliffs, No. 105 at pp. 7-8) DOE notes that large-
power transformers are not subject to energy conservation standards.
Several stakeholders suggested that producers of electrical steel
would discontinue production of GOES without demand for distribution
transformers, eliminating the domestic supply of electrical steel and
causing layoffs of approximately 1500 employees. (UAW, No. 90 at p. 1;
UAW Locals, No. 91 at p. 1; BCBC, No. 131 at p. 1; BCGC, No. 132 at p.
1) Stakeholders stated that this would eliminate the supply of
electrical steel for other industries, such as EV motors, and make the
U.S. entirely reliant on foreign entities to support the grid. Id. BCBC
and BCGC added that the Butler Works electrical steel plant supports
Butler County and any loss will have an exponential and devastating
impact well beyond the plant itself. (BCBC, No. 131 at p. 1; BCGC, No.
132 at p. 1) UAW Locals and BCBC and BCGC recommended that DOE either
withdraw the NOPR or proceed with an efficiency standard that ensures
continued use of GOES in distribution transformers. (UAW Locals, No. 91
at p. 2; BCBC, No. 131 at p. 1; BCGC, No. 132 at p. 1)
A number of stakeholders similarly submitted comments expressing
concern that the proposed rulemaking would weaken domestic supply
chains and jeopardize U.S. jobs by making the U.S. more reliant on
foreign amorphous suppliers and suggested DOE should ensure GOES can
continue to be used in distribution transformers. (Thomas, No. 155 at
p. 1-2; Pennsylvania AFL-CIO, No. 156 at p. 1-2; BCCC, No. 158 at p. 1-
2; Renick Brothers Co., No. 160 at p. 1; Snyder Companies, No. 161 at
p. 1; Nelson, No. 157 at p. 1)
Other stakeholders similarly expressed concern that the proposed
standards may lead the single domestic producer of GOES to either
reduce or discontinue production, which could hurt transformer supply
chains and make transformer manufacturers more reliant on foreign steel
importers. (Michigan Members of Congress, No. 152 at p. 1; HVOLT, No.
134 at p. 7; AISI, No. 115 at pp. 2-3; Alliant Energy, No. 128 at p. 3;
Kansas Congress Member, No. 143 at p. 1; Entergy, No. 114 at p. 2)
Eaton commented that DOE should consider the possibility of
domestic GOES manufacturing disappearing in response to standards,
leaving other critical resources like power transformers without a
stable supply chain. (Eaton, No. 137 at p. 26) TMMA commented that the
domestic GOES producer is not planning to invest in producing premium
GOES grades and, therefore, U.S. transformer manufacturers will need to
use foreign-produced GOES which isn't available in sufficient capacity
to support the U.S. transformer market. (TMMA, No. 138 at pp. 3-4) MTC
commented that the proposed standards will increase the cost of GOES
production, potentially jeopardizing refurbishment, resilience, and
upgrading of the grid. (MTC, No. 119 at p. 19) NEMA commented that the
administration has sought to increase domestic manufacturing and this
rule creates a dangerous imbalance of core steel supply. (NEMA, No. 141
at p. 2) NAHB commented that declining imports of both finished
transformers and GOES in recent years, paired with a lack of domestic
competition for GOES production, have exacerbated the transformer
crisis and expressed concern that the NOPR will worsen these issues.
(NAHB, No. 106 at pp. 6-8)
In the January 2023 NOPR, DOE discussed how GOES production can be
shifted to NOES production at only a modest cost. 88 FR 1722, 1767.
Stakeholders have commented that this transition is already occurring
and has partially contributed to the GOES shortages experienced by the
transformer industry. Id. The shift towards NOES production is largely
driven by electrification trends and increased production of EV motors,
creating an assured demand for NOES well into the future. As such,
manufacturers of GOES in the current market may have the option of
converting GOES production lines to NOES capacity in the event that
demand for GOES decreases.
While Cliffs indicated in its comment that GOES production is used
to support NOES production, DOE notes that in 2023 an additional
domestic NOES production facility opened without GOES production.\99\
This indicates that a NOES production facility is a reasonable
investment on its own.
---------------------------------------------------------------------------
\99\ U.S. Steel, Big River Steel Overview. Available at
www.ussteel.com/bigriversteeloverview (last accessed Nov. 8, 2023).
---------------------------------------------------------------------------
DOE also notes that other markets for GOES exist. For example, the
power transformer market also acts as an end-use for domestically
produced GOES. Although this market is smaller than the distribution
transformer market by volume, with total demand for medium and large
power transformers estimated to be over 2,700 units per year,
individual units can weigh several hundred tons, contributing a
significant source of demand for GOES. 86 FR 64606, 64662. Increased
electrification likely means that the demand for large-power
transformers, and therefore demand for GOES in large-power
transformers, will continue to increase. Given the assured demand for
GOES from the power transformer industry and the available option to
convert capacity to NOES, along with the fact that a second domestic
NOES production facility recently began
[[Page 29901]]
production, it is unlikely that domestic electrical steel production
would entirely disappear because of amended efficiency standards.
However, lead times for distribution transformers have
significantly increased in recent years and could be exacerbated by a
wholesale transition to amorphous cores at this time. Further, the vast
majority of domestic GOES production is used in distribution
transformers, and while alternative uses for that capital equipment may
exist, preemptive conversion of that capital in anticipation of
disappearing demand could exacerbate near-term transformer shortages.
In an effort to minimize this risk, DOE has evaluated an additional TSL
in which certain segments of the distribution transformer market remain
at efficiency levels that can be met cost-competitively via GOES, as
discussed in section V.A. DOE has also, in response to stakeholder
feedback, modified its consumer purchasing behavior model to reflect
the emphasis that both manufacturers and utilities are placing on lead
time, wherein consumers continue to purchase a GOES transformer even if
an amorphous transformer is lower cost up to a certain efficiency
level, as discussed in section IV.F.3 of this document.
Finally, the standards finalized in this final rule include several
equipment classes, representing considerable volume of core material,
where GOES is expected to remain cost-competitive. DOE estimates the
volume of core steel used in the equipment classes where GOES is
expected to remain cost-competitive to be over ~146,000 metric tons for
liquid-immersed distribution transformers, only a 21 percent reduction
from the ~185,000 metric tons for liquid-immersed distribution
transformers assumed in the no-new standards case. DOE also understands
that manufacturers prefer to continue using existing GOES core
production equipment, rather than replace GOES core production
equipment with amorphous core production equipment., Accordingly, DOE
expects that, for those classes where GOES remains cost-competitive,
manufacturers will continue purchasing GOES steel, and will do so in
quantities approximately equal to the existing domestic GOES market.
Therefore, DOE does not expect a significant decrease in domestic GOES
sales as a result of this rule.
DOE notes that core production equipment is somewhat flexible to
manufacturer a variety of core sizes. As such, if an existing piece of
GOES core production equipment manufactures cores for 75 kVA, 100 kVA
and 167 kVA, as an example, manufacturers can meet efficiency standards
by shifting that equipment to increase 75 kVA and 100 kVA GOES cores
and adding a new amorphous core production machinery to manufacture 167
kVA transformers. The resulting set-up results in an increase in total
transformer core production capacity as the amorphous line is invested
in as an additive equipment line, as opposed to replacing existing GOES
production equipment.
c. Transformer Core Production Dynamics
In the January 2023 NOPR, DOE discussed how transformer
manufacturers have the option of either making or purchasing
transformer cores, with some manufacturers choosing to do a mix of the
two. 88 FR 1722, 1757. DOE further stated that transformer
manufacturers also have the choice of producing cores domestically or
producing them in a foreign country and importing them into the U.S.
This creates three unique pathways for producing distribution
transformers: (1) producing both the distribution transformer core and
finished transformer domestically; (2) producing the distribution
transformer core and finished transformer in a foreign country and
importing into the United States; (3) purchasing distribution
transformer cores and producing only the finished transformer
domestically. Id.
DOE discussed how each of these unique sourcing pathways has their
own advantages and disadvantages. Manufacturers who produce cores
domestically may have the most control over their lead times and supply
chains but may be more limited in selection of steel grades as a result
of tariffs on foreign-produced GOES and only having access to one
domestic manufacturer. Producing cores in a foreign country and
importing into the U.S., on the other hand, allows for the same in-
house production with access to the entire global market for GOES
without the tariff on electrical steel, but provides less supply chain
control and may lead to longer lead times. Finally, purchasing finished
cores directly allows manufacturers to avoid investing in the labor and
capital equipment required for core production, but provides the least
control over delivery lead times and often will result in a higher cost
per pound of steel when compared to manufacturers producing their own
cores. Id.
In the January 2023 NOPR, DOE assumed that, in the presence of
amended standards, manufacturers would maintain the same core
production practices that they currently employ. 88 FR 1722, 1757-1758.
For manufacturers that produce their own cores, this would mean
investing in their in-house production processes and purchasing
additional capital equipment, as required, in order to produce cores
from higher grades of steel. For manufacturers that purchase finished
cores, this would mean switching from purchasing cores of one steel
grade to purchasing cores of a higher steel grade. Further, DOE stated
that it did not view any one of these core and transformer production
processes as becoming more advantaged or disadvantaged through amended
standards and requested comment on whether the proposed standards would
alter any of the current production pathways. Id.
A Kansas Congress Member recommended that DOE consider the
immediate economic impacts that new standards may have on domestic
steel and transformer manufacturers, energy providers, and developers.
(Kansas Congress Member, No. 143 at p. 1)
Schneider commented that the 2016 standards caused many companies
to shift from slitting steels to outsourcing core production. Schneider
stated the proposed standards could potentially impact U.S. labor by
further pushing core assembly to foreign suppliers. (Schneider, No. 92
at p. 10)
NEMA commented that GOES cores are both manufactured in-house and
purchased from third party sources, but stated that distribution
transformer manufacturers do not have the ability to produce amorphous
cores internally. (NEMA, No. 141 at pp. 2-3) NEMA stated that the
proposed standards would force manufacturers to either purchase
transformer cores, weakening the supply chain, or make substantial
investments in new capital. Id. NEMA added that there is only a single
domestic company manufacturing amorphous cores and due to large capital
costs, new capacity is unlikely to increase in the foreseeable future
without Federal funding to expand domestic amorphous core
manufacturing. (NEMA, No. 141 at pp. 2-3) NEMA further stated that the
capital expenses needed for amorphous cores are likely to increase
outsourcing of core manufacturing, potentially shifting jobs overseas
and giving a monopolistic hold to the sole domestic manufacturer of
amorphous cores. (NEMA, No. 141 at pp. 16-17) DOE notes that multiple
domestic manufacturers have in-house amorphous core production
capacity, although typically in substantially lesser volume than GOES
core production. Substantial capital investments would
[[Page 29902]]
be needed to add amorphous core production capacity. DOE has accounted
for these capital investments in its MIA as discussed in section IV.J.
Howard commented that any regulation favoring GOES or amorphous
will result in single source availability of core steel and encourage
core offshoring, as tariffs have already done. (Howard, No. 116 at p.
18)
MTC expressed concern that the more labor intensive production
process for amorphous metal cores will push core production outside the
U.S. (MTC, No. 119 at p. 19)
The SBA commented that DOE must consider statutory factors
including ``the impact of any lessening of competition.'' The SBA went
on to state that there is only one domestic manufacturer of transformer
cores which is already unable to keep up with demand. (SBA, No. 100 at
p. 5) DOE notes that there are multiple domestic producers of
distribution transformers, many of whom also produce cores domestically
as detailed in Chapter 3 of the TSD.
Alliant Energy commented that it prefers to procure transformers
domestically to protect grid security, expressing concern that there is
currently only one U.S. producer of amorphous core steel with limited
capacity. (Alliant Energy, No. 128 at pp. 2-3) DOE notes that most
distribution transformers are produced domestically; however, depending
on distribution transformer core production dynamics, the core steel in
those products may or may not be produced domestically. As discussed in
section IV.A.4.a of this document, both the amorphous and GOES market
have one domestic producer and multiple global producers with capacity
largely reflecting current demand.
Metglas stated that it does not control amorphous core costs, but
an increased number of amorphous core makers should promote competition
and drive down costs. (Metglas, No. 125 at p. 6)
DOE notes that while some stakeholders speculated efficiency
standards where amorphous cores were most cost competitive would change
core production dynamics, manufacturer's early responses in
anticipation of a final rule suggest that a similar core production
dynamic will exist (see chapter 3 of the TSD for additional details).
DOE notes that distribution transformer manufacturers have already
invested in additive facilities to produce amorphous cores domestically
(and are already producing them).\100\ DOE also notes that core
manufactures have stated that they are planning on adding new
facilities to produce amorphous cores in Canada and sell them to
transformer manufacturers.\101\
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\100\ Howard, T. Howard Industries cuts ribbon on Quitman plant,
The Meridian Star, 2023. Available at www.meridianstar.com/news/howard-industries-cuts-ribbon-on-quitman-plant/article_022f5248-7a7e-11ee-91f9-873895c690d6.html.
\101\ Worthington Steel, Investor Day. Transcript. Available at
s201.q4cdn.com/849745219/files/doc_events/2023/Oct/17/worthington-steel-investor-day-transcript-final-10-11-23.pdf.
---------------------------------------------------------------------------
DOE additionally notes that the adopted standards will maintain
cost-competitive market segments for both GOES and amorphous.
Therefore, manufacturers producing their own cores today can continue
to utilize existing core production equipment.
Further, distribution transformer manufacturers are already
investing in manufacturing expansions to support increased capacity
demands on the electrical grid. In the past several years,
manufacturers across the distribution transformer market have announced
expansions of current capacity and intentions expand (some of these
announced capacity expansions are discussed in chapter 3 of the TSD).
As such, even without amended standards, manufacturers currently
producing their own cores would need to invest in additional core
production equipment to support these capacity additions or make
alternative core procurement decisions. Therefore, manufacturers will
have the option to add amorphous production capacity as part of these
planned expansions in an additive fashion to meet increased demand,
rather than adding amorphous production capacity to replace existing
GOES capacity. This will further reduce the capital expenditures that
manufacturers would be required to incur to meet amended standards,
mitigating the risk that outsourcing of cores will increase.
Therefore, for the reasons discussed, DOE continued to assume in
this final rule that all three core and transformer production pathways
will remain viable options in the presence of amended standards, with
manufacturers expected to maintain their current production practices.
5. Distribution Transformer Supply Chain
The distribution transformer market is divided into three
segments--liquid-immersed, low-voltage dry-type, and medium-voltage
dry-type--each of which has unique market dynamics and production
practices. In recent years, the distribution transformer market has
experienced significant supply chain challenges across all three
segments of the market that have largely been attributed to demand for
distribution transformers, along with other electric grid related
equipment, increasing substantially. As result, lead times for
transformers have increased and utility companies' transformer
inventories have been reduced.
DOE notes that current shortages in the distribution transformer
market are unrelated to efficiency standards. Current distribution
transformer shortages are instead related to a significant increase in
demand for many electric grid related products, which includes not only
distribution transformers but many other products associated with
expansion of the electrical grid not subject to any efficiency
standards. Distribution transformer manufacturers have reported record
production, in terms of number of shipments, but still noted that
demand has grown even faster.\102\
---------------------------------------------------------------------------
\102\ TB&P, Electric Coops CEO wrestles with ever-evolving
factors to maintain reliability, affordability, Jan. 15, 2023.
Available online at: https://talkbusiness.net/2023/01/electric-coops-ceo-wrestles-with-ever-evolving-factors-to-maintain-reliability-affordability/.
---------------------------------------------------------------------------
PSE commented that lead times for distribution voltage regulators
are even longer than for distribution transformers and this is unlikely
to improve if electrical steelmakers are forced to shift to amorphous.
(PSE, No. 98 at p. 11) DOE notes that voltage regulators are not
subject to energy conservation standards but serve as an example of how
product shortages are associated with many electric grid related
products.
While numerous expansions of distribution transformer production
plants have been announced, as discussed in Chapter 3 of the TSD, it
takes time for those capacity expansions to come online. DOE notes that
its proposed standards have considered the interaction between capacity
expansions and conversion investment costs to meet the amended
efficiency standards. Specifically, DOE adopted standards wherein
manufacturers can choose to comply using either GOES or amorphous for
the vast majority of shipments and significantly limited the shipments
that can realistically only be met with amorphous cores. Stakeholders
have noted that the ability to leverage both GOES and amorphous will
reduce their electrical steel supply risk, provided development of that
capability does not disrupt existing product output.\103\
---------------------------------------------------------------------------
\103\ Markham, I., ERMCO CEO: For an Effective Outcome, Focus on
Inputs, The Wall Street Journal, Jan. 5, 2024. Available online at:
https://deloitte.wsj.com/riskandcompliance/ermco-ceo-for-an-effective-outcome-focus-on-inputs-3ecfbeff.
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[[Page 29903]]
In response to the January 2023 NOPR, DOE received comments on the
current state of the distribution transformer market.
A variety of utility companies, trade associations, and other
stakeholders commented that increased demand has led to nationwide
distribution transformer shortages, with utility reserve stocks
significantly reduced and lead times on the scale of 2 to 4 years.
(APPA, No. 103 at p. 4; TMMA, No. 138 at p. 2; Indiana Electric Co-Ops,
No. 81 at p. 1; Fall River, No. 83 at p. 2; Central Lincoln, No. 85 at
p. 1; NRECA, No. 98 at p. 2; EEI, No. 135 at pp. 6-7, 9-10; Pugh
Consulting, No. 117 at p. 3; NWPPA, No. 104 at p. 1-2; Entergy, No. 114
at p. 2; REC, No. 126 at p. 1-2; Xcel Energy, No. 127 at p. 1; Alliant
Energy, No. 128 at p. 2; NMHC & NAA, No. 97 at p. 3; Portland General
Electric, No. 130 at pp. 2-3; Webb, No. 133 at p. 1) Accordingly, many
stakeholders advised against amending efficiency standards due to
concerns that standards would further exacerbate supply chain
challenges, increase the cost of transformers, delay transformer
deliveries, and introduce additional strain on the electrical grid.
(BIAW, No. 94 at p. 1; TMMA, No. 138 at p. 2; Entergy, No. 114 at p. 2;
Alliant Energy, No. 128 at p. 1; Idaho Falls Power, No. 77 at pp. 1-2;
Fall River, No. 83 at p. 1; Joint Associates, No. 68 at p. 2; Central
Lincoln, No. 85 at p. 1; Chamber of Commerce, No. 88 at p. 3; NRECA,
No. 98 at pp. 2-3; SBA, No. 100 at p. 5; Pugh Consulting, No. 117 at
pp. 2-3; HVOLT, No. 134 at p. 6; Exelon, No. 95 at pp. 1-2; REC, No.
126 at pp. 1-3; Idaho Power, No. 139 at pp. 3, 6; Portland General
Electric, No. 130 at pp. 1, 4-5; Indiana Electric Co-Ops, No. 81 at p.
1; NEPPA, No. 129 at p. 3; WEC, No. 118 at p. 3; TVPPA, No. 144 at p.
2; AISI, No. 115 at pp. 2-3; TVPPA, No. 144 at p. 1-2; NAHB, No. 106 at
p. 4; CARES, No. 99 at p. 5; APPA, No. 103 at p. 2; Webb, No. 133 at p.
2; Allen-Batchelor Construction, No. 79 at p. 1; EEI, No. 135 at p. 1)
NRECA urged DOE to not amend standards and instead focus on other means
to incentivize amorphous cores without jeopardizing electric
reliability. (NRECA, No. 98 at p. 8)
Many elected officials submitted comments describing how their
local jurisdictions have been impacted by the national shortage of
distribution transformers, expressing concern that the proposed
standards could worsen the impacts of this shortage. (New York Members
of Congress, No. 153 at p. 1; Kansas Congress Member, No. 143 at p. 1;
Alabama Senator, No. 113 at p. 1; VA, MD, and DE Members of Congress,
No. 148 at p. 1; Texas Congress Member, No. 149 at p. 1; Florida
Members of Congress, No. 150 at pp. 1-2; South Dakota Congress Member,
No. 145 at p. 1)
EEI attached a joint response to DOE's RFI on the Defense
Production Act (87 FR 61306) reiterating a request that DOE dedicate
funding to provide financial support to transformer manufacturers and
producers of electrical steel. In that request, EEI stated that the
primary challenges for transformer manufacturers include attracting and
retaining a strong workforce and uncertainty of whether demand will
continue to grow. (EEI, No. 135 at pp. 32-43)
DOE notes that this final rule pertains only to energy conservation
standards for distribution transformers, and any efforts to amend other
Federal regulatory programs and policies are beyond the scope of this
rulemaking.
Several stakeholders specifically recommended that DOE abandon the
proposed standard and instead issue a temporary waiver of the existing
standards to allow more ubiquitous steel components to be used in the
manufacturing process to increase transformer supplies. (NEPPA, No. 129
at p. 3; NWPPA, No. 104 at p. 2; TVPPA, No. 144 at p. 2; CARES, No. 99
at pp. 2-3)
As discussed, DOE has made modifications to its distribution
transformer purchasing model to reflect the current challenges
associated with the distribution transformer supply chain as discussed
in section IV.F.3 of this document.
Pugh Consulting commented that the proposed rule will reduce
competition for electric utilities, distribution transformer
manufacturers, and home building construction companies. (Pugh
Consulting, No. 117 at p. 4) DOE notes that its adopted standard allows
for a diversity of core materials to be used and allows for
manufacturers to largely maintain existing production equipment.
Therefore, DOE does not anticipate reduced competition in the
distribution transformer market. This conclusion is consistent with the
assessment of the Attorney General as detailed in the letter published
at the end of this final rule.
Separately, DOE also received feedback that distribution
transformer shortages are delaying building projects, negatively
impacting the housing market and impeding the availability of
affordable housing in the U.S. (NAHB, No. 106 at p. 2; APPA, No. 103 at
p. 5; Fall River, No. 83 at p. 1; Cleveland, No. 80 at p. 1; Ivey
Residential, No. 82 at p. 1; BIAW, No. 94 at p. 1; Pugh Consulting, No.
117 at p. 4; NMHC & NAA, No. 97 at p. 1, Williams Development Partners,
No. 84 at p. 1, Kansas Congress Member, No. 143 at p. 1; Allen-
Batchelor Construction, No. 79 at p. 1; Alliant Energy, No. 128 at pp.
4-6) Several stakeholders also noted that the shortage of transformers
is limiting the ability of utilities to interconnect new customers
across the country, thereby impeding economic development in other
sectors. (Alliant Energy, No. 128 at p. 2; EEI, No. 135 at pp. 10-11)
Several stakeholders specifically commented that the shortage of
distribution transformers is delaying the construction of new housing
developments which increases costs for homebuyers and, in some cases,
may cause them to lose their rate lock on mortgage interest rates.
(BIAW, No. 94 at p. 1; NAHB, No. 106 at pp. 4-5; NMHC & NAA, No. 97 at
pp. 1-4; LBA, No. 108 at pp. 1-3)
Stakeholder comments demonstrate how distribution transformers play
an integral role in the electrical grid, and how the impact that a
shortage of transformers can have across industry and especially in
certain infrastructure-oriented segments such as the housing market.
DOE notes that the transformer industry is actively responding to
current shortages of distribution transformers, with multiple major
suppliers having announced capacity expansions in recent months and
years (as discussed in chapter 3 of the TSD). While additional capacity
takes time to build and the effects will not be immediately felt by the
broader distribution transformer market, once online, these capacity
expansions should help alleviate some of the current supply challenges.
DOE notes that, historically, amended efficiency standards have not
significantly increased transformer lead times, and current transformer
shortages began occurring long after the most recent energy
conservation standards went into effect. This is demonstrated by the
producer price index time series data for the electric power and
specialty transformer industry, which shows relatively steady pricing
from 2010 to 2020 followed by significant price increases starting in
2021.\104\ However, DOE acknowledges that if investments in conversion
costs compete with needed investments in capacity expansions, lead
times for distribution
[[Page 29904]]
transformers could increase. At the same time, investment in new
amorphous production equipment could allow for higher efficiency
standards for specific equipment classes, while shifting existing
production equipment to increase production of other equipment classes,
thereby increasing total capacity to produce distribution transformers.
DOE has considered the impact that amended standards could have on
distribution transformers costs in section IV.C.2 of this document.
---------------------------------------------------------------------------
\104\ U.S. Bureau of Labor Statistics, Producer Price Index by
Industry: PPI industry data for Electric power and specialty
transformer mfg, not seasonally adjusted., Available online at:
https://www.bls.gov/ppi/databases/ (retrieved on 03/17/2024).
---------------------------------------------------------------------------
Several stakeholders specifically expressed concern that shortages
of distribution transformers will reduce grid reliability, potentially
impeding the ability of utilities to restore power following natural
disasters and in emergency situations. (EEI, No. 135 at pp. 16-17, 28-
29; Michigan Members of Congress, No. 152 at p. 1; Alliant Energy, No.
128 at p. 2; Portland General Electric, No. 130 at pp. 4-5, Pugh
Consulting, No. 117 at p. 6; Florida Members of Congress, No. 150 at
pp. 1-2; Entergy, No. 114 at p. 3; APPA, No. 103 at p. 12; Exelon, No.
95 at p. 3)
Other stakeholders commented that transformer shortages are
negatively impacting grid resilience and modernization, and recommended
that DOE prioritize restoring a steady supply of distribution
transformers, which would facilitate electrification efforts. (Chamber
of Commerce, No. 88 at p. 3; CARES, No. 99 at p. 2; EEI, No. 135 at pp.
4-5; Pugh Consulting, No. 117 at p. 7; Exelon, No. 95 at p. 4; Xcel
Energy, No. 127 at p. 1; Alliant Energy, No. 128 at p. 3; Alliant
Energy, No. 128 at p. 4; NMHC & NAA, No. 97 at p. 3; Ivey Residential,
No. 82 at p. 1; NWPPA, No. 104 at pp. 1-2; New York House
Representatives, No. 153 at p. 1; Michigan Members of Congress, No. 152
at p. 1; Florida Members of Congress, No. 150 at p. 1)
Portland General Electric commented that it has made changes to
reduce the impact of shortages on its customers, such as delaying non-
critical, non-customer jobs and exploring new sources, including
offshore manufacturers, for refurbished transformers. (Portland General
Electric, No. 130 at p. 3) Similarly, WEC commented that it has taken
drastic steps to address the transformer shortages, and any additional
supply chain issues will further limit the company's ability to support
Federal and State grid resiliency initiatives, such as storm hardening
and increasing capacity to support electric-vehicle-charging and solar
installations. (WEC, No. 118 at p. 2)
EVgo commented that the distribution transformer supply chain
shortages are impacting deployment of EV charging infrastructure and
encouraged DOE to prioritize adequate supply of transformers so that
regulations do not hamper EV charger deployment goals. (EVgo, No. 111
at pp. 1-2)
APPA commented that this rulemaking will increase lead times by 6-
20 months and worsen supply chain constraints, which would negatively
impact larger electrification efforts. (APPA, No. 103 at pp. 1-2, 6-7)
NEMA commented that the proposed standards will increase production
time and will negatively impact electrification and grid resiliency
efforts while weakening domestic manufacturing capacity. (NEMA, No. 141
at pp. 1, 5) NEPPA commented that the proposed standards are infeasible
and may inhibit electric grid reliability, electrification, and
modernization goals. (NEPPA, No. 129 at p. 1)
NYSERDA commented that it anticipates a surge of distribution
transformer installations as utilities make up for recent pandemic-
related supply chain delays. NYSERDA further stated that any delay of
standards could result in a significant number of less efficient
transformers remaining in service well beyond 2050. (NYSERDA, No. 102
at p. 2)
DOE recognizes that a stable transformer supply chain will be
essential to grid modernization. However, DOE disagrees with the notion
that amended standards stand in opposition of those goals. As pointed
out by the CEC, increasing transformer efficiency saves energy that
would otherwise need to pass through the electrical grid, thereby
reducing strain on the electrical grid. Further, as stated by NYSERDA,
delaying efficiency standards for distribution transformers in a time
when additional capacity is expected to come online in the near-to
medium-term would result in the loss of significant energy savings
which could otherwise be realized. As discussed above, providing
certainty as to future transformer efficiency standards could
incentivize manufacturers to invest in more efficient core production
technology in an additive fashion that diversifies core materials and
increases overall production in the near term. DOE also notes that the
adopted standard levels provide the maximum improvement in energy
efficiency while still being technologically feasible and economically
justified. As discussed further, DOE has included in its consideration
of whether efficiency standards are justified the potential effect that
a given standard would have on existing distribution transformer
shortages, on the domestic electrical steel supply, and on projected
changes to the transformer market to support electrification.
DOE also received feedback on how the proposed rule might impact
costs to consumers because of the effect that standards would have on
the transformer supply chain.
Several stakeholders commented that the added costs of using
amorphous core transformers, both in the original purchase price and
increased installation/maintenance costs, will be borne by the end
consumer. (NEPPA, No. 129 at p. 3; REC, No. 126 at p. 2; TMMA, No. 138
at p. 3; Fall River, No. 83 at p. 2; Idaho Falls Power, No. 77 at p. 1)
NEPPA commented that during the 2016 rulemaking process, utilities and
manufacturers predicted that forcing increased efficiency levels would
cause increases to both per-unit cost and lead times. (REC, No. 126 at
p. 2) NEPPA commented that prices are currently up to four times the
predicted price and lead times are upwards of 188 weeks compared to 90-
percent shorter lead times just a few years ago, with many suppliers
not even providing a guaranteed price or lead time to small-volume
purchasers. (NEPPA, No. 129 at p. 2)
Portland General Electric further stated that prices are spiking as
utilities seek more transformers and that utilities are in a precarious
position as they commit to buying and storing more transformers than
may actually be needed. (Portland General Electric, No. 130 at p. 3)
Webb advised against amending efficiency standards given the current
volatility of the transformer market, with high material costs,
restricted production capacity and labor resources, and increasing raw
material costs all contributing to high prices and lead times for
distribution transformers. (Webb, No. 133 at pp. 1-2) WEG commented
that the initial costs of this rule outweigh the benefits, especially
when considering current supply chains. (WEG, No. 92 at p. 1)
DOE notes that the price increases and extended lead times
currently exhibited in the distribution transformer market do not
appear to be the direct result of standards amended in the 2013
Standards Final Rule, as suggested by NEPPA. Rather, the price of
distribution transformers stayed relative constant for several years
following the implementation of standards in 2016.\105\
[[Page 29905]]
It was not until late 2020 or early 2021, when significant disruptions
to the market and industry-wide supply chain challenges began to occur,
that distribution transformer prices began to significantly increase.
These price increases were directly correlated to price increases for
grain oriented electrical steel, which nearly doubled in price from
2021 to 2023.\106\ These price trends demonstrate how recent price
hikes for distribution transformers have been more the result of
increase demand, as opposed to amended efficiency standards. DOE has
considered the potential impact that amended efficiency standards could
have on transformer prices in section IV.C.2 of this document.
---------------------------------------------------------------------------
\105\ U.S. Bureau of Labor Statistics, PPI Commodity data for
Machinery and equipment-Power and distribution transformers, except
parts, not seasonally adjusted. Available at data.bls.gov/pdq/SurveyOutputServlet (last accessed Nov. 3, 2023).
\106\ Metal Miner, Global M3 Price Index. November 2023.
Available at agmetalminer.com/metal-prices/grain-oriented-electrical-steel/ (last accessed Nov. 3, 2023).
---------------------------------------------------------------------------
DOE also received comments relating to the specific challenges that
the transformer supply chain might face in transitioning to amorphous
cores.
Portland General Electric commented that a shift to amorphous core
transformers would lead to even more widespread unavailability of
distribution transformers as transformer manufacturers retool and
redesign production, which would require new submittal and approval
drawings to be provided to utilities. (Portland General Electric, No.
130 at p. 3) Entergy commented that the proposed standard creates an
additional supply constraint for distribution transformers, creates
technical issues that need to be vetted, increases costs, and hampers
resiliency efforts in an area of the country that is critical to energy
security. (Entergy, No. 114 at p. 4)
APPA commented that transformer manufacturers are not expanding due
to concern that the NOPR would make investments obsolete, concerns over
electrical steel availability, and labor shortages, which would be
exacerbated by the additional labor needed to produce amorphous
transformers. (APPA, No. 103 at p. 6) Webb recommended DOE confirm that
manufacturers can gear up their factories in a timely manner to
effectively produce the equipment required for the proposed standards.
(Webb, No. 133 at pp. 1-2)
ERMCO and Exelon stated that the proposed rule would divert
resources from resolving the current transformer supply crisis. (ERMCO,
No. 86 at p. 1; Exelon, No. 95 at p. 2) ERMCO added that this redirect
of resources will take focus off meeting current demand, which will
inevitably open the door for overseas manufacturers to supply the US
electrical grid. (ERMCO, No. 86 at p. 1) WEG commented that if
implemented, the proposed standards will significantly reduce the
supply of distribution transformers to the U.S. (WEG, No. 92 at p. 4)
Southwest Electric commented that enforcing the proposed standards
before sufficient capacity for both amorphous core material and copper
is established could restrict availability of new transformers and
further increase lead times. (Southwest Electric, No. 87 at p. 3)
Prolec GE commented that longer cycle times for amorphous could
reduce production capacity up to 20 percent. (Prolec GE, No. 120 at p.
3) Similarly, Prolec GE commented that thinner laminations for lower-
loss GOES grades affect total mill production capacity and make it
difficult to justify shifting production to lower-loss steels. (Prolec
GE, No. 120 at p. 10)
Eaton commented that prolonged labor and supply chain challenges
have driven lead times up to 18 months for LVDT units and ranging from
2 to 4 years for liquid immersed units. Eaton added that a forced
transition to amorphous will require multiple development projects and
significant capital investment, exacerbating existing labor and
material supply issues. (Eaton, No. 137 at pp. 2-3) Howard commented
that the NOPR has created uncertainty causing electrical steel
manufacturers not to build new silicon steel plants at a time when they
are desperately needed. Howard stated that even absent amended
standards, additional electrical steel capacity is needed to serve the
EV market and increasing efficiency standards magnify these
requirements. (Howard, No. 116 at p. 2) Howard went on to state that
virtually all components of transformers are experiencing a shortage
right now driven by the limited number of suppliers and global labor
and material shortages. Howard encouraged DOE to delay the
implementation of any standards until the existing transformer shortage
is resolved and lead times are back to normal. (Howard, No. 116 at pp.
4-5) Hammond commented that it has expanded capacity by 20 percent in
2020, with another 20 percent planned in 2023, but has still been
struggling to meet demand. Hammond added that all of the expanded
capacity is for GOES core construction, not amorphous. (Hammond, No.
142 at p. 2) ABB stated that the transformer industry will be unable to
provide an adequate supply of transformers to fuel grid modernization
without a robust supply of transformer core steel. (ABB, No. 107 at p.
3)
SolaHD commented that distribution transformers are already very
efficient, and due to the intricate designs, increasing efficiency by
even a fraction of a percent could add weeks or months to lead times.
(SolaHD, No. 93 at p. 2) SolaHD expressed concern that the proposed
standards will worsen existing lead times, which are currently over 16
months times for medium- and high-voltage distribution transformers and
6-8 weeks for the LVDT units that SolaHD produces. SolaHD added that
this might delay national efficiency improvements and electrification
initiatives. (SolaHD, No. 93 at pp. 1-2)
SolaHD, ABB, NEMA, and APPA commented that the administration
clearly recognized the severity of the current supply chain crisis for
transformers given the use of the Defense Production Act to prioritize
domestic transformer production. (SolaHD, No. 93 at p. 2; ABB, No. 107
at p. 3; NEMA, No. 141 at pp. 1-2; APPA, No. 103 at p. 5) Environmental
and Climate Advocates commented that funds from the Bipartisan
Infrastructure Bill and the Inflation Reduction Act can be used by
utilities and buildings owners to cover the costs of new transformers.
(Environmental and Climate Advocates, No. 122 at p. 2)
As previously stated, DOE notes the distribution transformer market
is in a unique position in which capacity needs to be added to meet
demand, regardless of the implementation of standards. This provides
the opportunity for industry to bring capital equipment online through
additions to existing capacity. In light of these comments, DOE has
evaluated an additional TSL in which certain equipment classes remain
at efficiency levels that can cost-competitively be met via GOES. DOE
notes the adopted efficiency levels allows GOES to remain cost-
competitive for a substantial volume of distribution transformer
shipments, meaning that manufacturers can retain their existing capital
equipment, thereby not worsening near-term supply chain issues.
DOE also notes that the standards adopted in this final rule will
allow distribution transformers to cost-competitively utilize existing
GOES capacity across many kVA ratings. As discussed, core production
equipment generally carries flexibility to manufacture a range of core
sizes. As such, if an existing piece of GOES core production equipment
manufactures cores for 75 kVA, 100 kVA and 167 kVA, as an example,
manufacturers can meet efficiency standards by shifting that equipment
to increase 75 kVA and 100 kVA GOES cores and adding a new
[[Page 29906]]
amorphous core production machinery to manufacture 167 kVA
transformers. The resulting arrangement results in an increase in total
transformer core production capacity as the amorphous line is invested
in as an additive equipment line, as opposed to replacing existing GOES
production equipment.
Further, DOE notes that the compliance period for amended standards
has been extended beyond what was proposed in the January 2023 NOPR.
DOE believes the additional time provided to redesign transformers and
build capacity will further mitigate the risk of disrupting production
necessary to meet current demand.
B. Screening Analysis
DOE uses the following four screening criteria to determine which
technology options are suitable for further consideration in an energy
conservation standards rulemaking:
(1) Technological feasibility. Technologies that are not
incorporated in commercial products or in commercially viable, existing
prototypes will not be considered further.
(2) Practicability to manufacture, install, and service. If it is
determined that mass production of a technology in commercial products
and reliable installation and servicing of the technology could not be
achieved on the scale necessary to serve the relevant market at the
time of the projected compliance date of the standard, then that
technology will not be considered further.
(3) Impacts on product utility. If a technology is determined to
have a significant adverse impact on the utility of the product to
subgroups of consumers, or result in the unavailability of any covered
product type with performance characteristics (including reliability),
features, sizes, capacities, and volumes that are substantially the
same as products generally available in the United States at the time,
it will not be considered further.
(4) Safety of technologies. If it is determined that a technology
would have significant adverse impacts on health or safety, it will not
be considered further.
(5) Unique-pathway proprietary technologies. If a technology has
proprietary protection and represents a unique pathway to achieving a
given efficiency level, it will not be considered further, due to the
potential for monopolistic concerns.
10 CFR 431.4; 10 CFR part 430, subpart C, appendix A, 6(c)(3) and 7(b).
In sum, if DOE determines that a technology, or a combination of
technologies, fails to meet one or more of the listed five criteria, it
will be excluded from further consideration in the engineering
analysis. The reasons for eliminating any technology are discussed in
the following sections.
The subsequent sections include comments from interested parties
pertinent to the screening criteria, DOE's evaluation of each
technology option against the screening analysis criteria, and whether
DOE determined that a technology option should be excluded (``screened
out'') based on the screening criteria.
1. Screened-Out Technologies
In the January 2023 NOPR, DOE screened-out the technology options
listed in Table IV.6 and detailed the basis for screening in chapter 4
of the NOPR TSD.\107\ DOE did not receive any comments on the screened-
out technology options. As such, DOE has retained those technology
options as screened-out.
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\107\ Available at Docket No. EERE-2019-BT-STD-0018-0060.
[GRAPHIC] [TIFF OMITTED] TR22AP24.533
2. Remaining Technologies
Through a review of each technology, DOE concludes that the
remaining combinations of core steels, winding configurations and core
configurations as combinations of ``design options'' for improving
distribution transformer efficiency met all five screening criteria to
be examined further as design options in DOE's final rule analysis.
DOE determined that these technology options are technologically
feasible because they are being used or
[[Page 29907]]
have previously been used in commercially available products or working
prototypes. DOE also finds that all of the remaining technology options
meet the other screening criteria (i.e., practicable to manufacture,
install, and service; do not result in adverse impacts on consumer
utility, product availability, health, or safety; and do not utilize
unique-pathway proprietary technologies). For additional details, see
chapter 4 of the final rule TSD.
DOE received comments from certain stakeholders suggesting that
amorphous cores should be screened out as a technology option.
Regarding use of amorphous cores in high-kVA distribution
transformers, Eaton commented that it is not aware of any amorphous
core transformers that are commercially available beyond 1,500 kVA and
therefore DOE should screen-out amorphous cores for distribution
transformers beyond 1,500 kVA. (Eaton, No. 137 at p. 19) Eaton stated
that manufacturers would need to resolve technical challenges before
manufacturing amorphous cores over 1,500 kVA and therefore DOE should
not evaluate efficiency standards for transformers above 1,500 kVA that
cannot be met with GOES. (Eaton, No. 137 at p. 26) TMMA commented that
amorphous is unproven for transformers larger than 2,500 kVA and
therefore it is not clear that the proposed standards are technically
feasible. (TMMA, No. 138 at p. 3) Prolec GE commented that amorphous is
not proven all the way up to 5,000 kVA. (Prolec GE, No. 120 at p. 3)
LBA commented that amorphous transformers have more limited capacity,
which will require manufacturers to increase the number of
transformers. (LBA, No. 108 at p. 3)
Carte commented that amorphous cores are highly susceptible to any
outside pressure on the cores and as such cannot be used to secure the
coils inside a transformer on larger kVA. (Carte, No. 140 at p. 2)
Carte stated that certain manufacturers had not built amorphous core
transformers beyond certain sizes due to these clamping limitations and
encouraged DOE to investigate if large amorphous cores could be built.
(Carte, No. 140 at p. 2) Carte added that developing new technology to
be able to brace large amorphous cores could take years and cost
hundreds of thousands of dollars. (Carte, No. 140 at p. 2)
DOE notes that amorphous transformers do exist over 1,500 kVA.
Numerous foreign manufacturers advertise both liquid-immersed and MVDT
distribution transformers above 1,500 kVA. One manufacturer in Korea
markets 15,000 kVA amorphous oil-immersed transformers, with deliveries
as early as 2007, and markets amorphous MVDT units up to 5,000
kVA.\108\ One manufacturer in India markets amorphous liquid-immersed
distribution transformers up to 5,000 kVA.\109\ Dating back to the
early 2010's, ABB offered an amorphous MVDT unit up to 4,000 kVA.\110\
Further, in public utility bid data, DOE has observed numerous
manufacturer bids for 2,500 kVA amorphous core distribution
transformers (see chapter 4 of the TSD). While Carte is correct that
amorphous cores do not have the same inherent mechanical strength as
GOES, manufacturers have developed core clamps and bracing to provide
the necessary mechanical strength. In some cases, this may even include
using a strip of GOES steel on the exterior of an amorphous core to
provide additional mechanical strength.\111\
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\108\ Cheryong Electric, Power Products. Available at
en.cheryongelec.com/eng/library/catalog.php.
\109\ Kotsons, Power & Distribution Transformers. Available at
www.kotsons.com/assets/images/Broucher.pdf.
\110\ ABB, Responding to a changing world: ABB launches new dry-
type transformer products, 2012. Available at library.e.abb.com/public/74cdbc97d4588a1cc1257ab8003a00b5/22-27%20sr105a_72dpi.pdf.
\111\ Advanced Amorphous Technology, About Amorphous
Distribution Transformer. Available at advancedamorphous.com/about-amorphous-distribution-transformer/ (last accessed Oct. 17, 2023).
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Regarding use of amorphous cores in LVDT distribution transformers,
Hammond commented that the performance of amorphous cores degrades
above 160C and LVDTs frequently are rated with an insulation system
capable of 220C, so there is insufficient technical data to understand
how amorphous cores will perform long term in LVDT applications.
(Hammond, No. 142 at pp. 2-3)
SolaHD expressed concern that amorphous cores are largely untested
for LVDT distribution transformers, stating that amorphous cores are
less flexible and more expensive than GOES. (SolaHD, No. 93 at p. 2)
Schneider commented that amorphous will increase the sound emitted from
distribution transformers, which likely won't be an issue for products
installed outdoors or in large electrical rooms but may be an issue for
LVDTs, which are typically in smaller rooms. (Schneider, No. 101 at p.
14) Eaton commented that there is a lack of technical data to validate
the performance of amorphous cores for LVDT transformers. Eaton further
stated that developing manufacturing processes for amorphous LVDT
transformers will require significant investment, years of research and
development, and impact required accuracy to meet customer
specifications. (Eaton, No. 137 at p. 41)
DOE notes that Hammond did not provide any data or modeling as to
the change in transformer core performance above 160C. However,
distribution transformer temperature rise is governed by transformer
losses. A more efficient transformer may not ever meet the insulation
temperature limits. In the case of amorphous dry-type transformers,
Schneider commented regarding K-factor rated transformers that computer
modeling suggests that the reduced losses of amorphous LVDT units would
place the thermal characteristics well below the insulation material.
(Schneider, No. 101 at pp. 5-6) Further, in the amorphous LVDT and MVDT
products marketed in international markets, it is common for
transformers to be marketed with Class H or Class F insulation,
corresponding to 150C and 115C temperature rise, or 220C and 185C
performance.112 113 A comparison of the performance of these
LVDT units to DOE modeled units is given in chapter 5 of the TSD and
indicates that it is technically feasible to build LVDTs with amorphous
cores that satisfy common customer specifications.
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\112\ Toyo Electric, ``Dry-type Amorphous core transformer.''
Available at www.toyo-elec.co.jp/en/products/dry-type-amorphous-core-transformer/ (last accessed Oct. 2023).
\113\ Chu Lei Electric Co., ``Amorphous Transformers.''
Available online at: www.powertransformer.com.tw/en/amorphous-
transformers.html (last accessed Oct. 2023).
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APPA stated that rewinding transformers, rather than purchasing a
new transformer, can result in a lower cost and shorter lead time for
utilities. (APPA, No. 103 at pp. 11-12) APPA commented that utilities
today are rewinding up to 15 percent of their transformers due to the
significant lead times. (APPA, No. 103 at pp. 11-12). APPA commented
that the ability to rewind GOES transformers is a consumer utility that
would be lost if DOE standards require amorphous cores. (APPA, No. 103
at pp. 11-12)
APPA stated that GOES transformer rewinding equipment is
incompatible with amorphous cores and notes that amorphous rewinding
equipment is far more complex and expensive. (APPA, No. 103 at pp. 11-
12) DOE notes that amorphous core transformers can also be rewound, as
acknowledged by APPA, and therefore DOE disagrees that the ability to
rewind a transformer is lost if an amorphous core is used.
DOE notes that the transformer rebuilding/rewinding market has
historically been relatively small. Rewinding a distribution
transformer
[[Page 29908]]
requires additional labor (because labor is required both to
deconstruct the transformer and rebuild it) that has made replacing a
distribution transformer the preferred option when a transformer fails.
While recently there has been an uptick in transformer rewinding, that
is primarily a function of long lead times for new transformers.
Regardless of the core steel used to meet efficiency standards,
rewinding of GOES transformers will continue to be an option for
utilities for as long as existing GOES transformers remain in the
field. Given that rewinding of transformers does not typically occur
until late in a distribution transformer's lifetime, any existing
utility investment in rewinding equipment will likely be used on the
existing stock of transformers for many decades. Any investment in
amorphous core rewinding equipment would likely be in an additive
function and not impact near or medium-term ability to rewind
transformers.
DOE notes that amorphous core transformers have been used as a
technology option for high-efficiency transformers for many decades.
While there are conversion costs, required to transition from producing
GOES cores to amorphous cores, those costs are considered in the
manufacturer impact analysis. Additionally, while amorphous cores are
different than GOES cores and require a degree of technological
understanding to properly use amorphous core transformers, the vast
majority of liquid-immersed transformer manufacturers have some
experience building amorphous core transformers, and numerous foreign
manufacturers produce amorphous core transformers spanning a range of
product classes. Further, manufacturers have the option to purchase
finished amorphous cores from third-party electrical processing
companies, which provides another avenue to producing amorphous core
transformers. Based on the foregoing discussion, DOE has retained
amorphous cores as a technology option for achieving higher efficiency
standards in distribution transformers.
C. Engineering Analysis
The purpose of the engineering analysis is to establish the
relationship between the efficiency and cost of distribution
transformers. There are two elements to consider in the engineering
analysis; the selection of efficiency levels to analyze (i.e., the
``efficiency analysis'') and the determination of product cost at each
efficiency level (i.e., the ``cost analysis''). In determining the
performance of higher-efficiency equipment, DOE considers technologies
and design option combinations not eliminated by the screening
analysis. For each equipment class, DOE estimates the baseline cost, as
well as the incremental cost for the product/equipment at efficiency
levels above the baseline. The output of the engineering analysis is a
set of cost-efficiency ``curves'' that are used in downstream analyses
(i.e., the LCC and PBP analyses and the NIA).
1. Efficiency Analysis
DOE typically uses one of two approaches to develop energy
efficiency levels for the engineering analysis: (1) relying on observed
efficiency levels in the market (i.e., the efficiency-level approach),
or (2) determining the incremental efficiency improvements associated
with incorporating specific design options to a baseline model (i.e.,
the design-option approach). Using the efficiency-level approach, the
efficiency levels established for the analysis are determined based on
the market distribution of existing products (in other words, based on
the range of efficiencies and efficiency level ``clusters'' that
already exist on the market). Using the design option approach, the
efficiency levels established for the analysis are determined through
detailed engineering calculations and/or computer simulations of the
efficiency improvements from implementing specific design options that
have been identified in the technology assessment. DOE may also rely on
a combination of these two approaches. For example, the efficiency-
level approach (based on actual products on the market) may be extended
using the design option approach to interpolate to define ``gap fill''
levels (to bridge large gaps between other identified efficiency
levels) and/or to extrapolate to the ``max-tech'' level (particularly
in cases where the ``max-tech'' level exceeds the maximum efficiency
level currently available on the market).
For this final rule analysis, DOE used an incremental efficiency
(design-option) approach. This approach allows DOE to investigate the
wide range of design option combinations, including varying the
quantity of materials, the core steel material, primary winding
material, secondary winding material, and core manufacturing technique.
For each representative unit analyzed, DOE generated hundreds of
unique distribution transformer designs by contracting with Optimized
Program Services, Inc. (OPS), a software company specializing in
distribution transformer design. The OPS software uses two primary
inputs: (1) a design option combination, which includes core steel
grade, primary and secondary conductor material, and core
configuration, and (2) a loss valuation.
DOE examined number design option combinations for each
representative unit. The OPS software generated 518 designs for each
design option combination based on unique loss valuation combinations.
Taking the loss value combinations, known in industry as A and B values
and representing the commercial consumer's present value of future no-
load and load losses in a distribution transformer respectively, the
OPS software sought to generate the minimum TOC. TOC can be calculated
using the equation below.
TOC = Transformer Purchase Price + A * [No Load Losses] + B * [Load
Losses]
a. Representative Units
Distribution transformers are divided into different equipment
classes, categorized by the physical characteristics that affect
equipment efficiency. DOE's current equipment classes are detailed in
section IV.A.2.
Because it is impractical to conduct detailed engineering analysis
at every kVA rating, DOE conducts detailed modeling on ``representative
units'' (RUs). These RUs are selected both to represent the more common
designs found in the market and to include a variety of design
specifications to enable generalization of results.
DOE detailed the specific RUs used in the NOPR analysis and those
units' characteristics in chapter 5 of the NOPR TSD.\114\ Each RU
represents an individual transformer model referred to by a specific RU
number (e.g., RU1, RU2, etc.). DOE requested comment on its
representative units as well as any data for potential equipment that
may have a different cost-efficiency curve than those that can be
represented by the representative units. 88 FR 1722, 1759-1760.
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\114\ Available at Docket No. EERE-2019-BT-STD-0018-0060.
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Regarding the characteristics of the representative units, Carte
commented that RU3 uses a 150 kV BIL when, based on its primary voltage
of 14.4 kV, it should use a 95 kV BIL or 125 kV BIL. (Carte No. 140 at
p. 9)
DOE notes that representative units are selected to represent both
common designs found on the market and to include a variety of design
specifications to enable generalization of results. In the case of RU3,
DOE selected a more conservative BIL rating to assist in generalization
of result. The
[[Page 29909]]
resulting design would be slightly more costly than a 95 kV BIL or 125
kV BIL and therefore represents a more conservative design than the
most common design.
Regarding any units that have different cost-efficiency curves,
Carte commented that high-impedance transformers still within the
normal impedance range can be more challenging to meet efficiency
standards. (Carte, No. 140 at p. 10) Carte commented that certain high-
BIL transformers can have higher costs in order to meet the current
efficiency levels as compared to the modeled BIL values. (Carte, No.
140 at pp. 9-10) Carte also identified multi-voltage transformers, and
main and teaser transformers as other designs that have a very high-
cost to meet NOPR levels using GOES. (Carte, No. 140 at pp. 9-10) Carte
commented that meeting NOPR levels with GOES for main and teaser
transformers increases costs by over 100 percent. (Carte, No. 140 at p.
9) DOE notes that the data cited by Carte refer to meeting EL 4 without
using amorphous and does not discuss the cost increase if those same
transformers were designed using amorphous cores.
DOE agrees that certain distribution transformers with uncommon
features may have a more difficult time meeting any given efficiency
level. However, typically those uncommon features result in higher
costs both at baseline and under amended efficiency standards.
Therefore, the incremental costs of building that same transformer are
similar.
In the January 2023 NOPR, DOE also noted that while some
applications may generally have a harder time meeting a given
efficiency standard, most applications would generally be able to use
amorphous cores to achieve higher efficiency levels. This includes
designs at efficiency levels beyond the max-tech efficiency included in
DOE's analysis. 88 FR 1722, 1759.
Eaton provided data demonstrating relatively consistent incremental
costs for a variety of multi-voltage distribution transformers. (Eaton,
No. 137 at p. 16) Eaton's data showed the cost-efficiency curve for a
500-kVA distribution transformer with an amorphous core and a variety
of different primary voltage configurations. Id. Eaton's data showed
that, depending on the voltage configuration, the baseline cost of a
given transformer could vary. Id. However, the incremental cost
associated with meeting any given efficiency level is similar for all
transformers up until that specific design reaches its ``efficiency
wall'' wherein the costs begin to increase rapidly.
As discussed in the January 2023 NOPR, Eaton's data shows that all
designs for this unit can meet max-tech efficiency levels using an
amorphous core; however, certain designs may have a harder time meeting
the max-tech level as evidence by the higher costs. Further, Eaton's
data shows that all of these designs have a similar incremental cost to
increase efficiency from a baseline design through the NOPR levels,
indicating that DOE's analysis is likely sufficient to encompass all of
these designs.
While Carte commented that the incremental costs associated with
meeting higher efficiency values is significant for distribution
transformers with a variety of characteristics, DOE notes that Carte
generally was referring to meeting higher standards without transiting
to amorphous cores. DOE data similarly shows that meeting NOPR
efficiency levels without using amorphous cores results in a
significant cost increase. However, if using an amorphous core, higher
efficiency levels can be met without extreme cost increases.
Several stakeholders commented regarding potential challenges
associated with transformers' ability to handle harmonics and the
potential challenges units would have in meeting efficiency standards.
Carte commented that solar inverters can create harmonics and
speculated that the modifications needed to accommodate these harmonics
may increase losses or not be achievable with amorphous cores. (Carte,
No. 140 at p. 3) Carte commented that IEEE is evaluating the impact of
solar generation on power quality and transformer design. Id. Nichols
commented that the smart grid will have increased harmonics and
additional control switches will be needed to monitor harmonics in
addition to the amount of power. (Nichols, No. 73 at p. 1) Eaton
commented that EV charging is likely to increase the amount of
harmonics currents on transformers. (Eaton, No. 137 at p. 38)
Harmonics lead to excess losses in both the transformer core and
transformer coil. Distribution transformer efficiency is measured using
a sinusoidal wave function (i.e., a current without harmonics) and
therefore the impact of harmonic currents is not captured in the DOE's
test procedure. The primary concern with harmonic currents is that they
lead to excess heat generation. This excess heat can lead a transformer
to overheat, even if it is not loaded at its maximum capacity. In
dealing with harmonic currents, consumers can purchase harmonic
mitigating transformers, K-factor rated transformers, or intentionally
oversize transformers such that they never operate near their thermal
loads. Regarding harmonic mitigating transformers, DOE notes harmonic
mitigating transformers involve phase-shifted windings, which would be
an option both at baseline and higher-efficiency levels, including with
amorphous cores.
Powersmiths commented that DOE did not consider K-factor rated
transformers in its representative units, which have larger footprints
and windings in order to deal with the thermal impacts of harmonic
currents, and stated that K-factor rated transformers have a lower
achievable efficiency. (Powersmiths, No. 112 at p. 2) Eaton expressed
concern that the OPS software may not accurately model the additional
requirements for data center transformers, such as higher k-factors,
lower flux density, and adjusted temperature rise. To demonstrate this,
Eaton provided data comparing the specifications of an OPS design
without a K-factor rating to the specifications of manufactured data
center transformers with various K-factor ratings. (Eaton, No. 137 at
p. 37)
Regarding modeling a K-factor rated transformer as a representative
unit, DOE notes that a transformer that has a K-factor rating is
designed to accommodate the additional thermal stress of equipment
harmonics. Rather than trying to cancel out harmonic currents, as
harmonic mitigating transformers do, K-factor rated transformers are
typically oversized and derated to accommodate the additional heat from
harmonics. As such, they have larger transformer cores and, therefore,
higher no-load losses. However, DOE notes that more efficient
transformers may not ever meet the insulation temperature limits. In
the case of amorphous dry-type transformers, Schneider commented
regarding K-factor rated transformers that computer modeling suggests
that the reduced losses of amorphous LVDT units would result in thermal
characteristics that are well below the insulation material.
(Schneider, No. 101 at pp. 5-6) Further, amorphous cores have lower no-
load losses per pound of core material. Hence, transformer with
additional core material, such as K-factor rated transformers, would
experience a greater improvement in efficiency relative to a baseline
transformer. For these reasons, DOE has not included a specific
representative unit for K-factor rated transformers and
[[Page 29910]]
assumes the current representative units are sufficiently
representative.
b. Data Validation
There can be differences between distribution transformer modeling
and real-world data. In order to ensure DOE's modeled data reflects
reality, DOE has relied on a variety of manufacturer literature,
manufacturer public utility bid data, and feedback from stakeholders.
DOE presented plots demonstrating how real-world data compares with
modeled data in chapter 5 of the NOPR TSD.\115\
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\115\ Available at Docket No. EERE-2019-BT-STD-0018-0060.
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Regarding data validation for LVDTs, Powersmiths commented that DOE
should ensure models meeting the proposed LVDT efficiency standards
have actually been built because gaps exist between transformer
modeling and real-world performance. (Powersmiths, No. 112 at p. 2)
Powersmiths stated that the OPS modeling software does not accurately
model stray and eddy losses, which for certain high-kVA designs can
increase significantly and requires comparison of modeling to real
designs in order to create a feedback loop to ensure the modeled
designs can actually be built. (Powersmith, No. 112 at pp. 3-4)
Powersmiths particularly expressed concern that DOE NOPR levels for
LVDTs are largely based on amorphous core transformers which include
deviations between the real-world data and the modeled data.
(Powersmiths, No. 112 at p. 2) Powersmiths recommended that DOE work
with industry to build, test, and verify modelled designs.
(Powersmiths, No. 112 at p. 6) Eaton commented that using modeling to
reflect what is achievable is a valid approach; however, software
modeling does not necessarily include the manufacturer-to-manufacturer
variability that exists in the real world. (Eaton, No. 137 at p. 41)
Hammond commented that their modeling confirms that amorphous cores
would be used to meet the NOPR efficiency levels for LVDTs. (Hammond,
No. 142 at p. 2)
For dry-type transformers, DOE notes that chapter 5 of the NOPR TSD
presents plots comparing the range of no-load and load loss
combinations modeled for each representative unit to real world no-load
and load loss data certified in NRCAN's database. These plots show the
modeled design space for GOES transformers very closely aligns with the
real-world design space shown in NRCAN's database. DOE notes that
Powersmiths did not identify any unique features associated with
amorphous core LVDTs that would result in the modeling for GOES to be
accurate while the modeling for amorphous transformers to not be
accurate. DOE has included additional data points taken from
manufacturer literature in chapter 5 of the final rule TSD to
demonstrate the real-world designs of amorphous LVDT transformers. DOE
notes that this real-world data shows that the modeled amorphous design
space very closely aligns with the real-world loss performance of
amorphous core LVDTs.
For liquid-immersed transformers, DOE has similarly presented a
comparison of the no-load and load loss combinations modeled in each
representative unit as compared to real world manufacturer data. These
plots show the modeled design space for both amorphous and GOES
transformers very closely aligns with the real-world design space shown
in manufacturer bid sheets.
Regarding the accuracy of DOE equipment costs, HVOLT commented that
DOE's optimization model understates selling prices by as much as 40-50
percent and suspected that this because some of DOE's designs were
developed as part of the previous rulemaking. (HVOLT, No. 134 at p. 6)
DOE notes that the difference between current prices and modeled
prices is related to the fact that DOE modeling uses a 5-year average
pricing while current prices for a baseline transformer are higher than
the 5-year average. DOE's modeled prices have historically been in-line
with real-world data, indicating that the physical construction of the
transformers is accurate.
Current distribution transformer pricing is near its all-time high
due to shortages. However, because most of the market relies on GOES,
the price of GOES steel has increased more than the price of amorphous
alloy. If DOE relied on current spot prices, as HVOLT suggests, the
cost of the baseline transformer would increase considerably and be
more in-line with the 40-50 percent increase cited by HVOLT. However,
higher efficiency levels, particularly those with amorphous cores,
would become far more cost competitive because amorphous alloy has not
had the same demand pressure as GOES steel in recent years. DOE has
updated prices for the final rule, as described in section IV.C.2 of
this document, to reflect updated 5-year average prices.
Eaton submitted independently developed cost-efficiency and max-
tech performance curves. Eaton provided a cost-efficiency curve for
both amorphous and GOES transformers of similar kVA sizes as DOE's RU5
unit. (Eaton, No. at p. 19) DOE has provided a comparison between
Eaton's data and DOE's modeled data in chapter 5 of the TSD. In
general, the two are very closely aligned.
Eaton stated that its modeling showed some discrepancies between
some of the max-tech efficiencies modeled by DOE and its max-tech
efficiencies resulting from scaling representative units to high-kVA
units. Eaton recommended DOE work with manufacturers to compare its
modeling to real world max-tech values, particularly for omitted kVA
ratings in the analysis. (Eaton, No. 137 at p. 20) DOE appreciates
Eaton's work to validate its modeling and has relied on Eaton's
modeling, in addition to other data sources, to modify DOE's scaling
methodology for high-kVA units, as detailed in section IV.C.1.e of this
document.
c. Baseline Energy Use
For each product/equipment class, DOE generally selects a baseline
model as a reference point for each class, and measures anticipated
changes resulting from potential energy conservation standards against
the baseline model. The baseline model in each product/equipment class
represents the characteristics of a product/equipment typical of that
class (e.g., capacity, physical size). Generally, a baseline model is
one that just meets current energy conservation standards, or, if no
standards are in place, the baseline is typically the most common or
least efficient unit on the market.
DOE's analysis for distribution transformers generally relies on a
baseline approach. However, instead of selecting a single unit for each
efficiency level, DOE selects a set of units to reflect that different
distribution transformer purchasers may not choose distribution
transformers with identical characteristics because of difference in
applications and manufacturer practices. The mechanics of the customer
choice model at baseline and higher efficiency level are discussed in
section IV.F.3 of this document.
d. Higher Efficiency Levels
Regarding evaluating higher efficiency standards, numerous
stakeholders commented that transformers are already efficient and
stated that because efficiency is only increased by less than one
percentage point, amended standards aren't worth the burdens that they
would impose on manufacturers and the supply chains. (NMHC & NAA, No.
97 at p. 4; TVPPA, No. 144 at p. 1; APPA, No. 103 at p. 7; Pugh
Consulting, No. 117 at p. 2; Alabama Senator, No.
[[Page 29911]]
113 at p. 2; Webb, No. 133 at p. 2; CARES, No. 99 at pp. 2-3; AISI, No.
115 at p. 1; Strauch, No. 74 at p. 1; VA, MD, and DE Members of
Congress, No. 148 at p. 2; New York Members of Congress, No. 153 at p.
2; EEI, No. 135 at pp. 44-47)
REC commented that, while amorphous cores provide a significant
percentage reduction in losses, the increase in rated efficiency is
small. (REC, No. 126 at p. 3)
CEC commented that distribution transformers are ubiquitous, and
even small improvements to standards can have significant benefits to
energy generators and distributors, manufacturers, consumers, and the
environment. (CEC, No. 124 at p. 1)
Stakeholders are correct in their assessment that currently
available distribution transformers are typically over 98 percent
efficient. However, nearly all electricity passes through at least one
distribution transformer and distribution transformers experience those
losses 24 hours a day, 365 days per year, across a usable life that
spans decades. Therefore, the losses from any single transformer, even
if small in a particular instance, can be substantial in the aggregate
and make up a considerable portion of a given transformer's total
ownership costs.
Further, the efficiency levels proposed in the January 2023 NOPR
represent a 2.5 to 50 percent reduction in transformer losses. DOE
conducts its analysis to determine if the benefits of these operating
cost and energy savings are economically justified. Hence, even though
the change in efficiency appears to be a small number, the benefits of
the evaluated efficiency standards may be substantial compared to
existing performance, as reflected in DOE's analysis.
In evaluating higher efficiency levels, DOE relies on a similar
approach to its baseline engineering analysis. DOE's modeled designs
span the entire design space. In evaluating a higher efficiency level
up until the max-tech that DOE considers, DOE evaluates the modeled
units that would exceed the higher efficiency level. Then, rather than
selecting a single unit, DOE applies a customer choice model to
evaluate the distribution transformer that would be purchased if
standards were amended.
DOE notes that for a given design option combination, the least
efficient units typically tend to be the lowest cost unit.
Eaton commented that when meeting higher efficiency levels with
GOES, manufacturers increase the core cross sectional area and decrease
the flux density. (Eaton, No. 137 at pp. 21-22) The larger transformer
cores require thicker conductors in order to maintain current density
but using thicker conductors increases stray and eddy losses, which
requires even larger conductor size to combat the additional stray and
eddy losses. (Eaton, No. 137 at pp. 21-22) Eaton stated that at some
point, the only option is to transition to copper windings, at which
point the cost of the transformer skyrockets and significant cost
increases are needed for even modest efficiency gains. (Eaton, No. 137
at pp. 21-22)
HVOLT commented that DOE proposed levels result in several products
that will hit an efficiency wall where significant cost increases would
result in very little efficiency improvement. (HVOLT, No. 134 at p. 2)
HVOLT did not specify which products or clarify if that comment was
across all core materials or only GOES.
Prolec GE commented that in their modeling, they found it was
technically feasible to meet proposed standards with GOES cores and
copper windings, but they would be at a cost disadvantage relative to
amorphous cores that could use aluminum windings to meet efficiency
standards. (Prolec GE, No. 120 at p. 8)
Powersmiths commented that the proposed standards for LVDTs are at
max-tech, which does not leave sufficient margin for manufacturing and
material batch variability. (Powersmiths, No. 112 at p. 2)
WEG commented that it is possible to reduce transformer losses to
get halfway to the NOPR standards using a GOES core and copper
windings, but the cost of the transformer would increase by 60 percent.
(WEG, No. 92 at p. 1) NEMA commented that meeting the proposed LVDT
efficiency standards with GOES would result in large weight increases
and be impractical. (NEMA, No. 141 at p. 6)
Stakeholder comment is consistent with DOE modeling that it is
technically feasible to meet many higher efficiency levels with GOES.
However, beyond some efficiency levels it is no longer the lowest cost
option. In evaluating higher efficiency levels, beyond a certain
reduction in losses, transitioning from a GOES steel core to an
amorphous core becomes by far the most cost effective approach for
meeting higher-efficiency standards due to the significant reduction in
no-load losses associated with an amorphous core.
As noted, the DOE test procedure specifies measuring efficiency at
50 percent PUL for liquid-immersed and MVDT distribution transformers
and 35 percent PUL for LVDT distribution transformers. Distribution
transformer performance at any given PUL can be approximated as no-load
losses plus load losses multiplied by the square of the PUL. In meeting
higher efficiency standards, manufacturers can employ design options
that reduce no-load losses, reduce load losses, or a combination of the
two. DOE models different design options that reduce both no-load
losses and load losses and generally relies on manufacturer selling
prices to determine what consumers are likely to purchase.
REC stated that if DOE measured energy efficiency at 100 percent
PUL, the losses of an amorphous transformer could be higher than the
losses of a GOES transformer. (REC, No. 126 at pp. 2-3) Idaho Power
commented that it prefers technologies that reduce load losses rather
than those that improve no-load losses. (Idaho Power, No. 139 at p. 2)
Cliffs stated that when load levels are at 50 percent or higher, GOES
transformers outperform amorphous transformers and provided plots to
demonstrate this. (Cliffs, No. 105 at pp. 16-17) HVOLT recommended that
DOE not implement any standards that exclude GOES given that amorphous
cores hit peak efficiency at 20 percent loading and are less efficient
than GOES above 50 percent loading. (HVOLT, No. 134 at p. 5) Cliffs
further commented that AM transformers will not be able to sustain grid
loading requirements, jeopardizing Department of Defense applications
which rely upon resilient grid systems to supply backup power
generation for mission requirements. (Cliffs, No. 105 at pp. 8-9)
NEPPA commented that amorphous cores may have slightly lower no-
load losses than GOES cores, but they typically have higher load
losses. NEPPA added that as loading levels increase due to
electrification, amorphous core use does not guarantee overall lower
losses when transformer loading increases over time. (NEPPA, No. 129 at
p. 2) Idaho Power further recommended DOE evaluate transformer
efficiency designs at higher load-losses (above 50 percent) instead of
targeting increased efficiencies in no-load losses, given expected
increases in loading with electrification. (Idaho Power, No. 139 at pp.
2-3) CARES and AISI commented that amorphous transformers are less
efficient at higher loads and therefore the benefits of the NOPR are
limited. (CARES, No. 99 at p. 4; AISI, No. 115 at p. 3) MTC commented
that both low-loss GOES and amorphous core transformers provide similar
energy savings at higher load factors. MTC provided data for both GOES
and amorphous designs compliant with the European ECO-1
[[Page 29912]]
and ECO-2 efficiency standards to demonstrate this point. (MTC, No. 119
at pp. 13-15) MTC added that higher losses above 50 percent loading is
not ubiquitous for amorphous transformers and is driven by DOE's
testing requirement at 50 percent load. (MTC, No. 119 at p. 15)
DOE notes that its analysis considers technologies that reduce both
no-load losses and load losses. As discussed, both amorphous core
transformers and GOES core transformers have no-load and load losses
wherein the no-load losses are approximately constant and the load
losses vary with loading. DOE evaluates efficiency at 50 percent
loading for liquid-immersed and MVDT distribution transformers and 35
percent for LVDT distribution transformers. DOE models any potential
energy savings by evaluating the actual loading on transformers and
accounts for both no-load and load losses as discussed in section IV.E
of this document.
Cliffs and Carte stated that increasing demand on the electric grid
will result in distribution transformers frequently operating beyond 50
percent load, which means that GOES transformers will have higher
efficiency in the field. (Cliffs, No. 105 at pp. 16-17; Carte, No. 140
at p. 6) WEG commented that amorphous cores have their peak efficiency
at lower loads and as loading increases as a result of electrification,
a GOES design will be better optimized for higher loading. (WEG, No. 92
at p. 3) WEC and Xcel Energy commented that new load growth, such as
the load growth associated with adding electric vehicles, will lead to
load losses becoming more important and no-load losses becoming less
important. (WEC, No. 118 at p. 1; Xcel Energy, No. 127 at p. 1) Webb
commented that DOE should confirm amorphous transformers are efficient
across a broad range of equipment loadings. (Webb, No. 133 at p. 2)
NEMA commented that certain LVDTs could operate less efficiently if
average load exceeds 35 percent. (NEMA, No. 141 at p. 6) Hammond
commented that future electrification may result in many LVDT loaded
above 35 percent and that puts greater emphasis on load losses, which
favors GOES over amorphous. (Hammond, No. 142 at p. 2) Efficiency
Advocates commented and provided data to show that, even under heavy
load growth which would results in near 100 percent average load by
2058, DOE's proposed standards would still provide energy savings.
(Efficiency Advocates, No. 121 at pp. 5-6)
Regarding the plots cited by Cliffs to support the claim that GOES
transformers outperform amorphous transformers beyond 50 percent
loading, DOE notes that Cliffs is making a comparison between a GOES
and amorphous transformers that are equally efficient at 50 percent
load. In evaluating higher efficiency standards, DOE makes a comparison
between the baseline transformer (one purchased under current
standards) and the transformer that would be purchased under amended
efficiency standards. The plots cited by Cliffs show that both the GOES
and amorphous designs at the proposed standards would outperform a
baseline GOES design up to and beyond 100 percent loading. However, DOE
notes that the GOES designs are expected to a require a significantly
higher increase in both cost and weight, making them less favorable
when compared to a current baseline design.\116\
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\116\ See attachment 2 of comment submitted by HVOLT for
underlying data (HVOLT, No. 134).
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Eaton commented that the efficiency of an amorphous transformer can
be improved at little cost by using larger conductors up until the size
limits for aluminum conductors, at which point it becomes very
expensive to reduce losses further. (Eaton, No. 137 at p. 22) Eaton
commented that it is a misconception that amorphous units are less
efficient than GOES transformers above 50 percent PUL. (Eaton, No. 137
at p. 32) Eaton provided similar plots to Cliffs and noted that
amorphous transformers that were designed to meet the current DOE 2016
efficiency levels required very little investment in the transformer
windings due to their very low no-load losses. Id. As such, the
amorphous core transformer is the lowest weight product but also has an
efficiency curve that decreases considerably as loading increases. Id.
Eaton further commented that amorphous transformers designed to
meet the proposed levels in the January 2023 NOPR include a modest
investment in the transformer winding such that the efficiency of an
amorphous design is greater than the baseline GOES design across all
loading points. (Eaton, No. 137 at p. 32) Eaton stated that the
incremental weight of the more efficient transformer is only 5.4
percent relative to the base amorphous design and ~1 percent relative
to the base GOES design. Id. Eaton noted that while a GOES design can
still meet the January 2023 NOPR levels and that GOES transformer would
have a higher efficiency beyond 50 percent load than the amorphous
transformer, considerably more material is needed, leading to a 50
percent weight increase. Id.
Eaton provided an additional design point to represent an amorphous
design with additional investment windings, which reduces the load
losses such that the amorphous design is more efficient across all
loading points than even the GOES design that meets the January 2023
NOPR levels. Id. Eaton noted that this amorphous transformer can be
built with an ``extremely modest weight increase of 14.5 percent''
relative to the baseline amorphous transformer. Id.
The data provided by Eaton further confirms that amorphous
transformers can be designed to maintain high efficiency across the
entire range of transformer loading. While a baseline GOES transformer
may exhibit higher efficiency than a baseline amorphous transformer at
higher loading, both DOE's modeling and stakeholder comment indicate
that either an amorphous or a GOES transformer designed to meet amended
efficiency standards would outperform a baseline transformer at all
loading points. As such, DOE maintains that amorphous transformers
stand to provide significant energy savings, even if average
transformer loading were to increase.
Southwest Electric commented that they used current design data to
model a baseline transformer and transformers that met the NOPR
efficiency levels for 3-phase pad-mount transformers ranging from 112.5
kVA to 3750 kVA. (Southwest Electric, No. 87 at p. 2) Southwest
Electric stated that in their case, all of the baseline transformer
designs would use amorphous cores. (Southwest Electric, No. 87 at p. 2)
Southwest Electric stated that based on their data, simply switching to
an amorphous core would not be sufficient to meet the NOPR efficiency
standards and additional investment would be needed in the conductor in
order to meet the NOPR proposed levels. (Southwest Electric, No. 87 at
p. 2)
DOE notes that manufacturer data from both Southwest Electric and
Eaton suggest that for at least some 3-phase, liquid-immersed units,
their design software suggest that the lowest cost design to meet
baseline efficiency standards is using an amorphous core transformer.
Despite this lower first cost, stakeholders have regularly stated that
amorphous cores make up a very small percentage of the current
distribution transformer market. DOE models amorphous core transformers
across a range of efficiencies. Due to the substantial reduction in no-
load losses associated with amorphous cores, a baseline transformer
with an amorphous core can meet DOE 2016 efficiency standards with very
little investment into the transformer windings. In
[[Page 29913]]
evaluating higher efficiency models with amorphous cores, DOE designs
include additional investment in the transformer windings which reduce
load losses. DOE incorporates both the additional costs in the
transformer core and the investment in the transformer windings in its
analysis.
Schneider commented that lower losses correspond to lower
impedance, which will increase the let-through current during short
circuits. Schneider stated that this will increase the required ratings
for connected equipment and impact system arc flash studies and
protection for workers. Schneider further commented that impedance
limits the impact of harmonics, which protects sensitive electronic
loads. Schneider added that lower impedance will reduce voltage drop
internal to LVDT devices. (Schneider, No. 101 at p. 14) APPA commented
that while within the ``normal'' impedance ranges, amorphous
transformers tend to have lower impedance which increases likelihood of
an extremely high fault current. (APPA, No. 103 at p. 13) NEMA
commented that higher efficiency standards met with GOES results in low
impedance levels and anything below 4 percent or preferably 5 percent
makes it difficult to design power systems and choose circuit breakers
or fuses to handle fault currents. (NEMA, No. 141 at p. 6)
Metglas commented that impedance is fixed at 5.75 percent for units
above 500 kVA and easily varied for smaller units. (Metglas, No. 125 at
p. 5)
In the January 2023 NOPR, DOE discussed that the design options
considered in the engineering analysis, including those that utilize
amorphous metal, span a range of impedance values within the ``normal
impedance'' range, as currently defined. 88 FR 1722, 1743. The design
options considered in this final rule continue to span a range of
impedance values at higher efficiency levels, both for designs that
utilize GOES and those that utilize amorphous metal. Further, DOE notes
that, while lower-loss transformer designs often have lower impedances,
higher efficiency does not necessarily correlate to lower impedance.
Based on a review of manufacturer literature, DOE found that
manufacturers often provide a range of impedance values for a given
design, with customers able to request a specific impedance range to
fit their application. DOE also observed transformers of varying levels
of efficiency that provide the same impedance
offerings.117 118 119 This indicates that options exist to
increase transformer impedance, even for higher efficiency
transformers. Therefore, in this final rule, DOE did not further
separate transformers based on impedance, aside from ensuring that a
range of normal impedance values are available at higher efficiency
levels.
---------------------------------------------------------------------------
\117\ Powersmiths, E-Saver Opal Series, Available at: https://www.powersmiths.com/products/transformers/e-saver-opal-series/
(accessed on 3/17/2024).
\118\ Eaton, General Purpose Ventilated Transformers, Available
at: https://www.eaton.com/us/en-us/catalog/low-voltage-power-distribution-controls-systems/ventilated-general-purpose-transformers.html (accessed on 3/17/2024).
\119\ Hammond Power Solutions, HPS Sentinel Energy Efficient
Distribution Transformers, Available at: https://americas.hammondpowersolutions.com/products/low-voltage-distribution/general-purpose-transformers (accessed on 3/17/2024).
---------------------------------------------------------------------------
e. kVA Scaling
In the January 2023 NOPR, DOE proposed to expand the scope of the
distribution transformer definition to include units up to 5,000 kVA.
88 FR 1722, 1746 To assess the impact and potential energy savings
associated with the expanded scope, DOE modeled three new
representative units by using the scaling rules for transformer
dimensions, weight, no-load losses, and load losses. 88 FR 1722, 1759-
1760. DOE noted that it only includes distribution transformers in its
downstream analysis if they would meet or exceed current energy
conservation standards. Because transformers greater than 2,500 kVA
have not historically been subject to energy conservation standards,
DOE relied on the consumer choice model to determine the efficiency of
a typical baseline unit that would be selected in the present market
based on lowest first-cost. DOE did not consider any units which did
not meet or exceed the efficiency of this assumed baseline unit. Id.
DOE requested comment on its approach to modeling these high-kVA
transformers.
DOE received numerous comments about scaling of design data for
units beyond 2,500 kVA.
Several stakeholders noted that the percentage that stray and eddy
losses contribute to load losses increases substantially at high-
current values, which typically correspond to high-kVA ratings.
Therefore, the 0.75 loss scaling cited by DOE does not hold when
scaling to larger kVA ratings. (Eaton, No. 137 at p. 23; Prolec GE, No.
120 at pp. 7-9; HVOLT, No. 134 at pp. 6-7; Howard, No. 116 at p. 14;
NEMA, No. 141 at p. 5; NEMA, No. 141 at p. 14; Powersmiths, No. 112 at
p. 3)
Prolec GE commented that several of the high-kVA rated designs
would be forced to use amorphous under the proposed standards because
manufacturers would not be able to meet the proposed efficiency levels
even with GOES and copper windings. (Prolec GE, No. 120 at p. 3) NEMA
commented that for high-current transformers, it would be impractical
to meet the NOPR efficiency levels with GOES as the flux density would
be forced to such low values to make up for the increased buss and load
losses. (NEMA, No. 141 at pp. 5-6)
Howard commented that designing transformers to meet the NOPR
efficiency levels is technically feasible for transformers 2,500 kVA
and less. However, the proposed standards beyond 2,500 kVA are not
feasible and therefore DOE should not include them in any amended
efficiency standards. (Howard, No. 116 at p. 5) Howard and HVOLT stated
that they have not been able to develop any valid designs, even with
amorphous cores, that meet the proposed standards at 3,750 kVA or 5,000
kVA. (Howard, No. 116 at p. 14; HVOLT, No. 134 at p. 7)
Eaton speculated that OPS modeling uses a constant stray loss
percentage, which could significantly underestimate the percentage of
load losses made up by stray losses for large kVA values. (Eaton, No.
137 at pp. 23-25) DOE notes that stray losses vary based on the design
specifications of each specific unit modelled using the OPS design
software and are not applied as a constant percentage of load losses.
Eaton noted that improper scaling of stray losses in DOE's analysis
may result in an overestimation of the efficiencies that can be
achieved and an underestimation of the transformer costs. (Eaton, No.
137 at p. 25) NEMA commented that for large kVA, high-current designs,
stray and eddy losses can make up nearly 80 percent of the total load
losses. (NEMA, No. 141 at pp. 13-14) HVOLT stated that stray and eddy
losses can increase the load losses of a transformer over 3,000 kVA by
as much as 50 percent. (HVOLT, No. 134 at p. 6)
Eaton commented and provided data to show that as conductor sizes
increase to meet higher efficiency standards, stray losses increase as
a percentage of total load losses. (Eaton, No. 137 at p. 23) Eaton's
data shows that a baseline transformer has stray and eddy losses which
make up about 15 percent of total load losses, whereas at max-tech,
stray and eddy losses make-up 30 percent of load losses. (Eaton, No.
137 at p. 23)
Howard stated that the scaling DOE used to estimate the performance
of
[[Page 29914]]
3,750 kVA units is not accurate due to the unique challenges associated
with the high-current densities in these units. (Howard, No. 116 at p.
15) HVOLT commented that the 0.75 scaling relationship is only accurate
over a narrow band of parameters and noted that scaling to high kVA
ratings could result in underestimating winding losses by more than 50
percent. (HVOLT, No. 134 at p. 6) Howard recommended DOE refer to Annex
G of IEEE C57.110-2018 to review industry data on stray and eddy losses
and their relationship with kVA. (Howard, No. 116 at p. 16)
Eaton referenced DOE's compliance certification management system
(CCMS) database and noted that the maximum reported percentage
efficiencies do not increase beyond 1,000 kVA. Eaton stated this was
evidence that the 0.75 scaling relationship does not hold for higher
kVA values. (Eaton, No. 137 at pp. 27-28) Eaton noted that in
evaluating the max-tech in their design software, some of the proposed
standards for high-kVA transformers were near the technological limit,
indicating a potential flaw in the 0.75 scaling relationship. (Eaton,
No. 137 at p. 22)
Regarding scaling generally, NEMA commented that the 0.75 scaling
relationship is only applicable across narrow kVA ranges. (NEMA, No.
141 at p. 4) NEMA commented that one of their members looked at their
design data for MVDT transformers to investigate how accurate scaling
transformer costs, no-load losses, and load losses from a 1,500 kVA and
300 kVA transformer were. (NEMA, No. 141 at p. 4) NEMA's member found
that the actual scaling factor can vary widely and at times can be much
more or much less than the DOE scaling factors. (NEMA, No. 141 at p. 4)
NEMA stated that this variability was a result of constraints on wire
sizes, impedance ranges, and construction requirements which can result
in considerably different scaling relationships. (NEMA, No. 141 at p.
5) NEMA identified the small wire sizes associated with small kVA
transformers as a very expensive component that skews the cost curve
for small kVA units. (NEMA, No. 141 at p. 5) NEMA commented that the
NOPR scaling factors only results in costs and losses that are within 5
percent across a small range of kVA values and not across the entire
range of kVA values. (NEMA, No. 141 at p. 4)
Eaton provided data demonstrating how the max-tech in their design
software varies based on secondary winding voltage and kVA. (Eaton, No.
137 at p. 18) Eaton's data shows that max-tech efficiency percentages
tend to increase as the kVA increase up until a certain point. (Eaton,
No. 137 at p. 18) Beyond that point, the current, and specifically the
additional stray and eddy losses associated with the higher currents,
can make a considerable difference as to the max-tech at a given kVA.
(Eaton, No. 137 at p. 18) Eaton's data shows that for a 480Y/277
secondary voltage, the maximum efficiency occurs around 1,500 kVA.
(Eaton, No. 137 at p. 18)
Based on the comments received, DOE re-evaluated the accuracy of
the OPS modeling of stray and eddy losses for the 1,500 kVA units and
how that modeling varies for high-current transformers. For DOE's
modeled RU5, corresponding to a 1,500 kVA distribution transformer with
480Y/277 secondary, OPS modeling indicates that stray and eddy losses
as a percentage of total load losses typically vary with design and
with efficiency. While the exact percentage varies depending on the
unique design specifications (e.g., efficiency, whether copper or
aluminum windings are used, core steel, etc.) the stray and eddy losses
for most designs make up between 10-20 percent of total load losses.
These values align well with the percentage of stray losses submitted
in Eaton's comment for a similar unit and many of the stray and eddy
values listed in Annex G of IEEE C57.110-2018. Therefore, DOE has
concluded that the OPS modeling accurately accounts for stray and eddy
losses.
Regarding the scaling of these OPS modeled representative units to
other kVA ratings that are not individually modeled, DOE notes that
scaling of units using power laws requires a variety of assumptions to
remain valid. In chapter 5 of the TSD, DOE notes that these scaling
relationships are valid if the core configuration, core material, core
flux density, current density, physical proportions, eddy loss
proportion, and insulation space factor are all held constant. DOE
notes that in practical applications, it is rare that all of these are
constant; however, scaling relationships can be used to establish
reasonable estimates of performance.
Real world data can vary depending on what variables are changing
between transformer designs. The data submitted by NEMA suggests that
material cost scaling can be as low as 0.14 or as high as 1.13, no-load
loss scaling can be as low as 0.33 or as high as 0.88, and load loss
scaling can be as low as 0.51 or as high as 1.02. IEEE C57.110-2018
shows real world load loss scaling data with transformer kVA for solid
cast transformers from 630 kVA to 20 MVA. These data show load loss
scaling of 0.76. Data submitted by Eaton show that DOE's max-tech
efficiency for 3-phase liquid-immersed distribution transformers are
within a few tenths of a percentage point for the vast majority of kVA
ratings, but the accuracy can vary depending on the current in the
transformer.
All of the data identified by manufacturers indicate that for the
vast majority of the kVA ranges, the scaling laws used in the NOPR are
sufficient to provide reasonable estimates of performance, dimensions,
costs, and losses. Stakeholder data also indicate that when the stray
and eddy losses increase substantially, those scaling relationships may
be less accurate.
However, stakeholders are correct in pointing out that for very
high currents, stray and eddy losses may increase substantially such
that it becomes much more difficult to meet efficiency standards. As
noted in section IV.A.2.c of this document, industry standards
recommend high-kVA transformers have higher-secondary voltages. As
such, currents do not tend to reach problematic values. Beyond 1,500
kVA, there tend to be considerably more 480Y/277 secondary voltages and
208Y/120 voltages become relatively rare. However, if a manufacturer
were to build a transformer with a very high-secondary current, the
stray and eddy losses would make up a much greater percentage of the
transformer load losses and, as such, the losses would scale at a
higher factor. This was pointed out by numerous manufacturers who
stated that DOE's proposed standards at 3,750 kVA may become
technologically impossible.
To account for the change in scaling relationships that occur for
high kVA transformers with high currents, DOE has established and
evaluated a separate equipment class for large three-phase transformers
with kVA ratings greater than or equal to 500 kVA, as discussed in
section IV.A.2.c of this document. DOE has also revised its high-kVA
scaled representative units to account for the increase in load losses
that occurs as a result of growing stray and eddy losses. These scaling
factors are discussed in chapter 5 of the TSD.
2. Cost Analysis
The cost analysis portion of the engineering analysis is conducted
using one or a combination of cost approaches. The selection of cost
approach depends on a suite of factors, including the availability and
reliability of public information, characteristics of the regulated
product, and the availability and timeliness of
[[Page 29915]]
purchasing the equipment on the market. The cost approaches are
summarized as follows:
Physical teardowns: Under this approach, DOE physically
dismantles a commercially available product, component-by-component, to
develop a detailed bill of materials for the product.
Catalog teardowns: In lieu of physically deconstructing a
product, DOE identifies each component using parts diagrams (available
from manufacturer websites or appliance repair websites, for example)
to develop the bill of materials for the product.
Price surveys: If neither a physical nor catalog teardown
is feasible (e.g., for tightly integrated products such as fluorescent
lamps, which are infeasible to disassemble and for which parts diagrams
are unavailable), cost-prohibitive, or otherwise impractical (e.g.
large commercial boilers), DOE conducts price surveys using publicly
available pricing data published on major online retailer websites and/
or by soliciting prices from distributors and other commercial
channels.
In the present case, DOE conducted the analysis by applying
material prices to the distribution transformer designs modeled by OPS.
The resulting bill of materials provides the basis for the manufacturer
production cost (MPC) estimates for products at various efficiency
levels spanning the full range of efficiencies from the baseline to
max-tech. Markups are applied these MPCs to generate manufacturer
selling prices (MSP). The primary material costs in distribution
transformers come from electrical steel used for the core and the
aluminum or copper conductor used for the primary and secondary
winding. In the January 2023 NOPR, DOE noted that while prices have
been up in recent years, it is difficult to say for certain how prices
will vary in the medium to long term and, therefore, DOE relies on a 5-
year average in its base scenario and evaluates how the results would
change with different pricing scenarios. 88 FR 1722, 1765.
Regarding the cost analysis generally, WEC commented that based on
information received from manufacturers, the costs used to support the
NOPR are out of date and do not reflect current costs. (WEC, No. 118 at
p. 1) APPA commented that DOE did not consider the recent rapid
increases in transformer costs; APPA provided data indicating that the
cost of transformers has increased substantially since 2018. (APPA, No.
103 at p. 7-8)
DOE data confirm that prices for distribution transformers have
been up significantly from their historical averages. However, it is
difficult to say for certain how those prices will vary in the medium
to long term. The distribution transformer producer price index was
approximately constant between 2010 and 2020, a time period that
included implementation of two sets of energy efficiency standards
(initial standards went into effect in 2010 and amended standards went
into effect in 2016). Beginning in 2021, the producer price index of
distribution transformers began to increase substantially through mid-
2022. Since mid-2022, prices have remained approximately constant.
As discussed in section IV.A.5 of this document, the current
distribution transformer shortage is largely driven by a supply-demand
imbalance that exists across both distribution transformers and many
electric and grid-related products. Considerable manufacturer
investments in capacity increases have been publicly announced,
including new locations which serve to expand accessible local labor
markets. However, it is difficult to predict with certainty how the
price of distribution transformers will vary when supply rises
sufficiently to expected demand. DOE continues to rely on a 5-year
average in its analysis.\120\ The five-year period preceding this
rulemaking includes price increases in addition to those accounted for
in the NOPR. Accordingly, material and transformer prices are generally
higher in this final rule than in the NOPR. Additional comments on
specific material prices are discussed in the sections that follow.
---------------------------------------------------------------------------
\120\ Engineering results with current pricing are included in
Appendix 5B of the TSD.
---------------------------------------------------------------------------
a. Electrical Steel Prices
Electrical steel is one of the main material costs in distribution
transformers and as such makes up a significant percentage of
manufacturer production costs. Using lower-loss core materials is one
of the primary tools for improving the energy efficiency of
distribution transformers. As such, the relative costs associated with
transitioning from the current baseline core materials to lower-loss
core materials has a considerable impact on the cost effectiveness of
amended efficiency standards.
In the January 2023 NOPR, DOE relied on 5-year average pricing for
the various grades of electrical steel evaluated. 88 FR 1722, 1765-
1767. In response to stakeholder comments submitted on the August 2021
Preliminary Analysis TSD that amended standards may introduce higher
volatility that may make 5-year average prices inaccurate, DOE stated
that historically, when amended standards have been adopted, core
material manufacturers have increased capacity of the electrical steel
grades needed to meet amended efficiency standards. Id.
DOE stated that substantial volatility has characterized the U.S.
steel market, including the existing transformer core steel market,
over the last several decades. From 2000 to 2007, U.S. steel markets,
and more specifically the U.S. electrical steel market, began to
experience pressure from several directions. Demand in China and India
for high-efficiency, grain-oriented core steel contributed to increased
prices and reduced global availability. Cost-cutting measures and
technical innovation at their respective facilities, combined with the
lower value of the U.S. dollar, enabled domestic core steel suppliers
to become globally competitive exporters.
In late 2007, the U.S. steel market began to decline with the onset
of the global economic crisis. U.S. steel manufacturing declined to
nearly 50 percent of production capacity utilization in 2009 from
almost 90 percent in 2008. Only in China and India did the production
and use of electrical grade steel increase for 2009.\121\ In 2010, the
price of steel began to recover. However, the recovery was driven more
by increasing costs of material inputs, such as iron ore and coking
coal, than broad demand recovery.
---------------------------------------------------------------------------
\121\ International Trade Administration. Global Steel Report.
Available at legacy.trade.gov/steel/pdfs/global-monitor-report-2018.pdf (last accessed Sept. 1, 2022).
---------------------------------------------------------------------------
In 2011, core steel prices again fell considerably. At this time,
China began to transition from a net electrical steel importer to a net
electrical steel exporter.\122\ Between 2005 and 2011, China imported
an estimated 253,000 to 353,000 tonnes of electrical steel. During this
time, China added significant domestic electrical steel production
capacity, such that from 2016 to 2019 only about 22,000 tonnes were
imported to China annually. China also exported nearly 200,000 tonnes
of electric steel annually by the late 2010s.
---------------------------------------------------------------------------
\122\ Capital Trade Incorporated, Effective Trade Relief on
Transformer Cores and Laminations, 2020. Submitted as part of AK
Steel comment at Docket No. BIS-2020-0015-0075 at p. 168.
---------------------------------------------------------------------------
Many of the exporters formerly serving China sought new markets
around 2011, namely the United States. The rise in U.S. imports at this
time hurt domestic U.S. steel manufacturers, such that in 2013,
domestic U.S. steel stakeholders filed anti-dumping and countervailing
duty petitions with the U.S. International Trade
[[Page 29916]]
Commission.\123\ The resulting investigation found, however, that
``industry in the United States is neither materially injured nor
threatened with material injury by reason of imports of grain-oriented
electrical steel . . . to be sold in the United States at less than
fair value.'' \124\
---------------------------------------------------------------------------
\123\ U.S. International Trade Commission, Grain-Oriented
Electrical Steel from Germany, Japan, and Poland, Investigation Nos.
731-TA-1233, 1234, and 1236. September 2014.
\124\ Id.
---------------------------------------------------------------------------
In the amorphous ribbon market, the necessary manufacturing
technology has existed for many decades and has been used in
distribution transformers since the late 1980s.\125\ In many countries,
amorphous ribbon is widely used in the cores of distribution
transformers.\126\ Significant amorphous ribbon use tends to occur in
regions with relatively high valuations on losses (e.g., certain
provinces of Canada, certain U.S. municipalities).
---------------------------------------------------------------------------
\125\ DeCristofaro, N., Amorphous Metals in Electric-Power
Distribution Applications, Material Research Society, MRS Bulletin,
Volume 23, Number 5, 1998.
\126\ BPA's Emerging Technologies Initiative, Phase 1 report:
High Efficiency Distribution Transformer Technology Assessment,
April 2020. Available at www.bpa.gov/EE/NewsEvents/presentations/Documents/Transformer%20webinar%204-7-20%20Final.pdf.
---------------------------------------------------------------------------
Beginning in 2018, the U.S. government instituted a series of
import duties on aluminum and steel articles, among other items. Steel
and aluminum articles were generally subject to respective import
duties of 25 and 10 percent ad valorem.127 83 FR 11619; 83
FR 11625. Since March 2018, several presidential proclamations have
created or modified steel and aluminum tariffs, including changes to
the products covered, countries subject to the tariffs, exclusions,
etc.\128\
---------------------------------------------------------------------------
\127\ Ad valorem tariffs are assessed in proportion to an item's
monetary value.
\128\ Congressional Research Service, Section 232
Investigations: Overview and Issues for Congress, May 18, 2021,
Available at fas.org/sgp/crs/misc/R45249.pdf.
---------------------------------------------------------------------------
Another recent trend in distribution transformer manufacturing is
an increase in the rate of import or purchase of finished core
products. The impact of electrical steel tariffs on manufacturers'
costs varies widely depending on if manufacturers are purchasing raw
electrical steel and paying a 25-percent tariff on imported steel, or
if they are importing finished transformer cores which, along with
distribution transformer core laminations and finished transformer
imports, are not subject to the tariffs. Some stakeholders have argued
that this trend toward importing distribution transformer cores,
primarily from Mexico and Canada, is a method of circumventing tariffs,
as electrical steel sold in the global market has been less expensive
than domestic electrical steel on account of being allegedly unfairly
traded.129 130 Conversely, other stakeholders have commented
that this trend predated the electrical steel tariffs and that
importation of transformer components is often necessary to remain
competitive in the U.S. market, given the limited number of domestic
manufacturers that produce transformer laminations and
cores.131 132
---------------------------------------------------------------------------
\129\ (AK Steel, Docket No. BIS-2020-0015-0075 at pp. 43-58).
\130\ (American Iron and Steel Institute, Docket No. BIS-2020-
0015-0033 at pp. 2-5).
\131\ (Central Maloney Inc., Docket No. BIS-2020-0015-0015 at p.
1).
\132\ (NEMA, Docket No. BIS-2020-0015-0034 at pp. 3-4).
---------------------------------------------------------------------------
On May 19, 2020, the U.S. Department of Commerce (DOC) opened an
investigation into the potential circumvention of tariffs via imports
of finished distribution transformer cores and laminations. 85 FR
29926. On November 18, 2021, DOC published a summary of the results of
their investigation in a notice to the Federal Register. The report
stated that importation of both GOES laminations and finished wound and
stacked cores has significantly increased in recent years, with
importation of laminations increasing from $15 million in 2015 to $33
million in 2019, and importation of finished cores increasing from $22
million in 2015 to $167 million in 2019. DOC attributed these
increases, at least in part, to the increased electrical steel costs
resulting from the imposed tariffs on electrical steel. In response to
its investigation, DOC stated it is exploring several options to shift
the market toward domestic production and consumption of GOES,
including extending tariffs to include laminations and finished cores.
No trade action has been taken at the time of publication of this final
rule. 86 FR 64606.
More recently, DOE learned from stakeholders during manufacturer
interviews and from public comments that pricing of electrical steel
has risen such that in the current market, the price of foreign
electrical steel, without any tariffs applied, is similar to the price
of domestic steel. (Powersmiths, No. 46 at p. 6; Carte, No. 54 at p. 3)
These recent price increases, particularly in foreign-produced
electrical steel, were cited as being a result of both general supply
chain complications and increased demand for non-oriented electrical
steel from electric motor applications. (NEMA, No. 50 at p. 9;
Powersmiths, No. 46 at p. 5; Zarnowski, Public Meeting Transcript, No.
40 at p. 36; Looby, Public Meeting Transcript, No. 40 at p. 37)
For the January 2023 NOPR, DOE stated that rather than constructing
sensitivity analysis scenarios to reflect every potential combination
of factors that may affect steel pricing, DOE relies on a 5-year
average pricing for its core steel. DOE requested comment on the
market, prices, and barriers to added capacity for both amorphous and
GOES. 88 FR 1722, 1767.
Regarding the impact of other products on GOES and amorphous
supply, Howard agreed that the price of GOES has increased
significantly based on NOES becoming a more valuable investment and
utilizing similar production equipment to GOES, thereby occupying some
of the production capacity that otherwise would produce GOES, leading
to material shortages of GOES. (Howard, No. 116 at p. 5) ABB commented
that shortages of domestic GOES and likely amorphous would require
transformer manufacturers to import electrical steel and bear the cost
of tariffs, adding to the cost of transformers. (ABB, No. 107 at p. 3)
Howard commented that competition for amorphous ribbon is limited
to low-volume and niche products, including brazing foil and high-
frequency transformers. (Howard, No. 116 at p. 18) Metglas added that
amorphous is almost exclusively used in distribution transformers,
without other significant sources of competition. (Metglas, No. 125 at
pp. 5-6) Efficiency and Climate Advocates commented that the proposed
rule will improve the transformer supply chain because amorphous does
not have as much price competition from EVs as GOES. (Efficiency and
Climate Advocates, No. 154 at p. 1)
NAHB commented that amorphous metals are used in aerospace, medical
devices, electric motor parts, and robotics. (NAHB, No. 106 at pp. 10-
11) NAHB stated that demand for both amorphous metals and GOES will
continue to increase due to grid modernization. Id. NAHB stated that,
although amorphous metals are not suited to EV motors, they are well
suited for other applications in EV manufacturing and will experience
increased demand within that segment of the automotive market. (NAHB,
No. 106 at pp. 10-11)
Stakeholder comments confirm that competition from other products
is greater for GOES than it is for amorphous. These statements
generally confirm DOE's January 2023 NOPR observations as to how the
price of
[[Page 29917]]
GOES has risen more in the previous 5-years than the price of amorphous
alloy.
Southwest Electric commented that the five-year average price of
GOES is much lower than the current price of GOES and therefore DOE
should update its cost models to reflect the more likely costs from
2023-2027, rather than incorporating the discounted prices that existed
between 2017 and 2021. (Southwest Electric, No. 87 at p. 3) NEMA
commented that the pricing of GOES is impacted by global demand and
stated that some foreign manufacturers of GOES have committed part of
their production capacity to serving their domestic markets. As such,
this foreign GOES capacity is no longer available to serve the U.S.
transformer market. (NEMA, No. 141 at p. 14) NAHB stated that energy
rationing policies in China increased electrical steel prices in 2021-
22 and, although prices have begun to stabilize, they are expected to
increase again as demand for GOES and NOES rises. (NAHB, No. 106 at p.
11) Webb questioned whether the tariffs were exacerbating industry
challenges. (Webb, No. 133 at p. 2) Carte commented that the market
should decide what steel to use, stating that the recent increase in
GOES prices paired with increased competition from NOES might naturally
shift the market toward increased usage of amorphous material. (Carte,
No. 140 at pp. 4-5)
DOE reiterates that there are a number of factors that can impact
core material pricing, including competition from other markets,
disruptions to supply chains, trade actions from both the U.S. and
foreign countries, and increased demand. DOE has updated its base
material prices in this final rule based on 5-year averages to capture
more recent pricing trends as well as broader market developments. In
general, the five-year average prices in this final rule are greater
than the prices in the January 2023 NOPR, consistent with the
observations from stakeholders.
DOE received numerous comments suggesting that the future price of
materials could be dependent on DOE's policy choice as to whether to
amend efficiency standards.
Howard commented that revised standards would further increase the
demand for GOES and that its preliminary data shows transformer prices
could be 50-125-percent greater than today's prices. (Howard, No. 116
at p. 5) Prolec GE stated that electrical steel price volatility is
expected to continue or become worse unless current supply and demand
issues are resolved. (Prolec GE, No. 120 at pp. 10-11) Prolec GE added
that increased demand coupled with limited supply for lower-loss
steels, both amorphous and GOES, will lead to price hikes. (Prolec GE,
No. 120 at pp. 10-11) Regarding the price of amorphous ribbon, Eaton
commented that DOE should consider the possibility that amorphous
prices will increase to curtail demand, causing distribution
transformer prices to increase 50-100 percent whether GOES or amorphous
is used. (Eaton, No. 137 at p. 26)
Metglas commented that the price of amorphous ribbon has been
stable relative to GOES over the last decade and additional amorphous
ribbon capacity would drive down the fixed costs of amorphous ribbon
and cores, which would improve the value of amorphous relative to GOES.
(Metglas, No. 125 at pp. 5-6)
DOE notes that both GOES and amorphous core production tend to
carry volume-based efficiencies. In Canadian markets, stakeholders have
noted that while amorphous core transformers previously had a 10% cost-
delta relative to GOES transformers, that cost-delta has fallen such
that costs today are ``more or less even'' with GOES transformers.\133\
DOE further notes that the adopted standards include equipment classes
with substantial volume where both GOES and amorphous are expected to
be cost-competitive. DOE also notes that the compliance period for
amended standards has been extended, from the 3-year compliance period
proposed in the January 2023 NOPR to a 5-year compliance period adopted
in this final rule. As discussed further below, DOE has considered
comments at to what length of compliance period is necessary to ensure
a competitive market.
---------------------------------------------------------------------------
\133\ Bonneville Power Administration, Low-Voltage Liquid
Immersed Amorphous Core Distribution Transformers. 2022. Available
at www.bpa.gov/-/media/Aep/energy-efficiency/emerging-technologies/ET-Documents/liquid-immersed-dist-transformers-final-22-02-16.pdf
(last accessed Oct. 30, 2023).
---------------------------------------------------------------------------
Howard commented that, while current cost structures indicate
amorphous is the cost effective option for meeting the proposed
efficiency standards, shortages of amorphous would increase amorphous
costs and decrease GOES costs, meaning GOES could remain a cost
effective option. (Howard, No. 116 at p. 3) Howard commented that both
amorphous and GOES prices are expected to increase due to tariffs and
increased demand due to the larger cores needed to meet the proposed
efficiency standards. (Howard, No. 116 at p. 17) TMMA commented that
the challenges associated with transitioning to amorphous cores will
cause a further increase in the cost of producing and delivering a
transformer, which will ultimately be borne by consumers. (TMMA, No.
138 at p. 3) WEG commented that the constrained supply of amorphous
metal will significantly increase the cost of distribution
transformers, amassing to $20M when applied across all of WEG's
products. (WEG, No. 92 at p. 2) APPA commented that its current quotes
from one vendor indicate that there would be a significant increase in
costs if purchasing amorphous core transformers. (APPA, No. 103 at
pp.7-8)
Prolec GE commented that DOE's analysis underestimates incremental
costs because it is unrealistic that the market will fully transition
to amorphous cores. (Prolec GE, No. 120 at p. 3) Prolec GE commented
that, because the supply of amorphous ribbon is insufficient to serve
the present market, manufacturers would be required to produce GOES
transformers with a 40-70-percent increase in incremental cost. (Prolec
GE, No. 120 at p. 2) TMMA added that an insufficient supply of
amorphous will force manufacturers to use GOES to meet standards,
leading to heavier transformers and higher costs that will be passed on
to consumers. (TMMA, No. 138 at pp. 3-4) Southwest Electric stated that
amorphous prices should be updated as well to reflect the expected cost
increases that would occur if DOE's NOPR efficiencies go into effect in
2027. (Southwest Electric, No. 87 at p. 3) Powersmiths commented that
DOE's costing estimate for amorphous transformers is flawed because a
5-year average includes low demand of the Covid pandemic period and
does not properly reflect current market prices, which are nearly
double and not expected to decline. (Powersmiths, No. 112 at p. 3)
Prolec GE commented that heavy investments in increasing amorphous
production capacity would be required to meet demand, implying that an
ROI cost would be added for new production. (Prolec GE, No. 120 at p.
10) Alliant Energy commented in support of numerous manufacturers who
expressed concern that conversion to amorphous cores by 2027 would
increase prices and worsen existing supply chain concerns. (Alliant
Energy, No. 128 at p. 2)
As noted, the current market for distribution transformers is
experiencing an imbalance in supply and demand that has led to price
increases for distribution transformers in recent years. This has also
led to an increase in the price of GOES material needed to build
distribution transformers. Compounding these price
[[Page 29918]]
increases is the fact that there is only a single domestic supplier of
GOES and, with tariffs on imported electrical steel, domestic
transformer manufacturers are generally limited to purchasing M3 \134\
steel from the single domestic GOES supplier. Manufacturers do have the
option of purchasing electrical steel from global suppliers, but that
would mean paying a 25-percent tariff and result in even higher
electrical steel prices. These factors have left manufacturers with a
limited supply of core material available for distribution transformer
production.
---------------------------------------------------------------------------
\134\ M3 steel is the short-hand naming convention for
conventional (i.e., not high-permeability) GOES that is 0.23 mm
thick. It makes up the majority of domestically produced GOES used
in distribution transformers in the U.S.
---------------------------------------------------------------------------
In theory, manufacturers--under current standards--have the option
of building amorphous transformers if the price of GOES transformers
becomes prohibitively expensive. However, amorphous transformers
require different capital equipment, meaning that manufacturers cannot
easily switch between amorphous and GOES without new capital
investments. As a result, the demand for GOES steel has increased by
more than the demand for amorphous ribbon.
Data submitted in Eaton's comment indicates that for a 1,500 kVA,
3-phase liquid immersed transformer, an amorphous transformer is less
expensive at baseline than a GOES transformer. Further, the proposed
efficiency levels can be met with virtually zero incremental costs
relative to a GOES transformer meeting efficiency standards today. If
DOE applied current spot prices, as stakeholders have suggested, the
baseline GOES transformer would get considerably more expensive while
amorphous costs would remain relatively steady.
Regarding stakeholder concerns that incremental costs will be
greater than DOE's analysis predicts due to a limited supply of
amorphous metal, DOE notes that it has constrained the consumer choice
model in this final rule to reflect the actions manufacturers will take
given their existing production equipment and concerns over core steel
supply. Specifically, consumers are assumed to meet standards with GOES
up to EL 2. (See section IV.F.3.a of this document). Further, the
adopted standards are expected to be met via a combination of GOES and
amorphous core steel, such that a limited supply of amorphous ribbon
will not be a constraining factor in meeting amended standards. As
such, DOE does not anticipate the supply of amorphous metal to become
significantly constrained as a result of standards such that the
incremental costs modeled in DOE's analysis to meet amended efficiency
standards would greatly increase. Eaton expressed concern that relying
on a single supplier of amorphous could create a virtual monopoly that
would prevent competition from keeping prices in check. Accordingly,
Eaton recommended DOE consider providing pricing and availability
assurances until the market can create additional competition. (Eaton,
No. 137 at p. 27) NEMA commented that it anticipates production of
amorphous cores to be the bottleneck in meeting the NOPR efficiency
standards. (NEMA, No. 141 at p. 14) NEMA stated that because it knew of
just one domestic manufacturer of amorphous cores, there would likely
be a dramatic increase in material price if the entire market is
reliant on a single supplier. (NEMA, No. 141 at p. 14) NEMA commented
that the NOPR would establish a monopoly on amorphous ribbon, which
will increase costs and lead times. (NEMA, No. 141 at p. 3) NRECA
commented that the proposed standards could eliminate production of
GOES while likely creating a monopoly supplier for amorphous. (NRECA,
No. 98 at p. 3)
Regarding the notion that amended efficiency standards would
significantly increase amorphous material prices by providing a
monopoly to the single domestic supplier, DOE notes that the current
distribution transformer market operates with a single domestic
supplier of GOES and multiple foreign suppliers. As discussed in
section IV.A.4.a of this document, in the presence of amended
standards, the distribution transformer market is expected to be
subject to the same dynamics present in the current market, even at
efficiency levels expected to be met with amorphous.
DOE does not assume having a single domestic supplier of GOES leads
to monopolistic pricing. DOE notes that domestic GOES experiences
competition from foreign-produced GOES. While direct imports of raw
GOES are subject to tariff, transformer cores and laminations are not
subject to tariffs. As previously discussed, transformer manufacturers
rely on a combination of domestic steel--to produce their own cores--
and imported cores (that use foreign-produced steel).
Similarly, DOE does not assume that because there is currently only
a single domestic supplier of amorphous today, that there will be
monopolistic pricing of amorphous in the presence of amended efficiency
standards. Similar to GOES transformers, amorphous ribbon experiences
competition from foreign-produced amorphous for which direct imports
are subject to tariffs but transformer cores are not. In both cases,
there are foreign competitors and opportunity for other suppliers to
enter the market.
However, there is uncertainty in the short-term price of electrical
steel, with a variety of factors impacting core steel pricing. Short-
term prices could be driven by policy decisions and decisions of select
market actors, including decisions made by distribution transformer
manufacturers, amorphous ribbon manufacturers, and GOES steel
manufacturers. The current market has limited supply of both amorphous
and GOES steel with better loss performance than M3. Long-term pricing
is driven by supply and demand, as well as the prices of the underlying
commodities. DOE's updated 5-year pricing is intended to estimate a
competitive market for core materials. While many factors are
influencing competition in the distribution transformer market, the
variety of supply pathways to produce transformers (e.g., domestically
producing transformer core, importing transformer cores and
domestically producing transformers, or importing finished
transformers) support the continued existence of a competitive market
for core materials in the long-term.
Further, DOE notes while the majority of the distribution
transformer shipments can meet adopted efficiency standards using
either GOES or amorphous, for certain equipment classes DOE is adopting
standards at EL4, which is likely to be met via amorphous cores. The
expected increase in amorphous core production equipment to meet the
adopted standards for equipment classes set at EL4 is likely to send a
demand signal to amorphous alloy producers, thereby increasing
amorphous supply. Further, because amorphous core production equipment
can manufacture a range of transformer sizes, it is likely that
additional competition will occur between GOES and amorphous core
equipment classes set at EL2 for liquid-immersed distribution
transformers.
Efficiency standards have a multi-year compliance period and
stakeholders are able to plan and invest such that a competitive market
exists. Indeed, DOE notes that the compliance period for amended
standards has been extended, from the 3-year compliance period proposed
in the January 2023 NOPR to a 5-year compliance period adopted in this
final rule. As previously discussed, DOE has considered comments at to
[[Page 29919]]
what sort of compliance period is necessary to ensure a market for GOES
and amorphous steel sufficiently robust and competitive to provide
adequate supply to the distribution transformer market to allow
manufacturers to meet demand at the efficiency standards adopted.
EEI commented that the proposed standards are in violation of EPCA
because there is not a sufficient supply of amorphous metal capacity to
replace GOES, making it likely that the available supply of compliant
distribution transformers will be reduced. EEI stated that the
conversion to amorphous will result in significant downtime for
distribution transformer production lines, limiting production capacity
in the near to medium term. (EEI, No. 135 at pp. 12-17) EEI added that
the proposed standards will require significant changes across the
entire value chain for distribution transformers, which raises concerns
regarding the practicability of manufacturing and reliably installing
and servicing amorphous core distribution transformers by the proposed
effective date. (EEI, No. 135 at pp. 17-19) Portland General Electric
commented that requiring amorphous metal transformers at a time when
supplies are already severely constrained risks electric grid
reliability, raising concerns regarding EPCA's requirement that DOE
consider the availability of covered products and the practicability of
manufacturing, installing, and servicing them. (Portland General
Electric, No. 130 at p. 3)
DOE notes that the adopted standards allow for both GOES and
amorphous transformers on the market. DOE estimates that the majority
of distribution transformers (the entirety of equipment class 1B and
2B) will use GOES to meet the adopted standard (corresponding to over
140,000 metric tons of GOES steel in just the liquid-immersed
distribution transformer market), while the remainder of the liquid-
immersed distribution transformer market will use amorphous cores.
Therefore, DOE has concluded that the adopted standards would not
result in the unavailability of distribution transformers or negatively
impact the distribution transformer supply chain.
Idaho Falls Power and Fall River both commented that a 3-year
compliance period is too aggressive and recommended that DOE consider a
longer compliance period, which allows efficiency goals to be completed
through innovation and utilization of incentives. (Idaho Falls Power,
No. 77 at p. 2; Fall River, No. 83 at p. 2). Pugh Consulting commented
that DOE did not consider the length of time and costs required to meet
the proposed standards by the 2027 compliance deadline. (Pugh
Consulting, No. 117 at p. 3) Portland General Electric questioned
whether the proposed standards can be met in a 3-year compliance
period, given the array of changes likely to result from the proposed
rule. (Portland General Electric, No. 130 at p. 4) LBA commented that
the proposed timeline is insufficient for the industry to make the
required changes, including redesigning factories, establishing a
dependable supply chain, hiring a workforce, and redesigning
infrastructure to accommodate a new variety of distribution
transformer. (LBA, No. 108 at p. 3)
ERMCO commented that the timeline to meet the proposed standards
will take longer than 3 years when considering the development of new
supply chains, certification of new apparatus designs, and engagement
of new manufacturing processes. (ERMCO, No. 86 at p. 1) Southwest
Electric stated that converting to amorphous for entities that either
supply or refine their own GOES appears to require more than the 3
years currently being allowed. (Southwest Electric, No. 87 at p. 3)
Howard commented that transformer manufacturers will not be able to
begin shipping amorphous transformers within 3 years because both
amorphous and GOES manufacturers would need to construct new facilities
and transformer manufacturers would need to invest in new equipment.
(Howard, No. 116 at pp. 1-2, 16)
Powersmiths stated that January 2027 is too short a timeframe for
the proposed standards due to how the technology change will disrupt
existing manufacturing processes and supply chains. (Powersmiths, No.
112 at p. 2) Schneider commented that the market is not prepared for
the proposed efficiency levels and more time is needed to explore the
risks of product substitution, impact on other power distribution
equipment, supply chain and capital investment, non-ideal capital
solutions, and electric room/building impacts. (Schneider, No. 101 at
pp. 2, 16)
DOE notes that the adopted standards include substantially lower
conversion costs, as discussed in section IV.J of this document, and a
longer compliance period, ensuring the energy savings associated with
the amended standards can be achieved without negatively impacting the
availability of distribution transformers.
While there was general agreement from stakeholders that a 3-year
compliance period was insufficient for the majority of liquid-immersed
and LVDT transformers to transition to amorphous cores, as was proposed
in the NOPR, there were a variety of opinions as to what efficiency
levels and timelines were achievable and would not exacerbate shortages
or lead to significant increases in material costs.
Several stakeholders specifically recommended DOE delay any
potential amendment of transformer standards until transformer prices
and lead times return to historical averages.
ABB recommended that DOE create an interagency working group to
focus on the increased production of GOES, amorphous metal, and other
constrained materials. (ABB, No. 107 at pp. 3-4)
Eaton recommended DOE delay consideration of the NOPR until supply
and demand for distribution transformers more closely aligns with
historical levels. (Eaton, No. 137 at pp. 1-2) Southwest Electric
recommended that the proposed standards be delayed until appropriate
measures are taken to stabilize supply chains, including increasing the
U.S. supplies of amorphous and copper, improving infrastructure for
supporting heavier overhead transformers, and decreasing average lead
times for liquid-filled transformers under 40 weeks. (Southwest
Electric, No. 87 at p. 4) Howard commented that the timeline for
proposed standards is too aggressive, reducing grid security by
removing GOES, and making current supply chain issues more challenging.
Accordingly, Howard encouraged DOE to delay implementation of standards
based on the supply crisis and overly aggressive timeline. (Howard, No.
116 at p. 5)
DOE notes that an indefinite delay in efficiency standards violates
DOE's statutory obligation to adopt the maximum increase in efficiency
that is technologically feasible and economically justified (See 42
U.S.C. 6295(m)). The adopted standards are both technologically
feasible and economically justified and do not pose substantial risk to
the distribution transformer supply chain as discussed in section V.C
of this document. The existing distribution transformer shortages are
primarily associated with increased demand for grid products and
shortages are unrelated to transformer efficiency. The adopted
standards complement the efforts to resolve these shortages by allowing
for significant flexibility in meeting efficiency standards such that
energy savings can be achieved while also investing in additive
transformer capacity that can diversify the core steel market and
increase total transformer capacity.
[[Page 29920]]
Several stakeholders suggested that implementing efficiency
standards that increased amorphous production could reduce the shortage
concerns by shifting the distribution transformer market to amorphous
material and freeing up GOES supply to be used in other applications or
converted to NOES for EV applications.
Environmental and Climate Advocates commented that current
transformer steel manufacturers are becoming increasingly focused on
the EV market, creating greater reliance on electrical steel imports.
Environmental and Climate Advocates stated that transitioning to
amorphous could alleviate current GOES capacity constraints and will
lead to a more robust long-term supply of distribution transformers
since amorphous is not used in EV motors. Environmental and Climate
Advocates also added that increasing capacity to amorphous production
is relatively fast and inexpensive compared to adding GOES capacity.
(Environmental and Climate Advocates, No. 122 at pp. 1-2)
Similarly, Efficiency Advocates and CEC commented that the proposed
standards will help create a more secure long-term distribution
transformer supply because amorphous does not experience competitive
pressure from the electric vehicle market as GOES does. (Efficiency
Advocates, No. 121 at p. 2; CEC, No. 124 at p. 2) Efficiency Advocates
further commented that it is reasonable to expect that amorphous
production would rapidly expand in response to standards given that
adding amorphous ribbon capacity is less capital-intensive than adding
GOES capacity. Efficiency Advocates added that there is a bias against
amorphous due to transformer production being geared toward GOES,
causing GOES transformers to be selected even in some instances when
amorphous transformers are cheaper. Efficiency Advocates stated that
the proposed standards would address this bias by spurring
manufacturers to invest in producing amorphous transformers.
(Efficiency Advocates, No. 121 at pp. 3-4)
DOE notes that the adopted standards include certain equipment
classes that are expected to be met by transitioning to amorphous
cores. Thereby, the adopted standards are likely to increase the number
of domestic core steel suppliers serving the U.S. market from a single
GOES producer to a mix of GOES and amorphous.
Several stakeholders suggested that DOE should establish revised
efficiency standards where GOES steel will likely remain cost
competitive and expand the compliance time to allow for more investment
in GOES steel.
A group of U.S. Senators commented requesting that DOE finalize the
proposed standards and extend the compliance date. The U.S. Senators
stated that the proposed standards would provide Americans with
significant savings on energy bills, but a longer compliance period is
required to address current shortages and strengthen domestic supply
chains. (U.S. Senators, No. 147 at pp. 1-2)
ERMCO suggested that DOE should either maintain current efficiency
standards or propose standards at EL 2 or less, which would allow the
U.S. supply chain to leverage both GOES and amorphous core steel
supplies. ERMCO commented that this would allow sufficient time to
validate the availability of raw materials, clarify load efficiency
tradeoffs, and properly consider the total manufacturing investment.
(ERMCO, No. 86 at pp. 1-2)
Sychak commented that Cliffs can supply lower-loss GOES grades but
needs sufficient time to implement changes to its product mix. (Sychak,
No. 89 at pp. 1-2) Sychak recommended DOE revise efficiency standards
to allow for lower-loss GOES grades to remain cost competitive and
revise the compliance date to 2030. (Sychak, No. 89 at pp. 1-2) Cliffs
encouraged DOE to withdraw the proposed rule and meet with stakeholders
to investigate alternative approaches, such as the possibility of
producing higher-efficiency grades of GOES, given sufficient lead time
to develop and manufacture these grades. (Cliffs, No. 105 at pp. 17-18)
Carte commented that GOES manufacturers are working to improve
quality and the timeline of the proposed standards is very aggressive,
not giving industry time to develop better GOES products. (Carte, No.
140 at pp. 3-4) Carte commented that future alloys will be able to
maintain the durability of GOES and reduce eddy currents, but the
proposed efficiency levels will inhibit this technology. (Carte, No.
140 at p. 4)
Carte recommended DOE delay standards until many of the concerns
with amorphous are further investigated and work with industry to
discuss what energy efficiency levels make sense. (Carte, No. 140 at p.
11)
MTC recommended DOE follow the lead of the European ECO-2
standards, which represent efficiency improvements over DOE's 2016
standards while allowing the use of GOES to ensure energy savings are
cost effective. (MTC, No. 119 at pp. 16-17) MTC further recommended DOE
delay amending efficiency standards for single phase transformers until
experience with new core designs has been developed for three phase
transformers similar to ECO-2. (MTC, No. 119 at p. 18)
DOE notes that the adopted standards include certain equipment
classes that are at EL 2, as suggested by ERMCO, and are expected to be
met with GOES cores. Further, the compliance period for amended
standards has been extended, from the 3-year compliance period proposed
in the January 2023 NOPR to a 5-year compliance period adopted in this
final rule. The expanded compliance time also offers substantial
opportunity for GOES manufacturers to increase production of lower-loss
GOES products, as Sychak and Cliffs suggested.
Several other manufacturers recommended DOE move a portion of the
market to amorphous and/or have expanded compliance dates in order to
provide certainty that amorphous capacity will be sufficient and
capital investment can be made without worsening near term transformer
shortages.
CPI recommended that the final rule provide enough time for
domestic transformer manufacturers to adjust to the proposed amorphous
requirement without exacerbating current supply chain issues. (CPI, No.
78 at p. 1) CPI urged DOE to ensure that adequate sources of amorphous
ribbon exist before the proposed rule becomes effective, suggesting
that this could be achieved through a phased approach to the proposed
rule. (CPI, No. 78 at p. 1)
Powersmiths and Eaton both commented that a tiered approach could
be taken to implement efficiency standards with a more gradual impact
to industry. (Powersmiths, No. 112 at p. 7; Eaton, No. 137 at p. 3)
Hammond commented that LVDT standards should not be amended because
LVDTs already meet the most stringent efficiency requirements in the
United States and Canada. However, Hammond stated that if DOE is going
to amend efficiency standards, it recommends no higher than EL 3 for
LVDTs. (Hammond, No. 142 at p. 3) Hammond also commented that the MVDT
proposed standards are achievable and reasonable, especially given the
proposed liquid-immersed levels. (Hammond, No. 142 at p. 3) DOE notes
that Hammond's recommended efficiency levels correspond to efficiencies
that could likely be cost effectively met using GOES.
Schneider stated that time would be needed to transition to
amorphous in order to validate models, finalize
[[Page 29921]]
footprint impacts, finalize capital requirements, and research impacts
on sustainability, but supply chain constraints are inhibiting this
research from being conducted via engineering samples. (Schneider, No.
92 at pp. 10-12) Schneider recommended that DOE establish the NOPR
levels immediately as a voluntary ENERGY STAR level and delay the
mandatory compliance date until January 1, 2030, to gradually convert
the market toward new efficiency. Schneider stated this would provide
manufacturers more time to evaluate technical impacts and establish
supply chain partners. (Schneider, No. 92 at pp. 2, 16)
DOE notes that while a 3-year compliance period was proposed in the
NOPR, stakeholder comment suggest that between 6 and 7 years would be
needed to fully retool their production process to meet the proposed
standards. WEG commented that between 5-7 years would be needed to
retool their facility. (WEG, No. 92 at pp. 3-4) Schneider recommended
mandatory compliance be delayed until 2030. (Schneider, No. 92 at pp.
2, 16) Sychak recommended DOE revise efficiency standards to allow for
lower-loss GOES grades to remain cost competitive and revise the
compliance date to 2030. (Sychak, No. 89 at pp. 1-2).
The timelines cited by stakeholders were generally based on the
need to add substantially more amorphous core production capacity, as
the January 2023 NOPR proposed EL4 for all liquid-immersed and EL5 for
all low-voltage dry-type transformers. The standards adopted here,
however, are expected to require less amorphous core production
capacity. Accordingly, DOE anticipates that these lower efficiency
standards could be achieved in fewer than the 7 years suggested by
commenters. However, based on existing transformer shortages, DOE
believes a 3-year compliance period may risk electrical steel prices
increasing due to increased demand, which could result in exacerbating
shortages in the near term. EPCA does not prescribe a specific time
period for compliance with new or amended standards for distribution
transformers.\135\ Therefore, DOE has concluded that it is appropriate
to extend the compliance period to 5 year to ensure sufficient time to
allow investments in amorphous core production equipment, amorphous
ribbon, and so that lower-loss GOES can be made without substantially
increasing electrical steel prices. DOE further notes that a five-year
compliance period is not uncommon for COMMERCIAL AND INDUSTRIAL
equipment regulated under EPCA. See generally, 42 U.S.C. 6313.
---------------------------------------------------------------------------
\135\ EPCA prohibits the application of new standards to a
product with respect to which other new standards have been required
during the prior 6-year period. 42 U.S.C. 6295(m)(4)(B). As noted
earlier, however, the standards for distribution transformers were
last amended in April 2013.
---------------------------------------------------------------------------
As discussed, the adopted efficiency standards include different
efficiency levels for different equipment classes as well as an
expanded timeline, thereby providing certainty that amorphous capacity
will be sufficient and capital investment can be made without worsening
near term transformer shortages. DOE notes that existing capacity
expansion announcements suggest that the near-term reaction to the
January 2023 NOPR was to invest in amorphous in an additive capacity,
given that additional distribution transformer production was needed
anyway, as discussed in Chapter 3 of the TSD.
In evaluating whether higher efficiency standards would be met with
GOES, DOE considers that, at baseline, most transformers are built with
M3, as that is the predominant product sold by the single domestic GOES
manufacturer. Lower-loss GOES exists and is included in DOE modeling;
however, it generally has a price premium relative to M3 in the present
market. As such, a transformer using lower-loss steel may be able to
meet higher efficiency levels than a baseline M3 transformer using the
same amount of steel (because the amount of losses per pound of steel
are lower). However, because the lower-loss steel is sold at a price
premium in the present market, the overall cost of that transformer may
increase.
Howard commented that the primary barrier to using lower-loss GOES
steels is supply related and manufacturers would use lower-loss GOES if
tariffs were removed and domestic core manufacturers could import
lower-loss GOES steel or domestic GOES manufacturers were incentivized
to make lower-loss material. (Howard, No. 116 at p. 17) Howard
commented that it produces its own cores domestically due to
insufficient availability of lower-loss GOES material. (Howard, No. 116
at p. 17)
In the presence of amended standards, Cliffs, Sychak, and Howard
suggested that existing producers of GOES may increase production of
lower-loss GOES to meet the demand of the market or new producers of
GOES may enter the market. If the increase in production capacity of
this lower-loss GOES results in a reduction in the price premium,
higher efficiency standards could be met without a transformer cost or
size increase. For example, if the single domestic producer
transitioned M3 grades to a lower-loss steel and did not increase the
price per pound of GOES, higher efficiency standards (up to a point)
could be met by building the exact same size transformers with the
exact same costs and no required capital investment from distribution
transformer manufacturers.
Schneider commented that as other countries require high grade dr
core steel, lower quality hib and M-grade steels may become extremely
cheap. (Schneider, No. 101 at p. 10)
Steel production tends to have volume-based efficiencies, wherein
an initial transition to higher performing grades requires some degree
of investment. However, once that investment is made and production is
standardized on lower-loss steels, the incremental cost may decrease.
DOE notes this sort of transitioning of core steel production was
observed in response to the April 2013 Standards Final Rule. Prior to
the compliance date of amended standards in 2016, baseline distribution
transformers used a significant amount of M4, M5, or M6 core steel. 78
FR 23336. However, following the implementation of amended standards in
2016, the domestic GOES producer standardized on primarily M3 steel
while many foreign producers standardized on hib and dr steels. These
volume-based efficiencies resulted in a lower incremental cost between
lower-loss GOES steel and M4, M5 or M6 grades. Not extremely cheap
grades of these steels, as Schneider suggested.
For the current rulemaking, DOE's modeling indicates there is
greater flexibility in transformer design, in terms of transformer size
and core and coil design, when meeting amended standards with lower-
loss GOES as compared to M3. Despite higher per pound prices, as
higher-efficiency standards are evaluated, designing transformers with
lower-loss core steel begins to achieve price parity with those
designed with M3 steel, as the M3 designs typically operate at a
reduced flux-density and add additional core material and/or use more
(or more expensive) winding materials in order to meet higher
efficiency standards, as demonstrated in Chapter 5 of the TSD. Whereas
designs using lower-loss core steels can use a lesser amount of
material to achieve the same efficiencies.
As stated by Howard, increased usage of lower-loss grades of GOES
has traditionally been limited due to supply constraints on these
steels which, in turn, contribute to a price premium on their market
sale. (Howard, No. 116 at
[[Page 29922]]
p. 17) In the past, the sole domestic producer of GOES has stated that
it has the technical experience and ability to invest in additional
grades of GOES as required by the market.\136\
---------------------------------------------------------------------------
\136\ (AK Steel, Docket No. BIS-2020-0015-0112 at pp. 7, 21).
---------------------------------------------------------------------------
Cliffs commented that they could produce higher-efficiency grades
of GOES, given sufficient lead time to develop and manufacture these
grades. (Cliffs, No. 105 at pp. 17-18) DOE notes that the adopted
standards for liquid-immersed distribution transformers both extended
the compliance period and adopted EL2 for equipment classes
representing a substantial volume of shipments. Given Cliffs stated
ability to manufacture lower-loss grades, expected demand for these
grades into the future, the widespread existence of these grades in the
global market, and the expanded compliance period by which these grades
will be needed, it is expected that an increase in domestically
produced lower-loss GOES grades will occur. As such, in the presence of
amended standards, it is likely that the supply of higher grades of
GOES would increase and, as a result of increased supply, the price
premium that currently exists between M3 grades and higher grades of
GOES would decrease.
Based on stakeholder feedback and historical GOES trends in the
presence of amended efficiency standards, DOE has revised its pricing
model for GOES in this final rule. In the no-new-standards case, DOE
has continued to rely upon 5-year average pricing to develop base
electrical steel prices. However, in the standards case, DOE revised
its pricing for GOES for the liquid-immersed representative units to
reflect an increased supply of low-loss GOES, as suggested by
stakeholders. DOE notes that it is difficult to predict the exact
investment and pricing strategy the domestic GOES manufacturer would
employ. However, DOE assumed it would follow similar pricing dynamics
to many of the foreign GOES suppliers that currently produce those
steel grades. While the domestic GOES manufacturer could choose to
follow different pricing dynamics, DOE notes that this would create
considerable risk of losing market share to foreign GOES producers or
the amorphous core market.
DOE modeled the price of 23hib090 at amended efficiency levels to
match the price of baseline M3 grades. DOE notes these two products are
sold for approximately the same price today (and, as discussed, foreign
produced hib was less expensive than domestic GOES prior to tariffs),
indicating that once manufacturers have invested in significant volumes
of hib grades, they sell them at approximately equivalent prices to M3.
For domain-refined grades, DOE reduced the price to a $0.10 cost-per-
pound premium between 23hib090 grades and domain-refined grades. This
premium aligns relatively well with the cost at which domain-refined
grades become cost competitive with M3 grades at baseline, which
stakeholders have noted is typical in the global market when sufficient
supply is available.\137\ This $0.10 cost-per-pound premium
additionally accounts for the incremental production costs associated
with the domain-refinement process.\138\
---------------------------------------------------------------------------
\137\ Central Moloney, a domestic manufacturer of distribution
transformers, has commented that they purchase cores made of pdr
steel for 90 percent of their designs. Indicating that if not
subject to supply constraints, pdr can compete with M3 on first
cost. See Docket No. EERE-2020-0015-0015.
\138\ DOE notes that while pdr grades are modeled for liquid-
immersed distribution transformers, there may be instances where dr
grades can be used in certain wound core transformer designs without
annealing, specifically if using a unicore production machinery. It
is uncertain whether investments would be into pdr steel or dr steel
as pdr steel typically requires greater investment (and therefore
have a greater premium than dr steel) but would achieve greater loss
reduction on account of annealing benefits.
---------------------------------------------------------------------------
DOE notes that the domain-refinement process can be either an
integrated process, such that domain-refined GOES is the direct output
of production, or an independent additional processing step, wherein
hib steel is separately treated to add domain-refinement. While the
latter of these options requires additional floor space and capital
investment, neither option has high input costs. As such, the material
inputs required to produce domain-refined grades are not likely to lead
to a significantly higher selling price once manufacturers have
invested in the necessary production equipment. Rather, in the presence
of sufficient supply, only a modest price premium is likely to exist
between domain-refined and hib grades to account for the additional
processing step required to add domain refinement to high permeability
steel grades. Additionally, since domain refinement can occur as an
independent processing step, it does not necessarily have to occur at
the steel production site. While domain-refinement is typically
conducted at the steel manufacturer sites, some manufacturers of
domain-refinement equipment market the products for transformer core
manufacturers to conduct their own laser scribing, which may be an
option for large volume core manufacturers to minimize the cost-premium
associated with domain-refined products, particularly if hib grades are
available in sufficient volume domestically.\139\
---------------------------------------------------------------------------
\139\ Castellini, Laser Scribing Machine, (Last Accessed 1/23/
2024), Available online at: https://www.castellini.it/products/solution/coil-processing/laser-scribing/.
---------------------------------------------------------------------------
These pricing updates reflect the fact that, in the no-new-
standards case, steel manufacturers are likely to maintain the status
quo. However, they also reflect stakeholder feedback that lower loss
GOES pricing is largely demand dependent and would likely be reduced if
GOES manufacturers invest in lower loss grades of GOES in the presence
of amended standards, or if tariffs were lifted. Further, given the
volume-based benefits of standardized production at a given steel
grade, the price of these lower loss GOES materials may decrease as a
result of increased production. Therefore, DOE evaluated any potential
amended standards for liquid-immersed distribution transformers based
on the reduced price of GOES that would be expected when compared to
the no-new-standards case. Additional details on DOE's modelling of
electrical steel pricing are provided in chapter 5 of the final rule
TSD.
Additionally, as previously noted, DOE's modeling, as well as
stakeholder comment, indicates that amorphous core transformer designs
are already cost competitive with GOES core transformers for many
transformer designs and would become even more favorable in the
presence of amended standards, given the inherent improvement in no-
load losses associated with amorphous cores as discussed in Eaton's
comment. (Eaton, No. 137 at pp. 21-22). Therefore, at standard levels
in which both GOES and amorphous metal can compete on a first cost
basis, provided manufacturers make investment into amorphous core
production equipment, it will be even more imperative for GOES
producers to provide a supply of lower loss grades of GOES at a
competitive price.
As discussed in section IV.F.3 of this document, DOE has also
revised its assumptions to reflect transformer manufacturers' desire to
not disrupt their existing GOES-core production capacity. Therefore,
consumer amorphous core selection is limited through EL 2. The
assumption limiting amorphous core selection is more likely to be valid
the more cost- and performance-competitive GOES is. If there is a
substantial increase in GOES core transformer cost, either resulting
from a lack of investment in higher performing GOES steel or a
substantial price premium for these lower loss GOES materials,
customers would be
[[Page 29923]]
more likely to select amorphous transformer at EL 1 and EL 2.
For medium-voltage and low-voltage dry-type equipment classes, DOE
did not similarly estimate a decrease in the price of higher grades of
GOES as a result of amended efficiency standards because the dry-type
market is served by a different supply chain than the liquid-immersed
market. As discussed in section IV.A.4.b of this document, although
both the liquid-immersed and dry-type markets may, in theory, be
supplied by the same grades of core steel, the liquid-immersed market
tends to be served first in practice due to its higher volume of
shipments. As a result, since the dry-type market represents a smaller
proportion of total distribution transformer shipments and, in turn, a
smaller required core steel capacity, any changes to amended efficiency
standards the dry-type market are less likely to significantly impact
the electrical steel market or incentivize manufacturers to invest in
higher grades of GOES. Further, even if standards were amended for the
liquid-immersed market and the supply of higher grades of GOES were to
increase as a result, the dry-type market would not necessarily
experience the price-reduction benefits of these investments. Since
core steel supply chains are established to serve the liquid-immersed
market first, any investments in GOES capacity would likely be
primarily directed towards the liquid-immersed market. As such, dry-
type transformer manufacturers may be required to either continue to
use M3 grades of GOES and meet amended efficiency standards via other
design improvements or continue to pay a premium on higher grades of
GOES in order to secure a supply chain over the liquid-immersed market.
Therefore, for the reasons discussed, DOE only revised its GOES pricing
model for the liquid-immersed representative units in this final rule
and has continued to use 5-year averages (updated to reflect recent
price changes between the January 2023 NOPR and final rule) to model
electrical steel prices at all evaluated standard levels for the dry-
type representative units.
Additionally, as discussed in sections IV.A.2.b and IV.A.2.c of
this document, DOE has established separate equipment classes for
liquid-immersed distribution transformers based on kVA rating. For
certain equipment kVA ranges, levels were set at the NOPR efficiency
levels, thereby assuring manufacturers that some portion of the market
will likely be cost-effectively met by amorphous, and assuring
amorphous ribbon manufacturers that capacity can be increased to meet
expected increases in demand. However, for other kVA ranges, DOE walked
back the efficiency levels such that GOES remains a very cost-
competitive option, even if standards may be more cost-effectively met
with amorphous. As such, manufacturers will continue to have the design
flexibility to decide which core material to utilize. Lastly,
distribution transformer capital equipment is capable of producing a
wide array of kVA ranges. Hence, existing GOES equipment can focus on
levels that are more cost-effectively met with GOES while additive
amorphous equipment can focus on levels that are more cost-effectively
met with amorphous. Additionally, DOE has expanded the compliance
period, such that transformers do not have to meet any higher
efficiency levels for 5 years, ensuring additional time for these
investments.
Taken together with an expanded compliance period, the standards
adopted here will give GOES manufacturers, amorphous manufacturers, and
distribution transformer manufacturers sufficient time and market
certainty to make investments in both GOES and amorphous such that,
prices will remain in line with DOE's modeling across a range of all
reasonable manufacturer choices and efficiency standards will not make
existing distribution transformer shortages worse. Further, DOE
believes at least some additional portion of the market is likely to be
met via amorphous ribbon, meaning the U.S. distribution transformer
core market will likely be served in considerable volume by at least
two domestic manufacturers, one for amorphous and one for GOES--as
compared to today, wherein nearly all of the domestic market is served
by a single domestic GOES manufacturer. A more diversified domestic
supply ensures that uncertainty in policy decisions, such as
implementation of tariffs, have less of an impact on domestic producers
of distribution transformers.
In the economic analysis for distribution transformers, DOE models
consumer purchases for baseline distribution transformers based on the
current market trends, whereby a utility customer purchases the lowest
cost distribution transformer that uses existing widely produced core
steels, as discussed in section IV.F.3.a of this document. At EL1 and
EL2 for liquid-immersed distribution transformers, DOE's analysis
continues to model that distribution transformer manufacturers will
choose to maintain their existing GOES equipment in order to avoid the
investments needed to upgrade their production facilities to
accommodate more-efficient types of steel used to make more-efficient
distribution transformers. Therefore, DOE models consumers as
purchasing GOES-core distribution transformers, even if amorphous-core
transformers would be lower first-cost. Starting at EL3, DOE assumes
liquid-immersed distribution transformer customers purchase the lowest
cost distribution transformer that meets the evaluated efficiency level
and therefore generally assumes most of that market transitions to
amorphous cores. DOE assumes manufacturers begin shift to amorphous at
EL 3 by making investments to upgrade their distribution transformer
production facilities to accommodate amorphous steel, even though they
would not at lower levels. Even though EL 3 can be met with more
efficient GOES, manufacturers may choose to use amorphous steel to make
distribution transformers cores because it is more economical. DOE
considers various Trial Standard Levels as discussed in section V.A of
this document; TSL 4 and above include all equipment classes at EL 4
and above, while TSL 3, the amended standard level, includes only
equipment class1A and 2A at EL 4 (with the remaining classes at EL 2),
resulting in only 48,000 metric tons of amorphous usage. That level of
amorphous steel usage is not expected to impact the current domestic
steel market given the existing domestic capacity and announced
amorphous capacity expansions.
As discussed, amended standards could increase or decrease the
demand for certain grades of GOES and amorphous steels that are used in
cores to make more-efficient distribution transformers. To the extent
that these shifts in market shares across raw material sources are
large, such as in the case of TSL 4, it is possible that shifts in
demand could change the underlying steel prices if supply cannot
accommodate the demand increases. The pricing dynamics of the electric
steel market are complicated given the global market dynamics, tariff
structures and the modernization of the U.S. electric grid to help
support resilience. DOE's adopted standard level accounts for these
dynamics by setting efficiency levels which, based on the assumptions
and data discussed above, are expected to maintain the demand for
domestic GOES while beginning to grow the demand for amorphous steel in
a managed transition that allows time for businesses and the workforce
to gain experience, familiarity, and confidence
[[Page 29924]]
in amorphous core distribution transformers.
Beyond any endogenous effect on steel demand--and price--resulting
from the standards adopted in this rule, demand for electrical steel
could be further heightened by efforts across the country to electrify
building end-uses and transportation, including government initiatives,
through legislation and rulemakings, outside the scope of this
document. As one example, the proposed rulemaking by EPA on emissions
standards for light duty vehicles projects that electricity demand will
increase by 4.2% in 2055 as a result of that rule.\140\ In this
rulemaking, for the reasons explained above, DOE models an increase in
distribution transformer shipments annually, which results in a 0.7-
percent increase annually or approximately 75,000 units. These
estimates are derived from AEO2023's growth rate to account for the
increase in electricity demand resulting from various electrification
policies and standards across the United States. DOE's use of AEO 2023
projections to drive its future shipments (and stock) growth result in
a 190-percent increase in total installed stock (in terms of capacity)
by 2050 as compared to a 2021 baseline. A report \141\ by the National
Renewable Energy Laboratory estimates future growth in stock between
160 and 260 percent by 2050 for distribution transformers, including
step-up transformers which are not in the scope of DOE's rulemaking,
but it shows consistent projections regarding future growth. DOE also
ran higher and lower growth sensitivities, which were developed from
the high and low scenarios in AEO 2023.\142\ Lastly, DOE presents in
appendix 10C of the TSD a sensitivity scenario examining the impacts of
utilities installing larger distribution transformers (increased per
unit average capacity) in response to growing decarbonization/
electrification initiatives. These are all further detailed in section
VI.E.3.a of this document. If these electrification increases are not
adequately captured by AEO 2023 energy usage projections and
sensitivities, DOE may be underestimating the demand for electricity-
and therefore distribution transformers-in the analysis.
---------------------------------------------------------------------------
\140\ 88 FR 29184. Multi-Pollutant Emissions Standards for Model
Years 2027 and Later Light-Duty and Medium-Duty Vehicles. May 5,
2023.
\141\ K. McKenna et al: Major Drivers of Long-Term Distribution
Transformer Demand, Feb 2024, NREL/TP-6A40-87653.
\142\ See appendix 10B of the TSD. National Impacts Analysis
Using Alternative Economic Growth Scenarios.
---------------------------------------------------------------------------
An additional pricing consideration within the market for
distribution transformers is the role of competition and market
structure. As elsewhere discussed in this document, GOES and amorphous
demand in the United States are each supplied by one (separate)
domestic producer. Existing foreign supply sources for amorphous alloy
is limited to one producer in Japan, as well as several producers in
China. As mentioned earlier, DOE does not expect the adopted standard
level to alter the demand for GOES, in addition to the estimated
efficiency benefits that amorphous steel transformers provide, DOE
further believes that shifting some demand to amorphous steel might on
the margin alleviate existing supply chain issues with GOES core
transformers that was the source of extensive stakeholder feedback in
response to the NOPR. While the increase in demand for amorphous alloy
caused by today's standard might encourage additional entrants into the
supply chain, it is worth considering the resulting market structure
for amorphous alloy suppliers should all new demand be serviced only by
existing producers.
At TSL 4, the demand for amorphous cores is projected to be
approximately equal to today's global capacity of amorphous alloy. In
the short term, an inability for suppliers to scale production and
manufacturers to retool production lines towards amorphous core
distribution transformers could lead to short-term market disruptions.
If amorphous demand is serviced by the domestic manufacturer of
amorphous alloy and tariffs remain in place, this introduces a
possibility for a shift towards monopoly markups absent price
competition. If foreign supply or additional domestic entrants for
amorphous alloy are available, these monopoly markup issues can be
somewhat mitigated. For example, in an alternative energy industry
context it has been empirically shown that duopoly markups are lower
than economic theory might otherwise predict, due to issues associated
with protecting against additional market entrants and imperfect
information.\143\
---------------------------------------------------------------------------
\143\ Wolfram, Catherine. Measuring Duopoly Power in the British
Electricity Spot Market. American Economic Review. 89 (4) 805-826.
1999.
---------------------------------------------------------------------------
DOE acknowledges the above issues with respect to this rulemaking's
potential impact on prices, and further acknowledges the complexity of
accurately modeling price responses to regulations. To address the
aforementioned concerns with endogenous price changes as a consequence
of the rulemaking, as well as increased demand resulting from exogenous
policy changes, in lieu of a market structure analysis, DOE has adopted
standards that DOE expects to require an increase in amorphous demand
that can be met with much higher probability in the revised 5-year
compliance window. DOE has determined that such standards achieve the
greatest energy savings that are economically justified. That is so
even though DOE estimates consumer benefits would be maximized under
the TSL4 standard that requires additional amorphous steel. However,
based on these market-structure concerns, DOE has determined such
standards are economically justified at this time.
General considerations for price responses and market structure are
areas DOE plans to explore in a forthcoming rulemaking action related
to the agency's updates to its overall analytic framework.
For TSL 3, DOE assumes that for the 1A and 2A equipment classes
where DOE has proposed efficiency level 4, all future demand for
distribution transformers will likely be met be met by amorphous cores.
However, at TSL 3 for all other liquid-immersed equipment classes where
DOE has proposed efficiency level 2, DOE assumes minimal amorphous core
production even where amorphous is the lower first-cost product. In the
long-run, it is possible that amorphous alloy supply will adequately
increase to meet the new demand and will increase adoption of amorphous
even for segments of the market that subject to standards that could be
met with GOES cores. In that scenario, consumer and energy savings may
be even greater than those modeled in this analysis. However, for
distribution transformers, given the acute shortages this market has
experienced in the past several years and the resulting higher prices,
DOE has accounted for stakeholder feedback that total conversion from
GOES to amorphous is not feasible in the short-term. Therefore, DOE has
adopted a TSL that reflects the extensive feedback and data supplied to
the rulemaking record that is economically justified and
technologically feasible.
b. Other Material Prices
Regarding other materials used in a distribution transformer, DOE
similarly relies on 5-year average costs for materials and includes
labor costs derived largely from public indices, markup costs, and
transportation costs.
[[Page 29925]]
DOE detailed all of these costs in chapter 5 of the NOPR TSD.
Regarding these costs, Idaho Power commented that the metal price
indices used by DOE are appropriate, but recommended DOE consider labor
and transportation costs. (Idaho Power, No. 139 at p. 4) Pugh
Consulting commented that DOE did not properly account for the impact
of labor shortages. (Pugh Consulting, No. 117 at p. 3)
Regarding labor requirements, Georg commented that automation can
reduce the labor-intensive work associated with transformer production
and stated that Georg offers solutions to automate wound core
production for both GOES and amorphous cores and stacked GOES cores.
(Georg, No. 76 at p. 1)
DOE notes that Idaho Power did not suggest an alternative method
for considering labor or transportation costs. As noted in the January
2023 NOPR, DOE applies a labor cost per hour that is generally derived
from the U.S. Bureau of Labor Statistics rates for North American
Industry Classification System (NAICS) Code 335311--``Power,
Distribution, and Specialty Transformer Manufacturing'' production
employees hourly rates and applies markups for indirect production,
overhead, fringe, assembly labor up-time, and a non-production markup
to get a fully burdened cost of labor. 88 FR 1722, 1768. DOE has
updated these labor rates, which reflect the recent increase in labor
costs as discussed in chapter 5 of the TSD.
Regarding other materials costs, DOE notes that the majority of
materials in a distribution transformer, aside from the transformer
core, are commodities used across many products.
Southwest Electric stated that it predicts a 47.5-percent average
increase in copper weight to meet the proposed standards and expressed
concern that this increased demand will both increase the cost of
copper and lead to potential shortages. (Southwest Electric, No. 87 at
p. 3) Southwest Electric commented that the 5-year average price of
copper is much lower than the current price of copper and therefore DOE
should update its cost models to reflect the more likely costs from
2023-2027, rather than incorporating the discounted prices that existed
between 2017-2021. (Southwest Electric, No. 87 at p. 3) Southwest
Electric further recommended that DOE correct its cost model before
finalizing a standard to reflect the direct cost increases associated
with rising metal prices and the indirect cost increases associated
with transporting, supporting, and repairing heavier overhead
transformers. Id.
Powersmiths commented that copper will be required to meet many
efficiency standards, which is more expensive, volatile, and subject to
substantial competing demand to meet efficiency standards. Accordingly,
Powersmiths encouraged DOE to set efficiency levels that can be met
with aluminum windings. (Powersmiths, No. 112 at p. 3)
WEG commented that the supply of copper is limited and higher
standards will drive more need for copper material vs aluminum. (WEG,
No. 92 at p. 2) Eaton recommended that DOE consider the risk of reduced
copper availability over the next two decades. (Eaton, No. 137 at p.
29) HVOLT commented that many designs will need to convert to copper
windings in a time when copper is in tight supply. (HVOLT, No. 134 at
p. 8) Carte commented that 20-percent additional conductor material
would also have environmental and supply chain impacts. (Carte, No. 140
at p. 2)
Howard commented that copper usage will likely increase, making it
more difficult for manufacturers to obtain. Howard added that, while
other materials like oil, transformer tank steel, and insulating paper
likely will not face significant shortages in the presence of amended
standards, the quantity of these materials used will increase, thereby
increasing the transformer MSP. (Howard, No. 116 at p. 24)
DOE notes that copper is used in a variety of industries and with a
variety of electrical products. Hence, the distribution transformer
market does not singularly dictate the supply and demand dynamics that
impact the price of copper. DOE has used common indexes to determine
the 5-year average price of copper. Further, DOE notes that the adopted
efficiency levels for liquid-immersed distribution transformers can be
met with GOES cores and aluminum windings for the equipment classes set
at EL2 and with amorphous cores and aluminum windings for the equipment
classes set at EL4. Low-voltage dry-type and medium-voltage dry-type
transformer efficiency levels can also be met with GOES cores and
aluminum windings.
Southwest Electric commented that, although a more efficient
transformer allows manufacturers to reduce the amount of radiators
required, the reduction is not enough to offset the material and labor
increases needed to reach those efficiencies. (Southwest Electric, No.
87 at p.2)
Regarding transportation and labor costs, Schneider commented that
DOE should consider the climate costs associated with increased
transportation costs if the size of LVDTs increases. (Schneider, No.
101 at p. 11) Multiple commenters stated that larger transformers, and
specifically amorphous core transformers, will require more truckloads
to deliver the same number of transformers and additional weight will
increase fuel costs, which DOE should account for in additional
transportation costs. (ERMCO, No. 86 at p. 1; Powersmiths, No. 112 at
p. 3; Idaho Power, No. 139 at p. 6; Eaton, No. 137 at p. 41)
Regarding transportation costs, DOE noted in the January 2023 NOPR
that it uses a price per pound estimate for the shipping cost of
distribution transformers. 88 FR 1722, 1768-1769. This methodology
means that transformers with increased weight will have increased
shipping costs reflected in DOE's analysis. DOE understands that the
cost to ship each unit will vary depending on weight, volume,
footprint, order size, destination, distance, and other, general
shipping costs (fuel prices, drive wages, demand, etc.). DOE has
previously sought comment as to whether this cost-per-pound accurately
models the complexity of distribution transformer shipping costs. Id.
In response, Eaton commented that shipping costs vary, but DOE's
shipping cost estimates are reasonable. (Eaton, No. 55 at p. 16) DOE
did not receive comments suggesting that its cost-per-pound to ship
transformers is inaccurate, or any suggestions as to how to model the
complexity of distribution transformer shipping costs more accurately.
Therefore, DOE retained its cost-per-pound shipping methodology
described in chapter 5 of the TSD.
The resulting bill of materials provides the basis for the
manufacturer production cost (MPC) estimates.
To account for manufacturers' non-production costs and profit
margin, DOE applies a multiplier (the manufacturer markup) to the MPC.
The resulting manufacturer selling price (MSP) is the price at which
the manufacturer distributes a unit into commerce.
DOE's average gross margin was developed by examining the annual
Securities and Exchange Commission (SEC) 10-K reports filed by publicly
traded manufacturers primarily engaged in distribution transformer
manufacturing and with a combined product range that includes
distribution transformers. For distribution transformers, DOE applied a
gross margin percentage of 20 percent for all distribution
transformers.\144\
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\144\ The gross margin percentage of 20 percent is based on a
manufacturer markup of 1.25.
---------------------------------------------------------------------------
In the January 2023 NOPR, DOE acknowledges that while some
manufacturer may have higher gross
[[Page 29926]]
margins, the gross margin is unchanged from the April 2013 Standards
Final Rule and was presented to manufacturers in confidential
interviews as part of both the preliminary analysis and the NOPR
analysis and there was general agreement that a 20-percent gross margin
was appropriate for the industry. 88 FR 1722, 1769. DOE has retained
the 20-percent gross margin as part of this analysis.
3. Cost-Efficiency Results
The results of the engineering analysis are reported as cost-
efficiency data (or ``curves'') in the form of energy efficiency (in
percentage) versus MSP (in dollars), which form the basis for
subsequent analyses in the final rule. DOE developed 19 curves
representing the 16 representative units. DOE implemented design
options by analyzing a variety of core steel material, winding
material, and core construction methods for each representative unit
and applying manufacturer selling prices to the output of the model for
each design option combination. See chapter 5 of the TSD for additional
details on the engineering analysis.
DOE then relies on these cost-efficiency curves and models consumer
choices in the presence of various amended efficiency levels to
calculate the downstream impacts of each theoretical efficiency
standard. In general, DOE's analysis assumes most distribution
transformer customers purchase based on lowest first cost and there is
limited market above minimum efficiency standards (see section IV.F.3
of this document).
D. Markups Analysis
The markups analysis develops appropriate markups (e.g., retailer
markups, distributor markups, and contractor markups) in the
distribution chain and sales taxes to convert the MSP estimates derived
in the engineering analysis to consumer prices, which are then used in
the LCC and PBP analysis. At each step in the distribution channel,
companies mark up the price of the product to cover costs. DOE's markup
analysis assumes that the MSPs estimated in the engineering analysis
(see section IV.C of this document) are occurring in a competitive
distribution transformer market as discussed in section V.B.2.d of this
document.
As part of the analysis, DOE identifies key market participants and
distribution channels. For distribution transformers, the main parties
in the distribution chain differ depending on purchaser and on the
variety of distribution transformer being purchased.
For the January 2023 NOPR, DOE assumed that liquid-immersed
distribution transformers are almost exclusively purchased and
installed by electrical distribution companies; as such, the
distribution chain assumed by DOE reflects the different parties
involved. 88 FR 1722, 1769. DOE also assumed that dry-type distribution
transformers are used to step down voltages from primary service into
the building to voltages used by different circuits within a building,
such as plug loads, lighting, and specialty equipment; as such, DOE
modeled that dry-type distribution transformers are purchased by non-
residential customers (i.e., COMMERCIAL AND INDUSTRIAL customers). Id.
DOE considered the following distribution channels in Table IV.7.
[GRAPHIC] [TIFF OMITTED] TR22AP24.534
DOE did not receive any comments on the distribution channels
applied in the NOPR and maintains the same approach in this final rule.
Chapter 6 of the final rule TSD provides details on DOE's
development of markups for distribution transformers.
E. Energy Use Analysis
The energy use analysis produces energy use estimates and end-use
load shapes for distribution transformers. The energy use analysis
estimates the range of energy use of distribution transformers in the
field (i.e., as they are used by consumers), enabling evaluation of
energy savings from the operation of distribution transformer equipment
at various efficiency levels, while the end-use load characterization
allows evaluation of the impact on monthly and peak demand for
electricity. The energy use analysis provides the basis for other
analyses DOE performed, particularly assessments of the energy savings
and the savings in operating costs that could result from adoption of
amended or new standards.
As presented in section IV.A.3, transformer losses can be
categorized as ``no-load'' or ``load.'' No-load losses are roughly
constant with the load on the transformer and exist whenever the
distribution transformer is energized (i.e., connected to electrical
power). Load losses, by contrast, are zero when the transformer is
unloaded, but grow quadratically with load on the transformer.
Because the application of distribution transformers varies
significantly by category of distribution transformer (liquid-immersed
or dry-type) and ownership (electric utilities own approximately 95
percent of liquid-immersed distribution transformers; commercial/
industrial entities use mainly dry type), DOE performed two separate
end-use load analyses to evaluate distribution transformer efficiency.
The analysis for liquid-immersed distribution transformers
[[Page 29927]]
assumes that these are owned by utilities and uses hourly load and
price data to estimate the energy, peak demand, and cost impacts of
improved efficiency. For dry-type distribution transformers, the
analysis assumes that these are owned by commercial and industrial
entities, so the energy and cost savings estimates are based on monthly
building-level demand and energy consumption data and marginal
electricity prices. In both cases, the energy and cost savings are
estimated for individual distribution transformers and aggregated to
the national level using weights derived from transformer shipments
data.
1. Trial Standard Levels
As discussed in detail in section V.A of this final rule, DOE
typically evaluates potential new or amended standards for products and
equipment by grouping individual efficiency levels for each class into
TSLs. Use of TSLs allows DOE to identify and consider manufacturer cost
interactions between the equipment classes, to the extent that there
are such interactions, and price elasticity of consumer purchasing
decisions that may change when different standard levels are set. For
this analysis, as in the NOPR, DOE applied a Purchase Decision model
(See section IV.F.3 of this document) to simulate the process that
consumers use to purchase their equipment in the field within the LCC
and PBP analysis (See section IV.F of this document). To conduct these
analysis DOE must know the composition of potential amended standards
(TSL) as an input as they represent the purchasing environment to
consumers under amended standards. The results that follow are
presented by TSL to capture the consumer, national, and manufacturer
impacts under the amended standards scenarios considered by DOE.
2. Hourly Load Model
For utilities, the cost of serving the next increment of load
varies as a function of the current load on the system. To
appropriately estimate the cost impacts of improved distribution
transformer efficiency in the LCC analysis, it is therefore important
to capture the correlation between electric system loads and operating
costs and between individual distribution transformer loads and system
loads. For this reason, DOE estimated hourly loads on individual
liquid-immersed distribution transformers using a statistical model
that simulates two relationships: (1) the relationship between system
load and system marginal price; and (2) the relationship between the
distribution transformer load and system load. Both are estimated at a
regional level. Distribution transformer loading is an important factor
in determining which varieties of distribution transformer designs will
deliver a specified efficiency, and for calculating distribution
transformer losses, and the time-dependent values of those losses. To
inform the hourly load model, DOE examined data made available through
the IEEE Distribution Transformer Subcommittee Task Force (IEEE TF).
DOE received the following comment regarding the loading of liquid-
immersed distribution transformers: Carte questioned if DOE's analysis
considered the wide range of loads that transformers serve in the field
and whether DOE considered periods of high loading and low loading as
part of its simulation. (Carte, No. 140 at p. 7) Central Hudson Gas and
Electric (CHG&E) commented that it attempts to size its transformers at
80-percent of their nameplate capacity on new installations, and that
some of its transformers are loaded at almost 200-percent of their
nameplate rating. (CHG&E, Public Meeting Transcript, No. 75 at pp. 92-
93) Metglas commented that an IEEE TF on Loading revealed that there is
less than a 20-percent load on most transformers--well below the 50-
percent loading test condition. Metglas added that it has heard from
multiple utilities and OEMs that oversizing transformers is common and
that, due to this fact, the actual loading is likely to remain around
20 percent. (Metglas, No. 125 at pp. 4, 7) Idaho Power commented that
it supports DOE's application of an hourly load model for liquid-
immersed distribution transformers. (Idaho Power, No. 139 at p. 4)
In response to CHG&E, DOE assumes CHG&E is referring to its
customers' maximum peak demand, and maximum peak demand is not the
average load on the distribution transformer. DOE loading analysis
accounts for occurrences where the distribution transformers are loaded
at a high percentage of their nameplate. While the overloading that
CHG&E describes is discussed in IEEE C57.91-2011 as acceptable
practice, DOE understands that overloading is the exception and not the
rule as, depending on seasonality, the additional heat accumulated in
the distribution transformer on high-temperature peak days can be
detrimental to distribution transformer insulation lifetimes,
potentially resulting in premature replacement. This strategy may be
beneficial to CHG&E given its operational cost structures, but runs
counter to DOE's understanding that utilities strive to reduce the cost
of operation.
In response to CHG&E, Carte, Idaho Power, and Metglas, DOE's hourly
load simulation, as discussed in the January 2023 NOPR, was designed
specifically to account for the wide range of loads seen in the field,
and for non-linear impacts on load losses when the transformer is under
high loads. 88 FR 1722, 1770-1772. To do so, DOE used a two-step
approach. Transformer load data were used to develop a set of joint
probability distribution functions (JPDF), which capture the
relationship between individual transformer loads and the total system
load.\145\ The transformer loads were calculated as the sum load of all
connected meters on a given transformer for each available hour of the
year. Because the system load is the sum of the individual transformer
loads, the value of the system load in a given hour conditions the
probability of the transformer load taking on a particular value. To
represent the full range of system load conditions in the United
States, DOE used FERC Form 714 \146\ data to compile separate system
load PDFs for each census division. These system PDFs are combined with
a selected transformer JPDF to generate a simulated load appropriate to
that system. As the simulated transformer loads are scaled to a maximum
of one to calculate the losses, the load is multiplied by a scaling
factor selected from the distribution of Initial Peak Loads (IPLs), and
by the capacity of the representative unit being modeled. In the August
2021 Preliminary Analysis, DOE defined the IPL as a triangular
distribution between 50 and 130 percent of a transformer's capacity,
with a mean of 85 percent. This produces an hourly distribution of PUL
values from which hourly load losses are determined. These
distributions of loads capture the variability of distribution
transformers load diversity, from very low to very high loads, that are
seen in the field. The comments received did not provide data or
evidence beyond anecdotal statements for DOE to change the modeling
assumptions in the NOPR; as such, this distribution was maintained from
the NOPR in this final rule.
---------------------------------------------------------------------------
\145\ See Distribution Transformer Load Simulation Inputs,
Technical Support Document, chapter 7.
\146\ Available at www.ferc.gov/industries-data/electric/general-information/electric-industry-forms/form-no-714-annual-electric/data.
---------------------------------------------------------------------------
APPA commented that amorphous transformers are larger and more
expensive, but the expense does not rise
[[Page 29928]]
linearly with the capacity of the transformer. APPA commented that
higher capacity transformers are cheaper per kW than smaller ones, so
to save money, it is only logical that where shared secondary cable
already exists, one should replace two or more (smaller capacity)
transformers with a single (larger capacity) transformer and combine
the shared portion of the secondary network. APPA commented that this
has been shown to increase losses in the shared secondary cable to
between 0.6 and 2.2 percent of total power delivered, far outstripping
the increased efficiency of the amorphous transformer. APPA added that
although DOE could consider working with utilities on secondary issues
for more efficiency, the NOPR's analysis does not adequately account
for this issue, which would undercut the efficiency conclusions in the
proposed rule. (APPA, No. 103 at p. 15)
Regarding the APPA comment, when DOE conducts its analysis, it
compares the costs and benefits of a revised standard against the no-
new standards case. APPA's scenario asserts that at the time of
transformer replacement, ``it is only logical that . . . banks of
distribution transformers should be replaced with a single,'' DOE
assumes a larger-capacity distribution transformer to optimize the cost
per unit capacity of service being delivered. The lack of information
provided by APPA makes it impossible for DOE to respond technically to
this assertion; DOE notes that any single-unit replacement of multiple-
unit installations would need to be sized in terms of capacity to meet
the aggregate maximum demand of all connected customers (plus any
safety margins) on said circuit. APPA's comment asserts that additional
losses on the secondary is a function of equipment aggregation--a
decision made at the individual utility's operational level, and, as
described by APPA, is an example of a utility favoring operational
efficiency over energy efficiency, which would happen in the absence of
a revised standard by DOE and, as such, is not considered in this final
rule.
a. Low-Voltage and Medium-Voltage Dry-Type Distribution Transformers
Data Sources
Idaho Power commented it believes the base data used in the April
2013 Standards Final Rule was scaled from 1992 and 1995 data, and there
have been many energy efficiency standards that have been incorporated
over the last 30 years. Idaho Power recommended that DOE consider
updating the standard to reflect current loading data and include
advanced data collection methods that provide more granular data. Idaho
Power added that many power companies have automated meter read data
that could be leveraged for better analysis. (Idaho Power, No. 139 at
p. 5)
DOE agrees with Idaho Power's comments that since the CBECS last
included monthly demand and energy use profiles for respondents in 1992
and 1995 editions that many energy efficiency standards have been
promulgated. For its dry-type analysis, DOE used the hourly load data
for COMMERCIAL AND INDUSTRIAL customers from data provided to the IEEE
TF (from 2020 and 2021) to scale these monthly values in its loading
analysis for low-, and medium-voltage dry-type distribution
transformers (see chapter 7 of this final rule TSD). DOE is aware that
many utilities meter their customers using real-time meters; however,
DOE does not have the authority to demand such data from said
utilities. Instead, DOE must rely on such industry initiatives such as
the IEEE TF or individual companies to voluntarily come forward with
data.
3. Future Load Growth
a. Liquid-Immersed Distribution Transformers
Several commenters stated their concerns over the possibility that
future loads would rise on distribution transformers as a result of
increased electrification. While no single commenter provided data or
projections (simulated or otherwise) to support this concern, some
commenters did hypothesize that liquid-immersed distribution
transformer loads may grow in the future. (Mulkey Engineering, No. 96
at p. 1; Cliffs, No. 105 at pp. 12-13; HVOLT, No. 134 at pp. 3-4; WEG,
No. 92 at p. 3; Idaho Power, No. 139 at p. 2)
Metglas commented that electrification impacts on distribution
transformers would be uncertain. Metglas commented that electrification
is likely to increase in response to global decarbonization goals.
However, Metglas added that efficiency improvements in HVAC units,
electric lighting, and other areas have kept the demand for electricity
consumption essentially flat since 2010. The proposed DOE efficiency
regulations will also help to decrease loading on the grid. (Metglas,
No. 125 at p. 4)
CEC commented that electrification is increasing energy demands,
with demand expected to increase by nearly 29 percent by 2035. CEC
noted that increasing transformer efficiency would help reduce demand
on the grid, but recommended DOE closely examine technical, cost, and
reliability issues because of the unique risk that transformers pose to
broader electrification trends. (CEC, No. 124 at pp. 1-2)
HVOLT and WEG commented that based on information supplied by EIA,
total (net) generation had grown at a rate of 3.3 percent between 2021
and 2023. (HVOLT, No. 134 at pp. 3-4; WEG, No. 92 at p. 3) Further,
APPA questioned DOE's use of EIA's AEO projection of future delivered
electricity, stating that other trends suggest potentially much higher
rates of electric end-use consumption, and citing President Biden's
Executive Order No. 14037, which calls for 50 percent of all new
passenger cars and light trucks sold in 2030 to be zero-emission
vehicles. APPA commented that there are a wide variety of projections
of electric vehicle sales by 2030, and EV sales already reached nearly
6 percent of all new car purchases in 2022, and that share is only
expected to increase. Additionally, APPA commented that Federal and
State governments are mandating that homes and buildings be electrified
to cut emissions. (APPA, No. 103 at p. 5) NYSERDA commented that EIA
forecasts of electricity demand do not reflect the significant demand
increases anticipated in New York and other parts of the country due to
aggressive decarbonization policies and accelerating rates of EV
adoption. As such, NYSERDA anticipates DOE has underestimated the
potential energy-saving impact of these standards, underscoring the
need to complete this rulemaking as quickly as possible. (NYSERDA, No.
102 at pp. 1-2) Carte commented that EIA's loading appears to be based
on history and not forward looking, which could explain why such a low
increase in loading is predicted. Carte commented that electrification
does not appear to be considered when talking about 0.9 percent
increases per year. (Carte, No. 140 at p. 6)
Further, APPA commented that with electric vehicles, solar
photovoltaic, building decarbonization, and other energy transition
technologies, the average household will move from an average load of 2
kW to an average of 6 kW and a peak of 5 kW to a peak of 10 to 25 kW
(with range based on EV sizing). APPA commented that currently, 25 kVA
transformers serve two to six residences, and transformers are going to
see at least twice the load, with fewer low/no load hours. APPA
commented that an economic justification analysis for the proposed
distribution transformer efficiency
[[Page 29929]]
standards would need to address the change in the way transformers will
operate during and after the transition and analyze how NOES
transformer efficiency will be impacted by these changes, and whether
those changes impact the NOPR's cost/benefit analysis. (APPA, No. 103
at p. 17)
Regarding HVOLT and WEG's comment about net generation growth, DOE
notes that net generation cannot be used as a proxy for distribution
transformer loads.\147\ Net generation is a ``top-down'' indicator of
how much generation is required to meet ``bottom-up'' demands of
electrical consumption (purchases) and must account for generating
capacity to meet total peak generation, reserve margins, the capacity
factors of each variety of generating unit, and transmission losses,
plus unavailable capacity (outages).148 149 150 DOE finds
that EIA's changes in projected purchased electricity to the final
consumer represents a more appropriate proxy for distribution
transformer load growth due to the distribution system's physical
proximity to the final electrical consumer. For this final rule, DOE
has continued to use AEO's projection of Energy Use: Delivered:
Purchased Electricity, noting that the rate has changed from that in
the NOPR to 0.7 percent per year in this final rule.\151\
---------------------------------------------------------------------------
\147\ Net generation: the amount of gross generation less the
electrical energy consumed at the generating station(s) for station
service or auxiliaries. See www.eia.gov/tools/glossary/
index.php?id=Net%20generation#:~:text=Net%20generation%3A%20The%20amo
unt%20of,is%20deducted%20from%20gross%20generation.
\148\ Rserve margin: The amount of unused available capability
of an electric power system (at peak load for a utility system) as a
percentage of total capability. See www.eia.gov/tools/glossary/index.php?id=R.
\149\ Capacity factor: The ratio of the electrical energy
produced by a generating unit for the period of time considered to
the electrical energy that could have been produced at continuous
full power operation during the same period. See www.eia.gov/tools/glossary/index.php?id=C.
\150\ Capacity factors vary by generating unit, ranging from 92
percent for nuclear generation (almost always on and available) to
24 percent for solar PV (the sun isn't always shining where the
collector are located). See www.eia.gov/electricity/monthly/epm_table_grapher.php?t=epmt_6_07_a, and www.eia.gov/electricity/monthly/epm_table_grapher.php?t=epmt_6_07_b.
\151\ See www.eia.gov/outlooks/aeo/data/browser/#/?id=2-
AEO2023®ion=1-
0&cases=ref2023&start=2021&end=2050&f=A&linechart=~~~~ref2023-
d020623a.103-2-AEO2023.1-0&map=ref2023-d020623a.3-2-AEO2023.1-
0&ctype=linechart&sourcekey=0.
---------------------------------------------------------------------------
APPA's comments to DOE did not suggest any specific alternative
trends that would suggest potentially much higher rates of electric
end-use consumption in place of AEO. As discussed later in this
section, DOE applies the rate of load growth over its entire analysis
period resulting in a significant growth of 22 percent, which results
in positive consumer benefits for all liquid-immersed equipment at
today's amended standard levels (see broadly: section V) Additionally,
as specified in 10 CFR part 431, subpart K, appendix A certification of
medium-voltage liquid-immersed distribution transformers must occur at
50 percent PUL--a rate that ensures efficient load-loss performance
over a wide range of loads, both low and high. If loads were to grow at
a rate greater than that estimated by AEO, the standard adopted by DOE
would result in greater energy savings, and consumer and National
benefits.
Further APPA, NYSERDA, and Carte commented that future loads would
be driven by increased EV adoption, claiming that EV adoption is not
included in AEO's total purchase electricity projection. DOE's
examination of AEO2023, Table 2, Energy Consumption by Sector and
Source, shows purchased electricity to transportation (including light
duty vehicles) to increase at a rate of 9.7 percent per year.
Idaho Power commented that it expects residential loads to increase
10 to 25 percent; however, no time period for this increase was
provided. (Idaho Power, No. 139 at p. 2) Xcel Energy commented that
with increased electrification, it expects an increase in load factor
and a higher rate of changeouts (to larger-capacity units). (Xcel
Energy, Public Meeting Transcript, No. 57 at p. 133) WEC commented that
it projected that loading would increase by 5 to 15 percent on its
single-phase distribution transformers; again, no period over which
this would occur was provided. (WEC, No. 118 at p. 1) Carte commented
that increased adoption of EVs and other electrification technologies
will greatly increase transformer loads. (Carte, No. 140 at pp. 5-6)
Further, Carte and CARES expressed a belief that loads will grow by 50
percent, a number that they attribute to EEI without citation. (Carte,
No. 140 at p 6; CARES, No. 99 at p. 4)
Specifically, in response to the assertions from Carte and CARES
that loads will grow by 50 percent over the next 5 to 10 years, DOE has
identified a presentation that is believed to be the source document of
these values; \152\ the presentation forecasts that the range of
electric loads increase will ``vary wildly, anywhere from 5 and 50
percent, depending on multiple factors,'' indicating that 50 percent is
a maximum bound of EEI's load growth estimate--not the likely outcome
indicated by Carte and CARES.
---------------------------------------------------------------------------
\152\ See: https://www.regulations.gov/document/EERE-2019-BT-STD-0018-0162.
---------------------------------------------------------------------------
As stated in the January 2023 NOPR, and evidenced by the comments
received, many factors potentially impact future distribution
transformer load growth, and these factors may be in opposition. At
this time, many utilities, States, and municipalities are pursuing EV
charging programs, and it is unclear the extent to which increases in
electricity demand for EV charging or other State-level decarbonization
efforts, will impact current distribution transformer sizing practices
(for example, whether distribution utilities plan to upgrade their
systems to increase the capacity of connected distribution
transformers, thus maintaining current loads as a function of
distribution transformer capacity; or if distribution utilities do not
plan to upgrade their systems and will allow the loads on existing
distribution transformers to rise). DOE recognizes that this is further
complicated by the current supply shortage of distribution equipment.
Some stakeholders speculate that these initiatives will increase the
intensive per-unit load over time as a function of per unit of
installed capacity. However, these stakeholders did not provide any
quantitative evidence that this is indeed happening on their
distribution systems, or in regions that are moving forward with
decarbonization efforts. Further, the hypothesis that intensive load
growth will be a factor in the future is not supported by available
future trends in AEO2023, as indicated by the purchased electricity
trend representing the delivered electricity to the customer. Others
asserted that higher loads in response to decarbonization initiatives
would be met with the extensive growth of the distribution system
(i.e., increasing the total capacity of the distribution system through
larger distribution transformers, or greater shipments, or some
combination of both). Again, data were not provided to support this
position, but some utilities stated they were maintaining service by
(a) increasing the distribution capacity of given circuits (i.e.,
installing larger transformers); or (b) reducing the number of
customers on a given circuit (i.e., installing more transformers).\153\
(APPA, No. 103 at p. 17; Highline Electric, No. 71 at pp. 1-2; Idaho
Power, No. 139 at p. 5) For this final rule, DOE finds that neither
position provides enough evidence to change its assumptions from the
January 2023
[[Page 29930]]
NOPR and August 2021 Preliminary Analysis TSD. For this final rule, DOE
updated its load growth assumption for liquid-immersed distribution
transformers based on the change in average growth of AEO2023:
Purchased Electricity: Delivered Electricity, which shows a year-on-
year growth rate of 0.7 percent. While this value may seem low, when
compounded over the analysis period it results in a significant growth
of 22 percent, which is higher than the rates indicated by Idaho Power
and WEC, albeit over a presumed longer timeframe.
---------------------------------------------------------------------------
\153\ Discussed in section IV.G.2 of this document in detail.
---------------------------------------------------------------------------
Additionally, DOE has examined a scenario in the NIA to measure the
potential impacts of increased capacity by shifting smaller units to
larger units. There is little information from which to model this
shift--specifically over how long a period this shift to larger
capacities would occur. Based on report studying the impact of EVs on
transformer overloading,\154\ and the impacts of reduced transformer
lifetimes from increased transformer loads \155\ DOE estimated the
extensive growth of the distribution system that would be needed. These
studies indicate that it is distribution transformer up to 100 kVA that
are at risk of overloading (EC 1B), and associated lifetime reductions,
and most likely to be replaced with larger capacity equipment. These
studies indicate that the risk of overload diminishes with increased
capacity, with 100 kVA being the upper limit. DOE's approach shifts the
capacities transformer shipments over to larger capacity equipment. DOE
includes this scenario for illustrative purposes. This shift and
results can be found in appendix 10C of the TSD. These results indicate
that for EC 1B in the event of such a capacity shift, the national
full-fuel cycle energy savings will increase by 21 percent, with the
net present value of consumer savings also increasing by 19 and 20
percent, at 3 and 7 percent discount rates, respectively.
---------------------------------------------------------------------------
\154\ Dalah, S., Aswani, D., Geraghty, M., Dunckley, J., Impact
of Increasing Replacement Transformer Size on the Probability of
Transformer Overloads with Increasing EV Adoption, 36th
International Electric Vehicle Symposium and Exhibition, June, 2023.
Available online at: https://evs36.com/wp-content/uploads/finalpapers/FinalPaper_Dahal_Sachindra.pdf.
\155\ Jodie Lupton, Right-Sizing Residential Transformers for
EVs, T&D World,January 2024, Available online: https://prismic-io.s3.amazonaws.com/wwwpowerengcom/9dd90ffc-4df8-442c-92c2-eb175f687ea0_Right-sizing+residential+transformers+for+EVs.pdf.
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[[Page 29931]]
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[[Page 29932]]
[GRAPHIC] [TIFF OMITTED] TR22AP24.536
[GRAPHIC] [TIFF OMITTED] TR22AP24.537
Chapter 7 of the final rule TSD provides details on DOE's energy
use analysis for distribution transformers.
F. Life-Cycle Cost and Payback Period Analysis
DOE conducted LCC and PBP analyses to evaluate the economic impacts
on individual consumers (in this case distribution utilities for
liquid-immersed, and COMMERCIAL AND INDUSTRIAL entities for low-, and
medium-voltage dry-type) of potential energy conservation standards for
[[Page 29933]]
distribution transformers. The effect of amended energy conservation
standards on individual consumers usually involves a reduction in
operating cost and an increase in purchase cost. DOE used the following
two metrics to measure consumer impacts:
[ssquf] The LCC is the total consumer expense of an appliance or
product over the life of that product, consisting of total installed
cost (manufacturer selling price, distribution chain markups, sales
tax, and installation costs) plus operating costs (expenses for energy
use, maintenance, and repair). To compute the operating costs, DOE
discounts future operating costs to the time of purchase and sums them
over the lifetime of the product.
[ssquf] The PBP is the estimated amount of time (in years) it takes
consumers to recover the increased purchase cost (including
installation) of a more-efficient product through lower operating
costs. DOE calculates the PBP by dividing the change in purchase cost
at higher efficiency levels by the change in annual operating cost for
the year that amended or new standards are assumed to take effect.
For any given efficiency level, DOE measures the change in LCC
relative to the LCC in the no-new-standards case, which reflects the
estimated efficiency distribution of distribution transformers in the
absence of new or amended energy conservation standards. In contrast,
the PBP for a given efficiency level is measured relative to the
baseline product.
For each considered efficiency level in each product class, DOE
calculated the LCC and PBP for a nationally representative set of
electric distribution utilities and commercial and industrial
customers. As stated previously, DOE developed these customer samples
from various sources, including utility data from the Federal Energy
Regulatory Commission (FERC), EIA; and commercial and industrial data
from the Commercial Building Energy Consumption Survey (CBECS) and
Manufacturing Energy Consumption Survey (MECS). For each sample, DOE
determined the energy consumption in terms of no-load and load losses
for distribution transformers and the appropriate electricity price. By
developing a representative sample of consumer entities, the analysis
captured the variability in energy consumption and energy prices
associated with the use of distribution transformers.
Inputs to the LCC calculation include the installed cost to the
consumer, operating expenses, the lifetime of the product, and a
discount rate. Inputs to the calculation of total installed cost
include the cost of the equipment--which includes MSPs, retailer and
distributor markups, and sales taxes--and installation costs. Inputs to
the calculation of operating expenses include annual energy
consumption, electricity prices and price projections, repair and
maintenance costs, equipment lifetimes, and discount rates. Inputs to
the PBP calculation include the installed cost to the consumer and
first year operating expenses. DOE created distributions of values for
equipment lifetime, discount rates, and sales taxes, with probabilities
attached to each value, to account for their uncertainty and
variability.
The computer model DOE uses to calculate the LCC and PBP relies on
a Monte Carlo simulation to incorporate uncertainty and variability
into the analysis. The Monte Carlo simulations randomly sample input
values from the probability distributions and distribution transformer
samples. For this rulemaking, the Monte Carlo approach is implemented
as a computer simulation. The model calculated the LCC and PBP for
products at each efficiency level for 10,000 individual distribution
transformer installations per simulation run. The analytical results
include a distribution of 10,000 data points showing the range of LCC
savings for a given efficiency level relative to the no-new-standards
case efficiency distribution. In performing an iteration of the Monte
Carlo simulation for a given consumer, product efficiency is as a
function of the consumer choice model described in section IV.F.2 of
this document. If the chosen equipment's efficiency is greater than or
equal to the efficiency of the standard level under consideration, the
LCC and PBP calculation reveals that a consumer is not impacted by the
standard level. By accounting for consumers who are already projected
to purchase more-efficient products in a given case, DOE avoids
overstating the potential benefits from increasing product efficiency.
DOE calculated the LCC and PBP for all consumers of distribution
transformers as if each were to purchase new equipment in the expected
year of required compliance with amended standards. Amended standards
would apply to distribution transformers manufactured five years after
the date on which any new or amended standard is published in the
Federal Register. Therefore, DOE used 2029 as the first year of
compliance with any amended standards for distribution transformers.
Table IV.11 summarizes the approach and data DOE used to derive
inputs to the LCC and PBP calculations. The subsections that follow
provide further discussion. Details of the model, and of all the inputs
to the LCC and PBP analyses, are contained in chapter 8 of the TSD and
its appendices.
[[Page 29934]]
[GRAPHIC] [TIFF OMITTED] TR22AP24.538
1. Equipment Cost
To calculate consumer product costs, DOE multiplied the MPCs
developed in the engineering analysis by the markups described
previously (along with sales taxes). DOE used different markups for
baseline products and higher-efficiency products because DOE applies an
incremental markup to the increase in MSP associated with higher-
efficiency products.
DOE examined historical producer price index (PPI) data for
electric power and specialty transformer manufacturing available
between 1967 and 2022 from the BLS.\156\ Even though this PPI series
may also contain prices of electrical equipment other that distribution
transformers, this is the most disaggregated price series that is
representative of distribution transformers. DOE assumes that this PPI
is a close proxy to historical price trends for distribution
transformers, including liquid-immersed, and medium-, and low-voltage
dry-type transformers. The PPI data reflect nominal prices adjusted for
product quality changes. The inflation-adjusted (deflated) price index
for electric power and specialty transformer manufacturing was
calculated by dividing the PPI series by the Gross Domestic Product
Chained Price Index.
---------------------------------------------------------------------------
\156\ Product series ID: PCU3353113353111. Available at
www.bls.gov/ppi/.
---------------------------------------------------------------------------
DOE has observed a spike in the trend of annual real prices between
2021 and 2022. However, when the PPI is examined at a month-by-month
level, the deflated PPI from 2022 through 2023 appears to be leveling
off. Specifically, the deflated monthly PPI data in Table IV.12 shows a
near constant value since June 2022. DOE further examined the trends on
key inputs into distribution transformers: steel, aluminum, and
copper--these inputs show a similar trend over this same
period.157 158 159 DOE notes that the engineering analysis
estimated MSPs in 2023; additionally, and that it has captured the
impact of this spike, if it were realized, as a constant increase in
real prices in the low economic price scenario results shown in section
V.C of this document.
---------------------------------------------------------------------------
\157\ Steel: WPU101
\158\ Aluminum: ID: WPU10250105
\159\ Copper: WPU10260314
---------------------------------------------------------------------------
[[Page 29935]]
[GRAPHIC] [TIFF OMITTED] TR22AP24.539
DOE received no comments on its future price trend methodology in
the NOPR. For this final rule, DOE maintained the same approach for
determining future equipment prices as in the NOPR and assumed that
equipment prices would be constant over time in terms of real dollars
(i.e., constant 2023 prices).
2. Efficiency Levels
As in the January 2023 NOPR, for this final rule, DOE analyzed
various efficiency levels expressed as a function of loss reduction
over the equipment baseline \160\ as well as an overall efficiency
rating. For units greater than 2,500 kVA, there is not a current
baseline efficiency level that must be met. Therefore, DOE established
EL 1 for these units as if they were aligning with the current energy
conservation standards efficiency vs kVA relationship, scaled to the
larger kVA sizes. To calculate this, DOE scaled the maximum losses of
the minimally compliant design from the next highest kVA representative
unit to the 3,750 kVA size using the equipment class specific scaling
relationships in TSD appendix 5C. For example, for three-phase liquid-
immersed distribution transformers, the highest kVA representative unit
is RU5, corresponding to a 1,500 kVA transformer. A minimally compliant
1,500 kVA design is 99.48-percent efficient and has 3,920 W of total
losses at 50-percent load, with representative no-load and load losses
of 1,618 W and 2,290 W respectively based on RU5. Using the updated
scaling factors of 0.73 and 1.04 for no-load and load losses
respectively, as described in appendix 5C, the total losses of a 3,750
kVA unit would be 9,096 W, corresponding to 99.52-percent efficient at
50-percent load.
---------------------------------------------------------------------------
\160\ Calculated as the current percentage loss (i.e., 100
percent minus the current standard) multiplied by the percent
reduction in loss plus the current standard
---------------------------------------------------------------------------
EL 2 through EL 5 align with the same percentage reduction in loss
as their respective equipment class, but rather than being relative to
a baseline level, efficiency levels were established relative to EL 1
levels.
The rate of reduction is shown in Table IV.13, and the
corresponding efficiency ratings in Table IV.14.
[[Page 29936]]
[GRAPHIC] [TIFF OMITTED] TR22AP24.540
[[Page 29937]]
[GRAPHIC] [TIFF OMITTED] TR22AP24.541
DOE did not receive any comments regarding either the loss rates or
the efficiency levels applied in the NOPR and continued their use for
this final rule.
3. Modeling Distribution Transformer Purchase Decision
In the January 2023 NOPR TSD, DOE presented its modelling
assumptions on how distribution transformers were purchased. DOE used
an approach that focuses on the selection criteria that customers are
known to use when purchasing distribution transformers. Those criteria
include first costs as well as the total ownership cost (TOC) method,
which combines first costs with the cost of losses. Purchasers of
distribution transformers, especially in the utility sector, have
historically used the TOC method to determine which distribution
transformers to purchase. However, comments received from stakeholders
responding to the 2012 ECS NOPR (77 FR 7323) and the June 2019 Early
Assessment RFI (84 FR 28254) indicated that the widespread practice of
concluding the final purchase of a distribution transformer based on
TOC is rare. Instead, customers have been purchasing the lowest first
cost transformer design regardless of its loss performance. Respondents
noted that some purchasers of distribution transformers do so on the
basis of first cost in order to, among other things, maximize their
inventories of transformers per dollar invested. This behavior allows
transformer purchasers to have the maximum inventory of units available
to quickly respond to demand for new transformers, as well as have
replacements readily available in the event of transformer failure. DOE
continues to explore consumer choice and market reaction to the new
efficiency standards levels and the impact it would have on purchasers'
inventory of transformers. This may be further explored in a future
RFI. As discussed in section IV.F.3.b of this document the practice of
purchasing based on first cost is unlikely to change over time.
The utility industry developed TOC evaluation as a tool to reflect
the unique financial environment faced by each distribution transformer
purchaser. To express variation in such factors as the cost of electric
energy, and capacity and financing costs, the utility industry
developed a range of evaluation factors: A and B values, to use in
their calculations.\161\ A and B are the
[[Page 29938]]
equivalent first costs of the no-load and load losses (in $/watt),
respectively.
---------------------------------------------------------------------------
\161\ In modeling the purchase decision for distribution
transformers DOE developed a probabilistic model of A and B values
based on utility requests for quotations when purchasing
distribution transformers. In the context of the LCC the A and B
model estimates the likely values that a utility might use when
making a purchase decision.
---------------------------------------------------------------------------
In response to the NOPR analysis, DOE received the following
comments regarding the modeling of distribution transformer purchases.
a. Equipment Selection
DOE did not receive comments regarding how engineering designs were
selected by the consumer choice model in the LCC and maintained the
material constraints in be no-new-standards case from the January 2023
NOPR in this final rule. For the January 2023 NOPR, DOE's research
indicated that distribution transformers can be fabricated with
amorphous core steels that are cost competitive with conventional
steels, as shown in the engineering analysis (see section IV.C), but
they cannot currently be fabricated in the quantities needed to meet
the large order requirements of electric utilities, and, as such, are
limited to niche products. DOE experience shows that this lack of
market response to the availability of new materials, amorphous, to be
unique to the purchase of distribution transformers. The current market
environment for distribution transformers is shaped primarily by the
availability of products with short lead times to consumers given
current demand dynamics. This in turn is driven by the availability of
existing production capacity. Currently, distribution transformer
capacity is primarily set up to produce equipment with GOES cores (97
percent of units). Because GOES production equipment cannot be readily
modified to manufacture amorphous distribution transformers, DOE
understands that this production capacity will continue to produce GOES
distribution transformers unless it is entirely replaced with amorphous
specific production equipment. As a result, the availability of GOES
core transformers will be maintained, even as amorphous production
capacity is added under amended standards.
This circumstance is unique to transformers where the production
lines for GOES and amorphous core equipment are not interchangeable,
meaning that to meet amended standards requiring amorphous core steel
manufacturers cannot retool existing production lines, but must add new
production capacity. DOE expects that, in the long term, manufacturers
may begin to replace GOES production equipment with amorphous
production equipment where amorphous is more cost competitive in the
presence of amended standards. However, as discussed in section IV.A.5
of this document, the distribution transformer market is currently
experiencing significant supply constraints, creating extended lead
times and supply shortages for distribution transformers. Therefore, to
address these supply shortages, manufacturers may choose to maintain
their GOES production to maximize their production output in the
presence of amended standards, even if amorphous production is a more
cost competitive production route. To reflect this, DOE has revised its
customer choice model in the no-new-standards and standards cases in
this final rule to limit the variety of core steel materials by TSL to
the ratios shown in Table IV.15. DOE updated the consumer choice model
from the January 2023 NOPR, which did not constrain the selection of
designs based on core material variety in the standards case, based on
feedback received expressing that manufacturers may maintain GOES
production, even in instances when amorphous transformers may be the
lowest cost option (See sections IV.A.4.c and IV.A.5 of this document).
These material limits account for impacts in the amended standards case
where GOES steel may continue to be used to meet the trial standard
levels (see section V.A of this document). These material limits
represent a conservative view of the future where AM does not displace
any GOES production, or the demand for GOES distribution transformers
is not diminished in favor of AM core distribution transformers. While
it is likely that over time there would be some displacement, it is too
speculative for DOE to establish amended standards on such a modeling
assumption. For informational purposes DOE has included LCC
sensitivities where the amorphous core distribution transformers
increase in availability to 10 percent, and 25 percent. These
sensitivity analyses, which demonstrate a higher percentage of
distribution transformer manufacturers utilizing amorphous steel cores
to meet TSL 3 standards, result in increasing LCC savings for EC 1B by
62 and 193 percent, respectively. Further for EC 2B the LCC savings
increased by 578 and 589 percent for increases in AM availability of 10
and 25 percent, respectively. The impacts of these sensitivities can be
reviewed in appendix 8E of the final rule TSD.
[[Page 29939]]
[GRAPHIC] [TIFF OMITTED] TR22AP24.542
b. Total Owning Cost and Evaluators
In the January 2023 NOPR Analysis TSD, DOE used TOC evaluation
rates as follows: 10 percent of liquid-immersed transformer purchases
were concluded using TOC, and 0 percent of low-voltage dry-type and
medium-voltage dry-type transformer purchases were concluded using TOC.
DOE received comments from several stakeholders regarding the rates at
which TOC are practiced.
NEMA and Prolec GE commented that the current percentage of
transformers that are being purchased using TOC is estimated to be
below 10 percent for both single-phase and three-phase transformers.
(Prolec GE, No. 120 at p. 12; NEMA, No. 141 at p. 15) However, Howard
commented that in 2022, its TOC adoption rate was in the 40-percent
range for both single- and three-phase liquid-immersed distribution
transformers. (Howard, No. 116 at p. 19) NRECA commented that many
electric cooperatives are RUS borrowers and thus use RUS Bulletin
1724D-107, ``Guide for Economic Evaluation of Distribution
Transformers,'' to calculate the cost of owning a transformer over its
useful life using the TOC method.\162\ NRECA added that given today's
supply chain challenges, its members' primary concern is the
availability of transformers, not the cost, and therefore DOE's
estimation of the utilities using TOC is not representative of real-
world experience. (NRECA, No. 98 at p. 7)
---------------------------------------------------------------------------
\162\ See: https://www.rd.usda.gov/sites/default/files/UEP_Bulletin_1724D-107.pdf.
---------------------------------------------------------------------------
Prolec GE, NEMA, NRECA, and Colorado Springs Utilities commented
that the low usage of TOC was the implementation of DOE's current
minimum efficiency levels (adopted in the April 2013 Standards Final
Rule (78 FR 23335) with compliance required in 2016) due to the TOC
formula becoming less relevant when defining the most cost-competitive
transformer design option resulting in most customers are purchasing
transformers based on lowest first-cost that meets the current DOE
efficiency levels. (Prolec GE, No. 120 at p. 12; NEMA, No. 141 at p.
15; Colorado Springs Utilities, Public Meeting Transcript, No. 75 at p.
114; NRECA, No. 98 at p. 7)
WEC commented that the best interests of its customers would be
served by allowing utilities to use their A and B factors to calculate
efficiency requirements, as cost evaluation is unique to each utility.
(WEC, No. 118 at p. 1) Rochester PU commented that it uses loss-
evaluated transformers for 30-plus years and if amorphous transformers
are the best choice based on its loss evaluation (which considers
energy cost), then those are the transformers Rochester PU would
purchase. (Rochester PU, Public Meeting Transcript, No. 75 at pp. 61-
62)
Given the comments received, DOE has maintained the same modeling
assumption in this final rule as it used in the January 2023 NOPR,
where an estimated 10 percent of purchases are concluded using TOC. DOE
notes however that this final rule is not prescriptive, and that
distribution transformers can be designed to meet any combination of A
and B values if the overall design meets the amended minimum efficiency
standards.
Howard provided the fraction of sales that are concluded based on
TOC. (Howard, No. 116 at p. 20) DOE applied the shipment weights per
EMM region from Howard's data in DOE's customer choice model with an
additional
[[Page 29940]]
percentage assigned to random EMM regions as was done in the NOPR, and
the entry for California split evenly between Northern and Southern
California. DOE found that for consumers who evaluate based on TOC in
DOE's modeling, they are limited to the EMM regions based on the
weights shown in Table IV.16.
[GRAPHIC] [TIFF OMITTED] TR22AP24.543
Band of Equivalents
In the August 2021 Preliminary Analysis TSD, DOE proposed the
following definition for Band of Equivalents (BOE): as a method to
establish equivalency between a set of transformer designs within a
range of similar TOC. BOE is defined as those transformer designs
within a range of similar TOCs. The range of TOC varies from utility to
utility and is expressed in percentage terms. In practice, the
purchaser would consider the TOC of the transformer designs within the
BOE and would select the lowest first-cost design from this set.
NEMA commented that BOE is generally not used for low- or medium-
voltage dry-type transformer purchases. (NEMA, No. 141 at p. 15) Based
on this comment from NEMA, DOE maintained its approach from the NOPR
where TOC and BOE are not applied to low- and medium-voltage
distribution transformers.
Mulkey Engineering commented on the risks associated with following
TOC ``to the penny,'' suggesting that a combination of TOC and BOE be
used when evaluating transformer purchases. In addition to other
experience-driven suggestions, Mulkey Engineering asserted a BOE rate
within TOC of 10 percent. (Mulkey Engineering, No. 96 at pp. 1-2) NEMA
commented that most utilities who use TOC methods also apply a band of
equivalency ranging from 3-10 percent of the TOC, where the lowest
first cost transformer in the band is purchased. (NEMA, No. 141 at p.
15) Finally, Prolec GE commented that BOE is used in less than half of
the cases where a TOC formula is specified. (Prolec GE, No. 120 at p.
12)
Based on the comments received, DOE will maintain the definition as
per the NOPR. Additionally, for this final rule, DOE included a BOE
rate of 5 percent for those consumers who use TOC in the consumer
choice model.
c. Non-Evaluators and First Cost Purchases
DOE defined those consumers who do not purchase based on TOC as
those who purchase based on lowest first costs. DOE did not receive any
comments regarding lowest first cost purchases and maintained the
approach from the NOPR in this final rule.
4. Installation Cost
Installation cost includes labor, overhead, and any miscellaneous
materials and parts needed to install the product. DOE used data from
RSMeans to estimate the baseline installation cost for distribution
transformers.\163\ In the January 2023 NOPR TSD, DOE asserted that
there would be no difference in installation costs between baseline and
more efficient equipment. DOE also asserted that 5 percent of
replacement installations would face increased costs over baseline
equipment due to the need for site modifications. Stakeholders
responded to DOE's assertions regarding installation costs as they
related to the increases in efficiency proposed in the NOPR.
---------------------------------------------------------------------------
\163\ Gordian, RSMeans Online, www.rsmeans.com/products/online
(last accessed Sept. 2023).
---------------------------------------------------------------------------
a. Overall Size Increase
Stakeholders had concerns over the increased size and weight of
equipment due to amended efficiency standards, specifically that
increased transformer size and weight would result in increased
technical issues and increased costs when replacement transformers are
installed in sensitive locations. (Cliffs, No. 105 at pp. 11-12; NEMA,
No. 141 at p. 6; Highline Electric, No. 71 at pp. 1-2; Indiana Electric
Co-Ops, No. 81 at p. 1; Southwest Electric, No. 87 at p. 3; Howard, No.
116 at pp. 24-25; Chamber of Commerce, No. 88 at p. 4; Pugh Consulting,
No. 117 at p. 5; NRECA, No. 98 at p. 6; Entergy, No. 114 at p. 4; SBA,
No. 100 at p. 6; WEC, No. 118 at p. 2; Portland General Electric, No.
130 at p. 4; Southwest Electric, No. 87 at pp. 2-3; Xcel Energy, No.
127 at p. 1; Idaho Power, No. 139 at pp. 5-6; APPA, No. 103 at p. 9;
Schneider, No.
[[Page 29941]]
101 at p. 2; Powersmiths, No. 112 at pp. 4-5)
The Efficiency Advocates commented that any size-related impacts
resulting from DOE's proposal are not expected to significantly impact
transformer installations. The Efficiency Advocates commented that as
of 2015, more than 4 million AM transformers had been sold globally,
with about 600,000 installed in the United States, over 1 million in
China, and 1.3 million in India--this number of installed global AM
units has increased several-fold since 2015. The Efficiency Advocates
estimated that over 90 percent of liquid-immersed transformers sold in
Canada use AM. The Efficiency Advocates commented it understands that
``well-designed AM transformers'' are not meaningfully larger than
current GOES transformers and noted that DOE's NOPR analysis considered
the potential impact of increased transformer size on pole and vault
installations. (Efficiency Advocates, No. 121 at pp. 6-7)
In response to these comments, the amended standard in this final
rule shows the following increases in transformer size and weight shown
in Table IV.17 through Table IV.19. The impact on liquid immersed
transformer weight om amended standards is expected to be less than 10
percent for small (<=100 kVA) single-phase (overhead and surface
mounts). For large (>100 kVA) single-phase the weight is expected to
increase from 16 to 21 percent. For small three-phase (<500 kVA) the
expected increase in weight and footprint (ft\2\) are 4 and 1 percent,
respectively. For large (>=500 kVA) three-phase the expected increase
in weight and footprint (ft\2\) are expected to be 2 and 1 percent,
respectively; with the exception of three-phase liquid-immersed
distribution transformers greater than 2500 kVA where ethe increases in
the weight and footprint (ft\2\) are expected to be 25 and 8 percent,
respectively.
[GRAPHIC] [TIFF OMITTED] TR22AP24.544
[[Page 29942]]
[GRAPHIC] [TIFF OMITTED] TR22AP24.545
[GRAPHIC] [TIFF OMITTED] TR22AP24.546
DOE appreciates these general comments and refers to its responses
below on specific installation cost concerns.
b. Liquid-immersed
NEMA, commented that the proposed amended standard would result in
medium-voltage liquid- and dry-type unit weight increasing by 50
percent and generally result in 15-percent taller, wider, and deeper
units compared to those designed to meet the current standards; and
that tank diameters and/or tank heights increases of 15 percent or more
will create new logistical challenges. (NEMA, No. 141 at p. 6). WEB and
LBA also expressed concerns regarding the potential increased weights
of transformers more generally. (WEG, No. 92 at p. 2; LBA, No. 108 at
p. 3)
EEI and NEMA commented that the transportation, delivery, and
handling of the new (heavier) equipment will also be impacted. EEI and
NEMA commented that the increased size means fewer units per truck,
with larger and heavier equipment requiring more trucks to move units
to their installation locations. EEI and NEMA commented that for pole
mounted transformers, new poles to support the weight will have to be
sourced; for pad-mounted transformers, thicker and larger concrete pads
will have to be poured. EEI and NEMA added that larger and heavier also
means bigger boom cranes necessary to lift such equipment will need to
be procured. (EEI, No. 135 at pp. 20-21; NEMA, No. 141 at p. 3)
[[Page 29943]]
Idaho Falls Power and Fall River commented that amorphous core
transformers are larger in size and heavier per kW rating than their
counterparts, sometimes by more than 40 percent, leading to issues
related to space and weight, such as placement in existing vaults where
clearances must be maintained for safety reasons, or placement on poles
designed to hold a specific weight. (Idaho Falls Power, No. 77 at p. 1;
Fall River, No. 83 at p. 2)
WEG commented that another major consideration, especially for
urban areas, will be physical space requirements, as distribution
transformers in major cities are often located in some variety of
physical structure with specific limitations as to what size
transformer can be installed. WEG commented that increased overall
transformer size could drive a significant civil engineering issue in
urban areas to accommodate transformers that meet these amended
standards. (WEG, No. 92 at p. 2)
As shown in in Table IV.17 through Table IV.19, DOE expects the
maximum weight increase from amended standards to be no greater 25
percent for three-phase liquid-immersed transformer over 2500 kVA,
representing less than 0.5 percent of unit shipped. This is much less
than 50 percent increase indicated by NEMA. DOE notes that for the vast
majority of unit shipped (small single-phase up to and including 100
kVA), representing 91 percent of single-phase shipments, the impact on
weight is an increase of between 1 and 2 percent.
c. Overhead (Pole) Mounted Transformers
Highline Electric provided information describing its fleet of
distribution transformers and limitations, including approximately 250
banks of three 75 kVA pole-mount transformers and 500 banks of three 50
kVA pole-mount transformers. Highline Electric commented that it
currently does not deploy larger than 75 kVA pole-mount transformers
due to pole load limitations and the proposed amended standards would
result in new, standards compliant, 50 kVA transformers with a weight
like existing baseline 75 kVA transformers, and compliant 75 kVA
transformers with a weight more than a baseline100 kVA pole-mount unit.
Highline Electric added that it discontinued use of 100 kVA pole-mount
units decades ago after outage records indicated such installations
were prone to unacceptable rates of pole failure. (Highline Electric,
No. 71 at pp. 1-2)
Further, Highline Electric commented that if transformer weights
are increased by 20-40 percent, compliant 75 kVA transformers could not
be installed on Highline Electric's standard class of poles. Highline
Electric commented it would instead have to: (1) Utilize pole-mount
transformers that predate the proposed amended standards, which would
require a two-man crew with a material handler truck plus a few hours
of labor and can be done proactively or reactively during outage
conditions; (2) Convert to pad-mount transformers, which would require
a 3-plus man crew, a digger derrick truck, and enough hours of labor
that such an operation could only be completed proactively as it would
require unacceptably long outage restoration times; or, (3) Replace the
existing pole to a much heavier-class of pole, which would require a 3-
plus man crew, a digger derrick truck, and enough hours of labor that
such an operation could only be completed proactively as it would
require unacceptably long outage restoration times--this option assumes
that the heavier-class of pole is available at the time of need.
(Highline Electric, No. 71 at p. 2)
Idaho Power commented that it considers the 25-percent estimate for
pole replacements to be too low, as it is likely that every transformer
larger than 100 kVA on its distribution system would require an upsized
pole. Idaho Power commented this may also be the case for 50 kVA and 75
kVA transformers. Idaho Power recommended that DOE consider increasing
the 25-percent replacement number used in 2013 to better reflect the
impact of the additional weight from amorphous core transformers on
pole replacements. (Idaho Power, No. 139 at pp. 5-6) Additionally,
Idaho Power stated it had designs for a few pole-mounted transformers
with amorphous cores, noting that for 50 kVA and smaller transformers,
the additional weight is not enough to increase the installation cost,
but for transformers 100 kVA and larger, the weights increased between
40 and 60 percent and will likely require higher class poles resulting
in increased installation costs. (Idaho Power, No. 139 at p. 5)
Alliant Energy commented that DOE's proposal presents
implementation and installation challenges given the greater size and
weight of amorphous core distribution transformers, which may require
additional pole replacement, larger trucks for transport, and the use
of cranes for installation. (Alliant Energy, No. 128 at p. 3)
Howard and Chamber of Commerce commented that the proposed amended
standards may require the upgrading and/or full replacement of the
brackets as IEEE standards stipulate that the top support lug must be
at least five times the transformer weight. Howard and Chamber of
Commerce commented that for most manufacturers, the current transformer
weight limit for support lug A is about 1000 lbs., B is about 3000
lbs., and Big B is 4000 lbs. Further, Howard and Chamber of Commerce
commented that the new designs under this NOPR would also increase tank
diameters, moving the center of gravity further away from the pole
interface and increasing the moment force on the pole bracket. (Howard,
No. 116 at pp. 24-25; Chamber of Commerce, No. 88 at p. 1) Highline
Electric commented that pole replacements are not directly attributable
to the larger kVA capacity, but rather are attributable to the weight
of these larger kVA units. Highline Electric commented that poles are
not rated to hold certain amounts of kVA capacity in the air; they are
rated to hold certain pounds in weight and certain pounds in wind-
loading (cross-sectional area of a transformer bank). (Highline
Electric, No. 71 at p. 1)
Southwest Electric commented that the proposed amended standard for
single-phase designs, which typically include simpler cooling
capability (fins versus cooling plates), will result in percent
increases in tank and conductor weights exceeding that of 3-phase,
raising the significant problem that most single-phase transformers are
mounted overhead via utility poles, scaffolding, or some other
platform. Southwest Electric commented that the increased weight of
NOPR-compliant transformers could lead to further potential outages,
pushing these annual costs even higher. (Southwest Electric, No. 87 at
p. 3)
EEI, Entergy, and Pugh Consulting commented that the electric
utility industry is experiencing constraints with wood pole supplies,
especially poles with higher strength capacities, and an increase in
demand for stronger poles could cause additional challenges. (Entergy,
No. 114 at p. 4; Pugh Consulting, No. 117 at p. 5; EEI, No. 135 at pp.
21-24)
DOE's analysis at the amended standard levels indicate the
following weight increases for overhead mounted distribution
transformers. DOE's engineering and LCC analysis of overheard
transformers are conducted for the representative units discussed in
section IV.C.1, representative unit 2 (25 kVA) and representative unit
3 (500 kVA). DOE has scaled the weights determined in the engineering,
and selected in the LCC model to the other common capacities shown in
Table IV.17. These show that the increased
[[Page 29944]]
weight under amended standards is projected to be modest, under 10
percent for transformers up to and including 100 kVA in capacity--which
is approximately 95 percent of all single-phase shipments (in terms
units) and 99 percent of overhead shipments (in terms of units).
Further, the projected weights, except for 833 kVA, which are less than
0.05 percent of annual overhead units shipped, are not expected to
change the application of the support lugs mentioned by NEMA from
current practices.\164\ The modest weight increases are below the
supplied thresholds for premature pole change outs supplied by Highline
Electric and Idaho Power and consequently are not expected results in
undue burden of requiring new, higher-grade poles.
---------------------------------------------------------------------------
\164\ Overhead transformers at 833 kVA represent less than 0.01
precent of units shipped. See section G for detailed shipments
projections.
---------------------------------------------------------------------------
DOE cannot directly comment on the availability of wooden poles at
higher strength classes. The comments from EEI, Entergy, and Pugh
Consulting did not state which classes of poles they considered
commonly used, or which classes of poles are considered higher
strength. DOE reiterates that the increase in transformer weight
determined in its analysis is expected to be sufficiently modest
(estimated to be less than 20 percent), that it will not likely disrupt
the current wooden pole supply chains, and not in the 40 to 60-percent
range suggested by stakeholders. There is insufficient information to
justify increased installation costs given the modest projected
increase in equipment weight resulting from amended standards, however,
DOE recognizes the uncertainty surrounding installation costs because
it is a complex issue. DOE's technical analysis in appendix 8F of this
final rule TSD shows there to be minimal load bearing impact on the
structures used to mount overhead distribution transformers resulting
from amended standards. However, each utility's distribution system is
unique with different equipment build-outs of different vintages. Given
the heterogeneous nature of distribution systems it is not possible for
DOE to account for every potential hypothetical installation
circumstance. To account for the uncertainty faced by distribution
utilities raised in the comments above, DOE has increased the fraction
of installations that will face additional costs from 5 percent in the
January 2023 NOPR to 50 percent when the weight increase over current
baseline equipment is greater than 10 percent.
NRECA commented that DOE analysis assumes like-for-like pole
replacements, which is misguided. NRECA commented it expects that more
transformer replacements will be necessary to allow for greater-
capacity transformers due to electrification, thus requiring larger
poles. (NRECA, No. 98 at p. 6)
In response to NRECA, for the purpose of estimating the cost and
benefits to consumers from a modeling perspective DOE needs to bound
the issue of what is considered a replacement versus new installation.
While NRECA comments that it expects future replacements to be of
greater capacity than what is currently installed, NRECA did not
provide any information on what it considers the current typical
capacity, and what they'd be replaced with in the future. DOE can agree
with NRECA that, in practice, replacing a 25 kVA overhead with a new 50
kVA to maintain current levels of service can reasonably be considered
a replacement. However, DOE maintains that, for example, installing a
167 kVA in the place of a 25 kVA to meet new service would be a new
installation, as it would require additional planning, secondary
conductors, and likely a new structure (pole).
Replacement Costs
Idaho Power typically charges between $3,500-5,000 for a pole
replacement. (Idaho Power, No. 139 at p. 6) SBA provided cost estimates
for wooden poles range anywhere from $500 to $1,400 per pole depending
on labor and material shipping costs for small utilities. (SBA, No. 100
at p. 6) WEC commented that it does not install transformers over 4,500
lbs. on a single pole. To change to a two-pole structure will cost from
$10,000 to $15,000 per transformer, assuming there is room for a two-
pole structure which is not viable in all locations. WEC further
commented it would cost anywhere from $2,000 to $10,000 to change out
the pole for a single transformer depending on its location and what
other equipment is installed on the pole, which could lead to increased
costs beyond these estimates. (WEC, No. 118 at p. 2)
Based on the comments from Idaho Power, SBA and WEC DOE examined
the values it used in the NOPR for the cost of pole replacement. DOE
derived its values based on the RSMeans 2023, and found that the
average price of a new single-pole installation ranged in cost,
equipment and labor, (excluding profit, and excavation) ranged from
$504 to $3,125 for 30 and 70 foot treated poles, respectively. The data
from RSMeans indicates a strong relationship between pole length and
cost, and did not include the additional cost for excavation that would
be incurred by a utility. While the stakeholders did not provide the
pole length or grades associated with the supplied costs, which DOE
would expect such costs to vary on a utility-by-utility bases. Based on
the information provided by stakeholders and RSMeans DOE has updated
its pole replacement cost distribution for this final rule, which is a
triangular distribution, for single-pole structures: low: $2,025; mode:
$4,012; high: $5,999. And for multi-pole structures: low: $5,877; mode:
$11,388; high: $16,899.
d. Surface (Pad) Mounted Transformers
WEC and Xcel Energy commented that pad-mounded 167 kVA single-phase
transformers will roughly increase in size (1-4 inches) under the
proposed amended standards, and that this increase of the dimensional
footprint will be incompatible with pad and fiberglass box-pad
foundations that the current transformers are using and have used for
many decades. WEC and Xcel Energy stated that this will make it more
difficult to use existing underground infrastructure (trench and
connections) for transformer changeouts and may result in extra digging
to install a compatible fiberglass box and pad. (Xcel Energy, No. 127
at p. 1; WEC, No. 118 at pp. 2-3)
Southwest Electric commented that the proposed amended standard for
3-phase designs will result in a significant weight increase, exceeding
the weights the pads were designed to support--especially in areas
where seismic zoning requires additional anchoring. (Southwest
Electric, No. 87 at pp. 2-3)
Howard commented that it and other manufacturers have difficulty
meeting some utilities' pad dimensions at the current efficiency
levels. Howard commented it had taken exception to required footprint
dimensions in the past for 100 kVA and above dual voltage and 167 kVA
and above straight voltage transformers for many utilities. Regarding
three-phase pads, Howard commented that utilities may have two or three
different pad sizes, and a bigger footprint for transformers will
require utilities to utilize large pad sizes. (Howard, No. 116 at p.
21)
In response to these comments, DOE's analysis shows an increase in
weight and footprint area of 7 and 3 percent, respectively, for single-
phase surface-mounted liquid-immersed distribution transformers up to
and including 100 kVA, and an increase in weight and
[[Page 29945]]
footprint area of 18 and 19 percent, respectively, for single-phase
liquid-immersed surface mounted distribution transformers greater
than100 kVA designed to meet the current standard, see Table IV.17.
Additionally, DOE's analysis shows that that the impacts to weight and
footprint area of three-phase surface mounted distribution transformers
to be 4 and 1 percent, respectively, for capacities up to 500 kVA,
while for capacities equal to or greater than 500 kVA the increase in
weight and footprint area is 2 and 1 percent (5 and 1 percent for 500
kVA) over current standards, see Table IV.19. Commenters did not
provide enough information to directly model the costs of increasing
pad, or fiberglass box size; however, for some of the capacity ranges
the increase in weight, particularly for single-phase surface-mounted
distribution transformers over 100 kVA, may be enough to trigger the
need to use additional materials or different crews to complete
installations. While the specifics are not available to DOE, to capture
these additional costs DOE increased the fraction of installation from
5 percent in the NOPR (88 FR 1777) to 50 percent in this final rule.
e. Logistics and Hoisting
Chamber of Commerce, EEI, Portland General Electric, WEC, and
Southwest Electric commented that heavier transformers may trigger
transportation and hoisting considerations and challenges, likely
requiring flatbed trucks, additional permitting, and cranes to install.
These commenters stated that weight and access restrictions for roads
and certain areas, especially in rural places, may create further
challenges for replacements of transformers. (Portland General
Electric, No. 130 at p. 4; Southwest Electric, No. 87 at pp. 2-3;
Chamber of Commerce, No. 88 at pp. 4-5; EEI, No. 135 at pp. 24-28; WEC,
No. 118 at pp. 2-3) SPA commented that small utilities were concerned
whether their current equipment (namely trucks and lifts) will be able
to handle increased sizes and weights. (SBA, No. 100 at p. 6) Chamber
of Commerce commented that larger transformers will consume more
storage space on an individual basis than current GOES models, thereby
reducing the number of units that can be held in reserve to support
system restoration efforts. (Chamber of Commerce, No. 88 at pp. 4-5)
As discussed in sections IV.F.4.c and IV.F.4.d of this document,
DOE's analysis shows that the projected increase in size and weight of
transformers under amended standards to be modest, which DOE believes
will not be disruptive to current logistics and hoisting procedures.
f. Installation of Ancillary Equipment: Gas Monitors and Fuses
APPA insinuated that DOE did not account for the costs associated
with more than 10 million gas monitors, which would equate to $25
billion in additional costs, and that these additional costs alone
would exceed the $13 billion of economic benefits cited in the NOPR.
APPA further stated that DOE's analysis did not consider the additional
cost of labor to remove and install the gas monitor and the cost of a
replacement transformer. (APPA, No. 103 at p. 11)
DOE disagrees with the assertions from APPA that there would be an
additional cost of $25 billion to consumers of distribution
transformers for the removal and installation of gas monitor or other
ancillary equipment not related to the transformer's efficiency. A gas
monitor is a device installed by the customer that monitors the
conditions of the transformer's internal insulating fluid to help
predict future equipment faults. Due to the additional cost, they are
typically installed by utilities on larger capacity (kVA) transformers
for operational reliability, with their installation occurring
regardless of the efficiency of the transformer. Further, DOE has never
prescribed the use of gas monitors for distribution transformers; gas
monitors are installed at the discretion of each individual utility,
and outside the scope of DOE's authority. DOE has not included the use
of gas monitoring equipment in this final rule.
APPA commented that amorphous core transformers experience higher
inrush currents, creating the need for external protective devices
(e.g., fuses) to be reviewed and changed. APPA commented that the
amount of core steel significantly increases, creating a much heavier
device that could force the utility to rerate framing hardware while
increasing pole size and class and potentially increasing costs in a
way that DOE has not addressed. (APPA, No. 103 at p. 15)
DOE's installation costs analysis includes increasing installation
costs as a function of transformer weight. As generally indicated by
stakeholders through their comments, there are many factors and costs
that are unique to each utility's operating procedures; as such, these
factors are beyond the practicality of DOE to model in detail. As
discussed in section IV.F.4.c of this document, DOE increased the
fraction of installations which would incur additional cost under
amended standards from 5 to 50 percent to account for the circumstances
described by APPA. This fraction is constant at all considered
efficiency levels above the baseline.
g. Low-Voltage Dry-Type
Increased floor space to store the LVDT units--product is
commercially available off the shelf (COTS) device (Schneider, No. 101
at p. 15) Powersmiths commented that an amended standard for LVDT,
which requires amorphous cores would, for retrofits, to be successful
the replacement transformers. In addition to customization to meet
footprint needs, they will require design changes to match terminal
layout, impedance. temperature rise and k-rating. These accommodations,
while possible today with GOES core transformers, will further increase
the level of difficulty of retrofitting with amorphous-based
transformers. Many older transformers are closer to people than newer
buildings so any increase the audible noise is a big issue--noise is
one of the biggest complaints from users, itself driving retrofit
projects.'' (Powersmiths, No. 112 at p. 4-5)
To alleviate concerns from Schneider and Powersmiths regarding
potential installation issues arising from moving to amended standard
that are achievable only using amorphous core materials, the amended
standards in this final rule are set at level that is achievable with
GOES core materials, TSL 3.
5. Annual Energy Consumption
For each sampled customer, DOE determined the energy consumption
for a distribution transformer at different efficiency levels using the
approach described previously in section IV.E of this document.
6. Energy Prices
DOE derived average and marginal electricity prices for
distribution transformers using two different methodologies to reflect
the differences in how the electricity is paid for by consumers of
distribution transformers. For liquid-immersed distribution
transformers, which are largely owned and operated by electric
distribution companies who purchase electricity from a variety of
markets, DOE developed an hourly electricity cost model. For low- and
medium-voltage dry-type, which are primarily owned and operated by
commercial and industrial entities, DOE developed a monthly electricity
cost model.
Fall River commented that the amended standards would in turn drive
up costs, which would ultimately be
[[Page 29946]]
borne by rate payers where energy burdens are already growing at a
severe rate. (Fall River, No. 83 at p. 2) DOE notes that any amended
standard is determined based on the specific criteria discussed in
section III.F.1 of this document, and in the context of Fall River's
comment criteria III.F.1.b of this document. The results in section
V.B.1.a of this document show that most consumers are projected to show
a net benefit from amended standards.
DOE did not receive any further comments regarding its electricity
costs analysis and maintained the approach used in the NOPR for this
final rule.
7. Maintenance and Repair Costs
Repair costs are associated with repairing or replacing product
components that have failed in an appliance; maintenance costs are
associated with maintaining the operation of the product. Typically,
small incremental increases in product efficiency produce no, or only
minor, changes in repair and maintenance costs compared to baseline
efficiency products. In the NOPR analysis, DOE asserted that
maintenance and repair costs do not increase with transformer
efficiency.
Cliffs commented that the costs of the rule would not outweigh the
benefits if the substantial increase in price and maintenance
requirements for amorphous metal cores were properly accounted for.
(Cliffs, No. 105 at p. 16) However, Cliffs did not specify how
amorphous metal cores increase the maintenance costs of a transformer
nor did it provide any data to showcase these higher costs. DOE
understands that most distribution transformers incur few maintenance
or repairs throughout their product lifetime and typically none to the
transformer core. As discussed in sections IV.A.4.a and IV.G.3 of this
document, both amorphous and GOES cores can be rewound and rebuilt. DOE
does not have any data to support that amorphous core transformers
would be subject to substantially higher maintenance costs than GOES
core transformers.
DOE did not receive any comments on this assertion and continued
its assumptions that maintenance and repair costs do not increase with
transformer efficiency for this final rule analysis.
8. Transformer Service Lifetime
For distribution transformers, DOE used a distribution of
lifetimes, with an estimated average of 32 years and a maximum of 60
years.\165\ 78 FR 23336, 23377. DOE received the following comments on
transformer service lifetime. Prolec GE and NEMA commented that the
current estimated transformer lifetime of 32 years is adequate, as
distribution transformers are extremely durable. However, Prolec GE and
NEMA noted, certain factors might accelerate transformer replacement
rates, such as increased trends in transformer loading practices due to
electrification and decarbonization initiatives. (Prolec GE, No. 120 at
p. 13; NEMA, No. 141 at p. 16) APPA commented that GOES service
transformers are typically run to failure (no operations and
maintenance costs) and last 40 to 70 years and that amorphous
distribution transformers are likely to have a lifetime of 20 to 40
years. (APPA, No. 103 at p. 11)
---------------------------------------------------------------------------
\165\ Barnes, P. R., Van Dyke, J. W., McConnell, B. W. & Das, S.
Determination Analysis of Energy Conservation Standards for
Distribution Transformers. (Oak Ridge National Laboratory, 1996).
---------------------------------------------------------------------------
In response to Prolec GE, NEMA, and APPA, DOE characterizes
transformer lifetimes as distribution of the possibility of equipment
failure in each year up to the estimated maximum lifetime--in this case
60 years--to account for circumstances where the transformer either
fails prematurely (degradation from heat or otherwise) or is
prematurely removed from service. APPA's range of service lifetimes for
GOES and amorphous distribution transformers overlaps considerably with
DOE's estimates. Additionally, DOE finds the APPA discussion from
Australia regarding high amorphous failure rates to be excessively
speculative, based on anecdotal discussion with unknown persons
regarding an unknown sample size of distribution transformers of
unknown vintage in a jurisdiction that operates on a fundamentally
different frequency (50 hertz versus 60 hertz), and presented without
citation, data, or analysis. For this final rule DOE is maintaining the
distribution of service lifetimes from the NOPR; the distribution is
shown in Table IV.20.
[[Page 29947]]
[GRAPHIC] [TIFF OMITTED] TR22AP24.547
9. Discount Rates
The discount rate is the rate at which future expenditures are
discounted to estimate their present value. DOE employs a two-step
approach in calculating discount rates for analyzing customer economic
impacts (e.g., LCC). The first step is to assume that the actual cost
of capital approximates the appropriate customer discount rate. The
second step is to use the capital asset pricing model (CAPM) to
calculate the equity capital component of the customer discount rate.
For this final rule, DOE estimated a statistical distribution of
commercial customer discount rates that varied by distribution
transformer category, by calculating the cost of capital for the
different varieties of distribution transformer owners.
DOE's method views the purchase of a higher-efficiency appliance as
an investment that yields a stream of energy cost savings. DOE derived
the discount rates for the LCC analysis by estimating the cost of
capital for companies or public entities that purchase distribution
transformers. For private firms, the weighted average cost of capital
(WACC) is commonly used to estimate the present value of cash flows to
be derived from a typical company project or investment. Most companies
use both debt and equity capital to fund investments, so their cost of
capital is the weighted average of the cost to the firm of equity and
debt financing, as estimated from financial data for publicly traded
firms in the sectors that purchase distribution transformers.\166\ As
discount rates can differ across industries, DOE estimates separate
discount rate distributions for a number of aggregate sectors with
which elements of the LCC building sample can be associated.
---------------------------------------------------------------------------
\166\ Previously, Damodaran Online provided firm-level data, but
now only industry-level data is available, as compiled from
individual firm data, for the period of 1998-2018. The data sets
note the number of firms included in the industry average for each
year.
---------------------------------------------------------------------------
DOE did not receive any comments in the NOPR to its approach to
determining discount rates and maintained the same approach in this
final rule. The discount rates applied to consumers of liquid-immersed
distribution transformers are shown in Table IV.21, and those applied
to low- and medium-voltage dry-type distribution transformers are shown
in Table IV.22.
[[Page 29948]]
[GRAPHIC] [TIFF OMITTED] TR22AP24.548
[GRAPHIC] [TIFF OMITTED] TR22AP24.549
See chapter 8 of the NOPR TSD for further details on the
development of consumer discount rates.
10. Energy Efficiency Distribution in the No-New-Standards Case
To accurately estimate the share of consumers that would be
affected by a potential energy conservation standard at a particular
efficiency level, DOE's LCC analysis considered the projected
distribution (market shares) of product efficiencies under the no-new-
standards case (i.e., the case without amended or new energy
conservation standards) in the compliance year. This approach reflects
the fact that some consumers may purchase products with efficiencies
greater than the baseline levels in the absence of new or amended
standards. To determine an appropriate basecase against which to
compare various potential standard levels, DOE used the purchase-
decision model described in section IV.F.3 of this document, where
distribution transformers are purchased based on either lowest first
cost or lowest TOC (with BOE). In the no-new-standards case,
distribution transformers are chosen from among the entire range of
available distribution transformer designs for each representative unit
simulated in the engineering analysis based on this purchase-decision
model with the core material constraints discussed in section IV.F.3.a
of this document. This selection is constrained only by purchase price
in most cases (90 percent, and 100 percent for liquid-immersed and all
dry-type transformers, respectively) and reflects the MSPs of the
available designs determined in the engineering analysis in section
IV.C of this document.
DOE did not receive any comments regarding its methodology of
determining its energy efficiency distribution in the no-new-standards
[[Page 29949]]
case and maintained the methodology from the NOPR in this final rule.
11. Payback Period Analysis
The PBP is the amount of time (expressed in years) it takes the
consumer to recover the additional installed cost of more-efficient
products, compared to baseline products, through energy cost savings.
PBPs that exceed the life of the product mean that the increased total
installed cost is not recovered in reduced operating expenses.
The inputs to the PBP calculation for each efficiency level are the
change in total installed cost of the product and the change in the
first-year annual operating expenditures relative to the baseline. DOE
refers to this as a ``simple PBP'' because it does not consider changes
over time in operating cost savings. The PBP calculation uses the same
inputs as the LCC analysis when deriving first-year operating costs.
As noted previously, EPCA establishes a rebuttable presumption that
a standard is economically justified if the Secretary finds that the
additional cost to the consumer of purchasing a product complying with
an energy conservation standard level will be less than three times the
value of the first year's energy savings resulting from the standard,
as calculated under the applicable test procedure. (42 U.S.C.
6295(o)(2)(B)(iii)) For each considered efficiency level, DOE
determined the value of the first year's energy savings by calculating
the energy savings in accordance with the applicable DOE test
procedure, and multiplying those savings by the average energy price
projection for the year in which compliance with the amended standards
would be required.
Carte commented that a study found that the increase to 2016
transformer efficiencies will take approximately 80 years to payback
(no citation provided) and questions what the PBP would be for the
proposed standard level. (Carte, No. 140 at pp. 6-7) In response to
Carte, DOE acknowledges that some consumers may be negatively affected
by amended standards due to the details of how they operate their
equipment. For example, consumers with low electricity costs may take
longer to realize the benefits from more efficient equipment than might
be seen from consumers with higher electricity costs. DOE's LCC
analysis uses a Monte Carlo simulation to incorporate uncertainty and
variability into the analysis precisely to capture and quantify the
differences in costs and benefits to consumers Nationally. Carte's
comment did not provide details for DOE to alter its LCC and PBP
analysis. The PBPs of this final rule is shown in section V.C.1 through
V.C.3 of this document.
G. Shipments Analysis
DOE uses projections of annual product shipments to calculate the
national impacts of potential amended or new energy conservation
standards on energy use, NPV, and future manufacturer cash flows.\167\
The shipments model takes an accounting approach, tracking market
shares of each product class and the vintage of units in the stock.
Stock accounting uses product shipments as inputs to estimate the age
distribution of in-service product stocks for all years. The age
distribution of in-service product stocks is a key input to
calculations of both the NES and NPV, because operating costs for any
year depend on the age distribution of the stock.
---------------------------------------------------------------------------
\167\ DOE uses data on manufacturer shipments as a proxy for
national sales, as aggregate data on sales are lacking. In general,
one would expect a close correspondence between shipments and sales.
---------------------------------------------------------------------------
As in the NOPR, for this final rule DOE projected distribution
transformer shipments for the no-new standards case by assuming that
long-term growth in distribution transformer shipments will be driven
by long-term growth in electricity consumption. For this final rule,
DOE did not receive any comments regarding initial shipments estimates
presented in the NOPR--which were based on data from the previous final
rule, data submitted to DOE from interested parties and confidential
manufacturer interviews. These initial shipments are shown for the
assumed compliance year (2029), by distribution transformer category,
in Table IV.23 through Table IV.25. DOE developed the shipments
projection for liquid-immersed distribution transformers by assuming
that annual shipments growth is equal to growth in electricity
consumption (sales) for all sectors, as given by the AEO2023 forecast
through 2050. DOE's model assumed that growth in annual shipments of
dry-type distribution transformers would be equal to the growth in
electricity consumption for COMMERCIAL AND INDUSTRIAL sectors,
respectively. The model starts with an estimate of the overall growth
in distribution transformer capacity, and then estimates shipments for
particular representative units and capacities, using estimates of the
recent market shares for different design and size categories.
Idaho Power commented that it supported DOE's approach and believed
it was still valid. (Idaho Power, No. 139 at p. 6)
[[Page 29950]]
[GRAPHIC] [TIFF OMITTED] TR22AP24.550
[GRAPHIC] [TIFF OMITTED] TR22AP24.551
[[Page 29951]]
[GRAPHIC] [TIFF OMITTED] TR22AP24.552
1. Equipment Switching
In the January 2023 NOPR, DOE stated MVDTs can be used as
replacements for liquid-immersed distribution transformers, but DOE has
historically considered it as an edge case due to the differences in
purchase price as well as consumer sensitivity to first costs. At the
time it proposed amended standards, DOE did not have sufficient data to
model the substitution of liquid-immersed distribution transformers
with MVDTs. DOE requested comment on the topic of using MVDT as a
substitute for liquid-immersed distribution transformers. 88 FR 1754,
1782. NEMA responded that this is not typical, and these two categories
of distribution transformers coexist in the market. (NEMA, No. 141 at
p. 16) Additionally, Prolec GE commented that switching tended to be
with three-phase substation transformers for indoor applications.
(Prolec GE, No. 120 at p. 13)
In response to comments from NEMA and Prolec GE, DOE did not
include the possible replacement of liquid-immersed distribution
transformers with MVDT or vice versa in its analysis of this final
rule.
2. Trends in Distribution Transformer Capacity (kVA)
In response to the August 2021 Preliminary Analysis, NEMA commented
that as consumer demand increases due to migration to all-electric
homes and buildings, it stands to reason that kVA sizes will increase
over time as infrastructure upgrades capacity to serve these consumer
demands. Likewise, NEMA commented that investments in renewable energy
generation would cause changes to transformer shipments, unit sizes,
and selections, and that DOE should examine non-static capacity
scenarios, where kVA of units by category increases over time as NEMA
members express growth in average kVA of ordered units over time in
recent years, presumably due to increased electrification of consumer
and industrial applications. 88 FR 1722, 1782. In response to the NOPR,
NEMA further commented that roughly 15 percent of the low-voltage
commercial market is increasing their distribution capacity sizes,
going from 500 kVA to 1,000 or 1,500 kVA. (NEMA, No. 141 at p. 16)
Additionally, DOE has found evidence that a similar shift in
transformer capacity occurs with liquid-immersed distribution
transformer to meet increasing loads.\168\ DOE's approach to shifting
capacities is discussed in section E.3.a, Idaho Power commented it
believes the base data used in the April 2013 Standards Final Rule was
scaled from 1992 and 1995 data, and there have been many energy
efficiency standards that have been incorporated over the last 30
years. Idaho Power recommended that DOE consider updating the standard
to reflect current loading data and include advanced data collection
methods that provide more granular data. Idaho Power added that many
power companies have automated meter read data that could be leveraged
for better analysis. (Idaho Power, No. 139 at p. 5)
---------------------------------------------------------------------------
\168\ Dahal, S, Aswami D, Geraghty M, Dunckley, J. Impact of
Increasing Replacement Transformer Sizing on the Probability of
Transformer Overloads with Increasing EV Adoptions. 36th
International Electric Vehicle Symposium and Exhibition Sacramento.
California, USA, June 2023.
---------------------------------------------------------------------------
DOE agrees with Idaho Power's comments that since the CBECS last
included monthly demand and energy use profiles for respondents in 1992
and 1995 editions that many energy efficiency standards have been
promulgated. For its dry-type analysis, DOE used the hourly load data
for COMMERCIAL AND INDUSTRIAL customers from data provided to the IEEE
TF (from 2020 and 2021) to scale
[[Page 29952]]
these monthly values in its loading analysis for low-, and medium-
voltage dry-type distribution transformers (see chapter 7 of this final
rule TSD). DOE is aware that many utilities meter their customers using
real-time meters; however, DOE does not have the authority to demand
such data from said utilities. Instead, DOE must rely on such industry
initiatives such as the IEEE TF or individual companies to voluntarily
come forward with data.
3. Rewound and Rebuilt Equipment
APPA estimated that more than 15 percent of transformers used
Nationally are rebuilt/rewound units. These units would have been
rebuilt/rewound by the owning utility or as a service performed by
rewinding business. (APPA, No. 103 at p 11; NEMA, No. 141 at p. 15)
Howard and APPA commented that rewinding was a common occurrence
(especially for units greater than 300 kVA) and that the service life
could be extended up to 60 years. (APPA, No. 103 at p. 11; Howard, No.
116 at p. 21) However, NEMA responded that rebuilding, as they
understood, did not typically occur with liquid-filled distribution
transformers and was undertaken typically as a consequence of equipment
failure unrelated to end of life. NEMA further commented that to its
knowledge, no one was rebuilding low-voltage distribution transformers.
(NEMA, No. 141 at p. 15)
APPA continued that because most of a transformer's parts can be
reused when rewinding (or when other repairs are made), it is possible
that a new core could be installed in the old transformer, that costs
could be lower, and that lead times could be currently shorter than
purchasing new equipment. However, APPA stated that the rewinding
equipment used for GOES core transformers is incompatible with
amorphous core transformers, and for amorphous transformers the
rewinding process is more complex (time-consuming) and therefore more
expensive, resulting in a loss of benefit from rewinding to individual
utilities and cutting the total available capacity of transformers.
(APPA, No. 103 at pp. 11-12) Also, Idaho Power commented that it has
refurbished some transformers and returned them to service. Idaho Power
stated that this decision is based on reduced lead time and
availability rather than cost, which is somewhat close between new and
refurbished transformers. Idaho Power stated that its refurbished units
are put back into inventory and used according to their nameplate data.
(Idaho Power, No. 139 at p. 7)
Despite the contradictory statements from NEMA and APPA, DOE is
aware that transformer rewinding/repair is a service available to
utilities, either as an ``in-house'' service or at an external repair
shop that provides an additional avenue for utilities to maintain
transformer stocks (as indicated by Idaho Power). DOE has viewed the
rewind/repair services as additive and not in direct competition with
new distribution transformer manufacturers. While APPA asserts that
amorphous core rewinding may be more complex and diminishes the value
of rewinding these transformers, DOE understands that rewinding this
equipment is still possible and that a shift to amorphous core
transformers does not negate the value of these services. Additionally,
this final rule can be met with GOES core materials for approximately
90 percent of projected annual units shipments.
Regarding APPA's comment about reusing transformer parts to
potential reduce lead times, DOE notes that the transformer rebuilding/
rewinding market has historically been relatively small. Rebuilding a
distribution transformer requires additional labor (because labor is
required both to deconstruct the transformer and rebuild it) that has
made purchasing a new distribution transformer the preferred option
when replacing a failed transformer. While recently there has been an
uptick in transformer rebuilds, that is primarily a function of long
lead times for new transformers and likely temporary as the transformer
market recalibrates. Further, in response to Howard, as rewound
equipment falls outside the scope of DOE authority, they are not
considered in this final rule.
H. National Impact Analysis
The NIA assesses the national energy savings (NES) and the NPV from
a national perspective of total consumer costs and savings that would
be expected to result from new or amended standards at specific
efficiency levels.\169\ (``Consumer'' in this context refers to
consumers of the product being regulated.) DOE calculates the NES and
NPV for the potential standard levels considered based on projections
of annual product shipments, along with the annual energy consumption
and total installed cost data from the energy use and LCC analyses. For
the present analysis, DOE projected the energy savings, operating cost
savings, product costs, and NPV of consumer benefits over the lifetime
of distribution transformers sold from 2029 through 2058.
---------------------------------------------------------------------------
\169\ The NIA accounts for impacts in the 50 states and U.S.
territories.
---------------------------------------------------------------------------
DOE evaluates the impacts of new or amended standards by comparing
a case without such standards with standards-case projections. The no-
new-standards case characterizes energy use and consumer costs for each
product class in the absence of new or amended energy conservation
standards. For this projection, DOE considers historical trends in
efficiency and various forces that are likely to affect the mix of
efficiencies over time. DOE compares the no-new-standards case with
projections characterizing the market for each product class if DOE
adopted new or amended standards at specific energy efficiency levels
(i.e., the TSLs or standards cases) for that class. For the standards
cases, DOE considers how a given standard would likely affect the
market shares of products with efficiencies greater than the standard.
DOE uses a spreadsheet model to calculate the energy savings and
the national consumer costs and savings from each TSL. Interested
parties can review DOE's analyses by changing various input quantities
within the spreadsheet. The NIA spreadsheet model uses typical values
(as opposed to probability distributions) as inputs.
Table IV.26 summarizes the inputs and methods DOE used for the NIA
analysis for the final rule. Discussion of these inputs and methods
follows the table. See chapter 10 of the final rule TSD for further
details.
[[Page 29953]]
[GRAPHIC] [TIFF OMITTED] TR22AP24.553
1. Equipment Efficiency Trends
A key component of the NIA is the trend in energy efficiency
projected for the no-new-standards case and each of the amended
standards cases. Section IV.F.3 of this document describes how DOE
developed an energy efficiency distribution for the no-new-standards
case for each of the considered equipment classes for the year of
anticipated compliance with an amended or new standard. As discussed in
section IV.F.3 of this document, DOE has found that the vast majority
of distribution transformers are purchased based on first cost. For
both the no-new-standards case and amended standards case, DOE used the
results of the consumer choice mode in the LCC, described in section
IV.F.3 of this document, to establish the shipment-weighted efficiency
for the year potential standards are assumed to become effective
(2029). For this final rule, despite the availability of a wide range
of efficiencies, DOE modelled that these efficiencies would remain
static over time because the purchase decision is largely based on
first costs (see section IV.F.3 of this document) and DOE's application
of constant future equipment costs (see section IV.F.1 of this
document).
2. National Energy Savings
The national energy savings analysis involves a comparison of
national energy consumption of the considered products between each TSL
and the case with no new or amended energy conservation standards. DOE
calculated the national energy consumption by multiplying the number of
units (stock) of each product (by vintage or age) by the unit energy
consumption (also by vintage). DOE calculated annual NES based on the
difference in national energy consumption for the no-new-standards case
and for each higher-efficiency standard case. DOE estimated energy
consumption and savings based on site energy and converted the
electricity consumption and savings to primary energy (i.e., the energy
consumed by power plants to generate site electricity) using annual
conversion factors derived from AEO2023. For natural gas, primary
energy is the same as site energy. Cumulative energy savings are the
sum of the NES for each year over the timeframe of the analysis.
Use of higher-efficiency equipment is occasionally associated with
a direct rebound effect, which refers to an increase in utilization of
the equipment due to the increase in efficiency and its lower operating
cost. A distribution transformer's utilization is entirely dependent on
the aggregation of the connected loads on the circuit the distribution
transformer serves. Greater utilization would result in greater PUL on
the distribution transformer. Any increase in distribution transformer
PUL is coincidental and not related to rebound effect. NEMA and Howard
agreed that a rebound effect is not needed for distribution
transformers analysis. (NEMA, No. 141 at p. 16; Howard, No. 116 at p.
22) Howard additionally speculated that a possible caveat to this is
that utility companies could conceivably be inclined to increase the
load on more efficient transformers. (Howard, No. 116 at p. 22)
For this final rule, DOE has maintained the approach used in the
NOPR and has not applied an additional rebound effect in the form of
additional load. DOE accounts for incidental load growth on the
distribution transformer resulting from additional connections not
related to the rebound effect due to increased equipment efficiency in
the LCC analysis in the form of future load growth. See section 0 for
more details on DOE approach to load growth.
In 2011, in response to the recommendations of a committee on
``Point-of-Use and Full-Fuel-Cycle Measurement Approaches to Energy
Efficiency Standards'' appointed by the National Academy of Sciences,
DOE announced its intention to use FFC
[[Page 29954]]
measures of energy use and greenhouse gas and other emissions in the
national impact analyses and emissions analyses included in future
energy conservation standards rulemakings. 76 FR 51281 (Aug. 18, 2011).
After evaluating the approaches discussed in the August 18, 2011
notice, DOE published a statement of amended policy in which DOE
explained its determination that EIA's National Energy Modeling System
(NEMS) is the most appropriate tool for its FFC analysis and its
intention to use NEMS for that purpose. 77 FR 49701 (Aug. 17, 2012).
NEMS is a public domain, multi-sector, partial equilibrium model of the
U.S. energy sector \170\ that EIA uses to prepare its Annual Energy
Outlook. The FFC factors incorporate losses in production and delivery
in the case of natural gas (including fugitive emissions) and
additional energy used to produce and deliver the various fuels used by
power plants. The approach used for deriving FFC measures of energy use
and emissions is described in appendix 10B of the final rule TSD.
---------------------------------------------------------------------------
\170\ For more information on NEMS, refer to The National Energy
Modeling System: An Overview DOE/EIA-0581(2023), May 2023 (Available
at: https://www.eia.gov/outlooks/aeo/nems/overview/pdf/0581(2023).pdf) (Last accessed Oct. 23, 2023).
---------------------------------------------------------------------------
3. Net Present Value Analysis
The inputs for determining the NPV of the total costs and benefits
experienced by consumers are (1) total annual installed cost, (2) total
annual operating costs (energy costs and repair and maintenance costs),
and (3) a discount factor to calculate the present value of costs and
savings. DOE calculates net savings each year as the difference between
the no-new-standards case and each standards case in terms of total
savings in operating costs versus total increases in installed costs.
DOE calculates operating cost savings over the lifetime of each product
shipped during the projection period.
As discussed in section IV.F.1 of this document, DOE developed
distribution transformers price trends based on historical PPI data.
DOE applied the same trends to project prices for each product class at
each considered efficiency level, which was a constant price trend
through the end of the analysis period in 2058. DOE's projection of
product prices is described in appendix 10C of the NOPR TSD.
To evaluate the effect of uncertainty regarding the price trend
estimates, DOE investigated the impact of different product price
projections on the consumer NPV for the considered TSLs for
distribution transformers. In addition to the default price trend, DOE
considered two product price sensitivity cases: (1) a high price
decline case based on the years between 2003 and 2019 and (2) a low
price decline case based on the years between 1967 and 2002. The
derivation of these price trends and the results of these sensitivity
cases are described in appendix 10C of the NOPR TSD.
The operating cost savings are energy cost savings, which are
calculated using the estimated energy savings in each year and the
projected price of the appropriate form of energy. To estimate energy
prices in future years, DOE multiplied the average regional energy
prices by the projection of annual national-average electricity price
changes in the Reference case from AEO2023, which has an end year of
2050. To estimate price trends after 2050, DOE maintained the price
constant at 2050 levels. As part of the NIA, DOE also analyzed
scenarios that used inputs from variants of the AEO2023 Reference case
that have lower and higher economic growth. Those cases have lower and
higher energy price trends compared to the Reference case. NIA results
based on these cases are presented in appendix 10C of the final rule
TSD.
In calculating the NPV, DOE multiplies the net savings in future
years by a discount factor to determine their present value. For this
final rule, DOE estimated the NPV of consumer benefits using both a 3-
percent and a 7-percent real discount rate. DOE uses these discount
rates in accordance with guidance provided by the Office of Management
and Budget (OMB) to Federal agencies on the development of regulatory
analysis.\171\ The discount rates for the determination of NPV are in
contrast to the discount rates used in the LCC analysis, which are
designed to reflect a consumer's perspective. The 7-percent real value
is an estimate of the average before-tax rate of return to private
capital in the U.S. economy. The 3-percent real value represents the
``social rate of time preference,'' which is the rate at which society
discounts future consumption flows to their present value.
---------------------------------------------------------------------------
\171\ U.S. Office of Management and Budget. Circular A-4:
Regulatory Analysis. Available at www.whitehouse.gov/omb/information-for-agencies/circulars (last accessed January 2, 2024).
DOE used the prior version of Circular A-4 (September 17, 2003) in
accordance with the effective date of the November 9, 2023 version.
---------------------------------------------------------------------------
I. Consumer Subgroup Analysis
In analyzing the potential impact of new or amended energy
conservation standards on consumers, DOE evaluates the impact on
identifiable subgroups of consumers that may be disproportionately
affected by a new or amended national standard. The purpose of a
subgroup analysis is to determine the extent of any such
disproportional impacts. DOE evaluates impacts on particular subgroups
of consumers by analyzing the LCC impacts and PBP for those particular
consumers from alternative standard levels. For this NOPR, DOE analyzed
the impacts of the considered standard levels on two subgroups: (1)
utilities serving low population densities and (2) utility purchasers
of vault (underground) and subsurface installations. DOE used the LCC
and PBP model to estimate the impacts of the considered efficiency
levels on these subgroups. Chapter 11 in the NOPR TSD describes the
consumer subgroup analysis.
1. Utilities Serving Low Customer Populations
In rural areas, mostly served by electric cooperatives (COOPs), the
number of customers per distribution transformer is lower than in
metropolitan areas and may result in lower PULs.
Idaho Power commented that low-population areas should include
adjustments in the PUL and it supported the DOE adjustments to the PUL.
Idaho Power commented that its transformers in rural areas do not
experience the same levels of loading as in densely populated areas.
(Idaho Power, No. 139 at p. 5) NEMA commented that for liquid-filled
transformers, its members estimated PUL would typically be 10 percent
of RMS-equivalent nameplate rating. (NEMA, No. 141 at p. 16) Further,
PSE indicated that an increase in equipment costs of 50 percent would
not be ideal for COOPs, as these additional costs would ultimately fall
on their member-owners. (PSE, No. 98 at pp. 9-10)
For this final rule, as in the January 2023 NOPR (88 FR 1722, 1785)
and April 2013 Standards Final Rule, DOE reduced the PUL by adjusting
the distribution of IPLs, as discussed in section IV.E.2.a of this
document, resulting in the PULs shown below in Table IV.27. Further,
DOE altered the customer sample to limit the distribution of discount
rates (see section IV.F.9 of this document) to those observed by State
and local governments discussed in IV.F.9 of this document.
In the NOPR, DOE stated that while COOPs deploy a range of
distribution transformers to serve their customers, in low population
densities the most common unit is a 25 kVA pole overhead
[[Page 29955]]
liquid-immersed distribution transformer, which is represented in this
analysis as representative unit 2B of equipment class 1B (small single-
phase liquid-immersed). NRECA suggested that 15 kVA transformers are
used more commonly in areas with densities of six customers per mile.
(NRECA, No. 98 at p. 7)
DOE recognizes the suggestion by NRECA that the most common
capacity used by their members to serve areas with very low customer
densities would be 15 kVA. However, DOE's engineering analysis is
limited to 25 kVA in this final rule, which is embodied in the results
for equipment class 1B, single-phase distribution transformers up to
and including 100 kVA.
The results of the subgroups analysis are presented in section
IV.I.1 for equipment class 1B. As equipment class 1B encompasses
designs that are both pole-mounted (representative unit 2B) and pad-
mounted (representative unit 1B) these results represent the capacity
scaled, shipment weighted average consumer benefits. NRECA stated that
the 15 kVA pole mounted unit is the most used in low costumer density
installations--this equipment is represented by representative unit 2B
(a 25 kVA pole mount). It can be inferred through examining the LCC
results by representative unit that shows that consumer benefits for
pole mounted transformers are higher than those of pad mounted
transformers, and that the consumer benefits for the 15 kVA pole
mounted units would likely be greater than those shown for the entirety
of equipment class 1B.\172\
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\172\ See appendix 8E of the TSD for LCC results by
representative unit.
[GRAPHIC] [TIFF OMITTED] TR22AP24.554
2. Utility Purchasers of Vault (Underground) and Subsurface
Installations
In some urban areas, utilities provide service to customers by
deploying parts of their transformer fleet in subsurface vaults, or
other prefabricated underground concrete structures, referred to as
vaults. At issue in the potential amended standards case is that the
volume (ft\3\) of the more efficient replacement transformers may be
too large to fit into the existing vault, which would have to be
replaced to fit the new equipment. This analysis is applied to the
representative units 15 and 16, specifically defined in the engineering
analysis for vault and submersible liquid-immersed distribution
transformers (see section IV.C.1 of this document).
DOE received numerous comments on the topic of installing
transformers in vaults: Subsurface and Confined Space Installations.
APPA commented that its members do not have an inventory of existing
vaults or their locations and dimensions; and that most vaults were
built to ``fit'' the equipment that is housed within the vault, and
currently many do not have ``safe working space'' for workers, given
rules changes since they were built. APPA commented that such vaults
are currently grandfathered into many of the work rules, but having to
expand them to take a new transformer that is larger will mean also
retrofitting them to safe working space rules. APPA added that under
these circumstances, if the transformer is only 10 or 15 percent larger
than the vault, expansion will likely be much larger. (APPA, No. 103 at
p. 10)
APPA commented that the $23,550 cost assigned in the NOPR to
replace an existing vault by DOE is low for transformers installed in
building interior vaults. By way of example, APPA commented that simple
single-story buildings with parking lot-located vaults may cost at
least $200,000; and there may be as much as a $4,000,000 to $50,000,000
discrepancy in vault replacement cost for a multi-story building that
would need to be braced and supported to have the foundation removed to
expand the vault. (APPA, No. 103 at p. 9) Carte also speculated that in
extreme cases, such as rooftop vaults, a weight increase could be
achieved by reinforcing the structure. (Carte, No. 140 at p. 7) APPA
and the Chamber of Commerce commented that DOE did not account for the
potential of significant increased infrastructure replacement and
business disruption costs that would be incurred if replacement
transformers could not fit into existing locations. (Chamber of
Commerce, No. 88 at p. 4; APPA, No. 103 at p. 9) Pugh Consulting
commented that for submersible transformers, installing a new
transformer that is larger than the existing vault size would lead to
significant costs for utilities and municipal governments, including
costs associated with potential soil testing to determine if soil can
be removed and costs associated with shutting down streets, highways,
and sidewalks while a vault is expanded. (Pugh Consulting, No. 117 at
p. 6)
DOE recognizes the potential for the cost to install transformers
underground, or in building vaults to carry tremendous financial risk
to utilities. While the examples provided by APPA, Carte, Chamber of
Commerce, and Pugh Consulting are extreme cases where a utility's
decision to alter or upgrade the existing installation location could
lead to service disruptions, and maybe even health and safety
liabilities. It is reasonable that utilities exercising good governance
and financial responsibility to their ratepayers would approach such
extreme projects only after exhausting all other avenues of maintaining
service. As such DOE views these examples as edge cases. Further,
stakeholders did not provide any technical information, such as
specific transformer designs, weights, volumes; whether these cost
estimates are for vaults that contain single or banks of multiple
transformers from which DOE can improve its technical analysis. As such
DOE is limited to revising its existing model. To address the cost
concerns that stakeholders raised regarding the cost being too low in
the NOPR, DOE reexamined the costs presented in RSMeans and found they
lacked details such as excavation, disposal or fill--further they
didn't account the additional costs associated with working in space
confined spaces. To better capture these costs, for this final rule DOE
has revised its transformer
[[Page 29956]]
vault installation cost function to the following:
Transformer Vault Installation Cost = 220.37 x DTVolume\1.1436\
[GRAPHIC] [TIFF OMITTED] TR22AP24.555
The Efficiency Advocates commented that the creation of equipment
classes for submersible distribution transformers (equipment class 12)
will largely mitigate any size concerns regarding underground vaulted
network transformer installations because the vast majority of these
are submersible designs and thus would not have to meet the higher
efficiency levels proposed for other liquid-immersed transformer
equipment classes. (Efficiency Advocates, No. 75 at p. 35)
DOE separated the vault and submersible equipment into their own
equipment class (equipment class 12) which are designed to operate
under higher heat loads which are experienced by equipment installed in
enclosed spaces than general purpose distribution transformers. DOE is
not amending standards for this equipment at this time precisely for
the multitude of installation challenges described by commenters.
J. Manufacturer Impact Analysis
1. Overview
DOE performed an MIA to estimate the financial impacts of amended
energy conservation standards on manufacturers of distribution
transformers and to estimate the potential impacts of such standards on
employment and manufacturing capacity. The MIA has both quantitative
and qualitative aspects and includes analyses of projected industry
cash flows, the INPV, investments in research and development (R&D) and
manufacturing capital, and domestic manufacturing employment.
Additionally, the MIA seeks to determine how amended energy
conservation standards might affect manufacturing employment, capacity,
and competition, as well as how standards contribute to overall
regulatory burden. Finally, the MIA serves to identify any
disproportionate impacts on manufacturer subgroups, including small
business manufacturers.
The quantitative part of the MIA primarily relies on the Government
Regulatory Impact Model (GRIM), an industry cash flow model with inputs
specific to this rulemaking. The key GRIM inputs include data on the
industry cost structure, unit production costs, equipment shipments,
manufacturer markups, and investments in R&D and manufacturing capital
required to produce compliant equipment. The key GRIM outputs are the
INPV, which is the sum of industry annual cash flows over the analysis
period, discounted using the industry-weighted average cost of capital,
and the impact to domestic manufacturing employment. The model uses
standard accounting principles to estimate the impacts of more-
stringent energy conservation standards on a given industry by
comparing changes in INPV and domestic manufacturing employment between
a no-new-standards case and the various standards cases (i.e., TSLs).
To capture the uncertainty relating to manufacturer pricing strategies
following amended standards, the GRIM estimates a range of possible
impacts under different manufacturer markup scenarios.
The qualitative part of the MIA addresses manufacturer
characteristics and market trends. Specifically, the MIA considers such
factors as a potential standard's impact on manufacturing capacity,
competition within the industry, the cumulative impact of other DOE and
non-DOE regulations, and impacts on manufacturer subgroups. The
complete MIA is outlined in chapter 12 of the final rule TSD.
DOE conducted the MIA for this rulemaking in three phases. In Phase
1 of the MIA, DOE prepared a profile of the distribution transformer
manufacturing industry based on the market and technology assessment,
preliminary manufacturer interviews, and publicly available
information. This included a top-down analysis of distribution
transformer manufacturers that DOE used to derive preliminary financial
inputs for the GRIM (e.g., revenues; materials, labor, overhead, and
depreciation expenses; selling, general, and administrative expenses
(SG&A); and R&D expenses). DOE also used public sources of information
to further calibrate its initial characterization of the distribution
transformer manufacturing industry, including company filings of form
10-K from the SEC,\173\ corporate annual reports, the U.S. Census
Bureau's ``Economic Census,'' \174\ and reports from D&B Hoovers.\175\
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\173\ See: www.sec.gov/edgar
\174\ See: www.census.gov/programs-surveys/asm/data/tables.html
\175\ See: app.avention.com
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In Phase 2 of the MIA, DOE prepared a framework industry cash flow
analysis to quantify the potential impacts of amended energy
conservation standards. The GRIM uses several factors to determine a
series of annual cash flows starting with the announcement of the
standard and extending over a 30-year period following the compliance
date of the standard. These factors include annual expected revenues,
costs of sales, SG&A and R&D expenses, taxes, and capital expenditures.
In general, energy conservation standards can affect manufacturer cash
flow in three distinct ways: (1) creating a need for increased
investment, (2) raising production costs per unit, and (3) altering
revenue due to higher per-unit prices and changes in sales volumes.
In addition, during Phase 2, DOE developed interview guides to
distribute to manufacturers of distribution transformers in order to
develop other key GRIM inputs, including product and capital conversion
costs, and to gather additional information on the anticipated effects
of energy conservation standards on revenues, direct employment,
capital assets, industry competitiveness, and subgroup impacts.
In Phase 3 of the MIA, DOE conducted structured, detailed
interviews with representative
[[Page 29957]]
manufacturers. During these interviews, DOE discussed engineering,
manufacturing, procurement, and financial topics to validate
assumptions used in the GRIM and to identify key issues or concerns. As
part of Phase 3, DOE also evaluated subgroups of manufacturers that may
be disproportionately impacted by amended standards or that may not be
accurately represented by the average cost assumptions used to develop
the industry cash flow analysis. Such manufacturer subgroups may
include small business manufacturers, low-volume manufacturers (LVMs),
niche players, and/or manufacturers exhibiting a cost structure that
largely differs from the industry average. DOE identified one subgroup
for a separate impact analysis: small business manufacturers. The small
business subgroup is discussed in section VI.B, ``Review under the
Regulatory Flexibility Act,'' and in chapter 12 of the final rule TSD.
2. Government Regulatory Impact Model and Key Inputs
DOE uses the GRIM to quantify the changes in cash flow due to
amended standards that result in a higher or lower industry value. The
GRIM uses a standard, annual discounted cash flow analysis that
incorporates manufacturer costs, manufacturer markups, shipments, and
industry financial information as inputs. The GRIM models changes in
costs, distribution of shipments, investments, and manufacturer margins
that could result from amended energy conservation standards. The GRIM
spreadsheet uses the inputs to arrive at a series of annual cash flows,
beginning in 2024 (the base year of the analysis) and continuing to
2058. DOE calculated INPVs by summing the stream of annual discounted
cash flows during this period. For manufacturers of distribution
transformers, DOE used a real discount rate of 7.4 percent for liquid-
immersed distribution transformers, 11.1 percent for LVDT distribution
transformers, and 9.0 percent for MVDT distribution transformers, which
was derived from the April 2013 Standards Final Rule and then modified
according to feedback received during manufacturer interviews.\176\
---------------------------------------------------------------------------
\176\ See Chapter 12 of the April 2013 Standards Final Rule TSD
for discussion of where initial discount factors were derived,
available online at www.regulations.gov/document/EERE-2010-BT-STD-0048-0760. For the April 2013 Standards Final Rule, DOE initially
calculated a 9.1 percent discount rate, however during manufacturer
interviews conducted for that rulemaking, manufacturers suggested
using different discount rates specific for each equipment class
group. During manufacturer interviews conducted for the January 2023
NOPR, manufacturers continued to agree that using different discount
rates for each equipment class group is appropriate.
---------------------------------------------------------------------------
The GRIM calculates cash flows using standard accounting principles
and compares changes in INPV between the no-new-standards case and each
standards case. The difference in INPV between the no-new-standards
case and a standards case represents the financial impact of amended
energy conservation standards on manufacturers. As discussed
previously, DOE developed critical GRIM inputs using a number of
sources, including publicly available data, results of the engineering
analysis, and information gathered from industry stakeholders during
the course of manufacturer interviews. The GRIM results are presented
in section V.B.2 of this document. Additional details about the GRIM,
the discount rate, and other financial parameters can be found in
chapter 12 of the final rule TSD.
a. Manufacturer Production Costs
Manufacturing more efficient equipment is typically more expensive
than manufacturing baseline equipment due to the use of more complex
components, which are typically more costly than baseline components.
The changes in the MPCs of covered equipment can affect the revenues,
gross margins, and cash flow of the industry.
During the engineering analysis, DOE used transformer design
software to create a database of designs spanning a broad range of
efficiencies for each of the representative units. This design software
generated a bill of materials. DOE then applied markups to allow for
scrap, handling, factory overhead, and other non-production costs, as
well as profit, to estimate the MSP.
These designs and their MSPs are subsequently inputted into the LCC
customer choice model. For each efficiency level and within each
representative unit, the LCC model uses a consumer choice model and
criteria described in section IV.F.3 of this document to select a
subset of all the potential designs options (and associated MSPs). This
subset is meant to represent those designs that would actually be
shipped in the market under the various analyzed TSLs. DOE inputted
into the GRIM the weighted average cost of the designs selected by the
LCC model and scaled those MSPs to other selected capacities in each
design line's KVA range.
For a complete description of the MSPs, see chapter 5 of the final
rule TSD.
b. Shipments Projections
The GRIM estimates manufacturer revenues based on total unit
shipment projections and the distribution of those shipments by
efficiency level. Changes in sales volumes and efficiency mix over time
can significantly affect manufacturer finances. For this analysis, the
GRIM uses the NIA's annual shipment projections derived from the
shipments analysis from 2024 (the base year) to 2058 (the end year of
the analysis period). See chapter 9 of the final rule TSD for
additional details.
c. Product and Capital Conversion Costs
Amended energy conservation standards could cause manufacturers to
incur conversion costs to bring their production facilities and
equipment designs into compliance. DOE evaluated the level of
conversion-related expenditures that would be needed to comply with
each considered efficiency level in each equipment class. For the MIA,
DOE classified these conversion costs into two major groups: (1)
product conversion costs; and (2) capital conversion costs. Product
conversion costs are investments in research, development, testing,
marketing, and other non-capitalized costs necessary to make equipment
designs comply with amended energy conservation standards. Capital
conversion costs are investments in property, plants, and equipment
necessary to adapt or change existing production facilities such that
new compliant equipment designs can be fabricated and assembled.
For capital conversion costs, DOE prepared bottom-up estimates of
the costs required to meet the analyzed amended energy conservation
standards at each EL for each representative unit. Major drivers of
capital conversion costs include changes in core steel variety (and
thickness), core weight, and core stack height, all of which are
interdependent and can vary by efficiency level. The MIA used the
estimated quantity of the core steel (by steel variety) for each EL at
each representative unit that was modeled as part of the engineering
analysis and incorporated into the LCC analysis, to estimate the
additional production equipment that the distribution transformer
industry would need to purchase in order to meet each analyzed EL.
Capital conversion costs are primarily driven at each EL by the
potential need for the industry to expand production capacity for the
potential increase in amorphous alloy used in distribution transformer
cores. In the January 2023 NOPR, DOE estimated that an
[[Page 29958]]
amorphous production line capable of producing 1,200 tons annual of
amorphous cores would cost approximately $1,000,000 in capital
investments. This capital investment includes costs associated with
purchasing annealing ovens, core cutting machines, lacing tables, as
well as additional conveyors and cranes to move the potentially larger
amorphous cores, new winding machines and assembly tools specific to
amorphous core production. Lastly, this capital investment also
accounts for the potential additional production floor space that could
be needed to accommodate these additional or larger production
equipment that would be required to manufacture amorphous cores. The
quantity of amorphous cores are outputs of the engineering analysis and
the LCC. At higher ELs, the percent of distribution transformers
selected in the LCC consumer choice model that have amorphous cores
increases. Additionally, at the highest ELs, the quantity of amorphous
material per distribution transformer also increases. As the increasing
stringency of the ELs drive the use of more amorphous cores in
distribution transformers (and more amorphous material per distribution
transformer), capital conversion costs increase.
For product conversion costs, DOE understands the production of
amorphous cores requires unique production expertise from a
manufacturer's employees and engineering labor to create new equipment
designs for distribution transformers using amorphous cores. For
manufacturers without experience with amorphous core production,
standards that would likely be met using amorphous cores would require
the development or the procurement of the technical knowledge to
produce cores as well as potentially re-training production employees.
Because amorphous material is thinner and more brittle after annealing,
materials management, safety measures, and design considerations that
are not associated with non-amorphous materials would need to be
implemented.
In the January 2023 NOPR, DOE estimated product conversion costs
would be equal to 100 percent of the normal annual industry R&D
expenses for those ELs where a majority of the market would be expected
to transition to amorphous material. These one-time product conversion
costs would be in addition to the annual R&D expenses normally incurred
by distribution transformer manufacturers. These one-time expenditures
account for the design, engineering, prototyping, re-training of
production employees, and other R&D efforts the industry would have to
undertake to move to a predominately amorphous market. For ELs that
would not require the use of amorphous cores, but would still require
distribution transformer models to be redesigned to meet higher
efficiency levels, the January 2023 NOPR estimated product conversion
costs would be equal to 50 percent of the normal annual industry R&D
expenses. These one-time product conversion costs would also be in
addition to the annual R&D expenses normally incurred by distribution
transformer manufacturers.
Several interested parties commented on the conversion cost
estimate used in the January 2023 NOPR. Several interested parties
commented that manufacturers converting from GOES core production to
amorphous core production will require large investments and the
acquisition of several production equipment as well as re-training
production employees. MTC commented that using amorphous cores requires
different mandrels, winding, assembly processes, and equipment,
including specialty annealing equipment and that the costs are
significant and would be a major cost burden on distribution
transformer manufacturers. (MTC, No. 119 at p. 19) Prolec GE commented
that converting to amorphous cores would require investment in larger
production lines in addition to other manufacturing equipment like
cutting lines and annealing ovens. (Prolec GE, No. 120, at pp. 2-3)
TMMA commented that in order to meet the standards proposed in the
January 2023 NOPR, distribution transformer manufacturers will be
required to make a significant investment for new manufacturing
equipment, including cutting machines and annealing ovens. (TMMA, No.
138 at pp. 2-3) NEMA commented that producing distribution transformers
that use amorphous cores requires manufacturers to reconfigure their
assembly processes, including time to retrain electricians to match
transformer coils to calibrate with the properties of the new steel and
the steel tanks which house both the coil and cores will need to be
reconfigured to match these new dimensions. (NEMA, No. 141 at p. 3)
Schneider commented that the January 2023 NOPR conversion cost
estimates only considered core conversion costs when in actuality the
standards proposed in the January 2023 NOPR would require new winding
equipment to handle larger cores, expanded conveyors, cranes, and ovens
to handle larger equipment, and potentially new facilities to handle
the larger manufacturing footprints. (Schneider, No. 101 at p. 11)
Howard commented that in addition to the capital equipment to produce
amorphous cores, some facilities will need to be upgraded to
accommodate the additional core-making equipment. (Howard, No. 116 at
p. 2) Carte commented that amorphous core production is totally
different than GOES core production and would require either a large
expansion of their plant or purchasing cores from an external vendor.
(Carte, No. 140 at p. 1) Eaton commented that distribution transformer
manufacturers that currently manufacture GOES cores will be left with
scrapping their equipment due to very little shared processes or
equipment between GOES and amorphous steel. (Eaton, No. 137 at p. 26)
Lastly, WEG commented that the standards proposed in the January 2023
NOPR would require 50 percent of their operations to be retooled for
amorphous core production and their employees would have to be
completely retrained. (WEG, No. 92 at p. 3)
DOE acknowledges that distribution transformer manufacturers would
incur significant conversion costs to convert production facilities
that are currently designed to produce GOES cores into production
facilities that would produce amorphous steel cores in order to meet
energy conservation standards. The January 2023 NOPR and this final
rule analysis attempts to capture the full costs that distribution
transformer manufacturers would incur to be able to produce compliant
distribution transformers analyzed in this rulemaking. The cost
estimates used in the January 2023 NOPR and this final rule analysis,
include manufacturing equipment used in the cutting lines, annealing
ovens, new winding equipment to handle larger cores, expanded conveyors
and cranes, as well as costs to expand production floor space.
Several interested parties commented that the conversion cost
estimates used in the January 2023 NOPR were underestimated and should
be increased. Cliffs commented that the substantial conversion costs
estimated in the January 2023 NOPR are far below the reasonably
foreseeable economic impact on manufacturers. (Cliffs, No. 105 at p.
14) Additionally, Cliffs commented that the January 2023 NOPR
conversion cost estimates were based on manufacturer interviews
conducted in 2019 and did not account for the significant inflationary
forces have substantially increased capital
[[Page 29959]]
equipment costs by at least 50 percent. (Id.) Cliffs continued by
commenting that in order for manufacturers to comply with the standards
proposed in the January 2023 NOPR, it would require new investments of
between $30 and $50 million for each individual manufacturer to retool
existing production factories, which they estimate would cost the
entire industry between $500 million and $800 million to convert all
distribution transformer production facilities into being capable of
producing amorphous cores for the entire U.S. distribution transformer
market. (Cliffs, No. 105 at p. 15) Hammond stated that they estimate
having their production facility produce amorphous cores for all of
their distribution transformers would take twice as long to produce and
would require $40 million to $45 million in investment to ensure
current and planned capacity could be shifted to the production of
distribution transformers using amorphous cores. (Hammond, No. 142 at
p. 2) Howard commented that if standards directly or indirectly force
all distribution transformer designs only to use amorphous cores, the
investment required from a monetary and time perspective would be even
larger and longer that the conversion costs estimated in the January
2023 NOPR. (Howard, No. 116 at p. 3) Howard commented that they
estimate distribution transformer manufacturers would need to invest
between $500 million and $1 billion to convert all distribution
transformer manufacturing to accommodate producing amorphous cores for
all distribution transformers sold in the U.S. (Howard, No. 116 at p.
2) Prolec GE commented that it would need to invest approximately $50
million to convert their liquid-immersed distribution transformer
production, which currently used GOES cores to use amorphous cores.
(Prolec GE, No. 120 at p. 1) WEG commented that they estimate that it
would take 5-7 years to retool their distribution transformer
production facilities to support the necessary production equipment and
methods to produce amorphous core transformers at an estimated
investment of between $25 million and $30 million. (WEG, No. 92 at pp.
3-4) Additionally WEG commented that developing amorphous core designs
would require building 20 prototypes and need three full time engineers
to complete this transition to all amorphous core distribution
transformers. WEG estimates this engineering effort would cost their
company approximately $2 million. (WEG, No, 92 at pp. 1-2)
As part of this final rule MIA, DOE reexamined the estimated
conversion costs used in the January 2023 NOPR. For this final rule
analysis, DOE continues to use the same methodology to estimate the
conversion costs that industry would incur at each analyzed EL for each
representative unit. However, DOE has increased the estimated capital
conversion costs used in the January 2023 NOPR from $1,000,000 in
capital investments to build a production line capable of producing
distribution transformers that use 1,200 tons annually of amorphous
core material to $2,000,000 in capital investments for the same
quantity of amorphous core material. This increase in capital
investments reflect both the inflationary market mentioned by Cliffs
and the additional production equipment that would be in addition to
the production equipment that is specific to amorphous core production,
as well as the potential increase in production floor space that might
be needed to accommodate additional or larger production equipment
associated with amorphous core production.
Additionally, DOE increased the estimated product conversion costs
for distribution transformers using amorphous cores from 100 percent of
the annual industry R&D expenses to be 150 percent of the annual
industry R&D expenses; and for distribution transformers continuing to
use GOES cores from 50 percent the annual industry R&D expenses to be
75 percent of annual R&D expenses. The end result is that product
conversion cost estimates used in this final rule analysis are 50
percent more than the product conversion cost estimates used in the
January 2023 NOPR, for the same level of amorphous core production
requirements. These one-time product conversion costs would be in
addition to the annual R&D expenses normally incurred by distribution
transformer manufacturers. This increase in product conversion costs
from the January 2023 NOPR to this final rule analysis reflect the
additional redesigning, engineering, prototyping, re-training of
production employees, and other R&D efforts the industry would have to
undertake to move to producing distribution transformers using
amorphous cores.
The conversion costs by TSL and representative unit are displayed
in Table IV.29. These conversion costs are incorporated into the cash
flow analysis discussed in section V.B.2.a. The industry-wide
conversion cost estimates to convert all distribution transformer
manufacturing to accommodate producing amorphous cores for all
distribution transformers sold in the U.S. (which would occur at TSL 5)
would be approximately $825 million. This industry-wide conversion
estimate aligns with the estimates that several interested parties
suggested in response to the January 2023 NOPR.
[[Page 29960]]
[GRAPHIC] [TIFF OMITTED] TR22AP24.556
Capital and product conversion costs are key inputs into the GRIM
and directly impact the change in INPV (which is outputted from the
model) due to analyzed amended standards. The GRIM assumes all
conversion-related investments occur between the year of publication of
this final rule and the year by which manufacturers must comply with
the amended standards. The conversion cost figures used in the GRIM can
be found in section V.B.2.a of this document. For additional
information on the estimated capital and product conversion costs, see
chapter 12 of the final rule TSD.
d. Manufacturer Markup Scenarios
MSPs include direct manufacturing production costs (i.e., labor,
materials, and overhead estimated in DOE's MPCs) and all non-production
costs (i.e., SG&A, R&D, and interest), along with profit. To calculate
the MSPs in the GRIM, DOE applied non-production cost markups to the
MPCs estimated in the engineering analysis for each equipment class and
efficiency level. Modifying these manufacturer markups in the standards
case yields different sets of impacts on manufacturers. For the MIA,
DOE modeled two standards-case manufacturer markup scenarios to
represent uncertainty regarding the potential impacts on prices and
profitability for manufacturers following the implementation of amended
energy conservation standards: (1) a preservation of gross margin
scenario; and (2) a preservation of operating profit scenario. These
scenarios lead to different manufacturer markup values that, when
applied to the MPCs, result in varying revenue and cash flow impacts.
Under the preservation of gross margin percentage markup scenario,
DOE applied a single uniform ``gross margin percentage'' across all
efficiency levels, which assumes that manufacturers would be able to
maintain the same amount of profit as a percentage of revenues at all
efficiency levels within an equipment class. This scenario assumes that
manufacturers would be able to maintain the same amount of profit as a
percentage of revenues at all TSLs, even as the MPCs increase in the
standards case. Based on data from the April 2013 Standards Final Rule,
publicly available financial information for manufacturers of
distribution transformers, and comments made during manufacturer
interviews, DOE estimated a gross margin percentage of 20 percent for
all distribution transformers.\177\ This is the same value used in the
January 2023 NOPR. Because this scenario assumes that manufacturers
would be able to maintain the same gross margin percentage as MPCs
increase in response to the analyzed energy conservation standards, it
represents the upper bound to industry profitability
[[Page 29961]]
under amended energy conservation standards.
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\177\ The gross margin percentage of 20 percent is based on a
manufacturer markup of 1.25.
---------------------------------------------------------------------------
Under the preservation of operating profit scenario, DOE modeled a
situation in which manufacturers are not able to increase per-unit
operating profit in proportion to increases in MPCs. Under this
scenario, as the MPCs increase, manufacturers reduce their manufacturer
markups (on a percentage basis) to a level that maintains the no-new-
standards operating profit (in absolute dollars). The implicit
assumption behind this scenario is that the industry can only maintain
its operating profit in absolute dollars after compliance with amended
standards. Therefore, operating margin in percentage terms is reduced
between the no-new-standards case and the analyzed standards cases. DOE
adjusted the manufacturer markups in the GRIM at each TSL to yield
approximately the same earnings before interest and taxes in the
standards case in the year after the compliance date of the amended
standards as in the no-new-standards case. This scenario represents the
lower bound to industry profitability under amended energy conservation
standards.
A comparison of industry financial impacts under the two
manufacturer markup scenarios is presented in section V.B.2.a of this
document.
K. Emissions Analysis
The emissions analysis consists of two components. The first
component estimates the effect of potential energy conservation
standards on power sector and site (where applicable) combustion
emissions of CO2, NOX, SO2, and Hg.
The second component estimates the impacts of potential standards on
emissions of two additional greenhouse gases, CH4 and
N2O, as well as the reductions in emissions of other gases
due to ``upstream'' activities in the fuel production chain. These
upstream activities comprise extraction, processing, and transporting
fuels to the site of combustion.
The analysis of electric power sector emissions of CO2,
NOX, SO2, and Hg uses emissions intended to
represent the marginal impacts of the change in electricity consumption
associated with amended or new standards. The methodology is based on
results published for the AEO, including a set of side cases that
implement a variety of efficiency-related policies. The methodology is
described in appendix 13A in the final rule TSD. The analysis presented
in this notice uses projections from AEO2023. Power sector emissions of
CH4 and N2O from fuel combustion are estimated
using Emission Factors for Greenhouse Gas Inventories published by the
Environmental Protection Agency (EPA).\178\
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\178\ Available at www.epa.gov/sites/production/files/2021-04/documents/emission-factors_apr2021.pdf (last accessed July 12,
2021).
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Site emissions of these gases were estimated using Emission Factors
for Greenhouse Gas Inventories and, for NOX and
SO2, emissions intensity factors from an EPA
publication.\179\
---------------------------------------------------------------------------
\179\ U.S. Environmental Protection Agency. External Combustion
Sources. In Compilation of Air Pollutant Emission Factors. AP-42.
Fifth Edition. Volume I: Stationary Point and Area Sources. Chapter
1. Available at www.epa.gov/air-emissions-factors-and-quantification/ap-42-compilation-air-emissions-factors#Proposed/
(last accessed July 12, 2021).
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FFC upstream emissions, which include emissions from fuel
combustion during extraction, processing, and transportation of fuels,
and ``fugitive'' emissions (direct leakage to the atmosphere) of
CH4 and CO2, are estimated based on the
methodology described in chapter 15 of the final rule TSD.
The emissions intensity factors are expressed in terms of physical
units per MWh or MMBtu of site energy savings. For power sector
emissions, specific emissions intensity factors are calculated by
sector and end use. Total emissions reductions are estimated using the
energy savings calculated in the national impact analysis.
1. Air Quality Regulations Incorporated in DOE's Analysis
DOE's no-new-standards case for the electric power sector reflects
the AEO, which incorporates the projected impacts of existing air
quality regulations on emissions. AEO2023 reflects, to the extent
possible, laws and regulations adopted through mid-November 2022,
including the emissions control programs discussed in the following
paragraphs and the Inflation Reduction Act.\180\
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\180\ For further information, see the Assumptions to AEO2023
report that sets forth the major assumptions used to generate the
projections in the Annual Energy Outlook. Available at www.eia.gov/outlooks/aeo/assumptions/ (last accessed January 2, 2024).
---------------------------------------------------------------------------
SO2 emissions from affected electric generating units
(EGUs) are subject to nationwide and regional emissions cap-and-trade
programs. Title IV of the Clean Air Act sets an annual emissions cap on
SO2 for affected EGUs in the 48 contiguous States and the
District of Columbia (``D.C.''). (42 U.S.C. 7651 et seq.)
SO2 emissions from numerous States in the eastern half of
the United States are also limited under the Cross-State Air Pollution
Rule (``CSAPR''). 76 FR 48208 (Aug. 8, 2011). CSAPR requires these
States to reduce certain emissions, including annual SO2
emissions, and went into effect as of January 1, 2015.\181\ The AEO
incorporates implementation of CSAPR, including the update to the CSAPR
ozone season program emission budgets and target dates issued in 2016.
81 FR 74504 (Oct. 26, 2016). Compliance with CSAPR is flexible among
EGUs and is enforced through the use of tradable emissions allowances.
Under existing EPA regulations, for states subject to SO2
emissions limits under CSAPR, any excess SO2 emissions
allowances resulting from the lower electricity demand caused by the
adoption of an efficiency standard could be used to permit offsetting
increases in SO2 emissions by another regulated EGU.
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\181\ CSAPR requires states to address annual emissions of
SO2 and NOX, precursors to the formation of
fine particulate matter (PM2.5) pollution, in order to
address the interstate transport of pollution with respect to the
1997 and 2006 PM2.5 National Ambient Air Quality
Standards (NAAQS). CSAPR also requires certain states to address the
ozone season (May-September) emissions of NOX, a
precursor to the formation of ozone pollution, in order to address
the interstate transport of ozone pollution with respect to the 1997
ozone NAAQS. 76 FR 48208 (Aug. 8, 2011). EPA subsequently issued a
supplemental rule that included an additional five states in the
CSAPR ozone season program; 76 FR 80760 (Dec. 27, 2011)
(Supplemental Rule), and EPA issued the CSAPR Update for the 2008
ozone NAAQS. 81 FR 74504 (Oct. 26, 2016).
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However, beginning in 2016, SO2 emissions began to fall
as a result of the Mercury and Air Toxics Standards (MATS) for power
plants.\182\ 77 FR 9304 (Feb. 16, 2012). The final rule establishes
power plant emission standards for mercury, acid gases, and non-mercury
metallic toxic pollutants. Because of the emissions reductions under
the MATS, it is unlikely that excess SO2 emissions
allowances resulting from the lower electricity demand would be needed
or used to permit offsetting increases in SO2 emissions by
another regulated EGU. Therefore, energy conservation standards that
decrease electricity generation will generally reduce SO2
emissions. DOE estimated SO2 emissions reduction using
emissions factors based on AEO2023.
---------------------------------------------------------------------------
\182\ In order to continue operating, coal power plants must
have either flue gas desulfurization or dry sorbent injection
systems installed. Both technologies, which are used to reduce acid
gas emissions, also reduce SO2 emissions.
---------------------------------------------------------------------------
CSAPR also established limits on NOX emissions for
numerous States in the eastern half of the United States. Energy
conservation standards would have little effect on NOX
emissions in those States covered by CSAPR emissions limits if excess
NOX emissions allowances resulting from the lower
electricity demand could be used to
[[Page 29962]]
permit offsetting increases in NOX emissions from other
EGUs. In such case, NOX emissions would remain near the
limit even if electricity generation goes down. Depending on the
configuration of the power sector in the different regions and the need
for allowances, however, NOX emissions might not remain at
the limit in the case of lower electricity demand. That would mean that
standards might reduce NOX emissions in covered States.
Despite this possibility, DOE has chosen to be conservative in its
analysis and has maintained the assumption that standards will not
reduce NOX emissions in States covered by CSAPR. Standards
would be expected to reduce NOX emissions in the States not
covered by CSAPR. DOE used AEO2023 data to derive NOX
emissions factors for the group of States not covered by CSAPR.
The MATS limit mercury emissions from power plants, but they do not
include emissions caps and, as such, DOE's energy conservation
standards would be expected to slightly reduce Hg emissions. DOE
estimated mercury emissions reduction using emissions factors based on
AEO2023, which incorporates the MATS.
EEI commented that electric companies are already reducing
greenhouse gas emissions via clean energy initiatives such as utilizing
more renewable energy technology. (EEI, No. 135 at pp. 7-8) Several
other stakeholders similarly commented that utility companies are
actively reducing greenhouse gas emissions and already utilize carbon-
free energy sources. (Idaho Falls Power, No. 77 at p. 2; Fall River,
No. 83 at p. 2; WEC, No. 118 at p. 3)
In response to EEI and other utility stakeholders, DOE notes that
the emissions factors are determined by AEO, which accounts for
declining future carbon emissions due increased renewable generation.
L. Monetizing Emissions Impacts
As part of the development of this final rule, for the purpose of
complying with the requirements of Executive Order 12866, DOE
considered the estimated monetary benefits from the reduced emissions
of CO2, CH4, N2O, NOX, and
SO2 that are expected to result from each of the TSLs
considered. In order to make this calculation analogous to the
calculation of the NPV of consumer benefit, DOE considered the reduced
emissions expected to result over the lifetime of products shipped in
the projection period for each TSL. This section summarizes the basis
for the values used for monetizing the emissions benefits and presents
the values considered in this final rule.
To monetize the benefits of reducing GHG emissions, this analysis
uses the interim estimates presented in the Technical Support Document:
Social Cost of Carbon, Methane, and Nitrous Oxide Interim Estimates
Under Executive Order 13990 published in February 2021 by the IWG.
1. Monetization of Greenhouse Gas Emissions
DOE estimates the monetized benefits of the reductions in emissions
of CO2, CH4, and N2O by using a
measure of the SC of each pollutant (e.g., SC-CO2). These
estimates represent the monetary value of the net harm to society
associated with a marginal increase in emissions of these pollutants in
a given year, or the benefit of avoiding that increase. These estimates
are intended to include (but are not limited to) climate-change-related
changes in net agricultural productivity, human health, property
damages from increased flood risk, disruption of energy systems, risk
of conflict, environmental migration, and the value of ecosystem
services.
DOE exercises its own judgment in presenting monetized climate
benefits as recommended by applicable Executive orders, and DOE would
reach the same conclusion presented in this rulemaking in the absence
of the social cost of greenhouse gases. That is, the social costs of
greenhouse gases, whether measured using the February 2021 interim
estimates presented by the IWG on the Social Cost of Greenhouse Gases
or by another means, did not affect the rule ultimately adopted by DOE.
DOE estimated the global social benefits of CO2,
CH4, and N2O reductions using SC-GHG values that
were based on the interim values presented in the Technical Support
Document: Social Cost of Carbon, Methane, and Nitrous Oxide Interim
Estimates under Executive Order 13990, published in February 2021 by
the IWG (``February 2021 SC-GHG TSD''). The SC-GHG is the monetary
value of the net harm to society associated with a marginal increase in
emissions in a given year, or the benefit of avoiding that increase. In
principle, the SC-GHG includes the value of all climate change impacts,
including (but not limited to) changes in net agricultural
productivity, human health effects, property damage from increased
flood risk and natural disasters, disruption of energy systems, risk of
conflict, environmental migration, and the value of ecosystem services.
The SC-GHG, therefore, reflects the societal value of reducing
emissions of the gas in question by 1 metric ton. The SC-GHG is the
theoretically appropriate value to use in conducting benefit-cost
analyses of policies that affect CO2, N2O, and
CH4 emissions. As a member of the IWG involved in the
development of the February 2021 SC-GHG TSD, DOE agrees that the
interim SC-GHG estimates represent the most appropriate estimate of the
SC-GHG until revised estimates have been developed reflecting the
latest, peer-reviewed science. DOE continues to evaluate recent
developments in the scientific literature, including the updated SC-GHG
estimates published by the EPA in December 2023 within their rulemaking
on oil and natural gas sector sources.\183\ For this rulemaking, DOE
used these updated SC-GHG values to conduct a sensitivity analysis of
the value of GHG emissions reductions associated with alternative
standards for distribution transformers (see section IV.L.1.c of this
document).
---------------------------------------------------------------------------
\183\ U.S. EPA. (2023). Supplementary Material for the
Regulatory Impact Analysis for the Final Rulemaking, ``Standards of
Performance for New, Reconstructed, and Modified Sources and
Emissions Guidelines for Existing Sources: Oil and Natural Gas
Sector Climate Review'': EPA Report on the Social Cost of Greenhouse
Gases: Estimates Incorporating Recent Scientific Advances.
Washington, DC: U.S. EPA. https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-operations/epas-final-rule-oil-and-natural-gas.
---------------------------------------------------------------------------
The SC-GHG estimates presented here were developed over many years,
using peer-reviewed methodologies, a transparent process, the best
science available at the time of that process, and input from the
public. Specifically, in 2009, the IWG, which included DOE and other
Executive branch agencies and offices, was established to ensure that
agencies were using the best available science and to promote
consistency in the SC-CO2 values used across agencies. The
IWG published SC-CO2 estimates in 2010 that were developed
from an ensemble of three widely cited integrated assessment models
(IAMs) that estimate global climate damages using highly aggregated
representations of climate processes and the global economy combined
into a single modeling framework. The three IAMs were run using a
common set of input assumptions in each model for future population,
economic, and CO2 emissions growth, as well as equilibrium
climate sensitivity--a measure of the globally averaged temperature
response to increased atmospheric CO2 concentrations. These
estimates were updated in 2013 based on new versions of each IAM. In
August 2016 the IWG published estimates of the
[[Page 29963]]
SC-CH4 and SC-N2O using methodologies that are
consistent with the methodology underlying the SC-CO2
estimates. The modeling approach that extends the IWG SC-CO2
methodology to non-CO2 GHGs has undergone multiple stages of
peer review. The SC-CH4 and SC-N2O estimates were
developed by Marten et al.\184\ and underwent a standard double-blind
peer review process prior to journal publication. In 2015, as part of
the response to public comments received to a 2013 solicitation for
comments on the SC-CO2 estimates, the IWG announced a
National Academies of Sciences, Engineering, and Medicine review of the
SC-CO2 estimates to offer advice on how to approach future
updates to ensure that the estimates continue to reflect the best
available science and methodologies. In January 2017, the National
Academies released their final report, ``Valuing Climate Damages:
Updating Estimation of the Social Cost of Carbon Dioxide,'' and
recommended specific criteria for future updates to the SC-
CO2 estimates, a modeling framework to satisfy the specified
criteria, and both near-term updates and longer-term research needs
pertaining to various components of the estimation process.\185\
Shortly thereafter, in March 2017, President Trump issued Executive
Order 13783, which disbanded the IWG, withdrew the previous TSDs, and
directed agencies to ensure SC-CO2 estimates used in
regulatory analyses are consistent with the guidance contained in OMB's
Circular A-4, ``including with respect to the consideration of domestic
versus international impacts and the consideration of appropriate
discount rates'' (E.O. 13783, Section 5(c)). Benefit-cost analyses
following E.O. 13783 used SC-GHG estimates that attempted to focus on
the U.S.-specific share of climate change damages as estimated by the
models and were calculated using two discount rates recommended by
Circular A-4, 3 percent and 7 percent. All other methodological
decisions and model versions used in SC-GHG calculations remained the
same as those used by the IWG in 2010 and 2013, respectively.
---------------------------------------------------------------------------
\184\ Marten, A.L., E.A. Kopits, C.W. Griffiths, S.C. Newbold,
and A. Wolverton. Incremental CH4 and N2O
mitigation benefits consistent with the U.S. Government's SC-
CO2 estimates. Climate Policy. 2015. 15(2): pp. 272-298.
\185\ National Academies of Sciences, Engineering, and Medicine.
Valuing Climate Damages: Updating Estimation of the Social Cost of
Carbon Dioxide. 2017. The National Academies Press: Washington, DC.
nap.nationalacademies.org/catalog/24651/valuing-climate-damages-updating-estimation-of-the-social-cost-of.
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On January 20, 2021, President Biden issued Executive Order 13990,
which re-established the IWG and directed it to ensure that the U.S.
Government's estimates of the social cost of carbon and other
greenhouse gases reflect the best available science and the
recommendations in the National Academies 2017 report. The IWG was
tasked with first reviewing the SC-GHG estimates currently used in
Federal analyses and publishing interim estimates within 30 days of the
E.O. that reflect the full impact of GHG emissions, including by taking
global damages into account. The interim SC-GHG estimates published in
February 2021 are used here to estimate the climate benefits for this
rulemaking. The E.O. instructs the IWG to undertake a fuller update of
the SC-GHG estimates that takes into consideration the advice in the
National Academies 2017 report and other recent scientific literature.
The February 2021 SC-GHG TSD provides a complete discussion of the
IWG's initial review conducted under E.O. 13990. In particular, the IWG
found that the SC-GHG estimates used under E.O. 13783 fail to reflect
the full impact of GHG emissions in multiple ways.
First, the IWG found that the SC-GHG estimates used under E.O.
13783 fail to fully capture many climate impacts that affect the
welfare of U.S. citizens and residents, and those impacts are better
reflected by global measures of the SC-GHG. Examples of omitted effects
from the E.O. 13783 estimates include direct effects on U.S. citizens,
assets and investments located abroad, supply chains, U.S. military
assets and interests abroad, tourism, and spillover pathways such as
economic and political destabilization and global migration that can
lead to adverse impacts on U.S. national security, public health, and
humanitarian concerns. In addition, assessing the benefits of U.S. GHG
mitigation activities requires consideration of how those actions may
affect mitigation activities by other countries, as those international
mitigation actions will provide a benefit to U.S. citizens and
residents by mitigating climate impacts that affect U.S. citizens and
residents. A wide range of scientific and economic experts have
emphasized the issue of reciprocity as support for considering global
damages of GHG emissions. If the United States does not consider
impacts on other countries, it is difficult to convince other countries
to consider the impacts of their emissions on the United States. The
only way to achieve an efficient allocation of resources for emissions
reduction on a global basis--and so benefit the U.S. and its citizens--
is for all countries to base their policies on global estimates of
damages. As a member of the IWG involved in the development of the
February 2021 SC-GHG TSD, DOE agrees with this assessment and,
therefore, in this final rule DOE centers attention on a global measure
of SC-GHG. This approach is the same as that taken in DOE regulatory
analyses from 2012 through 2016. A robust estimate of climate damages
that accrue only to U.S. citizens and residents does not currently
exist in the literature. As explained in the February 2021 SC-GHG TSD,
existing estimates are both incomplete and an underestimate of total
damages that accrue to the citizens and residents of the U.S. because
they do not fully capture the regional interactions and spillovers
discussed above, nor do they include all of the important physical,
ecological, and economic impacts of climate change recognized in the
climate change literature. As noted in the February 2021 SC-GHG TSD,
the IWG will continue to review developments in the literature,
including more robust methodologies for estimating a U.S.-specific SC-
GHG value, and explore ways to better inform the public of the full
range of carbon impacts. As a member of the IWG, DOE will continue to
follow developments in the literature pertaining to this issue.
Second, the IWG found that the use of the social rate of return on
capital (estimated to be 7 percent under OMB's 2003 Circular A-4
guidance) to discount the future benefits of reducing GHG emissions
inappropriately underestimates the impacts of climate change for the
purposes of estimating the SC-GHG. Consistent with the findings of the
National Academies and the economic literature, the IWG continued to
conclude that the consumption rate of interest is the theoretically
appropriate discount rate in an intergenerational context,\186\ and it
[[Page 29964]]
recommended that discount rate uncertainty and relevant aspects of
intergenerational ethical considerations be accounted for in selecting
future discount rates.
---------------------------------------------------------------------------
\186\ Interagency Working Group on Social Cost of Carbon. Social
Cost of Carbon for Regulatory Impact Analysis under Executive Order
12866. 2010. United States Government. www.epa.gov/sites/default/files/2016-12/documents/scc_tsd_2010.pdf (last accessed April 15,
2022.); Interagency Working Group on Social Cost of Carbon.
Technical Update of the Social Cost of Carbon for Regulatory Impact
Analysis Under Executive Order 12866. 2013. www.federalregister.gov/documents/2013/11/26/2013-28242/technical-support-document-technical-update-of-the-social-cost-of-carbon-for-regulatory-impact
(last accessed April 15, 2022.); Interagency Working Group on Social
Cost of Greenhouse Gases, United States Government. Technical
Support Document: Technical Update on the Social Cost of Carbon for
Regulatory Impact Analysis--Under Executive Order 12866. August
2016. www.epa.gov/sites/default/files/2016-12/documents/sc_co2_tsd_august_2016.pdf (last accessed January 18, 2022.);
Interagency Working Group on Social Cost of Greenhouse Gases, United
States Government. Addendum to Technical Support Document on Social
Cost of Carbon for Regulatory Impact Analysis under Executive Order
12866: Application of the Methodology to Estimate the Social Cost of
Methane and the Social Cost of Nitrous Oxide. August 2016.
www.epa.gov/sites/default/files/2016-12/documents/addendum_to_sc-ghg_tsd_august_2016.pdf (last accessed January 18, 2022.).
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Furthermore, the damage estimates developed for use in the SC-GHG
are estimated in consumption-equivalent terms, and so an application of
OMB Circular A-4's guidance for regulatory analysis would then use the
consumption discount rate to calculate the SC-GHG. DOE agrees with this
assessment and will continue to follow developments in the literature
pertaining to this issue. DOE also notes that while OMB's 2003 Circular
A-4 recommends using 3-percent and 7-percent discount rates as
``default'' values, Circular A-4 also reminds agencies that ``different
regulations may call for different emphases in the analysis, depending
on the nature and complexity of the regulatory issues and the
sensitivity of the benefit and cost estimates to the key assumptions.''
On discounting, Circular A-4 recognizes that ``special ethical
considerations arise when comparing benefits and costs across
generations,'' and Circular A-4 acknowledges that analyses may
appropriately ``discount future costs and consumption benefits . . . at
a lower rate than for intragenerational analysis.'' In the 2015
Response to Comments on the Social Cost of Carbon for Regulatory Impact
Analysis, OMB, DOE, and the other IWG members recognized that
``Circular A-4 is a living document'' and ``the use of 7 percent is not
considered appropriate for intergenerational discounting. There is wide
support for this view in the academic literature, and it is recognized
in Circular A-4 itself.'' Thus, DOE concludes that a 7-percent discount
rate is not appropriate to apply to value the social cost of greenhouse
gases in the analysis presented in this analysis.
To calculate the present and annualized values of climate benefits,
DOE uses the same discount rate as the rate used to discount the value
of damages from future GHG emissions, for internal consistency. That
approach to discounting follows the same approach that the February
2021 SC-GHG TSD recommends ``to ensure internal consistency--i.e.,
future damages from climate change using the SC-GHG at 2.5 percent
should be discounted to the base year of the analysis using the same
2.5 percent rate.'' DOE has also consulted the National Academies' 2017
recommendations on how SC-GHG estimates can ``be combined in RIAs with
other cost and benefits estimates that may use different discount
rates.'' The National Academies reviewed several options, including
``presenting all discount rate combinations of other costs and benefits
with [SC-GHG] estimates.''
As a member of the IWG involved in the development of the February
2021 SC-GHG TSD, DOE agrees with the above assessment and will continue
to follow developments in the literature pertaining to this issue.
While the IWG works to assess how best to incorporate the latest, peer-
reviewed science to develop an updated set of SC-GHG estimates, it set
the interim estimates to be the most recent estimates developed by the
IWG prior to the group being disbanded in 2017. The estimates rely on
the same models and harmonized inputs and are calculated using a range
of discount rates. As explained in the February 2021 SC-GHG TSD, the
IWG has recommended that agencies revert to the same set of four values
drawn from the SC-GHG distributions based on three discount rates as
were used in regulatory analyses between 2010 and 2016 and were subject
to public comment. For each discount rate, the IWG combined the
distributions across models and socioeconomic emissions scenarios
(applying equal weight to each) and then selected a set of four values
recommended for use in benefit-cost analyses: an average value
resulting from the model runs for each of three discount rates (2.5
percent, 3 percent, and 5 percent), plus a fourth value, selected as
the 95th percentile of estimates based on a 3-percent discount rate.
The fourth value was included to provide information on potentially
higher-than-expected economic impacts from climate change. As explained
in the February 2021 SC-GHG TSD, and DOE agrees, this update reflects
the immediate need to have an operational SC-GHG for use in regulatory
benefit-cost analyses and other applications that was developed using a
transparent process, peer-reviewed methodologies, and the science
available at the time of that process. Those estimates were subject to
public comment in the context of dozens of proposed rulemakings as well
as in a dedicated public comment period in 2013.
There are a number of limitations and uncertainties associated with
the SC-GHG estimates. First, the current scientific and economic
understanding of discounting approaches suggests discount rates
appropriate for intergenerational analysis in the context of climate
change are likely to be less than 3 percent, near 2 percent or
lower.\187\ Second, the IAMs used to produce these interim estimates do
not include all of the important physical, ecological, and economic
impacts of climate change recognized in the climate change literature
and the science underlying their ``damage functions''--i.e., the core
parts of the IAMs that map global mean temperature changes and other
physical impacts of climate change into economic (both market and
nonmarket) damages--lags behind the most recent research. For example,
limitations include the incomplete treatment of catastrophic and non-
catastrophic impacts in the integrated assessment models, their
incomplete treatment of adaptation and technological change, the
incomplete way in which inter-regional and intersectoral linkages are
modeled, uncertainty in the extrapolation of damages to high
temperatures, and inadequate representation of the relationship between
the discount rate and uncertainty in economic growth over long time
horizons. Likewise, the socioeconomic and emissions scenarios used as
inputs to the models do not reflect new information from the last
decade of scenario generation or the full range of projections. The
modeling limitations do not all work in the same direction in terms of
their influence on the SC-CO2 estimates. However, as
discussed in the February 2021 SC-GHG TSD, the IWG has recommended
that, taken together, the limitations suggest that the interim SC-GHG
estimates used in this final rule likely underestimate the damages from
GHG emissions. DOE concurs with this assessment.
---------------------------------------------------------------------------
\187\ Interagency Working Group on Social Cost of Greenhouse
Gases. 2021. Technical Support Document: Social Cost of Carbon,
Methane, and Nitrous Oxide Interim Estimates under Executive Order
13990. February. United States Government. Available at
www.whitehouse.gov/briefing-room/blog/2021/02/26/a-return-to-science-evidence-based-estimates-of-the-benefits-of-reducing-climate-pollution/.
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DOE's derivations of the SC-CO2, SC-N2O, and
SC-CH4 values used for this NOPR are discussed in the
following sections, and the results of DOE's analyses estimating the
benefits of the reductions in emissions of these GHGs are presented in
section V.B.6 of this document.
a. Social Cost of Carbon
The SC-CO2 values used for this final rule were based on
the values developed for the February 2021 SC-GHG TSD,
[[Page 29965]]
which are shown in Table IV.30 in 5-year increments from 2020 to 2050.
The set of annual values that DOE used, which was adapted from
estimates published by EPA,\188\ is presented in appendix 14A of the
final rule TSD. These estimates are based on methods, assumptions, and
parameters identical to the estimates published by the IWG (which were
based on EPA modeling), and include values for 2051 to 2070. DOE
expects additional climate benefits to accrue for products still
operating after 2070, but a lack of available SC-CO2
estimates for emissions years beyond 2070 prevents DOE from monetizing
these potential benefits in this analysis.
---------------------------------------------------------------------------
\188\ See EPA, ``Revised 2023 and Later Model Year Light-Duty
Vehicle GHG Emissions Standards: Regulatory Impact Analysis,''
Washington, DC, December 2021. Available at nepis.epa.gov/Exe/ZyPDF.cgi?Dockey=P1013ORN.pdf (last accessed Feb. 21, 2023).
[GRAPHIC] [TIFF OMITTED] TR22AP24.557
DOE multiplied the CO2 emissions reduction estimated for
each year by the SC-CO2 value for that year in each of the
four cases. DOE adjusted the values to 2022$ using the implicit price
deflator for gross domestic product (GDP) from the Bureau of Economic
Analysis. To calculate a present value of the stream of monetary
values, DOE discounted the values in each of the four cases using the
specific discount rate that had been used to obtain the SC-
CO2 values in each case.
b. Social Cost of Methane and Nitrous Oxide
The SC-CH4 and SC-N2O values used for this
final rule were based on the values developed for the February 2021 SC-
GHG TSD. Table IV.31 shows the updated sets of SC-CH4 and
SC-N2O estimates from the latest interagency update in 5-
year increments from 2020 to 2050. The full set of annual values used
is presented in appendix 14A of the final rule TSD. To capture the
uncertainties involved in regulatory impact analysis, DOE has
determined it is appropriate to include all four sets of SC-
CH4 and SC-N2O values, as recommended by the IWG.
DOE derived values after 2050 using the approach described above for
the SC-CO2.
[GRAPHIC] [TIFF OMITTED] TR22AP24.558
DOE multiplied the CH4 and N2O emissions
reduction estimated for each year by the SC-CH4 and SC-
N2O estimates for that year in each of the cases. DOE
adjusted the values to 2022$ using the implicit price deflator for GDP
from the Bureau of Economic Analysis. To calculate a present value of
the stream of monetary values, DOE discounted the values in each of the
cases using the specific discount rate that had been used to obtain the
SC-CH4 and SC-N2O estimates in each case.
c. Sensitivity Analysis Using EPA's New SC-GHG Estimates
In the regulatory impact analysis of EPA's December 2023 Final
Rulemaking, ``Standards of Performance for New, Reconstructed, and
Modified Sources and Emissions Guidelines for Existing Sources: Oil and
Natural Gas
[[Page 29966]]
Sector Climate Review,'' EPA estimated climate benefits using a new set
of Social Cost of Greenhouse Gas (SC-GHG) estimates. These estimates
incorporate recent research addressing recommendations of the National
Academies (2017), responses to public comments on an earlier
sensitivity analysis using draft SC-GHG estimates, and comments from a
2023 external peer review of the accompanying technical report.\189\
---------------------------------------------------------------------------
\189\ For further information about the methodology used to
develop these values, public comments, and information pertaining to
the peer review, see https://www.epa.gov/environmental-economics/scghg.
---------------------------------------------------------------------------
The full set of annual values is presented in appendix 14C of the
direct final rule TSD. Although DOE continues to review EPA's
estimates, for this rulemaking, DOE used these new SC-GHG values to
conduct a sensitivity analysis of the value of GHG emissions reductions
associated with alternative standards for distribution transformers.
This sensitivity analysis provides an expanded range of potential
climate benefits associated with amended standards. The final year of
EPA's new estimates is 2080; therefore, DOE did not monetize the
climate benefits of GHG emissions reductions occurring after 2080.
The results of the sensitivity analysis are presented in appendix
14C of the final rule TSD. The overall climate benefits are larger when
using EPA's higher SC-GHG estimates, compared to the climate benefits
using the more conservative IWG SC-GHG estimates. However, DOE's
conclusion that the standards are economically justified remains the
same regardless of which SC-GHG estimates are used.
2. Monetization of Other Emissions Impacts
For the final rule, DOE estimated the monetized value of
NOX and SO2 emissions reductions from electricity
generation using benefit-per-ton estimates for that sector from the
EPA's Benefits Mapping and Analysis Program. \190\ DOE used EPA's
values for PM2.5-related benefits associated with
NOX and SO2 and for ozone-related benefits
associated with NOX for 2025 and 2030, 2035, and 2040,
calculated with discount rates of 3 percent and 7 percent. DOE used
linear interpolation to define values for the years not given in the
2025 to 2040 period; for years beyond 2040, the values are held
constant (rather than extrapolated) to be conservative. DOE combined
the EPA regional benefit-per-ton estimates with regional information on
electricity consumption and emissions from AEO2023 to define weighted-
average national values for NOX and SO2.
---------------------------------------------------------------------------
\190\ U.S. Environmental Protection Agency. Estimating the
Benefit per Ton of Reducing Directly-Emitted PM2.5,
PM2.5 Precursors and Ozone Precursors from 21 Sectors.
www.epa.gov/benmap/estimating-benefit-ton-reducing-directly-emitted-pm25-pm25-precursors-and-ozone-precursors.
---------------------------------------------------------------------------
DOE received the following comments regarding its monetization of
emissions impacts.
The Chamber of Commerce urged DOE to reconsider the use of the SC-
GHG estimates in this rulemaking based on three core concerns. First,
the Chamber of Commerce commented that before DOE considers applying
the SC-GHG estimates to the proposed rule (and, likewise, to any final
rule resulting from this rulemaking), the SC-GHG estimates should be
subject to a proper administrative process, including a full and fair
public comment process, as well as a robust independent peer review.
Second, the Chamber of Commerce stated that there are statutory
limitations on using the SC-GHG estimates, and it urged DOE to fully
consider the applicable limits before applying the estimates. Third,
the Chamber of Commerce urged DOE to carefully consider whether the
``major questions'' doctrine precludes the application of the SC-GHG
estimates in the proposed rule given the political and economic
significance of the estimates. (Chamber of Commerce, No. 88 at p. 6)
In response, DOE first notes that it would reach the same
conclusion presented in this final rule in the absence of the social
cost of greenhouse gases. As it relates to the Chamber of Commerce's
first comment, DOE reiterates that the SC-GHG estimates were developed
using a transparent process, peer-reviewed methodologies, the best
science available at the time of that process, and input from the
public.
Regarding possible statutory limitations on using the SC-GHG
estimates, DOE maintains that environmental and public health benefits
associated with the more efficient use of energy, including those
connected to global climate change, are important to take into account
when considering the ``need for national energy . . . conservation,''
which is one of the factors that EPCA requires DOE to evaluate in
determining whether a potential energy conservation standard is
economically justified. (42 U.S.C. 6295(o)(2)(B)(i)(VI)); Zero Zone,
Inc. v. United States DOE, 832 F.3d 654, 677 (7th Cir. 2016) (pointing
to 42 U.S.C. 6295(o)(2)(B)(i)(VI) in concluding that ``[w]e have no
doubt that Congress intended that DOE have the authority under the EPCA
to consider the reduction in SCC.'') DOE has been analyzing the
monetized emissions impacts from its rules, for over 10 years. In
addition, Executive Order 13563, ``Improving Regulation and Regulatory
Review,'' which was re-affirmed on January 20, 2021, states that each
agency, among other things, must, to the extent permitted by law:
``select, in choosing among alternative regulatory approaches, those
approaches that maximize net benefits (including potential economic,
environmental, public health and safety, and other advantages;
distributive impacts; and equity).'' E.O. 13563, Section 1(b).
Furthermore, as noted previously, E.O. 13990, ``Protecting Public
Health and the Environment and Restoring Science to Tackle the Climate
Crisis,'' re-established the IWG and directed it to ensure that the
U.S. Government's estimates of the social cost of carbon and other
greenhouse gases reflect the best available science and the
recommendations of the National Academies. As a member of the IWG
involved in the development of the February 2021 SC-GHG TSD, DOE agrees
that the interim SC-GHG estimates represent the most appropriate
estimate of the SC-GHG until revised estimates have been developed
reflecting the latest, peer-reviewed science. For these reasons, DOE
includes monetized emissions reductions in its evaluation of potential
standard levels.
Regarding whether the ``major questions'' doctrine precludes the
application of the SC-GHG estimates in proposed or final rules, DOE
notes that the ``major questions'' doctrine raised by the Chamber of
Commerce applies only in ``extraordinary cases'' concerning Federal
agencies claiming highly consequential regulatory authority beyond what
Congress could reasonably be understood to have granted. West Virginia
v. EPA, 142 S. Ct. 2587, 2609 (2022); N.C. Coastal Fisheries Reform
Grp. v. Capt. Gaston LLC, 2023 U.S. App. LEXIS 20325, *6-8 (4th Cir.,
Aug. 7, 2023) (listing the hallmarks courts have recognized to invoke
the major questions doctrine, such as a hesitancy ``to recognize new-
found powers in old statutes against a backdrop of an agency failing to
invoke them previously,'' ``when the asserted power raises federalism
concerns,'' or ``when the asserted authority falls outside the agency's
traditional expertise, . . . or is found in an `ancillary provision.'
''). DOE has clear authorization under EPCA to regulate the energy
efficiency or energy use of a variety of COMMERCIAL AND INDUSTRIAL
[[Page 29967]]
equipment, including distribution transformers. Although DOE routinely
conducts an analysis of the anticipated emissions impacts of potential
energy conservation standards under consideration, see, e.g., Zero
Zone, 832 F.3d at 677, DOE does not purport to regulate such emissions,
and as stated elsewhere in this document, DOE's selection of standards
would be the same without consideration of emissions. Where DOE applied
the factors it was tasked to consider under EPCA and the rule is
justified even absent use of the SC-GHG analysis, the major questions
doctrine has no bearing.
The Institute for Policy Integrity (IPI) commented that DOE
appropriately applies the social cost estimates developed by the IWG to
its analysis of climate benefits. IPI stated that these values are
widely agreed to underestimate the full social costs of greenhouse gas
emissions, but for now they remain appropriate to use as conservative
estimates. (IPI, No. 123 at p. 1)
DOE agrees that the interim SC-GHG values applied for this final
rule are conservative estimates. In the February 2021 SC-GHG TSD, the
IWG stated that the models used to produce the interim estimates do not
include all of the important physical, ecological, and economic impacts
of climate change recognized in the climate change literature. For
these same impacts, the science underlying their ``damage functions''
lags behind the most recent research. In the judgment of the IWG, these
and other limitations suggest that the range of four interim SC-GHG
estimates presented in the TSD likely underestimate societal damages
from GHG emissions. The IWG is in the process of assessing how best to
incorporate the latest peer-reviewed science and the recommendations of
the National Academies to develop an updated set of SC-GHG estimates,
and DOE remains engaged in that process.
IPI suggested that DOE should state that criticisms of the social
cost of greenhouse gases are moot in this rulemaking because the
proposed rule is justified without them. DOE agrees that the proposed
rule is economically justified without including climate benefits
associated with reduced GHG emissions. (IPI, No. 123 at p. 2)
IPI commented that DOE should consider applying sensitivity
analysis using EPA's draft climate-damage estimates released in
November 2022, as EPA's work faithfully implements the road map laid
out in 2017 by the National Academies of Sciences and applies recent
advances in the science and economics on the costs of climate change.
(IPI, No. 123 at p. 1)
DOE typically does not conduct analyses using draft inputs that are
still under review. DOE notes that because the EPA's draft estimates
are considerably higher than the IWG's interim SC-GHG values applied
for this final rule, an analysis that used the draft values would
result in significantly greater climate-related benefits. However, such
results would not affect DOE's decision in this proposed rule.
M. Utility Impact Analysis
The utility impact analysis estimates the changes in installed
electrical capacity and generation projected to result for each
considered TSL. The analysis is based on published output from the NEMS
associated with AEO2023. NEMS produces the AEO Reference case, as well
as a number of side cases that estimate the economy-wide impacts of
changes to energy supply and demand. For the current analysis, impacts
are quantified by comparing the levels of electricity sector
generation, installed capacity, fuel consumption and emissions in the
AEO2023 Reference case and various side cases. Details of the
methodology are provided in the appendices to chapters 13 and 15 of the
final rule TSD.
The output of this analysis is a set of time-dependent coefficients
that capture the change in electricity generation, primary fuel
consumption, installed capacity and power sector emissions due to a
unit reduction in demand for a given end use. These coefficients are
multiplied by the stream of electricity savings calculated in the NIA
to provide estimates of selected utility impacts of potential new or
amended energy conservation standards.
N. Employment Impact Analysis
DOE considers employment impacts in the domestic economy as one
factor in selecting a standard. Employment impacts from new or amended
energy conservation standards include both direct and indirect impacts.
Direct employment impacts are any changes in the number of employees of
manufacturers of the products subject to standards, their suppliers,
and related service firms. The MIA addresses those impacts. Indirect
employment impacts are changes in national employment that occur due to
the shift in expenditures and capital investment caused by the purchase
and operation of more-efficient appliances. Indirect employment impacts
from standards consist of the net jobs created or eliminated in the
national economy, other than in the manufacturing sector being
regulated, caused by (1) reduced spending by consumers on energy, (2)
reduced spending on new energy supply by the utility industry, (3)
increased consumer spending on the products to which the new standards
apply and other goods and services, and (4) the effects of those three
factors throughout the economy.
One method for assessing the possible effects on the demand for
labor of such shifts in economic activity is to compare sector
employment statistics developed by the Labor Department's Bureau of
Labor Statistics (BLS). BLS regularly publishes its estimates of the
number of jobs per million dollars of economic activity in different
sectors of the economy, as well as the jobs created elsewhere in the
economy by this same economic activity. Data from BLS indicate that
expenditures in the utility sector generally create fewer jobs (both
directly and indirectly) than expenditures in other sectors of the
economy.\191\ There are many reasons for these differences, including
wage differences and the fact that the utility sector is more capital-
intensive and less labor-intensive than other sectors. Energy
conservation standards have the effect of reducing consumer utility
bills. Because reduced consumer expenditures for energy likely lead to
increased expenditures in other sectors of the economy, the general
effect of efficiency standards is to shift economic activity from a
less labor-intensive sector (i.e., the utility sector) to more labor-
intensive sectors (e.g., the retail and service sectors). Thus, the BLS
data suggest that net national employment may increase due to shifts in
economic activity resulting from energy conservation standards.
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\191\ See U.S. Department of Commerce-Bureau of Economic
Analysis. Regional Input-Output Modeling System (RIMS II) User's
Guide. Available at: apps.bea.gov/resources/methodologies/RIMSII-user-guide (last accessed Sept. 12, 2022).
---------------------------------------------------------------------------
DOE estimated indirect national employment impacts for the standard
levels considered in this final rule using an input/output model of the
U.S. economy called Impact of Sector Energy Technologies version 4
(ImSET).\192\ ImSET is a special-purpose version of the U.S. Benchmark
National Input-Output (I-O) model, which was designed to estimate the
national employment and income effects of energy-saving technologies.
The ImSET software includes a computer-based I-O model having
structural coefficients that
[[Page 29968]]
characterize economic flows among 187 sectors most relevant to
industrial, commercial, and residential building energy use.
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\192\ Livingston, O. V., S. R. Bender, M. J. Scott, and R. W.
Schultz. ImSET 4.0: Impact of Sector Energy Technologies Model
Description and User's Guide. 2015. Pacific Northwest National
Laboratory: Richland, WA. PNNL-24563.
---------------------------------------------------------------------------
DOE notes that ImSET is not a general equilibrium forecasting
model, and that there are uncertainties involved in projecting
employment impacts, especially changes in the later years of the
analysis. Because ImSET does not incorporate price changes, the
employment effects predicted by ImSET may overestimate actual job
impacts over the long run for this rule. Therefore, DOE used ImSET only
to generate results for near-term timeframes (2034), where these
uncertainties are reduced. In the long-term DOE expects that the net
effect from amended standards will be an increased shift towards
consumer goods from the utility sector. For more details on the
employment impact analysis, see chapter 16 of the final rule TSD.
V. Analytical Results and Conclusions
The following section addresses the results from DOE's analyses
with respect to the considered energy conservation standards for
distribution transformers. It addresses the TSLs examined by DOE, the
projected impacts of each of these levels if adopted as energy
conservation standards for distribution transformers, and the standards
levels that DOE is adopting in this final rule. Additional details
regarding DOE's analyses are contained in the final rule TSD supporting
this document.
[GRAPHIC] [TIFF OMITTED] TR22AP24.559
A. Trial Standard Levels
In general, DOE typically evaluates potential new or amended
standards for products and equipment by grouping individual efficiency
levels for each class into TSLs. Use of TSLs allows DOE to identify and
consider manufacturer cost interactions between the equipment classes,
to the extent that there are such interactions, and price elasticity of
consumer purchasing decisions that may change when different standard
levels are set.
In the analysis conducted for this final rule, DOE analyzed the
benefits and burdens of five TSLs for distribution transformers. DOE
developed TSLs that combine efficiency levels for each analyzed
equipment class and kVA rating. For this analysis, DOE defined its
efficiency levels as a percentage reduction in baseline losses (See
section IV.F.2 of this document). To create TSLs, DOE maintained this
approach and directly mapped ELs to TSLs, for low-voltage dry-type and
medium-voltage dry-type distribution transformers. To create TSLs for
liquid-immersed distribution transformers other than submersible
distribution transformers, DOE directly mapped ELs to TSLs for TSL 1,
2, 4, and 5. For TSL 3, DOE considered a TSL wherein class 1A and 2A
were mapped to EL 4 and equipment class 1B and 2B were mapped to EL 2,
which corresponds to a TSL where a diversity of domestically produced
core materials are cost competitive without requiring substantial
investments in new capacity for core materials.
DOE notes that all TSLs align with the TSLs from the NOPR except
for liquid-immersed TSL 3. In the NOPR, DOE mapped EL 3 to TSL 3.
In this final rule, DOE modified TSL 3 for liquid-immersed
distribution transformers such that for equipment classes 1A, 1B, 2A,
and 2B TSL3 is a combination wherein equipment classes 1B and 2B are
set at EL2, and 1A and 2A are set at EL4. This ensures that capacity
for amorphous ribbon increases driven by equipment classes 1A and 2A;
and leaves a considerable portion of the market at efficiency levels
where GOES remains cost competitive, equipment classes 1B and 2B.
Further, TSL 3 ensures that units that are more likely
[[Page 29969]]
to have high currents (equipment class 2B) and units that are more
likely to be overloaded (equipment class 1B), have additional
flexibility in meeting efficiency standards to accommodate this
consumer utility, as discussed in sections IV.A.2.b and IV.A.2.c of
this document. For all other equipment classes TSL 3 is identical to
that which was presented in the January 2023 NOPR. DOE notes that the
ELs used in the final rule correspond to an identical reduction in
rated losses as the ELs used in the January 2023 NOPR. However, the
grouping of these ELs by equipment class has been modified in response
to stakeholder feedback. TSL3 is intended to reflect stakeholder
concerns that substantial amorphous core production could lead to near
term supply chain constraints given the investment required to
transition the entire U.S. market to amorphous cores.
DOE notes that both EL 3 and EL 4 for liquid-immersed distribution
transformers generally are met with substantial amorphous core
production and therefore would have similar consumer and manufacturer
impacts along with similar concerns regarding supply chain and domestic
core production. DOE considered, and adopts, TSL 3 in this final rule
to maximize the energy savings and consumer benefits without requiring
that the entire market transition to amorphous cores, which, as
discussed, would not be economically justified.
Liquid-immersed submersible distribution transformers remain at
baseline for all TSLs except max-tech. For submersible distribution
transformers, being able to fit in an existing vault is a performance
related feature of significant consumer utility and these transformers
often serve high density applications. DOE recognizes that beyond some
size increase a vault replacement may be necessary, however, DOE lacks
sufficient data as to where exactly that vault replacement is needed.
In order to maintain the consumer utility associated with submersible
transformers, DOE has taken the conservative approach of not
considering TSLs for submersible transformers aside from max-tech. DOE
presents the results for the TSLs in this document, while the results
for all efficiency levels that DOE analyzed are in the final rule TSD.
Table V.2 presents the TSLs and the corresponding efficiency levels
that DOE has identified for potential amended energy conservation
standards for distribution transformers. TSL 5 represents the maximum
technologically feasible (``max-tech'') energy efficiency for all
product classes. TSL 4 represents a loss reduction over baseline of 20
percent for liquid-immersed transformers, except submersible liquid-
immersed transformers which remain at baseline; a 40 and 30 percent
reduction in baseline losses for single-, and three-phase low-voltage
distribution transformers, respectively; and a 30 percent reduction in
baseline losses for all medium-voltage dry-type distribution
transformers. TSL 3 represents a loss reduction over baseline of 5
percent for liquid-immersed transformers for single-phase transformers
less than or equal to 100 kVA and three-phase transformers greater than
or equal to 500 kVA and a loss reduction over baseline of 20 percent
for all other liquid-immersed transformers, except submersible liquid-
immersed transformers which remain at baseline; a 30 and 20 percent
reduction in baseline losses for single-, and three-phase low-voltage
distribution transformers, respectively; and a 20 percent reduction in
baseline losses for all medium-voltage dry-type distribution
transformers. TSL 2 represents a loss reduction over baseline of 5
percent for liquid-immersed transformers, except submersible liquid-
immersed transformers which remain at baseline; a 20 and 10 percent
reduction in baseline losses for single-, and three-phase low-voltage
distribution transformers, respectively; and a 10 percent reduction in
baseline losses for all medium-voltage dry-type distribution
transformers. TSL 1 represents a loss reduction over baseline of 2.5
percent for liquid-immersed transformers, except submersible liquid-
immersed transformers which remain at baseline; a 10 and 5 percent
reduction in baseline losses for single-, and three-phase low-voltage
distribution transformers, respectively; and a 5 percent reduction in
baseline losses for all medium-voltage dry-type distribution
transformers.
[[Page 29970]]
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[GRAPHIC] [TIFF OMITTED] TR22AP24.561
DOE constructed the TSLs for this final rule to include ELs
representative of ELs with similar characteristics (i.e., using similar
technologies and/or efficiencies, and having roughly comparable
equipment availability) and taking into consideration the domestic
electrical steel and amorphous capacity and conversion cost impacts
associated with various ELs. The use of representative ELs provided for
greater distinction between the TSLs. While representative ELs were
included in the TSLs, DOE considered all efficiency levels as part of
its analysis.\193\
---------------------------------------------------------------------------
\193\ Efficiency levels that were analyzed for this final rule
are discussed in section IV.F.2 of this document. Results by
efficiency level are presented in TSD chapters 8, 10, and 12.
---------------------------------------------------------------------------
[[Page 29971]]
B. Economic Justification and Energy Savings
1. Economic Impacts on Individual Consumers
DOE analyzed the economic impacts on distribution transformer
consumers by looking at the effects that potential amended standards at
each TSL would have on the LCC and PBP. DOE also examined the impacts
of potential standards on selected consumer subgroups. These analyses
are discussed in the following sections.
a. Life-Cycle Cost and Payback Period
In general, higher-efficiency products affect consumers in two
ways: (1) purchase price increases and (2) annual operating costs
decrease. Inputs used for calculating the LCC and PBP include total
installed costs (i.e., product price plus installation costs), and
operating costs (i.e., annual energy use, energy prices, energy price
trends, repair costs, and maintenance costs). The LCC calculation also
uses product lifetime and a discount rate. Chapter 8 of the final rule
TSD provides detailed information on the LCC and PBP analyses.
The following sections show the LCC and PBP results for the TSLs
considered for each product class. In the first of each pair of tables,
the simple payback is measured relative to the baseline product. In the
second table, the impacts are measured relative to the efficiency
distribution in the in the no-new-standards case in the compliance year
(see section IV.F.10 of this document). Because some consumers purchase
products with higher efficiency in the no-new-standards case, the
average savings are less than the difference between the average LCC of
the baseline product and the average LCC at each TSL. The savings refer
only to consumers who are affected by a standard at a given TSL. Those
who already purchase a product with efficiency at or above a given TSL
are not affected. Consumers for whom the LCC increases at a given TSL
experience a net cost.
Liquid-Immersed Distribution Transformer
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[[Page 29972]]
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[[Page 29973]]
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[[Page 29974]]
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[[Page 29975]]
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[[Page 29976]]
Medium-Voltage Dry-Type Distribution Transformer
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[[Page 29977]]
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[GRAPHIC] [TIFF OMITTED] TR22AP24.580
[GRAPHIC] [TIFF OMITTED] TR22AP24.581
b. Consumer Subgroup Analysis
In the consumer subgroup analysis, DOE estimated the impact of the
considered TSLs on utilities who deploy distribution transformers in
vaults or other space constrained areas, and utilities who serve low
population densities. For each of these subgroups, DOE compares the
average LCC savings and PBP at each efficiency level for the consumer
subgroups with similar metrics.
For the utilities serving low-population densities subgroup DOE
presents the impacts of small single-phase liquid-immersed (equipment
class 1B) against the those determined for the National average. DOEs
analysis show that the impacts for utilities serving low populations to
be negligible in terms of impacts and increased total installed cost,
see Table V.23 and Table V.24.
In most cases, the average LCC savings and PBP for utilities
serving low populations at the considered trial standard levels are not
substantially different from the average for all consumers. Chapter 11
of the final rule TSD presents the complete LCC and PBP results for the
subgroups.
Utilities Serving Low Population Densities
[[Page 29978]]
[GRAPHIC] [TIFF OMITTED] TR22AP24.582
[GRAPHIC] [TIFF OMITTED] TR22AP24.583
Utilities That Deploy Distribution Transformers in Vaults or Other
Space Constrained Areas
As noted in section IV.I of this document, for this final rule DOE
considered submersible distribution transformers and their associated
vault, or space constrained installation costs with individual
representative units, 15 and 16. DOE has incorporated increased
installation costs as a function of increased volume in these results.
However, as discussed in sections IV.1.2 and V.A of this document,
there is considerable uncertainty surrounding the volume increase at
which vault replacement would become necessary, and were this to occur
at a lower volume than assumed and/or were the volume to increase with
EL at a higher rate than assumed, this would result in significantly
worse average LCC savings. Due to this significant uncertainty, DOE is
unable to pinpoint at which EL, if any, this would occur. The consumer
results for these equipment are presented in Table V.25 and Table V.26.
[[Page 29979]]
[GRAPHIC] [TIFF OMITTED] TR22AP24.584
[GRAPHIC] [TIFF OMITTED] TR22AP24.585
c. Rebuttable Presumption Payback
As discussed in section IV.F.11, EPCA establishes a rebuttable
presumption that an energy conservation standard is economically
justified if the increased purchase cost for a product that meets the
standard is less than three times the value of the first-year energy
savings resulting from the standard. In calculating a rebuttable
presumption PBP for each of the considered TSLs, DOE used discrete
values and, as required by EPCA, based the energy use calculation on
the DOE test procedures for distribution transformers. In contrast, the
PBPs presented in section V.B.1.a of this document were calculated
using distributions that reflect the range of energy use in the field.
Table V.27 presents the rebuttable-presumption PBPs for the
considered TSLs for distribution transformers. While DOE examined the
rebuttable-presumption criterion, it considered whether the standard
levels considered for this rule are economically justified through a
more detailed analysis of the economic impacts of those levels,
pursuant to 42 U.S.C. 6295(o)(2)(B)(i), that considers the full range
of impacts to the consumer, manufacturer, Nation, and environment. The
results of that analysis serve as the basis for DOE to definitively
evaluate the economic justification for a potential standard level,
thereby supporting or rebutting the results of any preliminary
determination of economic justification.
[[Page 29980]]
[GRAPHIC] [TIFF OMITTED] TR22AP24.586
2. Economic Impacts on Manufacturers
DOE performed an MIA to estimate the impact of amended energy
conservation standards on manufacturers of distribution transformers.
The next section describes the expected impacts on manufacturers at
each considered TSL. Chapter 12 of the final rule TSD explains the
analysis in further detail.
a. Industry Cash Flow Analysis Results
In this section, DOE provides GRIM results from the analysis, which
examines changes in the industry that would result from amended
standards. The following tables summarize the estimated financial
impacts (represented by changes in INPV) of potential amended energy
conservation standards on manufacturers of distribution transformers,
as well as the conversion costs that DOE estimates manufacturers of
distribution transformers would incur at each TSL. DOE analyzes the
potential impacts on INPV separately for each category of distribution
transformer manufacturer: liquid-immersed, LVDT, and MVDT.
As discussed in section IV.J.2.d of this document, DOE modeled two
scenarios to evaluate a range of cash flow impacts on the distribution
transformer industry: (1) the preservation of gross margin scenario and
(2) the preservation of operating profit scenario. In the preservation
of gross margin scenario, distribution transformer manufacturers are
able to maintain the same gross margin percentage, even as the MPCs of
distribution transformers increase due to energy conservation
standards. In this scenario, the same gross margin percentage of 20
percent \194\ is applied across all ELs. In the preservation of
operating profit scenario, manufacturers do not earn additional
operating profit when compared to the no-standards case scenario. While
manufacturers make the necessary upfront investments required to
produce compliant equipment, per-unit operating profit does not change
in absolute dollars. The preservation of operating profit scenario
results in the lower (or more severe) bound to impacts of amended
standards on industry.
---------------------------------------------------------------------------
\194\ The gross margin percentage of 20 percent is based on a
manufacturer markup of 1.25.
---------------------------------------------------------------------------
Each of the modeled scenarios results in a unique set of cash flows
and corresponding industry values at each TSL for each category of
distribution transformer manufacturer. In the following discussion, the
INPV results refer to the difference in industry value between the no-
new-standards case and each standards case resulting from the sum of
discounted cash flows from 2024 through 2058. To provide perspective on
the short-run cash flow impact, DOE includes in the discussion of
results a comparison of free cash flow between the no-new-standards
case and the standards case at each TSL in the year before amended
standards are required.
DOE presents the range in INPV for liquid-immersed distribution
transformer manufacturers in Table V.28 and Table V.29; the range in
INPV for LVDT distribution transformer manufacturers in Table V.31 and
Table V.32; and the range in INPV for MVDT distribution transformer
manufacturers in Table V.34 and Table V.35.
Liquid-Immersed Distribution Transformers
[GRAPHIC] [TIFF OMITTED] TR22AP24.587
[[Page 29981]]
[GRAPHIC] [TIFF OMITTED] TR22AP24.588
[GRAPHIC] [TIFF OMITTED] TR22AP24.589
At TSL 5, DOE estimates the impacts on INPV for liquid-immersed
distribution transformer manufacturers to range from -$686 million to -
$338 million, corresponding to a change in INPV of -38.3 percent to -
18.8 percent. At TSL 5, industry free cash flow is estimated to
decrease by approximately 245 percent to -$175 million, compared to the
no-new-standard case value of $121 million in 2028, the year before the
compliance date.
TSL 5 would set the energy conservation standard at EL 5, max-tech,
for all liquid-immersed distribution transformers. DOE estimates that
less than one percent of shipments would meet these energy conservation
standards in the no-new-standards case in 2029. DOE estimates liquid-
immersed distribution transformer manufacturers would spend
approximately $194 million in product conversion costs to redesign
transformers and approximately $503 million in capital conversion costs
as all liquid-immersed distribution transformer cores manufactured are
expected to use amorphous steel.
At TSL 5, the shipment weighted average MPC for liquid-immersed
distribution transformers significantly increases by 27.0 percent
relative to the no-new-standards case shipment weighted average MPC in
2029. In the preservation of gross margin scenario, manufacturers can
fully pass along this cost increase, which causes an increase in
manufacturers' free cash flow. However, the $697 million in conversion
costs estimated at TSL 5, ultimately results in a significantly
negative change in INPV at TSL 5 under the preservation of gross margin
scenario.
Under the preservation of operating profit scenario, manufacturers
earn the same per-unit operating profit as would be earned in the no-
new-standards case, but manufacturers do not earn additional profit
from their investments or potentially higher MPCs. In this scenario,
the 27.0 percent increase in the shipment weighted average MPC results
in a reduction in the margin after the compliance year. This reduction
in the manufacturer margin and the $697 million in conversion costs
incurred by manufacturers cause a significantly negative change in INPV
at TSL 5 in the preservation of operating profit scenario. This
represents the lower-bound, or most severe impact, on manufacturer
profitability.
At TSL 4, DOE estimates the impacts on INPV for liquid-immersed
distribution transformer manufacturers to range from -$476 million to -
$388 million, corresponding to a change in INPV of -26.6 percent to -
21.6 percent. At TSL 4, industry free cash flow is estimated to
decrease by approximately 204 percent to -$125 million, compared to the
no-new-standard case value of $121 million in 2028, the year before the
compliance date.
TSL 4 would set the energy conservation standard at EL 4 for all
liquid-immersed distribution transformer representative units, except
for representative units 15 and 16, which are set at baseline. DOE
estimates that less than one percent of shipments would meet or exceed
these energy conservation standards in the no-new-standards case in
2029. DOE estimates liquid-immersed distribution transformer
manufacturers would spend approximately $193 million in product
conversion costs to redesign transformers and approximately $395
million in capital conversion costs as almost all liquid-immersed
distribution transformer cores manufactured are expected to use
amorphous steel.
At TSL 4, the shipment weighted average MPC for liquid-immersed
distribution transformers increases by 6.9 percent relative to the no-
new-standards case shipment weighted
[[Page 29982]]
average MPC in 2029. In the preservation of gross margin scenario,
manufacturers can fully pass along this cost increase, which causes an
increase in manufacturers' free cash flow. However, the $587 million in
conversion costs estimated at TSL 4, ultimately results in a moderately
negative change in INPV at TSL 4 under the preservation of gross margin
scenario.
Under the preservation of operating profit scenario, manufacturers
earn the same per-unit operating profit as would be earned in the no-
new-standards case, but manufacturers do not earn additional profit
from their investments or potentially higher MPCs. In this scenario,
the 6.9 percent increase in the shipment weighted average MPC results
in a reduction in the margin after the compliance year. This reduction
in the manufacturer margin and the $587 million in conversion costs
incurred by manufacturers cause a moderately negative change in INPV at
TSL 4 in the preservation of operating profit scenario. This represents
the lower-bound, or most severe impact, on manufacturer profitability.
At TSL 3, DOE estimates the impacts on INPV for liquid-immersed
distribution transformer manufacturers to range from -$145 million to -
$111 million, corresponding to a change in INPV of -8.1 percent to -6.2
percent. At TSL 3, industry free cash flow is estimated to decrease by
approximately 60 percent to $48 million, compared to the no-new-
standard case value of $121 million in 2028, the year before the
compliance date.
TSL 3 would set the energy conservation standard at EL 4 for the
liquid-immersed distribution transformer representative units 1A, 2A,
3, and 4A; at EL 2 for the liquid-immersed distribution transformer
representative units 1B, 2B, 4B, 5, and 17; and at baseline for the
liquid-immersed distribution transformer representative units 15 and
16. DOE estimates that approximately 3.7 percent of shipments would
meet or exceed these energy conservation standards in the no-new-
standards case in 2029. DOE estimates liquid-immersed distribution
transformer manufacturers would spend approximately $118 million in
product conversion costs to redesign transformers and approximately $69
million in capital conversion costs as a portion of liquid-immersed
distribution transformer cores manufactured are expected to use
amorphous steel.
At TSL 3, the shipment weighted average MPC for liquid-immersed
distribution transformers increases by 2.6 percent relative to the no-
new-standards case shipment weighted average MPC in 2029. In the
preservation of gross margin scenario, manufacturers can fully pass
along this cost increase, which causes an increase in manufacturers'
free cash flow. However, the $187 million in conversion costs estimated
at TSL 3, ultimately results in a moderately negative change in INPV at
TSL 3 under the preservation of gross margin scenario.
Under the preservation of operating profit scenario, manufacturers
earn the same per-unit operating profit as would be earned in the no-
new-standards case, but manufacturers do not earn additional profit
from their investments or potentially higher MPCs. In this scenario,
the 2.6 percent increase in the shipment weighted average MPC results
in a reduction in the margin after the compliance year. This reduction
in the manufacturer margin and the $187 million in conversion costs
incurred by manufacturers cause a moderately negative change in INPV at
TSL 3 in the preservation of operating profit scenario. This represents
the lower-bound, or most severe impact, on manufacturer profitability.
At TSL 2, DOE estimates the impacts on INPV for liquid-immersed
distribution transformer manufacturers to range from -$77 million to -
$58 million, corresponding to a change in INPV of -4.3 percent to -3.2
percent. At TSL 2, industry free cash flow is estimated to decrease by
approximately 32 percent to $82 million, compared to the no-new-
standard case value of $121 million in 2028, the year before the
compliance date.
TSL 2 would set the energy conservation standard at EL 2 for all
liquid-immersed distribution transformer representative units, except
for representative units 15 and 16, which are set at baseline. DOE
estimates that approximately 4.0 percent of shipments would meet or
exceed these energy conservation standards in the no-new-standards case
in 2029. DOE estimates liquid-immersed distribution transformer
manufacturers would spend approximately $101 million in product
conversion costs to redesign transformers and approximately $6 million
in capital conversion costs as almost all liquid-immersed distribution
transformer cores manufactured are expected to continue to use GOES
steel.
At TSL 2, the shipment weighted average MPC for liquid-immersed
distribution transformers increases slightly by 1.5 percent relative to
the no-new-standards case shipment weighted average MPC in 2029. In the
preservation of gross margin scenario, manufacturers can fully pass
along this cost increase, which causes a slight increase in
manufacturers' free cash flow. However, the $107 million in conversion
costs estimated at TSL 2, ultimately results in a slightly negative
change in INPV at TSL 2 under the preservation of gross margin
scenario.
Under the preservation of operating profit scenario, manufacturers
earn the same per-unit operating profit as would be earned in the no-
new-standards case, but manufacturers do not earn additional profit
from their investments or potentially higher MPCs. In this scenario,
the 1.5 percent increase in the shipment weighted average MPC results
in a slight reduction in the margin after the compliance year. This
slight reduction in the manufacturer margin and the $107 million in
conversion costs incurred by manufacturers cause a slightly negative
change in INPV at TSL 2 in the preservation of operating profit
scenario. This represents the lower-bound, or most severe impact, on
manufacturer profitability.
At TSL 1, DOE estimates the impacts on INPV for liquid-immersed
distribution transformer manufacturers to range from -$66 million to -
$62 million, corresponding to a change in INPV of -3.7 percent to -3.5
percent. At TSL 1, industry free cash flow is estimated to decrease by
approximately 30 percent to $84 million, compared to the no-new-
standard case value of $121 million in 2028, the year before the
compliance date.
TSL 1 would set the energy conservation standard at EL 1 for all
liquid-immersed distribution transformer representative units, except
for representative units 15 and 16, which are set at baseline. DOE
estimates that approximately 13.3 percent of shipments would meet or
exceed these energy conservation standards in the no-new-standards case
in 2029. DOE estimates liquid-immersed distribution transformer
manufacturers would spend approximately $100 million in product
conversion costs to redesign transformers and approximately $2 million
in capital conversion costs as almost all liquid-immersed distribution
transformer cores manufactured are expected to continue to use GOES
steel.
At TSL 1, the shipment weighted average MPC for liquid-immersed
distribution transformers increases slightly by 0.3 percent relative to
the no-new-standards case shipment weighted average MPC in 2029. In the
preservation of gross margin scenario, manufacturers can fully pass
along this cost increase, which causes a slight increase in
manufacturers' free cash flow. However, the $102 million in
[[Page 29983]]
conversion costs estimated at TSL 1, ultimately results in a slightly
negative change in INPV at TSL 1 under the preservation of gross margin
scenario.
Under the preservation of operating profit scenario, manufacturers
earn the same per-unit operating profit as would be earned in the no-
new-standards case, but manufacturers do not earn additional profit
from their investments or potentially higher MPCs. In this scenario,
the 0.3 percent increase in the shipment weighted average MPC results
in a slight reduction in the margin after the compliance year. This
slight reduction in the manufacturer margin and the $102 million in
conversion costs incurred by manufacturers cause a slightly negative
change in INPV at TSL 1 in the preservation of operating profit
scenario. This represents the lower-bound, or most severe impact, on
manufacturer profitability.
Low-Voltage Dry-Type Distribution Transformers
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[GRAPHIC] [TIFF OMITTED] TR22AP24.592
At TSL 5, DOE estimates the impacts on INPV for LVDT distribution
transformer manufacturers to range from -$68.4 million to -$54.0
million, corresponding to a change in INPV of -32.3 percent to -25.5
percent. At TSL 5, industry free cash flow is estimated to decrease by
approximately 183.6 percent to -$17.5 million, compared to the no-new-
standard case value of $20.9 million in 2028, the year before the
compliance date.
TSL 5 would set the energy conservation standard at EL 5, max-tech,
for all LVDT distribution transformers. DOE estimates that no shipments
would meet these energy conservation standards in the no-new-standards
case in 2029. DOE estimates LVDT distribution transformer manufacturers
would spend approximately $31.0 million in product conversion costs to
redesign transformers and approximately $60.8 million in capital
conversion costs as all LVDT distribution transformer cores
manufactured are expected to use amorphous steel.
At TSL 5, the shipment weighted average MPC for LVDT distribution
transformers increases by 11.1 percent relative to the no-new-standards
case shipment weighted average MPC in 2029. In the preservation of
gross margin scenario, manufacturers can fully pass along this cost
increase, which causes an increase in manufacturers' free cash flow.
However,
[[Page 29984]]
the $91.8 million in conversion costs estimated at TSL 5, ultimately
results in a moderately negative change in INPV at TSL 5 under the
preservation of gross margin scenario.
Under the preservation of operating profit scenario, manufacturers
earn the same per-unit operating profit as would be earned in the no-
new-standards case, but manufacturers do not earn additional profit
from their investments or potentially higher MPCs. In this scenario,
the 11.1 percent increase in the shipment weighted average MPC results
in a reduction in the margin after the compliance year. This reduction
in the manufacturer margin and the $91.8 million in conversion costs
incurred by manufacturers cause a significantly negative change in INPV
at TSL 5 in the preservation of operating profit scenario. This
represents the lower-bound, or most severe impact, on manufacturer
profitability.
At TSL 4, DOE estimates the impacts on INPV for LVDT distribution
transformer manufacturers to range from -$62.9 million to -$52.2
million, corresponding to a change in INPV of -29.7 percent to -24.7
percent. At TSL 4, industry free cash flow is estimated to decrease by
approximately 173.0 percent to -$15.2 million, compared to the no-new-
standard case value of $20.9 million in 2028, the year before the
compliance date.
TSL 4 would set the energy conservation standard at EL 4 for all
LVDT distribution transformers. DOE estimates that no shipments would
meet these energy conservation standards in the no-new-standards case
in 2029. DOE estimates LVDT distribution transformer manufacturers
would spend approximately $30.3 million in product conversion costs to
redesign transformers and approximately $56.4 million in capital
conversion costs as almost all LVDT distribution transformer cores
manufactured are expected to use amorphous steel.
At TSL 4, the shipment weighted average MPC for LVDT distribution
transformers increases by 8.2 percent relative to the no-new-standards
case shipment weighted average MPC in 2029. In the preservation of
gross margin scenario, manufacturers can fully pass along this cost
increase, which causes an increase in manufacturers' free cash flow.
However, the $86.7 million in conversion costs estimated at TSL 4,
ultimately results in a moderately negative change in INPV at TSL 4
under the preservation of gross margin scenario.
Under the preservation of operating profit scenario, manufacturers
earn the same per-unit operating profit as would be earned in the no-
new-standards case, but manufacturers do not earn additional profit
from their investments or potentially higher MPCs. In this scenario,
the 8.2 percent increase in the shipment weighted average MPC results
in a reduction in the margin after the compliance year. This reduction
in the manufacturer margin and the $86.7 million in conversion costs
incurred by manufacturers cause a moderately negative change in INPV at
TSL 4 in the preservation of operating profit scenario. This represents
the lower-bound, or most severe impact, on manufacturer profitability.
At TSL 3, DOE estimates the impacts on INPV for LVDT distribution
transformer manufacturers to range from -$27.1 million to -$18.9
million, corresponding to a change in INPV of -12.8 percent to -8.9
percent. At TSL 3, industry free cash flow is estimated to decrease by
approximately 68.8 percent to $6.5 million, compared to the no-new-
standard case value of $20.9 million in 2028, the year before the
compliance date.
TSL 3 would set the energy conservation standard at EL 3 for all
LVDT distribution transformers. DOE estimates that less than one
percent of shipments would meet these energy conservation standards in
the no-new-standards case in 2029. DOE estimates LVDT distribution
transformer manufacturers would spend approximately $19.9 million in
product conversion costs to redesign transformers and approximately
$16.3 million in capital conversion costs as a portion of LVDT
distribution transformer cores manufactured are expected to use
amorphous steel.
At TSL 3, the shipment weighted average MPC for LVDT distribution
transformers increases by 6.3 percent relative to the no-new-standards
case shipment weighted average MPC in 2029. In the preservation of
gross margin scenario, manufacturers can fully pass along this cost
increase, which causes an increase in manufacturers' free cash flow.
However, the $36.1 million in conversion costs estimated at TSL 3,
ultimately results in a moderately negative change in INPV at TSL 3
under the preservation of gross margin scenario.
Under the preservation of operating profit scenario, manufacturers
earn the same per-unit operating profit as would be earned in the no-
new-standards case, but manufacturers do not earn additional profit
from their investments or potentially higher MPCs. In this scenario,
the 6.3 percent increase in the shipment weighted average MPC results
in a reduction in the margin after the compliance year. This reduction
in the manufacturer margin and the $36.1 million in conversion costs
incurred by manufacturers cause a moderately negative change in INPV at
TSL 3 in the preservation of operating profit scenario. This represents
the lower-bound, or most severe impact, on manufacturer profitability.
At TSL 2, DOE estimates the impacts on INPV for LVDT distribution
transformer manufacturers to range from -$10.4 million to -$9.6
million, corresponding to a change in INPV of -4.9 percent to -4.5
percent. At TSL 2, industry free cash flow is estimated to decrease by
approximately 30.1 percent to $14.6 million, compared to the no-new-
standard case value of $20.9 million in 2028, the year before the
compliance date.
TSL 2 would set the energy conservation standard at EL 2 for all
LVDT distribution transformers. DOE estimates that approximately 3.7
percent of shipments would meet these energy conservation standards in
the no-new-standards case in 2029. DOE estimates LVDT distribution
transformer manufacturers would spend approximately $15.9 million in
product conversion costs to redesign transformers and approximately
$1.4 million in capital conversion costs as almost all LVDT
distribution transformer cores manufactured are expected to continue to
use GOES steel.
At TSL 2, the shipment weighted average MPC for LVDT distribution
transformers increases by 0.6 percent relative to the no-new-standards
case shipment weighted average MPC in 2029. In the preservation of
gross margin scenario, manufacturers can fully pass along this cost
increase, which causes an increase in manufacturers' free cash flow.
However, the $17.3 million in conversion costs estimated at TSL 2,
ultimately results in a slightly negative change in INPV at TSL 2 under
the preservation of gross margin scenario.
Under the preservation of operating profit scenario, manufacturers
earn the same per-unit operating profit as would be earned in the no-
new-standards case, but manufacturers do not earn additional profit
from their investments or potentially higher MPCs. In this scenario,
the 0.6 percent increase in the shipment weighted average MPC results
in a reduction in the margin after the compliance year. This reduction
in the manufacturer margin and the $17.3 million in conversion costs
incurred by manufacturers cause a slightly negative change in INPV at
TSL 2 in the preservation of operating profit scenario. This represents
the lower-
[[Page 29985]]
bound, or most severe impact, on manufacturer profitability.
At TSL 1, DOE estimates the impacts on INPV for LVDT distribution
transformer manufacturers to range from -$8.9 million to -$8.5 million,
corresponding to a change in INPV of -4.2 percent to -4.0 percent. At
TSL 1, industry free cash flow is estimated to decrease by
approximately 26.4 percent to $15.4 million, compared to the no-new-
standard case value of $20.9 million in 2028, the year before the
compliance date.
TSL 1 would set the energy conservation standard at EL 1 for all
LVDT distribution transformers. DOE estimates that approximately 24.5
percent of shipments would meet these energy conservation standards in
the no-new-standards case in 2029. DOE estimates LVDT distribution
transformer manufacturers would spend approximately $15.5 million in
product conversion costs to redesign transformers.
At TSL 1, the shipment weighted average MPC for LVDT distribution
transformers deceases slightly by 0.3 percent relative to the no-new-
standards case shipment weighted average MPC in 2029. In both
manufacturer markup scenarios, this slight decrease in manufacturer
markup does not have a significant impact on manufacturers' free cash
flow. However, in both manufacturer markup scenarios, the $15.5 million
in conversion costs estimated at TSL 1, results in a slightly negative
change in INPV at TSL 1.
Medium-Voltage Dry-Type Distribution Transformers
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[GRAPHIC] [TIFF OMITTED] TR22AP24.594
[GRAPHIC] [TIFF OMITTED] TR22AP24.595
At TSL 5, DOE estimates the impacts on INPV for MVDT distribution
transformer manufacturers to range from -$33.2 million to -$16.3
million, corresponding to a change in INPV of -34.9 percent to -17.1
percent. At TSL 5, industry free cash flow is estimated to decrease by
approximately 200.3 percent to -$7.7 million, compared to the no-new-
standard case value of $7.7 million in 2028, the year before the
compliance date.
TSL 5 would set the energy conservation standard at EL 5, max-tech,
for all MVDT distribution transformers. DOE estimates that no shipments
would meet these energy conservation standards in the no-new-standards
case in 2029. DOE estimates MVDT distribution transformer manufacturers
would spend approximately $10.1 million in product conversion costs to
redesign transformers and approximately $26.2 million in capital
[[Page 29986]]
conversion costs as all MVDT distribution transformer cores
manufactured are expected to use amorphous steel.
At TSL 5, the shipment weighted average MPC for LVDT distribution
transformers significantly increases by 26.3 percent relative to the
no-new-standards case shipment weighted average MPC in 2029. In the
preservation of gross margin scenario, manufacturers can fully pass
along this cost increase, which causes an increase in manufacturers'
free cash flow. However, the $36.2 million in conversion costs
estimated at TSL 5, ultimately results in a moderately negative change
in INPV at TSL 5 under the preservation of gross margin scenario.
Under the preservation of operating profit scenario, manufacturers
earn the same per-unit operating profit as would be earned in the no-
new-standards case, but manufacturers do not earn additional profit
from their investments or potentially higher MPCs. In this scenario,
the 26.3 percent increase in the shipment weighted average MPC results
in a reduction in the margin after the compliance year. This reduction
in the manufacturer margin and the $36.2 million in conversion costs
incurred by manufacturers cause a significantly negative change in INPV
at TSL 5 in the preservation of operating profit scenario. This
represents the lower-bound, or most severe impact, on manufacturer
profitability.
At TSL 4, DOE estimates the impacts on INPV for MVDT distribution
transformer manufacturers to range from -$29.5 million to -$18.6
million, corresponding to a change in INPV of -31.0 percent to -19.5
percent. At TSL 4, industry free cash flow is estimated to decrease by
approximately 191.7 percent to -$7.0 million, compared to the no-new-
standard case value of $7.7 million in 2028, the year before the
compliance date.
TSL 4 would set the energy conservation standard at EL 4 for all
MVDT distribution transformers. DOE estimates that no shipments would
meet these energy conservation standards in the no-new-standards case
in 2029. DOE estimates LVDT distribution transformer manufacturers
would spend approximately $10.1 million in product conversion costs to
redesign transformers and approximately $24.7 million in capital
conversion costs as all MVDT distribution transformer cores
manufactured are expected to use amorphous steel.
At TSL 4, the shipment weighted average MPC for MVDT distribution
transformers increases by 17.0 percent relative to the no-new-standards
case shipment weighted average MPC in 2029. In the preservation of
gross margin scenario, manufacturers can fully pass along this cost
increase, which causes an increase in manufacturers' free cash flow.
However, the $34.8 million in conversion costs estimated at TSL 4,
ultimately results in a moderately negative change in INPV at TSL 4
under the preservation of gross margin scenario.
Under the preservation of operating profit scenario, manufacturers
earn the same per-unit operating profit as would be earned in the no-
new-standards case, but manufacturers do not earn additional profit
from their investments or potentially higher MPCs. In this scenario,
the 17.0 percent increase in the shipment weighted average MPC results
in a reduction in the margin after the compliance year. This reduction
in the manufacturer margin and the $34.8 million in conversion costs
incurred by manufacturers cause a significantly negative change in INPV
at TSL 4 in the preservation of operating profit scenario. This
represents the lower-bound, or most severe impact, on manufacturer
profitability.
At TSL 3, DOE estimates the impacts on INPV for MVDT distribution
transformer manufacturers to range from -$26.4 million to -$19.1
million, corresponding to a change in INPV of -27.8 percent to -20.1
percent. At TSL 3, industry free cash flow is estimated to decrease by
approximately 179.9 percent to -$6.1 million, compared to the no-new-
standard case value of $7.7 million in 2028, the year before the
compliance date.
TSL 3 would set the energy conservation standard at EL 3 for all
MVDT distribution transformers. DOE estimates that no shipments would
meet these energy conservation standards in the no-new-standards case
in 2029. DOE estimates MVDT distribution transformer manufacturers
would spend approximately $9.8 million in product conversion costs to
redesign transformers and approximately $22.9 million in capital
conversion costs as the majority of MVDT distribution transformer cores
manufactured are expected to use amorphous steel.
At TSL 3, the shipment weighted average MPC for MVDT distribution
transformers increases by 11.3 percent relative to the no-new-standards
case shipment weighted average MPC in 2029. In the preservation of
gross margin scenario, manufacturers can fully pass along this cost
increase, which causes an increase in manufacturers' free cash flow.
However, the $32.7 million in conversion costs estimated at TSL 3,
ultimately results in a moderately negative change in INPV at TSL 3
under the preservation of gross margin scenario.
Under the preservation of operating profit scenario, manufacturers
earn the same per-unit operating profit as would be earned in the no-
new-standards case, but manufacturers do not earn additional profit
from their investments or potentially higher MPCs. In this scenario,
the 11.3 percent increase in the shipment weighted average MPC results
in a reduction in the margin after the compliance year. This reduction
in the manufacturer margin and the $32.7 million in conversion costs
incurred by manufacturers cause a moderately negative change in INPV at
TSL 3 in the preservation of operating profit scenario. This represents
the lower-bound, or most severe impact, on manufacturer profitability.
At TSL 2, DOE estimates the impacts on INPV for MVDT distribution
transformer manufacturers to range from -$4.4 million to -$2.3 million,
corresponding to a change in INPV of -4.7 percent to -2.5 percent. At
TSL 2, industry free cash flow is estimated to decrease by
approximately 27.2 percent to $5.6 million, compared to the no-new-
standard case value of $7.7 million in 2028, the year before the
compliance date.
TSL 2 would set the energy conservation standard at EL 2 for all
MVDT distribution transformers. DOE estimates that approximately 3.8
percent of shipments would meet these energy conservation standards in
the no-new-standards case in 2029. DOE estimates MVDT distribution
transformer manufacturers would spend approximately $5.2 million in
product conversion costs to redesign transformers and approximately
$0.5 million in capital conversion costs as almost all MVDT
distribution transformer cores manufactured are expected to continue to
use GOES steel.
At TSL 2, the shipment weighted average MPC for MVDT distribution
transformers increases by 3.2 percent relative to the no-new-standards
case shipment weighted average MPC in 2029. In the preservation of
gross margin scenario, manufacturers can fully pass along this cost
increase, which causes an increase in manufacturers' free cash flow.
However, the $5.7 million in conversion costs estimated at TSL 2,
ultimately results in a slightly negative change in INPV at TSL 2 under
the preservation of gross margin scenario.
Under the preservation of operating profit scenario, manufacturers
earn the same per-unit operating profit as would
[[Page 29987]]
be earned in the no-new-standards case, but manufacturers do not earn
additional profit from their investments or potentially higher MPCs. In
this scenario, the 3.2 percent increase in the shipment weighted
average MPC results in a reduction in the margin after the compliance
year. This reduction in the manufacturer margin and the $5.7 million in
conversion costs incurred by manufacturers cause a slightly negative
change in INPV at TSL 2 in the preservation of operating profit
scenario. This represents the lower-bound, or most severe impact, on
manufacturer profitability.
At TSL 1, DOE estimates the impacts on INPV for MVDT distribution
transformer manufacturers to range from -$3.5 million to -$2.7 million,
corresponding to a change in INPV of -3.6 percent to -2.8 percent. At
TSL 1, industry free cash flow is estimated to decrease by
approximately 23.4 percent to $5.9 million, compared to the no-new-
standard case value of $7.7 million in 2028, the year before the
compliance date.
TSL 1 would set the energy conservation standard at EL 1 for all
MVDT distribution transformers. DOE estimates that approximately 21.7
percent of shipments would meet these energy conservation standards in
the no-new-standards case in 2029. DOE estimates MVDT distribution
transformer manufacturers would spend approximately $5.0 million in
product conversion costs to redesign transformers.
At TSL 1, the shipment weighted average MPC for MVDT distribution
transformers deceases slightly by 1.2 percent relative to the no-new-
standards case shipment weighted average MPC in 2029. In both
manufacturer markup scenarios, this slight decrease in manufacturer
markup does not have a significant impact on manufacturers' free cash
flow. However, in both manufacturer markup scenarios, the $5.0 million
in conversion costs estimated at TSL 1, results in a slightly negative
change in INPV at TSL 1.
b. Direct Impacts on Employment
To quantitatively assess the potential impacts of amended energy
conservation standards on direct employment in the distribution
transformer industry, DOE used the GRIM to estimate the domestic labor
expenditures and number of direct employees in the no-new-standards
case and in each of the standards cases during the analysis period.
Production employees are those who are directly involved in
fabricating and assembling equipment within a manufacturer facility.
Workers performing services that are closely associated with production
operations, such as materials handling tasks using forklifts, are
included as production labor, as well as line supervisors.
DOE used the GRIM to calculate the number of production employees
from labor expenditures. DOE used statistical data from the U.S. Census
Bureau's 2021 Annual Survey of Manufacturers (ASM) and the results of
the engineering analysis to calculate industry-wide labor expenditures.
Labor expenditures related to equipment manufacturing depend on the
labor intensity of the product, the sales volume, and an assumption
that wages remain fixed in real terms over time. The total labor
expenditures in the GRIM were then converted to domestic production
employment levels by dividing production labor expenditures by the
annual payment per production worker.
Non-production employees account for those workers that are not
directly engaged in the manufacturing of the covered equipment. This
could include sales, human resources, engineering, and management. DOE
estimated non-production employment levels by multiplying the number of
distribution transformer workers by a scaling factor. The scaling
factor is calculated by taking the ratio of the total number of
employees, and the total production workers associated with the
industry NAICS code 335311, which covers power, distribution, and
specialty transformer manufacturing.
Using data from manufacturer interviews and estimated market share
data, DOE estimates that approximately 85 percent of all liquid-
immersed distribution transformer manufacturing; 15 percent of all LVDT
distribution transformer manufacturing; and 75 percent of all MVDT
distribution transformer manufacturing takes place domestically.
Several interested parties commented on the direct employment
analysis in the January 2023 NOPR. Some interested parties commented
that the standards proposed in the January 2023 NOPR would result in a
decrease in domestic employment. UAW commented that it expects mass
layoffs as a result of the standards proposed in the January 2023 NOPR
since 70 percent of the electrical steel that UAW members produce for
Cleveland Cliffs is used in distribution transformer cores. (UAW, No.
90 at P. 2) UAW also commented that currently 90 percent of
distribution transformers are made with GOES. Without this demand for
GOES, the continued production of all GOES in the United States could
be placed in jeopardy. (Id.) UAW urged DOE to consider the potential
loss of electrical steel jobs as a result of any adopted standards for
distribution transformers. (Id.) Similarly, UAW Locals commented that
the standards proposed in the January 2023 NOPR would make Cleveland
Cliffs electrical steel plants uneconomic, which could jeopardize
nearly 1,500 steel manufacturing jobs. (UAW Locals, No. 91 at p. 1)
NAHB commented that DOE must consider the possibility that
requiring a new manufacturing process to make distribution transformers
more efficient may actually require fewer workers. (NAHB, No. 106 at
pp. 11-12) Prolec GE commented that any standards that required a shift
from GOES production to amorphous steel production would affect
domestic employment as currently most of the core manufacturing using
GOES is done in-house, and it would need to be shifted to outsourced
finished amorphous metal cores where most of the production capacity is
not domestic. (Prolec GE, No. 120 at p. 13) Lastly, Cliffs commented
that DOE underestimated the required number amount of labor to convert
to amorphous production in the January 2023 NOPR and the actual
additional number of employees to meet the standards proposed in the
January 2023 NOPR will lead to increased offshoring. (Cliffs, No. 105
at pp. 14-15)
Other interested parties comments that the standards proposed in
the January 2023 NOPR would result in an increase in domestic
employment. Eaton commented that it expects an increase in labor
content to meet the standards proposed in the January 2023 NOPR.
(Eaton, No. 137 at p. 29) Howard commented that they would need to add
1,000-2,000 employees (which corresponds to a 25-50 percent increase in
their current employment levels) to meet the standards proposed in the
January 2023 NOPR. (Howard, No. 116 at p. 2) Howard stated they
estimate the entire industry could need an additional 5,500 to 6,000
employees to meet the standards proposed in the January 2023 NOPR.
(Howard, No. 116 at p. 2) Additionally, Howard commented that in
addition to distribution transformer manufacturers adding employees,
electrical steel manufacturers would have to add employees as well,
which will be difficult given the 3-year compliance period used in the
January 2023 NOPR and the current labor market, which lacks available
personnel. (Howard, No. 116 at pp. 2-3) Metglas commented that it
estimated that amorphous production would require 600 to 900 new U.S.
jobs to meet the standards proposed in the January
[[Page 29988]]
2023 NOPR. (Metglas, No. 125 at p. 7) Efficiency advocates commented
that the expansion of amorphous production capacity would be expected
to add hundreds of electrical steel manufacturing jobs. (Efficiency
advocates, No. 121 at pp. 4-5) Efficiency advocates additionally stated
that producers of GOES would be well positioned to transition
production capacity to NOES to preserve manufacturing jobs. (Id.)
DOE's direct employment analysis conducted in the January 2023 NOPR
presented a range of impacts to employment. As some interested parties
commented, manufacturing distribution transformers with amorphous cores
will likely require additional employees. However, DOE also recognizes
that currently many amorphous core manufacturing locations are outside
the U.S., as some interested parties commented. DOE continues to
present a range of domestic employment impacts in this final rule that
show the likely range in domestic employment given that manufacturing
more efficient distribution transformers will likely result in an
increase in production employees; however, some manufacturers may shift
current domestic production to non-domestic locations to fulfill this
additional labor demand. The range of potential impacts displayed in
Table V.37, Table V.38, and Table V.39 present the most likely range of
potential impacts to domestic employment for the analyzed TSLs.
Liquid-Immersed Distribution Transformers
[GRAPHIC] [TIFF OMITTED] TR22AP24.596
Using the estimated labor content from the GRIM combined with data
from the 2021 ASM, DOE estimates that there would be approximately
6,561 domestic production workers, and 2,721 domestic non-production
workers involved in liquid-immersed distribution transformer
manufacturing in 2029 in the absence of amended energy conservation
standards. Table V.37 shows the range of the impacts of energy
conservation standards on U.S. production on liquid-immersed
distribution transformers.
Amorphous core production is more labor intensive and would require
additional labor expenditures. The upper range of the ``Potential
Change in Total Domestic Employment in 2029'' displayed in Table V.37,
assumes that all domestic liquid-immersed distribution transformer
manufacturing remains in the U.S. For this scenario, the additional
labor expenditures associated with amorphous core production result in
the number of total direct employees to increase due to energy
conservation standards. At higher TSLs, the estimated number of
amorphous cores used in liquid-immersed distribution transformers
increases, which causes the number of direct employees to also
increase. The lower range of the ``Potential Change in Total Domestic
Employment in 2029'' displayed in Table V.37, assumes that as more
amorphous cores are used to meet higher energy conservation standards,
either the amorphous core production is outsourced to core only
manufacturers (manufacturers that specialize in manufacturing cores
used in distribution transformers, but do not actually manufacture
entire distribution transformers) which may be located in foreign
countries, or distribution transformer manufacturing is re-located to
foreign countries. This lower range assumes that 30 percent of
distribution transformers using amorphous cores are re-located to
foreign countries due to energy conservation standards. DOE
acknowledges that each distribution transformer manufacturer would
individually make a business decision to either make the substantial
investments to add or increase their own amorphous core production
capabilities and continue to manufacturer their own cores in-house;
outsource their amorphous core production to another distribution core
manufacturer, which may or may not be located in the U.S.; or re-locate
some or all of their distribution transformer manufacturing to a
foreign country. DOE acknowledges there is a wide range of potential
domestic employment impacts due to energy conservation standards,
especially at the higher TSLs. The ranges in potential employment
impacts displayed in Table V.37 at each TSL attempt to provide a
reasonable upper and lower bound to how liquid-immersed distribution
transformer manufacturers may respond to potential energy conservation
standards.
Low-Voltage Dry-Type Distribution Transformers
[[Page 29989]]
[GRAPHIC] [TIFF OMITTED] TR22AP24.597
Using the estimated labor content from the GRIM combined with data
from the 2021 ASM, DOE estimates that there would be approximately 185
domestic production workers, and 77 domestic non-production workers
involved in LVDT distribution transformer manufacturing in 2029 in the
absence of amended energy conservation standards. Table V.38 shows the
range of the impacts of energy conservation standards on U.S.
production on LVDT distribution transformers.
DOE used the same methodology to estimate the potential impacts to
domestic employment for LVDT distribution transformer manufacturing
that was used for liquid-immersed distribution transformer
manufacturing. The upper range of the ``Potential Change in Total
Domestic Employment in 2029'' displayed in Table V.38, assumes that all
LVDT distribution transformer manufacturing remains in the U.S. The
lower range of the ``Potential Change in Total Domestic Employment in
2029'', assumes that 30 percent of distribution transformers using
amorphous cores are re-located to foreign countries, either due to
amorphous core production that is outsourced to core only manufacturers
located in foreign countries or LVDT distribution transformer
manufacturers re-locating their distribution transformer production to
foreign countries.
Medium-Voltage Dry-Type Distribution Transformers
[GRAPHIC] [TIFF OMITTED] TR22AP24.598
Using the estimated labor content from the GRIM combined with data
from the 2021 ASM, DOE estimates that there would be approximately 300
domestic production workers, and 125 domestic non-production workers
involved in MVDT distribution transformer manufacturing in 2029 in the
absence of amended energy conservation standards. Table V.39 shows the
range of the impacts of energy conservation standards on U.S.
production on MVDT distribution transformers.
DOE used the same methodology to estimate the potential impacts to
domestic employment for MVDT distribution transformer manufacturing
that was used for liquid-immersed distribution transformer
manufacturing. The upper range of the ``Potential Change in Total
Domestic Employment in 2029'' displayed in Table V.39, assumes that all
MVDT distribution transformer manufacturing remains in the U.S. The
lower range of the ``Potential Change in Total Domestic Employment in
2029'', assumes that 30 percent of distribution transformers using
amorphous cores are re-located to foreign countries, either due to
amorphous core production that is outsourced to core only manufacturers
located in foreign countries or MVDT distribution transformer
manufacturers re-locating their distribution transformer production to
foreign countries.
c. Impacts on Manufacturing Capacity
The prices of raw materials currently used in distribution
transformers, such as GOES, copper, and aluminum, have all experienced
a significant increase in price starting at the beginning of 2021. The
availability of these commodities remains a significant concern with
distribution transformer manufacturers. As previously stated in the
January 2023
[[Page 29990]]
NOPR, GOES investment from steel producers is competing with NOES
investment suited for electric vehicle production. This competing
investment, combined with demand growth supporting other
electrification trends has led to a substantial global increase in
GOES. However, amorphous alloys have not seen the same significant
increase in price as GOES.
The availability of amorphous material is a concern for many
distribution transformer manufacturers. Based on information received
during manufacturer interviews, some distribution transformer
manufacturers suggested that there would not be enough amorphous steel
available to be used in all or even most distribution transformers
currently sold in the U.S. Other distribution transformer manufacturers
and steel suppliers interviewed stated that, while the current capacity
of amorphous steel does not exist to supply the majority of the steel
used in distribution transformer cores, steel manufacturers are capable
of significantly increasing their amorphous steel production if there
is sufficient market demand for amorphous steel.
Cliffs commented that the January 2023 NOPR did not accurately
account for the supply chain constraints associated with ramping up
production of amorphous steel in addition to the tremendous increased
demands linked to greater market penetration of electric vehicles and
other decarbonization efforts that the steel industry is facing.
(Cliffs., No, 105 at p. 15) Cliffs continued stating the increased
costs associated with all distribution transformers using amorphous
cores, which currently constitutes about three percent of the market
for distribution transformers, will be massive and stretch the limits
of existing supply chains beyond their breaking point. (Id.) Eaton
commented that changing the current supply of GOES that used in almost
all distribution transformer cores today to having almost all
distribution transformers using amorphous cores would disrupt the
supply of cores and/or core steel to a massive extent and would likely
to be accompanied by some unexpected outcomes. (Eaton, No. 137 at p.
26)
While the availability of both GOES and amorphous steel is a
concern for many distribution transformer manufacturers, steel
suppliers should be able to meet the market demand for amorphous steel
for all TSLs analyzed given the 5-year compliance period for
distribution transformers. Steel manufacturers should be able to
significantly increase their supply of amorphous steel if they know
there will be an increase in the demand for this material due to energy
conservation standards for distribution transformers. See section V.C
for a more detailed discussion of the expected core materials needed to
meet amended standards.
Additionally, in response to the January 2023 NOPR, Howard
commented that the standards proposed in the January 2023 NOPR would
require them to redesign 8,000--10,000 distribution transformers, which
ordinarily would be done over a 5-year period. (Howard, No. 116 at p.
3) Howard also commented that they estimate that facility and equipment
additions alone will take 5 years and Howard will need to begin
production of new units prior to the actual compliance deadline to
ensure all raw materials are used. (Id.) In the January 2023 NOPR, DOE
used a 3-year compliance period. For this final rule, DOE is adopting a
5-year compliance period. While DOE acknowledges that manufacturers
will be required to make significant changes to their manufacturing
facilities to be able to produce distribution transformers that use
amorphous cores, this is not anticipated to cause manufacturing
capacity constraints given the 5-year compliance period. Further, DOE
notes that the adopted standards in this final rule require
substantially less manufacturer investment than those proposed in the
January 2023 NOPR.
d. Impacts on Subgroups of Manufacturers
As discussed in section IV.J.1 of this document, using average cost
assumptions to develop an industry cash flow estimate may not be
adequate for assessing differential impacts among manufacturer
subgroups. Small manufacturers, niche manufacturers, and manufacturers
exhibiting a cost structure substantially different from the industry
average could be affected disproportionately. DOE used the results of
the industry characterization to group manufacturers exhibiting similar
characteristics. Consequently, DOE considered four manufacturer
subgroups in the MIA: liquid-immersed, LVDT, MVDT, and small
manufacturers as a subgroup for a separate impact analysis. DOE
discussed the potential impacts on liquid-immersed, LVDT, and MVDT
distribution transformer manufacturers separately in sections V.B.2.a
and V.B.2.b of this document.
For the small business subgroup analysis, DOE applied the small
business size standards published by the Small Business Administration
(SBA) to determine whether a company is considered a small business.
The size standards are codified at 13 CFR part 121. To be categorized
as a small business under NAICS code 335311, ``power, distribution, and
specialty transformer manufacturing,'' a distribution transformer
manufacturer and its affiliates may employ a maximum of 800 employees.
The 800-employee threshold includes all employees in a business's
parent company and any other subsidiaries. For a discussion of the
impacts on the small manufacturer subgroup, see the Regulatory
Flexibility Analysis in section VI.B of this document.
e. Cumulative Regulatory Burden
One aspect of assessing manufacturer burden involves looking at the
cumulative impact of multiple DOE standards and the regulatory actions
of other Federal agencies and States that affect the manufacturers of a
covered product or equipment. While any one regulation may not impose a
significant burden on manufacturers, the combined effects of several
existing or impending regulations may have serious consequences for
some manufacturers, groups of manufacturers, or an entire industry.
Multiple regulations affecting the same manufacturer can strain profits
and lead companies to abandon product lines or markets with lower
expected future returns than competing products. For these reasons, DOE
conducts an analysis of cumulative regulatory burden as part of its
rulemakings pertaining to appliance efficiency.
DOE evaluates product-specific regulations that will take effect
approximately 3 years before or after the estimated 2029 compliance
date of any amended energy conservation standards for distribution
transformers. This information is presented in Table V.40.
[[Page 29991]]
[GRAPHIC] [TIFF OMITTED] TR22AP24.599
3. National Impact Analysis
This section presents DOE's estimates of the national energy
savings and the NPV of consumer benefits that would result from each of
the TSLs considered as potential amended standards.
a. National Energy Savings
To estimate the energy savings attributable to potential amended
standards for distribution transformers, DOE compared their energy
consumption under the no-new-standards case to their anticipated energy
consumption under each TSL. The savings are measured over the entire
lifetime of products purchased in the 30-year period that begins in the
year of anticipated compliance with amended standards 2029-2058. Table
V.41 presents DOE's projections of the national energy savings for each
TSL considered for distribution transformers, the results showing DOE's
amended standards are in bold. The savings were calculated using the
approach described in section IV.H of this document.
[[Page 29992]]
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[[Page 29993]]
[GRAPHIC] [TIFF OMITTED] TR22AP24.601
OMB Circular A-4 \195\ requires agencies to present analytical
results, including separate schedules of the monetized benefits and
costs that show the type and timing of benefits and costs. Circular A-4
also directs agencies to consider the variability of key elements
underlying the estimates of benefits and costs. For this rulemaking,
DOE undertook a sensitivity analysis using 9 years, rather than 30
years, of product shipments. The choice of a 9-year period is a proxy
for the timeline in EPCA for the review of certain energy conservation
standards and potential revision of and compliance with such revised
standards.\196\ The review timeframe established in EPCA is generally
not synchronized with the product lifetime, product manufacturing
cycles, or other factors specific to distribution transformers. Thus,
such results are presented for informational purposes only and are not
indicative of any change in DOE's analytical methodology. The NES
sensitivity analysis results based on a 9-year analytical period are
presented in Table V.42. The impacts are counted over the lifetime of
distribution transformers purchased during the period 2029-2058, the
results showing DOE's amended standards are in bold.
---------------------------------------------------------------------------
\195\ U.S. Office of Management and Budget. Circular A-4:
Regulatory Analysis. Available at www.whitehouse.gov/omb/information-for-agencies/circulars (last accessed January 19, 2024).
DOE used the prior version of Circular A-4 (September 17, 2003) in
accordance with the effective date of the November 9, 2023 version.
\196\ EPCA requires DOE to review its standards at least once
every 6 years, and requires, for certain products, a 3-year period
after any new standard is promulgated before compliance is required,
except that in no case may any new standards be required within 6
years of the compliance date of the previous standards. (42 U.S.C.
6316(a); 42 U.S.C. 6295(m)) While adding a 6-year review to the 3-
year compliance period adds up to 9 years, DOE notes that it may
undertake reviews at any time within the 6-year period and that the
3-year compliance date may yield to the 6-year backstop. A 9-year
analysis period may not be appropriate given the variability that
occurs in the timing of standards reviews and the fact that for some
products, the compliance period is 5 years rather than 3 years.
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[[Page 29994]]
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[[Page 29995]]
[GRAPHIC] [TIFF OMITTED] TR22AP24.603
b. Net Present Value of Consumer Costs and Benefits
DOE estimated the cumulative NPV of the total costs and savings for
consumers that would result from the TSLs considered for distribution
transformers. In accordance with OMB's guidelines on regulatory
analysis,\197\ DOE calculated NPV using both a 7-percent and a 3-
percent real discount rate. Table V.43 shows the consumer NPV results
with impacts counted over the lifetime of products purchased during the
period 2029-2058.
---------------------------------------------------------------------------
\197\ U.S. Office of Management and Budget. Circular A-4:
Regulatory Analysis. September 17, 2003. https://www.whitehouse.gov/wp-content/uploads/legacy_drupal_files/omb/circulars/A4/a-4.pdf#page=33.
[GRAPHIC] [TIFF OMITTED] TR22AP24.604
[[Page 29996]]
[GRAPHIC] [TIFF OMITTED] TR22AP24.605
The NPV results based on the aforementioned 9-year analytical
period are presented in Table V.44. The impacts are counted over the
lifetime of products purchased during the period 2029-2037. As
mentioned previously, such results are presented for informational
purposes only and are not indicative of any change in DOE's analytical
methodology or decision criteria.
[[Page 29997]]
[GRAPHIC] [TIFF OMITTED] TR22AP24.606
The previous results reflect the use of a default trend to estimate
the change in price for distribution transformers over the analysis
period (see section IV.H.3 of this document). DOE also conducted a
sensitivity analysis that considered
[[Page 29998]]
one scenario with a lower rate of price decline than the reference case
and one scenario with a higher rate of price decline than the reference
case. The results of these alternative cases are presented in appendix
10C of the final rule TSD. In the high-price-decline case, the NPV of
consumer benefits is higher than in the default case. In the low-price-
decline case, the NPV of consumer benefits is lower than in the default
case.
c. Indirect Impacts on Employment
DOE estimates that amended energy conservation standards for
distribution transformers will reduce energy expenditures for consumers
of those products, with the resulting net savings being redirected to
other forms of economic activity. These expected shifts in spending and
economic activity could affect the demand for labor. As described in
section IV.N of this document, DOE used an input/output model of the
U.S. economy to estimate indirect employment impacts of the TSLs that
DOE considered. There are uncertainties involved in projecting
employment impacts, especially changes in the later years of the
analysis. Therefore, DOE generated results for near-term timeframes
(2029-2034), where these uncertainties are reduced.
The results suggest that the adopted standards are likely to have a
negligible impact on the net demand for labor in the economy. The net
change in jobs is so small that it would be imperceptible in national
labor statistics and might be offset by other, unanticipated effects on
employment. Chapter 16 of the final rule TSD presents detailed results
regarding anticipated indirect employment impacts.
4. Impact on Utility or Performance of Products
As discussed in section IV.C.1.b of this document, DOE has
concluded that the standards adopted in this final rule will not lessen
the utility or performance of the distribution transformers under
consideration in this rulemaking. Manufacturers of these products
currently offer units that meet or exceed the adopted standards.
5. Impact of Any Lessening of Competition
DOE considered any lessening of competition that would be likely to
result from new or amended standards. As discussed in section III.F.1.e
of this document, EPCA directs the Attorney General of the United
States (``Attorney General'') to determine the impact, if any, of any
lessening of competition likely to result from a proposed standard and
to transmit such determination in writing to the Secretary within 60
days of the publication of a proposed rule, together with an analysis
of the nature and extent of the impact. To assist the Attorney General
in making this determination, DOE provided the Department of Justice
(DOJ) with copies of the NOPR and the TSD for review. In its assessment
letter responding to DOE, DOJ concluded that the proposed energy
conservation standards for distribution transformers are unlikely to
have a significant adverse impact on competition. DOE is publishing the
Attorney General's assessment at the end of this final rule.
6. Need of the Nation to Conserve Energy
Enhanced energy efficiency, where economically justified, improves
the Nation's energy security, strengthens the economy, and reduces the
environmental impacts (costs) of energy production. Reduced electricity
demand due to energy conservation standards is also likely to reduce
the cost of maintaining the reliability of the electricity system,
particularly during peak-load periods. Chapter 15 in the final rule TSD
presents the estimated impacts on electricity generating capacity,
relative to the no-new-standards case, for the TSLs that DOE considered
in this rulemaking.
Energy conservation resulting from potential energy conservation
standards for distribution transformers is expected to yield
environmental benefits in the form of reduced emissions of certain air
pollutants and greenhouse gases. Table V.45 through Table V.48 provides
DOE's estimate of cumulative emissions reductions expected to result
from the TSLs considered in this rulemaking. The emissions were
calculated using the multipliers discussed in section IV.K of this
document. DOE reports annual emissions reductions for each TSL in
chapter 13 of the final rule TSD.
[[Page 29999]]
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[GRAPHIC] [TIFF OMITTED] TR22AP24.608
[[Page 30000]]
[GRAPHIC] [TIFF OMITTED] TR22AP24.609
[GRAPHIC] [TIFF OMITTED] TR22AP24.610
As part of the analysis for this rule, DOE estimated monetary
benefits likely to result from the reduced emissions of CO2
that DOE estimated for each of the considered TSLs for distribution
transformers. Section IV.L.1.a of this
[[Page 30001]]
document discusses the estimated SC-CO2 values that DOE
used. Table V.49 presents the value of CO2 emissions
reduction at each TSL for each of the SC-CO2 cases. The
time-series of annual values is presented for the selected TSL in
chapter 14 of the final rule TSD.
[GRAPHIC] [TIFF OMITTED] TR22AP24.611
As discussed in section IV.L.2 of this document, DOE estimated the
climate benefits likely to result from the reduced emissions of methane
and N2O that DOE estimated for each of the considered TSLs
for distribution transformers. Table V.50 presents the value of the
CH4 emissions reduction at each TSL, and Table V.51 presents
the value of the N2O emissions reduction at each TSL. The
time-series of annual values is presented for the selected TSL in
chapter 14 of the final rule TSD.
[[Page 30002]]
[GRAPHIC] [TIFF OMITTED] TR22AP24.612
[GRAPHIC] [TIFF OMITTED] TR22AP24.613
DOE is well aware that scientific and economic knowledge about the
contribution of CO2 and other GHG emissions to changes in
the future global climate and the potential resulting damages to the
global and U.S. economy continues to evolve rapidly. DOE, together with
other Federal agencies, will continue to review methodologies for
estimating the monetary value of reductions in CO2 and other
GHG emissions. This ongoing review will consider the comments on this
subject that are part of the public record for this and other
rulemakings, as well as other methodological assumptions and issues.
DOE notes, however, that the adopted standards would be economically
justified even without inclusion of monetized benefits of reduced GHG
emissions.
DOE also estimated the monetary value of the economic benefits
associated with NOX and SO2 emissions reductions
anticipated to result from the considered TSLs for distribution
transformers. The dollar-per-ton values that DOE used are discussed in
section IV.L of this document. Table V.52 presents the present value
for NOX emissions reduction for each TSL calculated using 7-
percent and 3-percent discount rates, and Table V.53 presents similar
results for SO2 emissions reductions. The results in these
tables reflect application of EPA's low dollar-per-ton values, which
DOE used to be conservative. The time-series of annual values is
presented for the selected TSL in chapter 14 of the final rule TSD.
[[Page 30003]]
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[GRAPHIC] [TIFF OMITTED] TR22AP24.615
[[Page 30004]]
[GRAPHIC] [TIFF OMITTED] TR22AP24.616
[GRAPHIC] [TIFF OMITTED] TR22AP24.617
[[Page 30005]]
Not all the public health and environmental benefits from the
reduction of greenhouse gases, NOX, and SO2 are
captured in the values above, and additional unquantified benefits from
the reductions of those pollutants as well as from the reduction of
direct PM and other co-pollutants may be significant. DOE has not
included monetary benefits of the reduction of Hg emissions because the
amount of reduction is very small.
7. Other Factors
The Secretary of Energy, in determining whether a standard is
economically justified, may consider any other factors that the
Secretary deems to be relevant. (42 U.S.C. 6295(o)(2)(B)(i)(VII)) In
this final rule, DOE considered the near-term impact of amended
standards on existing distribution transformer shortages, on the
domestic electrical steel supply, and on projected changes to the
transformer market to support electrification.
8. Summary of Economic Impacts
Table V.54 presents the NPV values that result from adding the
estimates of the economic benefits resulting from reduced GHG and
NOX and SO2 emissions to the NPV of consumer
benefits calculated for each TSL considered in this rulemaking. The
consumer benefits are domestic U.S. monetary savings that occur as a
result of purchasing the covered equipment and are measured for the
lifetime of products shipped during the period 2029-2058. The climate
benefits associated with reduced GHG emissions resulting from the
adopted standards are global benefits and are also calculated based on
the lifetime of distribution transformers shipped during the period
2029-2058.
[GRAPHIC] [TIFF OMITTED] TR22AP24.618
[[Page 30006]]
C. Conclusion
When considering new or amended energy conservation standards, the
standards that DOE adopts for any type (or class) of covered equipment
must be designed to achieve the maximum improvement in energy
efficiency that the Secretary determines is technologically feasible
and economically justified. (42 U.S.C. 6316(a); 42 U.S.C.
6295(o)(2)(A)) In determining whether a standard is economically
justified, the Secretary must determine whether the benefits of the
standard exceed its burdens by, to the greatest extent practicable,
considering the seven statutory factors discussed previously. (42
U.S.C. 6316(a); 42 U.S.C. 6295(o)(2)(B)(i)) The new or amended standard
must also result in significant conservation of energy. (42 U.S.C.
6316(a); 42 U.S.C. 6295(o)(3)(B))
For this final rule, DOE considered the impacts of amended
standards for distribution transformers at each TSL, beginning with the
maximum technologically feasible level, to determine whether that level
was economically justified. Where the max-tech level was not justified,
DOE then considered the next most efficient level and undertook the
same evaluation until it reached the highest efficiency level that is
both technologically feasible and economically justified and saves a
significant amount of energy.
To aid the reader as DOE discusses the benefits and/or burdens of
each TSL, tables in this section present a summary of the results of
DOE's quantitative analysis for each TSL. In addition to the
quantitative results presented in the tables, DOE also considers other
burdens and benefits that affect economic justification. These include
the impacts on identifiable subgroups of consumers who may be
disproportionately affected by a national standard and impacts on
employment.
DOE also notes that the economics literature provides a wide-
ranging discussion of how consumers trade off upfront costs and energy
savings in the absence of government intervention. Much of this
literature attempts to explain why consumers appear to undervalue
energy efficiency improvements. There is evidence that consumers
undervalue future energy savings as a result of: (1) a lack of
information; (2) a lack of sufficient salience of the long-term or
aggregate benefits; (3) a lack of sufficient savings to warrant
delaying or altering purchases; (4) excessive focus on the short term,
in the form of inconsistent weighting of future energy cost savings
relative to available returns on other investments; (5) computational
or other difficulties associated with the evaluation of relevant
tradeoffs; and (6) a divergence in incentives (for example, between
renters and owners, or builders and purchasers). Having less than
perfect foresight and a high degree of uncertainty about the future,
consumers may trade off these varieties of investments at a higher-
than-expected rate between current consumption and uncertain future
energy cost savings.
1. Benefits and Burdens of TSLs Considered for Liquid-Immersed
Distribution Transformer Standards
Table V.55 and Table V.56 summarize the quantitative impacts
estimated for each TSL for liquid-immersed distribution transformers.
The national impacts are measured over the lifetime of distribution
transformers purchased in the 30-year period that begins in the
anticipated year of compliance with amended standards (2029-2058). The
energy savings, emissions reductions, and value of emissions reductions
refer to full-fuel-cycle results. DOE is presenting monetized benefits
of GHG emissions reductions in accordance with the applicable Executive
Orders, and DOE would reach the same conclusion presented in this
notice in the absence of the social cost of greenhouse gases, including
the Interim Estimates presented by the Interagency Working Group. The
efficiency levels contained in each TSL are described in section V.A of
this document.
[[Page 30007]]
[GRAPHIC] [TIFF OMITTED] TR22AP24.619
[[Page 30008]]
[GRAPHIC] [TIFF OMITTED] TR22AP24.620
DOE first considered TSL 5, which represents the max-tech
efficiency levels across all product classes of liquid-immersed
distribution transformers essentially requiring the shift to the most-
efficient electrical steel for core fabrication and larger and heavier
distribution transformers as more material is needed to support the
efficiency gains. TSL 5 would save an estimated 10.91 quads of energy,
an amount DOE considers significant. Under TSL 5, the NPV of consumer
benefit would be -$7.39 billion using a discount rate of 7 percent, and
-$3.57 billion using a discount rate of 3 percent.
The cumulative emissions reductions at TSL 5 are 204.96 Mt of
CO2, 49.0 thousand tons of SO2, 358.5 thousand
tons of NOX, 0.3 tons of Hg, 1,660.6 thousand tons of
CH4, and 1.6 thousand tons of N2O. The estimated
monetary value of the climate benefits from reduced GHG emissions
(associated with the average SC-GHG at a 3-percent discount rate) at
TSL 5 is $7.37 billion. The estimated monetary value of the health
benefits from reduced SO2 and NOX emissions at
TSL 5 is $4.42 billion using a 7-percent discount rate and $14.81
billion using a 3-percent discount rate.
Using a 7-percent discount rate for consumer benefits and costs,
health benefits from reduced SO2 and NOX
emissions, and the 3-percent discount rate case for climate benefits
from reduced GHG emissions, the estimated total NPV at TSL 5 is $4.40
billion. Using a 3-percent discount rate for all benefits and costs,
the estimated total NPV at TSL 5 is $18.61 billion. The estimated total
NPV is provided for additional information, however DOE primarily
relies upon the NPV of consumer benefits when determining whether a
standard level is economically justified.
At TSL 5, the average LCC impact ranges from -$2,977 for equipment
class 2B to $770 for equipment class 12. The median PBP ranges from
14.8 years for equipment class 12 to 42.1 years for equipment class 1A.
The fraction of consumers experiencing a net LCC cost ranges from 28.7
percent for equipment class 2A to 89.0 percent for equipment class 1A.
At TSL 5, the projected change in INPV ranges from a decrease of
$686 million to a decrease of $338 million, which corresponds to
decreases of 38.3 percent and 18.8 percent, respectively. This decrease
is primarily driven by the investments needed to move the entire
liquid-immersed distribution transformer market to the most-efficient
designs, including converting their production facilities to produce
and accommodate amorphous core technology. DOE estimates that industry
must invest $697 million to comply with standards set at TSL 5.
The Secretary concludes that at TSL 5 for liquid-immersed
distribution transformers, the benefits of energy savings, emission
reductions, and the estimated monetary value of the emissions
reductions would be outweighed by the economic burden on many consumers
as indicated by lengthy PBPs, the percentage of customers who would
experience LCC increases, negative consumer NPV at both 3- and 7-
percent discount rates,
[[Page 30009]]
and the capital and engineering costs that would result in a reduction
in INPV for manufacturers. At TSL 5, the LCC savings are negative for
most liquid-immersed distribution transformers, indicating there is a
substantial risk that a disproportionate number of consumers will incur
increased costs; these costs are also reflected in simple PBP estimates
that approach average transformer lifetimes for some equipment. NPVs
are calculated for equipment shipped over the period of 2029 through
2058 (see section IV.H.3 of this document). Distribution transformers
are durable equipment with a maximum lifetime estimated at 60 years
(see section IV.F.8), accruing operating cost savings through 2117.
When considered over this time period, the discounted value of the
incremental equipment costs outweighs the discounted value of the
operating costs savings. Incremental equipment costs are incurred in
the first year of equipment life, while operating cost savings occur
throughout the equipment lifetime, with later years heavily discounted.
Further, there is risk of greater reduction in INPV at max-tech if
manufacturers maintain their operating profit in the presence of
amended efficiency standards on account of having higher costs but
similar profits. The benefits of max-tech efficiency levels for liquid-
immersed distribution transformers do not outweigh the negative impacts
to consumers and manufacturers. Consequently, the Secretary has
concluded that TSL 5 is not economically justified.
Next, DOE considered TSL 4, a level at which DOE estimates a likely
shift in the electrical steel used for distribution transformer cores
for liquid-immersed distribution transformers. TSL 4 would save an
estimated 10.67 quads of energy, an amount DOE considers significant.
Under TSL 4, the NPV of consumer benefit would be $2.82 billion using a
discount rate of 7 percent, and $13.01 billion using a discount rate of
3 percent.
The cumulative emissions reductions at TSL 4 are 201.15 Mt of
CO2, 48.0 thousand tons of SO2, 350.8 thousand
tons of NOX, 0.3 tons of Hg, 1,624.0 thousand tons of
CH4, and 1.5 thousand tons of N2O. The estimated
monetary value of the climate benefits from reduced GHG emissions
(associated with the average SC-GHG at a 3-percent discount rate) at
TSL 4 is $7.23 billion. The estimated monetary value of the health
benefits from reduced SO2 and NOX emissions at
TSL 4 is $4.33 billion using a 7-percent discount rate and $14.50
billion using a 3-percent discount rate.
Using a 7-percent discount rate for consumer benefits and costs,
health benefits from reduced SO2 and NOX
emissions, and the 3-percent discount rate case for climate benefits
from reduced GHG emissions, the estimated total NPV at TSL 4 is $14.38
billion. Using a 3-percent discount rate for all benefits and costs,
the estimated total NPV at TSL 4 is $34.74 billion. The estimated total
NPV is provided for additional information, however DOE primarily
relies upon the NPV of consumer benefits when determining whether a
standard level is economically justified.
At TSL 4, the average LCC impact ranges from $317 for equipment
class 1B to $5,301 for equipment class 2B. The median PBP ranges from
7.4 years for equipment class 1B to 10.7 years for equipment class 1A.
The fraction of consumers experiencing a net LCC cost ranges from
7.1percent for equipment classes 1B and 2A to 27.5 percent for
equipment class 1A.
At TSL 4, the projected change in INPV ranges from a decrease of
$476 million to a decrease of $388 million, which corresponds to
decreases of 26.6 percent and 21.6 percent, respectively. These
estimates are driven by DOE's estimate that liquid-immersed
distribution transformer manufacturers will need to invest $587 million
to comply with standards set at TSL 4 to produce or accommodate
amorphous core technology.
The energy savings under TSL 4 are primarily achievable by using
amorphous cores and DOE believes manufacturers will likely choose this
technology pathway in order to meet TSL 4 efficiency levels due to the
relative cost of meeting these levels with amorphous and GOES cores. In
the present market, distribution transformers are primarily designed
using GOES cores and the production equipment used for GOES core
distribution transformer manufacturing is not the same. While DOE
understands that amorphous core distribution transformers are
technically feasible for liquid-immersed, DOE also understands that
current domestic supply would need to ramp up significantly for
amorphous steel to support this market.
The transition to amorphous cores is constrained in two important
ways. First, amorphous cores require amorphous steel. Supply of
amorphous steel for transformer cores is not inherently constrained.
Supply, including domestic supply, could increase in the face of
increased demand.
For example, both global and domestic annual production capacity of
amorphous ribbon is greater now than it was leading up to the April
2013 Standards Final Rule, with global annual production capacity of
amorphous ribbon (estimated to be approximately 150,000-250,000 metric
tons) approximately equal to the U.S. annual demand for core steel in
distribution transformer applications (estimated to be approximately
225,000 metric tons). While additional amorphous ribbon capacity would
be required to serve the entirety of the U.S. distribution transformer
market, in addition to existing global applications, it is likely that
supply would increase quickly in response to increased demand from
standards. Following the April 2013 Standards Final Rule, amorphous
ribbon capacity grew, although amorphous ribbon demand did not grow in-
kind. As such, excess amorphous ribbon capacity already exists that
could be utilized to serve a larger portion of the distribution
transformer market, if demand were to increase. Further, the response
of amorphous ribbon manufacturers following the April 2013 Standards
Final Rule, as well as public announcements of development in amorphous
core production capacity since the January 2023 NOPR, demonstrate that
amorphous ribbon and core capacity can be added quickly if suppliers
anticipate demand. As such, the supply of amorphous metal would likely
increase in response to amended standards that favored amorphous ribbon
as the optimal design option. Stakeholders have expressed a willingness
to increase supply to match any potential demand created by an amended
efficiency standard. As noted, in the current market, sales of
amorphous ribbon are limited by demand for amorphous cores rather than
any constraints on production capacity. Therefore, in the presence of
an amended standard, it is expected that amorphous ribbon capacity
would quickly rise to meet demand before the effective date of any
amended energy conservation standards.
However, and secondly, demand for amorphous steel is constrained by
distribution transformer manufacturers' willingness and ability to
invest in in the capital equipment required to produce and process
amorphous metal cores. The production pathway for both amorphous core
and GOES core transformers is similar once this investment in the
equipment has been made. However, the transition from production of
GOES cores to production of amorphous cores would require significant
investment by distribution
[[Page 30010]]
transformer manufacturers that produce their own cores. At TSL 4, most
existing core production equipment, which is predominantly set up to
produce GOES cores, would need to be replaced with amorphous core
production equipment. Given existing supply challenges and long lead
times for distribution transformers, it is unclear if most
manufacturers would have the capacity to complete the necessary
investments in amorphous core production equipment within the 5-year
compliance period and maintain their existing GOES production lines to
supply the current market demand without increasing near-term
distribution transformer lead times. If manufacturers anticipate
requiring more than 5 years to fully convert production or add
production of amorphous cores, they may prioritize maintaining lead
times by continuing to produce transformers with GOES cores. If GOES
cores are used to meet TSL 4, the resulting designs are substantially
larger and more expensive than amorphous core designs, with some size
capacities in DOE's modelling unable to meet TSL 4 at all with GOES.
Conversely, if manufacturers prioritize a transition to amorphous cores
over maintaining lead times, they may prioritize investing in replacing
existing production equipment, rather than in new additive capacity.
This could inhibit manufacturers' abilities to invest in necessary
capacity upgrades to help resolve the existing transformer shortages.
In addition to the production equipment and investments needed to
support a TSL 4 transition by distribution transformers, DOE
understands that the current workforce supporting the distribution
transformer manufacturer is also limited in their experience with
amorphous core production. DOE understands from the many stakeholder
comments that current workforce challenges within the distribution
transformer industry may be exacerbated in the short-term if a full
transition to TSL 4 is required. While DOE understands most
manufacturers currently can produce liquid-immersed transformers at TSL
4 efficiencies, DOE also understand that due to the lower volume of
amorphous cores in the market today many production facilities
outsource amorphous core production but produce GOES cores in-house.
DOE believes that if TSL 4 efficiencies were required for liquid-
immersed distribution transformers the sourcing decisions on core
fabrication would not largely change from what they are today as these
are inherent business decisions that balance quality, control, and
lead-times. Therefore, despite offering liquid-immersed transformers at
TSL 4 efficiencies, manufacturers do not yet have a lot of experience
fabricating amorphous cores and will take significant training and time
in order to support a transition of this magnitude. Some manufacturers
raised questions in comments about their ability to invest in both the
capital as well as the workforce in the time provided to transition to
TSL 4, while maintaining their supply needs for GOES transformers in
the near-term.
DOE notes that while the January 2023 NOPR proposed standards at
TSL 4, distribution transformer shortages persisted throughout 2023.
DOE further notes that hundreds of millions of dollars in investments
have been announced by distribution transformer manufacturers to add
capacity to resolve the existing transformer shortages and those
investments are currently undergoing the design, permitting,
engineering, and construction process needed to begin production with
scheduled completions typically targeting 24 to 36 months. DOE updated
its analysis of conversion costs in this final rule based on
stakeholder feedback and are the costs are now greater than the costs
analyzed in the January 2023 NOPR. Investing in conversion costs and
workforce training, in addition to manufacturers investments to
increase capacity, without offering flexibility for manufacturers to
add amorphous capacity in an additive manner has led DOE to conclude
that TSL 4 offers substantial risk that could extend current
transformer shortages longer they otherwise would be.
The Secretary concludes that at TSL 4 for liquid-immersed
distribution transformers, the benefits of energy savings, emission
reductions, and the estimated monetary value of the emissions
reductions would be outweighed by the significant impact to
manufacturers (a loss in INPV of up to 26.6 percent, conversion costs
of approximately $587 million, and a free cash flow of -$125 million in
the year leading up to the compliance year) and the risks that
manufacturers would not be able to scale up amorphous core production
capacity within the compliance period without significantly increasing
distribution transformer lead times or maintaining very large and
costly GOES core transformers after the compliance period. In addition,
DOE has concerns about distribution transformer manufacturer's ability
to maintain their existing GOES lines in the near-term, while training
their workforce to become comfortable with producing transformers cores
with amorphous ribbon. Further, as discussed in section IV.C.2.a, an
inability of suppliers of amorphous ribbon to scale production and
manufacturers to retool production lines for amorphous cores within the
compliance period could lead to market uncertainty and disruption
during a critical time. Several stakeholders have noted that given
existing supply challenges, a total conversion to amorphous is not
feasible in the near term. While this final rule considers a longer
compliance period, the impacts of shortages are substantial, which may
have an impact on grid reliability. Therefore, the risks of scale-up
and compliance taking slightly longer, due to any number of unforeseen
challenges, could have substantial impacts. The benefits of TSL 4 for
liquid-immersed distribution transformer do not outweigh the risks when
considering the potential impacts to the broader distribution
transformer supply chain. Consequently, the Secretary has concluded
that TSL 4 is not economically justified.
Next, DOE considered TSL 3. TSL 3 would save an estimated 2.73
quads of energy, an amount DOE considers significant. Under TSL 3, the
NPV of consumer benefit would be $0.56 billion using a discount rate of
7 percent, and $3.41 billion using a discount rate of 3 percent.
The cumulative emissions reductions at TSL 3 are 51.40 Mt of
CO2, 12.3 thousand tons of SO2, 89.9 thousand
tons of NOX, 0.1 tons of Hg, 416.2 thousand tons of
CH4, and 0.4 thousand tons of N2O. The estimated
monetary value of the climate benefits from reduced GHG emissions
(associated with the average SC-GHG at a 3-percent discount rate) at
TSL 3 is $1.85 billion. The estimated monetary value of the health
benefits from reduced SO2 and NOX emissions at
TSL 3 is $1.11 billion using a 7-percent discount rate and $3.71
billion using a 3-percent discount rate.
Using a 7-percent discount rate for consumer benefits and costs,
health benefits from reduced SO2 and NOX
emissions, and the 3-percent discount rate case for climate benefits
from reduced GHG emissions, the estimated total NPV at TSL 3 is $3.52
billion. Using a 3-percent discount rate for all benefits and costs,
the estimated total NPV at TSL 3 is $9.97 billion. The estimated total
NPV is provided for additional information, however DOE primarily
relies upon the NPV of consumer benefits when determining whether a
standard level is economically justified.
[[Page 30011]]
At TSL 3, the average LCC impact ranges from $48 for equipment
class 1B to $851 for equipment class 2A. The median PBP ranges from 9.2
years for equipment class 2A to 19.5 years for equipment class 1B. The
fraction of consumers experiencing a net LCC cost ranges from 7.1
percent for equipment class 2A to 39.6 percent for equipment class 2B.
At TSL 3, the projected change in INPV ranges from a decrease of
$145 million to a decrease of $111 million, which corresponds to
decreases of 8.1 percent and 6.2 percent, respectively. DOE estimates
that industry must invest $187 million to comply with standards set at
TSL 3.
After considering the analysis and weighing the benefits and
burdens, the Secretary has concluded that a standard set at TSL 3 for
liquid-immersed distribution transformers would be economically
justified. Notably, the benefits to consumers outweigh the cost to
manufacturers. At TSL 3, the average LCC savings are positive across
all equipment classes. An estimated 29 percent of liquid-immersed
distribution transformer consumers experience a net cost. DOE notes
that if the shipments equipment classes 1B and 2B transition to
amorphous cores from DOE's assumed rate of 3 percent to 10, or 25
percent, the maximum number of consumers experiencing a net cost
decreases to 25 and 21 percent, respectively.\198\ The FFC national
energy savings are significant and the NPV of consumer benefits is
positive using both a 3-percent and 7-percent discount rate when
considered for all liquid-immersed distribution transformers subject to
amended standards. When examined as individual equipment classes the
NPV at 7 percent is positive for most equipment classes; with the
exception of equipment class 2B, where the NPV at a 7 percent discount
rate is negative: -$0.05 billion (see Table V.43). When equipment class
2B is considered with the addition of its associated health benefits of
$0.22 billion at TSL 3 (see Table V.51 and Table V.52) the impacts
become positive, with a net benefit of $0.17 billion. At TSL 3, the NPV
of consumer benefits, even measured at the more conservative discount
rate of 7 percent is larger than the maximum estimated manufacturers'
loss in INPV. The standard levels at TSL 3 are economically justified
even without weighing the estimated monetary value of emissions
reductions. When those emissions reductions are included--representing
$1.85 billion in climate benefits (associated with the average SC-GHG
at a 3-percent discount rate), and $3.71 billion (using a 3-percent
discount rate) or $1.11 billion (using a 7-percent discount rate) in
health benefits--the rationale becomes stronger still.
---------------------------------------------------------------------------
\198\ See: Appendix 8D of the final rule TSD for DOE's scenario
examining the impacts resulting from increased amorphous adoption.
---------------------------------------------------------------------------
Notably, the standards under TSL 3 would not pose the same near-
term risks to distribution transformer availability. As compared to TSL
4, for which the energy savings are primarily achievable via amorphous
cores, the energy savings under TSL 3 are achieved by using a mix of
amorphous cores and GOES cores. Under TSL 3, DOE estimates that
equipment class 1A and 2A will meet efficiency standards by
transitioning to amorphous cores. If the unit sizes represented by
these equipment classes shift entirely to amorphous, DOE estimates that
approximately 48,000 metric tons of amorphous ribbon would be consumed,
which is approximately equal to the current domestic amorphous ribbon
production capacity (45,000 metric tons of domestic amorphous today).
Under TSL 3, DOE estimates that the vast majority of liquid-immersed
distribution transformers shipments (89 percent of units) could be met
with GOES cores.
As noted, the transition from GOES cores to amorphous cores
requires significant investment on the part of distribution transformer
manufacturers that produce their own cores. However, core production
equipment is somewhat flexible in that a given piece of equipment can
produce a range of core sizes corresponding to a range of transformer
kVA sizes. Given existing supply challenges facing the distribution
transformer market, DOE assumes that manufacturers would prioritize
maintaining lead times by continuing to produce transformers with GOES
cores for transformer sizes where costs are approximately equal, even
if a transformer with an amorphous core may be slightly less expensive
to produce. Under TSL 3, DOE evaluated a higher efficiency level for
Equipment Class 1A and 2A and a lower efficiency level for Equipment
Class 1B and 2B. As such, manufacturers would have significant
flexibility to invest in new capacity to meet efficiency standards
while allowing for the continued use of current production equipment to
ensure a robust short- to medium-term supply of distribution
transformers.
TSL 3 results in positive LCCs for all equipment classes, whether
expected to remain predominantly GOES-based (Equipment Class 1B and 2B)
or predominantly amorphous-based (Equipment Class 1A and 2A).
Because only a portion of the market is expected to transition to
amorphous at TSL 3 and because existing GOES production equipment can
produce a variety of kVA sizes, manufacturers may invest in amorphous
production equipment as additive capacity to serve those portions of
the market where amorphous is most competitive. As such, manufacturers
would have the flexibility of using existing GOES production equipment
to serve the rest of the market, while adding additional amorphous
production equipment that may help resolve the existing transformer
shortages. Public statements from major liquid-immersed distribution
transformer core manufacturers suggest that some have already begun
investing in additive amorphous capacity in response to the January
2023 NOPR.199 200 201
---------------------------------------------------------------------------
\199\ Yahoo Finance, Howard Industries cuts ribbon on Quitman
plant, November 3, 2023, Available online at: https://finance.yahoo.com/news/howard-industries-cuts-ribbon-quitman-035900515.html.
\200\ JFE Shoji Power, ``What Got Us Here Won't Get Us to Where
We Want to Go'', You Will Be an Embarrassment to the Company, Nov.
2023. https://www.amazon.in/What-Here-Wont-Where-Want/dp/B0CMD84HRW.
\201\ Worthington Steel, Investor Day, Oct. 2023, Transcript.
Available online at: worthington-steel-investor-day-transcript-
final-10-11-23.pdf (worthingtonenterprises.com.)
---------------------------------------------------------------------------
Amorphous cores are expected to be the most cost-effective option
for meeting efficiency levels for equipment class 1A and 2A. This
suggests a future demand for amorphous ribbon and encourages both
existing amorphous producers to increase supply and potential new
producers to enter the market.
DOE expects manufacturers would prioritize amorphous core capital
investments at the kVA ranges (i.e., equipment class 1A and 2A), where
amorphous cores are expected to be most cost competitive. However, if
excess amorphous ribbon and amorphous core capacity exists, amorphous
is also a cost-effective option for many of the other kVA ratings.
While DOE has modeled equipment class 1B and 2B as meeting amended
standards using exclusively GOES in its base analysis at TSL 3, DOE has
included additional sensitivities in which amorphous core usage
increases to a maximum of 25 percent at equipment class 1B and 2B.
These scenarios further increase consumer benefits (see appendix 8G of
the TSD).
DOE expects manufacturers would maintain some amount of GOES core
production equipment and some amount of amorphous core production
[[Page 30012]]
equipment, thereby ensuring the U.S. distribution transformer market
continues to be served by at least two domestic electrical steel
providers, one producing GOES and one producing amorphous. This may
support balanced supply chain for distribution transformers through a
more diversified core steel supply, which is presently served
predominantly by GOES production for which there is only one domestic
supplier.
As stated, DOE conducts the walk-down analysis to determine the TSL
that represents the maximum improvement in energy efficiency that is
technologically feasible and economically justified as required under
EPCA. The walk-down is not a comparative analysis, as a comparative
analysis would result in the maximization of net benefits instead of
energy savings that are technologically feasible and economically
justified, which would be contrary to the statute. 86 FR 70892, 70908.
Although DOE has not conducted a comparative analysis to select the
new energy conservation standards, DOE notes that TSL 3 ensures
capacity for amorphous ribbon increases, on account of anticipated
future demand, while leaving a considerable portion of the market at
efficiency levels wherein GOES would remain cost competitive. As a
result, this ensures that near-term shortages can be resolved and that
overall U.S. electrification trends and support for domestic electrical
steel industries are not compromised. As noted by numerous
stakeholders, distribution transformers are crucial to supporting U.S.
infrastructure, grid resiliency, and electrification goals. TSL 3
allows for efficiency standards to be met by additive capacity, which
can help renormalize distribution transformer lead times. TSL 4 and TSL
5 did not include the same possibility for stakeholders to invest in an
additive capacity to meet efficiency standards, thereby creating risks
to the short- and medium-term supply of distribution transformers.
Although DOE considered amended standard levels for distribution
transformers by grouping the efficiency levels for each equipment
category into TSLs, DOE evaluates all analyzed efficiency levels in its
analysis. The TSLs constructed by DOE to examine the impacts of amended
energy efficiency standards for liquid-immersed distribution
transformers align with the corresponding ELs defined in the
engineering analysis, which the exception of TSL 3 which seeks to
consider electrical steel capacity and demand growth limitations. For
the ELs above baseline that compose TSL 3, DOE finds that LCC savings
are positive for all equipment classes, with simple paybacks well below
the average equipment lifetimes. DOE also finds that the estimated
fraction of consumers who would be negatively impacted from a standard
at TSL 3 to be 29.2 percent for all equipment classes. Importantly, DOE
expects TSL 3 to be achievable with additive distribution transformer
capacity in addition to capital conversion costs, thereby reducing both
transformer and larger grid supply concerns.
Therefore, based on the previous considerations, DOE adopts the
energy conservation standards for liquid-immersed distribution
transformers at TSL 3. The amended energy conservation standards for
distribution transformers, which are expressed as percentage efficiency
at 50 percent PUL, are shown in Table V.57.
[GRAPHIC] [TIFF OMITTED] TR22AP24.621
2. Benefits and Burdens of TSLs Considered for Low-Voltage Dry-Type
Distribution Transformer Standards
Table V.58 and Table V.59 summarize the quantitative impacts
estimated for each TSL for low-voltage dry-type distribution
transformers. The national impacts are measured over the lifetime of
distribution transformers purchased in the 30-year period that begins
in the anticipated year of compliance with amended standards (2029-
2058). The energy savings, emissions reductions, and value of emissions
reductions refer to full-fuel-cycle results. DOE is presenting
monetized benefits of GHG emissions reductions in accordance with the
applicable Executive Orders, and DOE would reach the same conclusion
presented in this notice in
[[Page 30013]]
the absence of the social cost of greenhouse gases, including the
Interim Estimates presented by the Interagency Working Group. The
efficiency levels contained in each TSL are described in section V.A of
this document.
[GRAPHIC] [TIFF OMITTED] TR22AP24.622
[[Page 30014]]
[GRAPHIC] [TIFF OMITTED] TR22AP24.623
DOE first considered TSL 5, which represents the max-tech
efficiency levels. TSL 5 would save an estimated 2.53 quads of energy,
an amount DOE considers significant. Under TSL 5, the NPV of consumer
benefit would be $3.00 billion using a discount rate of 7 percent, and
$9.86 billion using a discount rate of 3 percent.
The cumulative emissions reductions at TSL 5 are 46.20 Mt of
CO2, 11.1 thousand tons of SO2, 82.7 thousand
tons of NOX, 0.1 tons of Hg, 384.4 thousand tons of
CH4, and 0.4 thousand tons of N2O. The estimated
monetary value of the climate benefits from reduced GHG emissions
(associated with the average SC-GHG at a 3-percent discount rate) at
TSL 5 is $1.81 billion. The estimated monetary value of the health
benefits from reduced SO2 and NOX emissions at
TSL 5 is $1.12 billion using a 7-percent discount rate and $3.58
billion using a 3-percent discount rate.
Using a 7-percent discount rate for consumer benefits and costs,
health benefits from reduced SO2 and NOX
emissions, and the 3-percent discount rate case for climate benefits
from reduced GHG emissions, the estimated total NPV at TSL 5 is $5.93
billion. Using a 3-percent discount rate for all benefits and costs,
the estimated total NPV at TSL 5 is $15.25 billion. The estimated total
NPV is provided for additional information, however DOE primarily
relies upon the NPV of consumer benefits when determining whether a
proposed standard level is economically justified.
At TSL 5, the average LCC impact ranges from $517 for equipment
class 3 to $1,044 for equipment class 4. The median PBP ranges from 4.8
years for equipment class 4 to 8.9 years for equipment class 3. The
fraction of consumers experiencing a net LCC cost ranges from 3 percent
for equipment class 4 to 18 percent for equipment class 3.
At TSL 5, the projected change in INPV ranges from a decrease of
$68.4 million to a decrease of $54.0 million, which corresponds to
decreases of 32.3 percent and 25.5 percent, respectively. DOE estimates
that industry must invest $91.8 million to comply with standards set at
TSL 5.
The energy savings under TSL 5 are primarily achievable by using
amorphous cores. The transition from GOES cores to amorphous cores
requires significant investment on the part of the distribution
transformer manufacturer if they produce their own cores. At TSL 5,
most existing core production equipment would need to be replaced with
amorphous core production equipment. Most LVDT manufacturers have
little or no experience producing transformer designs with amorphous
cores and little experience as to potential modifications that may need
to be made to new protective equipment. Further, LVDT manufacturers
tend to have considerably lower transformer core volumes than liquid-
immersed manufacturers. As such, electrical steel manufacturers tend to
prioritize service to liquid-immersed manufacturers over dry-type
distribution transformer manufacturers. This creates a risk that, given
the quantity of amorphous ribbon expected to be used within the liquid-
immersed distribution transformer market, there may be considerable
competition for amorphous ribbon that may hamper LVDT manufacturers'
ability to develop experience with amorphous cores in the near-term,
which would lead to considerable
[[Page 30015]]
supply chain disruptions in the compliance year.
DOE notes that while the January 2023 NOPR proposed standards at
TSL 5, distribution transformer shortages have persisted throughout
2023. DOE further notes that hundreds of millions of dollars in
investments have been announced by distribution transformer
manufacturers to add capacity to resolve the existing transformer
shortages and those investments are currently undergoing the design,
permitting, engineering, and construction process needed to begin
production with scheduled completions typically targeting 24 to 36
months. DOE updated its analysis of conversion costs in this final rule
based on stakeholder feedback and are the costs are now greater than
the costs analyzed in the January 2023 NOPR. Investing in conversion
costs, in addition to manufacturers investments to increase capacity,
without offering flexibility for manufacturers to add amorphous
capacity in an additive manner has led DOE to conclude that TSL 5
offers substantial risk that could extend current transformer shortages
longer they otherwise would be.
The Secretary concludes that at TSL 5 for low-voltage dry-type
distribution transformers, the benefits of energy savings, emission
reductions, and the estimated monetary value of the emissions
reductions would be outweighed by the risks that manufacturers would
not be able to scale up amorphous core production within the compliance
period without significantly increasing distribution transformer lead
times. The benefits of TSL 5 for low-voltage dry-type distribution
transformers do not outweigh the risks of significant impacts to the
distribution transformer supply chain, particularly when considered in
conjunction with the expected demand for core materials in the liquid-
immersed distribution transformer market. Consequently, the Secretary
has concluded that TSL 5 is not economically justified.
Next, DOE considered TSL 4. TSL 4 would save an estimated 2.38
quads of energy, an amount DOE considers significant. Under TSL 4, the
NPV of consumer benefit would be $3.20 billion using a discount rate of
7 percent, and $10.14 billion using a discount rate of 3 percent.
The cumulative emissions reductions at TSL 4 are 43.56 Mt of
CO2, 10.4 thousand tons of SO2, 77.9 thousand
tons of NOX, 0.1 tons of Hg, 362.3 thousand tons of
CH4, and 0.3 thousand tons of N2O. The estimated
monetary value of the climate benefits from reduced GHG emissions
(associated with the average SC-GHG at a 3-percent discount rate) at
TSL 4 is $1.71 billion. The estimated monetary value of the health
benefits from reduced SO2 and NOX emissions at
TSL 4 is $1.06 billion using a 7-percent discount rate and $3.38
billion using a 3-percent discount rate.
Using a 7-percent discount rate for consumer benefits and costs,
health benefits from reduced SO2 and NOX
emissions, and the 3-percent discount rate case for climate benefits
from reduced GHG emissions, the estimated total NPV at TSL 4 is $5.97
billion. Using a 3-percent discount rate for all benefits and costs,
the estimated total NPV at TSL 4 is $15.23 billion. The estimated total
NPV is provided for additional information, however DOE primarily
relies upon the NPV of consumer benefits when determining whether a
proposed standard level is economically justified.
At TSL 4, the average LCC impact ranges from $551 for equipment
class 3 to $1,068 for equipment class 4. The median PBP ranges from 3.4
years for equipment class 4 to 7.4 years for equipment class 3. The
fraction of consumers experiencing a net LCC cost ranges from 2 percent
for equipment class 4 to 14 percent for equipment class 3.
At TSL 4, the projected change in INPV ranges from a decrease of
$62.9 million to a decrease of $52.2 million, which corresponds to
decreases of 29.7 percent and 24.7 percent, respectively. DOE estimates
that industry must invest $86.7 million to comply with standards set at
TSL 4.
The energy savings under TSL 4 are primarily achievable by using
amorphous cores. As noted, LVDT manufacturers have little or no
experience producing transformer designs with amorphous cores and
little experience as to potential modifications that may need to be
made to new protective equipment. DOE is concerned that given the large
quantity of amorphous ribbon expected to be used within the liquid-
immersed distribution transformer market, there may be considerable
competition for amorphous ribbon that may hamper LVDT manufacturers'
ability to develop experience with amorphous cores in the near-term,
which would lead to considerable supply chain disruptions in the
compliance year.
The Secretary concludes that at TSL 4 for low-voltage dry-type
distribution transformers, the benefits of energy savings, emission
reductions, and the estimated monetary value of the emissions
reductions would be outweighed by the risks that manufacturers would
not be able to scale up amorphous core production within the compliance
period without significantly increasing distribution transformer lead
times. Further, as discussed in section IV.C.2.a of this document, an
inability of suppliers of amorphous ribbon to scale production and
manufacturers to retool production lines for amorphous cores within the
compliance period could lead to market uncertainty and disruption
during a critical time. Several stakeholders have noted that given
existing supply challenges, a total conversion to amorphous is not
feasible in the near term. While this final rule considers a longer
compliance period, the impacts of shortages are substantial, which may
have an impact on grid reliability. Therefore, the risks of scale-up
and compliance taking slightly longer, due to any number of unforeseen
challenges, could have substantial impacts. The benefits of TSL 4 for
low-voltage dry-type distribution transformer do not outweigh the risks
of significant impacts to the distribution transformer supply chain,
particularly when considered in conjunction with the expected demand
for core materials in the liquid-immersed distribution transformer
market. Consequently, the Secretary has concluded that TSL 4 is not
economically justified.
Next, DOE considered TSL 3. TSL 3 would save an estimated 1.71
quads of energy, an amount DOE considers significant. Under TSL 3, the
NPV of consumer benefit would be $2.08 billion using a discount rate of
7 percent, and $6.68 billion using a discount rate of 3 percent.
The cumulative emissions reductions at TSL 3 are 31.28 Mt of
CO2, 7.5 thousand tons of SO2, 55.9 thousand tons
of NOX, 0.1 tons of Hg, 260.0 thousand tons of
CH4, and 0.2 thousand tons of N2O. The estimated
monetary value of the climate benefits from reduced GHG emissions
(associated with the average SC-GHG at a 3-percent discount rate) at
TSL 3 is $1.23 billion. The estimated monetary value of the health
benefits from reduced SO2 and NOX emissions at
TSL 3 is $0.76 billion using a 7-percent discount rate and $2.42
billion using a 3-percent discount rate.
Using a 7-percent discount rate for consumer benefits and costs,
health benefits from reduced SO2 and NOX
emissions, and the 3-percent discount rate case for climate benefits
from reduced GHG emissions, the estimated total NPV at TSL 3 is $4.07
billion. Using a 3-percent discount rate for all benefits and costs,
the estimated total NPV at TSL 3 is $10.33 billion. The
[[Page 30016]]
estimated total NPV is provided for additional information, however DOE
primarily relies upon the NPV of consumer benefits when determining
whether a standard level is economically justified.
At TSL 3, the average LCC impact ranges from $321 for equipment
class 3 to $765 for equipment class 4. The median PBP ranges from 3.6
years for equipment class 4 to 7.4 years for equipment class 3--well
below the estimated average lifetime of 32 years. The fraction of
consumers experiencing a net LCC cost ranges from 9 percent for
equipment class 4 to 28 percent for equipment class 3.
At TSL 3, the projected change in INPV ranges from a decrease of
$27.1 million to a decrease of $18.9 million, which corresponds to
decreases of 12.8 percent and 8.9 percent, respectively. DOE estimates
that industry must invest $36.1 million to comply with standards set at
TSL 3.
After considering the analysis and weighing the benefits and
burdens, the Secretary has concluded that a standard set at TSL 3 for
low-voltage dry-type distribution transformers would be economically
justified. Notably, the benefits to consumers outweigh the cost to
manufacturers. At this TSL, the average LCC savings are positive across
all equipment classes. An estimated 11 percent of low-voltage dry-type
distribution transformer consumers experience a net cost. The FFC
national energy savings are significant and the NPV of consumer
benefits is positive using both a 3-percent and 7-percent discount
rate. At TSL 3, the NPV of consumer benefits, even measured at the more
conservative discount rate of 7 percent, is larger than the maximum
estimated manufacturers' loss in INPV. The standard levels at TSL 3 are
economically justified even without weighing the estimated monetary
value of emissions reductions. When those emissions reductions are
included--representing $1.23 billion in climate benefits (associated
with the average SC-GHG at a 3-percent discount rate), and $2.42
billion (using a 3-percent discount rate) or $0.76 billion (using a 7-
percent discount rate) in health benefits--the rationale becomes
stronger still.
Notably, the energy savings under TSL 3 do not carry the same risks
to distribution transformer supply chains as TSL 4 and TSL 5. The
energy savings under TSL 3 are primarily achieved using lower-loss GOES
cores with some shipments using amorphous cores where it is most cost-
competitive. DOE notes that at TSL 3, both amorphous and GOES cores are
cost-competitive with regard to which core steel produces the lowest
first-cost unit, allowing manufacturers flexibility in establishing
supply chains and redesigning transformers to meet amended standards
based on their specific needs.
As stated, DOE conducts the walk-down analysis to determine the TSL
that represents the maximum improvement in energy efficiency that is
technologically feasible and economically justified as required under
EPCA. The walk-down is not a comparative analysis, as a comparative
analysis would result in the maximization of net benefits instead of
energy savings that are technologically feasible and economically
justified, which would be contrary to the statute. 86 FR 70892, 70908.
Although DOE has not conducted a comparative analysis to select the
new energy conservation standards, DOE notes that TSL 3 has
considerably lower manufacturer impacts than TSL 4 and TSL 5. Further,
TSL 3 allows both GOES and amorphous cores to compete, ensuring a
diverse supply of materials can serve the LVDT market.
Although DOE considered amended standard levels for distribution
transformers by grouping the efficiency levels for each equipment
category into TSLs, DOE evaluates all analyzed efficiency levels in its
analysis. The TSLs constructed by DOE to examine the impacts of amended
energy efficiency standards for low-voltage dry-type distribution
transformers align with the corresponding ELs defined in the
engineering analysis. For the ELs above baseline that compose TSL 3,
DOE finds that LCC savings are positive for all equipment classes, with
simple paybacks well below the average equipment lifetimes. DOE also
finds that the estimated fraction of consumers who would be negatively
impacted from a standard at TSL 3 to be 11 percent for all equipment
classes. Importantly, DOE expects TSL 3 to be achievable with both
amorphous and GOES core materials.
Therefore, based on the previous considerations, DOE adopts the
energy conservation standards for LVDT distribution transformers at TSL
3. The amended energy conservation standards for distribution
transformers, which are expressed as percentage efficiency at 35
percent PUL, are shown in Table V.60.
[GRAPHIC] [TIFF OMITTED] TR22AP24.624
[[Page 30017]]
3. Benefits and Burdens of TSLs Considered for Medium-Voltage Dry-Type
Distribution Transformer Standards
Table V.61 and Table V.62 summarize the quantitative impacts
estimated for each TSL for medium-voltage dry-type distribution
transformers. The national impacts are measured over the lifetime of
distribution transformers purchased in the 30-year period that begins
in the anticipated year of compliance with amended standards (2029-
2058). The energy savings, emissions reductions, and value of emissions
reductions refer to full-fuel-cycle results. DOE is presenting
monetized benefits of GHG emissions reductions in accordance with the
applicable Executive Orders, and DOE would reach the same conclusion
presented in this notice in the absence of the social cost of
greenhouse gases, including the Interim Estimates presented by the
Interagency Working Group. The efficiency levels contained in each TSL
are described in section V.A of this document.
[[Page 30018]]
[GRAPHIC] [TIFF OMITTED] TR22AP24.625
[[Page 30019]]
[GRAPHIC] [TIFF OMITTED] TR22AP24.626
DOE first considered TSL 5. TSL 5 would save an estimated 0.65
quads of energy, an amount DOE considers significant. Under TSL 5, the
NPV of consumer benefit would be $-0.08 billion using a discount rate
of 7 percent, and $0.72 billion using a discount rate of 3 percent.
The cumulative emissions reductions at TSL 5 are 11.72 Mt of
CO2, 2.8 thousand tons of SO2, 21.2 thousand tons
of NOX, 0.02 tons of Hg, 98.6 thousand tons of
CH4, and 0.1 thousand tons of N2O. The estimated
monetary value of the climate benefits from reduced GHG emissions
(associated with the average SC-GHG at a 3-percent discount rate) at
TSL 5 is $0.46 billion. The estimated monetary value of the health
benefits from reduced SO2 and NOX emissions at
TSL 5 is $0.29 billion using a 7-percent discount rate and $0.92
billion using a 3-percent discount rate.
Using a 7-percent discount rate for consumer benefits and costs,
health benefits from reduced SO2 and NOX
emissions, and the 3-percent discount rate case for climate benefits
from reduced GHG emissions, the estimated total NPV at TSL 5 is $0.67
billion. Using a 3-percent discount rate for all benefits and costs,
the estimated total NPV at TSL 5 is $2.10 billion. The estimated total
NPV is provided for additional information, however DOE primarily
relies upon the NPV of consumer benefits when determining whether a
standard level is economically justified.
At TSL 5, the average LCC impact ranges from $-6,239 for equipment
class 10 to $136 for equipment class 6. The median PBP ranges from 5.0
years for equipment class 6 to 10.5 years for equipment class 10. The
fraction of consumers experiencing a net LCC cost ranges from 47
percent for equipment class 6 to 85 percent for equipment class 10.
At TSL 5, the projected change in INPV ranges from a decrease of
$33.2 million to a decrease of $16.3 million, which corresponds to
decreases of 34.9 percent and 17.1 percent, respectively. DOE estimates
that industry must invest $36.2 million to comply with standards set at
TSL 5.
The Secretary concludes that at TSL 5 for medium-voltage dry-type
distribution transformers, the benefits of energy savings, emission
reductions, and the estimated monetary value of the emissions
reductions would be outweighed by the economic burden on many consumers
as indicated by the negative LCCs for many equipment classes, the
percentage of customers who would experience LCC increases, and the
capital and engineering costs that could result in a reduction in INPV
for manufacturers. At TSL 5 DOE is estimating negative benefits for a
disproportionate fraction of consumers--a shipment weighted average of
68 percent. Further DOE estimates that there is a substantial risk to
consumers, with a shipment weighted LCC savings for all MVDT equipment
of -$3,178. Consequently, the Secretary has concluded that TSL 5 is not
economically justified.
Next, DOE considered TSL 4. TSL 4 would save an estimated 0.55
quads of energy, an amount DOE considers significant. Under TSL 4, the
NPV of
[[Page 30020]]
consumer benefit would be $0.18 billion using a discount rate of 7
percent, and $1.14 billion using a discount rate of 3 percent.
The cumulative emissions reductions at TSL 4 are 9.85 Mt of
CO2, 2.4 thousand tons of SO2, 17.8 thousand tons
of NOX, 0.02 tons of Hg, 82.9 thousand tons of
CH4, and 0.1 thousand tons of N2O. The estimated
monetary value of the climate benefits from reduced GHG emissions
(associated with the average SC-GHG at a 3-percent discount rate) at
TSL 4 is $0.39 billion. The estimated monetary value of the health
benefits from reduced SO2 and NOX emissions at
TSL 4 is $0.24 billion using a 7-percent discount rate and $0.77
billion using a 3-percent discount rate.
Using a 7-percent discount rate for consumer benefits and costs,
health benefits from reduced SO2 and NOX
emissions, and the 3-percent discount rate case for climate benefits
from reduced GHG emissions, the estimated total NPV at TSL 4 is $0.81
billion. Using a 3-percent discount rate for all benefits and costs,
the estimated total NPV at TSL 4 is $2.30 billion. The estimated total
NPV is provided for additional information, however DOE primarily
relies upon the NPV of consumer benefits when determining whether a
proposed standard level is economically justified.
At TSL 4, the average LCC impact ranges from $-2,569 for equipment
class 10 to $2,882 for equipment class 8. The median PBP ranges from
4.2 years for equipment class 8 to 9.2 years for equipment class 10.
The fraction of consumers experiencing a net LCC cost ranges from 29
percent for equipment class 8 to 67 percent for equipment class 10.
At TSL 4, the projected change in INPV ranges from a decrease of
$29.5 million to a decrease of $18.6 million, which corresponds to
decreases of 31.0 percent and 19.5 percent, respectively. DOE estimates
that industry must invest $34.8 million to comply with standards set at
TSL 4.
The Secretary concludes that at TSL 4 for medium-voltage dry-type
distribution transformers, the benefits of energy savings, emission
reductions, and the estimated monetary value of the emissions
reductions would be outweighed by the economic burden on many consumers
as indicated by the negative LCCs for many equipment classes, the
percentage of customers who would experience LCC increases, and the
capital and engineering costs that could result in a reduction in INPV
for manufacturers. At TSL 4 DOE is estimating negative benefits for a
disproportionate fraction of consumers--a shipment weighted average of
45 percent. Consequently, the Secretary has concluded that TSL 4 is not
economically justified.
Next, DOE considered TSL 3. TSL 3 would save an estimated 0.42
quads of energy, an amount DOE considers significant. Under TSL 3, the
NPV of consumer benefit would be $0.25 billion using a discount rate of
7 percent, and $1.15 billion using a discount rate of 3 percent.
The cumulative emissions reductions at TSL 3 are 7.55 Mt of
CO2, 1.8 thousand tons of SO2, 13.6 thousand tons
of NOX, 0.01 tons of Hg, 63.5 thousand tons of
CH4, and 0.1 thousand tons of N2O. The estimated
monetary value of the climate benefits from reduced GHG emissions
(associated with the average SC-GHG at a 3-percent discount rate) at
TSL 3 is $0.30 billion. The estimated monetary value of the health
benefits from reduced SO2 and NOX emissions at
TSL 3 is $0.19 billion using a 7-percent discount rate and $0.59
billion using a 3-percent discount rate.
Using a 7-percent discount rate for consumer benefits and costs,
health benefits from reduced SO2 and NOX
emissions, and the 3-percent discount rate case for climate benefits
from reduced GHG emissions, the estimated total NPV at TSL 3 is $0.73
billion. Using a 3-percent discount rate for all benefits and costs,
the estimated total NPV at TSL 3 is $2.04 billion. The estimated total
NPV is provided for additional information, however DOE primarily
relies upon the NPV of consumer benefits when determining whether a
proposed standard level is economically justified. At TSL 3, the
average LCC impact ranges from $-2,788 for equipment class 10 to $3,418
for equipment class 8. The median PBP ranges from 3.5 years for
equipment class 6 to 10.0 years for equipment class 10. The fraction of
consumers experiencing a net LCC cost ranges from 29 percent for
equipment class 8 to 63 percent for equipment class 10.
At TSL 3, the projected change in INPV ranges from a decrease of
$26.4 million to a decrease of $19.1 million, which corresponds to
decreases of 27.8 percent and 20.1 percent, respectively. DOE estimates
that industry must invest $32.7 million to comply with standards set at
TSL 3.
The Secretary concludes that at TSL 3 for medium-voltage dry-type
distribution transformers, the benefits of energy savings, emission
reductions, and the estimated monetary value of the emissions
reductions would be outweighed by the economic burden on many consumers
as indicated by the negative LCCs for many equipment classes, the
percentage of customers who would experience LCC increases, and the
capital and engineering costs that could result in a reduction in INPV
for manufacturers. At TSL 3, DOE estimates negative benefits for a
disproportionate fraction of consumers--a shipment weighted average of
41 percent. Consequently, the Secretary has concluded that TSL 3 is not
economically justified.
Next, DOE considered TSL 2. TSL 2 would save an estimated 0.14
quads of energy, an amount DOE considers significant. Under TSL 2, the
NPV of consumer benefit would be $0.03 billion using a discount rate of
7 percent, and $0.22 billion using a discount rate of 3 percent.
The cumulative emissions reductions at TSL 2 are 2.59 Mt of
CO2, 0.6 thousand tons of SO2, 4.7 thousand tons
of NOX, 0.0 tons of Hg, 21.9 thousand tons of
CH4, and 0.0 thousand tons of N2O. The estimated
monetary value of the climate benefits from reduced GHG emissions
(associated with the average SC-GHG at a 3-percent discount rate) at
TSL 2 is $0.10 billion. The estimated monetary value of the health
benefits from reduced SO2 and NOX emissions at
TSL 2 is $0.06 billion using a 7-percent discount rate and $0.20
billion using a 3-percent discount rate.
Using a 7-percent discount rate for consumer benefits and costs,
health benefits from reduced SO2 and NOX
emissions, and the 3-percent discount rate case for climate benefits
from reduced GHG emissions, the estimated total NPV at TSL 2 is $0.20
billion. Using a 3-percent discount rate for all benefits and costs,
the estimated total NPV at TSL 2 is $0.52 billion. The estimated total
NPV is provided for additional information, however DOE primarily
relies upon the NPV of consumer benefits when determining whether a
proposed standard level is economically justified.
At TSL 2, the average LCC impact ranges from $-1,438 for equipment
class 10 to $3,794 for equipment class 8. The median PBP ranges from
0.5 years for equipment class 8 to 10.1 years for equipment class 10.
The fraction of consumers experiencing a net LCC cost ranges from 10
percent for equipment class 6 to 77 percent for equipment class 10.
At TSL 2, the projected change in INPV ranges from a decrease of
$4.4 million to a decrease of $2.3 million, which corresponds to
decreases of 4.7 percent and 2.5 percent, respectively. DOE estimates
that industry must invest
[[Page 30021]]
$5.7 million to comply with standards set at TSL 2.
After considering the analysis and weighing the benefits and
burdens, the Secretary has concluded that at a standard set at TSL 2
for medium-voltage distribution transformers would be economically
justified. At this TSL, the average LCC savings are positive across all
equipment classes except for equipment class 10, with a shipment
weighed average LCC for all medium-voltage dry-type distribution
transformers of $1,738. An estimated 10 percent of equipment class 6 to
77 percent of equipment class 10 medium-voltage dry-type distribution
transformer consumers experience a net cost, while the shipment
weighted average of consumers who experience a net cost is 33 percent.
The FFC national energy savings are significant and the NPV of consumer
benefits is positive using both a 3-percent and 7-percent discount
rate. Notably, the benefits to consumers outweigh the cost to
manufacturers. At TSL 2, the NPV of consumer benefits, even measured at
the more conservative discount rate of 7 percent is over 6 times higher
than the maximum estimated manufacturers' loss in INPV. The standard
levels at TSL 2 are economically justified even without weighing the
estimated monetary value of emissions reductions. When those emissions
reductions are included--representing $0.10 billion in climate benefits
(associated with the average SC-GHG at a 3-percent discount rate), and
$0.20 billion (using a 3-percent discount rate) or $0.06 billion (using
a 7-percent discount rate) in health benefits--the rationale becomes
stronger still.
As stated, DOE conducts the walk-down analysis to determine the TSL
that represents the maximum improvement in energy efficiency that is
technologically feasible and economically justified as required under
EPCA. The walk-down is not a comparative analysis, as a comparative
analysis would result in the maximization of net benefits instead of
energy savings that are technologically feasible and economically
justified, which would be contrary to the statute. 86 FR 70892, 70908.
Although DOE considered amended standard levels for distribution
transformers by grouping the efficiency levels for each equipment
category into TSLs, DOE evaluates all analyzed efficiency levels in its
analysis. For medium-voltage dry-type distribution transformer the TSL
2 maps directly to EL 2 for all equipment classes. EL 2 represents a 10
percent reduction in losses over the current standard. While the
consumer benefits for equipment class 10 are negative at EL 2 at -
$1,438, they are positive for all other equipment representing 67
percent of all MVDT units shipped, additionally the consumer benefits
at EL 2, excluding equipment class 10, increases from $1,738 to $2,217
in LCC savings Further, the EL 2 represent an improvement in efficiency
where the FFC national energy savings is maximized, with positive NPVs
at both 3 and 7 percent, and the shipment weighted average consumer
benefit at EL 2 is positive. The shipment weighted consumer benefits
for TSL, and EL 2 are shown in Table V.63.
As discussed previously, at the max-tech efficiency levels (TSL 5),
TSL 4, and TSL 3 for all medium-voltage dry-type distribution
transformers there is a substantial risk to consumers due to negative
LCC savings for some equipment, with a shipment weighted average
consumer benefit of -$3,178, $754, and $1,036, respectively, while at
TSL 2 it is $1,738. Therefore, DOE has concluded that the efficiency
levels above TSL 2 are not justified. Additionally, at the examined
efficiency levels greater than TSL 2 DOE is estimating that a
disproportionate fraction of consumers would be negatively impacted by
these efficiency levels. DOE estimates that shipment weighted fraction
of negatively impacted consumers for TSL 3, TSL 4, and TSL 5 (max-tech)
to be 68, 45, and 41 percent, respectively.
Therefore, based on the previous considerations, DOE adopts the
energy conservation standards for distribution transformers at TSL 2.
The amended energy conservation standards for MVDT distribution
transformers, which are expressed as percentage efficiency at 50
percent PUL, are shown in Table V.63.
[[Page 30022]]
[GRAPHIC] [TIFF OMITTED] TR22AP24.627
4. Annualized Benefits and Costs of the Adopted Standards for Liquid-
Immersed Distribution Transformers
The benefits and costs of the adopted standards can also be
expressed in terms of annualized values. The annualized net benefit is
(1) the annualized national economic value (expressed in 2022$) of the
benefits from operating products that meet the adopted standards
(consisting primarily of operating cost savings from using less
energy), minus increases in product purchase costs, and (2) the
annualized monetary value of the climate and health benefits.
Table V.64 shows the annualized values for liquid-immersed
distribution transformers under TSL 3, expressed in 2022$. The results
under the primary estimate are as follows.
Using a 7-percent discount rate for consumer benefits and costs and
NOx and SO2 reductions, and the 3-percent discount rate case
for GHG social costs, the estimated cost of the adopted standards for
liquid-immersed distribution transformers is $151.1 million per year in
increased equipment installed costs, while the estimated annual
benefits are $210.2 million from reduced equipment operating costs,
$106.1 million in GHG reductions, and $117.0 million from reduced
NOX and SO2 emissions. In this case, the net
benefit amounts to $282.3 million per year.
Using a 3-percent discount rate for all benefits and costs, the
estimated cost of the adopted standards for liquid-immersed
distribution transformers is $152.6 million per year in increased
equipment costs, while the estimated annual benefits are $348.3 million
in reduced operating costs, $106.1 million from GHG reductions, and
$213.2 million from reduced NOX and SO2
emissions. In this case, the net benefit amounts to $515.1 million per
year.
[[Page 30023]]
[GRAPHIC] [TIFF OMITTED] TR22AP24.628
[[Page 30024]]
[GRAPHIC] [TIFF OMITTED] TR22AP24.629
5. Annualized Benefits and Costs of the Adopted Standards for Low-
Voltage Dry-Type Distribution Transformers
The benefits and costs of the adopted standards can also be
expressed in terms of annualized values. The annualized net benefit is
(1) the annualized national economic value (expressed in 2022$) of the
benefits from operating products that meet the adopted standards
(consisting primarily of operating cost savings from using less
energy), minus increases in product purchase costs, and (2) the
annualized monetary value of the climate and health benefits.
Table V.65 shows the annualized values for low-voltage dry-type
under TSL 3, expressed in 2022$. The results under the primary estimate
are as follows.
Using a 7-percent discount rate for consumer benefits and costs and
NOx and SO2 reductions, and the 3-percent discount rate case
for GHG social costs, the estimated cost of the adopted standards for
low-voltage dry-type is $66.6 million per year in increased equipment
installed costs, while the estimated annual benefits are $286.8 million
from reduced equipment operating costs, $70.4 million in GHG
reductions, and $80.3 million from reduced NOX and
SO2 emissions. In this case, the net benefit amounts to
$370.8 million per year.
Using a 3-percent discount rate for all benefits and costs, the
estimated cost of the adopted standards for low-voltage dry-type is
$67.4 million per year in increased equipment costs, while the
estimated annual benefits are $450.9 million in reduced operating
costs, $70.4 million from GHG reductions, and $139.1 million from
reduced NOX and SO2 emissions. In this case, the
net benefit amounts to $593.0 million per year.
[[Page 30025]]
[GRAPHIC] [TIFF OMITTED] TR22AP24.630
[[Page 30026]]
[GRAPHIC] [TIFF OMITTED] TR22AP24.631
6. Annualized Benefits and Costs of the Adopted Standards for Medium-
Voltage Dry-Type Distribution Transformers
The benefits and costs of the adopted standards can also be
expressed in terms of annualized values. The annualized net benefit is
(1) the annualized national economic value (expressed in 2022$) of the
benefits from operating products that meet the adopted standards
(consisting primarily of operating cost savings from using less
energy), minus increases in product purchase costs, and (2) the
annualized monetary value of the climate and health benefits.
Table V.66 shows the annualized values for medium-voltage dry-type
under TSL 2, expressed in 2022$. The results under the primary estimate
are as follows.
Using a 7-percent discount rate for consumer benefits and costs and
NOx and SO2 reductions, and the 3-percent discount rate case
for GHG social costs, the estimated cost of the adopted standards for
medium-voltage dry-type is $12.5 million per year in increased
equipment installed costs, while the estimated annual benefits are
$15.9 million from reduced equipment operating costs, $5.9 million in
GHG reductions, and $6.7 million from reduced NOX and
SO2 emissions. In this case, the net benefit amounts to
$16.0 million per year.
Using a 3-percent discount rate for all benefits and costs, the
estimated cost of the adopted standards for medium-voltage dry-type is
$12.7 million per year in increased equipment costs, while the
estimated annual benefits are $25.1 million in reduced operating costs,
$5.9 million from GHG reductions, and $11.7 million from reduced
NOX and SO2 emissions. In this case, the net
benefit amounts to $29.9 million per year.
[[Page 30027]]
[GRAPHIC] [TIFF OMITTED] TR22AP24.632
[[Page 30028]]
[GRAPHIC] [TIFF OMITTED] TR22AP24.633
7. Benefits and Costs of the Proposed Standards for All Considered
Distribution Transformers
As described in sections V.C.1 through V.C.3, for this final rule
DOE is adopting TSL 3 for liquid-immersed, TSL 3 for low-voltage dry-
type, and TSL 2 for medium-voltage dry-type distribution transformers.
Table V.67 shows the combined cumulative benefits, and Table V.68 shows
the combined annualized benefits for the proposed levels for all
distribution transformers.
[[Page 30029]]
[GRAPHIC] [TIFF OMITTED] TR22AP24.634
[[Page 30030]]
[GRAPHIC] [TIFF OMITTED] TR22AP24.635
[[Page 30031]]
[GRAPHIC] [TIFF OMITTED] TR22AP24.636
[[Page 30032]]
[GRAPHIC] [TIFF OMITTED] TR22AP24.637
8. Severability
Finally, DOE added a new paragraph (e) to 10 CFR 431.196 to provide
that each energy conservation standard for each distribution
transformer category (liquid immersed, LVDT, MDVT) is separate and
severable from one another, and that if any energy conservation
standard for any category is stayed or determined to be invalid by a
court of competent jurisdiction, the remaining energy conservation
standards for the other categories shall continue in effect. This
severability clause is intended to clearly express the Department's
intent that should an energy conservation standard for any category be
stayed or invalidated, energy conservation standards for the other
categories shall continue to remain in full force and legal effect.
VI. Procedural Issues and Regulatory Review
A. Review Under Executive Orders 12866, 13563, and 14094
Executive Order (E.O.) 12866, ``Regulatory Planning and Review,''
as supplemented and reaffirmed by E.O. 13563, ``Improving Regulation
and Regulatory Review,'' 76 FR 3821 (Jan. 21, 2011) and amended by E.O.
14094, ``Modernizing Regulatory Review,'' 88 FR 21879 (April 11, 2023),
requires agencies, to the extent permitted by law, to (1) propose or
adopt a regulation only upon a reasoned determination that its benefits
justify its costs (recognizing that some benefits and costs are
difficult to quantify); (2) tailor regulations to impose the least
burden on society, consistent with obtaining regulatory objectives,
taking into account, among other things, and to the extent practicable,
the costs of cumulative regulations; (3) select, in choosing among
alternative regulatory approaches, those approaches that maximize net
benefits (including potential economic, environmental, public health
and safety, and other advantages; distributive impacts; and equity);
(4) to the extent feasible, specify performance objectives, rather than
specifying the behavior or manner of compliance that regulated entities
must adopt; and (5) identify and assess available alternatives to
direct regulation, including providing economic incentives to encourage
the desired behavior, such as user fees or marketable permits, or
providing information upon which choices can be made by the public. DOE
emphasizes as well that E.O. 13563 requires agencies to
[[Page 30033]]
use the best available techniques to quantify anticipated present and
future benefits and costs as accurately as possible. In its guidance,
the Office of Information and Regulatory Affairs (OIRA) in the Office
of Management and Budget (OMB) has emphasized that such techniques may
include identifying changing future compliance costs that might result
from technological innovation or anticipated behavioral changes. For
the reasons stated in the preamble, this final regulatory action is
consistent with these principles.
Section 6(a) of E.O. 12866 also requires agencies to submit
``significant regulatory actions'' to OIRA for review. OIRA has
determined that this final regulatory action constitutes a
``significant regulatory action'' within the scope of section 3(f)(1)
of E.O. 12866. Accordingly, pursuant to section 6(a)(3)(C) of E.O.
12866, DOE has provided to OIRA an assessment, including the underlying
analysis, of benefits and costs anticipated from the final regulatory
action, together with, to the extent feasible, a quantification of
those costs; and an assessment, including the underlying analysis, of
costs and benefits of potentially effective and reasonably feasible
alternatives to the planned regulation, and an explanation why the
planned regulatory action is preferable to the identified potential
alternatives. These assessments are summarized in this preamble and
further detail can be found in the technical support document for this
rulemaking.
B. Review Under the Regulatory Flexibility Act
The Regulatory Flexibility Act (5 U.S.C. 601 et seq.) requires
preparation of an initial regulatory flexibility analysis (IRFA) and a
final regulatory flexibility analysis (FRFA) for any rule that by law
must be proposed for public comment, unless the agency certifies that
the rule, if promulgated, will not have a significant economic impact
on a substantial number of small entities. As required by E.O. 13272,
``Proper Consideration of Small Entities in Agency Rulemaking,'' 67 FR
53461 (Aug. 16, 2002), DOE published procedures and policies on
February 19, 2003, to ensure that the potential impacts of its rules on
small entities are properly considered during the rulemaking process.
68 FR 7990. DOE has made its procedures and policies available on the
Office of the General Counsel's website (www.energy.gov/gc/office-general-counsel). DOE has prepared the following FRFA for the products
that are the subject of this rulemaking.
For manufacturers of distribution transformers, the SBA has set a
size threshold, which defines those entities classified as ``small
businesses'' for the purposes of the statute. DOE used the SBA's small
business size standards to determine whether any small entities would
be subject to the requirements of the rule. (See 13 CFR part 121.) The
size standards are listed by NAICS code and industry description and
are available at www.sba.gov/document/support-table-size-standards.
Manufacturing of distribution transformers is classified under NAICS
335311, ``Power, Distribution, and Specialty Transformer
Manufacturing''. The SBA sets a threshold of 800 employees or fewer for
an entity to be considered as a small business for this category.
1. Need for, and Objectives of, Rule
EPCA authorizes DOE to regulate the energy efficiency of a number
of consumer products and certain industrial equipment. Title III, Part
B of EPCA established the Energy Conservation Program for Consumer
Products Other Than Automobiles. (42 U.S.C. 6291-6309) Title III, Part
C of EPCA, added by Public Law 95-619, Title IV, section 411(a),
established the Energy Conservation Program for Certain Industrial
Equipment. The Energy Policy Act of 1992, Public Law 102-486, amended
EPCA and directed DOE to prescribe energy conservation standards for
those distribution transformers for which DOE determines such standards
would be technologically feasible, economically justified, and would
result in significant energy savings. (42 U.S.C. 6317(a)) The Energy
Policy Act of 2005, Public Law 109-58, amended EPCA to establish energy
conservation standards for low-voltage dry-type distribution
transformers. (42 U.S.C. 6295(y))
EPCA further provides that, not later than six years after the
issuance of any final rule establishing or amending a standard, DOE
must publish either a notice of determination that standards for the
product do not need to be amended, or a NOPR including new proposed
energy conservation standards (proceeding to a final rule, as
appropriate). (42 U.S.C. 6316(a); 42 U.S.C. 6295(m)(1))
DOE must follow specific statutory criteria for prescribing new or
amended standards for covered equipment, including distribution
transformers. Any new or amended standard for a covered product must be
designed to achieve the maximum improvement in energy efficiency that
the Secretary of Energy determines is technologically feasible and
economically justified. (42 U.S.C. 6316(a); 42 U.S.C. 6295(o)(2)(A))
Furthermore, DOE may not adopt any standard that would not result in
the significant conservation of energy. (42 U.S.C. 6316(a); 42 U.S.C.
6295(o)(3))
2. Significant Issues Raised by Public Comments in Response to the IRFA
APPA commented that some small manufacturers will not be able to
retool in sufficient time and will further worsen supply chain
concerns. (APPA, No. 103 at p. 6) Powersmiths commented that using
amorphous steel for LVDT distribution transformers requires an overhaul
of the manufacturing production process. (Powersmiths, No. 112 at p. 6)
Powersmiths commented that small manufacturers may not be able to make
this transition due to the complexity and novelty of amorphous steel,
along with the need for qualified designers, significant retooling
costs, new manufacturing processes, and other additional resources.
(Id.) Additionally, Powersmiths commented that even if LVDT small
manufacturers could make this transition to amorphous steel they will
need more than the 3-year compliance period proposed in the January
2023 NOPR. (Id.)
DOE understands that distribution transformer manufacturers,
including small businesses, will incur conversion costs, which include
retooling production facilities, in order to comply with standards. DOE
estimates the impacts to the distribution transformer industry at each
TSL in section V.B.2.a of this document and specifically estimates the
impact to small businesses as part of this FRFA. Additionally, in the
January 2023 NOPR DOE proposed a 3-year compliance period for
manufacturers to meet the proposed standards. DOE is adopting a 5-year
compliance period for this final rule. This additional time should
allow for manufacturers, including small manufacturers, to retool their
production facilities and make the necessary equipment additions that
manufacturers will have to make to manufacture compliant distribution
transformers. DOE also notes that the expanded compliance date provides
greater time for core steel manufacturers, both GOES and amorphous, to
meet expected demand.
NAHB commented that most home builders are considered a small
business based on SBA's small business definition and expressed concern
that DOE has not considered these home builders and other small
businesses that rely on a consistent supply of distribution
transformers that might be impacted by this rulemaking. (NAHB,
[[Page 30034]]
No. 106 at p. 5) As stated in section IV.A.5 of this document, DOE
notes that the standards amended in this rule will allow distribution
transformers to cost-competitively utilize existing GOES capacity
across many kVA ratings. Additionally, DOE notes that the compliance
period for amended standards has been extended, from the 3-year
compliance period proposed in the January 2023 NOPR to a 5-year
compliance period adopted in this final rule. The additional time
provided to redesign distribution transformers and build capacity will
further mitigate any risk of disrupting production to meet current
demand. Additionally, as stated in section V.B.2.c of this document,
DOE does not anticipate that there will be a significant disruption in
the supply of distribution transformers due to the adopted standards to
home builders or any other distribution transformer markets.
3. Description and Estimated Number of Small Entities Affected
DOE conducted a more focused inquiry of the companies that could be
small businesses that manufacture distribution transformers covered by
this rulemaking. DOE used publicly available information to identify
potential small businesses. DOE's research involved industry trade
association membership directories (including NEMA),\202\ DOE's
publicly available Compliance Certification Database \203\ (CCD),
California Energy Commission's Modernized Appliance Efficiency Database
System \204\ (MAEDBS) to create a list of companies that manufacture or
sell distribution transformers covered by this rulemaking. DOE also
asked stakeholders and industry representatives if they were aware of
any other small businesses during manufacturer interviews. DOE
contacted select companies on its list, as necessary, to determine
whether they met the SBA's definition of a small business that
manufacturers distribution transformers covered by this rulemaking. DOE
screened out companies that did not offer products covered by this
rulemaking, did not meet the definition of a ``small business,'' or are
foreign owned and operated.
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\202\ See: www.nema.org/membership/manufacturers.
\203\ See: www.regulations.doe.gov/certification-data.
\204\ See: cacertappliances.energy.ca.gov.
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DOE's analysis identified 36 companies that sell or manufacture
distribution transformers coved by this rulemaking in the U.S. market.
At least two of these companies are not the original equipment
manufacturers (OEM) and instead privately label distribution
transformers that are manufactured by another distribution transformer
manufacturer. Of the 34 companies that are OEMs, DOE identified nine
companies that have fewer than 800 total employees and are not entirely
foreign owned and operated. There are three small businesses that
manufacture liquid-immersed distribution transformers; there are three
small businesses that manufacture LVDT and MVDT distribution
transformers; and there are three small businesses that only
manufacture LVDT distribution transformers.\205\
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\205\ Therefore, there are a total of six small businesses that
manufacture LVDT distribution transformers. Three that exclusively
manufacture LVDT distribution transformers and three that
manufacture both LVDT and MVDT distribution transformers.
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Liquid-Immersed Distribution Transformer Small Businesses
Liquid-immersed distribution transformers account for over 80
percent of all distribution transformer shipments covered by this
rulemaking. Seven major manufacturers supply more than 80 percent of
the market for liquid-immersed distribution transformers covered by
this rulemaking. None of these seven major manufacturers of liquid-
immersed distribution transformers are small businesses. Most liquid-
immersed distribution transformers are manufactured domestically.
Electric utilities compose the customer base and typically buy on a
first-cost basis. Many small manufacturers position themselves towards
the higher end of the market or in particular product niches, such as
network transformers or harmonic mitigating transformers, but, in
general, competition is based on price after a given unit's specs are
prescribed by a customer. None of the three small businesses have a
market share larger than five percent of the liquid-immersed
distribution transformer market.
Low-Voltage Dry-Type Distribution Transformer Small Businesses
LVDT distribution transformers account for approximately 16 percent
of all distribution shipments covered by this rulemaking. Eleven major
manufacturers supply more than 80 percent of the market for LVDT
distribution transformers covered by this rulemaking. Two of these 11
major LVDT distribution transformer manufacturers are small businesses.
The majority of LVDT distribution transformers are manufactured outside
the U.S., mostly in Canada and Mexico. The customer base rarely
purchases on efficiency and is very first-cost conscious, which, in
turn, places a premium on economies of scale in manufacturing. However,
there are universities and other buildings that purchase LVDT based on
efficiency as more and more organizations are striving to get to
reduced or net-zero emission targets.
In the LVDT market, lower volume manufacturers typically do not
compete directly with larger volume manufacturers, as these lower
volume manufacturers are frequently not able to compete on a first cost
basis. However, there are lower volume manufactures that do serve
customers that purchase more efficient LVDT distribution transformers.
Lastly, there are some smaller firms that focus on the engineering and
design of LVDT distribution transformers and source the production of
some parts of the distribution transformer, most frequently the cores,
to another company that manufactures those components.
Medium-Voltage Dry-Type Distribution Transformer Small Businesses
MVDT distribution transformers account for less than one percent of
all distribution transformer shipments covered by this rulemaking.
Eight major manufacturers supply more than 80 percent of the market for
MVDT distribution transformers covered by this rulemaking. Two of the
eight major MVDT distribution transformer manufacturers are small
businesses. The rest of MVDT distribution transformer market is served
by a mix of large and small manufactures. Most MVDT distribution
transformers are manufactured domestically. Electric utilities and
industrial users make up most of the customer base and typically buy on
first-cost or features other than efficiency.
4. Description of Reporting, Recordkeeping, and Other Compliance
Requirements
Liquid-Immersed Distribution Transformers
DOE is adopting energy conservation standards at TSL 3 for liquid-
immersed distribution transformers. For liquid-immersed distribution
transformers, TSL 3 is a combination of EL 2 and EL 4 for most liquid-
immersed distribution transformer equipment classes.
Based on the LCC consumer choice model, DOE anticipates that most
[[Page 30035]]
liquid-immersed distribution transformer manufacturers would use
primarily grain-oriented with amorphous cores at select kVA ranges in
their distribution transformers to meet these adopted energy
conservation standards. While DOE anticipates that several large
liquid-immersed distribution transformer manufacturers would make
significant capital investments to accommodate the production of
amorphous cores, DOE does not anticipate that any small businesses will
make these capital investments to be able to produce their own
amorphous cores, based on the large capital investments needed to be
able to make amorphous cores and the limited ability for small
businesses to access large capital investments. Based on manufacturer
interviews and market research, DOE was not able to identify any
liquid-immersed small businesses that manufacture their own cores.
Therefore, DOE anticipates that all liquid-immersed small manufacturers
would continue to outsource their production of distribution
transformer cores. However, instead of outsourcing exclusively GOES
cores they will now outsource a combination of GOES cores and amorphous
cores for most of the liquid-immersed distribution transformers that
they manufacture in order to comply with the adopted energy
conservation standard for liquid-immersed distribution transformers.
DOE acknowledges that there is uncertainty if these small
businesses will be able to find core manufacturers that will supply
them with amorphous cores in order to comply with the adopted energy
conservation standards for liquid-immersed distribution transformers.
DOE anticipates that there will be an increase in the number of large
liquid-immersed distribution transformer manufacturers that will
outsource the production of their cores to core manufacturers capable
of producing amorphous cores. This could increase the competition for
small businesses to procure amorphous cores for their distribution
transformers. Small businesses manufacturing liquid-immersed
distribution transformers must be able to procure amorphous cores
suitable for their distribution transformers at a cost that allows them
to continue to be competitive in the market.
Based on feedback received during manufacturer interviews, DOE does
not anticipate that liquid-immersed small businesses that are currently
not producing their own cores would have to make a significant capital
investment in their production lines to be able to use amorphous cores,
that are purchased from a core manufacturer, in the distribution
transformers that they manufacture. There will be some additional
product conversion costs, in the form of additional R&D and testing,
that will need to be incurred by small businesses that manufacture
liquid-immersed distribution transformers, even if they do not
manufacture their own cores. The methodology used to calculate product
conversion costs, described in section IV.J.2.c of this document,
estimates that manufacturers would incur approximately one and a half
additional years of R&D expenditure to redesign their distribution
transformers to be capable of accommodating the use of an amorphous
core. Based on the financial parameters used in the GRIM, DOE estimated
that the normal annual R&D is approximately 3.0 percent of annual
revenue. Therefore, liquid-immersed small businesses would incur an
additional 4.5 percent of annual revenue to redesign their distribution
transformers to be able to accommodate using amorphous cores that were
purchased from core manufacturers.
Low-Voltage Dry-Type Distribution Transformers
DOE is adopting amended energy conservation standards to be at TSL
3 for LVDT distribution transformers. For LVDT distribution
transformers, TSL 3 corresponds to EL 3 for all LVDT distribution
transformer equipment classes.
Based on the LCC consumer choice model, DOE anticipates that
approximately 30 percent of LVDT distribution transformer manufacturers
would use amorphous cores in their distribution transformers to meet
these adopted energy conservation standards. Based on manufacturer
interviews and market research, DOE was able to identify one LVDT small
business that manufactures their own cores. The one LVDT small business
that is currently manufacturing their own cores would have to make a
business decision to either continue making GOES cores that they
currently manufacture, make a large capital investment to be able to
manufacture amorphous cores, or to outsource the production of
amorphous cores. Outsourcing the production of their cores would be a
significant change in their production process and could result in a
reduction in this small business' market share in the LVDT distribution
transformer market.
The other LVDT small businesses that are currently outsourcing
their cores will continue to outsource their cores. These LVDT small
businesses will have to make a business decision either to continue
outsourcing GOES cores that they currently use in their LVDT
distribution transformers or to find a core manufacturer that is
capable of producing amorphous cores and outsource the production of
amorphous cores.
DOE acknowledges that there is uncertainty if these small
businesses will be able to find core manufacturers that will supply
them with amorphous cores in order to comply with the adopted energy
conservation standards for LVDT distribution transformers. DOE
anticipates that there will be an increase in the number of large LVDT
distribution transformer manufacturers that will outsource the
production of their cores to core manufacturers capable of producing
amorphous cores. This could increase the competition for small
businesses to procure amorphous cores for their LVDT distribution
transformers. However, small businesses manufacturing LVDT distribution
transformers will still be able to meet the adopted energy conservation
standards using GOES cores.
Based on feedback received during manufacturer interviews, DOE does
not anticipate that small businesses that are currently not producing
their own cores would have to make a significant capital investment in
their production lines to be able to meet the adopted energy
conservation standards for LVDT distribution transformers. There will
be some additional product conversion costs, in the form of additional
R&D and testing, that will need to be incurred by small businesses that
manufacture LVDT distribution transformers, even if they do not
manufacture their own cores. The methodology used to calculate product
conversion costs, described in section IV.J.2.c estimates that
manufacturers would incur approximately one and a half additional years
of R&D expenditure to redesign their distribution transformers to be
capable of accommodating the use of an amorphous core and 75 percent of
annual R&D expenditures to redesign their distribution transformers
that continue to use GOES cores. Based on the financial parameters used
in the GRIM, DOE estimated that the normal annual R&D is approximately
3.0 percent of annual revenue. Therefore, LVDT small businesses would
incur an additional 2.25 to 4.5 percent of annual revenue to redesign
their distribution transformers, depending on if they choose to
continue to use GOES cores or amorphous cores, to meet the adopted
energy conservation standard for LVDT distribution transformers, which
are set at TSL 3.
[[Page 30036]]
Medium-Voltage Dry-Type Distribution Transformers
DOE is adopting energy conservation standards to be at TSL 2 for
MVDT distribution transformers. This corresponds to EL 2 for all MVDT
distribution transformer equipment classes. Based on the LCC consumer
choice model, DOE only anticipates that approximately 12 percent of
MVDT distribution transformer manufacturers would use amorphous cores
in their MVDT distribution transformers to meet these adopted energy
conservation standards. DOE does not anticipate that MVDT distribution
transformer manufacturers would make significant investments to either
be able to produce cores capable of meeting these adopted amended
energy conservation standards or be able to integrate more efficient
purchased cores from core manufacturers. There will be some additional
product conversion costs, in the form of additional R&D and testing,
that will need to be incurred by small businesses that manufacture MVDT
distribution transformers, even if they do not manufacture their own
cores. The methodology used to calculate product conversion costs,
described in section IV.J.2.c of this document, estimates that
manufacturers would incur approximately 75 percent of additional R&D
expenditure to redesign their distribution transformers to higher
efficiency levels, when continuing to use GOES cores. Based on the
financial parameters used in the GRIM, DOE estimated that the normal
annual R&D is approximately 3.0 percent of annual revenue. Therefore,
MVDT small businesses would include an additional 2.25 percent of
annual revenue to redesign, MVDT distribution transformers to higher
efficiency levels that could be met without using amorphous cores.
5. Significant Alternatives Considered and Steps Taken To Minimize
Significant Economic Impacts on Small Entities
The discussion in the previous section analyzes impacts on small
businesses that would result from DOE's proposed rule, represented by
TSL 3 for liquid-immersed distribution transformer equipment classes;
TSL 3 for LVDT equipment classes; and TSL 2 for MVDT equipment classes.
In reviewing alternatives to the proposed rule, DOE examined energy
conservation standards set at lower efficiency levels. While lower TSLs
would reduce the impacts on small business manufacturers, it would come
at the expense of a reduction in energy savings. For liquid-immersed
equipment classes TSL 1 achieves 84 percent lower energy savings
compared to the energy savings at TSL 3; and TSL 2 achieves 58 percent
lower energy savings compared to the energy savings at TSL 3. For LVDT
equipment classes TSL 1 achieves 77 percent lower energy savings
compared to the energy savings at TSL 3; and TSL 2 achieves 65 percent
lower energy savings compared to the energy savings at TSL 3. For MVDT
equipment classes TSL 1 achieves 29 percent lower energy savings
compared to the energy savings at TSL 2.
Establishing standards at TSL 3 for liquid-immersed equipment
classes and LVDT equipment classes and TSL 2 for MVDT equipment classes
balances the benefits of the energy savings at the adopted TSLs with
the potential burdens placed on distribution transformer manufacturers,
including small business manufacturers. Accordingly, DOE is not
adopting one of the other TSLs considered in the analysis, or the other
policy alternatives examined as part of the regulatory impact analysis
and included in chapter 17 of the final rule TSD.
Additional compliance flexibilities may be available through other
means. Manufacturers subject to DOE's energy efficiency standards may
apply to DOE's Office of Hearings and Appeals for exception relief
under certain circumstances. Manufacturers should refer to 10 CFR part
430, subpart E, and 10 CFR part 1003 for additional details.
C. Review Under the Paperwork Reduction Act
Manufacturers of distribution transformers must certify to DOE that
their products comply with any applicable energy conservation
standards. In certifying compliance, manufacturers must test their
products according to the DOE test procedures for distribution
transformers, including any amendments adopted for those test
procedures. DOE has established regulations for the certification and
recordkeeping requirements for all covered consumer products and
commercial equipment, including distribution transformers. (See
generally 10 CFR part 429). The collection-of-information requirement
for the certification and recordkeeping is subject to review and
approval by OMB under the Paperwork Reduction Act (PRA). This
requirement has been approved by OMB under OMB Control Number 1910-
1400. Public reporting burden for the certification is estimated to
average 35 hours per response, including the time for reviewing
instructions, searching existing data sources, gathering and
maintaining the data needed, and completing and reviewing the
collection of information.
Notwithstanding any other provision of the law, no person is
required to respond to, nor shall any person be subject to a penalty
for failure to comply with, a collection of information subject to the
requirements of the PRA, unless that collection of information displays
a currently valid OMB Control Number.
D. Review Under the National Environmental Policy Act of 1969
Pursuant to the National Environmental Policy Act of 1969 (NEPA),
DOE has analyzed this rule in accordance with NEPA and DOE's NEPA
implementing regulations (10 CFR part 1021). DOE has determined that
this rule qualifies for categorical exclusion under 10 CFR part 1021,
subpart D, appendix B5.1 because it is a rulemaking that establishes
energy conservation standards for consumer products or industrial
equipment, none of the exceptions identified in B5.1(b) apply, no
extraordinary circumstances exist that require further environmental
analysis, and it meets the requirements for application of a
categorical exclusion. See 10 CFR 1021.410. Therefore, DOE has
determined that promulgation of this rule is not a major Federal action
significantly affecting the quality of the human environment within the
meaning of NEPA, and does not require an environmental assessment or an
environmental impact statement.
E. Review Under Executive Order 13132
E.O. 13132, ``Federalism,'' 64 FR 43255 (Aug. 10, 1999), imposes
certain requirements on Federal agencies formulating and implementing
policies or regulations that preempt State law or that have federalism
implications. The Executive order requires agencies to examine the
constitutional and statutory authority supporting any action that would
limit the policymaking discretion of the States and to carefully assess
the necessity for such actions. The Executive order also requires
agencies to have an accountable process to ensure meaningful and timely
input by State and local officials in the development of regulatory
policies that have federalism implications. On March 14, 2000, DOE
published a statement of policy describing the intergovernmental
consultation process it will follow in the development of such
regulations. 65 FR 13735. DOE has examined this rule and has determined
that it would not have a substantial direct effect on the States, on
the relationship between the national government and the States, or on
the
[[Page 30037]]
distribution of power and responsibilities among the various levels of
government. EPCA governs and prescribes Federal preemption of State
regulations as to energy conservation for the equipment that is the
subject of this final rule. States can petition DOE for exemption from
such preemption to the extent, and based on criteria, set forth in
EPCA. (42 U.S.C. 6316(a) and (b); 42 U.S.C. 6297) Therefore, no further
action is required by Executive Order 13132.
F. Review Under Executive Order 12988
With respect to the review of existing regulations and the
promulgation of new regulations, section 3(a) of E.O. 12988, ``Civil
Justice Reform,'' imposes on Federal agencies the general duty to
adhere to the following requirements: (1) eliminate drafting errors and
ambiguity, (2) write regulations to minimize litigation, (3) provide a
clear legal standard for affected conduct rather than a general
standard, and (4) promote simplification and burden reduction. 61 FR
4729 (Feb. 7, 1996). Regarding the review required by section 3(a),
section 3(b) of E.O. 12988 specifically requires that Executive
agencies make every reasonable effort to ensure that the regulation (1)
clearly specifies the preemptive effect, if any, (2) clearly specifies
any effect on existing Federal law or regulation, (3) provides a clear
legal standard for affected conduct while promoting simplification and
burden reduction, (4) specifies the retroactive effect, if any, (5)
adequately defines key terms, and (6) addresses other important issues
affecting clarity and general draftsmanship under any guidelines issued
by the Attorney General. Section 3(c) of E.O. 12988 requires Executive
agencies to review regulations in light of applicable standards in
section 3(a) and section 3(b) to determine whether they are met or it
is unreasonable to meet one or more of them. DOE has completed the
required review and determined that, to the extent permitted by law,
this final rule meets the relevant standards of E.O. 12988.
G. Review Under the Unfunded Mandates Reform Act of 1995
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA)
requires each Federal agency to assess the effects of Federal
regulatory actions on State, local, and Tribal governments and the
private sector. Public Law 104-4, sec. 201 (codified at 2 U.S.C. 1531).
For a regulatory action likely to result in a rule that may cause the
expenditure by State, local, and Tribal governments, in the aggregate,
or by the private sector of $100 million or more in any one year
(adjusted annually for inflation), section 202 of UMRA requires a
Federal agency to publish a written statement that estimates the
resulting costs, benefits, and other effects on the national economy.
(2 U.S.C. 1532(a), (b)) The UMRA also requires a Federal agency to
develop an effective process to permit timely input by elected officers
of State, local, and Tribal governments on a ``significant
intergovernmental mandate,'' and requires an agency plan for giving
notice and opportunity for timely input to potentially affected small
governments before establishing any requirements that might
significantly or uniquely affect them. On March 18, 1997, DOE published
a statement of policy on its process for intergovernmental consultation
under UMRA. 62 FR 12820. DOE's policy statement is also available at
www.energy.gov/sites/prod/files/gcprod/documents/umra_97.pdf.
DOE has concluded that this final rule may require expenditures of
$100 million or more in any one year by the private sector. Such
expenditures may include (1) investment in research and development and
in capital expenditures by distribution transformer manufacturers in
the years between the final rule and the compliance date for the new
standards and (2) incremental additional expenditures by consumers to
purchase higher-efficiency distribution transformers, starting at the
compliance date for the applicable standard.
Section 202 of UMRA authorizes a Federal agency to respond to the
content requirements of UMRA in any other statement or analysis that
accompanies the final rule. (2 U.S.C. 1532(c)) The content requirements
of section 202(b) of UMRA relevant to a private sector mandate
substantially overlap the economic analysis requirements that apply
under section 325(o) of EPCA and Executive Order 12866. The
SUPPLEMENTARY INFORMATION section of this document and the TSD for this
final rule respond to those requirements.
Under section 205 of UMRA, DOE is obligated to identify and
consider a reasonable number of regulatory alternatives before
promulgating a rule for which a written statement under section 202 is
required. (2 U.S.C. 1535(a)) DOE is required to select from those
alternatives the most cost effective and least burdensome alternative
that achieves the objectives of the rule unless DOE publishes an
explanation for doing otherwise, or the selection of such an
alternative is inconsistent with law. As required by 42 U.S.C. 6316(a)
and 42 U.S.C. 6295(m)(1), this final rule establishes amended energy
conservation standards for distribution transformers that are designed
to achieve the maximum improvement in energy efficiency that DOE has
determined to be both technologically feasible and economically
justified, as required by 42 U.S.C. 6316(a); 6295(o)(2)(A) and
6295(o)(3)(B). A full discussion of the alternatives considered by DOE
is presented in chapter 17 of the TSD for this final rule.
H. Review Under the Treasury and General Government Appropriations Act,
1999
Section 654 of the Treasury and General Government Appropriations
Act, 1999 (Pub. L. 105-277) requires Federal agencies to issue a Family
Policymaking Assessment for any proposed rule or policy that may affect
family well-being. Although this final rule would not have any impact
on the autonomy or integrity of the family as an institution as
defined, this final rule could impact a family's well-being. When
developing a Family Policymaking Assessment, agencies must assess
whether: (1) the action strengthens or erodes the stability or safety
of the family and, particularly, the marital commitment; (2) the action
strengthens or erodes the authority and rights of parents in the
education, nurture, and supervision of their children; (3) the action
helps the family perform its functions, or substitutes governmental
activity for the function; (4) the action increases or decreases
disposable income or poverty of families and children; (5) the proposed
benefits of the action justify the financial impact on the family; (6)
the action may be carried out by State or local government or by the
family; and whether (7) the action establishes an implicit or explicit
policy concerning the relationship between the behavior and personal
responsibility of youth, and the norms of society.
DOE has considered how the benefits of this final rule compare to
the possible financial impact on a family (the only factor listed that
is relevant to this proposed rule). As part of its rulemaking process,
DOE must determine whether the energy conservation standards enacted in
this final rule are economically justified. As discussed in sections
V.C.1 through V.C.3 of this document, DOE has determined that the
standards enacted in this final rule are economically justified because
the benefits to consumers would far outweigh the costs to
manufacturers. Moreover, as discussed further in section V.B.1 of this
document, DOE has determined that for utilities who serve
[[Page 30038]]
low population densities, average LCC savings and PBP at the considered
efficiency levels are not substantially different, and are often
improved (i.e., higher LCC savings and lower PBP), as compared to the
average for all utilities. Further, the standards will also result in
climate and health benefits for families.
I. Review Under Executive Order 12630
Pursuant to E.O. 12630, ``Governmental Actions and Interference
with Constitutionally Protected Property Rights,'' 53 FR 8859 (March
18, 1988), DOE has determined that this rule would not result in any
takings that might require compensation under the Fifth Amendment to
the U.S. Constitution.
J. Review Under the Treasury and General Government Appropriations Act,
2001
Section 515 of the Treasury and General Government Appropriations
Act, 2001 (44 U.S.C. 3516, note) provides for Federal agencies to
review most disseminations of information to the public under
information quality guidelines established by each agency pursuant to
general guidelines issued by OMB. OMB's guidelines were published at 67
FR 8452 (Feb. 22, 2002), and DOE's guidelines were published at 67 FR
62446 (Oct. 7, 2002). Pursuant to OMB Memorandum M-19-15, Improving
Implementation of the Information Quality Act (April 24, 2019), DOE
published updated guidelines which are available at www.energy.gov/sites/prod/files/2019/12/f70/DOE%20Final%20Updated%20IQA%20Guidelines%20Dec%202019.pdf. DOE has
reviewed this final rule under the OMB and DOE guidelines and has
concluded that it is consistent with applicable policies in those
guidelines.
K. Review Under Executive Order 13211
E.O. 13211, ``Actions Concerning Regulations That Significantly
Affect Energy Supply, Distribution, or Use,'' 66 FR 28355 (May 22,
2001), requires Federal agencies to prepare and submit to OIRA at OMB,
a Statement of Energy Effects for any significant energy action. A
``significant energy action'' is defined as any action by an agency
that promulgates or is expected to lead to promulgation of a final
rule, and that (1) is a significant regulatory action under Executive
Order 12866, or any successor order; and (2) is likely to have a
significant adverse effect on the supply, distribution, or use of
energy, or (3) is designated by the Administrator of OIRA as a
significant energy action. For any significant energy action, the
agency must give a detailed statement of any adverse effects on energy
supply, distribution, or use should the proposal be implemented, and of
reasonable alternatives to the action and their expected benefits on
energy supply, distribution, and use.
DOE has concluded that this regulatory action, which sets forth
amended energy conservation standards for distribution transformers, is
not a significant energy action because the standards are not likely to
have a significant adverse effect on the supply, distribution, or use
of energy, nor has it been designated as such by the Administrator at
OIRA. Accordingly, DOE has not prepared a Statement of Energy Effects
on this final rule.
L. Information Quality
On December 16, 2004, OMB, in consultation with the Office of
Science and Technology Policy (OSTP), issued its Final Information
Quality Bulletin for Peer Review (``the Bulletin''). 70 FR 2664 (Jan.
14, 2005). The Bulletin establishes that certain scientific information
shall be peer reviewed by qualified specialists before it is
disseminated by the Federal Government, including influential
scientific information related to agency regulatory actions. The
purpose of the Bulletin is to enhance the quality and credibility of
the Government's scientific information. Under the Bulletin, the energy
conservation standards rulemaking analyses are ``influential scientific
information,'' which the Bulletin defines as ``scientific information
the agency reasonably can determine will have, or does have, a clear
and substantial impact on important public policies or private sector
decisions.'' 70 FR 2664, 2667.
In response to OMB's Bulletin, DOE conducted formal peer reviews of
the energy conservation standards development process and the analyses
that are typically used and prepared a report describing that peer
review.\206\ Generation of this report involved a rigorous, formal, and
documented evaluation using objective criteria and qualified and
independent reviewers to make a judgment as to the technical/
scientific/business merit, the actual or anticipated results, and the
productivity and management effectiveness of programs and/or projects.
Because available data, models, and technological understanding have
changed since 2007, DOE has engaged with the National Academy of
Sciences to review DOE's analytical methodologies to ascertain whether
modifications are needed to improve DOE's analyses. DOE is in the
process of evaluating the resulting report.\207\
---------------------------------------------------------------------------
\206\ The 2007 ``Energy Conservation Standards Rulemaking Peer
Review Report'' is available at the following website: energy.gov/eere/buildings/downloads/energy-conservation-standards-rulemaking-peer-review-report-0 (last accessed Jan. 16, 2024).
\207\ The report is available at www.nationalacademies.org/our-work/review-of-methods-for-setting-building-and-equipment-performance-standards.
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M. Congressional Notification
As required by 5 U.S.C. 801, DOE will report to Congress on the
promulgation of this rule prior to its effective date. The report will
state that the Office of Information and Regulatory Affairs has
determined that the rule meets the criteria set forth in 5 U.S.C.
804(2).).
VII. Approval of the Office of the Secretary
The Secretary of Energy has approved publication of this final
rule.
List of Subjects in 10 CFR Part 431
Administrative practice and procedure, Confidential business
information, Energy conservation test procedures, Reporting and
recordkeeping requirements.
Signing Authority
This document of the Department of Energy was signed on April 3,
2024, by Jeffrey Marootian, Principal Deputy Assistant Secretary for
Energy Efficiency and Renewable Energy, pursuant to delegated authority
from the Secretary of Energy. That document with the original signature
and date is maintained by DOE. For administrative purposes only, and in
compliance with requirements of the Office of the Federal Register, the
undersigned DOE Federal Register Liaison Officer has been authorized to
sign and submit the document in electronic format for publication, as
an official document of the Department of Energy. This administrative
process in no way alters the legal effect of this document upon
publication in the Federal Register.
Signed in Washington, DC, on April 4, 2024.
Treena V. Garrett,
Federal Register Liaison Officer, U.S. Department of Energy.
For the reasons set forth in the preamble, DOE amends part 431 of
chapter II, of title 10 of the Code of Federal Regulations, as set
forth below:
[[Page 30039]]
PART 431--ENERGY EFFICIENCY PROGRAM FOR CERTAIN COMMERCIAL AND
INDUSTRIAL EQUIPMENT
0
1. The authority citation for part 431 continues to read as follows:
Authority: 42 U.S.C. 6291-6317; 28 U.S.C. 2461 note.
0
2. Amend Sec. 431.192 by:
0
a. Revising the definitions for ``Distribution transformer'', ``Drive
(isolation) transformer'', ``Nonventilated transformer'', ``Sealed
transformer'', and ``Special-impedance transformer'';
0
b. Adding in alphabetical order a definition for ``Submersible
distribution transformer''; and
0
c. Revising the definitions for ``Transformer with a tap range of 20
percent or more'' and ``Uninterruptible power supply transformer''.
The revisions and addition read as follows:
Sec. 431.192 Definitions.
* * * * *
Distribution transformer means a transformer that--
(1) Has an input line voltage of 34.5 kV or less;
(2) Has an output line voltage of 600 V or less;
(3) Is rated for operation at a frequency of 60 Hz; and
(4) Has a capacity of 10 kVA to 5000 kVA for liquid-immersed units
and 15 kVA to 5000 kVA for dry-type units; but
(5) The term ``distribution transformer'' does not include a
transformer that is an--
(i) Autotransformer;
(ii) Drive (isolation) transformer;
(iii) Grounding transformer;
(iv) Machine-tool (control) transformer;
(v) Nonventilated transformer;
(vi) Rectifier transformer;
(vii) Regulating transformer;
(viii) Sealed transformer;
(ix) Special-impedance transformer;
(x) Testing transformer;
(xi) Transformer with tap range of 20 percent or more;
(xii) Uninterruptible power supply transformer; or
(xiii) Welding transformer.
Drive (isolation) transformer means a transformer that:
(1) Isolates an electric motor from the line;
(2) Accommodates the added loads of drive-created harmonics;
(3) Is designed to withstand the additional mechanical stresses
resulting from an alternating current adjustable frequency motor drive
or a direct current motor drive; and
(4) Has a rated output voltage that is neither ``208Y/120'' nor
``480Y/277''.
* * * * *
Nonventilated transformer means a dry-type transformer constructed
so as to prevent external air circulation through the coils of the
transformer while operating at zero gauge pressure.
* * * * *
Sealed transformer means a dry-type transformer designed to remain
hermetically sealed under specified conditions of temperature and
pressure.
Special-impedance transformer means a transformer built to operate
at an impedance outside of the normal impedance range for that
transformer's kVA rating. The normal impedance range for each kVA
rating for liquid-immersed and dry-type transformers is shown in Tables
1 and 2, respectively.
Table 1 to the Definition o ``Special-Impedance Transformer''--Normal Impedance Ranges for Liquid-Immersed Transformers
--------------------------------------------------------------------------------------------------------------------------------------------------------
Single-phase transformers Three-phase transformers
--------------------------------------------------------------------------------------------------------------------------------------------------------
kVA Impedance (%) kVA Impedance (%)
--------------------------------------------------------------------------------------------------------------------------------------------------------
10 <= kVA < 50 1.0-4.5 15 <= kVA < 75 1.0-4.5
50 <= kVA < 250 1.5-4.5 75 <= kVA < 112.5 1.0-5.0
250 <= kVA < 500 1.5-6.0 112.5 <= kVA < 500 1.2-6.0
500 <= kVA < 667 1.5-7.0 500 <= kVA < 750 1.5-7.0
667 <= kVA <= 833 5.0-7.5 750 <= kVA <= 5000 5.0-7.5
--------------------------------------------------------------------------------------------------------------------------------------------------------
Table 2 to the Definition o ``Special-Impedance Transformer''--Normal Impedance Ranges for Dry-Type Transformers
--------------------------------------------------------------------------------------------------------------------------------------------------------
Single-phase transformers Three-phase transformers
--------------------------------------------------------------------------------------------------------------------------------------------------------
kVA Impedance (%) kVA Impedance (%)
--------------------------------------------------------------------------------------------------------------------------------------------------------
10 <= kVA < 50 1.0-4.5 15 <= kVA < 75 1.0-4.5
50 <= kVA < 250 1.5-4.5 75 <= kVA < 112.5 1.0-5.0
250 <= kVA < 500 1.5-6.0 112.5 <= kVA < 500 1.2-6.0
500 <= kVA < 667 1.5-7.0 500 <= kVA < 750 1.5-7.0
667 <= kVA <= 833 5.0-7.5 750 <= kVA <= 5000 5.0-7.5
--------------------------------------------------------------------------------------------------------------------------------------------------------
Submersible distribution transformer means a liquid-immersed
distribution transformer, so constructed as to be operable when fully
or partially submerged in water including the following features--
(1) Has sealed-tank construction; and
(2) Has the tank, cover, and all external appurtenances made of
corrosion-resistant material or with appropriate corrosion resistant
surface treatment to induce the components surface to be corrosion
resistant.
* * * * *
Transformer with tap range of 20 percent or more means a
transformer with multiple voltage taps, each capable of operating at
full, rated capacity (kVA), whose range, defined as the difference
between the highest voltage tap and the lowest voltage tap, is 20
percent or more of the highest voltage tap.
Uninterruptible power supply transformer means a transformer that
is used within an uninterruptible power system, which in turn supplies
power to
[[Page 30040]]
loads that are sensitive to power failure, power sages, over voltage,
switching transients, line notice, and other power quality factors. It
does not include distribution transformers at the input, output, or by-
pass of an uninterruptible power system.
* * * * *
0
3. Amend Sec. 431.196 by:
0
a. Revising paragraph (a)(2) and adding paragraph (a)(3);
0
b. Revising paragraph (b)(2) and adding paragraphs (b)(3) and (4);
0
c. Revising paragraph (c)(2) and adding paragraph (c)(3); and
0
d. Adding paragraph (e).
The revisions and additions read as follows:
Sec. 431.196 Energy conservation standards and their effective
dates.
(a) * * *
(2) The efficiency of a low-voltage, dry-type distribution
transformer manufactured on or after January 1, 2016, but before April
23, 2029, shall be no less than that required for the applicable kVA
rating in the following table. Low-voltage dry-type distribution
transformers with kVA ratings not appearing in the table shall have
their minimum efficiency level determined by linear interpolation of
the kVA and efficiency values immediately above and below that kVA
rating.
Table 2 to Paragraph (a)(1)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Single-phase Three-phase
--------------------------------------------------------------------------------------------------------------------------------------------------------
kVA kVA
--------------------------------------------------------------------------------------------------------------------------------------------------------
15 97.70 15 97.89
25 98.00 30 98.23
37.5 98.20 45 98.40
50 98.30 75 98.60
75 98.50 112.5 98.74
100 98.60 150 98.83
167 98.70 225 98.94
250 98.80 300 99.02
333 98.90 500 99.14
750 99.23
1000 99.28
--------------------------------------------------------------------------------------------------------------------------------------------------------
Note: All efficiency values are at 35 percent of nameplate-rated load, determined according to the DOE Test Method for Measuring the Energy Consumption
of Distribution Transformers under appendix A to this subpart K.
(3) The efficiency of a low-voltage dry-type distribution
transformer manufactured on or after April 23, 2029, shall be no less
than that required for their kVA rating in the following table. Low-
voltage dry-type distribution transformers with kVA ratings not
appearing in the table shall have their minimum efficiency level
determined by linear interpolation of the kVA and efficiency values
immediately above and below that kVA rating.
Table 3 to Paragraph (a)(3)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Single-phase Three-phase
--------------------------------------------------------------------------------------------------------------------------------------------------------
kVA Efficiency (%) kVA Efficiency (%)
--------------------------------------------------------------------------------------------------------------------------------------------------------
15 98.39 15 98.31
25 98.60 30 98.58
37.5 98.74 45 98.72
50 98.81 75 98.88
75 98.95 112.5 98.99
100 99.02 150 99.06
167 99.09 225 99.15
250 99.16 300 99.22
333 99.23 500 99.31
750 99.38
1000 99.42
--------------------------------------------------------------------------------------------------------------------------------------------------------
Note: All efficiency values are at 35 percent of nameplate-rated load, determined according to the DOE Test Method for Measuring the Energy Consumption
of Distribution Transformers under appendix A to this subpart K.
(b) * * *
(2) The efficiency of a liquid-immersed distribution transformer,
including submersible distribution transformers, manufactured on or
after January 1, 2016, but before April 23, 2029, shall be no less than
that required for their kVA rating in the following table. Liquid-
immersed distribution transformers, including submersible distribution
transformers, with kVA ratings not appearing in the table shall have
their minimum efficiency level determined by linear interpolation of
the kVA and efficiency values immediately above and below that kVA
rating.
[[Page 30041]]
Table 5 to Paragraph (b)(2)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Single-phase Three-phase
--------------------------------------------------------------------------------------------------------------------------------------------------------
kVA Efficiency (%) kVA Efficiency (%)
--------------------------------------------------------------------------------------------------------------------------------------------------------
10 98.70 15 98.65
15 98.82 30 98.83
25 98.95 45 98.92
37.5 99.05 75 99.03
50 99.11 112.5 99.11
75 99.19 150 99.16
100 99.25 225 99.23
167 99.33 300 99.27
250 99.39 500 99.35
333 99.43 750 99.40
500 99.49 1000 99.43
667 99.52 1500 99.48
833 99.55 2000 99.51
2500 99.53
--------------------------------------------------------------------------------------------------------------------------------------------------------
Note: All efficiency values are at 50 percent of nameplate-rated load, determined according to the DOE Test--Procedure, appendix A to this subpart K.
(3) The efficiency of a liquid-immersed distribution transformer,
that is not a submersible distribution transformer, manufactured on or
after April 23, 2029, shall be no less than that required for their kVA
rating in the following table. Liquid-immersed distribution
transformers with kVA ratings not appearing in the table shall have
their minimum efficiency level determined by linear interpolation of
the kVA and efficiency values immediately above and below that kVA
rating.
Table 6 to Paragraph (b)(3)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Single-phase Three-phase
--------------------------------------------------------------------------------------------------------------------------------------------------------
kVA Efficiency (%) kVA Efficiency (%)
--------------------------------------------------------------------------------------------------------------------------------------------------------
10 98.77 15 98.92
15 98.88 30 99.06
25 99.00 45 99.14
37.5 99.10 75 99.22
50 99.15 112.5 99.29
75 99.23 150 99.33
100 99.29 225 99.38
167 99.46 300 99.42
250 99.51 500 99.38
333 99.54 750 99.43
500 99.59 1000 99.46
667 99.62 1500 99.51
833 99.64 2000 99.53
2500 99.55
3750 99.54
5000 99.53
--------------------------------------------------------------------------------------------------------------------------------------------------------
Note: All efficiency values are at 50 percent of nameplate-rated load, determined according to the DOE Test Method for Measuring the Energy Consumption
of Distribution Transformers under appendix A to this subpart K.
(4) The efficiency of a submersible distribution transformer,
manufactured on or after April 23, 2029, shall be no less than that
required for their kVA rating in the following table. Submersible
distribution transformers with kVA ratings not appearing in the table
shall have their minimum efficiency level determined by linear
interpolation of the kVA and efficiency values immediately above and
below that kVA rating.
Table 7 to Paragraph (b)(4)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Single-phase Three-phase
--------------------------------------------------------------------------------------------------------------------------------------------------------
kVA Efficiency (%) kVA Efficiency (%)
--------------------------------------------------------------------------------------------------------------------------------------------------------
10 98.70 15 98.65
15 98.82 30 98.83
25 98.95 45 98.92
37.5 99.05 75 99.03
[[Page 30042]]
50 99.11 112.5 99.11
75 99.19 150 99.16
100 99.25 225 99.23
167 99.33 300 99.27
250 99.39 500 99.35
333 99.43 750 99.40
500 99.49 1000 99.43
667 99.52 1500 99.48
833 99.55 2000 99.51
2500 99.53
--------------------------------------------------------------------------------------------------------------------------------------------------------
Note: All efficiency values are at 50 percent of nameplate-rated load, determined according to the DOE Test--Procedure, appendix A to this subpart K.
(c) * * *
(2) The efficiency of a medium-voltage dry-type distribution
transformer manufactured on or after January 1, 2016, but before April
23, 2029, shall be no less than that required for their kVA and BIL
rating in the following table. Medium-voltage dry-type distribution
transformers with kVA ratings not appearing in the table shall have
their minimum efficiency level determined by linear interpolation of
the kVA and efficiency values immediately above and below that kVA
rating.
Table 9 to Paragraph (c)(2)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Single-phase Three-phase
---------------------------------------------------------- --------------------------------------------------------
BIL \1\ BIL
kVA ---------------------------------------------------------- kVA --------------------------------------------------------
20-45 kV 46-95 kV >=96 kV 20-45 kV 46-95 kV >=96 kV
---------------------------------------------------------- --------------------------------------------------------
Efficiency (%) Efficiency (%) Efficiency (%) Efficiency (%) Efficiency (%) Efficiency (%)
--------------------------------------------------------------------------------------------------------------------------------------------------------
15 98.10 97.86 .................. 15 97.50 97.18 .................
25 98.33 98.12 .................. 30 97.90 97.63 .................
37.5 98.49 98.30 .................. 45 98.10 97.86 .................
50 98.60 98.42 .................. 75 98.33 98.13 .................
75 98.73 98.57 98.53 112.5 98.52 98.36 .................
100 98.82 98.67 98.63 150 98.65 98.51 .................
167 98.96 98.83 98.80 225 98.82 98.69 98.57
250 99.07 98.95 98.91 300 98.93 98.81 98.69
333 99.14 99.03 98.99 500 99.09 98.99 98.89
500 99.22 99.12 99.09 750 99.21 99.12 99.02
667 99.27 99.18 99.15 1000 99.28 99.20 99.11
833 99.31 99.23 99.20 1500 99.37 99.30 99.21
................. ................. .................. 2000 99.43 99.36 99.28
................. ................. .................. 2500 99.47 99.41 99.33
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ BIL means basic impulse insulation level.
Note: All efficiency values are at 50 percent of nameplate rated load, determined according to the DOE Test Method for Measuring the Energy Consumption
of Distribution Transformers under appendix A to this subpart K.
(3) The efficiency of a medium-voltage dry-type distribution
transformer manufactured on or after April 23, 2029, shall be no less
than that required for their kVA and BIL rating in the following table.
Medium-voltage dry-type distribution transformers with kVA ratings not
appearing in the table shall have their minimum efficiency level
determined by linear interpolation of the kVA and efficiency values
immediately above and below that kVA rating.
Table 10 to Paragraph (c)(3)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Single-phase Three-phase
---------------------------------------------------------- --------------------------------------------------------
BIL \1\ BIL
kVA ---------------------------------------------------------- kVA --------------------------------------------------------
20-45 kV 46-95 kV >=96 kV 20-45 kV 46-95 kV >=96 kV
---------------------------------------------------------- --------------------------------------------------------
Efficiency (%) Efficiency (%) Efficiency (%) Efficiency (%) Efficiency (%) Efficiency (%)
--------------------------------------------------------------------------------------------------------------------------------------------------------
15 98.29 98.07 .................. 15 97.75 97.46 .................
[[Page 30043]]
25 98.50 98.31 .................. 30 98.11 97.87 .................
37.5 98.64 98.47 .................. 45 98.29 98.07 .................
50 98.74 98.58 .................. 75 98.50 98.32 .................
75 98.86 98.71 98.68 112.5 98.67 98.52 .................
100 98.94 98.80 98.77 150 98.79 98.66 .................
167 99.06 98.95 98.92 225 98.94 98.82 98.71
250 99.16 99.06 99.02 300 99.04 98.93 98.82
333 99.23 99.13 99.09 500 99.18 99.09 99.00
500 99.30 99.21 99.18 750 99.29 99.21 99.12
667 99.34 99.26 99.24 1000 99.35 99.28 99.20
833 99.38 99.31 99.28 1500 99.43 99.37 99.29
................. ................. .................. 2000 99.49 99.42 99.35
................. ................. .................. 2500 99.52 99.47 99.40
................. ................. .................. 3750 99.50 99.44 99.40
................. ................. .................. 5000 99.48 99.43 99.39
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ BIL means basic impulse insulation level/
Note: All efficiency values are at 50 percent of nameplate rated load, determined according to the DOE Test Method for Measuring the Energy Consumption
of Distribution Transformers under appendix A to this subpart K.
* * * * *
(e) Severability. The provisions of paragraphs (a) through (d) of
this section are separate and severable from one another. Should a
court of competent jurisdiction hold any provision(s) of this section
to be stayed or invalid, such action shall not affect any other
provision of this section.
Note: The following letter will not appear in the Code of
Federal Regulations.
U.S. DEPARTMENT OF JUSTICE
Antitrust Division
RFK Main Justice Building
950 Pennsylvania Avenue NW
Washington, DC 20530-0001
March 20, 2023
Ami Grace-Tardy
Assistant General Counsel for Legislation, Regulation and Energy
Efficiency
U.S. Department of Energy
Washington, DC 20585
[email protected]
Re: Energy Conservation Standards for Distribution Transformers, DOE
Docket No. EERE-2019-BT-STD-0018
Dear Assistant General Counsel Grace-Tardy:
I am responding to your January 19, 2023 letter seeking the
views of the Attorney General about the potential impact on
competition of proposed energy conservation standards for
distribution transformers.
Your request was submitted under Section 325(o)(2)(B)(i)(V) of
the Energy Policy and Conservation Act, as amended (ECPA), 42 U.S.C.
6295(o)(2)(B)(i)(V), which requires the Attorney General to make a
determination of the impact of any lessening of competition that is
likely to result from the imposition of proposed energy conservation
standards. The Attorney General's responsibility for responding to
requests from other departments about the effect of a program on
competition has been delegated to the Assistant Attorney General for
the Antitrust Division in 28 CFR 0.40(g). The Assistant Attorney
General for the Antitrust Division has authorized me, as the Policy
Director for the Antitrust Division, to provide the Antitrust
Division's views regarding the potential impact on competition of
proposed energy conservation standards on his behalf.
In conducting its analysis, the Antitrust Division examines
whether a proposed standard may lessen competition, for example, by
substantially limiting consumer choice, by placing certain
manufacturers at an unjustified competitive disadvantage, or by
inducing avoidable inefficiencies in production or distribution of
particular products. A lessening of competition could result in
higher prices to manufacturers and consumers.
We have reviewed the proposed standards contained in the Notice
of proposed rulemaking and request for comment (88 FR 1722, January
11, 2023) and the related Technical Support Document. We have also
reviewed public comments and information presented at the Webinar of
the Public Meetings held on September 29, 2021 and February 16,
2023.
Based on this review, our conclusion is that the proposed energy
conservation standards for distribution transformers are unlikely to
have a significant adverse impact on competition.
Sincerely,
David G.B. Lawrence,
Policy Director.
[FR Doc. 2024-07480 Filed 4-19-24; 8:45 am]
BILLING CODE 6450-01-P