[Federal Register Volume 89, Number 148 (Thursday, August 1, 2024)]
[Proposed Rules]
[Pages 63030-63071]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2024-16718]
[[Page 63029]]
Vol. 89
Thursday,
No. 148
August 1, 2024
Part IV
Environmental Protection Agency
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40 CFR Part 52
Air Plan Partial Approval and Partial Disapproval; Wyoming; Regional
Haze Plan for the Second Implementation Period; Proposed Rule
Federal Register / Vol. 89 , No. 148 / Thursday, August 1, 2024 /
Proposed Rules
[[Page 63030]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 52
[EPA-R08-OAR-2023-0489; FRL-12135-01-R8]
Air Plan Partial Approval and Partial Disapproval; Wyoming;
Regional Haze Plan for the Second Implementation Period
AGENCY: Environmental Protection Agency (EPA).
ACTION: Proposed rule.
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SUMMARY: The Environmental Protection Agency (EPA) is proposing to
partially approve and partially disapprove the regional haze state
implementation plan (SIP) submission submitted by the State of Wyoming
on August 10, 2022 (Wyoming's 2022 SIP submission) under the Clean Air
Act (CAA) and the EPA's Regional Haze Rule (RHR) for the program's
second implementation period. Wyoming's 2022 SIP submission addresses
the requirement that states revise their long-term strategies every
implementation period to make reasonable progress towards the national
goal of preventing any future, and remedying any existing,
anthropogenic impairment of visibility, including regional haze, in
mandatory Class I Federal areas. Wyoming's 2022 SIP submission also
addresses other applicable requirements for the second implementation
period of the regional haze program. The EPA is taking this action
pursuant to the CAA.
DATES: Written comments must be received on or before September 3,
2024.
ADDRESSES: Submit your comments, identified by Docket ID No. EPA-R08-
OAR-2023-0489, to the Federal Rulemaking Portal: https://www.regulations.gov. Follow the online instructions for submitting
comments. Once submitted, comments cannot be edited or removed from
https://www.regulations.gov. The EPA may publish any comment received
to its public docket. Do not submit electronically any information you
consider to be Confidential Business Information (CBI) or other
information whose disclosure is restricted by statute. Multimedia
submissions (audio, video, etc.) must be accompanied by a written
comment. The written comment is considered the official comment and
should include discussion of all points you wish to make. The EPA will
generally not consider comments or comment contents located outside of
the primary submission (i.e., on the web, cloud, or other file sharing
system). For additional submission methods, the full EPA public comment
policy, information about CBI or multimedia submissions, and general
guidance on making effective comments, please visit https://www2.epa.gov/dockets/commenting-epa-dockets.
Docket: All documents in the docket are listed in the https://www.regulations.gov index. Although listed in the index, some
information is not publicly available, e.g., CBI or other information
whose disclosure is restricted by statute. Certain other material, such
as copyrighted material, will be publicly available only in hard copy.
Publicly available docket materials are available electronically in
https://www.regulations.gov. Please email or call the person listed in
the FOR FURTHER INFORMATION CONTACT section if you need to make
alternative arrangements for access to the docket.
FOR FURTHER INFORMATION CONTACT: Jaslyn Dobrahner, Air and Radiation
Division, EPA, Region 8, Mailcode 8ARD-IO, 1595 Wynkoop Street, Denver,
Colorado, 80202-1129, telephone number: (303) 312-6252; email address:
[email protected].
SUPPLEMENTARY INFORMATION: Throughout this document wherever ``we,''
``us,'' or ``our'' is used, we mean the EPA.
Table of Contents
I. What action is the EPA proposing?
II. Background and Requirements for Regional Haze Plans
A. Regional Haze
B. Roles of Agencies in Addressing Regional Haze
C. Status of Wyoming's Regional Haze Plan for the First
Implementation Period
D. Wyoming's Regional Haze Plan for the Second Implementation
Period
III. Requirements for Regional Haze Plans for the Second
Implementation Period
A. Identification of Class I Areas
B. Calculation of Baseline, Current, and Natural Visibility
Conditions; Progress to Date; and Uniform Rate of Progress
C. Long-Term Strategy for Regional Haze
D. Reasonable Progress Goals
E. Monitoring Strategy and Other State Implementation Plan
Requirements
F. Requirements for Periodic Reports Describing Progress Towards
the Reasonable Progress Goals
G. Requirements for State and Federal Land Manager Coordination
IV. The EPA's Evaluation of Wyoming's Regional Haze Plan for the
Second Implementation Period
A. Identification of Class I Areas
B. Calculation of Baseline, Current, and Natural Visibility
Conditions; Progress to Date; and Uniform Rate of Progress for Class
I Areas Within the State
C. Long-Term Strategy
1. Summary of Wyoming's 2022 SIP Submission
a. PacifiCorp--Jim Bridger Power Plant
b. PacifiCorp--Naughton Power Plant
c. Basin Electric--Laramie River Station Power Plant
d. PacifiCorp--Dave Johnston Power Plant
e. Genesis Alkali--Westvaco
f. Mountain Cement Company--Laramie Portland Cement
g. PacifiCorp--Wyodak Power Plant
h. TATA Chemicals--Green River Works
i. Contango Resources, Inc.--Elk Basin Gas Plant
j. Genesis Alkali--Granger Soda Ash Facility
k. Burlington Resources--Lost Cabin Gas Plant
l. Dyno Nobel Inc.--Cheyenne Fertilizer Facility
m. Summary of Wyoming's Reasons for Concluding That No
Additional Emission Reduction Measures Are Necessary To Make
Reasonable Progress
2. The EPA's Evaluation
a. Failure To Perform a Four-Factor Analysis To Analyze Control
Measures for Selected Sources To Determine What Is Necessary To Make
Reasonable Progress
i. Reliance on Existing Controls Without Adequate Technical
Documentation To Avoid Four-Factor Analysis of Sources That May
Affect Visibility at Class I Areas
ii. Reliance on Unenforceable Source Retirements To Avoid Four-
Factor Analysis
iii. Other Improper Rationales for Not Performing Four-Factor
Analyses
b. Failure To Document the Technical Basis of the State's
Determination of the Emission Reduction Measures Necessary To Make
Reasonable Progress
i. Laramie Portland Cement
ii. Lost Cabin Gas Plant
iii. Elk Basin Gas Plant, Dave Johnston Unit 4, and Green River
Works
c. Sources Where the State Unreasonably Rejected Potential
Emission Reduction Measures
d. Other Unjustified Reasons for Rejecting All Additional
Emission Reduction Measures
e. Other Long-Term Strategy Requirements (40 CFR
51.308(f)(2)(ii)-(iv))
D. Reasonable Progress Goals
E. Reasonably Attributable Visibility Impairment (RAVI)
F. Monitoring Strategy and Other State Implementation Plan
Requirements
G. Requirements for Periodic Reports Describing Progress Towards
the Reasonable Progress Goals
H. Requirements for State and Federal Land Manager Coordination
V. Proposed Action
VI. Environmental Justice
VII. Statutory and Executive Order Reviews
I. What action is the EPA proposing?
The EPA is proposing to partially approve and partially disapprove
a SIP submission submitted by the State of Wyoming to the EPA on August
10,
[[Page 63031]]
2022, addressing the requirements of the second implementation period
of the RHR. Specifically, the EPA is proposing approval for the
portions of Wyoming's 2022 SIP submission relating to 40 CFR
51.308(f)(1): calculations of baseline, current, and natural visibility
conditions, progress to date, and the uniform rate of progress; 40 CFR
51.308(f)(4): reasonably attributable visibility impairment; 40 CFR
51.308(f)(5) and 40 CFR 51.308(g): progress report requirements; and 40
CFR 51.308(f)(6): monitoring strategy and other implementation plan
requirements. For the reasons described in this document, the EPA is
proposing disapproval for the remainder of Wyoming's 2022 SIP
submission, which addresses 40 CFR 51.308(f)(2): long-term strategy; 40
CFR 51.308(f)(3): reasonable progress goals; and 40 CFR 51.308(i): FLM
consultation. Consistent with section 110(k)(3) of the CAA, the EPA may
partially approve portions of a submittal if those elements meet all
applicable requirements and may disapprove the remainder so long as the
elements are fully separable.\1\
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\1\ See CAA section 110(k)(3) and July 1992 EPA memorandum
titled ``Processing of State Implementation Plan (SIP) Submittals''
from John Calcagni, at https://www.epa.gov/sites/default/files/2015-07/documents/procsip.pdf.
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II. Background and Requirements for Regional Haze Plans
A. Regional Haze
In the 1977 CAA amendments, Congress created a program for
protecting visibility in the nation's mandatory Class I Federal areas,
which include certain national parks and wilderness areas.\2\ CAA
section 169A. The CAA establishes as a national goal the ``prevention
of any future, and the remedying of any existing, impairment of
visibility in mandatory Class I Federal areas which impairment results
from manmade air pollution.'' CAA section 169A(a)(1). The CAA further
directs the EPA to promulgate regulations to assure reasonable progress
toward meeting this national goal. CAA section 169A(a)(4). On December
2, 1980, the EPA promulgated regulations to address visibility
impairment in mandatory Class I Federal areas (hereinafter referred to
as ``Class I areas'') that is ``reasonably attributable'' to a single
source or small group of sources. (45 FR 80084, December 2, 1980).
These regulations, codified at 40 CFR 51.300 through 51.307,
represented the first phase of the EPA's efforts to address visibility
impairment. In 1990, Congress added section 169B to the CAA to further
address visibility impairment, specifically, impairment from regional
haze. CAA section 169B. The EPA promulgated the Regional Haze Rule
(RHR), codified at 40 CFR 51.308 and 51.309,\3\ on July 1, 1999. (64 FR
35714, July 1, 1999). On January 10, 2017, the EPA promulgated
additional regulations that address visibility impairment for the
second and subsequent implementation periods (82 FR 3078, January 10,
2017). These regional haze regulations are a central component of the
EPA's comprehensive visibility protection program for Class I areas.
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\2\ Areas statutorily designated as mandatory Class I Federal
areas consist of national parks exceeding 6,000 acres, wilderness
areas and national memorial parks exceeding 5,000 acres, and all
international parks that were in existence on August 7, 1977. CAA
section 162(a). There are 156 mandatory Class I areas. The list of
areas to which the requirements of the visibility protection program
apply is in 40 CFR part 81, subpart D.
\3\ In addition to the generally applicable regional haze
provisions at 40 CFR 51.308, the EPA also promulgated regulations
specific to addressing regional haze visibility impairment in Class
I areas on the Colorado Plateau at 40 CFR 51.309. The requirements
under 40 CFR 51.309(d)(4) contain general requirements pertaining to
stationary sources and market trading and allow states to adopt
alternatives to the point source application of BART.
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Regional haze is visibility impairment that is produced by a
multitude of anthropogenic sources and activities that are located
across a broad geographic area and that emit pollutants that impair
visibility. Visibility impairing pollutants include fine and coarse
particulate matter (PM) (e.g., sulfates, nitrates, organic carbon,
elemental carbon, and soil dust) and their precursors (e.g., sulfur
dioxide (SO2), nitrogen oxides (NOX), and, in
some cases, volatile organic compounds (VOC) and ammonia
(NH3)). Fine particle precursors react in the atmosphere to
form fine particulate matter (PM2.5), which impairs
visibility by scattering and absorbing light. Visibility impairment
reduces the perception of clarity and color, as well as visible
distance.\4\
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\4\ There are several ways to measure the amount of visibility
impairment, i.e., haze. One such measurement is the deciview, which
is the principal metric used by the RHR. Under many circumstances, a
change in one deciview will be perceived by the human eye to be the
same on both clear and hazy days. The deciview is unitless. It is
proportional to the logarithm of the atmospheric extinction of
light, which is the perceived dimming of light due to its being
scattered and absorbed as it passes through the atmosphere.
Atmospheric light extinction (b\ext\) is a metric used for
expressing visibility and is measured in inverse megameters
(Mm-1). The EPA's Guidance on Regional Haze State
Implementation Plans for the Second Implementation Period (``2019
Guidance'') offers the flexibility for the use of light extinction
in certain cases. Light extinction can be simpler to use in
calculations than deciviews, since it is not a logarithmic function.
See, e.g., 2019 Guidance at 16, 19, https://www.epa.gov/visibility/guidance-regional-haze-state-implementation-plans-second-implementation-period, The EPA Office of Air Quality Planning and
Standards, Research Triangle Park (August 20, 2019). The formula for
the deciview is 10 ln (bext)/10 Mm-1). 40 CFR 51.301.
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To address regional haze visibility impairment, the 1999 RHR
established an iterative planning process that requires both states in
which Class I areas are located and states ``the emissions from which
may reasonably be anticipated to cause or contribute to any impairment
of visibility'' in a Class I area to periodically submit SIP revisions
to address such impairment. CAA section 169A(b)(2); \5\ see also 40 CFR
51.308(b), (f) (establishing submission dates for iterative regional
haze SIP revisions); (64 FR at 35768, July 1, 1999). Under the CAA,
each SIP submission must contain ``a long-term (ten to fifteen years)
strategy for making reasonable progress toward meeting the national
goal,'' CAA section 169A(b)(2)(B); the initial round of SIP submissions
also had to address the statutory requirement that certain older,
larger sources of visibility impairing pollutants install and operate
the best available retrofit technology (BART). CAA section
169A(b)(2)(A); 40 CFR 51.308(d) and (e). States' first regional haze
SIPs were due by December 17, 2007, 40 CFR 51.308(b), with subsequent
SIP submissions containing updated long-term strategies originally due
July 31, 2018, and every ten years thereafter. (64 FR at 35768, July 1,
1999). The EPA established in the 1999 RHR that all states either have
Class I areas within their borders or ``contain sources whose emissions
are reasonably anticipated to contribute to regional haze in a Class I
area''; therefore, all states must submit regional haze SIPs.\6\ Id. at
35721.
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\5\ The RHR expresses the statutory requirement for states to
submit plans addressing out-of-state Class I areas by providing that
states must address visibility impairment ``in each mandatory Class
I Federal area located outside the State that may be affected by
emissions from within the State.'' 40 CFR 51.308(d), (f).
\6\ In addition to each of the fifty states, the EPA also
concluded that the Virgin Islands and District of Columbia must also
submit regional haze SIPs because they either contain a Class I area
or contain sources whose emissions are reasonably anticipated to
contribute regional haze in a Class I area. See 40 CFR 51.300(b),
(d)(3).
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Much of the focus in the first implementation period of the
regional haze program, which ran from 2007 through 2018, was on
satisfying states' BART obligations. First implementation period SIPs
were additionally required to contain long-term strategies for making
reasonable progress toward the national visibility goal, of which BART
is one component. The core required
[[Page 63032]]
elements for the first implementation period SIPs (other than BART) are
laid out in 40 CFR 51.308(d). Those provisions required that states
containing Class I areas establish reasonable progress goals (RPGs)
that are measured in deciviews and reflect the anticipated visibility
conditions at the end of the implementation period including from
implementation of states' long-term strategies. The first planning
period \7\ RPGs were required to provide for an improvement in
visibility for the most impaired days over the period of the
implementation plan and ensure no degradation in visibility for the
least impaired days over the same period. In establishing the RPGs for
any Class I area in a state, the state was required to consider four
statutory factors: the costs of compliance, the time necessary for
compliance, the energy and non-air quality environmental impacts of
compliance, and the remaining useful life of any potentially affected
sources. CAA section 169A(g)(1); 40 CFR 51.308(d)(1).
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\7\ The EPA uses the terms ``implementation period'' and
``planning period'' interchangeably.
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States were also required to calculate baseline (using the five-
year period of 2000-2004) and natural visibility conditions (i.e.,
visibility conditions without anthropogenic visibility impairment) for
each Class I area, and to calculate the linear rate of progress needed
to attain natural visibility conditions, assuming a starting point of
baseline visibility conditions in 2004 and ending with natural
conditions in 2064. This linear interpolation is known as the uniform
rate of progress (URP) and is used as a tracking metric to help states
assess the amount of progress they are making towards the national
visibility goal over time in each Class I area.\8\ 40 CFR
51.308(d)(1)(i)(B), (d)(2). The 1999 RHR also provided that states'
long-term strategies must include the ``enforceable emissions
limitations, compliance schedules, and other measures as necessary to
achieve the reasonable progress goals.'' 40 CFR 51.308(d)(3). In
establishing their long-term strategies, states are required to consult
with other states that also contribute to visibility impairment in a
given Class I area and include all measures necessary to obtain their
shares of the emission reductions needed to meet the RPGs. 40 CFR
51.308(d)(3)(i), (ii). Section 51.308(d) also contains seven additional
factors states must consider in formulating their long-term strategies,
40 CFR 51.308(d)(3)(v), as well as provisions governing monitoring and
other implementation plan requirements. 40 CFR 51.308(d)(4). Finally,
the 1999 RHR required states to submit periodic progress reports--SIP
revisions due every five years that contain information on states'
implementation of their regional haze plans and an assessment of
whether anything additional is needed to make reasonable progress, see
40 CFR 51.308(g), (h)--and to consult with the Federal Land Manager(s)
\9\ (FLMs) responsible for each Class I area according to the
requirements in CAA section 169A(d) and 40 CFR 51.308(i).
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\8\ The EPA established the URP framework in the 1999 RHR to
provide ``an equitable analytical approach'' to assessing the rate
of visibility improvement at Class I areas across the country. The
starting point for the URP analysis is 2004 and the endpoint was
calculated based on the amount of visibility improvement that was
anticipated to result from implementation of existing CAA programs
over the period from the mid-1990s to approximately 2005. Assuming
this rate of progress would continue into the future, the EPA
determined that natural visibility conditions would be reached in 60
years, or 2064 (60 years from the baseline starting point of 2004).
However, the EPA did not establish 2064 as the year by which the
national goal must be reached. 64 FR at 35731-32. That is, the URP
and the 2064 date are not enforceable targets but are rather tools
that ``allow for analytical comparisons between the rate of progress
that would be achieved by the state's chosen set of control measures
and the URP.'' (82 FR 3078, 3084, January 10, 2017).
\9\ The EPA's regulations define ``Federal Land Manager'' as
``the Secretary of the department with authority over the Federal
Class I area (or the Secretary's designee) or, with respect to
Roosevelt-Campobello International Park, the Chairman of the
Roosevelt-Campobello International Park Commission.'' 40 CFR 51.301.
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On January 10, 2017, the EPA promulgated revisions to the RHR, (82
FR 3078, January 10, 2017), that apply for the second and subsequent
implementation periods. The 2017 rulemaking made several changes to the
requirements for regional haze SIPs to clarify states' obligations and
streamline certain regional haze requirements. The revisions to the
regional haze program for the second and subsequent implementation
periods focused on the requirement that states' SIPs contain long-term
strategies for making reasonable progress towards the national
visibility goal. The reasonable progress requirements as revised in the
2017 rulemaking (referred to here as the 2017 RHR Revisions) are
codified at 40 CFR 51.308(f). Among other changes, the 2017 RHR
Revisions adjusted the deadline for states to submit their second
implementation period SIPs from July 31, 2018, to July 31, 2021,
clarified the order of analysis and the relationship between RPGs and
the long-term strategy, and focused on making visibility improvements
on the days with the most anthropogenic visibility impairment, as
opposed to the days with the most visibility impairment overall. The
EPA also revised requirements of the visibility protection program
related to periodic progress reports and FLM consultation. The specific
requirements applicable to second implementation period regional haze
SIP submissions are addressed in detail below.
The EPA provided guidance to the states for their second
implementation period SIP submissions in the preamble to the 2017 RHR
Revisions as well as in subsequent, stand-alone guidance documents. In
August 2019, the EPA issued ``Guidance on Regional Haze State
Implementation Plans for the Second Implementation Period'' (``2019
Guidance'').\10\ On July 8, 2021, the EPA issued a memorandum
containing ``Clarifications Regarding Regional Haze State
Implementation Plans for the Second Implementation Period'' (``2021
Clarifications Memo'').\11\ Additionally, the EPA further clarified the
recommended procedures for processing ambient visibility data and
optionally adjusting the URP to account for international anthropogenic
and prescribed fire impacts in two technical guidance documents: the
December 2018 ``Technical Guidance on Tracking Visibility Progress for
the Second Implementation Period of the Regional Haze Program'' (``2018
Visibility Tracking Guidance''),\12\ and the June 2020 ``Recommendation
for the Use of Patched and Substituted Data and Clarification of Data
Completeness for Tracking Visibility Progress for the Second
Implementation Period of the Regional Haze Program'' and associated
Technical Addendum (``2020 Data Completeness Memo'').\13\
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\10\ Guidance on Regional Haze State Implementation Plans for
the Second Implementation Period. https://www.epa.gov/visibility/guidance-regional-haze-state-implementation-plans-second-implementation-period. The EPA Office of Air Quality Planning and
Standards, Research Triangle Park (August 20, 2019).
\11\ Clarifications Regarding Regional Haze State Implementation
Plans for the Second Implementation Period. https://www.epa.gov/system/files/documents/2021-07/clarifications-regarding-regional-haze-state-implementation-plans-for-the-second-implementation-period.pdf. The EPA Office of Air Quality Planning and Standards,
Research Triangle Park (July 8, 2021).
\12\ Technical Guidance on Tracking Visibility Progress for the
Second Implementation Period of the Regional Haze Program. https://www.epa.gov/visibility/technical-guidance-tracking-visibility-progress-second-implementation-period-regional. The EPA Office of
Air Quality Planning and Standards, Research Triangle Park.
(December 20, 2018).
\13\ Recommendation for the Use of Patched and Substituted Data
and Clarification of Data Completeness for Tracking Visibility
Progress for the Second Implementation Period of the Regional Haze
Program. https://www.epa.gov/visibility/memo-and-technical-addendum-ambient-data-usage-and-completeness-regional-haze-program. The EPA
Office of Air Quality Planning and Standards, Research Triangle Park
(June 3, 2020).
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As explained in the 2021 Clarifications Memo, the EPA intends the
second implementation period of the regional haze program to secure
meaningful reductions in visibility impairing pollutants that build on
the significant progress states have achieved to date. The Agency also
recognizes that analyses regarding reasonable progress are state-
specific and that, based on states' and sources' individual
circumstances, what constitutes reasonable reductions in visibility
impairing pollutants will vary from state-to-state. While there exist
many opportunities for states to leverage both ongoing and upcoming
emission reductions under other CAA programs, the Agency expects states
to undertake rigorous reasonable progress analyses that identify
further opportunities to advance the national visibility goal
consistent with the statutory and regulatory requirements. See
generally 2021 Clarifications Memo. This is consistent with Congress's
determination that a visibility protection program is needed in
addition to the CAA's National Ambient Air Quality Standards and
Prevention of Significant Deterioration programs, as further emission
reductions may be necessary to adequately protect visibility in Class I
areas throughout the country.\14\
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\14\ See, e.g., H.R. Rep. No. 95-294 at 205 (``In determining
how to best remedy the growing visibility problem in these areas of
great scenic importance, the committee realizes that as a matter of
equity, the national ambient air quality standards cannot be revised
to adequately protect visibility in all areas of the country.''),
(``the mandatory Class I increments of [the PSD program] do not
adequately protect visibility in Class I areas'').
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B. Roles of Agencies in Addressing Regional Haze
Because the air pollutants and pollution affecting visibility in
Class I areas can be transported over long distances, successful
implementation of the regional haze program requires long-term,
regional coordination among multiple jurisdictions and agencies that
have responsibility for Class I areas and the emissions that impact
visibility in those areas. To address regional haze, states need to
develop strategies in coordination with one another, considering the
effect of emissions from one jurisdiction on the air quality in
another. Five regional planning organizations (RPOs),\15\ which include
representation from state and Tribal governments, the EPA, and FLMs,
were developed in the lead-up to the first implementation period to
address regional haze. RPOs evaluate technical information to better
understand how emissions from state and tribal land impact Class I
areas across the country, pursue the development of regional strategies
to reduce emissions of particulate matter and other pollutants leading
to regional haze, and help states meet the consultation requirements of
the RHR.
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\15\ RPOs are sometimes also referred to as ``multi-
jurisdictional organizations,'' or MJOs. For the purposes of this
document, the terms RPO and MJO are synonymous.
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The Western Regional Air Partnership (WRAP), one of the five
regional planning organizations described in the previous paragraph, is
a collaborative effort of state governments, local air agencies, tribal
governments, and various federal agencies established to initiate and
coordinate activities associated with the management of regional haze,
visibility, and other air quality issues in the Western United States.
Members include the states of Alaska, Arizona, California, Colorado,
Hawaii, Idaho, Montana, Nevada, New Mexico, North Dakota, Oregon, South
Dakota, Utah, Washington, Wyoming, and 28 tribal governments.\16\ The
federal partner members of WRAP are the EPA, U.S. National Parks
Service (NPS), U.S. Fish and Wildlife Service (USFWS), U.S. Forest
Service (USFS), and the Bureau of Land Management (BLM).
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\16\ A full list of WRAP members is available at https://www.westar.org/wrap-council-members/.
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The WRAP membership formed a workgroup to develop a planning
framework for state regional haze second planning period SIPs. Based on
emissions and monitoring data supplied by its membership, WRAP produced
a technical system to support regional modeling of visibility impacts
at Class I areas across the West. The WRAP Technical Support System
consolidated air quality monitoring data, meteorological and receptor
modeling data analyses, emissions inventories and projections, and
gridded air quality/visibility regional modeling results. The Technical
Support System is accessible by member states and allows for the
creation of maps, figures, and tables to export and use in state plan
development. It also maintains the original source data for
verification and further analysis.
C. Status of Wyoming's Regional Haze Plan for the First Implementation
Period
The CAA requires that regional haze plans for the first
implementation period (2008 through 2018) include, among other things,
a long-term strategy for making reasonable progress and BART
requirements for certain older stationary sources, where
applicable.\17\ In 2011 and 2012, Wyoming submitted first
implementation period regional haze SIP submissions addressing the
requirements of 40 CFR 51.309, which superseded its regional haze SIP
submissions from 2003, 2004, and 2008.\18\ On December 12, 2012, the
EPA approved the 2011 and 2012 SIP submissions as meeting the
requirements of the CAA and the RHR, with the exception of 40 CFR
51.309(d)(4)(vii) and 40 CFR 51.309(g).\19\ The EPA then issued a final
rule in 2014 (2014 final rule) partially approving and partially
disapproving the 2011 SIP submission under 40 CFR 51.309(g) and
promulgating a FIP for the disapproved portions (together referred to
as the regional haze implementation plan).\20\
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\17\ Requirements for regional haze SIPs for the first
implementation period are also contained in CAA section 169A(b)(2).
The 1999 Regional Haze Rule provided two paths for states to address
regional haze in the first implementation period. Most states must
follow 40 CFR 51.308(d) and (e), which require states to perform
individual point source BART determinations and evaluate the need
for other control strategies. Additionally, the requirements for
addressing regional haze visibility impairment in the sixteen Class
I areas covered by the Grand Canyon Visibility Transport Commission
are found in 40 CFR 51.309(d)(4), which contains general
requirements pertaining to stationary sources and market trading and
allows states to adopt alternatives to the point source application
of BART. See also 40 CFR 51.308(b). States with Class I areas
covered by the Grand Canyon Visibility Transport Commission could
choose to submit a regional haze SIP under 40 CFR 51.308 or 40 CFR
51.309.
\18\ These SIP submissions were submitted on January 12, 2011;
April 19, 2012; December 24, 2003; May 27, 2004; and November 21,
2008.
\19\ 77 FR 73926 (December 12, 2012).
\20\ 79 FR 5032 (January 30, 2014).
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Several parties filed petitions for review of the 2014 final rule
in the U.S. Court of Appeals for the Tenth Circuit, challenging the
portions of the rule related to NOX BART determinations for
several facilities.\21\ The parties settled the challenges regarding
Laramie River Station Units 1-3 \22\ and Dave Johnston Unit 3. The
Court ruled on the remaining issues in 2023. It upheld the EPA's
approval of Wyoming's NOX BART determination for Naughton
Units 1 and 2 and vacated and remanded the EPA's disapproval of
Wyoming's NOX
[[Page 63034]]
BART determination (and the EPA's subsequent promulgation of a FIP
emission limit) for Wyodak power plant.\23\
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\21\ Basin Electric Cooperative v. EPA, No. 14-9533 (10th Cir.);
Wyoming v. EPA, No. 14-9529 (10th Cir.); PacifiCorp v. EPA, No. 14-
9534 (10th Cir.); Powder River Basin Resource Council, et al. v.
EPA, No. 14-9530 (10th Cir.).
\22\ Following that settlement, on May 20, 2019, the EPA
approved SIP revisions and revised the FIP to: (1) modify the
SO2 emissions reporting requirements for Laramie River
Station Units 1 and 2; (2) revise the NOX emission limits
for Laramie River Station Units 1, 2 and 3; and (3) establish an
SO2 emission limit averaged annually across Laramie River
Station Units 1 and 2. 84 FR 22711 (May 20, 2019).
\23\ Wyoming v. EPA, 78 F.4th 1171, 1175, 1181, 1183 (10th Cir.
2023).
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On November 28, 2017, Wyoming submitted its first progress report
SIP submission. It detailed progress made toward achieving reasonable
progress for visibility improvement and included a determination of
adequacy of the State's regional haze implementation plan to meet
reasonable progress goals. In 2020, we approved Wyoming's progress
report SIP submission.\24\
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\24\ 85 FR 21341 (April 17, 2020) (proposed rule); 85 FR 38325
(June 26, 2020) (final rule).
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In addition, in 2019, we approved an additional first
implementation period SIP submission regarding BART requirements for
Naughton Unit 3.\25\ On April 10, 2024, we proposed to approve
additional revisions for Jim Bridger Power Plant that Wyoming submitted
for the first implementation period regional haze SIP.\26\
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\25\ 84 FR 10433 (March 21, 2019).
\26\ 89 FR 25200 (April 10, 2024). The EPA has not yet issued a
final rule.
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D. Wyoming's Regional Haze Plan for the Second Implementation Period
On August 10, 2022, Wyoming submitted a SIP submission to address
its regional haze obligations for the second implementation period
(2018-2028). Wyoming's 2022 SIP submission contains the State's long-
term strategy to address regional haze visibility impairment for each
Class I area within the State and each Class I area outside the State
that may be affected by emissions from the State. In developing its
long-term strategy, the State examined the need to implement additional
enforceable emission limitations, compliance schedules, and other
measures that are necessary to make reasonable progress since the first
implementation period. Specifically, Wyoming's 2022 SIP submission
contains an assessment of visibility progress made at Class I areas
since the first implementation period and a long-term strategy to
address regional haze visibility impairment at the 23 Class I areas the
State identified, including: Wyoming's selection of sources that may
affect visibility in Class I areas within the State and outside the
State for four-factor analysis; its evaluation of the selected sources
to determine what emission reduction measures constitute reasonable
progress for the long-term strategy; regional scale modeling of the
State's long-term strategy to set reasonable progress goals for 2028;
and ultimately, Wyoming's determinations on what control measures are
necessary for the long-term strategy to address regional haze
visibility impairment in the 23 Class I areas. The State concluded that
no additional emission reduction measures for any Wyoming facilities
are required for the second implementation period under its long-term
strategy.
III. Requirements for Regional Haze Plans for the Second Implementation
Period
Under the CAA and the EPA's regulations, all 50 states, the
District of Columbia, and the U.S. Virgin Islands are required to
submit regional haze SIPs satisfying the applicable requirements for
the second implementation period of the regional haze program by July
31, 2021.\27\ Each state's SIP must contain a long-term strategy for
making reasonable progress toward meeting the national goal of
remedying any existing and preventing any future anthropogenic
visibility impairment in Class I areas. CAA section 169A(b)(2)(B). To
this end, Sec. 51.308(f) lays out the process by which states
determine what constitutes their long-term strategies, with the order
of the requirements in Sec. 51.308(f)(1) through (3) generally
mirroring the order of the steps in the reasonable progress analysis
\28\ and (f)(4) through (6) containing additional, related
requirements. Broadly speaking, a state first must identify the Class I
areas within the state and determine the Class I areas outside the
state in which visibility may be affected by emissions from the state.
These are the Class I areas that must be addressed in the state's long-
term strategy. See 40 CFR 51.308(f), (f)(2). For each Class I area
within its borders, a state must then calculate the baseline, current,
and natural visibility conditions for that area, as well as the
visibility improvement made to date and the URP. See 40 CFR
51.308(f)(1). Each state having a Class I area and/or emissions that
may affect visibility in a Class I area must then develop a long-term
strategy that includes the enforceable emission limitations, compliance
schedules, and other measures that are necessary to make reasonable
progress in such areas. A reasonable progress determination is based on
applying the four factors in CAA section 169A(g)(1) to sources of
visibility impairing pollutants that the state has selected to assess
for controls for the second implementation period. Additionally, as
further explained below, the RHR at 40 CFR 51.3108(f)(2)(iv) separately
provides five ``additional factors'' \29\ that states must consider in
developing their long-term strategies. See 40 CFR 51.308(f)(2). A state
evaluates potential emission reduction measures for those selected
sources and determines which are necessary to make reasonable progress.
Those measures are then incorporated into the state's long-term
strategy. After a state has developed its long-term strategy, it then
establishes RPGs for each Class I area within its borders by modeling
the visibility impacts of all reasonable progress controls at the end
of the second implementation period, i.e., in 2028, as well as the
impacts of other requirements of the CAA. The RPGs include reasonable
progress controls not only for sources in the state in which the Class
I area is located, but also for sources in other states that contribute
to visibility impairment in that area. The RPGs are then compared to
the baseline visibility conditions and the URP to ensure that progress
is being made towards the statutory goal of preventing any future and
remedying any existing anthropogenic visibility impairment in Class I
areas. 40 CFR 51.308(f)(2)-(3).
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\27\ Wyoming is one of a few states with outstanding first
planning period obligations. The EPA is not precluded from acting on
a second planning period SIP submission on the basis that a state
has outstanding first planning period obligations. All states have
an obligation to submit second planning period SIP submissions by
July 31, 2021, regardless of the status of first planning period
obligations. After a second planning period SIP submission is
submitted to the EPA for review, the EPA is statutorily required to
review and act on that submission within 12 months of it being
deemed complete. See CAA section 110(k)(1)(B), 42 U.S.C.
7410(k)(1)(B). Throughout actions on the second planning period, the
EPA will continue to work with those states who have outstanding
first planning period obligations to ensure there is no gap that
could affect the continuous progress of visibility improvement.
\28\ The EPA explained in the 2017 RHR Revisions that we were
adopting new regulatory language in 40 CFR 51.308(f) that, unlike
the structure in 51.308(d), ``tracked the actual planning
sequence.'' (82 FR at 3091).
\29\ The five ``additional factors'' for consideration in Sec.
51.308(f)(2)(iv) are distinct from the four factors listed in CAA
section 169A(g)(1) and 40 CFR 51.308(f)(2)(i) that states must
consider and apply to sources in determining reasonable progress.
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In addition to satisfying the requirements at 40 CFR 51.308(f)
related to reasonable progress, the regional haze SIP revisions for the
second implementation period must address the requirements in Sec.
51.308(g)(1) through (5) pertaining to periodic reports describing
progress towards the RPGs, 40 CFR 51.308(f)(5), as well as requirements
for FLM consultation that apply to all visibility protection SIPs and
SIP revisions. 40 CFR 51.308(i).
A state must submit its regional haze SIP and subsequent SIP
revisions to the EPA according to the requirements
[[Page 63035]]
applicable to all SIP revisions under the CAA and the EPA's
regulations. See CAA section 169A(b)(2); CAA section 110(a). Upon
approval by the EPA, a SIP is enforceable by the Agency and the public
under the CAA. If the EPA finds that a state fails to make a required
SIP revision, or if the EPA finds that a state's SIP is incomplete or
if it disapproves the SIP, the Agency must promulgate a federal
implementation plan (FIP) that satisfies the applicable requirements.
CAA section 110(c)(1).
A. Identification of Class I Areas
The first step in developing a regional haze SIP is for a state to
determine which Class I areas, in addition to those within its borders,
``may be affected'' by emissions from within the state. In the 1999
RHR, the EPA determined that all states contribute to visibility
impairment in at least one Class I area, 64 FR at 35720-22, and
explained that the statute and regulations lay out an ``extremely low
triggering threshold'' for determining ``whether States should be
required to engage in air quality planning and analysis as a
prerequisite to determining the need for control of emissions from
sources within their State.'' Id. at 35721.
A state must determine which Class I areas must be addressed by its
SIP by evaluating the total emissions of visibility impairing
pollutants from all sources within the state. While the RHR does not
require this evaluation to be conducted in any particular manner, EPA's
2019 Guidance provides recommendations for how such an assessment might
be accomplished, including by, where appropriate, using the
determinations previously made for the first implementation period.
2019 Guidance at 8-9. In addition, the determination of which Class I
areas may be affected by a state's emissions is subject to the
requirement in 40 CFR 51.308(f)(2)(iii) to ``document the technical
basis, including modeling, monitoring, cost, engineering, and emissions
information, on which the State is relying to determine the emission
reduction measures that are necessary to make reasonable progress in
each mandatory Class I Federal area it affects.''
B. Calculation of Baseline, Current, and Natural Visibility Conditions;
Progress to Date; and Uniform Rate of Progress
As part of assessing whether a SIP submission for the second
implementation period is providing for reasonable progress towards the
national visibility goal, the RHR contains requirements in Sec.
51.308(f)(1) related to tracking visibility improvement over time. The
requirements of this section apply only to states having Class I areas
within their borders; the required calculations must be made for each
such Class I area. The EPA's 2018 Visibility Tracking Guidance \30\
provides recommendations to assist states in satisfying their
obligations under Sec. 51.308(f)(1); specifically, in developing
information on baseline, current, and natural visibility conditions,
and in making optional adjustments to the URP to account for the
impacts of international anthropogenic emissions and prescribed fires.
See 82 FR at 3103-05.
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\30\ The 2018 Visibility Tracking Guidance references and relies
on parts of the 2003 Tracking Guidance: ``Guidance for Tracking
Progress Under the Regional Haze Rule,'' which can be found at
https://www.epa.gov/sites/default/files/2021-03/documents/tracking.pdf.
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The RHR requires tracking of visibility conditions on two sets of
days: the clearest and the most impaired days. Visibility conditions
for both sets of days are expressed as the average deciview index for
the relevant five-year period (the period representing baseline or
current visibility conditions). The RHR provides that the relevant sets
of days for visibility tracking purposes are the 20% clearest (the 20%
of monitored days in a calendar year with the lowest values of the
deciview index) and 20% most impaired days (the 20% of monitored days
in a calendar year with the highest amounts of anthropogenic visibility
impairment).\31\ 40 CFR 51.301. A state must calculate visibility
conditions for both the 20% clearest and 20% most impaired days for the
baseline period of 2000-2004 and the most recent five-year period for
which visibility monitoring data are available (representing current
visibility conditions). 40 CFR 51.308(f)(1)(i), (iii). States must also
calculate natural visibility conditions for the clearest and most
impaired days,\32\ by estimating the conditions that would exist on
those two sets of days absent anthropogenic visibility impairment. 40
CFR 51.308(f)(1)(ii). Using all these data, states must then calculate,
for each Class I area, the amount of progress made since the baseline
period (2000-2004) and how much improvement is left to achieve to reach
natural visibility conditions.
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\31\ This document also refers to the 20% clearest and 20% most
anthropogenically impaired days as the ``clearest'' and ``most
impaired'' or ``most anthropogenically impaired'' days,
respectively.
\32\ The RHR at 40 CFR 51.308(f)(1)(ii) contains an error
related to the requirement for calculating two sets of natural
conditions values. The rule says ``most impaired days or the
clearest days'' where it should say ``most impaired days and
clearest days.'' This is an error that was intended to be corrected
in the 2017 RHR Revisions but did not get corrected in the final
rule language. This is supported by the preamble text at 82 FR at
3098: ``In the final version of 40 CFR 51.308(f)(1)(ii), an
occurrence of `or' has been corrected to `and' to indicate that
natural visibility conditions for both the most impaired days and
the clearest days must be based on available monitoring
information.''
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Using the data for the set of most impaired days only, states must
plot a line between visibility conditions in the baseline period and
natural visibility conditions for each Class I area to determine the
URP--the amount of visibility improvement, measured in deciviews, that
would need to be achieved during each implementation period to achieve
natural visibility conditions by the end of 2064. The URP is used in
later steps of the reasonable progress analysis for informational
purposes and to provide a non-enforceable benchmark against which to
assess a Class I area's rate of visibility improvement.\33\
Additionally, in the 2017 RHR Revisions, the EPA provided states the
option of proposing to adjust the endpoint of the URP to account for
impacts of anthropogenic sources outside the United States and/or
impacts of certain types of wildland prescribed fires. These
adjustments, which must be approved by the EPA, are intended to avoid
any perception that states should compensate for impacts from
international anthropogenic sources and to give states the flexibility
to determine that limiting the use of wildland-prescribed fire is not
necessary for reasonable progress. 82 FR at 3107 footnote 116.
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\33\ Being on or below the URP is not a ``safe harbor''; i.e.,
achieving the URP does not mean that a Class I area is making
``reasonable progress'' and does not relieve a state from using the
four statutory factors to determine what level of control is needed
to achieve such progress. See, e.g., 82 FR at 3093.
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The EPA's 2018 Visibility Tracking Guidance can be used to help
satisfy the 40 CFR 51.308(f)(1) requirements, including in developing
information on baseline, current, and natural visibility conditions,
and in making optional adjustments to the URP. In addition, the 2020
Data Completeness Memo provides recommendations on the data
completeness language referenced in Sec. 51.308(f)(1)(i) and provides
updated natural conditions estimates for each Class I area.
C. Long-Term Strategy for Regional Haze
The core component of a regional haze SIP submission is a long-term
strategy that addresses regional haze in each Class I area within a
state's borders and each Class I area outside the state that may be
affected by emissions from the state. The long-term strategy ``must
include the enforceable emissions
[[Page 63036]]
limitations, compliance schedules, and other measures that are
necessary to make reasonable progress, as determined pursuant to
(f)(2)(i) through (iv).'' 40 CFR 51.308(f)(2). The amount of progress
that is ``reasonable progress'' is based on applying the four statutory
factors in CAA section 169A(g)(1) in an evaluation of potential control
options for sources of visibility impairing pollutants, which is
referred to as a ``four-factor'' analysis.\34\ The outcome of that
analysis is the emission reduction measures that a particular source or
group of sources needs to implement to make reasonable progress towards
the national visibility goal. See 40 CFR 51.308(f)(2)(i). Emission
reduction measures that are necessary to make reasonable progress may
be either new, additional control measures for a source, or they may be
the existing emission reduction measures that a source is already
implementing. See 2019 Guidance at 43; 2021 Clarifications Memo at 8-
10. Such measures must be represented by ``enforceable emissions
limitations, compliance schedules, and other measures'' (i.e., any
additional compliance tools) in a state's long-term strategy in its
SIP. 40 CFR 51.308(f)(2).
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\34\ Four-factor analysis considers the four statutory factors
specified in CAA section 169A(g)(1) and 40 CFR 51.308(f)(2)(i).
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Section 51.308(f)(2)(i) provides the requirements for the four-
factor analysis. The first step of this analysis entails selecting the
sources to be evaluated for emission reduction measures; to this end,
the RHR requires states to consider ``major and minor stationary
sources or groups of sources, mobile sources, and area sources'' of
visibility impairing pollutants for potential four-factor control
analysis. 40 CFR 51.308(f)(2)(i). A threshold question at this step is
which visibility impairing pollutants will be analyzed. As the EPA
previously explained, consistent with the first implementation period,
the EPA generally expects that each state will analyze at least
SO2 and NOX in selecting sources and determining
control measures. See 2019 Guidance at 12, 2021 Clarifications Memo at
4. A state that chooses not to consider at least these two pollutants
should demonstrate why such consideration would be unreasonable. 2021
Clarifications Memo at 4.
While states have the option to analyze all sources, the 2019
Guidance explains that ``an analysis of control measures is not
required for every source in each implementation period,'' and that
``[s]electing a set of sources for analysis of control measures in each
implementation period is . . . consistent with the Regional Haze Rule,
which sets up an iterative planning process and anticipates that a
state may not need to analyze control measures for all its sources in a
given SIP revision.'' 2019 Guidance at 9. However, given that source
selection is the basis of all subsequent control determinations, a
reasonable source selection process ``should be designed and conducted
to ensure that source selection results in a set of pollutants and
sources the evaluation of which has the potential to meaningfully
reduce their contributions to visibility impairment.'' 2021
Clarifications Memo at 3.
The EPA explained in the 2021 Clarifications Memo that each state
has an obligation to submit a long-term strategy that addresses the
regional haze visibility impairment that results from emissions from
within that state. Thus, source selection should focus on the in-state
contribution to visibility impairment and be designed to capture a
meaningful portion of the state's total contribution to visibility
impairment in Class I areas. A state should not decline to select its
largest in-state sources on the basis that there are even larger out-
of-state contributors. 2021 Clarifications Memo at 4.\35\
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\35\ Similarly, in responding to comments on the 2017 RHR
Revisions the EPA explained that ``[a] state should not fail to
address its many relatively low-impact sources merely because it
only has such sources and another state has even more low-impact
sources and/or some high impact sources.'' Responses to Comments on
Protection of Visibility: Amendments to Requirements for State
Plans; Proposed Rule (81 FR 26942, May 4, 2016) at 87-88.
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Thus, while states have discretion to choose any source selection
methodology that is reasonable, whatever choices they make should be
reasonably explained. To this end, 40 CFR 51.308(f)(2)(i) requires that
a state's SIP submission include ``a description of the criteria it
used to determine which sources or groups of sources it evaluated.''
The technical basis for source selection, which may include methods for
quantifying potential visibility impacts such as emissions divided by
distance metrics, trajectory analyses, residence time analyses, and/or
photochemical modeling, must also be appropriately documented, as
required by 40 CFR 51.308(f)(2)(iii).
Once a state has selected the set of sources, the next step is to
determine the emissions reduction measures for those sources that are
necessary to make reasonable progress for the second implementation
period.\36\ This is accomplished by considering the four factors--``the
costs of compliance, the time necessary for compliance, and the energy
and non-air quality environmental impacts of compliance, and the
remaining useful life of any existing source subject to such
requirements.'' CAA section 169A(g)(1). The EPA has explained that the
four-factor analysis is an assessment of potential emission reduction
measures (i.e., control options) for sources; ``use of the terms
`compliance' and `subject to such requirements' in section 169A(g)(1)
strongly indicates that Congress intended the relevant determination to
be the requirements with which sources would have to comply to satisfy
the CAA's reasonable progress mandate.'' 82 FR at 3091. Thus, for each
source it has selected for four-factor analysis,\37\ a state must
consider a ``meaningful set'' of technically feasible control options
for reducing emissions of visibility impairing pollutants. Id. at 3088.
The 2019 Guidance provides that ``[a] state must reasonably pick and
justify the measures that it will consider, recognizing that there is
no statutory or regulatory requirement to consider all technically
feasible measures or any particular measures. A range of technically
feasible measures available to reduce emissions would be one way to
justify a reasonable set.'' 2019 Guidance at 29.
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\36\ The CAA provides that, ``[i]n determining reasonable
progress there shall be taken into consideration'' the four
statutory factors. CAA section 169A(g)(1). However, in addition to
four-factor analyses for selected sources, groups of sources, or
source categories, a state may also consider additional emission
reduction measures for inclusion in its long-term strategy, e.g.,
from other newly adopted, on-the-books, or on-the-way rules and
measures for sources not selected for four-factor analysis for the
second implementation period.
\37\ ``Each source'' or ``particular source'' is used here as
shorthand. While a source-specific analysis is one way of applying
the four factors, neither the statute nor the RHR requires states to
evaluate individual sources. Rather, states have ``the flexibility
to conduct four-factor analyses for specific sources, groups of
sources or even entire source categories, depending on state policy
preferences and the specific circumstances of each state.'' 82 FR at
3088. However, not all approaches to grouping sources for four-
factor analysis are necessarily reasonable; the reasonableness of
grouping sources in any particular instance will depend on the
circumstances and the manner in which grouping is conducted. If it
is feasible to establish and enforce different requirements for
sources or subgroups of sources, and if relevant factors can be
quantified for those sources or subgroups, then states should make a
separate reasonable progress determination for each source or
subgroup. 2021 Clarifications Memo at 7-8.
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The EPA's 2021 Clarifications Memo provides further guidance on
what constitutes a reasonable set of control options for consideration:
``A reasonable four-factor analysis will consider the full range of
potentially reasonable options for reducing emissions.'' 2021
Clarifications Memo at 7. In addition to
[[Page 63037]]
add-on controls and other retrofits (i.e., new emissions reduction
measures for sources), the EPA explained that states should generally
analyze efficiency improvements for sources' existing measures as
control options in their four-factor analyses, as in many cases such
improvements are reasonable given that they typically involve only
additional operation and maintenance costs. Additionally, the 2021
Clarifications Memo provides that states that have assumed a higher
emissions rate than a source has achieved or could potentially achieve
using its existing measures should also consider lower emissions rates
as potential control options. That is, a state should consider a
source's recent actual and projected emission rates to determine if it
could reasonably attain lower emission rates with its existing
measures. If so, the state should analyze the lower emission rate as a
control option for reducing emissions. 2021 Clarifications Memo at 7.
The EPA's recommendations to analyze potential efficiency improvements
and achievable lower emission rates apply to both sources that have
been selected for four-factor analysis and those that have forgone a
four-factor analysis on the basis of existing ``effective controls.''
See 2021 Clarifications Memo at 5, 10.
After identifying a reasonable set of potential control options for
the sources it has selected, a state then collects information on the
four factors with regard to each option identified. The EPA has also
explained that, in addition to the four statutory factors, states have
flexibility under the CAA and RHR to reasonably consider visibility
benefits as an additional factor alongside the four statutory
factors.\38\ The 2019 Guidance provides recommendations for the types
of information that can be used to characterize the four factors (with
or without visibility), as well as ways in which states might
reasonably consider and balance that information to determine which of
the potential control options is necessary to make reasonable progress.
See 2019 Guidance at 30-36. The 2021 Clarifications Memo contains
further guidance on how states can reasonably consider modeled
visibility impacts or benefits in the context of a four-factor
analysis. 2021 Clarifications Memo at 12-13, 14-15. Specifically, the
EPA explained that while visibility can reasonably be used when
comparing and choosing between multiple reasonable control options, it
should not be used to summarily reject controls that are reasonable
given the four statutory factors. 2021 Clarifications Memo at 13.
Ultimately, while states have discretion to reasonably weigh the
factors and to determine what level of control is needed, Sec.
51.308(f)(2)(i) provides that a state ``must include in its
implementation plan a description of . . . how the four factors were
taken into consideration in selecting the measure for inclusion in its
long-term strategy.''
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\38\ See, e.g., Responses to Comments on Protection of
Visibility: Amendments to Requirements for State Plans; Proposed
Rule (81 FR 26942, May 4, 2016), Docket ID No. EPA-HQ-OAR-2015-0531,
U.S. Environmental Protection Agency at 186; 2019 Guidance at 36-37.
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As explained above, Sec. 51.308(f)(2)(i) requires states to
determine the emission reduction measures for sources that are
necessary to make reasonable progress by considering the four factors.
Pursuant to Sec. 51.308(f)(2), measures that are necessary to make
reasonable progress towards the national visibility goal must be
included in a state's long-term strategy and in its SIP.\39\ If the
outcome of a four-factor analysis is a new, additional emission
reduction measure for a source, that new measure is necessary to make
reasonable progress towards remedying existing anthropogenic visibility
impairment and must be included in the SIP. If the outcome of a four-
factor analysis is that no new measures are reasonable for a source,
continued implementation of the source's existing measures is generally
necessary to prevent future emission increases and thus to make
reasonable progress towards the second part of the national visibility
goal: preventing future anthropogenic visibility impairment. See CAA
section 169A(a)(1). That is, when the result of a four-factor analysis
is that no new measures are necessary to make reasonable progress, the
source's existing measures are generally necessary to make reasonable
progress and must be included in the SIP. However, there may be
circumstances in which a state can demonstrate that a source's existing
measures are not necessary to make reasonable progress. Specifically,
if a state can demonstrate that a source will continue to implement its
existing measures and will not increase its emissions rate, it may not
be necessary to have those measures in the long-term strategy to
prevent future emissions increases and future visibility impairment.
The EPA's 2021 Clarifications Memo provides further explanation and
guidance on how states may demonstrate that a source's existing
measures are not necessary to make reasonable progress. See 2021
Clarifications Memo at 8-10. If the state can make such a
demonstration, it need not include a source's existing measures in the
long-term strategy or its SIP.
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\39\ States may choose to, but are not required to, include
measures in their long-term strategies beyond just the emission
reduction measures that are necessary for reasonable progress. See
2021 Clarifications Memo at 16. For example, states with smoke
management programs may choose to submit their smoke management
plans to the EPA for inclusion in their SIPs but are not required to
do so. See, e.g., 82 FR at 3108-09 (requirement to consider smoke
management practices and smoke management programs under 40 CFR
51.308(f)(2)(iv) does not require states to adopt such practices or
programs into their SIPs, although they may elect to do so).
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As with source selection, the characterization of information on
each of the factors is also subject to the documentation requirement in
Sec. 51.308(f)(2)(iii). The reasonable progress analysis, including
source selection, information gathering, characterization of the four
statutory factors (and potentially visibility), balancing of the four
factors, and selection of the emission reduction measures that
represent reasonable progress, is a technically complex exercise, but
also a flexible one that provides states with bounded discretion to
design and implement approaches appropriate to their circumstances.
Given this flexibility, Sec. 51.308(f)(2)(iii) plays an important
function in requiring a state to document the technical basis for its
decision making so that the public and the EPA can comprehend and
evaluate the information and analysis the state relied upon to
determine what emission reduction measures must be in place to make
reasonable progress. The technical documentation must include the
modeling, monitoring, cost, engineering, and emissions information on
which the state relied to determine the measures necessary to make
reasonable progress. This documentation requirement can be met through
the provision of and reliance on technical analyses developed through a
regional planning process, so long as that process and its output has
been approved by all state participants. In addition to the explicit
regulatory requirement to document the technical basis of their
reasonable progress determinations, states are also subject to the
general principle that those determinations must be reasonably moored
to the statute.\40\ That is, a state's decisions about the emission
reduction measures that are necessary to
[[Page 63038]]
make reasonable progress must be consistent with the statutory goal of
remedying existing and preventing future visibility impairment.
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\40\ See Arizona ex rel. Darwin v. U.S. EPA, 815 F.3d 519, 531
(9th Cir. 2016); Nebraska v. EPA, 812 F.3d 662, 668 (8th Cir. 2016);
North Dakota v. EPA, 730 F.3d 750, 761 (8th Cir. 2013); Oklahoma v.
EPA, 723 F.3d 1201, 1206, 1208-10 (10th Cir. 2013); cf. Nat'l Parks
Conservation Ass'n v. EPA, 803 F.3d 151, 165 (3d Cir. 2015); Alaska
Dep't of Envtl. Conservation v. EPA, 540 U.S. 461, 485, 490 (2004).
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The four statutory factors (and potentially visibility) are used to
determine what emission reduction measures for selected sources must be
included in a state's long-term strategy for making reasonable
progress. Additionally, the RHR at 40 CFR 51.3108(f)(2)(iv) separately
provides five ``additional factors'' \41\ that states must consider in
developing their long-term strategies: (1) Emission reductions due to
ongoing air pollution control programs, including measures to address
reasonably attributable visibility impairment; (2) measures to reduce
the impacts of construction activities; (3) source retirement and
replacement schedules; (4) basic smoke management practices for
prescribed fire used for agricultural and wildland vegetation
management purposes and smoke management programs; and (5) the
anticipated net effect on visibility due to projected changes in point,
area, and mobile source emissions over the period addressed by the
long-term strategy. The 2019 Guidance provides that a state may satisfy
this requirement by considering these additional factors in the process
of selecting sources for four-factor analysis, when performing that
analysis, or both, and that not every one of the additional factors
needs to be considered at the same stage of the process. See 2019
Guidance at 21. The EPA provided further guidance on the five
additional factors in the 2021 Clarifications Memo, explaining that a
state should generally not reject cost-effective and otherwise
reasonable controls merely because there have been emission reductions
since the first planning period owing to other ongoing air pollution
control programs or merely because visibility is otherwise projected to
improve at Class I areas. Additionally, states generally should not
rely on these additional factors to summarily assert that the state has
already made sufficient progress and, therefore, no sources need to be
selected or no new controls are needed regardless of the outcome of
four-factor analyses. 2021 Clarifications Memo at 13.
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\41\ The five ``additional factors'' for consideration in Sec.
51.308(f)(2)(iv) are distinct from the four factors listed in CAA
section 169A(g)(1) and 40 CFR 51.308(f)(2)(i) that states must
consider and apply to sources in determining reasonable progress.
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Because the air pollution that causes regional haze crosses state
boundaries, Sec. 51.308(f)(2)(ii) requires a state to consult with
other states that also have emissions that are reasonably anticipated
to contribute to visibility impairment in a given Class I area.
Consultation allows for each state that impacts visibility in an area
to share whatever technical information, analyses, and control
determinations may be necessary to develop coordinated emission
management strategies. This coordination may be managed through inter-
and intra-RPO consultation and the development of regional emissions
strategies; additional consultations between states outside of RPO
processes may also occur. If a state, pursuant to consultation, agrees
that certain measures (e.g., a certain emission limitation) are
necessary to make reasonable progress at a Class I area, it must
include those measures in its SIP. 40 CFR 51.308(f)(2)(ii)(A).
Additionally, the RHR requires that states that contribute to
visibility impairment at the same Class I area consider the emission
reduction measures the other contributing states have identified as
being necessary to make reasonable progress for their own sources. 40
CFR 51.308(f)(2)(ii)(B). If a state has been asked to consider or adopt
certain emission reduction measures, but ultimately determines those
measures are not necessary to make reasonable progress, that state must
document in its SIP the actions taken to resolve the disagreement. 40
CFR 51.308(f)(2)(ii)(C). The EPA will consider the technical
information and explanations presented by the submitting state and the
state with which it disagrees when considering whether to approve the
state's SIP. See id.; 2019 Guidance at 53. Under all circumstances, a
state must document in its SIP submission all substantive consultations
with other contributing states. 40 CFR 51.308(f)(2)(ii)(C).
D. Reasonable Progress Goals
Reasonable progress goals ``measure the progress that is projected
to be achieved by the control measures states have determined are
necessary to make reasonable progress based on a four-factor
analysis.'' 82 FR at 3091. Their primary purpose is to assist the
public and the EPA in assessing the reasonableness of states' long-term
strategies for making reasonable progress towards the national
visibility goal for Class I areas within the state. See 40 CFR
51.308(f)(3)(iii)-(iv). States in which Class I areas are located must
establish two RPGs, both in deciviews--one representing visibility
conditions on the clearest days and one representing visibility on the
most anthropogenically impaired days--for each area within their
borders. 40 CFR 51.308(f)(3)(i). The two RPGs are intended to reflect
the projected impacts, on the two sets of days, of the emission
reduction measures the state with the Class I area, as well as all
other contributing states, have included in their long-term strategies
for the second implementation period.\42\ The RPGs also account for the
projected impacts of implementing other CAA requirements, including
non-SIP based requirements. Because RPGs are the modeled result of the
measures in states' long-term strategies (as well as other measures
required under the CAA), they cannot be determined before states have
conducted their four-factor analyses and determined the control
measures that are necessary to make reasonable progress. See 2021
Clarifications Memo at 6.
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\42\ RPGs are intended to reflect the projected impacts of the
measures all contributing states include in their long-term
strategies. However, due to the timing of analyses, control
determinations by other states, and other on-going emissions
changes, a particular state's RPGs may not reflect all control
measures and emissions reductions that are expected to occur by the
end of the implementation period. The 2019 Guidance provides
recommendations for addressing the timing of RPG calculations when
states are developing their long-term strategies on disparate
schedules, as well as for adjusting RPGs using a post-modeling
approach. 2019 Guidance at 47-48.
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For the second implementation period, the RPGs are set for 2028.
Reasonable progress goals are not enforceable targets, 40 CFR
51.308(f)(3)(iii); rather, they ``provide a way for the states to check
the projected outcome of the [long-term strategy] against the goals for
visibility improvement.'' 2019 Guidance at 46. While states are not
legally obligated to achieve the visibility conditions described in
their RPGs, Sec. 51.308(f)(3)(i) requires that ``[t]he long-term
strategy and the reasonable progress goals must provide for an
improvement in visibility for the most impaired days since the baseline
period and ensure no degradation in visibility for the clearest days
since the baseline period.'' Thus, states are required to have emission
reduction measures in their long-term strategies that are projected to
achieve visibility conditions on the most impaired days that are better
than the baseline period and that show no degradation on the clearest
days compared to the clearest days from the baseline period. The
baseline period for the purpose of this comparison is the baseline
visibility condition--the annual average visibility condition for the
period 2000-2004. See 40 CFR 51.308(f)(1)(i), 82 FR at 3097-98.
So that RPGs may also serve as a metric for assessing the amount of
progress a state is making towards the national visibility goal, the
RHR
[[Page 63039]]
requires states with Class I areas to compare the 2028 RPG for the most
impaired days to the corresponding point on the URP line (representing
visibility conditions in 2028 if visibility were to improve at a linear
rate from conditions in the baseline period of 2000-2004 to natural
visibility conditions in 2064). If the most impaired days RPG in 2028
is above the URP (i.e., if visibility conditions are improving more
slowly than the rate described by the URP), each state that contributes
to visibility impairment in the Class I area must demonstrate, based on
the four-factor analysis required under 40 CFR 51.308(f)(2)(i), that no
additional emission reduction measures would be reasonable to include
in its long-term strategy. 40 CFR 51.308(f)(3)(ii). To this end, 40 CFR
51.308(f)(3)(ii) requires that each state contributing to visibility
impairment in a Class I area that is projected to improve more slowly
than the URP provide ``a robust demonstration, including documenting
the criteria used to determine which sources or groups [of] sources
were evaluated and how the four factors required by paragraph (f)(2)(i)
were taken into consideration in selecting the measures for inclusion
in its long-term strategy.'' The 2019 Guidance provides suggestions
about how such a ``robust demonstration'' might be conducted. See 2019
Guidance at 50-51.
The 2017 RHR, 2019 Guidance, and 2021 Clarifications Memo also
explain that projecting an RPG that is on or below the URP based on
only on-the-books and/or on-the-way control measures (i.e., control
measures already required or anticipated before the four-factor
analysis is conducted) is not a ``safe harbor'' from the CAA's and
RHR's requirement that all states must conduct a four-factor analysis
to determine what emission reduction measures constitute reasonable
progress. The URP is a planning metric used to gauge the amount of
progress made thus far and the amount left before reaching natural
visibility conditions. However, the URP is not based on consideration
of the four statutory factors and therefore cannot answer the question
of whether the amount of progress being made in any particular
implementation period is ``reasonable progress.'' See 82 FR at 3093,
3099-3100; 2019 Guidance at 22; 2021 Clarifications Memo at 15-16.
E. Monitoring Strategy and Other State Implementation Plan Requirements
Section 51.308(f)(6) requires states to have certain strategies and
elements in place for assessing and reporting on visibility. Individual
requirements under this section apply either to states with Class I
areas within their borders, states with no Class I areas but that are
reasonably anticipated to cause or contribute to visibility impairment
in any Class I area, or both. A state with Class I areas within its
borders must submit with its SIP revision a monitoring strategy for
measuring, characterizing, and reporting regional haze visibility
impairment that is representative of all Class I areas within the
state. SIP revisions for such states must also provide for the
establishment of any additional monitoring sites or equipment needed to
assess visibility conditions in Class I areas, as well as reporting of
all visibility monitoring data to the EPA at least annually. Compliance
with the monitoring strategy requirement may be met through a state's
participation in the Interagency Monitoring of Protected Visual
Environments (IMPROVE) monitoring network, which is used to measure
visibility impairment caused by air pollution at the 156 Class I areas
covered by the visibility program. 40 CFR 51.308(f)(6), (f)(6)(i),
(f)(6)(iv). The IMPROVE monitoring data is used to determine the 20%
most anthropogenically impaired and 20% clearest sets of days every
year at each Class I area and tracks visibility impairment over time.
All states' SIPs must provide for procedures by which monitoring
data and other information are used to determine the contribution of
emissions from within the state to regional haze visibility impairment
in affected Class I areas. 40 CFR 51.308(f)(6)(ii) and (iii). Section
51.308(f)(6)(v) further requires that all states' SIPs provide for a
statewide inventory of emissions of pollutants that are reasonably
anticipated to cause or contribute to visibility impairment in any
Class I area; the inventory must include emissions for the most recent
year for which data are available and estimates of future projected
emissions. States must also include commitments to update their
inventories periodically. The inventories themselves do not need to be
included as elements in the SIP and are not subject to the EPA's review
as part of the Agency's evaluation of a SIP revision.\43\ All states'
SIPs must also provide for any other elements, including reporting,
recordkeeping, and other measures, that are necessary for states to
assess and report on visibility. 40 CFR 51.308(f)(6)(vi). Per the 2019
Guidance, a state may note in its regional haze SIP that its compliance
with the Air Emissions Reporting Rule (AERR) in 40 CFR part 51, subpart
A satisfies the requirement to provide for an emissions inventory for
the most recent year for which data are available. To satisfy the
requirement to provide estimates of future projected emissions, a state
may explain in its SIP how projected emissions were developed for use
in establishing RPGs for its own and nearby Class I areas.\44\
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\43\ See ``Step 8: Additional requirements for regional haze
SIPs'' in the 2019 Guidance at 55.
\44\ Id.
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Separate from the requirements related to monitoring for regional
haze purposes under 40 CFR 51.308(f)(6), the RHR also contains a
requirement at Sec. 51.308(f)(4) related to any additional monitoring
that may be needed to address visibility impairment in Class I areas
from a single source or a small group of sources. This is called
``reasonably attributable visibility impairment.'' \45\ Under this
provision, if the EPA or the FLM of an affected Class I area has
advised a state that additional monitoring is needed to assess
reasonably attributable visibility impairment, the state must include
in its SIP revision for the second implementation period an appropriate
strategy for evaluating such impairment.
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\45\ The EPA's visibility protection regulations define
``reasonably attributable visibility impairment'' as ``visibility
impairment that is caused by the emission of air pollutants from
one, or a small number of sources.'' 40 CFR 51.301.
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F. Requirements for Periodic Reports Describing Progress Towards the
Reasonable Progress Goals
Section 51.308(f)(5) requires a state's regional haze SIP revision
to address the requirements of paragraphs 40 CFR 51.308(g)(1) through
(5) so that the plan revision due in 2021 will serve also as a progress
report addressing the period since submission of the progress report
for the first implementation period. The regional haze progress report
requirement is designed to inform the public and the EPA about a
state's implementation of its existing long-term strategy and whether
such implementation is in fact resulting in the expected visibility
improvement. See 81 FR 26942, 26950 (May 4, 2016), (82 FR at 3119,
January 10, 2017). To this end, every state's SIP revision for the
second implementation period is required to describe the status of
implementation of all measures included in the state's long-term
strategy, including BART and reasonable progress emission reduction
measures from the first implementation period, and the resulting
emissions reductions. 40 CFR 51.308(g)(1) and (2).
A core component of the progress report requirements is an
assessment of
[[Page 63040]]
changes in visibility conditions on the clearest and most impaired
days. For second implementation period progress reports, Sec.
51.308(g)(3) requires states with Class I areas within their borders to
first determine current visibility conditions for each area on the most
impaired and clearest days, 40 CFR 51.308(g)(3)(i), and then to
calculate the difference between those current conditions and baseline
(2000-2004) visibility conditions to assess progress made to date. See
40 CFR 51.308(g)(3)(ii). States must also assess the changes in
visibility impairment for the most impaired and clearest days since
they submitted their first implementation period progress reports. See
40 CFR 51.308(g)(3)(iii), (f)(5). Since different states submitted
their first implementation period progress reports at different times,
the starting point for this assessment will vary state by state.
Similarly, states must provide analyses tracking the change in
emissions of pollutants contributing to visibility impairment from all
sources and activities within the state over the period since they
submitted their first implementation period progress reports. See 40
CFR 51.308(g)(4), (f)(5). Changes in emissions should be identified by
the type of source or activity. Section 51.308(g)(5) also addresses
changes in emissions since the period addressed by the previous
progress report and requires states' SIP revisions to include an
assessment of any significant changes in anthropogenic emissions within
or outside the state. This assessment must explain whether these
changes in emissions were anticipated and whether they have limited or
impeded progress in reducing emissions and improving visibility
relative to what the state projected based on its long-term strategy
for the first implementation period.
G. Requirements for State and Federal Land Manager Coordination
CAA section 169A(d) requires that before a state holds a public
hearing on a proposed regional haze SIP revision, it must consult with
the appropriate FLM or FLMs; pursuant to that consultation, the state
must include a summary of the FLMs' conclusions and recommendations in
the notice to the public. Consistent with this statutory requirement,
the RHR also requires that states ``provide the [FLM] with an
opportunity for consultation, in person and at a point early enough in
the State's policy analyses of its long-term strategy emission
reduction obligation so that information and recommendations provided
by the [FLM] can meaningfully inform the State's decisions on the long-
term strategy.'' 40 CFR 51.308(i)(2). Consultation that occurs 120 days
prior to any public hearing or public comment opportunity will be
deemed ``early enough,'' but the RHR provides that in any event the
opportunity for consultation must be provided at least 60 days before a
public hearing or comment opportunity. This consultation must include
the opportunity for the FLMs to discuss their assessment of visibility
impairment in any Class I area and their recommendations on the
development and implementation of strategies to address such
impairment. 40 CFR 51.308(i)(2). For the EPA to evaluate whether FLM
consultation meeting the requirements of the RHR has occurred, the SIP
submission should include documentation of the timing and content of
such consultation. The SIP revision submitted to the EPA must also
describe how the state addressed any comments provided by the FLMs. 40
CFR 51.308(i)(3). Finally, a SIP revision must provide procedures for
continuing consultation between the state and FLMs regarding the
state's visibility protection program, including development and review
of SIP revisions, five-year progress reports, and the implementation of
other programs having the potential to contribute to impairment of
visibility in Class I areas. 40 CFR 51.308(i)(4).
IV. The EPA's Evaluation of Wyoming's Regional Haze Plan for the Second
Implementation Period
In section IV. of this document, we describe Wyoming's 2022 SIP
submission and evaluate it against the requirements of the CAA and RHR
for the second implementation period of the regional haze program.
A. Identification of Class I Areas
Section 169A(b)(2) of the CAA requires each state in which any
Class I area is located or ``the emissions from which may reasonably be
anticipated to cause or contribute to any impairment of visibility'' in
a Class I area to have a long-term strategy for making reasonable
progress toward the national visibility goal. The RHR implements this
statutory requirement in 40 CFR 51.308(f) for the second and subsequent
planning periods for regional haze. 40 CFR 51.308(f)(2) requires states
to submit a long-term strategy that addresses regional haze visibility
impairment for each mandatory Class I area within the state and for
each mandatory Class I area located outside the state that may be
affected by emissions from the state.
There are seven designated Class I areas within the State of
Wyoming, including two national parks managed by the U.S. National
Parks Service (Grand Teton National Park and Yellowstone National Park)
and five wilderness areas managed by the U.S. Forest Service (Bridger
Wilderness Area, Fitzpatrick Wilderness Area, North Absaroka Wilderness
Area, Teton Wilderness Area, and Washakie Wilderness Area).\46\
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\46\ Wyoming 2022 SIP submission at 20, 35-57.
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Grand Teton National Park, established in 1929, occupies 305,504
acres along the Teton Range and Jackson Lake. It is adjacent to the
Teton Wilderness Area to the northeast and is 6 miles south of
Yellowstone National Park. In 2018, Grand Teton National Park had
3,491,151 visitors.
Yellowstone National Park became the world's first national park on
March 1, 1872, and occupies 2,020,625 acres \47\ in northwestern
Wyoming, overlapping into Montana and Idaho. In 2018, Yellowstone
National Park had 4,114,999 visitors.
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\47\ Yellowstone National Park has 2,219,737 acres overall, of
which 2,020,625 acres are in Wyoming. EPA. List of Areas Protected
by the Regional Haze Program. https://www.epa.gov/visibility/list-areas-protected-regional-haze-program.
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The Bridger Wilderness Area, consisting of 392,160 acres, is
situated on the western slope of the Wind River Range in Wyoming and
extends approximately 80 miles along the western slope of the
Continental Divide. It lies south of the other six Class I areas in
Wyoming and is on the western border of the Fitzpatrick Wilderness
Area.
The Fitzpatrick Wilderness Area, designated in 1976, occupies
191,103 acres and is located on the east slope of the northern Wind
River Range in Wyoming along the Continental Divide, which makes up its
western border. It shares its western border with the Bridger
Wilderness Area and its eastern border with the Wind River Indian
Reservation.
The North Absaroka Wilderness Area, designated in 1964, is part of
the Greater Yellowstone Area of northwestern Wyoming. It is located
along the northeastern boundary of Yellowstone National Park, east of
the Continental Divide, and occupies 351,104 acres.
The Teton Wilderness Area encompasses 557,311 acres that straddle
the Continental Divide in western Wyoming. It is bordered by
Yellowstone National Park to the north, Grand Teton National Park to
the west, and the Washakie Wilderness Area to the east.
The Washakie Wilderness Area encompasses 686,584 acres. It is
bordered on the west by the Teton Wilderness Area and Yellowstone
[[Page 63041]]
National Park, and the North Absaroka Wilderness Area lies to the
north.
Additionally, Wyoming identified 16 Class I areas outside the State
where visibility may be affected by Wyoming sources (table 1).\48\
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\48\ To identify Class I areas in other states that may be
affected by emissions from Wyoming sources, the State used a
threshold of Q/d > 10. Wyoming 2022 SIP submission at 64-67.
Table 1--Class I Areas in Other States That May Be Affected by Wyoming
Sources
------------------------------------------------------------------------
State Class I area
------------------------------------------------------------------------
Colorado........................... Eagles Nest Wilderness Area.
Colorado........................... Flat Tops Wilderness Area.
Colorado........................... Maroon Bells-Snowmass Wilderness
Area.
Colorado........................... Mount Zirkel.
Colorado........................... Rawah Wilderness.
Colorado........................... Rocky Moutain National Park.
Colorado........................... West Elk Wilderness.
Idaho.............................. Craters of the Moon National
Monument.
Montana............................ Red Rocks Lakes National Wildlife
Refuge.
North Dakota....................... Theodore Roosevelt National Park.
Nevada............................. Jarbidge Wilderness.
South Dakota....................... Badlands/Sage Creek Wilderness.
South Dakota....................... Wind Cave National Park.
Utah............................... Arches National Park.
Utah............................... Canyonlands National Park.
Utah............................... Capitol Reef National Park.
------------------------------------------------------------------------
B. Calculation of Baseline, Current, and Natural Visibility Conditions;
Progress to Date; and Uniform Rate of Progress for Class I Areas Within
the State
Section 51.308(f)(1) requires states to determine the following for
``each mandatory Class I Federal area located within the State'':
baseline visibility conditions for the most impaired and clearest days,
natural visibility conditions for the most impaired and clearest days,
progress to date for the most impaired and clearest days, the
differences between current visibility conditions and natural
visibility conditions, and the URP. This section also provides the
option for states to propose adjustments to the URP line for a Class I
area to account for visibility impacts from anthropogenic sources
outside the United States and/or the impacts from wildland prescribed
fires that were conducted for certain specified objectives. 40 CFR
51.308(f)(1)(vi)(B).
The IMPROVE monitoring network measures visibility impairment
caused by air pollution at Class I areas. Wyoming's 2022 SIP submission
provides visibility conditions for each IMPROVE monitor and associated
Class I area in Wyoming (table 2).\49\
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\49\ Wyoming 2022 SIP submission at 34-63.
Table 2--Visibility Conditions (Deciviews) for Wyoming IMPROVE Stations
--------------------------------------------------------------------------------------------------------------------------------------------------------
Progress during Difference
Progress since last between
Baseline Period (2008- Current Natural baseline (2000- implementation current
Monitor ID Class I areas (2000-2004) 2012) (2014-2018) (2064) 2004)- (2014- period (2008- (2014-2018)
2018) 2012)- (2014- and natural
2018) (2064)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Most Impaired Days
--------------------------------------------------------------------------------------------------------------------------------------------------------
YELL2........................ Yellowstone National 8.3 7.5 7.5 4.0 0.8 0 3.5
Park, Grand Teton
National Park, Teton
Wilderness Area.
NOAB1........................ Washakie Wilderness 8.8 7.7 7.2 4.5 1.6 0.5 2.7
Area, North Absaroka
Wilderness Area.
BRID1........................ Bridger Wilderness 8.0 7.2 6.8 3.9 1.2 0.4 3.5
Area, Fitzpatrick
Wilderness Area.
--------------------------------------------------------------------------------------------------------------------------------------------------------
Clearest Days
--------------------------------------------------------------------------------------------------------------------------------------------------------
YELL2........................ Yellowstone National 2.6 1.5 1.4 0.4 1.1 0.1 1
Park, Grand Teton
National Park, Teton
Wilderness Area.
NOAB1........................ Washakie Wilderness 2.0 1.4 0.7 0.6 1.3 0.7 0.1
Area, North Absaroka
Wilderness Area.
BRID1........................ Bridger Wilderness 2.1 1.1 0.9 0.3 1.2 0.2 0.6
Area, Fitzpatrick
Wilderness Area.
--------------------------------------------------------------------------------------------------------------------------------------------------------
The State also determined the uniform rate of progress for the most
impaired and clearest days for all Wyoming Class I areas.\50\ Under 40
CFR 51.308(f)(1)(vi)(B), Wyoming chose to adjust the uniform rate of
progress glidepath for all the State's Class I areas to account for
impacts from anthropogenic sources outside the United States and
impacts from wildland prescribed fires.51 52 Wyoming also
provided haze indices and the
[[Page 63042]]
uniform rate of progress for IMPROVE monitors and associated Class I
areas outside the State.\53\
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\50\ Wyoming 2022 SIP submission at Figures 6-9 and 6-10
(YELL2), Figures 6-18 and 6-19 (NOAB1), and Figures 6-26 and 6-27
(BRID1).
\51\ Wildland prescribed fires are those conducted with the
objective to establish, restore, and/or maintain sustainable and
resilient wildland ecosystems, to reduce the risk of catastrophic
wildfires, and/or to preserve endangered or threatened species
during which appropriate basic smoke management practices were
applied.
\52\ Wyoming 2022 SIP submission at 239-242.
\53\ Wyoming 2022 SIP submission at 70-106.
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Based on the information provided in Chapter 6 of Wyoming's 2022
SIP submission, the EPA is proposing to approve the State's visibility
condition calculations for Grand Teton National Park, Yellowstone
National Park, Bridger Wilderness Area, Fitzpatrick Wilderness Area,
North Absaroka Wilderness Area, Teton Wilderness Area, and Washakie
Wilderness Area, as meeting the requirements of 40 CFR 51.308(f)(1)
related to the calculations of baseline, current, and natural
visibility conditions; progress to date; and the URP.
C. Long-Term Strategy
Each state having a Class I area within its borders or emissions
that may affect visibility in any Class I area outside the state must
develop a long-term strategy for making reasonable progress towards the
national visibility goal for each impacted Class I area. CAA section
169A(b)(2)(B). As explained in the Background section of this document,
reasonable progress is achieved when all states contributing to
visibility impairment in a Class I area are implementing the measures
determined--through application of the four statutory factors to
sources of visibility impairing pollutants--to be necessary to make
reasonable progress. 40 CFR 51.308(f)(2)(i). Each state's long-term
strategy must include the enforceable emission limitations, compliance
schedules, and other measures that are necessary to make reasonable
progress. 40 CFR 51.308(f)(2). All new (i.e., additional) measures that
are the outcome of four-factor analyses are necessary to make
reasonable progress and must be in the long-term strategy. If the
outcome of a four-factor analysis and other measures necessary to make
reasonable progress is that no new measures are reasonable for a
source, that source's existing measures are necessary to make
reasonable progress, unless the state can demonstrate that the source
will continue to implement those measures and will not increase its
emission rate. Existing measures that are necessary to make reasonable
progress must also be in the long-term strategy. In developing its
long-term strategy, a state must also consider the five additional
factors in 40 CFR 51.308(f)(2)(iv). As part of its reasonable progress
determinations, the state must describe the criteria used to determine
which sources or group of sources were evaluated (i.e., subjected to
four-factor analysis) for the second implementation period and how the
four factors were taken into consideration in selecting the emission
reduction measures for inclusion in the long-term strategy. 40 CFR
51.308(f)(2)(iii).
1. Summary of Wyoming's 2022 SIP Submission
Wyoming identified 23 Class I areas that must be addressed in its
long-term strategy.\54\ Under 40 CFR 51.308(f)(2)(i), SIP submittals
must include a description of the criteria a state used to determine
which sources or groups of sources to evaluate through four-factor
analysis. Wyoming used a Q/d screening approach to identify sources for
four-factor analysis. The Q/d screening metric uses a source's annual
emissions in tons (Q) divided by the distance in kilometers (d) between
the source and the nearest Class I area, along with a reasonably
selected threshold for this metric. The larger the Q/d value, the
greater the source's expected effect on visibility in each associated
Class I area. Wyoming opted to use the Q/d screening metric because,
according to the State, it accounts for three of the largest
anthropogenically-sourced pollutants (NOX, SO2,
and PM) that contribute to visibility impairment in Wyoming Class I
areas.\55\
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\54\ Wyoming 2022 SIP submission at 34, 64.
\55\ Wyoming 2022 SIP submission at Figures 8-1 and 8-2 (YELL2),
Figures 8-3 and 8-4 (NOAB1), and Figures 8-5 and 8-6 (BRID1), and
121.
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Using a screening threshold of Q/d > 10 and emissions information
from the 2014 National Emission Inventory (NEI), Wyoming initially
identified 20 sources in the State that may be affecting visibility at
Class I areas in Wyoming and surrounding states.\56\ Upon contacting
the identified sources, the State received updated emissions
information from 14 of the 20 sources,\57\ and the State further
revised emissions values for the sources that did not provide updated
emissions information to reflect the 2017 NEI.\58\ Using updated
emissions information to calculate Q/d, the State screened out five
sources because they fell below its Q/d threshold of 10.\59\ Three coal
facilities (Antelope Mine, Black Thunder Mine, and North Antelope
Rochelle Mine) were also screened out from further consideration based
on the State's assessment that coarse mass PM, the primary component of
emissions from those mines, has relatively little effect on visibility
in Class I areas and should not be included in the mines' Q values.\60\
Ultimately, the State selected twelve sources to perform a four-factor
analysis (table 3).
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\56\ Wyoming 2022 SIP submission at Figure 10-1.
\57\ The State did not receive updated emissions information
from Westvaco, Wyodak, Laramie Portland Cement, Naughton Power
Plant, Dave Johnston Power Plant, and Rock Springs Coke Production
Facility. Wyoming 2022 SIP submission at 125-26.
\58\ Wyoming noted that the 2017 NEI was released in April 2020,
after sources were asked to prepare four-factor analyses. Wyoming
2022 SIP submission at 125.
\59\ Rock Springs Coke Production Facility, Cordero Rojo
Complex, Solvay Green River Soda Ash Plant, Simplot Rock Springs
Fertilizer Complex, and HollyFrontier Refinery. Wyoming 2022 SIP
submission at 128.
\60\ Wyoming 2022 SIP submission at 128-130 and appendix B.
Table 3--Facilities Screened in Using Q/d and Class I Area With Maximum Q/d
--------------------------------------------------------------------------------------------------------------------------------------------------------
Updated Q/d value (tpy/km)
Distance (km) ---------------------------------------------------------------
Facility name Class I area with Class I to Class I NOX + SO2 +
maximum Q/d area state area PM10 NOX SO2 PM10
--------------------------------------------------------------------------------------------------------------------------------------------------------
Jim Bridger Power Plant Bridger Wilderness WY 97.39 160 83.75 68.48 7.77
(PacifiCorp). Area.
Laramie River Station Power Plant Rawah Wilderness Area. CO 164.27 85.89 36.25 42.80 6.85
(Basin Electric).
Laramie Portland Cement (Mountain Rocky Mountain CO 30.54 82.23 73.16 4.19 4.87
Cement Company). National Park.
Naughton Power Plant (PacifiCorp).. Bridger Wilderness WY 141.64 78.57 39.31 28.58 10.68
Area.
Dave Johnston Power Plant Wind Cave National SD 198.38 77.33 32.15 41.38 3.80
(PacifiCorp). Park.
Green River Works (TATA Chemicals). Bridger Wilderness WY 122.11 43.81 16.08 18.52 9.22
Area.
Westvaco Facility (Genesis Alkali). Bridger Wilderness WY 122.62 38.23 17.04 11.96 9.23
Area.
[[Page 63043]]
Wyodak Power Plant (PacifiCorp).... Wind Cave National SD 167.23 37.53 21.89 14.65 0.99
Park.
Elk Basin Gas Plant (Contango North Absaroka WY 52.84 27.64 16.58 10.82 0.24
Resources, Inc.). Wilderness Area.
Granger Soda Ash Facility (Genesis Bridger Wilderness WY 119.74 15.49 10.94 1.62 2.93
Alkali). Area.
Lost Cabin Gas Plant (Burlington Washakie Wilderness WY 132.94 13.06 0.54 12.28 0.24
Resources). Area.
Cheyenne Fertilizer (Dyno Nobel Rocky Mountain CO 81.73 12.33 8.57 0.01 3.76
Inc.). National Park.
--------------------------------------------------------------------------------------------------------------------------------------------------------
The State then requested each of the twelve sources to submit four-
factor analyses for its review and consideration.\61\ As described in
this document, some sources elected not to do so, arguing that four-
factor analysis should not be required for their facilities. Wyoming
attached the facilities' four-factor analyses (or other submissions) as
Appendices C-L to its 2022 SIP submission. Chapter 11 of the SIP
submission contains Wyoming's evaluation of the four statutory factors
for each source (or the reasons for not performing a four-factor
analysis) and Wyoming's determinations of the source-specific emission
reduction measures necessary to make reasonable progress. In sections
IV.C.1.a.-l. of this document, we summarize the four-factor analyses or
other facility submissions for the twelve selected sources.
---------------------------------------------------------------------------
\61\ Id. at 123-25.
---------------------------------------------------------------------------
a. PacifiCorp--Jim Bridger Power Plant \62\
---------------------------------------------------------------------------
\62\ This facility is addressed at pages 134-35 and appendix C
of the Wyoming 2022 SIP submission.
---------------------------------------------------------------------------
PacifiCorp's Jim Bridger Power Plant is located in Sweetwater
County, Wyoming. Jim Bridger is comprised of four identically sized
nominal 530 megawatts (MW) tangentially coal-fired boilers that have a
total net generating capacity of 2,120 MW. Emissions from Jim Bridger
may affect visibility in 17 Class I areas in Colorado, Montana, Utah,
and Wyoming (table 32 in section IV.C.2.a. of this document).
Neither the State nor PacifiCorp conducted a four-factor analysis
for this source. Relying on the ``facility analysis information''
submitted by PacifiCorp (appendix C to Wyoming's 2022 SIP submission),
the State concluded that Jim Bridger Units 1-4 already have effective
NOX and SO2 emission control technologies in
place (table 4).
Table 4--Installed NOX and SO2 Emissions Controls at Jim Bridger Units 1-
4
------------------------------------------------------------------------
Unit SO2 controls NOX controls
------------------------------------------------------------------------
1....................... FGD \1\............... LNB \2\/SOFA.\3\
2....................... FGD................... LNB/SOFA.
3....................... FGD................... LNB/SOFA + SCR.\4\
4....................... FGD................... LNB/SOFA + SCR.
------------------------------------------------------------------------
\1\ Flue gas desulfurization (FGD).
\2\ Low NOX burners (LNB).
\3\ Separated overfire air (SOFA).
\4\ Selective catalytic reduction (SCR).
Additionally, the State describes a consent decree between Wyoming
and PacifiCorp allowing for the short-term continued operation of Jim
Bridger Units 1-2, subject to lower plant-wide month-by-month permitted
emission limits and an annual emissions cap for NOX and
SO2, until Units 1-2 are converted to natural gas in
2024.\63\ Finally, the State notes that dry sorbent injection (DSI) was
not recommended for Jim Bridger because the existing SO2
controls are more efficient.
---------------------------------------------------------------------------
\63\ The consent decree was approved by the Wyoming First
Judicial District Court on February 14, 2022, and requires Jim
Bridger Units 1 and 2 to convert to natural gas with NOX
emission limits of 0.12 lb/MMBtu (30-day rolling average) and 1,314
tons/year per unit along with a 41.6% reduction in maximum heat
input.
---------------------------------------------------------------------------
In its response to the State's initial request to submit a four-
factor analysis,\64\ PacifiCorp asserted that Jim Bridger should be
excluded from that requirement, and consequently the facility should
not be analyzed or required to install any additional controls or take
further actions during the regional haze second planning period. First,
PacifiCorp claimed that Jim Bridger Units 1-4 already have effective
NOX and SO2 controls in place, thereby exempting
these units from further analysis. Specifically, PacifiCorp referenced:
(1) FGD scrubber systems, installed on all units, as meeting the
applicable alternative SO2 emission limit of the 2012
Mercury and Air Toxics Standards (MATS); (2) LNB/SOFA NOX
emission controls installed in 2010 (Unit 1), 2006 (Unit 2), 2007 (Unit
3), and 2008 (Unit 4); and (3) SCR NOX emission controls
installed in 2015 (Unit 3) and 2016 (Unit 4). PacifiCorp also
referenced plant-wide monthly-block NOX and SO2
emission limits, which it stated have been demonstrated to achieve
greater reasonable progress and visibility improvement than could be
achieved through installation of SCR at Jim Bridger Units 1 and 2 and
at a substantially lower cost. PacifiCorp contended that these
circumstances align with the examples provided in the EPA's 2019
Guidance, which detail scenarios \65\ in which it may be reasonable for
a state not to select a particular source for further analysis,
including: (1) FGD controls that meet the applicable alternative
SO2 emission limit of the 2012 MATS rule for power
[[Page 63044]]
plants; (2) NOX and SO2 controls that were
installed during the first planning period and operate year-round with
an effectiveness of at least 90 percent on a pollutant-specific basis
(e.g., FGD or SCR); and (3) BART-eligible units that installed and
began operating controls to meet BART emission limits for the first
regional haze implementation period.
---------------------------------------------------------------------------
\64\ Wyoming 2022 SIP submission, appendix C.
\65\ 2019 Guidance at 22-25.
---------------------------------------------------------------------------
Second, PacifiCorp argued that recent decision making regarding
emission controls for the first implementation period and PacifiCorp's
installation of post-combustion controls during that period should
exempt Jim Bridger from further analysis during the second
implementation period. PacifiCorp referenced the reasonable progress
``reassessment'' conducted under 40 CFR 51.308(d)(1) for the first
implementation period, which led to Wyoming's submission of a first
implementation period SIP revision containing emission limits
associated with the conversion from coal-firing to natural gas-firing
at Units 1-2.\66\ PacifiCorp also highlighted the 2015-2016
installation of SCR on Units 3-4 and FGD scrubbers upgraded on Units 1-
4 between 2008-2011. PacifiCorp argued that these first implementation
period controls eliminate the need for a four-factor analysis for the
second implementation period, pointing to the EPA's statement in the
2019 Guidance that ``it may be appropriate for a state to rely on a
previous . . . reasonable progress analysis for the characterization of
a factor, for example information developed in the first implementation
period on the availability, cost, and effectiveness of controls for a
particular source, if the previous analysis was sound and no
significant new information is available.'' \67\
---------------------------------------------------------------------------
\66\ If approved, Wyoming's first planning period SIP submission
would replace the State's previously approved source-specific
NOX long-term strategy determination for Jim Bridger
Units 1 and 2 of 0.07 lb/MMBtu for each unit, which is associated
with the installation of SCR controls. Wyoming found that conversion
from coal-firing to natural gas-firing, together with NOX
emission limits of 0.12 lb/MMBtu (30-day rolling average) and 1,314
tons/year, and a heat input limit of 21,900,000 MMBtu/year, allows
for identical reasonable progress during the first planning period
as the installation of SCR controls. The EPA issued a notice of
proposed rulemaking on this first implementation period SIP
submission, 89 FR 25200 (April 10, 2024), but has not yet taken
final action.
\67\ 2019 Guidance at 36.
---------------------------------------------------------------------------
Third, PacifiCorp asserted that Jim Bridger Units 1-2 are exempt
from four-factor analysis for the second implementation period because,
under the company's 2019 Integrated Resource Plan (IRP), Unit 1 was
scheduled for retirement by the end of 2023 and Unit 2 was scheduled
for retirement before the end of 2028.\68\ Those scheduled closures
both fall within the second planning period, although PacifiCorp
acknowledged it is not subject to an enforceable obligation to close
any units at Jim Bridger.
---------------------------------------------------------------------------
\68\ PacifiCorp Integrated Resource Plan, October 18, 2019.
Volume I at 12-13.
---------------------------------------------------------------------------
Lastly, PacifiCorp stated that under the EPA's 2019 Guidance,
Wyoming may consider changes in operating parameters, such as those
resulting from renewable energy sources coming online, to exempt Jim
Bridger Units 1-4 from four-factor analysis. PacifiCorp cited its 2019
IRP,\69\ which documents plans to make operational adjustments at Jim
Bridger to accommodate renewable energy resources. PacifiCorp stated
that these changes will cause future emissions at Jim Bridger to differ
significantly from historical emissions.
---------------------------------------------------------------------------
\69\ Id., Volume I at 8.
---------------------------------------------------------------------------
b. PacifiCorp--Naughton Power Plant \70\
---------------------------------------------------------------------------
\70\ This facility is addressed at pages 136-37 and appendix C
of the Wyoming 2022 SIP submission.
---------------------------------------------------------------------------
PacifiCorp's Naughton Power Plant is located in Lincoln County,
Wyoming. Naughton is comprised of two tangentially-fired units burning
pulverized coal (Units 1-2) and one natural gas-fired unit (Unit 3),
which have a total net generating capacity of 700 MW. Emissions from
Naughton may affect the visibility in 17 Class I areas in Colorado,
Idaho, Montana, Nevada, Utah, and Wyoming (table 32).
Neither the State nor PacifiCorp conducted a four-factor analysis
for Naughton. Instead, Wyoming refers to the ``facility analysis
information'' submitted by PacifiCorp, which Wyoming included as
appendix C in its 2022 SIP submission. The State references
PacifiCorp's 2019 IRP, which includes the planned retirement of Units 1
and 2 by the end of 2025.\71\ Unit 3 ceased coal combustion in 2019 and
converted to natural gas that same year. The State also notes that
Naughton Units 1-2 already have NOX and SO2
emission control technologies in place (table 5).
---------------------------------------------------------------------------
\71\ Separately, and in the State's discussion of the long-term
strategy to set reasonable progress goals, Wyoming refers to the
planned retirement of Naughton Units 1-2 by the end of 2025 to meet
the requirements of the CCR rule. Wyoming 2022 SIP submission at
227.
Table 5--Installed NOX and SO2 Emissions Controls at Naughton Units 1-2
------------------------------------------------------------------------
Unit SO2 controls NOX controls
------------------------------------------------------------------------
1 FGD................... LNB/SOFA.
2 FGD................... LNB/SOFA.
------------------------------------------------------------------------
The State further explains that although its modeling incorporated
the planned retirements and associated emissions reductions at Units 1-
2, the State is not crediting the planned emissions reductions until
the facility submits a permit application and the State issues a
permit. The State notes that DSI is not being considered for Units 1-2
because the existing scrubbers are more effective for SO2
removal. Wyoming states that it intends to conduct additional analysis
on Units 1-2 in its 2025 regional haze progress report.
With respect to Naughton Unit 3, the State asserts that the 2019
conversion to natural gas resulted in a potential reduction of 8,909.5
tons of visibility impairing pollutants. The Q/d analysis of Naughton
Unit 3 is 4.1, which the State notes is below its chosen threshold of
Q/d > 10 for sources warranting a four-factor analysis.
In its response to the State's initial request to submit a four-
factor analysis,\72\ PacifiCorp asserted that its Naughton facility
should be excluded from that requirement, and consequently should not
be required to install any additional controls or take further actions
during the regional haze second implementation period. PacifiCorp
relied on arguments similar to those it provided for Jim Bridger,
discussed in section IV.C.1.a. above.
---------------------------------------------------------------------------
\72\ Wyoming 2022 SIP submission, appendix C.
---------------------------------------------------------------------------
First, PacifiCorp cited its 2019 IRP preferred portfolio, which
includes the planned retirement of Naughton Units 1-2 by the end of
2025 (before the end of the regional haze second planning period in
2028). PacifiCorp acknowledged that it is under no legal obligation to
close those units by that time, but detailed the plans in its 2019
[[Page 63045]]
IRP to initiate closure of Units 1-2, complete regulatory notices and
filings, engage in employee transition and community action plans,
confirm transmission system reliability, and terminate, amend, or close
out existing permits, contracts, and agreements.\73\ PacifiCorp also
pointed to the EPA's coal combustion residuals (CCR) disposal rule as
further impacting the certainty of closure for Naughton Units 1-2 if
that rule is finalized as proposed. According to PacifiCorp, the CCR
rule would require it to construct new, lined CCR impoundments that
PacifiCorp claimed would prove uneconomical for its customers, or
otherwise cease operation and close the CCR impoundments by 2028.
---------------------------------------------------------------------------
\73\ PacifiCorp Integrated Resource Plan, October 18, 2019.
Volume I at 22-23.
---------------------------------------------------------------------------
Second, PacifiCorp asserted that Naughton Units 1-3 already have
effective NOX and SO2 controls in place, thereby
exempting these units from further analysis. Specifically, PacifiCorp
referenced: (1) FGD scrubber systems, installed on Unit 1 in 2011 and
on Unit 2 in 2012, as meeting the applicable alternative SO2
emission limit of the 2012 MATS rule; and (2) LNB/SOFA NOX
emission controls installed on Unit 1 in 2012 and on Unit 2 in 2011.
Additionally, PacifiCorp explained that Unit 3 ceased coal-fired
operation in 2019 and is undergoing conversion to natural gas. These
NOX and SO2 emission control technologies,
according to PacifiCorp, align with the examples provided in the EPA's
2019 Guidance.
Third, PacifiCorp cited expected operational adjustments at
Naughton to accommodate increases in renewable energy as an additional
reason why a four-factor analysis is not required. PacifiCorp stated
that Naughton's 2028 projected operations, or lack thereof, indicate
that the plant's emissions will differ significantly from historical
emissions due to PacifiCorp's changing portfolio and market
opportunities to increase both energy efficiency and renewable
resources.
Finally, PacifiCorp concluded that given the planned retirements of
Units 1-2, Naughton would fall below Wyoming's Q/d threshold of >10 and
should therefore be excluded from four-factor analysis at this time.
According to PacifiCorp's calculations, Unit 3 would be the only
operating unit throughout the second implementation period and has a Q/
d of 4.1 for the nearest Class I area (Bridger Wilderness).
c. Basin Electric--Laramie River Station Power Plant \74\
---------------------------------------------------------------------------
\74\ This facility is addressed at pages 137-42 and appendix D
of the Wyoming 2022 SIP submission.
---------------------------------------------------------------------------
Basin Electric's Laramie River Station Power Plant is located in
Platte County, Wyoming and is comprised of three 614 MW (gross)
subbituminous coal-fired boilers. Emissions from Laramie River Station
may affect the visibility in 10 Class I areas in Colorado, South
Dakota, and Wyoming (table 32).
Table 6 describes the installed NOX, SO2, and
PM emissions controls for all three units.
Table 6--Installed NOX, SO2, and PM Emissions Controls at Laramie River Station 1-3
----------------------------------------------------------------------------------------------------------------
Unit SO2 controls NOX controls PM controls
----------------------------------------------------------------------------------------------------------------
1.................................... Wet FGD................ LNB/OFA \1\ + SCR...... ESPs.\2\
2.................................... Wet FGD................ LNB/OFA + SNCR \3\..... ESPs.
3.................................... Dry FGD................ LNB/OFA + SNCR......... ESPs.
----------------------------------------------------------------------------------------------------------------
\1\ Overfire air (OFA).
\2\ Electrostatic precipitation (ESP).
\3\ Selective non-catalytic reduction (SNCR).
Relying on an analysis submitted by the facility (included as
appendix D in the Wyoming 2022 SIP submission), the State conducted a
four-factor analysis for NOX and SO2 controls,
but not for PM controls. The State did not evaluate Unit 1 for further
NOX emissions controls because it is equipped with SCR,
which the State asserts is the best available control technology (BACT)
for NOX. The State evaluated SCR as the technically feasible
option for further NOX emissions control on Units 2 and 3
(table 7). For further SO2 emissions control for Units 1 and
2, the State evaluated equipment upgrades and chemical additives to the
existing wet FGD controls as well as the installation of a 6th absorber
vessel. For SO2 emissions controls for Unit 3, the State
evaluated converting the existing ESP to a fabric filter (FF) and
replacing the existing ESP and installing a new stand-alone FF (table
8).
Table 7--Summary of Laramie River Station Units 2-3 NOX Cost Analysis
----------------------------------------------------------------------------------------------------------------
Emission Average cost
Unit Control technology reduction Total annual cost effectiveness
(tons/year) ($/year) ($/ton)
----------------------------------------------------------------------------------------------------------------
2 SCR.......................... 1,917 $45,473,000 $23,722
3 SCR.......................... 2,676 45,058,000 16,840
----------------------------------------------------------------------------------------------------------------
Table 8--Summary of Laramie River Station Units 1-3 SO2 Cost Analysis
----------------------------------------------------------------------------------------------------------------
Emission Average cost
Unit Control technology reduction Total annual cost effectiveness
(tons/year) ($/year) ($/ton)
----------------------------------------------------------------------------------------------------------------
1 Wet FGD upgrades............. 235 $1,134,000 $4,824
Wet FGD additives............ 494 5,018,000 10,156
6th absorber vessel.......... 587 7,399,000 12,611
2 Wet FGD upgrades............. 266 1,167,000 4,388
Wet FGD additives............ 559 7,266,000 12,998
[[Page 63046]]
6th absorber vessel.......... 664 10,068,000 15,168
3 ESP to FF conversion......... 703 20,079,000 28,551
ESP to FF replacement........ 703 25,022,000 35,580
----------------------------------------------------------------------------------------------------------------
The State estimated the time necessary to achieve compliance using
SCR controls at Units 2 and 3 to be 60 months. It estimated the time
necessary to achieve compliance at Units 1 and 2 using wet FGD upgrades
as 11 months, wet FGD additives as 12 months, and addition of a 6th
absorber vessel as 60 months. The State estimated the time necessary to
achieve compliance with ESP to FF conversion to be 32 months and ESP to
FF replacement to be 46 months. These timelines do not include the time
associated with regulation development or SIP approval.
The State identified several energy and non-air environmental
impacts associated with the installation and operation of potential
controls at Laramie River Station. For SCR on Units 2 and 3, the State
noted increased auxiliary power requirements and heat rate penalty,
potential decrease in ammonia slip emissions, and potential increase in
SO2 emissions. For SO2 controls on Units 1 and 2,
the State observed that (1) wet FGD upgrades may result in increased
limestone consumption, increased solid FGD by-product management and
disposal, and increased auxiliary power requirements and heat rate
penalty; (2) wet FGD additives may result in increased limestone
consumption, high reagent consumption cost, increased solid FGD by-
product management and disposal, and increased auxiliary power
requirements and heat rate penalty; and (3) 6th absorber vessel
addition may require capital intensive projects, resulting in
relocation of existing dewatering equipment, increased limestone and
water consumption, increased solid FGD by-product management and
disposal, and increased auxiliary power requirements and heat rate
penalty. Finally, as to converting the existing ESP to a FF or
replacing the existing ESP with a FF, the State noted impacts from
capital intensive projects, extended unit outage or unit derate, and
increased auxiliary power requirements and heat rate penalty.
In its consideration of the remaining useful life of Laramie River
Station Units 1-3, the State used the 20-year equipment life of the
control measures.
Finally, the State highlighted that NOX emissions are
below the permitted \75\ threshold and have been decreasing overall,
particularly for Units 1 and 3. The State also noted that it did not
expect permit conditions to change between 2020 and the third
implementation period. Likewise, the State determined that
SO2 emissions have declined by over 780 tons/year between
the three units, SO2 emissions trends do not show an
increase in emissions, and permit conditions are not anticipated to
change between 2020 and the third planning period.
---------------------------------------------------------------------------
\75\ Wyoming Permit Number 3-2-102.
---------------------------------------------------------------------------
Ultimately, after considering the four factors, historical
emissions data, and permit conditions, Wyoming determined that no
additional controls are necessary on Laramie River Station Units 1-3 in
the second planning period for regional haze. The State concluded that
further controls will be evaluated in the third planning period.
d. PacifiCorp--Dave Johnston Power Plant \76\
---------------------------------------------------------------------------
\76\ This facility is addressed at pages 143-45 and appendix C
of the Wyoming 2022 SIP submission.
---------------------------------------------------------------------------
PacifiCorp's Dave Johnston Power Plant is located in Converse
County, Wyoming and is comprised of four coal-fired units using local
subbituminous coal. Units 3 and 4 were both subject to BART in the
first planning period. Unit 3 is a nominal 230 MW pulverized coal-fired
boiler that commenced service in 1964 and has a federally enforceable
commitment to shut down by December 31, 2027. Unit 4 is a nominal 361
MW pulverized coal-fired tangential boiler that commenced service in
1972 and is equipped with FGD for SO2 control, LNB/SOFA for
NOX control, and a baghouse retrofit for PM control.
Emissions from Dave Johnston may affect the visibility in 13 Class I
areas in Colorado, South Dakota, and Wyoming (table 32).
Neither the State nor PacifiCorp conducted a four-factor analysis
for Units 1-3. Instead, the State referenced information supplied by
PacifiCorp in appendix C of Wyoming's 2022 SIP submission and in
PacifiCorp's 2019 IRP. The 2019 IRP includes the planned retirement of
Units 1 and 2 by the end of 2027 \77\ and the federally enforceable
retirement of Unit 3 by December 31, 2027.\78\ The State explained that
its modeling incorporated the planned retirements and associated
emission reductions at Units 1-3. However, until the facility submits a
permit application and the State issues a permit, the State is not
crediting the planned emission reductions and intends to conduct
additional analysis on Units 1-3 in its 2025 regional haze progress
report.
---------------------------------------------------------------------------
\77\ Separately, and in the State's discussion of the long-term
strategy to set reasonable progress goals, Wyoming refers to an
enforceable federal commitment to close Dave Johnston Units 1-2 by
the end of 2028 to meet the requirements of the Effluent Limitations
Guidelines and Standards for the Steam Electric Power Generating
Point Source Category for regulation of wastewater discharges from
power plants. Wyoming 2022 SIP submission at 227.
\78\ PacifiCorp Integrated Resource Plan, October 18, 2019.
Volume I at 13.
---------------------------------------------------------------------------
In its response to the State's initial request to submit a four-
factor analysis,\79\ PacifiCorp asserted that Dave Johnston should be
excluded from that requirement, and consequently should not be required
to install any additional controls or take further actions during the
regional haze second planning period. PacifiCorp submitted a four-
factor analysis only for Unit 4.
---------------------------------------------------------------------------
\79\ Wyoming 2022 SIP submission, appendix C.
---------------------------------------------------------------------------
PacifiCorp argued that several factors alleviate the need for a
four-factor analysis for Dave Johnston Units 1-3. First, PacifiCorp
cited its 2019 IRP preferred portfolio, which includes the planned--but
not federally enforceable--retirement of Dave Johnston Units 1-2 by the
end of 2027 (before the end of the regional haze second planning period
in 2028).\80\ PacifiCorp also pointed to the EPA's proposed revisions
to the Effluent Limitations Guidelines and Standards for the Steam
Electric Power Generating Point Source Category as further impacting
the certainty of closure for Units 1-2 if the rules are finalized as
proposed. PacifiCorp contended that the rules would require generating
units like Dave Johnston Units 1-2 that currently rely on the discharge
of treated bottom ash transport water into
[[Page 63047]]
a surface impoundment to close by December 31, 2028.
---------------------------------------------------------------------------
\80\ PacifiCorp Integrated Resource Plan, October 18, 2019.
Volume I at 12-13.
---------------------------------------------------------------------------
Second, PacifiCorp explained that Dave Johnston Unit 3 is subject
to a federally enforceable requirement to shut down and is therefore
not subject to four-factor analysis. As a result of its decision to
pursue a shutdown compliance option provided in the EPA's 2014 FIP,
PacifiCorp requested that the State revise BART permit MD-6041A to
include an enforceable requirement for Unit 3 to cease operation by
December 31, 2027.
Third, PacifiCorp argued that Dave Johnston Unit 3 currently has
effective SO2 and PM emissions control technology in place,
which it asserted exempts this unit from further analysis. PacifiCorp
referenced: (1) FGD scrubber systems, installed in 2010, as meeting the
applicable alternative SO2 emission limit of the 2012 MATS
rule; and (2) a baghouse retrofit for PM emissions control installed in
2010. PacifiCorp argued that these SO2 and PM emissions
controls align with the examples provided in the EPA's 2019 Guidance.
Finally, PacifiCorp urged Wyoming to consider changes in operating
parameters at Dave Johnston Units 1-3 to accommodate increased
deployment of renewable energy resources in its portfolio. PacifiCorp
stated that these operational adjustments will cause future emissions
at Dave Johnston to decline compared to historical emissions.
PacifiCorp argued that the EPA's 2019 Guidance allows for consideration
of such circumstances when evaluating the need for a four-factor
analysis.
Unlike Units 1-3, the State performed a four-factor analysis for
Dave Johnston Unit 4 for NOX and SO2 controls.
Table 9 describes the installed NOX, SO2, and PM
controls at Unit 4.
Table 9--Installed NOX, SO2, and PM Emissions Controls at Dave Johnston, Unit 4
----------------------------------------------------------------------------------------------------------------
Unit SO2 controls NOX controls PM controls
----------------------------------------------------------------------------------------------------------------
4.................................... FGD; SDA \1\........... LNB/OFA................ FF baghouse.
----------------------------------------------------------------------------------------------------------------
\1\ Spray dryer absorber.
The State evaluated both SNCR and SCR as technically feasible
options for NOX control at Unit 4 (table 10). DSI was not
evaluated for SO2 control because, according to the State,
scrubber upgrades are more effective than DSI for incremental pollution
control; no further SO2 analysis was conducted. No four-
factor analysis for PM controls was provided.
Table 10--Summary of Dave Johnston Unit 4 NOX Cost Analysis
----------------------------------------------------------------------------------------------------------------
Emission Average cost
Control technology Emission rate reduction Total annual cost effectiveness
(lb/MMBtu) \1\ (tons/year) ($/year) ($/ton)
----------------------------------------------------------------------------------------------------------------
SNCR......................................... 0.12 187 $2,889,000 $15,411
SCR.......................................... 0.05 1,035 11,881,000 11,480
----------------------------------------------------------------------------------------------------------------
\1\ Pound per one million British thermal units (lb/MMBtu).
The State estimated the time necessary to achieve compliance using
either SNCR or SCR at Unit 4 to be 2028, the end of the second planning
period.
The State identified the following energy and non-air environmental
impacts associated with the installation and operation of SCR:
increased electrical energy to operate; the storage, use, and disposal
of ammonia (a hazardous substance); and a potential increase in the
amount of coal the unit would be required to burn to achieve the same
amount of energy production, resulting in an increase of CCR waste
requiring disposal, emissions of greenhouse gases, and consumption of
water and other resources. The State also identified the storage and
use of urea as a non-air environmental impact associated with the
installation and operation of SNCR.
The State estimated the remaining useful life of Unit 4 to be 2027
based on PacifiCorp's 2019 IRP. However, the State also noted that
PacifiCorp used a depreciable life of 20 years for SNCR and 30 years
for SCR to estimate costs.
Based on the four-factor analysis, the State determined that
installation of SNCR or SCR at Unit 4 is not cost-effective, would
require long lead times before emissions reductions are achieved, would
have negative energy and non-air environmental impacts, and would make
the unit less likely to operate through the end of its remaining useful
life. Additional consideration of historical emissions data and permit
conditions, which Wyoming expects to remain the same, led the State to
ultimately determine that no additional controls are necessary for Unit
4 in the second planning period.
e. Genesis Alkali--Westvaco \81\
---------------------------------------------------------------------------
\81\ This facility is addressed at pages 145-55 and appendix E
of the Wyoming 2022 SIP submission.
---------------------------------------------------------------------------
Genesis Alkali's Westvaco facility is a trona ore \82\ mine and
soda ash production plant located in Sweetwater County, Wyoming.
Westvaco has two existing subbituminous coal-fired boilers, Unit NS-1A
and Unit NS-1B, with each having a design heat input rate of 887 MMBtu/
hr. The facility also has two mono calciners (MONO5 and NS3) and one
lime kiln (SM-1) that, combined with the two boilers, have emissions of
NOX, SO2, and PM totaling at least 100 tons/year.
Emissions from Westvaco may affect the visibility in 19 Class I areas
in Colorado, Idaho, Montana, Utah, and Wyoming (table 32).
---------------------------------------------------------------------------
\82\ Trona is a mineral found in large deposits in Wyoming and
elsewhere. It is a common source of sodium carbonate (soda ash).
---------------------------------------------------------------------------
Table 11 describes the installed NOX, SO2,
and PM emissions controls at Westvaco.
[[Page 63048]]
Table 11--Installed NOX, SO2, and PM Emissions Controls at Westvaco
----------------------------------------------------------------------------------------------------------------
Unit SO2 controls NOX controls PM controls
----------------------------------------------------------------------------------------------------------------
NS-1A (coal-fired boiler)............ Wet scrubber........... LNB/OFA................ ESP.
NS-1B (coal-fired boiler)............ Wet scrubber........... LNB/OFA................ ESP.
NS3 (gas-fired calciner)............. ....................... Good combustion \1\.... ESP.
MONO5 (gas-fired calciner)........... ....................... Good combustion \1\.... Wet scrubber.
SM-1 (gas-fired kiln)................ ....................... Good combustion \1\.... Wet scrubber.
----------------------------------------------------------------------------------------------------------------
\1\ Wyoming used the term ``good combustion practices'' to describe existing efforts to control NOX emissions
from these units. Although not specified by the State, good combustion practices may include, but are not
limited to, proper burner maintenance, proper burner alignment, proper fuel to air distribution and mixing,
routine inspection, and preventive maintenance.
The State conducted a four-factor analysis for several units at
Westvaco, relying on information submitted by the facility (attached as
appendix E to the Wyoming 2022 SIP submission). In its evaluation of
further NOX emissions controls, the State considered SNCR
and SCR for the two coal-fired boilers and LNB for the gas-fired
calciners and lime kiln (table 12). Trona injection prior to ESP was
evaluated for further SO2 emissions control on the coal-
fired boilers; no further SO2 emissions controls were
evaluated for the gas-fired calciners and lime kiln (table 13). For
further PM emissions control, the State evaluated FF and wet ESP on the
two coal-fired boilers, wet ESP on one of the calciners (NS3), and ESP
and wet ESP on the other calciner (MONO5) and lime kiln (table 14).
Table 12--Summary of Westvaco NOX Cost Analysis
----------------------------------------------------------------------------------------------------------------
Emission Average cost
Unit Control technology reduction Total annual cost ($/ effectiveness
(tons/year) year) ($/ton)
----------------------------------------------------------------------------------------------------------------
NS-1A (coal-fired boiler)........ SNCR/SCR........... 397/893 $3,079,590/$5,395,079 $7,757/$6,039
NS-1B (coal-fired boiler)........ SNCR/SCR........... 414/933 3,014,532/5,379,506 7,273/5,769
NS3 (gas-fired calciner)......... LNB................ 36.6 530,569 14,490
MONO5 (gas-fired calciner)....... LNB................ 28.3 395,507 14,000
SM-1 (gas-fired kiln)............ LNB................ 44.1 323,875 7,339
----------------------------------------------------------------------------------------------------------------
Table 13--Summary of Westvaco SO2 Cost Analysis
----------------------------------------------------------------------------------------------------------------
Emission Average cost
Unit Control technology reduction Total annual cost effectiveness
(tons/year) ($/year) ($/ton)
----------------------------------------------------------------------------------------------------------------
NS-1A (coal-fired boiler)........... Trona injection prior 205.6 $2,674,635 $13,007
to ESP.
NS-1B (coal-fired boiler)........... Trona injection prior 201.9 2,674,634 13,249
to ESP.
----------------------------------------------------------------------------------------------------------------
Table 14--Summary of Westvaco PM Cost Analysis
----------------------------------------------------------------------------------------------------------------
Emission Average cost
Unit Control technology reduction Total annual cost ($/ effectiveness ($/
(tons/year) year) ton)
----------------------------------------------------------------------------------------------------------------
NS-1A (coal-fired boiler)...... Fabric filter/Wet \1\ 242.2/ $3,466,804/$3,064,278 $14,314/$12,652
ESP. 242.2
NS-1B (coal-fired boiler)...... Fabric filter/Wet \1\ 33.4/33.4 3,445,297/3,026,284 103,079/90,542
ESP.
NS3 (gas-fired calciner)....... Wet ESP........... 267.2 2,196,068 8,219
MONO5 (gas-fired calciner)..... ESP/Wet ESP....... 145/145 1,203,249/1,330,528 8,296/9,174
SM-1 (gas-fired kiln).......... ESP/Wet ESP....... 15.7/15.7 911,823/1,114,931 58,004/70,924
----------------------------------------------------------------------------------------------------------------
\1\ The PM emissions reductions for NS-1A and NS-1B do not match due to a difference in the 2014 stack test data
and heat input.
The State estimated the time necessary to achieve compliance using
the controls it evaluated to be at least four years.
The State identified several energy and non-air environmental
impacts associated with potential controls at Westvaco. For
installation and operation of SNCR on the coal-fired boilers, the State
noted storage of additional reagent chemicals onsite, ammonia slip,
generation and disposal of wastewater, and generation of emissions due
to additional fuel combustion to overcome the energy penalty associated
with SNCR. For installation and operation of SCR on the coal-fired
boilers, the State identified impacts related to the transport,
handling, and use of aqueous ammonia, replacement and disposal of spent
catalyst, and adverse air impacts due to ammonia slip; possible
formation of a visible plume; oxidation of carbon monoxide to carbon
dioxide; and oxidation of SO2 to sulfur trioxide, with
subsequent formation of sulfuric acid mist due to ambient or stack
moisture. The State observed that running a wet ESP would require
additional electricity and would lead to the generation and disposal of
solid waste and wastewater, while replacement of the ESP with a FF
would require additional electricity and disposal of the filter bags as
waste upon replacement.
The State considered the remaining useful life of the emission
units at Westvaco to be 20 years or more.
Finally, Wyoming described the Westvaco permitted NOX,
SO2, and PM
[[Page 63049]]
emissions limits \83\ for the boilers, calciners, and lime kiln in
addition to emissions trends for these units over five years (2016-
2020). For the boilers, the figures show consistent declines in
NOX emissions (from approximately 900 tons/year to
approximately 600 tons/year), SO2 emissions (from
approximately 1,300 tons/year to approximately 550 tons/year), and PM
emissions (from approximately 100 tons/year to almost 0 tons/year). For
the calciners, NOX emissions remained constant (50-100 tons/
year) and PM emissions slightly declined (from approximately 230 tons/
year to 220 tons/year). PM emissions for the lime kiln remained
consistent (approximately 20 tons/year), while NOX emissions
increased slightly (from approximately 50 tons/year to approximately 75
tons/year). The State notes that permit conditions were renewed in 2021
and it does not expect emissions at Westvaco to increase before the
third planning period.
---------------------------------------------------------------------------
\83\ Wyoming Permit Number 3-1-132. The Wyoming 2022 SIP
submission at 151 appears to erroneously refer to this permit as
Wyoming Permit Number 3-2-132.
---------------------------------------------------------------------------
After considering the four factors, historical emissions data, and
current control technologies, Wyoming determined that no additional
controls are necessary at Westvaco in the second planning period for
regional haze. The State concluded that further controls will be
evaluated in the third planning period.
f. Mountain Cement Company--Laramie Portland Cement \84\
---------------------------------------------------------------------------
\84\ This facility is addressed at pages 156-60 and appendix L
of the Wyoming 2022 SIP submission.
---------------------------------------------------------------------------
Mountain Cement Company's Laramie Portland Cement plant is located
in Laramie, Wyoming and consists of one long-dry process kiln (Kiln 1)
and one long-dry 2-stage preheater kiln (Kiln 2). Together, the kilns
are permitted to produce 900,000 tons of cement annually, with Kilns 1
and 2 capable of producing 254,000 tons/year of clinker and 547,500
tons/year of clinker, respectively. Emissions from Laramie Portland
Cement may affect the visibility in five Class I areas in Colorado
(table 32).
Table 15 describes the installed NOX, SO2,
and PM emissions controls at Laramie Portland Cement.
Table 15--Installed NOX, SO2, and PM Emissions Controls at Laramie Portland Cement
----------------------------------------------------------------------------------------------------------------
Unit SO2 controls NOX controls PM controls
----------------------------------------------------------------------------------------------------------------
Kiln 1............................... Inherent dry scrubbing. Good combustion Baghouse.
practice.
Kiln 2............................... Inherent dry scrubbing. Good combustion Baghouse.
practice/2-stage
preheater.
----------------------------------------------------------------------------------------------------------------
Wyoming did not evaluate further SO2 or PM emissions
controls based on historical decreasing emissions trends, PM emissions
limits for both kilns based on CAA maximum achievable control
technology (MACT) standards, and the use of dust collectors/baghouses
that constitute BACT for PM at all point sources at the facility.\85\
---------------------------------------------------------------------------
\85\ Wyoming 2022 SIP submission, appendix L.
---------------------------------------------------------------------------
Relying on an evaluation submitted by the facility (attached as
appendix L to the Wyoming 2022 SIP submission), the State conducted a
four-factor analysis for NOX emissions control and evaluated
SNCR as a technically feasible option (table 16).
Table 16--Summary of Laramie Portland Cement Plant Kilns 1-2 * NOX Cost Analysis Associated With SNCR
----------------------------------------------------------------------------------------------------------------
Emission Average cost
Level of control (% emissions Total capital reduction Total annual effectiveness ($/
reductions) investment ($) (tons/year) cost ($/year) ton)
----------------------------------------------------------------------------------------------------------------
10..................................... $5,833,000 933 $17,639,442 $18,900
15..................................... ................. 1,005.6 ................. 17,540
20..................................... ................. 1,077.9 ................. 16,360
25..................................... ................. 1,150.2 ................. 15,340
----------------------------------------------------------------------------------------------------------------
* Figures are for both kilns combined.
The State estimated the time necessary to achieve compliance using
SNCR to be a minimum of 18 months for design, procurement, build, and
installation, plus an additional 12 months for staging the installation
process across both kilns.
The State identified the following energy and non-air environmental
impacts associated with the installation and operation of SNCR:
increased electrical energy to operate the SNCR system; possible
byproducts from unreacted ammonia, including ammonium sulfate, ammonium
bisulfite, and ammonium chloride; and ammonia slip, which can reduce
visibility. In addition, the State noted that ammonia and salt
absorption into the cement kiln dust (a byproduct) could also make the
cement kiln dust unsellable, resulting in an economic penalty.
The State estimated the remaining useful life of Kilns 1 and 2 to
be longer than the projected lifetime of the pollution control
technology (SNCR) of 20 years, which is the capital cost recovery
period of the controls.\86\
---------------------------------------------------------------------------
\86\ According to Laramie Portland Cement's cost analyses found
in appendix L of Wyoming's 2022 SIP submission, the facility used an
amortization period of 10 years to evaluate SNCR on Kilns 1 and 2.
---------------------------------------------------------------------------
The State noted that NOX emissions at Kilns 1 and 2
consistently decreased between 2016 and 2020 and that permitted
emissions are not expected to change. It also pointed out that Kiln 2
NOX emissions, in particular, have consistently fallen under
the allowable emission limit. Based on consideration of the four
factors, historical emissions data, and current control technologies,
Wyoming determined that no additional controls at Laramie Portland
Cement are
[[Page 63050]]
necessary to make reasonable progress in the regional haze second
implementation period. It stated that further controls will be
evaluated in the third implementation period.
g. PacifiCorp--Wyodak Power Plant \87\
---------------------------------------------------------------------------
\87\ This facility is addressed at page 160 and appendix C of
the Wyoming 2022 SIP submission.
---------------------------------------------------------------------------
PacifiCorp's Wyodak Power Plant (Wyodak) is located in Campbell
County, Wyoming and includes one coal-fired boiler burning sub-
bituminous coal, with a net generating capacity of 335 MW. Emissions
from Wyodak may affect the visibility in 11 Class I areas in Colorado,
North Dakota, South Dakota, and Wyoming (table 32).
Neither the State nor PacifiCorp conducted a four-factor analysis
for Wyodak. In response to the State's initial request to submit a
four-factor analysis,\88\ PacifiCorp explained that it was
participating in ongoing confidential settlement discussions regarding
the first planning period requirements for Wyodak, which it argued will
influence whether and how a four-factor analysis will be completed.
PacifiCorp requested that the State delay submittal of a second
planning period analysis until after settlement discussions concluded.
Wyoming referred to ongoing litigation as the reason not to evaluate
this source and stated that a four-factor analysis will occur in a
future implementation period, if needed.
---------------------------------------------------------------------------
\88\ Wyoming 2022 SIP submission, appendix C.
---------------------------------------------------------------------------
h. TATA Chemicals--Green River Works \89\
---------------------------------------------------------------------------
\89\ This facility is addressed at pages 161-67 and appendix G
of the Wyoming 2022 SIP submission.
---------------------------------------------------------------------------
TATA Chemicals' Green River Works facility is a trona ore mine and
soda ash production plant located in Sweetwater County, Wyoming. Green
River Works has two existing subbituminous coal-fired stoker boilers, C
Boiler and D Boiler, with a firing rate of 534 MMBtu/hour and 880
MMBtu/hour, respectively. In addition, Green River Works has seven
natural gas-fired calciners: five smaller calciners rated at 65 tons of
soda ash/hour (50 MMBtu/hour) and two larger calciners, Calciner 1 and
Calciner 2, rated at 145 tons of soda ash/hour (200 MMBtu/hour).
Relying on information submitted by the facility (attached as appendix
G to Wyoming's 2022 SIP submission), the State conducted a four-factor
analysis for the two coal-fired boilers and the two large natural gas-
fired calciners, as these units have annual actual emissions of
visibility-impairing pollutants in excess of 100 tons/year. The State
asserts that the remaining emission units at Green River Works are
small and contribute a fraction of the facility's visibility-impairing
emissions; no four-factor analysis was performed for those units.
Emissions from Green River Works may affect the visibility in 19 Class
I areas in Wyoming (table 32).
Table 17 describes the installed NOX, SO2,
and PM emissions controls at Green River Works.
Table 17--Installed NOX, SO2, and PM Emissions Controls at Green River Works
----------------------------------------------------------------------------------------------------------------
Unit NOX controls SO2 controls PM controls
----------------------------------------------------------------------------------------------------------------
C Boiler............................. LNB + OFA.............. DSI.................... ESPs.
D Boiler............................. LNB + OFA.............. DSI.................... ESPs.
Calciner 1........................... ....................... ....................... ESPs.
Calciner 2........................... ....................... ....................... ESPs.
----------------------------------------------------------------------------------------------------------------
In its evaluation of further NOX emissions controls, the
State evaluated SNCR and SCR on the two coal-fired boilers and LNB and
SCR on the two calciners (table 18). It evaluated wet and dry flue gas
desulfurization (FGD) for further SO2 emissions control on
the coal-fired boilers (table 19). The State evaluated wet and dry ESP
for further PM emissions control on the two calciners (table 20).
Table 18--Summary of Green River Works NOX Cost Analysis
----------------------------------------------------------------------------------------------------------------
Emission Average cost
Unit Control reduction Total annual cost ($/year) effectiveness \1\
technology (tons/year) \1\ ($/ton)
----------------------------------------------------------------------------------------------------------------
C Boiler..................... SNCR/SCR........ 98/295 $885,174/$3,701,998 $9,000/$12,547
D Boiler..................... SNCR/SCR........ 150/449 $1,195,034/$5,525,216 $7,992/$12,317
Calciner 1................... LNB/SCR......... 48.3/56.4 $269,500/$548,100 $5,580/$9,720
Calciner 2................... LNB/SCR......... 28.9/38.3 $269,500/$540,900 $9,310/$14,140
----------------------------------------------------------------------------------------------------------------
\1\ The total annual cost and average cost effectiveness figures for the C and D Boilers in Wyoming's 2022 SIP
submission on page 164 conflict with the figures presented in appendix G (pages G-36 and G-57, among others).
The figures from page 164 are presented in table 18.
Table 19--Summary of Green River Works SO2 Cost Analysis
--------------------------------------------------------------------------------------------------------------------------------------------------------
Emission Average cost
Unit Control technology reduction (tons/ Total annual cost ($/year) effectiveness ($/
year) ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
C Boiler........................................ Dry FGD/Wet FGD................... 855.3/894.4 $5,407,000/$6,092,600 $6,320/$6,810
D Boiler........................................ Dry FGD/Wet FGD................... 1,392.0/1,456.7 $8,889,200/$10,023,100 $6,390/$6,880
--------------------------------------------------------------------------------------------------------------------------------------------------------
[[Page 63051]]
Table 20--Summary of Green River Works PM Cost Analysis
----------------------------------------------------------------------------------------------------------------
Emission Average cost
Unit Control reduction Total annual cost ($/year) effectiveness ($/
technology (tons/year) ton)
----------------------------------------------------------------------------------------------------------------
Calciner 1................... Wet ESP/Dry ESP. 67.8/57.9 $1,202,900/$976,900 $17,700/$16,900
Calciner 2................... Wet ESP/Dry ESP. 69.3/67.7 $1,202,900/$976,900 $17,400/$14,400
----------------------------------------------------------------------------------------------------------------
For the two boilers, the State estimated the time necessary to
achieve compliance using SCR to be 28 months and using SNCR to be 24
months. For the two calciners, the State estimated that installation of
LNB or SCR would take 28 months, and installation of wet or dry ESP
would take 18 months. It estimated the time needed to install wet and
dry FGD on the two boilers to be 36 months. These timelines do not
include time associated with regulation development or SIP approval.
The State identified several energy and non-air environmental
impacts associated with the installation and operation of controls at
Green River Works. For SCR or SNCR, the State noted the storage of
additional reagent chemicals onsite, ammonia slip, increased electric
power requirements, and formation of ammonium salt, which may result in
additional fine particulate matter emissions. As to wet or dry FGD, the
State identified steam output capacity penalty or reduction of more
than 1%, along with a boiler efficiency impact of approximately 1.5%,
combined with additional electricity and water demand and liquid and
solid waste disposal requirements. In addition, the State asserted that
dry FGD systems (for SO2 control) may increase PM emissions
from the boiler, while the operation of a wet FGD system, and
potentially a dry FGD system, would result in visibility impacts by
causing a visible plume from the stack.
In considering remaining useful life, the State explained that both
the emission units and the new equipment are expected to last 20 years
or more.
Finally, Wyoming provided the emission trends for the C and D
Boilers over five years (2016-2020).\90\ The figures show that C Boiler
NOX emissions remained steady (at approximately 400 tons/
year), while SO2 emissions consistently declined (from
approximately 1,800 tons/year to approximately 700 tons/year). For the
D Boiler, NOX emissions also remained steady (at
approximately 600 tons/year), while SO2 emissions
consistently declined (from approximately 3,500 tons/year to
approximately 1,000 tons/year). Wyoming stated that NOX and
SO2 emissions from the C and D Boilers are not expected to
significantly increase between 2020 and the third planning period.
---------------------------------------------------------------------------
\90\ Wyoming 2022 SIP submission at 166-67.
---------------------------------------------------------------------------
Ultimately, based on its consideration of the four factors,
historical emissions data, and current control technologies, Wyoming
determined that no additional controls are necessary at Green River
Works in the second planning period for regional haze. The State
concluded that further controls will be evaluated in the third planning
period.
i. Contango Resources, Inc.--Elk Basin Gas Plant \91\
---------------------------------------------------------------------------
\91\ This facility is addressed at pages 168-72 and appendix H
of the Wyoming 2022 SIP submission.
---------------------------------------------------------------------------
Contango Resources, Inc.'s Elk Basin Gas Plant in Park County,
Wyoming is a sour natural gas processing and liquids extraction plant
designed to process 10 million standard cubic feet per day of sour gas
into propane, butane, natural gas, gasoline, and elemental sulfur. The
Elk Basin Gas Plant has nine natural gas-fired compressor engines and a
natural gas-fired incinerator, with each having a design heat input
rate of 358.5 MMBtu/hour. Emissions from the Elk Basin Gas Plant may
affect the visibility in two Class I areas in Wyoming (table 32).
Relying on information submitted by the facility (attached as
appendix H to the Wyoming 2022 SIP submission), the State evaluated low
emission combustion (LEC) for further NOX emissions control
on the nine compressor engines (table 21). For further SO2
emissions control on the incinerator, it evaluated one option of
optimization of the existing 2-stage Claus Plant, and another option of
adding a third stage to the Claus Plant and adding a tail gas treating
unit (table 22). The State did not evaluate further PM emissions
controls on any units.
Table 21--Summary of Elk Basin Gas Plant NOX Cost Analysis
----------------------------------------------------------------------------------------------------------------
Emission Average cost
Unit Control reduction effectiveness
technology (tons/year) ($/ton)
----------------------------------------------------------------------------------------------------------------
Nine (9) compressor engines (EC1-EC9)........................ LEC 1,793.55 $1,500-$2,200
----------------------------------------------------------------------------------------------------------------
Table 22--Summary of Elk Basin Gas Plant SO2 Cost Analysis
----------------------------------------------------------------------------------------------------------------
Emission Average cost
Unit Control technology reduction effectiveness
(tons/year) ($/ton)
----------------------------------------------------------------------------------------------------------------
Incinerator (INC-1)........................ Optimizing 2-stage Claus Plant..... 50 $24,000
Adding a 3rd stage to the Claus 80 200,000
Plant and a tail gas treating unit.
----------------------------------------------------------------------------------------------------------------
The State estimated the time necessary to achieve compliance using
LEC NOX emissions controls on the nine compressor engines to
be three to five years after the SIP is approved. For SO2
control on the incinerator, it estimated that optimizing the 2-stage
Claus Plant would take two to five years, while adding a third stage to
the Claus Plant
[[Page 63052]]
together with adding a tail gas treating unit would take three to five
years after the SIP is approved.
The State identified the following energy and non-air environmental
impacts associated with the installation and operation of LEC controls
on the nine compressor engines: an annual electricity cost increase of
approximately $11,500 per 1,200 horsepower engine and a potential
decrease in PM emissions due to more ideal combustion. Likewise, the
State expected that optimizing the 2-stage Claus Plant and adding a
third stage to the Claus Plant would both result in increased use of
electricity due to added instrumentation. It noted that the amount of
sulphur catalyst requiring landfill disposal is expected to decrease
with the optimization of the existing 2-stage Claus Plant, while adding
a third stage to the Claus Plant is expected to increase sulphur
catalyst disposal needs.
In evaluating remaining useful life, Wyoming stated that the LEC
control units are expected to last 20 to 25 years. Both control options
for the tail gas incinerator are expected to last 30 years.
The State also provided the permitted SO2 emissions
limits for the incinerator \92\ and emissions trends for both the
incinerator and nine compressor engines over five years (2016-2020).
The figures show that the incinerator's SO2 emissions
consistently dropped (from approximately 500 tons/year to approximately
350 tons/year) and are below the permitted limit of 3,044.1 tons/year.
According to the State, the SO2 emissions from the
incinerator are expected to continue to decrease. The figures show
consistent declines in NOX emissions between 2016-2020 for
all compressor engines except EC8, which showed a slight increase.
Overall, Wyoming concluded that NOX and SO2
emissions at the Elk Basin Gas Plant have consistently declined and are
not expected to change in a way that significantly increases emissions.
---------------------------------------------------------------------------
\92\ Wyoming Permit Number 0022339.
---------------------------------------------------------------------------
Ultimately, after considering the four factors, emissions trends,
and permit conditions, Wyoming determined that the Elk Basin Gas Plant
may warrant further analysis of emission controls. The State remarked
that it would submit more detailed analyses in the regional haze
progress report due January 31, 2025, to determine if any new controls
are reasonable for this facility and should be scheduled for
implementation.
j. Genesis Alkali--Granger Soda Ash Facility \93\
---------------------------------------------------------------------------
\93\ This facility is addressed at pages 172-77 and appendix I
of the Wyoming 2022 SIP submission.
---------------------------------------------------------------------------
Genesis Alkali's Granger Soda Ash facility (Granger) is a trona ore
mine and soda ash production plant located in Sweetwater County,
Wyoming. Granger has two existing subbituminous coal-fired stoker
boilers, Unit UIN-14 and Unit UIN-15, with each having a design heat
input rate of 358.5 MMBtu/hour. The remaining emission units at Granger
reported 2014 actual emissions of less than 5 tons/year each of
SO2, NOX, and PM10. Emissions from
Granger may affect the visibility in two Class I areas in Wyoming
(table 32).
Table 23 describes the installed NOX, SO2,
and PM emissions controls at Granger.
Table 23--Installed NOX, SO2, and PM Emissions Controls at Granger
------------------------------------------------------------------------
NOX PM
Unit SO2 controls controls controls
------------------------------------------------------------------------
UIN-14 (coal-fired boiler)... Wet scrubber.... OFA........ ESP.
UIN-15 (coal-fired boiler)... Wet scrubber.... OFA........ ESP.
------------------------------------------------------------------------
Relying on information submitted by the facility (attached as
appendix I to the Wyoming 2022 SIP submission), the State conducted a
four-factor analysis for further emissions controls on the two coal-
fired boilers. It evaluated SNCR and SCR for further NOX
control (table 24), trona injection prior to ESP for further
SO2 control (table 25), and wet ESP and FF for further PM
control (table 26).
Table 24--Summary of Granger NOX Cost Analysis
----------------------------------------------------------------------------------------------------------------
Emission Average cost
Unit Control reduction Total annual cost ($/year) effectiveness ($/
technology (tons/year) ton)
----------------------------------------------------------------------------------------------------------------
UIN-14 (coal-fired boiler)... SNCR/SCR........ 271/610 $1,450,702/$3,175,904 $5,347/$5,202
UIN-15 (coal-fired boiler)... SNCR/SCR........ 233/524 1,422,667/3,175,825 6,111/6,063
----------------------------------------------------------------------------------------------------------------
Table 25--Summary of Granger SO2 Cost Analysis
----------------------------------------------------------------------------------------------------------------
Emission Average cost
Unit Control technology reduction Total annual effectiveness ($/
(tons/year) cost ($/year) ton)
----------------------------------------------------------------------------------------------------------------
UIN-14 (coal-fired boiler)......... Trona injection prior 104.5 $2,745,234 $26,283
to ESP.
UIN-15 (coal-fired boiler)......... Trona injection prior 70.4 2,745,202 38,994
to ESP.
----------------------------------------------------------------------------------------------------------------
[[Page 63053]]
Table 26--Summary of Granger PM Cost Analysis
--------------------------------------------------------------------------------------------------------------------------------------------------------
Emission
Unit Control technology reduction Total annual cost ($/year) Average cost effectiveness
(tons/year) ($/ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
UIN-14 (coal-fired boiler).................. Wet ESP/FF.................... 8.9/8.9 $1,765,111/$1,945,510 $198,774/$219,089
UIN-15 (coal-fired boiler).................. Wet ESP/FF.................... 120/120 1,732,090/1,933,758 14,434/16,115
--------------------------------------------------------------------------------------------------------------------------------------------------------
The State estimated the time necessary to achieve compliance to be
at least four years. The State also identified several energy and non-
air environmental impacts associated with the installation and
operation of the controls it evaluated. For SNCR, it noted the storage
of additional reagent chemicals onsite, ammonia slip, generation and
disposal of wastewater, and generation of further emissions due to
additional fuel combustion to overcome the energy penalty associated
with SNCR. As to SCR, the State identified the transport, handling, and
use of aqueous ammonia; replacement and disposal of spent catalyst; and
adverse air impacts due to ammonia slip, possible formation of a
visible plume, oxidation of carbon monoxide to carbon dioxide, and
oxidation of SO2 to sulfur trioxide with subsequent
formation of sulfuric acid mist due to ambient or stack moisture. The
State remarked that additional electricity would be needed for
operation of a wet ESP, which would also require generation and
disposal of solid waste and wastewater. Replacement of the ESP with a
FF would require additional electricity and disposal of the filter bags
as waste upon replacement, while trona injection prior to electrostatic
precipitation would generate solid waste and require additional
electricity. For remaining useful life, the State estimated that the
emission units are expected to last 20 years or more.
Finally, Wyoming noted that Granger has shut down several sources
since 2014 and has made voluntary emissions reductions as part of the
Granger Optimization Project. That project triggered prevention of
significant deterioration (PSD) review for NOX,
SO2, and PM10 emissions and included an
evaluation of the facility's emissions impacts at nearby Class I areas,
which the State found to be acceptable.
The State also provided the permitted NOX,
SO2, and PM emission limits \94\ and emissions trends for
the boilers over five years (2016-2020). The figures show that boiler
UIN-14 NOX emissions dropped (from approximately 630 tons/
year to approximately 120 tons/year), as did SO2 emissions
(from approximately 180 tons/year to approximately 20 tons/year) and PM
emissions (from approximately 95 tons/year to approximately 10 tons/
year). Emissions also declined for boiler UIN-15 for NOX
(from approximately 675 tons/year to approximately 150 tons/year),
SO2 (from approximately 150 tons/year to approximately 10
tons/year), and PM (from approximately 40 tons/year to approximately 10
tons/year). Wyoming concluded that NOX, SO2, and
PM emissions at both boilers decreased or remained consistent between
2016 and 2020, remained under their permitted emission limits, and are
not expected to change for the next permit renewal.
---------------------------------------------------------------------------
\94\ Wyoming Permit Number 0021849. Emission limits for each
boiler, UIN-14 and UIN-15, are 985.5 tons/year for NOX,
284.7 tons/year for SO2, and 118.3 tons/year for PM.
---------------------------------------------------------------------------
Ultimately, Wyoming determined, based on the four factors,
emissions trends, and permit conditions, that no additional controls
are necessary at Granger to make reasonable progress in the second
planning period for regional haze. The State concluded that further
controls will be evaluated in the third planning period.
k. Burlington Resources--Lost Cabin Gas Plant \95\
---------------------------------------------------------------------------
\95\ This facility is addressed at pages 178-82 and appendix J
of the Wyoming 2022 SIP submission.
---------------------------------------------------------------------------
Burlington Resources' Lost Cabin Gas Plant is a natural gas
sweeting plant located in Fremont County, Wyoming. The plant has two
natural gas processing trains, Trains 2 and 3; each processing train
consists of a solvent absorption section to separate carbon dioxide
(CO2), hydrogen sulfide (H2S), and carbonyl
sulfide (COS) from the natural gas.\96\ Emissions from the Lost Cabin
Gas Plant may affect the visibility in three Class I areas in Wyoming
(table 32).
---------------------------------------------------------------------------
\96\ Train 1 was decommissioned and decoupled from Train 2.
Wyoming 2022 SIP submission at 178.
---------------------------------------------------------------------------
Relying on information submitted by the facility (attached as
appendix J to the Wyoming 2022 SIP submission), the State evaluated wet
scrubbers for SO2 emissions control on Trains 2 and 3 (table
27).\97\ It noted that the Lost Cabin Gas Plant is currently
controlling SO2 emissions by continued emphasis on
minimization of flaring events through the combination of operational
controls, equipment upgrades, and facility design changes.\98\ Wyoming
did not conduct a four-factor analysis for NOX and PM
emissions control measures, reasoning that NOX and PM
account for a small fraction of total emissions from the facility.\99\
---------------------------------------------------------------------------
\97\ Flaring emissions were not included in the SO2
control analysis because SO2 emissions from flaring are
already well controlled, according to the State, and decreased from
2,289 tons/year to 1,075 tons/year between 2014 and 2018.
\98\ Significant changes to the facility design were implemented
to reduce flaring and SO2 emissions, including addition
of a sulfur tank vapor thermal oxidized in 2017, improved tail gas
unit cooling on Train 2, addition of a flare H2S analyzer
on Train 2 (Train 3 pending) to troubleshoot potential sour vent and
drain valve leaks, and addition of fuel gas assist and improved
programming logic for sour flare events on both Trains 2 and 3.
Wyoming 2022 SIP submission at 178-79.
\99\ According to Wyoming, total NOX and
PM10 emissions for the Lost Cabin Gas Plant are 124.9
tons/year and 12.0 tons/year, respectively. Wyoming 2022 SIP
submission at 178.
Table 27--Summary of Lost Cabin Gas Plant SO2 Cost Analysis
----------------------------------------------------------------------------------------------------------------
Emission Total annual Average cost
Unit Control technology reduction cost ($/year) effectiveness
(tons/year) \1\ ($/ton) \2\
----------------------------------------------------------------------------------------------------------------
Train 2............................. Wet Scrubber........... 174.9 $1,442,233 $7,710
[[Page 63054]]
Train 3............................. Wet Scrubber........... 304.2 2,438,411 7,470
----------------------------------------------------------------------------------------------------------------
\1\ Cost figures reflect those on page 179 and appendix J of the Wyoming 2022 SIP submission. The cost figures
found in table 11-34 on page 180 of the Wyoming 2022 SIP submission ($1,348,694 for Train 2 and $2,272,044 for
Train 3) conflict with these. These conflicting numbers are addressed in section IV.C.2.b.ii. of this
document.
\2\ Cost figures reflect those on page 180 of the Wyoming 2022 SIP submission, which conflict with the cost
figures found in appendix J ($8,250 for Train 2 and $8,010 for Train 3). These conflicting numbers are
addressed in section IV.C.2.b.ii. of this document.
The State estimated the time necessary to achieve compliance using
wet scrubbers to be 30 months, but potentially up to 42 months.
The State identified the following energy and non-air environmental
impacts associated with the installation and operation of wet scrubbers
on Trains 2 and 3: an energy penalty from operation of the scrubber
systems; significant water usage; disposal of salt-laden spent scrubber
liquor; and the possibility of highly visible secondary particulate
formation.
The State estimated the remaining useful life of the wet scrubbers
to be 15 years. Additionally, Wyoming noted that actual SO2
emissions (269 tons/year from Train 2 and 338.05 tons/year from Train 3
in 2020) have consistently remained under allowable emission limits
(503.7 tons/year for Train 2 and 1,366.6 tons/year for Train 3). The
State also provided SO2 emissions trends for Trains 2 and 3
over five years (2016-2020). The figures show that SO2
emissions from Train 2 consistently increased (from approximately 125
tons/year to approximately 275 tons/year), while SO2
emissions from Train 3 trended upward between 2016 and the end of 2018
(from approximately 280 tons/year to approximately 340 tons/year)
before dropping to 0 tons/year in 2019 and 2020.\100\ The State also
noted an overall reduction in actual SO2 emissions from 2014
to 2018 of 1,553.6 tons/year (which represents total SO2
actual emissions, including those from flaring), as well as a permitted
allowable SO2 emission reduction of 389.6 tons/year.
---------------------------------------------------------------------------
\100\ According to the State, in December 2018, Train 3 had a
backfire and was not operating in 2019 and 2020. Train 3 was rebuilt
and restarted in early 2021; the State expects consistent emissions
trends following the rebuild. Wyoming 2022 SIP submission at 181.
---------------------------------------------------------------------------
Wyoming concluded that installing wet scrubbers for SO2
emissions control on Trains 2 and 3, at a cost of over $7,000/ton
removed, is cost prohibitive. In addition, the State noted that it
expects total SO2 emissions to decrease year-over-year as
production continues to decline at an approximate rate of 4 to 5
percent, with overall SO2 emissions declining at 3 to 5
percent per year during normal operation.
Ultimately, Wyoming determined, after consideration of the four
factors and emissions trends, not to propose any changes to current
SO2 emissions controls at the Lost Cabin Gas Plant. The
State concluded that further controls will be evaluated in the third
planning period.
l. Dyno Nobel Inc.--Cheyenne Fertilizer Facility \101\
---------------------------------------------------------------------------
\101\ This facility is addressed at pages 182-91 and appendix K
of the Wyoming 2022 SIP submission.
---------------------------------------------------------------------------
Dyno Nobel Inc.'s Cheyenne Fertilizer Facility is a chemical
manufacturing plant located in Cheyenne, Wyoming that produces ammonia,
nitric acid, urea/diesel exhaust fluid, carbon dioxide, low density
ammonium nitrate, and other related products. Relying on information
submitted by the facility (attached as appendix K to the Wyoming 2022
SIP submission), the State conducted a four-factor analysis for several
emission units: two natural gas-fired Cooper reciprocating compressor
engines (ENG004 and ENG005), a natural gas-fired primary reformer
(CKD001), and three cooling towers (CTW001, CTW002, CTW003). Together,
these units account for 88.6% of the total NOX,
SO2, and PM10 emissions from the facility.
Emissions from the Cheyenne Fertilizer Facility may affect the
visibility in two Class I areas in Colorado (table 32).
Table 28 describes the installed NOX, SO2,
and PM emissions controls at the Cheyenne Fertilizer Facility.
Table 28--Installed NOX, SO2, and PM Emissions Controls at the Cheyenne Fertilizer Facility
----------------------------------------------------------------------------------------------------------------
Unit SO2 controls \1\ NOX controls PM controls
----------------------------------------------------------------------------------------------------------------
ENG004 (engine)...................... ....................... Lean burn combustion...
ENG005 (engine)...................... ....................... Lean burn combustion...
CKD001 (reformer).................... ....................... LNB....................
CTW001 (cooling tower)............... ....................... ....................... Legacy mist eliminator.
CTW002 (cooling tower)............... ....................... ....................... Mist eliminator.\2\
CTW003 (cooling tower)............... ....................... ....................... Legacy mist eliminator.
----------------------------------------------------------------------------------------------------------------
\1\ All emission units are natural gas-fired.
\2\ Designed for 0.001% drift.
For further NOX emissions control, the State evaluated
LEC and SCR on the two engines and SCR on the reformer (table 29). The
State evaluated upgraded mist eliminators for further PM emissions
control on two of the cooling towers (CTW001 and CTW003) (table 30). No
additional SO2 controls were evaluated for any of the
natural gas-fired units.
[[Page 63055]]
Table 29--Summary of the Cheyenne Fertilizer Facility NOX Cost Analysis
----------------------------------------------------------------------------------------------------------------
Emission Average cost
Unit Control reduction (tons/ Total annual cost effectiveness ($/
technology year) ($/year) ton)
----------------------------------------------------------------------------------------------------------------
ENG004, ENG005 (engines)........ LEC............... 229/engine........ $244,100/engine... $1,067/engine
SCR............... 78 \1\............ 418,700........... 5,354.
CKD001 (reformer)............... SCR............... 34................ 716,300........... 21,030.
----------------------------------------------------------------------------------------------------------------
\1\ Emission reductions beyond LEC.
Table 30--Summary of Cheyenne Fertilizer Facility PM Cost Analysis
----------------------------------------------------------------------------------------------------------------
Emission Average cost
Unit Control technology reduction Total annual effectiveness ($/
(tons/year) cost ($/year) ton)
----------------------------------------------------------------------------------------------------------------
CTW001 (cooling tower).............. Upgraded mist 15.5 $16,300 $1,056
eliminators.
CTW003 (cooling tower).............. Upgraded mist 2.4 5,740 2,368
eliminators.
----------------------------------------------------------------------------------------------------------------
The State estimated the time necessary to achieve compliance using
LEC retrofits on the engines to be one year. However, the State
asserted that the retrofits need to be completed during the next
scheduled turnarounds, which are four years apart for each engine and
are scheduled for 2026 and 2030. The State estimated the time necessary
to achieve compliance using SCR to be one to two years but noted it
would require a total shutdown that could not occur until 2030 or
later. The State estimated the time necessary to achieve compliance
using the mist eliminator upgrades on the cooling towers to be one to
five years for CTW001 and six or more years for CTW003 because the
upgrades must occur during a scheduled turnaround/shutdown.
The State identified several energy and non-air environmental
impacts associated with the installation and operation of potential
controls. For SCR on the engines and reformer, the State noted the need
to retrofit both the engines and reformer into the existing structures
using extensive ductwork, which may lead to a pressure drop
corresponding to a slight decrease in efficiency. Wyoming asserted this
could result in greater fuel and energy consumption as well as upsets
due to backpressure effects, which could lead to forced shutdowns,
safety incidents/injuries, excess emissions, and wasted product. The
LEC retrofit on the engines would require a modest increase to heat
load, while the mist eliminator upgrades for the cooling towers were
not expected to result in any significant energy and non-air quality
environmental impacts. In its evaluation of remaining useful life, the
State estimated 25 years for SCR and LEC and 30 years for the mist
eliminator upgrades.
Wyoming also provided the Cheyenne Fertilizer Facility permitted
NOX emission limits \102\ for the engines and reformer, in
addition to NOX emissions trends for these units over five
years (2016-2020). NOX emissions for the engines initially
declined (from approximately 1,500 tons/year in 2016 to approximately
500 tons/year in 2019) before increasing in 2020 (to approximately
1,500 tons/year). According to the State, a stack test performed in
April 2021 indicated that NOX emissions from the engines
were 700 tons/year, representing a decrease of over 50% in emissions
from the 2016-2020 time frame.\103\ In addition, the average
NOX emission rate for both engines was 46.9 lb/hour in 2021,
below their allowable emission rate of 170.61 lb/hour, which has
remained the same since 2012 and the State asserts is unlikely to
change when a new permit is issued. The NOX emissions trends
for the reformer over five years (2016-2020) indicate a decline from
approximately 120 tons/year in 2016 to approximately 35 tons/year in
2020. In addition, the average NOX emission rates for the
reformer between 2016-2020 varied between 4-10 lb/hour, below the
permitted limit of 28.2 lb/hour, which has also remained the same since
2012 and the State believes is unlikely to change when a new permit is
issued. The State also provided PM emissions trends for all three
cooling towers (CTW001, CTW002, and CTW003) over five years (2016-
2020), which show a decline in PM emissions (from approximately 400
tons/year to approximately 25 tons/year across all three cooling towers
combined).
---------------------------------------------------------------------------
\102\ Wyoming Title V Permit Number 0022581.
\103\ According to the State, the emissions measurement
methodology was consistent between 2016-2020 but changed to an
alternate, more accurate stack test methodology in 2021. Wyoming
2022 SIP submission at 188.
---------------------------------------------------------------------------
Wyoming concluded that, given emissions trends and allowable vs.
actual emission rates, there is no evidence that NOX
emissions from the engines and reformer will increase or that changes
to the allowable emissions will be necessary, as NOX
emissions are expected to remain consistent or decrease between 2020
and 2028. The State also determined that the total capital investment
required to install mist eliminators on CTW001 and CTW003 is not
justified given what it considered to be a ``minute'' amount of
potential PM emissions reductions.
Overall, after considering the four factors and emissions trends,
Wyoming determined that no additional emission controls are necessary
at the Cheyenne Fertilizer Facility to make reasonable progress in the
second planning period for regional haze. At the same time, the State
also concluded that this facility may warrant further analysis of
emission controls to reach reasonable progress, which it stated would
be detailed in the progress report due January 31, 2025.
m. Summary of Wyoming's Reasons for Concluding That No Additional
Emission Reduction Measures Are Necessary To Make Reasonable Progress
After evaluating the twelve sources it had selected for
consideration of additional controls, Wyoming concluded that no new
controls on those sources are warranted during the regional haze second
planning period.\104\ Chapter 13 of Wyoming's 2022 SIP submission
summarizes the State's reasons for not requiring any additional
emission reduction measures
[[Page 63056]]
to make reasonable progress toward the national visibility goal.
---------------------------------------------------------------------------
\104\ Wyoming 2022 SIP submission at 206.
---------------------------------------------------------------------------
First, the State explained how it considered costs of compliance.
Wyoming did not rely on a cost-effectiveness threshold to determine
whether additional emission reduction measures are reasonable. It
asserted that the cost of additional controls could harm the State's
economy and the livelihoods of Wyoming's rural communities,
particularly because coal-fired units and oil and gas development tend
to operate in rural areas that depend on those activities for economic
support. The State remarked that any additional costs could cause
economic stress to energy producers that are operating in an uncertain
financial climate, potentially forcing those sources out of the market
prematurely. It also pointed to potential detrimental effects on grid
stability and on Wyoming and out-of-state ratepayers.
Second, Wyoming highlighted historical and anticipated reductions
in emissions from first implementation period measures, increasing
renewable energy generation, facility shutdowns and conversions, and
measures taken in other states and nationwide. It described emission
reductions at Wyoming facilities since 2014, noting that NOX
emissions declined by almost 17,400 tons, SO2 emissions
declined by approximately 18,000 tons, and PM10 emissions
declined by almost 850 tons. Wyoming expects further reductions to
occur between 2020 and 2028, which it asserted will benefit all Class I
areas. It pointed to expected facility retirements at Dave Johnston
Units 1 and 2, which Wyoming stated has an enforceable consent decree
requirement to cease coal operations by 2028; Dave Johnston Unit 3,
which has an enforceable state and federal commitment to close by the
end of 2027; and Naughton Units 1 and 2, which Wyoming stated are
planned to retire by the end of 2025. Wyoming also cited future
facility conversions at Jim Bridger Units 1 and 2, which have an
enforceable conversion to natural gas by January 2024,\105\ and
Naughton Unit 3, which converted from coal to natural gas in 2019.
---------------------------------------------------------------------------
\105\ The EPA has proposed to approve Wyoming's 2022 SIP
submission to convert Jim Bridger Units 1-2 from coal-fired boilers
to natural gas-fired boilers and establish associated NOX
and annual heat input limits. 89 FR 25200.
---------------------------------------------------------------------------
Third, the State considered the level of potential visibility
improvements at issue. Wyoming stated that all seven Class I areas
within the State are below the adjusted URP glidepath to attain natural
conditions by 2064. It noted that potential additional controls, which
would reduce NOX by 12,300 tons and SO2 by 10,000
tons, would not impact the projected 2028 and 2064 visibility
conditions in Wyoming Class I areas. According to the State, WRAP
modeling indicates that potential additional controls would have
``little to no influence'' (less than 0.1 deciview) \106\ on visibility
improvement in Wyoming's Class I areas. Wyoming also pointed to the
impact on visibility of sources beyond its control, noting that
international anthropogenic sources and natural sources such as
wildfires are large contributors to visibility impairment in the
State's Class I areas.
---------------------------------------------------------------------------
\106\ Wyoming 2022 SIP Submission at 205.
---------------------------------------------------------------------------
The State ultimately concluded that imposing any additional costs
on Wyoming sources is unwarranted during the second implementation
period. Wyoming stated that it will continue to monitor Class I area
visibility, regional haze, sources of emissions, and electrical and oil
and gas markets, and will reevaluate its position in the next regional
haze progress report due in January 2025.
2. The EPA's Evaluation
The EPA finds that Wyoming's selection of twelve sources to
evaluate through four-factor analyses, as described in section IV.C.1.
of this document, was reasonable. However, as detailed in sections
IV.C.2.a.-d. below, we find that Wyoming's long-term strategy does not
satisfy the requirements of CAA section 169A and 40 CFR 51.308(f)(2) on
four separate grounds: (1) Wyoming failed to consider the required four
statutory factors to analyze control measures for some selected sources
to determine what is necessary to make reasonable progress, despite
determining that those sources may affect visibility at certain Class I
areas; (2) Wyoming did not document the technical basis of some of its
decisions and made numerous calculation and other methodological
errors; (3) Wyoming unreasonably rejected emission reduction measures
for some sources; and (4) Wyoming's other reasons for not requiring any
emission reduction measures in its long-term strategy (e.g., its
reliance on alleged economic hardships, historical and future emissions
reductions, and lack of visibility improvement) are not adequately
supported or lack foundation in the CAA and RHR. Therefore, we are
proposing to disapprove Wyoming's long-term strategy for the second
implementation period under CAA section 169A and 40 CFR 51.308(f)(2).
The following sections IV.C.2.a.-d. detail these separate bases for our
proposed disapproval, with a focus on specific sources, units, and
pollutants for illustrative purposes.
a. Failure To Perform a Four-Factor Analysis To Analyze Control
Measures for Selected Sources To Determine What Is Necessary To Make
Reasonable Progress
Under CAA section 169A and 40 CFR 51.308(f)(2), a state must submit
a long-term strategy to make reasonable progress for Class I areas
within the state and Class I areas outside the state that may be
affected by the state's emissions. CAA section 169A(g)(1) and 40 CFR
51.308(f)(2)(i) provide that in determining the emission reduction
measures necessary to make reasonable progress, the state must consider
the following four factors:
Costs of compliance;
Time necessary for compliance;
Energy and non-air quality environmental impacts of
compliance; and
Remaining useful life of any potentially affected sources.
In its 2022 SIP submission, Wyoming determined that twelve
stationary sources should be evaluated for additional controls due to
their potential effect on visibility at Class I areas within the State
and outside the State. For some of these sources, we acknowledge that
there are several instances where the State appropriately relied on the
effectiveness of existing controls or an existing federally enforceable
commitment to cease operations as a reason to forgo a four-factor
analysis. However, for other sources, neither the State nor the
facility determined the emission reduction measures that are necessary
for reasonable progress by considering the four statutory factors--nor
did they provide technical documentation or other justification to
support that lack of analysis--despite the State's determination that
those sources may affect visibility at Class I areas. Therefore, we
find that Wyoming failed to meet the requirements under CAA section
169A and 40 CFR 51.308(f)(2)(i) to consider the four statutory factors
for the sources and associated units and pollutants listed in table 31
that may affect visibility at Class I areas.
[[Page 63057]]
Table 31--Sources, Units, and Associated Pollutants That May Affect
Visibility at Class I Areas and Selected for Four-Factor Analysis Where
No Four-Factor Analysis Was Performed
------------------------------------------------------------------------
Associated
Source Unit(s) pollutant(s)
------------------------------------------------------------------------
Jim Bridger (PacifiCorp)........ 1, 2.............. NOX, SO2, PM
Jim Bridger (PacifiCorp)........ 3, 4.............. SO2, PM
Naughton (PacifiCorp)........... 1, 2.............. NOX, SO2, PM
Naughton (PacifiCorp)........... 3................. NOX, PM
Dave Johnston (PacifiCorp)...... 1, 2.............. NOX, SO2, PM
Dave Johnston (PacifiCorp)...... 4................. PM
Wyodak (PacifiCorp)............. 1................. NOX, SO2, PM
Laramie River Station (Basin 1-3............... PM
Electric).
Laramie Portland Cement Kilns 1, 2........ SO2
(Mountain Cement Company).
Elk Basin Gas Plant (Contango Engines (9) and PM
Resources, Inc.). incinerator.
Elk Basin Gas Plant (Contango Engines (9)....... SO2
Resources, Inc.).
Elk Basin Gas Plant (Contango Incinerator....... NOX
Resources, Inc.).
Lost Cabin Gas Plant............ Trains 2, 3....... NOX, PM
------------------------------------------------------------------------
States are required to evaluate sources, or groups of sources, that
may be affecting visibility at Class I areas within the state and
outside the state. Although states have discretion under the RHR in
identifying sources or groups of sources, the implementation plan must
include a description of the criteria the state used to determine which
sources or groups of sources it evaluated and how the four factors were
taken into consideration in selecting the measures for inclusion in its
long-term strategy.\107\ Many of the sources for which Wyoming failed
to conduct a four-factor analysis are among the largest contributors to
visibility impairment in Class I areas, according to the State's own Q/
d analysis (table 32).
---------------------------------------------------------------------------
\107\ CAA section 169A(b)(2)(B), CAA section 169A(g)(1), and 40
CFR 51.308(f)(2)(i). While states have discretion to select a
reasonable set of sources for four-factor analysis, their selection
should result in a set of pollutants and sources with the potential
to meaningfully reduce contributions to visibility impairment. 2021
Clarifications Memo at 3 (noting that a source selection process
that ``excludes a state's largest visibility impairing sources from
selection is more likely to be unreasonable'').
---------------------------------------------------------------------------
BILLING CODE 6560-50-P
[[Page 63058]]
Table 32--Wyoming Sources That the State Determined May Affect Class I
Areas and Respective Q/d Values for Total NOX, SO2, and PM10 Emissions
at Affected Class I Areas
[GRAPHIC] [TIFF OMITTED] TP01AU24.001
[[Page 63059]]
[GRAPHIC] [TIFF OMITTED] TP01AU24.002
BILLING CODE 6560-50-C
Table 32 shows the Q/d value associated with each of the sources
that Wyoming determined may affect visibility at Class I areas and that
it selected for four-factor analysis. Q represents the total sum of
NOX, SO2, and PM emissions, and d represents the
distance (in kilometers) to the nearest Class I area. The larger the Q/
d value, the greater the source's expected effect on visibility in each
associated Class I area. The State's own analysis shows that Jim
Bridger, Naughton, and Dave Johnston are expected to have the greatest
effect on visibility at the seven Wyoming Class I areas, more than the
other sources the State selected. Nevertheless, the State did not
conduct a four-factor analysis on any of those sources, except for a
single unit (Unit 4) at Dave Johnston. Further, as detailed in sections
IV.C.2.a.i.-iii. below, none of the reasons the State provided justify
not conducting four-factor analyses of sources it determined may affect
visibility at Class I areas to determine what is necessary for
reasonable progress, as required under CAA section 169A(g)(1) and 40
CFR 51.308(f)(2)(i).
i. Reliance on Existing Controls Without Adequate Technical
Documentation To Avoid Four-Factor Analysis of Sources That May Affect
Visibility at Class I Areas
In declining to perform a four-factor analysis for Jim Bridger
Units 1-4 and Naughton Units 1-3, the State maintained that these
sources have effective NOX and SO2 emissions
control technologies in place. PacifiCorp argued in its submittal to
the State (appendix C to the SIP submission) that these sources are
exempt from further analysis under the EPA's 2019 Guidance because they
have effective NOX and SO2 emissions control
technologies in place. PacifiCorp and the State specifically referred
to the presence of: (1) FGD scrubber systems that meet the applicable
alternative SO2 MATS emissions limit; (2) NOX and
SO2 emissions controls installed during the first planning
period and operated year-round with an effectiveness of at least 90
percent on a pollutant-specific basis
[[Page 63060]]
(e.g., FGD or SCR); (3) LNB/SOFA NOX emission controls; and
(4) BART-eligible units that installed and began operating controls to
meet BART emission limits in the first planning period.
Without additional explanation from the State, the EPA disagrees
that these sources' existing NOX and SO2
emissions controls exempt these sources from the requirement to
consider the four statutory factors to determine whether additional
controls are necessary for reasonable progress. The EPA's 2019 Guidance
illustrates scenarios in which it may be reasonable for a state not to
select a particular source for further analysis due to the source's
existing emissions controls, including:
For the purposes of SO2 emissions control
measures, FGD controls that meet the applicable alternative
SO2 emission limit of the 2012 MATS rule for coal-fired
power plants (0.2 lb/MMBtu);
For the purposes of SO2 and PM emissions
control measures, combustion of only pipeline natural gas;
For the purposes of SO2 and NOX
emissions control measures, FGD that operates year-round with an
effectiveness of at least 90 percent or SCR that operates year-round
with an overall effectiveness of at least 90 percent, on a pollutant-
specific basis; and
BART-eligible units that installed and began operating
controls to meet BART emission limits for the first implementation
period, on a pollutant-specific basis.\108\
---------------------------------------------------------------------------
\108\ 2019 Guidance at 24-25.
---------------------------------------------------------------------------
The premise underlying the flexibility for ``effectively
controlled'' sources is that performing a four-factor analysis would be
futile due to the unavailability of further cost-effective emission
controls.\109\ Indeed, some units at Jim Bridger and Naughton may
already have effective controls installed on a pollutant-specific basis
(e.g., Jim Bridger Units 3-4 with SCR for NOX emissions
control and Naughton Unit 3 with combustion of pipeline natural gas for
SO2 emissions control), and we agree that it would be
reasonable not to perform four-factor analyses for those particular
units on a pollutant-specific basis. However, it is not readily
apparent, due to the State's failure to provide a sufficient technical
demonstration, that additional emission controls for NOX or
SO2 at Jim Bridger and Naughton would not be cost-effective
or reasonable. For example, the State could have evaluated post-
combustion NOX controls (e.g., SNCR and SCR) for Jim Bridger
Units 1-2 and Naughton Units 1-3, which are currently equipped only
with combustion controls. It may also be possible to achieve a lower
SO2 emissions rate at Jim Bridger Units 1-4 \110\ and
Naughton Units 1-2 by optimizing existing SO2 emissions
controls (e.g., requiring existing scrubbers to run continuously at
their maximum efficiencies), in addition to evaluating whether scrubber
upgrades or tightening emission limits might be reasonable.
Additionally, regardless of the State's determination that existing
SO2 emissions controls are effective, those existing
controls may be necessary to make reasonable progress and therefore
must be included in the SIP.\111\ Wyoming's 2022 SIP submission does
not address whether any of the existing SO2 emissions
controls at Jim Bridger and Naughton are necessary to make reasonable
progress, and thus whether they are a part of Wyoming's long-term
strategy for the second planning period. Moreover, the State did not
address PM emissions controls in any context for any of these sources.
Thus, the State failed to evaluate and determine the emission reduction
measures that are necessary to make reasonable progress through
consideration of the four statutory factors, as required by 40 CFR
51.308(f)(2), for Jim Bridger Units 1 and 2 for NOX,
SO2, and PM; Jim Bridger Units 3 and 4 for SO2
and PM; Naughton Units 1 and 2 for NOX, SO2, and
PM; and Naughton Unit 3 for NOX and PM.
---------------------------------------------------------------------------
\109\ 2019 Guidance at 22-23; 2021 Clarifications Memo at 5.
\110\ The EPA has not yet taken final action on Wyoming's
separate SIP submission to convert Jim Bridger Units 1-2 from coal-
fired boilers to natural gas-fired boilers and to establish
associated NOX and annual heat input limits. The proposed
action is published at 89 FR 25200.
\111\ CAA section 169A and 40 CFR 51.308(f)(2). Guidance on how
to determine whether existing measures are necessary for reasonable
progress is contained in the 2019 Guidance at 43 and the 2021
Clarifications Memo at 8-10.
---------------------------------------------------------------------------
Finally, for Laramie Portland Cement, the State notes that
SO2 emissions, which are currently controlled only through
the inherent dry scrubbing processes of the rotary kiln itself, are
consistently less than permitted allowable emissions (table 33) and
have decreased by over 100 tons/year from 2014 to 2018. Wyoming appears
to consider inherent dry scrubbing as an existing effective control
that justifies the lack of a four-factor analysis for SO2
controls at this source. However, because the State provides no details
about the operation or emissions performance of the inherent dry
scrubbing process, we cannot determine whether it is reasonable to
assume that a four-factor analysis would not identify any reasonable
additional controls. The State does not address, and it is not clear
based on the emissions information alone, whether further
SO2 reductions would be reasonable at Laramie Portland
Cement, particularly emission limit tightening. The State is also
silent as to whether the facility's existing control measures are
necessary for reasonable progress and are a part of the state's long-
term strategy for the second planning period.
Table 33--Laramie Portland
Cement Actual and Permitted SO2 Limits
------------------------------------------------------------------------
Permitted SO2 Actual SO2
Unit emissions emissions
(2018)
------------------------------------------------------------------------
tons/year
-------------------------------
Kiln 1.................................. 438 114.2
Kiln 2.................................. 438 13.7
------------------------------------------------------------------------
ii. Reliance on Unenforceable Source Retirements To Avoid Four-Factor
Analysis
Wyoming also improperly relies on unenforceable source retirements
to avoid conducting a four-factor analysis for certain sources. For
example, Wyoming's SIP submission refers to planned retirements at Jim
Bridger Units 1-2, Naughton Units 1-2, and Dave Johnston Units 1-2, as
described in PacifiCorp's 2019 IRP and in PacifiCorp's submittal to
Wyoming (appendix C to the Wyoming 2022 SIP submission). However, these
shutdowns are not federally enforceable. Under the CAA and the RHR, a
state's long-term strategy must include the enforceable emissions
limitations, compliance schedules, and other measures that are
necessary to make reasonable progress.\112\ Thus, if a state is relying
on source shutdowns to forgo conducting a four-factor analysis (because
a shutdown is effectively the most stringent control available), the
shutdown must be federally enforceable (for example, through inclusion
in the SIP).\113\
---------------------------------------------------------------------------
\112\ See CAA section 110(a), CAA section 169A(b)(2), and 40 CFR
51.308(f)(2).
\113\ Id. 2019 Guidance at 20.
---------------------------------------------------------------------------
As PacifiCorp conceded in its submittal to the State, it has no
legal obligation to close these units and is not committing to do so in
connection with the second planning period SIP.\114\ Indeed, in the
time since the State submitted its 2022 SIP submission, PacifiCorp has
changed its planned
[[Page 63061]]
retirement of Naughton Units 1-2, which is now slated for 2036 despite
PacifiCorp's previous statements that the CCR rule necessitated a 2025
closure. Similarly, PacifiCorp has changed its retirement of Dave
Johnston Units 1-2 \115\ (now planned for 2028 instead of 2027) and Jim
Bridger Units 1-2 (now planned for 2037 instead of 2023 and 2028,
respectively).\116\ For Naughton specifically, we also disagree with
the State's reliance on the planned unenforceable retirements of Units
1 and 2 to calculate a revised Q/d value using only Unit 3, and then
choosing to exempt the entire source from a four-factor analysis. These
shifting plans underscore the importance of shutdowns being federally
enforceable to justify excluding a source from conducting a four-factor
analysis given that the SIP needs to meet the requirements of the CAA.
---------------------------------------------------------------------------
\114\ 2022 Wyoming SIP submission, appendix C at C-7, C-10, C-
14.
\115\ The State asserts that PacifiCorp submitted a notice to
the Wyoming Department of Environmental Quality committing to cease
combusting coal at these units before December 31, 2028 to meet
requirements of the Effluent Limitations Guidelines and Standards
for the Steam Electric Power Generating Point Source Category for
regulation of wastewater discharges from power plants. Wyoming 2022
SIP Submission at 227. However, Wyoming did not submit a copy of
that notice or explain why it amounts to a federally enforceable
shutdown.
\116\ PacifiCorp Integrated Resource Plan, April 2024, at 13.
---------------------------------------------------------------------------
Because Wyoming has not demonstrated that these planned retirements
are federally enforceable as required under the CAA and RHR, we find
that the State unreasonably failed to consider the required four
statutory factors to determine the emission reduction measures
necessary to make reasonable progress for sources it determined may
affect visibility at Class I areas.\117\
---------------------------------------------------------------------------
\117\ In addition to facility shutdowns, Wyoming stated that it
considered emissions reductions associated with increased renewable
energy generation in determining what measures are necessary to make
reasonable progress. 2022 Wyoming SIP Submission at 203, 206. In its
submittal to the State (appendix C to the Wyoming 2022 SIP
submission), PacifiCorp cited expected changes in operating
parameters at Jim Bridger, Naughton, and Dave Johnston to
accommodate increased renewable energy deployment as an additional
reason why the State should not require a four-factor analysis for
these sources. The EPA has stated that ``energy efficiency,
renewable energy, and other such programs where there is a
documented commitment to participate and a verifiable basis for
quantifying any change in future emissions due to operational
changes'' may be relevant considerations in estimating 2028
emissions for source selection purposes. 2019 Guidance at 17.
However, neither PacifiCorp nor Wyoming provided a verifiable basis
for quantifying any projected future changes in emissions at these
(or any other) sources that may result from participation in such
programs.
---------------------------------------------------------------------------
iii. Other Improper Rationales for Not Performing Four-Factor Analyses
The State's decision not to perform four-factor analyses for
certain sources it selected is improper for several other reasons. For
Jim Bridger, the State determined, without providing additional
examination or explanation, that first planning period actions--
specifically, the conversion to natural gas and associated
NOX and annual heat input limits \118\ for Units 1-2 and the
monthly and annual NOX and SO2 emissions limits
for Units 1-4--demonstrate that no further analysis for the second
planning period is necessary. As we previously acknowledged, states may
appropriately rely in some instances on the effectiveness of existing
controls (including first planning period controls) or an existing
federally enforceable commitment to cease operations to forgo a four-
factor analysis. However, the existence of these first planning period
obligations alone (none of which are currently federally enforceable),
without adequate technical documentation of their effectiveness, does
not automatically eliminate the requirement for a four-factor analysis
in the second planning period if emissions from the facility continue
to affect visibility at Class I areas.\119\ One of the fundamental
requirements of the RHR is the requirement for periodic revisions of
implementation plans at prescribed intervals in order to meet the
national goal of preventing and remedying visibility impairment at
Class I areas.\120\ As explained in section IV.C.2.a.i. of this
document, a four-factor analysis might have shown that more stringent
NOX and SO2 controls are cost-effective and
reasonable at Jim Bridger and thus necessary for reasonable progress.
Ultimately, regardless of first planning period obligations and
requirements, the State must continue to meet its regional haze
obligations for the second planning period under the statute and the
RHR.
---------------------------------------------------------------------------
\118\ The EPA has not yet taken final action on Wyoming's 2022
SIP submission to convert Jim Bridger Units 1-2 from coal-fired
boilers to natural gas-fired boilers and establish associated
NOX and annual heat input limits. Our proposed action is
published at 89 FR 25200.
\119\ CAA section 169A requires states to conduct both a one-
time BART evaluation as well as develop and submit a long-term
strategy for making reasonable progress toward meeting the national
goal for federal Class I areas every 10-15 years. In addition, 40
CFR 51.308(e)(5) states that ``[a]fter a State has met the
requirements for BART or implemented an emissions trading program or
other alternative measure that achieves more reasonable progress
than . . . BART, BART-eligible sources will be subject to the
requirements of paragraphs (d) and (f) of this section.''
\120\ 40 CFR 51.308(f).
---------------------------------------------------------------------------
Similarly, for Wyodak, the State's decision not to conduct a four-
factor analysis due to ongoing first planning period litigation is not
justified. In its submittal to the State, PacifiCorp asserted, without
explanation, that first planning period settlement negotiations may
impact whether and how a four-factor analysis for the second planning
period would be conducted for Wyodak.\121\ Nothing in CAA section 169A
or the RHR supports excluding a source from analysis based on
litigation and settlement negotiations, and the State provided no
explanation for its decision to do so. Conducting a second planning
period four-factor analysis for a source is not contingent on
completion of first planning period obligations. Just as the presence
of BART controls does not exempt sources from pursuing additional
emission reduction measures that are shown to be necessary, through
four-factor analysis, to make reasonable progress during the second
planning period,\122\ the absence of BART (or other first
implementation period controls) does not exempt sources from conducting
a four-factor analysis to determine what emission reduction measures
are necessary to make reasonable progress for subsequent planning
periods. While the anticipated approach may have been for states to
submit second planning period SIP revisions that take into account
finalized first planning period measures, the obligation to submit a
second planning period SIP revision was not suspended for states with
outstanding first planning period obligations. As required, Wyoming
submitted its second planning period SIP submission, which must include
a long-term strategy for making reasonable progress, pursuant to the
second planning period deadline. Consequently, the EPA has a statutory
obligation to review and act on a SIP submission within one year after
it has been deemed complete.\123\
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\121\ Wyoming 2022 SIP submission, appendix C at C-21.
\122\ See footnote 119.
\123\ See CAA section 110(k)(2), 42 U.S.C. 7410(k)(2).
---------------------------------------------------------------------------
For the Lost Cabin Gas Plant, Wyoming did not conduct a four-factor
analysis evaluating NOX or PM emission reduction measures.
As justification, the State explains that permitted NOX and
PM emissions account for only a ``small fraction'' of the total
emissions from the facility.\124\ However, the State did not show that
these NOX and PM emissions do not affect visibility in Class
I areas. Nor did it supply information that NOX or PM
emissions are effectively
[[Page 63062]]
controlled or point to applicable regulations that may subject the
facility to control measures that would limit future emissions
increases. Given the lack of information regarding existing
NOX and PM controls or applicable regulations limiting these
emissions, we cannot conclude that Wyoming's decision not to conduct a
four-factor analysis was reasonable or justified.
---------------------------------------------------------------------------
\124\ Wyoming 2022 SIP submission at 178.
---------------------------------------------------------------------------
Finally, the State failed to conduct a four-factor analysis
evaluating PM emission reduction measures for several sources,
including Laramie River Station, Dave Johnston Unit 4, and the Elk
Basin Gas Plant, despite doing so for NOX and/or
SO2 control measures. For the Elk Basin Gas Plant, the State
did not perform a four-factor analysis for NOX control
measures for the incinerator and SO2 control measures for
the nine compressor engines. It is unclear whether these omissions are
intentional (e.g., based on effectively controlled emissions or some
other justification) or an oversight, as Wyoming did not address the
absence of these four-factor analyses in its SIP submission.
In summary, we propose to disapprove Wyoming's long-term strategy
under CAA section 169A and 40 CFR 51.308(f)(2) because the State failed
to consider the required four statutory factors to determine the
measures necessary to make reasonable progress for certain sources it
determined may affect visibility at Class I areas.
b. Failure To Document the Technical Basis of the State's Determination
of the Emission Reduction Measures Necessary To Make Reasonable
Progress
In formulating their long-term strategies, states must comply with
the requirements under CAA section 110(a), CAA section 169A, and 40 CFR
51.308(f)(2)(iii) to document the technical basis, including modeling,
monitoring, cost, engineering, and emissions information, on which they
are relying to determine the emission reduction measures necessary to
make reasonable progress. The EPA must exercise its independent
technical judgment in evaluating the adequacy of the State's long-term
strategy, including the sufficiency of the underlying methodology and
documentation; we may not approve a SIP that is based on unreasoned
analysis or that lacks foundation in the CAA's requirements.\125\
---------------------------------------------------------------------------
\125\ See Wyoming v. EPA, 78 F.4th 1171, 1180-81 (10th Cir.
2023); Oklahoma v. EPA, 723 F.3d 1201 (10th Cir. 2013); Arizona v.
EPA, 815 F.3d 519, 530-32 (9th Cir. 2016); North Dakota v. EPA, 730
F.3d 750, 760-61 (8th Cir. 2013).
---------------------------------------------------------------------------
As detailed in this section IV.C.2.b., we are proposing to
disapprove Wyoming's long-term strategy due to the State's reliance on
unsupported technical rationales and its failure to adequately document
the technical basis on which it is relying to determine the emission
reduction measures necessary to make reasonable progress (table 34).
Table 34--Sources, Units, and Associated Pollutants Where the State
Failed To Document the Technical Basis of Its Determination of Emission
Reduction Measures Necessary To Make Reasonable Progress
------------------------------------------------------------------------
Associated
Source Unit(s) pollutant(s)
------------------------------------------------------------------------
Dave Johnston (PacifiCorp)...... 4................. SO2.
Laramie Portland Cement Kilns 1, 2........ NOX.
(Mountain Cement Company).
Green River Works (TATA Calciner 1, NOX, PM.
Chemicals). Calciner 2.
Elk Basin Gas Plant (Contango Engines (9)....... NOX.
Resources, Inc.).
Elk Basin Gas Plant (Contango Incinerator....... SO2.
Resources, Inc.).
Lost Cabin Gas Plant............ Trains 2, 3....... SO2.
------------------------------------------------------------------------
i. Laramie Portland Cement
We identified several consequential errors and unsupported
technical rationales in the State's evaluation of NOX
emission reduction measures for Laramie Portland Cement, where
NOX is currently controlled using good combustion practices
(Kilns 1 and 2) and a 2-stage preheater (Kiln 2). Considered in the
aggregate, the problems detailed in this section IV.C.2.b.i. prevent us
from concluding that the State's determination of the emission
reduction measures for Laramie Portland Cement that are necessary to
make reasonable progress is based on sound and adequately documented
technical grounds.
First, there are consequential errors with the State's calculation
of the level of NOX emissions reductions achievable through
installing SNCR on Kiln 2. The State calculated the combined
NOX emissions reductions that could be achieved on both Kiln
1 and Kiln 2 considering 10%, 15%, 20%, and 25% SNCR control
efficiencies.\126\ In addition, the State (through information
submitted by the facility in appendix L) provided baseline and
controlled emissions rates, including NOX emissions
reductions estimates at 10% and 25% control efficiency, for Kiln 1 and
Kiln 2 separately (table 35).\127\
---------------------------------------------------------------------------
\126\ Wyoming 2022 SIP submission at 158.
\127\ Wyoming 2022 SIP submission, appendix L.
Table 35--Wyoming's Analysis of Laramie Portland Cement Baseline and
Estimated NOX Emission Reductions for Kiln 1 and Kiln 2 Associated With
SNCR NOX Controls at 10% and 25% Control Efficiency
------------------------------------------------------------------------
NOX emissions
Baseline NOX reduction
Kiln emissions (control
efficiency)
------------------------------------------------------------------------
tons/year
------------------------------------------------------------------------
Kiln 1.................................. 722.8 72.3 (10%)
181 (25%)
Kiln 2.................................. 1,511.6 861 (10%)
970 (25%)
------------------------------------------------------------------------
Using the baseline NOX emission rate provided, we
performed an accuracy check on the calculations of the NOX
emission reductions for Kiln 2 \128\ associated with 10% and 25%
control efficiency. We multiplied the baseline
[[Page 63063]]
NOX emissions (tons/year) with each control efficiency (%)
to achieve the NOX emissions reduction (tons/year)
associated with each control efficiency (table 36).\129\
---------------------------------------------------------------------------
\128\ We found the State's calculated NOX reductions
for Kiln 1 at 10% and 25% control efficiencies to be correct.
\129\ Laramie Portland Cement_EPA NOX
calculations_January 2024.
Table 36--The EPA's Analysis of Laramie Portland Cement Estimated NOX
Emission Reductions for Kiln 2 Associated With SNCR NOX Controls at 10%
and 25% Control Efficiency
------------------------------------------------------------------------
NOX emissions
Baseline NOX reduction
Kiln emissions (level of
control)
------------------------------------------------------------------------
tons/year
------------------------------------------------------------------------
Kiln 2.................................. 1,511.6 151 (10%)
378 (25%)
------------------------------------------------------------------------
We find that Wyoming overestimated the amount of NOX
emissions reductions by 710 tons/year at 10% control efficiency and 592
tons/year at 25% control efficiency. This overestimation appears to be
the result of a math error. Because the State's calculated
NOX emissions reductions associated with SNCR for Kiln 2 are
incorrect, the emissions reductions for Kilns 1 and 2 combined, as well
as the associated average cost effectiveness ($/ton) shown in table 16
for all levels of control efficiencies, are also incorrect. Given that
the error impacts the control efficiencies of various control
technologies, the calculated emissions reductions and cost
effectiveness values cannot be relied upon to determine what
NOX emissions control measures for Laramie Portland Cement
are necessary to make reasonable progress.
Second, the State did not document the technical basis of the SNCR
control efficiencies that were used to calculate costs of compliance
for the four-factor analysis. The State evaluated the cost
effectiveness of SNCR NOX emission controls on Kiln 1 and
Kiln 2 using control efficiencies ranging from a minimum of 10% to a
maximum of 25% without any supporting documentation.\130\ The EPA
recognizes that it is challenging to predict the control efficiency of
SNCR for long cement kilns.\131\ We agree that absent the use of post-
installation control demonstrations to set NOX emission
limits, it is appropriate to include a range of control efficiencies in
the four-factor analysis. However, Wyoming did not justify its use of
SNCR control efficiencies as low as 10-25% for Kiln 1 and Kiln 2. In
2017, we revised the Montana regional haze FIP NOX emission
limit on a long kiln in Montana. As part of that action, we assessed
information on SNCR control efficiencies that had been demonstrated on
long kilns since our promulgation of the original FIP and SNCR-based
NOX emission limit in 2012.132 133 We found that
the control efficiency of SNCR installed on kilns as a result of
consent decrees \134\ is highly variable and ranges from 29% to 47%,
with a mean of 40%.\135\ Wyoming did not consider this or any other
data showing higher SNCR efficiencies in the four-factor analysis for
Laramie Portland Cement. While the facility asserted generally that
other cement kilns ``have challenges'' and ``are battling issues'' with
SNCR, it provided no documentation of the control efficiencies those
other cement kilns have achieved.\136\ Therefore, we find that Wyoming
did not adequately document the technical basis of the control
efficiencies it relied on, and, as a result, likely underestimated the
cost effectiveness of SNCR.
---------------------------------------------------------------------------
\130\ 2022 Wyoming SIP submission at 157-58.
\131\ 82 FR 17948, 17951 (April 14, 2017).
\132\ 82 FR 17948 (April 14, 2017).
\133\ 82 FR 42738 (September 12, 2017).
\134\ SNCR was installed on several wet or dry long kilns in
association with consent decree enforcement actions.
\135\ Technical Support Document--Oldcastle Trident Federal
Implementation Plan Revision, March 8, 2017. See Attachment 1 to the
TSD, Summary of SNCR Performance Data for Long Cement Kilns.
\136\ Wyoming 2022 SIP submission, appendix L at L-29 to L-30.
The facility also stated that SNCR at a cement plant in Tulsa owned
by its parent company has been ``operating with some success.'' Id.
at L-30.
---------------------------------------------------------------------------
Third, the State included the potential loss of cement kiln dust
sales in its cost analysis without providing technical documentation to
substantiate the expected loss. The State projected a loss of over
$13,000,000 in kiln dust sales across all control efficiencies due to
purported contamination associated with the operation of SNCR.\137\
This figure represents a very significant portion--over 76%--of the
total annualized costs associated with SNCR on Kilns 1 and 2. However,
Wyoming did not submit any documentation on the likelihood of
contamination or the specific amount of projected lost sales, which
greatly influenced the cost-effectiveness of controls. Given the lack
of justification and supporting evidence, incorporating potential lost
cement kiln dust sales into the cost analysis was unreasonable.
---------------------------------------------------------------------------
\137\ Wyoming 2022 SIP submission at 158 and appendix L at L-34
and L-38.
---------------------------------------------------------------------------
Fourth, the State did not provide technical documentation to
support its reliance on a 10-year amortization period and 10% interest
rate in its cost analysis for SNCR on Kilns 1 and 2. The amortization
period (also termed the remaining useful life) and interest rate are
used to calculate annualized capital costs. Annualized capital costs
ultimately determine, along with the tons of emissions reduced and
additional annualized costs, the cost per ton of emissions reduced of
the evaluated control technology. Wyoming used a 10-year equipment life
for SNCR \138\--half the 20-year amortization period specified in EPA's
Control Cost Manual \139\--without providing documentation justifying
that deviation or otherwise explaining why a 10-year equipment life is
reasonable. And while the Control Cost Manual recommends using a firm-
specific nominal interest rate if one is available,\140\ the State
provided no documentation to support its use of a 10% interest rate,
which was more than double the bank prime rate as of January 2020 \141\
(when the analysis was conducted) and well outside the range of similar
firms' interest rates.\142\
---------------------------------------------------------------------------
\138\ Cost analyses found in appendix L of Wyoming's 2022 SIP
submission include an amortization period of 10 years for SNCR on
Kilns 1 and 2. The narrative overview on page 157 of Wyoming's 2022
SIP submission erroneously states that the cost analysis used an
amortization period of 20 years.
\139\ EPA, ``Control Cost Manual,'' section 4, chapter 1, April
2019, page 1-54, available at https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-reports-and-guidance-air-pollution (last visited January 2024).
\140\ EPA, ``Control Cost Manual,'' section 1, chapter 2,
November 2017, page 16, available at https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-reports-and-guidance-air-pollution (last visited January 2024).
\141\ Data from the Federal Reserve shows that the bank prime
rate between November 2019 and February 2020 was 4.75% (See Bank
Prime Rate Graph, March 25, 2024). https://www.federalreserve.gov/releases/h15/ (last visited February 2024).
\142\ See, e.g., 2022 South Dakota Regional Haze State
Implementation Plan. 2022. pp. 134, 137.
---------------------------------------------------------------------------
EPA's Control Cost Manual provides detailed technical guidance on
the estimation of capital and annual costs for air pollution control
devices for stationary sources. The Control Cost Manual is commonly
used by the EPA, State and local officials, and industry parties that
must comply with EPA regulations or EPA permits. EPA has been updating
the Control Cost Manual under the authority of the Consolidated
Appropriations Act of 2014.\143\ Chapter
[[Page 63064]]
revisions undergo public notice and comment.\144\ In the EPA's 2019
Guidance, we noted that if a state deviates from the principles and
factors recommended in the Control Cost Manual, it should explain and
document how its alternative approach is appropriate.\145\ Because
Wyoming provided no justification or documentation to support the
unusually short amortization period and atypically high firm-specific
interest rate it used to evaluate SNCR for Laramie Portland Cement, as
required by 40 CFR 51.308(f)(2)(iii), we find that the State's cost
analysis methodology lacks adequate technical support.
---------------------------------------------------------------------------
\143\ Public Law 113-76 (2014); 160 Cong. Rec. H475, H979
(January 15, 2014) (stating that the process for reviewing regional
haze SIPs ``is well-served when EPA, States, and industry work
collaboratively to ensure that dispersion models are continually
improved and updated to ensure the most accurate predictions of
visibility impacts, as well as a uniform set of cost estimates'').
\144\ Id.; 81 FR 65352 (September 22, 2016) (section 1, chapter
2 on cost estimation concepts and methodology); 80 FR 33515 (June
12, 2015) (section 4, chapter 1 on SNCR and section 4, chapter 2 on
SCR).
\145\ 2019 Guidance at 31.
---------------------------------------------------------------------------
In summary, the multitude of methodological errors and unsupported
technical bases, considered collectively, makes it impossible for us to
determine the adequacy of the State's determination of the emission
reduction measures for Laramie Portland Cement that are necessary to
make reasonable progress.
ii. Lost Cabin Gas Plant
We identified several defects in the State's cost analysis for
SO2 controls at the Lost Cabin Gas Plant, including
conflicting cost figures and SO2 emissions data, use of an
unsubstantiated amortization period and firm-specific interest rate,
and an unjustifiably low estimate of wet scrubber control efficiency.
Considered in the aggregate, the problems detailed in this section
IV.C.2.b.ii. prevent us from concluding that the State's determination
of the emission reduction measures for Lost Cabin Gas Plant that are
necessary to make reasonable progress is based on sound and adequately
documented technical grounds.
First, we find numerous discrepancies between the cost figures,
specifically `Total Annual Cost ($/year)' and `Cost per Ton of
SO2 Removed ($/ton)' on pages 179 and 180 and appendix J of
the Wyoming 2022 SIP submission.\146\ Ultimately, these discrepancies
lead to the inaccurate calculation of cost/ton of SO2
emissions removed ($/ton) in table 11-34 for both Trains 2 and 3.
---------------------------------------------------------------------------
\146\ On page 179 of the Wyoming 2022 SIP submission, annualized
costs ($/year) for the installation of wet scrubbers on Train 2 are
$1,442,233 and on Train 3 are $2,438,411. These figures conflict
with those listed on the following page (page 180) in table 11-34
for Train 2 ($1,348,694) and Train 3 ($2,272,044). Additionally,
while the cost/ton figures on pages 179 and in table 11-34 are
consistent for Train 2 ($7,710/ton) and Train 3 ($7,470/ton), they
conflict with the cost/ton figures provided in appendix J for Train
2 ($8,250/ton) and Train 3 ($8,010/ton).
---------------------------------------------------------------------------
Second, other aspects of Wyoming's cost analysis lack adequate
documentation. The State provides no support for its reliance on a 15-
year amortization period (remaining useful life) in its evaluation of
wet scrubbers for SO2 control,\147\ which is half the useful
life for wet scrubbers (30 years) recommended in the EPA's Control Cost
Manual.\148\ The State also relied on a 10% firm-specific interest
rate--more than double the bank prime rate at the time of analysis--
without offering any rationale or supporting documentation.\149\ These
factors are important inputs in the calculation of control technology
cost effectiveness, and Wyoming's failure to substantiate them
undermines its cost analysis.
---------------------------------------------------------------------------
\147\ Wyoming's 2022 SIP submission at 180 and appendix J.
\148\ EPA, ``Control Cost Manual,'' section 5, chapter 1, April
2021, pages 1-8, 1-35, and 1-36, available at https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-reports-and-guidance-air-pollution (last visited February 2024).
\149\ Data from the Federal Reserve shows that the bank prime
rate between November 2019 and February 2020 was 4.75% (See Bank
Prime Rate Graph, March 25, 2024). https://www.federalreserve.gov/releases/h15/ (last visited February 2024).
---------------------------------------------------------------------------
Third, the State's use of a 90% control efficiency for wet scrubber
SO2 emissions control is not adequately supported. As
documented in the Control Cost Manual, wet scrubbers typically achieve
removal efficiencies of between 95% and 99% for most industrial
applications, with many vendors publishing SO2 removal
efficiencies of over 99% for new wet FGD systems.150 151 We
acknowledge the State's concern regarding the necessary water
requirements to supply a 95% efficiency or greater wet scrubber system,
which it cited as justification for using a 90% efficiency. However,
the State makes no attempt to quantify or otherwise detail the
incremental water requirements necessary to achieve a 95% or greater
control efficiency to support its rejection of control efficiencies
above 90% for a wet scrubber system. Without any supporting
demonstration of the impact of those water requirements on the cost
analysis, beyond a bare assertion that supplying additional water would
not be economical, we find the State's assumption of 90% wet scrubber
control efficiency to be unfounded. Relatedly, despite its concern
regarding the necessary water requirements for the operation of wet
scrubbers, the State did not demonstrate why less water-intensive
SO2 emissions control options (i.e., dry scrubbing) are not
feasible. Indeed, dry scrubbing was identified in public comments as a
potential control option.\152\ The State provided no explanation for
its failure to evaluate whether dry scrubbing is an emission reduction
measure that is necessary to make reasonable progress toward the
national visibility goal.
---------------------------------------------------------------------------
\150\ EPA, ``Control Cost Manual,'' section 5, chapter 1, April
2021, pages 1-9 and 1-12 available at https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-reports-and-guidance-air-pollution (last visited February 2024).
\151\ The term ``scrubber'' is used to refer to control devices
that use gas absorption to remove gases from waste gas streams. When
used to remove SO2 from flue gas, gas absorbers are
commonly called flue gas desulfurization (FGD) systems.
\152\ Wyoming 2022 SIP submission at 1,122.
---------------------------------------------------------------------------
Collectively, these factors--conflicting cost figures, an
unsubstantiated amortization period and firm-specific interest rate,
and an unjustifiably low estimate of wet scrubber control efficiency--
undercut the technical support for Wyoming's cost analysis and its
resulting conclusion that additional SO2 controls are not
cost-effective at the Lost Cabin Gas Plant.
iii. Elk Basin Gas Plant, Dave Johnston Unit 4, and Green River Works
Finally, some of the State's four-factor analyses are critically
incomplete because there are gaps in technical analysis with no
documentation or justification to support that lack of analysis. For
example, the State provided no data or cost figures to support its
decision not to evaluate additional SO2 emissions control
measures for Dave Johnston Unit 4, including possible upgrades to the
existing spray dryer absorber, other than stating that scrubber
upgrades are more effective than DSI for incremental pollution control
removal.\153\ In its evaluation of NOX controls for Elk
Basin Gas Plant's nine compressor engines and SO2 controls
for the plant's incinerator, the State omitted key elements necessary
to determine cost-effectiveness: figures related to direct, indirect,
and total costs; information necessary (i.e., interest rate,
amortization period) to determine the capital recovery factor and
associated total annual costs and annualized capital costs; the assumed
control efficiency of LEC NOX emissions controls on the
compressor engines; and the SO2 emissions baseline for the
incinerator.\154\ And in its evaluation of NOX and PM
emissions controls for Calciner 1 and Calciner 2 at Green River
[[Page 63065]]
Works, the State failed to provide a demonstration with supporting
documentation that existing measures are likely not necessary to make
reasonable progress, despite having made that showing for the C Boiler
and D Boiler.\155\
---------------------------------------------------------------------------
\153\ Wyoming 2022 SIP submission at 144.
\154\ Wyoming 2022 SIP submission at 168-172.
\155\ Wyoming 2022 SIP submission at 166-167.
---------------------------------------------------------------------------
In summary, for the reasons explained in this section IV.C.2.b., we
propose to disapprove Wyoming's long-term strategy under CAA section
169A and 40 CFR 51.308(f)(2) because the State relied on unsupported
technical rationales and failed to adequately document the technical
basis on which it relied to determine the emission reduction measures
necessary to make reasonable progress.
c. Sources Where the State Unreasonably Rejected Potential Emission
Reduction Measures
We also propose to disapprove Wyoming's long-term strategy due to
the State's unreasonable rejection of emission reduction measures at
the Elk Basin Gas Plant and the Cheyenne Fertilizer Facility (table
37).
Table 37--Sources, Units, and Associated Pollutants and Emission Control Technology Where the State Unreasonably
Rejected Emission Reduction Measures
----------------------------------------------------------------------------------------------------------------
Associated Emission control
Source Unit(s) pollutant(s) technology
----------------------------------------------------------------------------------------------------------------
Elk Basin Gas Plant (Contango Resources, Engines (9)............... NOX LEC.
Inc.).
Cheyenne Fertilizer Facility (Dyno ENG004, ENG005 (engines).. NOX LEC.
Nobel, Inc.).
Cheyenne Fertilizer Facility (Dyno CTW001, CTW003 (cooling PM Upgraded Mist Eliminators.
Nobel, Inc.). towers).
----------------------------------------------------------------------------------------------------------------
In its evaluation of NOX emissions controls for Elk
Basin Gas Plant's nine engines, the State determined the cost/ton of
LEC to be between $1,500-$2,200 per ton of NOX emissions
reduced, with a total expected reduction of 1,793.5 tons of
NOX per year.\156\ Similarly, the State determined the cost/
ton of an LEC retrofit at Cheyenne Fertilizer Facility for engines
ENG004 and ENG005 to be $1,067 per ton of NOX emissions
reduced, with a total expected reduction of 229 tons of NOX
per year for each engine.\157\ The State then rejected LEC control
technology for both facilities despite concluding, after consideration
of the four statutory factors as well as emission trends and permit
conditions, that these facilities may warrant further analysis of
emission controls to reach reasonable progress. Notably, Wyoming did
not determine these cost/ton values for LEC to be unreasonable. Indeed,
cost-effectiveness values of $1,067-$2,200 are in line with what the
EPA and states found reasonable for regional haze control measures in
the first planning period, even without adjusting for inflation.\158\
While Wyoming stated it would further analyze these facilities in its
next regional haze progress report, nothing in the CAA or RHR allows
states to defer controls that are shown, through four-factor analysis,
to be necessary to make reasonable progress. States may not avoid their
second planning period obligations by delaying decision making to a
future date.\159\
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\156\ Wyoming 2022 SIP submission at 168. As explained in
section IV.C.2.a.iii., the State did not supply key information
necessary for the EPA to determine the appropriateness of this cost
analysis.
\157\ Wyoming 2022 SIP submission at 184.
\158\ The 2019 Guidance emphasized that ``[w]hen the cost/ton of
a possible measure is within the range of the cost/ton values that
have been incurred multiple times by sources of similar type to meet
regional haze requirements or any other CAA requirement, this weighs
in favor of concluding that the cost of compliance is not an
obstacle to the measure being considered necessary to make
reasonable progress.'' 2019 Guidance at 40. After evaluating first
planning period cost of compliance values, plus the other BART
statutory factors and/or the four reasonable progress statutory
factors, the vast majority of cost/ton values < $2,500/ton were
found to be reasonable and cost-effective. Examples for several
sources can be found at: 76 FR 16168, 16180-81 (Mar. 22, 2011)
(proposed), finalized at 76 FR 81728 (Dec. 28, 2011) (Oklahoma); 76
FR 58570, 58586 (Sept. 21, 2011) (proposed), finalized at 77 FR
20894 (Apr. 6, 2012) (North Dakota); 77 FR 24794, 24817 (Apr. 25,
2012) (proposed), finalized at 77 FR 51915 (Aug. 28, 2012) (New
York); 77 FR 18052, 18070-71 (Mar. 26, 2012) (proposed), finalized
at 77 FR 76871 (Dec. 31, 2012) (Colorado); and 77 FR 73369, 73378
(Dec. 10, 2012) (proposed), finalized at 78 FR 53250 (Aug. 29, 2013)
(Florida). These costs have not been adjusted for inflation.
\159\ C.f. NRDC v. EPA, 22 F.3d 1125, 1134 (D.C. Cir. 1994)
(noting that SIPs must ``contain[ ] something more than a mere
promise to take appropriate but unidentified measures in the
future''). In addition, because progress reports due in 2025 will
not take the form of SIP revisions that must be approved or
disapproved by EPA, it is not clear how Wyoming could evaluate and
potentially impose emission reduction measures at Elk Basin Gas
Plant through that process. See generally 40 CFR 51.308(g).
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For its evaluation of PM emissions controls at the Cheyenne
Fertilizer Facility on cooling towers CTW001 and CTW003, the State
found the cost/ton for upgraded mist eliminators to be $1,056 for
CTW001 and $2,368 for CTW003 per ton of PM emissions reduced, for total
expected reductions of 15.5 tons (CTW001) and 2.4 tons (CTW003) of PM
per year.\160\ Here again, Wyoming did not determine these cost/ton
values to be unreasonable. However, the State concluded that the total
capital investment for upgraded mist eliminators of $153,600 (for
CTW001) and $53,990 (for CTW003) was not justified given what it
considered to be the ``minute'' amount of emissions reductions that
could be achieved; the State also cited declining PM emissions trends.
At the same time, Wyoming concluded that the Cheyenne Fertilizer
Facility may warrant further analysis of emission controls in the next
regional haze progress report. We find that the State did not
adequately justify its rejection of upgraded mist eliminators. Wyoming
inappropriately relied on declining emissions trends--which is not one
of the four statutory factors--to summarily reject controls shown to be
cost-effective and otherwise reasonable through four-factor analysis.
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\160\ Wyoming 2022 SIP submission at 185.
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In summary, we propose to disapprove Wyoming's long-term strategy
under 40 CFR 51.308(f)(2) because the State unreasonably rejected
potential controls for certain sources and thus did not reasonably
determine the emission reduction measures necessary to make reasonable
progress.
d. Other Unjustified Reasons for Rejecting All Additional Emission
Reduction Measures
After evaluating potential emission reduction measures at the
source-specific level, Wyoming explained its overall reasoning for not
requiring any additional measures in its long-term strategy to make
reasonable progress for the second planning period for affected Class I
areas.\161\ Whether individually or in combination, Wyoming's reasons
are not supported by the CAA and the RHR and provide another basis for
our proposed disapproval of Wyoming's long-term strategy.
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\161\ Wyoming 2022 SIP Submission at 203-06.
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First, Wyoming unreasonably relied on generalized and
unsubstantiated assertions that any emission reduction
[[Page 63066]]
measures would impose economic hardships on sources and negatively
affect rural communities. Wyoming provided no analyses, data, or other
evidence to support its assertions that the cost of additional controls
could force energy producers out of the market, harm ratepayers, impose
economic stress on rural communities, or cause grid instability. In CAA
section 169A, Congress established the national goal of preventing any
future and remedying any existing impairment of visibility in Class I
areas; it then directed states to develop SIPs containing long-term
strategies comprised of emission limits, schedules of compliance, and
other measures necessary to make reasonable progress toward that
national goal through consideration of the four statutory factors.\162\
Wyoming cannot overcome Congress's express mandate by relying on an
unsupported policy position that any additional control costs will
cause unwarranted economic harm.
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\162\ See CAA sections 169A(a)(1), (b)(2)(B), and (g)(1).
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Second, past and projected emissions reductions do not support
Wyoming's rejection of all additional control measures for the second
planning period. To support its determination that no further emissions
reductions are warranted, Wyoming pointed to first implementation
period measures, increasing renewable energy generation, facility
shutdowns and conversions, and measures taken in other states and
nationwide. The RHR, however, sets out an iterative planning process by
which states have a continuing obligation to determine the emission
reduction measures necessary to make reasonable progress in each
implementation period. As we recognized in the 2017 RHR Revisions,
while first implementation period measures resulted in significant
reductions in emissions nationwide, continued progress is still
necessary and is required by statute.\163\ The fact that some emissions
reductions have already been achieved and are expected to occur in the
future, whatever the source of those reductions, does not exempt states
from determining the measures necessary to make reasonable progress
based on consideration of the four statutory factors in each planning
period. Furthermore, as detailed in section IV.C.2.a.ii. of this
document, the facility shutdowns cited by the State (with the exception
of Dave Johnston Unit 3) are not federally enforceable or have
otherwise not been validated. Nor did Wyoming quantify or substantiate
the changes in emissions that it believes will occur due to increased
renewable energy generation.\164\
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\163\ 82 FR 3080.
\164\ See footnote 117.
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Third, Wyoming unreasonably pointed to other sources' contribution
to visibility impairment in the State's Class I areas as a reason not
to require its own emission reduction measures. But nothing in the CAA
or RHR authorizes the rejection of control measures that are shown to
be appropriate through four-factor analysis on the basis that some
portion of visibility-impairing pollutants affecting Class I areas
originates from international anthropogenic sources or natural sources
such as wildfires. The four statutory factors do not include a state's
relative level of contribution of visibility-impairing pollutants.
Indeed, Congress's national goal is ``the prevention of any future, and
the remedying of any existing, impairment of visibility in mandatory
Class I Federal areas which impairment results from manmade air
pollution,'' including visibility impairment caused by sources within
the states.\165\
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\165\ CAA section 169A(a)(1) (emphasis added); section
169A(b)(2) (requiring states to develop SIPs to address visibility
impairment).
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Fourth, Wyoming improperly relied on the fact that its seven Class
I areas are currently below the adjusted URP and are projected to
remain so in 2028. As the EPA has consistently explained, states may
not use the URP as a ``safe harbor'' to conclude that additional
emission reduction measures are not necessary for reasonable progress.
The 2017 RHR explains that the CAA requires that each SIP revision
contain long-term strategies for making reasonable progress, and that
in determining reasonable progress states must consider the four
statutory factors. Treating the URP as a safe harbor would be
inconsistent with the statutory requirement that states assess the
potential to make further reasonable progress towards natural
visibility goal in every implementation period. Even if a state is
currently on or below the URP, there may be sources contributing to
visibility impairment for which it would be reasonable to apply
additional control measures in light of the four factors. Although it
may conversely be the case that no such sources or control measures
exist in a particular state with respect to a particular Class I area
and implementation period, this should be determined based on a four-
factor analysis for a reasonable set of in-state sources that are
contributing the most to the visibility impairment that is still
occurring at the Class I area. It would bypass the four statutory
factors and undermine the fundamental structure and purpose of the
reasonable progress analysis to treat the URP as a safe harbor, or as a
rigid requirement.\166\ The EPA reiterated this concept in the 2019
Guidance \167\ and in the 2021 Clarifications Memo.\168\ The CAA and
RHR do not include the URP among the four factors states must consider
in developing their long-term strategies. Treating the URP as a safe
harbor, as Wyoming has done, is inconsistent with statutory
requirements and undermines the core structure of an appropriate
regional haze analysis.
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\166\ 82 FR 3099-3100.
\167\ 2019 Guidance at 49.
\168\ 2021 Clarifications Memo at 15.
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Finally, Wyoming claims that WRAP modeling indicates that
``potential additional controls will have little to no influence (< 0.1
dv)'' on visibility conditions at Wyoming Class I areas.\169\ There is
no basis for Wyoming's assertion. First, the State does not explain
what ``potential additional controls'' on Wyoming sources were modeled;
our review of the WRAP modeling information shows that none were. To
support its claim, Wyoming pointed to the figures in Chapter 15 of its
SIP submission, which show visibility modeling results for various
emission scenarios: the WRAP modeling scenario ``2028OTBa2'' (``On the
Books Inventory'') reflects emissions levels associated with
implementation by 2028 of all applicable ``on the books'' federal and
state requirements; \170\ the WRAP modeling scenario ``PAC2''
(``Potential Additional Controls'') reflects emissions levels
associated with implementation of potential additional controls beyond
those included in the 2028OTBa2/``On the Books Inventory''
scenario.\171\ No potential additional control measures beyond the ``on
the books inventory'' were modeled for Wyoming, as indicated in tables
9-1 through 9-4 of Wyoming's 2022 SIP submission,\172\ WRAP
spreadsheets for the modeling scenarios,\173\ and other WRAP modeling
documentation.\174\ Instead, the < 0.1
[[Page 63067]]
deciview modeled visibility improvement that Wyoming referenced is
attributable to potential emission reductions in other states.\175\
Simply put, Wyoming did not model visibility improvements associated
with the emission reduction measures it considered, and rejected,
through four-factor analysis. The State therefore had no basis to
conclude that potential additional controls would have little to no
influence on visibility conditions at its Class I areas.\176\
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\169\ Wyoming 2022 SIP Submission at 205.
\170\ WRAP Technical Support Systems for Regional Haze Planning:
Emissions Methods, Results, and References, September 30, 2021
(``WRAP Emissions Reference''), 7-9.
\171\ Id. at 11.
\172\ Wyoming 2022 SIP submission at 115-119. A comparison of
the columns titled `2028OTBa2' and `2028 PAC2' in tables 9-1 through
9-4 shows that NOX, SOx, PM10, and
PM2.5 emissions levels for Wyoming sources are the same.
\173\ WRAP PAC2 and 2028OTBa2_August 17 2021. Comparing the
Wyoming emissions levels listed in the summary tables on the `WRAP
2028PAC2 point emissions' and `WRAP 2028OTBa2 point emissions'
worksheets shows that Wyoming emissions for the two scenarios are
the same.
\174\ WRAP Emissions Reference, table 5 at 11.
\175\ Table 5 of the WRAP Emissions Reference identifies the
states that included ``Potential Additional Controls'' beyond ``On
the Books'' emissions controls to evaluate the potential visibility
response in 2028. The `WRAP 2028PAC2 point emissions' worksheet in
the WRAP PAC2 and 2028OTBa2_August 17 2021 file lists the emissions
levels that were modeled for those states.
\176\ In addition, Wyoming said nothing about potential
visibility improvements at out-of-state Class I areas. Under CAA
section 169A(b)(2) and 40 CFR 51.308(f)(2), Wyoming's long-term
strategy must address regional haze visibility impairment at both
in-state and out-of-state Class I areas that may be affected by
emissions from Wyoming sources.
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In conclusion, Wyoming's unsubstantiated reasons for not requiring
any additional emission reduction measures as part of its long-term
strategy to make reasonable progress lack foundation in the CAA and
RHR. Therefore, we propose to disapprove Wyoming's long-term strategy
under CAA section 169A and 40 CFR 51.308(f)(2).
e. Other Long-Term Strategy Requirements (40 CFR 51.308(f)(2)(ii)-(iv))
States must meet the additional requirements specified in 40 CFR
51.308(f)(2)(ii)-(iv) when developing their long-term strategies. 40
CFR 51.308(f)(2)(ii) requires states to consult with other states that
have emissions that are reasonably anticipated to contribute to
visibility impairment in Class I areas to develop coordinated emission
management strategies. Chapters 14.7.2 through 14.7.5 of Wyoming's 2022
SIP submission describe the State's consultation with other states
throughout the development of its regional haze plan.
40 CFR 51.308(f)(2)(iii) requires states to document the technical
basis, including modeling, monitoring, costs, engineering, and
emissions information, on which the state is relying to determine the
emission reduction measures that are necessary to make reasonable
progress in each mandatory Class I area it impacts. The State relied on
WRAP technical information, modeling, and analysis to support
development of its long-term strategy.\177\
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\177\ Wyoming 2002 SIP submission at 24-25.
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40 CFR 51.308(f)(2)(iv) specifies five additional factors states
must consider in developing their long-term strategies. The five
additional factors are: emission reductions due to ongoing air
pollution control programs, including measures to address reasonably
attributable visibility impairment; measures to mitigate the impacts of
construction activities; source retirement and replacement schedules;
basic smoke management practices for prescribed fire used for
agricultural and wildland vegetation management purposes and smoke
management programs; and the anticipated net effect on visibility due
to projected changes in point, area, and mobile source emissions over
the period addressed by the long-term strategy. Chapter 14.5 of
Wyoming's 2022 SIP submission describes each of the five additional
factors.
Regardless, as explained in the preceding sections, due to flaws
and omissions in its four-factor analyses and the resulting control
determinations, we find that Wyoming failed to reasonably ``evaluate
and determine the emission reduction measures that are necessary to
make reasonable progress'' by considering the four statutory factors as
required by CAA section 169A(b)(2)(A), CAA section 169A(g)(1), and 40
CFR 51.308(f)(2)(i). We also find that Wyoming failed to adequately
document the technical basis that it relied upon to determine these
emissions reduction measures, as required by 40 CFR 51.308(f)(2)(iii).
In so doing, Wyoming failed to submit to the EPA a long-term strategy
that includes ``the enforceable emissions limitations, compliance
schedules, and other measures that are necessary to make reasonable
progress'' \178\ Consequently, the EPA finds that the Wyoming's 2022
SIP submission does not satisfy the long-term strategy requirements of
40 CFR 51.308(f)(2). Therefore, we are proposing to disapprove these
corresponding portions of Wyoming's 2022 SIP submission.
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\178\ See also CAA section 169A(b)(2), 169A(b)(2)(B) (requiring
regional haze SIPs to ``contain such emission limits, schedules of
compliance and other measures as may be necessary to make reasonable
progress toward meeting the national goal, . . . including . . . a
long-term . . . strategy for making reasonable progress[.]'') and
CAA section 110(a)(2)(A) (requiring SIPs to contain ''enforceable
emission limitations and other control measures, means, or
techniques . . . . as well as schedules and timetables for
compliance.''
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D. Reasonable Progress Goals
Section 51.308(f)(3)(i) requires a state in which a Class I area is
located to establish RPGs--one each for the most impaired and clearest
days--reflecting the visibility conditions that will be achieved at the
end of the implementation period as a result of the emission
limitations, compliance schedules and other measures required under
paragraph (f)(2) in states' long-term strategies, as well as
implementation of other CAA requirements.
After establishing its long-term strategy, Wyoming developed
reasonable progress goals for each Class I area for the 20% most
impaired days and 20% clearest days based on the results of 2028 WRAP
modeling (table 38).\179\
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\179\ Wyoming 2022 SIP submission at 234-236.
Table 38--Reasonable Progress Goals for the 20% Most Impaired Days and 20% Clearest Days for Wyoming Class I
Areas
----------------------------------------------------------------------------------------------------------------
20% Most impaired days 20% Clearest days
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Average 2028 Average
Class I Area baseline 2028 Uniform Reasonable baseline 2028
conditions progress goal progress goal conditions Reasonable
(2000-2004) \1\ \2\ (2000-2004) progress goal
----------------------------------------------------------------------------------------------------------------
Deciviews
----------------------------------------------------------------------------------------------------------------
Grand Teton National Park....... 8.3 7.2 7 2.6 2.3
Teton Wilderness Area
Yellowstone National Park
[[Page 63068]]
North Absaroka Wilderness Area.. 8.8 8.1 6.9 2.0 1.7
Washakie Wilderness Area
Bridger Wilderness Area......... 8 7.1 6.3 2.1 1.8
Fitzpatrick Wilderness Area
----------------------------------------------------------------------------------------------------------------
\1\ Based on the adjusted glidepath.
\2\ Based on WRAP 2028OTBa2.
The reasonable progress goals are based on Wyoming's long-term
strategy, the long-term strategy of other states that may affect Class
I areas in Wyoming, and other CAA requirements. Per 40 CFR
51.308(f)(3)(iv), the EPA must evaluate the demonstrations the State
developed pursuant to 40 CFR 51.308(f)(2) to determine whether the
State's reasonable progress goals for visibility improvement provide
for reasonable progress towards natural visibility conditions. As
previously explained in sections IV.C.2.a.-d., we are proposing to
disapprove Wyoming's long-term strategy for failing to meet the
requirements of 40 CFR 51.308(f)(2).\180\ Therefore, we also propose to
disapprove Wyoming's reasonable progress goals under 40 CFR
51.308(f)(3) because compliance with that requirement is dependent on
compliance with 40 CFR 51.308(f)(2).
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\180\ Wyoming's 2022 SIP submission does not include enforceable
source retirement dates or any enforceable emission reduction
measures in the long-term strategy for the second planning period
under 40 CFR 51.308(f)(2). However, projected emissions reductions
reflecting the planned--but not enforceable--shutdowns of Naughton
Units 1 and 2 and Dave Johnston Units 1 and 2 are included in the
2028 WRAP modeling scenario (WRAP 2028OTBa2 and RepBase2_August 17
2021 in the docket) that Wyoming used as the basis of its 2028
reasonable progress goals under 40 CFR 51.308(f)(3). As noted in
section IV.C.2.a.ii. of this document, PacifiCorp has already pushed
back those sources' planned retirement dates in the time since
Wyoming finalized its 2022 SIP submission. Because Wyoming's
reasonable progress goals reflect projected emission reductions that
are not enforceable and are not included in the SIP, they do not
comport with 40 CFR 51.308(f)(3)(i)'s requirement that reasonable
progress goals reflect enforceable emissions limitations, compliance
schedules, and other measures.
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E. Reasonably Attributable Visibility Impairment (RAVI)
The RHR contains a requirement at 40 CFR 51.308(f)(4) related to
any additional monitoring that may be needed to address visibility
impairment in Class I areas from a single source or a small group of
sources. This is called ``reasonably attributable visibility
impairment,'' \181\ also known as RAVI. Under this provision, if the
EPA or the FLM of an affected Class I area has advised a state that
additional monitoring is needed to assess RAVI, the state must include
in its SIP revision for the second implementation period an appropriate
strategy for evaluating such impairment. The EPA has not advised the
State to that effect; nor did the State indicate that FLMs for Bridger
Wilderness Area, Fitzpatrick Wilderness Area, Grand Teton National
Park, North Absaroka Wilderness Area, Teton Wilderness Area, Washakie
Wilderness Area, and Yellowstone National Park identified any RAVI from
Wyoming sources. For this reason, the EPA proposes to approve the
portions of Wyoming's 2022 SIP submission relating to 40 CFR
51.308(f)(4).
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\181\ The EPA's visibility protection regulations define
``reasonably attributable visibility impairment'' as ``visibility
impairment that is caused by the emission of air pollutants from
one, or a small number of sources.'' 40 CFR 51.301.
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F. Monitoring Strategy and Other State Implementation Plan Requirements
Section 51.308(f)(6) specifies that each comprehensive revision of
a state's regional haze SIP must contain or provide for certain
elements, including monitoring strategies, emissions inventories, and
any reporting, recordkeeping and other measures needed to assess and
report on visibility. A main requirement of this section is for states
with Class I areas to submit monitoring strategies for measuring,
characterizing, and reporting on visibility impairment. Compliance with
this requirement may be met through participation in the IMPROVE
network.
Under 40 CFR 51.308(f)(6)(i), States must provide for the
establishment of additional monitoring sites or equipment needed to
assess whether reasonable progress goals to address regional haze for
all mandatory Class I Federal areas within the state are being
achieved. For states with Class I areas (including Wyoming), Sec.
51.308(f)(6)(ii) requires SIPs to provide for procedures by which
monitoring data and other information are used in determining the
contribution of emissions from within the state to regional haze
visibility impairment at mandatory Class I Federal areas both within
and outside the state. Section 51.308(f)(6)(iv) requires the SIP to
provide for the reporting of all visibility monitoring data to the
Administrator at least annually for each Class I area in the state. 40
CFR 51.308(f)(6)(v) requires SIPs to provide for a statewide inventory
of emissions of pollutants that are reasonably anticipated to cause or
contribute to visibility impairment, including emissions for the most
recent year for which data are available. Section 51.308(f)(6)(v) also
requires states to include estimates of future projected emissions.
Finally, 40 CFR 51.308(f)(6)(vi) requires the SIP to provide for any
other elements, including reporting, recordkeeping, and other measures,
that are necessary for states to assess and report on visibility.
Wyoming describes its participation in the IMPROVE network, which
is comprised of 110 monitoring sites across the nation, three of which
are in Wyoming. The State relied on the IMPROVE monitoring network to
assess visibility at Class I areas across Wyoming \182\ and considered
the three monitoring sites, YELL2, NOAB1, and BRID1, to be adequate for
assessing reasonable progress goals at the State's seven Class I
areas.\183\ Using the monitoring data procedures described in its 2022
SIP submission along with
[[Page 63069]]
other technical information supplied by WRAP,184 185 the
State determined the contribution of in-State emissions to Class I
areas inside and outside Wyoming.\186\ In addition, the State also
provided a statewide inventory of emissions that are reasonably
anticipated to cause or contribute to visibility impairment in Class I
areas; the State relied primarily on 2014 data but also estimated
future projected emissions.\187\
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\182\ Wyoming 2022 SIP submission at 31-32.
\183\ Id. at 34-63.
\184\ Id. at 31-33.
\185\ Wyoming relied on the WRAP Technical Support System (TSS)
``Analysis and Planning'' section to determine baseline, natural,
and current conditions for Class I areas in Wyoming. https://views.cira.colostate.edu/tssv2/.
\186\ Wyoming 2022 SIP submission at 34-106.
\187\ Id. at 114-120.
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The EPA finds that Wyoming has met the requirements of 40 CFR
51.308(f)(6), including through its continued participation in the
IMPROVE network and WRAP RPO and its ongoing compliance with the Air
Emissions Reporting Requirements (AERR). There is no indication that
further SIP elements are necessary at this time for Wyoming to assess
and report on visibility. Therefore, the EPA proposes to approve the
monitoring strategy and other state implementation plan elements of
Wyoming's 2022 SIP submission as meeting the requirements of 40 CFR
51.308(f)(6).
G. Requirements for Periodic Reports Describing Progress Towards the
Reasonable Progress Goals
40 CFR 51.308(f)(5) requires that periodic comprehensive revisions
of states' regional haze plans also address the progress report
requirements of 40 CFR 51.308(g)(1) through (5). The purpose of these
requirements is to evaluate progress towards the applicable RPGs for
each Class I area within the state and each Class I area outside the
state that may be affected by emissions from within that state.
Sections 51.308(g)(1) and (2) apply to all states and require a
description of the status of implementation of all measures included in
a state's first implementation period regional haze plan and a summary
of the emission reductions achieved through implementation of those
measures. Section 51.308(g)(3) applies only to states with Class I
areas within their borders and requires such states to assess current
visibility conditions, changes in visibility relative to baseline
(2000-2004) visibility conditions, and changes in visibility conditions
relative to the period addressed in the first implementation period
progress report. Section 51.308(g)(4) applies to all states and
requires an analysis tracking changes in emissions of pollutants
contributing to visibility impairment from all sources and sectors
since the period addressed by the first implementation period progress
report. This provision further specifies the year or years through
which the analysis must extend depending on the type of source and the
platform through which its emission information is reported. Finally,
40 CFR 51.308(g)(5), which also applies to all states, requires an
assessment of any significant changes in anthropogenic emissions within
or outside the state that have occurred since the period addressed by
the first implementation period progress report, including whether such
changes were anticipated and whether they have limited or impeded
expected progress towards reducing emissions and improving visibility.
In its 2022 SIP submission, Wyoming included the elements of the
periodic progress report specified in 40 CFR 51.308(f)(5) and 40 CFR
51.308(g)(1)-(5). Wyoming summarized the facility improvements made
during and after the first implementation period, including emission
control measures installed and emission reductions achieved by the
facilities that most affected each Class I area.\188\ In addition, the
State summarized the implementation status of ongoing air pollution
control programs, measures to mitigate construction activities, source
retirement and replacement schedules, and smoke management practices
and programs, as well as projected changes in point, area, and mobile
source emissions.\189\ The State also provided emissions inventories
for NOX, SO2, PM, and CO that identify the type
of source, activity, and pollutant representing 2014 actual emissions
and 2014-2018 representative baseline emissions.\190\
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\188\ Wyoming 2022 SIP submission at 212-223.
\189\ Id. at 223-229.
\190\ Id. at 114-120.
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Visibility conditions (in deciviews) are reported in Wyoming's 2022
SIP submission for the most impaired and clearest days. Visibility
conditions are expressed in terms of 5-year averages for the baseline
period (2000-2004), 2008-2012 period, and current period (2014-2018),
as well as the progress made since the baseline period ((2000-2004)-
(2014-2018)) and during the last implementation period ((2008-2012)-
(2014-2018)) for each Class I area.\191\ Wyoming also provided an
assessment and discussion of the significant changes in anthropogenic
emissions since the first implementation period.\192\
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\191\ Id. at 42-61.
\192\ Id. at 114-120.
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Because Wyoming's 2022 SIP submission addresses the requirements of
40 CFR 51.308(g)(1) through (5), the EPA finds that Wyoming has met the
progress report requirements of 40 CFR 51.308(f)(5). Therefore, we
propose to approve Wyoming's 2022 SIP submission as meeting the
requirements of 40 CFR 51.308(f)(5) and 40 CFR 51.308(g) for periodic
progress reports.
H. Requirements for State and Federal Land Manager Coordination
Section 169A(d) of the CAA requires states to consult with FLMs
before holding the public hearing on a proposed regional haze SIP, and
to include a summary of the FLMs' conclusions and recommendations in
the notice to the public. In addition, the 40 CFR 51.308(i)(2) FLM
consultation provision requires a state to provide FLMs with an
opportunity for consultation that is early enough in the state's policy
analyses of its emission reduction obligation so that information and
recommendations provided by the FLMs can meaningfully inform the
state's decisions on its long-term strategy. If the consultation has
taken place at least 120 days before a public hearing or public comment
period, the opportunity for consultation will be deemed early enough.
Regardless, the opportunity for consultation must be provided at least
sixty days before a public hearing or public comment period at the
state level. Section 51.308(i)(2) also lists two substantive topics on
which FLMs must be provided an opportunity to discuss with states:
assessment of visibility impairment in any Class I area and
recommendations on the development and implementation of strategies to
address visibility impairment. Section 51.308(i)(3) requires states, in
developing their implementation plans, to include a description of how
they addressed FLMs' comments.
Wyoming's 2022 SIP submission summarizes the State's consultation
and coordination with the FLMs. In August and September 2020, Wyoming
began initial consultation and provided the FLMs with the four-factor
analyses that were performed for Wyoming's sources. Subsequent
consultation meetings with the FLMs were held every 4-8 weeks. Wyoming
shared a complete draft of the SIP with the FLMs on August 10, 2021,
which initiated the 60-day consultation period. Following the FLM
consultation period, a 30-day public comment period took place in
February and March 2022,
[[Page 63070]]
followed by a public hearing conducted on March 23, 2022.\193\ The
State explained how it addressed comments received by the FLMs \194\
and committed to coordinating and consulting with the FLMs during the
development of future progress reports and SIP submissions, as well as
during the implementation of programs having the potential to
contribute to visibility impairment in Class I areas.\195\
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\193\ Wyoming 2022 SIP submission at 25-26.
\194\ Wyoming 2022 SIP submission at appendix M.
\195\ Wyoming 2022 SIP submission at 26-27.
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Compliance with 40 CFR 51.308(i) is dependent on compliance with 40
CFR 51.308(f)(2)'s long-term strategy provisions and 40 CFR
51.308(f)(3)'s reasonable progress goals provisions. Because the EPA is
proposing to disapprove Wyoming's long-term strategy under 51.308(f)(2)
and the reasonable progress goals under 51.308(f)(3), the EPA is also
proposing to disapprove the State's FLM consultation under 51.308(i).
While Wyoming did take administrative steps to provide the FLMs the
opportunity to review and provide feedback on the State's draft
regional haze plan, the EPA cannot approve that consultation because it
was based on a plan that does not meet the statutory and regulatory
requirements of the CAA and the RHR, as described throughout this
document. In addition, if the EPA finalizes our proposed partial
approval and partial disapproval of Wyoming's SIP submission, the State
(or the EPA in the potential case of a FIP) will be required to again
complete the FLM consultation requirements under 40 CFR 51.308(i).
Therefore, the EPA proposes to disapprove the FLM consultation
component of Wyoming's SIP submission for failure to meet the
requirements of 40 CFR 51.308(i), as outlined in this section.
V. Proposed Action
The EPA is proposing approval of the portions of Wyoming's 2022 SIP
submission relating to 40 CFR 51.308(f)(1): calculations of baseline,
current, and natural visibility conditions, progress to date, and the
uniform rate of progress; 40 CFR 51.308(f)(4): reasonably attributable
visibility impairment; 40 CFR 51.308(f)(5): progress report
requirements; and 40 CFR 51.308(f)(6): monitoring strategy and other
implementation plan requirements. The EPA is proposing disapproval of
the remainder of Wyoming's 2022 SIP submission, which addresses 40 CFR
51.308(f)(2): long-term strategy; 40 CFR 51.308 (f)(3): reasonable
progress goals; and 40 CFR 51.308(i): FLM consultation.
VI. Environmental Justice
The EPA conducted an environmental justice (EJ) screening analysis
around the location of the facilities associated with Wyoming's 2022
SIP submission to identify potential environmental stressors on these
communities. The EPA is providing the information associated with this
analysis for informational purposes only; it does not form any part of
the basis of this proposed action. The EPA conducted the screening
analyses using EJScreen, an environmental justice mapping and screening
tool that provides the EPA with a nationally consistent dataset and
approach for combining various environmental and demographic
indicators.\196\
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\196\ The EJSCREEN tool is available at https://www.epa.gov/ejscreen.
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The EPA prepared EJScreen reports covering buffer areas of
approximately six miles around the twelve facilities selected for four-
factor analysis in Wyoming's 2022 SIP submission.\197\ From those
reports, no facilities showed environmental justice indices greater
than the 80th national percentiles.\198\ The full, detailed EJScreen
reports are provided in the docket for this rulemaking.
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\197\ See EJScreens in docket.
\198\ This means that 20 percent of the U.S. population has a
higher value. The EPA identified the 80th percentile filter as an
initial starting point for interpreting EJScreen results. The use of
an initial filter promotes consistency for the EPA's programs and
regions when interpreting screening results.
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VII. Statutory and Executive Order Reviews
Under the CAA, the Administrator is required to approve a SIP
submission that complies with the provisions of the Act and applicable
Federal regulations. 42 U.S.C. 7410(k); 40 CFR 52.02(a). Thus, in
reviewing SIP submissions, the EPA's role is to approve state choices,
provided that they meet the criteria of the CAA. Accordingly, this
action merely proposes to partially approve and partially disapprove
the state's SIP submission as meeting federal requirements and does not
impose additional requirements beyond those imposed by state law. For
that reason, this action:
Is not a ``significant regulatory action'' subject to
review by the Office of Management and Budget under Executive Orders
12866 (58 FR 51735, October 4, 1993) and 13563 (76 FR 3821, January 21,
2011);
Does not impose an information collection burden under the
provisions of the Paperwork Reduction Act (44 U.S.C. 3501 et seq.);
Is certified as not having a significant economic impact
on a substantial number of small entities under the Regulatory
Flexibility Act (5 U.S.C. 601 et seq.);
Does not contain any unfunded mandate or significantly or
uniquely affect small governments, as described in the Unfunded
Mandates Reform Act of 1995 (Pub. L. 104-4);
Does not have Federalism implications as specified in
Executive Order 13132 (64 FR 43255, August 10, 1999);
Is not an economically significant regulatory action based
on health or safety risks subject to Executive Order 13045 (62 FR
19885, April 23, 1997);
Is not a significant regulatory action subject to
Executive Order 13211 (66 FR 28355, May 22, 2001);
Is not subject to requirements of section 12(d) of the
National Technology Transfer and Advancement Act of 1995 (15 U.S.C. 272
note) because application of those requirements would be inconsistent
with the CAA; and
In addition, the SIP is not approved to apply on any Indian
reservation land or in any other area where EPA or an Indian tribe has
demonstrated that a tribe has jurisdiction. In those areas of Indian
country, the proposed rule does not have tribal implications and will
not impose substantial direct costs on tribal governments or preempt
tribal law as specified by Executive Order 13175 (65 FR 67249, November
9, 2000).
Executive Order 12898 (Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations, 59 FR 7629,
Feb. 16, 1994) directs Federal agencies to identify and address
``disproportionately high and adverse human health or environmental
effects'' of their actions on minority populations and low-income
populations to the greatest extent practicable and permitted by law.
EPA defines environmental justice (EJ) as ``the fair treatment and
meaningful involvement of all people regardless of race, color,
national origin, or income with respect to the development,
implementation, and enforcement of environmental laws, regulations, and
policies.'' EPA further defines the term fair treatment to mean that
``no group of people should bear a disproportionate burden of
environmental harms and risks, including those resulting from the
negative environmental consequences of industrial, governmental, and
commercial operations or programs and policies.''
[[Page 63071]]
Wyoming did not evaluate environmental justice considerations as
part of its SIP submission; the CAA and applicable implementing
regulations neither prohibit nor require such an evaluation. The EPA
performed an environmental justice screening analysis, as described
previously in section VI. Environmental Justice. The analysis was done
for the purpose of providing additional context and information about
this rulemaking to the public, not as a basis of the action. There is
no information in the record upon which this decision is based
inconsistent with the stated goal of E.O. 12898 of achieving
environmental justice for people of color, low-income populations, and
Indigenous peoples.
List of Subjects in 40 CFR Part 52
Environmental protection, Air pollution control, Carbon monoxide,
Greenhouse gases, Incorporation by reference, Intergovernmental
relations, Lead, Nitrogen dioxide, Ozone, Particulate matter, Reporting
and recordkeeping requirements, Sulfur oxides, Volatile organic
compounds.
Authority: 42 U.S.C. 7401 et seq.
Dated: July 24, 2024.
KC Becker,
Regional Administrator, Region 8.
[FR Doc. 2024-16718 Filed 7-31-24; 8:45 am]
BILLING CODE 6560-50-P