[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).
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.''
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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).
---------------------------------------------------------------------------

    \34\ Four-factor analysis considers the four statutory factors 
specified in CAA section 169A(g)(1) and 40 CFR 51.308(f)(2)(i).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.''
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \43\ See ``Step 8: Additional requirements for regional haze 
SIPs'' in the 2019 Guidance at 55.
    \44\ Id.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \46\ Wyoming 2022 SIP submission at 20, 35-57.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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).
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \160\ Wyoming 2022 SIP submission at 185.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \161\ Wyoming 2022 SIP Submission at 203-06.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \162\ See CAA sections 169A(a)(1), (b)(2)(B), and (g)(1).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \163\ 82 FR 3080.
    \164\ See footnote 117.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \165\ CAA section 169A(a)(1) (emphasis added); section 
169A(b)(2) (requiring states to develop SIPs to address visibility 
impairment).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \166\ 82 FR 3099-3100.
    \167\ 2019 Guidance at 49.
    \168\ 2021 Clarifications Memo at 15.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \177\ Wyoming 2002 SIP submission at 24-25.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.''
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \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
                                 -------------------------------------------------------------------------------
                                      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).
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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).
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \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