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Proposed Rule2024-16718

Air Plan Partial Approval and Partial Disapproval; Wyoming; Regional Haze Plan for the Second Implementation Period

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Published

August 1, 2024

Issuing agencies

Environmental Protection Agency

Abstract

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.

Full Text

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<title>Federal Register, Volume 89 Issue 148 (Thursday, August 1, 2024)</title>
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[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 [<a href="http://www.gpo.gov">www.gpo.gov</a>]
[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: <a href="https://www.regulations.gov">https://www.regulations.gov</a>. Follow the online instructions for submitting
comments. Once submitted, comments cannot be edited or removed from
<a href="https://www.regulations.gov">https://www.regulations.gov</a>. 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 <a href="https://www2.epa.gov/dockets/commenting-epa-dockets">https://www2.epa.gov/dockets/commenting-epa-dockets</a>.
Docket: All documents in the docket are listed in the <a href="https://www.regulations.gov">https://www.regulations.gov</a> 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
<a href="https://www.regulations.gov">https://www.regulations.gov</a>. 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:
<a href="/cdn-cgi/l/email-protection#294d464b5b4841474c5b0743485a455047694c5948074e465f">[email&#160;protected]</a>.

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 <a href="https://www.epa.gov/sites/default/files/2015-07/documents/procsip.pdf">https://www.epa.gov/sites/default/files/2015-07/documents/procsip.pdf</a>.
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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 (SO<INF>2</INF>), nitrogen oxides (NO<INF>X</INF>), and, in
some cases, volatile organic compounds (VOC) and ammonia
(NH<INF>3</INF>)). Fine particle precursors react in the atmosphere to
form fine particulate matter (PM<INF>2.5</INF>), 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, <a href="https://www.epa.gov/visibility/guidance-regional-haze-state-implementation-plans-second-implementation-period">https://www.epa.gov/visibility/guidance-regional-haze-state-implementation-plans-second-implementation-period</a>, 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. <a href="https://www.epa.gov/visibility/guidance-regional-haze-state-implementation-plans-second-implementation-period">https://www.epa.gov/visibility/guidance-regional-haze-state-implementation-plans-second-implementation-period</a>. 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. <a href="https://www.epa.gov/system/files/documents/2021-07/clarifications-regarding-regional-haze-state-implementation-plans-for-the-second-implementation-period.pdf">https://www.epa.gov/system/files/documents/2021-07/clarifications-regarding-regional-haze-state-implementation-plans-for-the-second-implementation-period.pdf</a>. 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. <a href="https://www.epa.gov/visibility/technical-guidance-tracking-visibility-progress-second-implementation-period-regional">https://www.epa.gov/visibility/technical-guidance-tracking-visibility-progress-second-implementation-period-regional</a>. 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. <a href="https://www.epa.gov/visibility/memo-and-technical-addendum-ambient-data-usage-and-completeness-regional-haze-program">https://www.epa.gov/visibility/memo-and-technical-addendum-ambient-data-usage-and-completeness-regional-haze-program</a>. The EPA
Office of Air Quality Planning and Standards, Research Triangle Park
(June 3, 2020).

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[[Page 63033]]

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 <a href="https://www.westar.org/wrap-council-members/">https://www.westar.org/wrap-council-members/</a>.
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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 NO<INF>X</INF> 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 NO<INF>X</INF> BART determination for Naughton
Units 1 and 2 and vacated and remanded the EPA's disapproval of
Wyoming's NO<INF>X</INF>

[[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
SO<INF>2</INF> emissions reporting requirements for Laramie River
Station Units 1 and 2; (2) revise the NO<INF>X</INF> emission limits
for Laramie River Station Units 1, 2 and 3; and (3) establish an
SO<INF>2</INF> emission limit averaged annually across Laramie River
Station Units 1 and 2. 84 FR 22711 (May 20, 2019).
\23\ Wyoming v. EPA, 78 F.4th 1171, 1175, 1181, 1183 (10th Cir.
2023).
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On November 28, 2017, Wyoming submitted its first progress report
SIP submission. It detailed progress made toward achieving reasonable
progress for visibility improvement and included a determination of
adequacy of the State's regional haze implementation plan to meet
reasonable progress goals. In 2020, we approved Wyoming's progress
report SIP submission.\24\
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\24\ 85 FR 21341 (April 17, 2020) (proposed rule); 85 FR 38325
(June 26, 2020) (final rule).
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In addition, in 2019, we approved an additional first
implementation period SIP submission regarding BART requirements for
Naughton Unit 3.\25\ On April 10, 2024, we proposed to approve
additional revisions for Jim Bridger Power Plant that Wyoming submitted
for the first implementation period regional haze SIP.\26\
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\25\ 84 FR 10433 (March 21, 2019).
\26\ 89 FR 25200 (April 10, 2024). The EPA has not yet issued a
final rule.
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D. Wyoming's Regional Haze Plan for the Second Implementation Period

On August 10, 2022, Wyoming submitted a SIP submission to address
its regional haze obligations for the second implementation period
(2018-2028). Wyoming's 2022 SIP submission contains the State's long-
term strategy to address regional haze visibility impairment for each
Class I area within the State and each Class I area outside the State
that may be affected by emissions from the State. In developing its
long-term strategy, the State examined the need to implement additional
enforceable emission limitations, compliance schedules, and other
measures that are necessary to make reasonable progress since the first
implementation period. Specifically, Wyoming's 2022 SIP submission
contains an assessment of visibility progress made at Class I areas
since the first implementation period and a long-term strategy to
address regional haze visibility impairment at the 23 Class I areas the
State identified, including: Wyoming's selection of sources that may
affect visibility in Class I areas within the State and outside the
State for four-factor analysis; its evaluation of the selected sources
to determine what emission reduction measures constitute reasonable
progress for the long-term strategy; regional scale modeling of the
State's long-term strategy to set reasonable progress goals for 2028;
and ultimately, Wyoming's determinations on what control measures are
necessary for the long-term strategy to address regional haze
visibility impairment in the 23 Class I areas. The State concluded that
no additional emission reduction measures for any Wyoming facilities
are required for the second implementation period under its long-term
strategy.

III. Requirements for Regional Haze Plans for the Second Implementation
Period

Under the CAA and the EPA's regulations, all 50 states, the
District of Columbia, and the U.S. Virgin Islands are required to
submit regional haze SIPs satisfying the applicable requirements for
the second implementation period of the regional haze program by July
31, 2021.\27\ Each state's SIP must contain a long-term strategy for
making reasonable progress toward meeting the national goal of
remedying any existing and preventing any future anthropogenic
visibility impairment in Class I areas. CAA section 169A(b)(2)(B). To
this end, Sec. 51.308(f) lays out the process by which states
determine what constitutes their long-term strategies, with the order
of the requirements in Sec. 51.308(f)(1) through (3) generally
mirroring the order of the steps in the reasonable progress analysis
\28\ and (f)(4) through (6) containing additional, related
requirements. Broadly speaking, a state first must identify the Class I
areas within the state and determine the Class I areas outside the
state in which visibility may be affected by emissions from the state.
These are the Class I areas that must be addressed in the state's long-
term strategy. See 40 CFR 51.308(f), (f)(2). For each Class I area
within its borders, a state must then calculate the baseline, current,
and natural visibility conditions for that area, as well as the
visibility improvement made to date and the URP. See 40 CFR
51.308(f)(1). Each state having a Class I area and/or emissions that
may affect visibility in a Class I area must then develop a long-term
strategy that includes the enforceable emission limitations, compliance
schedules, and other measures that are necessary to make reasonable
progress in such areas. A reasonable progress determination is based on
applying the four factors in CAA section 169A(g)(1) to sources of
visibility impairing pollutants that the state has selected to assess
for controls for the second implementation period. Additionally, as
further explained below, the RHR at 40 CFR 51.3108(f)(2)(iv) separately
provides five ``additional factors'' \29\ that states must consider in
developing their long-term strategies. See 40 CFR 51.308(f)(2). A state
evaluates potential emission reduction measures for those selected
sources and determines which are necessary to make reasonable progress.
Those measures are then incorporated into the state's long-term
strategy. After a state has developed its long-term strategy, it then
establishes RPGs for each Class I area within its borders by modeling
the visibility impacts of all reasonable progress controls at the end
of the second implementation period, i.e., in 2028, as well as the
impacts of other requirements of the CAA. The RPGs include reasonable
progress controls not only for sources in the state in which the Class
I area is located, but also for sources in other states that contribute
to visibility impairment in that area. The RPGs are then compared to
the baseline visibility conditions and the URP to ensure that progress
is being made towards the statutory goal of preventing any future and
remedying any existing anthropogenic visibility impairment in Class I
areas. 40 CFR 51.308(f)(2)-(3).
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\27\ Wyoming is one of a few states with outstanding first
planning period obligations. The EPA is not precluded from acting on
a second planning period SIP submission on the basis that a state
has outstanding first planning period obligations. All states have
an obligation to submit second planning period SIP submissions by
July 31, 2021, regardless of the status of first planning period
obligations. After a second planning period SIP submission is
submitted to the EPA for review, the EPA is statutorily required to
review and act on that submission within 12 months of it being
deemed complete. See CAA section 110(k)(1)(B), 42 U.S.C.
7410(k)(1)(B). Throughout actions on the second planning period, the
EPA will continue to work with those states who have outstanding
first planning period obligations to ensure there is no gap that
could affect the continuous progress of visibility improvement.
\28\ The EPA explained in the 2017 RHR Revisions that we were
adopting new regulatory language in 40 CFR 51.308(f) that, unlike
the structure in 51.308(d), ``tracked the actual planning
sequence.'' (82 FR at 3091).
\29\ The five ``additional factors'' for consideration in Sec.
51.308(f)(2)(iv) are distinct from the four factors listed in CAA
section 169A(g)(1) and 40 CFR 51.308(f)(2)(i) that states must
consider and apply to sources in determining reasonable progress.
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In addition to satisfying the requirements at 40 CFR 51.308(f)
related to reasonable progress, the regional haze SIP revisions for the
second implementation period must address the requirements in Sec.
51.308(g)(1) through (5) pertaining to periodic reports describing
progress towards the RPGs, 40 CFR 51.308(f)(5), as well as requirements
for FLM consultation that apply to all visibility protection SIPs and
SIP revisions. 40 CFR 51.308(i).
A state must submit its regional haze SIP and subsequent SIP
revisions to the EPA according to the requirements

[[Page 63035]]

applicable to all SIP revisions under the CAA and the EPA's
regulations. See CAA section 169A(b)(2); CAA section 110(a). Upon
approval by the EPA, a SIP is enforceable by the Agency and the public
under the CAA. If the EPA finds that a state fails to make a required
SIP revision, or if the EPA finds that a state's SIP is incomplete or
if it disapproves the SIP, the Agency must promulgate a federal
implementation plan (FIP) that satisfies the applicable requirements.
CAA section 110(c)(1).

A. Identification of Class I Areas

The first step in developing a regional haze SIP is for a state to
determine which Class I areas, in addition to those within its borders,
``may be affected'' by emissions from within the state. In the 1999
RHR, the EPA determined that all states contribute to visibility
impairment in at least one Class I area, 64 FR at 35720-22, and
explained that the statute and regulations lay out an ``extremely low
triggering threshold'' for determining ``whether States should be
required to engage in air quality planning and analysis as a
prerequisite to determining the need for control of emissions from
sources within their State.'' Id. at 35721.
A state must determine which Class I areas must be addressed by its
SIP by evaluating the total emissions of visibility impairing
pollutants from all sources within the state. While the RHR does not
require this evaluation to be conducted in any particular manner, EPA's
2019 Guidance provides recommendations for how such an assessment might
be accomplished, including by, where appropriate, using the
determinations previously made for the first implementation period.
2019 Guidance at 8-9. In addition, the determination of which Class I
areas may be affected by a state's emissions is subject to the
requirement in 40 CFR 51.308(f)(2)(iii) to ``document the technical
basis, including modeling, monitoring, cost, engineering, and emissions
information, on which the State is relying to determine the emission
reduction measures that are necessary to make reasonable progress in
each mandatory Class I Federal area it affects.''

B. Calculation of Baseline, Current, and Natural Visibility Conditions;
Progress to Date; and Uniform Rate of Progress

As part of assessing whether a SIP submission for the second
implementation period is providing for reasonable progress towards the
national visibility goal, the RHR contains requirements in Sec.
51.308(f)(1) related to tracking visibility improvement over time. The
requirements of this section apply only to states having Class I areas
within their borders; the required calculations must be made for each
such Class I area. The EPA's 2018 Visibility Tracking Guidance \30\
provides recommendations to assist states in satisfying their
obligations under Sec. 51.308(f)(1); specifically, in developing
information on baseline, current, and natural visibility conditions,
and in making optional adjustments to the URP to account for the
impacts of international anthropogenic emissions and prescribed fires.
See 82 FR at 3103-05.
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\30\ The 2018 Visibility Tracking Guidance references and relies
on parts of the 2003 Tracking Guidance: ``Guidance for Tracking
Progress Under the Regional Haze Rule,'' which can be found at
<a href="https://www.epa.gov/sites/default/files/2021-03/documents/tracking.pdf">https://www.epa.gov/sites/default/files/2021-03/documents/tracking.pdf</a>.
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The RHR requires tracking of visibility conditions on two sets of
days: the clearest and the most impaired days. Visibility conditions
for both sets of days are expressed as the average deciview index for
the relevant five-year period (the period representing baseline or
current visibility conditions). The RHR provides that the relevant sets
of days for visibility tracking purposes are the 20% clearest (the 20%
of monitored days in a calendar year with the lowest values of the
deciview index) and 20% most impaired days (the 20% of monitored days
in a calendar year with the highest amounts of anthropogenic visibility
impairment).\31\ 40 CFR 51.301. A state must calculate visibility
conditions for both the 20% clearest and 20% most impaired days for the
baseline period of 2000-2004 and the most recent five-year period for
which visibility monitoring data are available (representing current
visibility conditions). 40 CFR 51.308(f)(1)(i), (iii). States must also
calculate natural visibility conditions for the clearest and most
impaired days,\32\ by estimating the conditions that would exist on
those two sets of days absent anthropogenic visibility impairment. 40
CFR 51.308(f)(1)(ii). Using all these data, states must then calculate,
for each Class I area, the amount of progress made since the baseline
period (2000-2004) and how much improvement is left to achieve to reach
natural visibility conditions.
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\31\ This document also refers to the 20% clearest and 20% most
anthropogenically impaired days as the ``clearest'' and ``most
impaired'' or ``most anthropogenically impaired'' days,
respectively.
\32\ The RHR at 40 CFR 51.308(f)(1)(ii) contains an error
related to the requirement for calculating two sets of natural
conditions values. The rule says ``most impaired days or the
clearest days'' where it should say ``most impaired days and
clearest days.'' This is an error that was intended to be corrected
in the 2017 RHR Revisions but did not get corrected in the final
rule language. This is supported by the preamble text at 82 FR at
3098: ``In the final version of 40 CFR 51.308(f)(1)(ii), an
occurrence of `or' has been corrected to `and' to indicate that
natural visibility conditions for both the most impaired days and
the clearest days must be based on available monitoring
information.''
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Using the data for the set of most impaired days only, states must
plot a line between visibility conditions in the baseline period and
natural visibility conditions for each Class I area to determine the
URP--the amount of visibility improvement, measured in deciviews, that
would need to be achieved during each implementation period to achieve
natural visibility conditions by the end of 2064. The URP is used in
later steps of the reasonable progress analysis for informational
purposes and to provide a non-enforceable benchmark against which to
assess a Class I area's rate of visibility improvement.\33\
Additionally, in the 2017 RHR Revisions, the EPA provided states the
option of proposing to adjust the endpoint of the URP to account for
impacts of anthropogenic sources outside the United States and/or
impacts of certain types of wildland prescribed fires. These
adjustments, which must be approved by the EPA, are intended to avoid
any perception that states should compensate for impacts from
international anthropogenic sources and to give states the flexibility
to determine that limiting the use of wildland-prescribed fire is not
necessary for reasonable progress. 82 FR at 3107 footnote 116.
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\33\ Being on or below the URP is not a ``safe harbor''; i.e.,
achieving the URP does not mean that a Class I area is making
``reasonable progress'' and does not relieve a state from using the
four statutory factors to determine what level of control is needed
to achieve such progress. See, e.g., 82 FR at 3093.
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The EPA's 2018 Visibility Tracking Guidance can be used to help
satisfy the 40 CFR 51.308(f)(1) requirements, including in developing
information on baseline, current, and natural visibility conditions,
and in making optional adjustments to the URP. In addition, the 2020
Data Completeness Memo provides recommendations on the data
completeness language referenced in Sec. 51.308(f)(1)(i) and provides
updated natural conditions estimates for each Class I area.

C. Long-Term Strategy for Regional Haze

The core component of a regional haze SIP submission is a long-term
strategy that addresses regional haze in each Class I area within a
state's borders and each Class I area outside the state that may be
affected by emissions from the state. The long-term strategy ``must
include the enforceable emissions

[[Page 63036]]

limitations, compliance schedules, and other measures that are
necessary to make reasonable progress, as determined pursuant to
(f)(2)(i) through (iv).'' 40 CFR 51.308(f)(2). The amount of progress
that is ``reasonable progress'' is based on applying the four statutory
factors in CAA section 169A(g)(1) in an evaluation of potential control
options for sources of visibility impairing pollutants, which is
referred to as a ``four-factor'' analysis.\34\ The outcome of that
analysis is the emission reduction measures that a particular source or
group of sources needs to implement to make reasonable progress towards
the national visibility goal. See 40 CFR 51.308(f)(2)(i). Emission
reduction measures that are necessary to make reasonable progress may
be either new, additional control measures for a source, or they may be
the existing emission reduction measures that a source is already
implementing. See 2019 Guidance at 43; 2021 Clarifications Memo at 8-
10. Such measures must be represented by ``enforceable emissions
limitations, compliance schedules, and other measures'' (i.e., any
additional compliance tools) in a state's long-term strategy in its
SIP. 40 CFR 51.308(f)(2).
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\34\ Four-factor analysis considers the four statutory factors
specified in CAA section 169A(g)(1) and 40 CFR 51.308(f)(2)(i).
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Section 51.308(f)(2)(i) provides the requirements for the four-
factor analysis. The first step of this analysis entails selecting the
sources to be evaluated for emission reduction measures; to this end,
the RHR requires states to consider ``major and minor stationary
sources or groups of sources, mobile sources, and area sources'' of
visibility impairing pollutants for potential four-factor control
analysis. 40 CFR 51.308(f)(2)(i). A threshold question at this step is
which visibility impairing pollutants will be analyzed. As the EPA
previously explained, consistent with the first implementation period,
the EPA generally expects that each state will analyze at least
SO<INF>2</INF> and NO<INF>X</INF> in selecting sources and determining
control measures. See 2019 Guidance at 12, 2021 Clarifications Memo at
4. A state that chooses not to consider at least these two pollutants
should demonstrate why such consideration would be unreasonable. 2021
Clarifications Memo at 4.
While states have the option to analyze all sources, the 2019
Guidance explains that ``an analysis of control measures is not
required for every source in each implementation period,'' and that
``[s]electing a set of sources for analysis of control measures in each
implementation period is . . . consistent with the Regional Haze Rule,
which sets up an iterative planning process and anticipates that a
state may not need to analyze control measures for all its sources in a
given SIP revision.'' 2019 Guidance at 9. However, given that source
selection is the basis of all subsequent control determinations, a
reasonable source selection process ``should be designed and conducted
to ensure that source selection results in a set of pollutants and
sources the evaluation of which has the potential to meaningfully
reduce their contributions to visibility impairment.'' 2021
Clarifications Memo at 3.
The EPA explained in the 2021 Clarifications Memo that each state
has an obligation to submit a long-term strategy that addresses the
regional haze visibility impairment that results from emissions from
within that state. Thus, source selection should focus on the in-state
contribution to visibility impairment and be designed to capture a
meaningful portion of the state's total contribution to visibility
impairment in Class I areas. A state should not decline to select its
largest in-state sources on the basis that there are even larger out-
of-state contributors. 2021 Clarifications Memo at 4.\35\
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\35\ Similarly, in responding to comments on the 2017 RHR
Revisions the EPA explained that ``[a] state should not fail to
address its many relatively low-impact sources merely because it
only has such sources and another state has even more low-impact
sources and/or some high impact sources.'' Responses to Comments on
Protection of Visibility: Amendments to Requirements for State
Plans; Proposed Rule (81 FR 26942, May 4, 2016) at 87-88.
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Thus, while states have discretion to choose any source selection
methodology that is reasonable, whatever choices they make should be
reasonably explained. To this end, 40 CFR 51.308(f)(2)(i) requires that
a state's SIP submission include ``a description of the criteria it
used to determine which sources or groups of sources it evaluated.''
The technical basis for source selection, which may include methods for
quantifying potential visibility impacts such as emissions divided by
distance metrics, trajectory analyses, residence time analyses, and/or
photochemical modeling, must also be appropriately documented, as
required by 40 CFR 51.308(f)(2)(iii).
Once a state has selected the set of sources, the next step is to
determine the emissions reduction measures for those sources that are
necessary to make reasonable progress for the second implementation
period.\36\ This is accomplished by considering the four factors--``the
costs of compliance, the time necessary for compliance, and the energy
and non-air quality environmental impacts of compliance, and the
remaining useful life of any existing source subject to such
requirements.'' CAA section 169A(g)(1). The EPA has explained that the
four-factor analysis is an assessment of potential emission reduction
measures (i.e., control options) for sources; ``use of the terms
`compliance' and `subject to such requirements' in section 169A(g)(1)
strongly indicates that Congress intended the relevant determination to
be the requirements with which sources would have to comply to satisfy
the CAA's reasonable progress mandate.'' 82 FR at 3091. Thus, for each
source it has selected for four-factor analysis,\37\ a state must
consider a ``meaningful set'' of technically feasible control options
for reducing emissions of visibility impairing pollutants. Id. at 3088.
The 2019 Guidance provides that ``[a] state must reasonably pick and
justify the measures that it will consider, recognizing that there is
no statutory or regulatory requirement to consider all technically
feasible measures or any particular measures. A range of technically
feasible measures available to reduce emissions would be one way to
justify a reasonable set.'' 2019 Guidance at 29.
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\36\ The CAA provides that, ``[i]n determining reasonable
progress there shall be taken into consideration'' the four
statutory factors. CAA section 169A(g)(1). However, in addition to
four-factor analyses for selected sources, groups of sources, or
source categories, a state may also consider additional emission
reduction measures for inclusion in its long-term strategy, e.g.,
from other newly adopted, on-the-books, or on-the-way rules and
measures for sources not selected for four-factor analysis for the
second implementation period.
\37\ ``Each source'' or ``particular source'' is used here as
shorthand. While a source-specific analysis is one way of applying
the four factors, neither the statute nor the RHR requires states to
evaluate individual sources. Rather, states have ``the flexibility
to conduct four-factor analyses for specific sources, groups of
sources or even entire source categories, depending on state policy
preferences and the specific circumstances of each state.'' 82 FR at
3088. However, not all approaches to grouping sources for four-
factor analysis are necessarily reasonable; the reasonableness of
grouping sources in any particular instance will depend on the
circumstances and the manner in which grouping is conducted. If it
is feasible to establish and enforce different requirements for
sources or subgroups of sources, and if relevant factors can be
quantified for those sources or subgroups, then states should make a
separate reasonable progress determination for each source or
subgroup. 2021 Clarifications Memo at 7-8.
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The EPA's 2021 Clarifications Memo provides further guidance on
what constitutes a reasonable set of control options for consideration:
``A reasonable four-factor analysis will consider the full range of
potentially reasonable options for reducing emissions.'' 2021
Clarifications Memo at 7. In addition to

[[Page 63037]]

add-on controls and other retrofits (i.e., new emissions reduction
measures for sources), the EPA explained that states should generally
analyze efficiency improvements for sources' existing measures as
control options in their four-factor analyses, as in many cases such
improvements are reasonable given that they typically involve only
additional operation and maintenance costs. Additionally, the 2021
Clarifications Memo provides that states that have assumed a higher
emissions rate than a source has achieved or could potentially achieve
using its existing measures should also consider lower emissions rates
as potential control options. That is, a state should consider a
source's recent actual and projected emission rates to determine if it
could reasonably attain lower emission rates with its existing
measures. If so, the state should analyze the lower emission rate as a
control option for reducing emissions. 2021 Clarifications Memo at 7.
The EPA's recommendations to analyze potential efficiency improvements
and achievable lower emission rates apply to both sources that have
been selected for four-factor analysis and those that have forgone a
four-factor analysis on the basis of existing ``effective controls.''
See 2021 Clarifications Memo at 5, 10.
After identifying a reasonable set of potential control options for
the sources it has selected, a state then collects information on the
four factors with regard to each option identified. The EPA has also
explained that, in addition to the four statutory factors, states have
flexibility under the CAA and RHR to reasonably consider visibility
benefits as an additional factor alongside the four statutory
factors.\38\ The 2019 Guidance provides recommendations for the types
of information that can be used to characterize the four factors (with
or without visibility), as well as ways in which states might
reasonably consider and balance that information to determine which of
the potential control options is necessary to make reasonable progress.
See 2019 Guidance at 30-36. The 2021 Clarifications Memo contains
further guidance on how states can reasonably consider modeled
visibility impacts or benefits in the context of a four-factor
analysis. 2021 Clarifications Memo at 12-13, 14-15. Specifically, the
EPA explained that while visibility can reasonably be used when
comparing and choosing between multiple reasonable control options, it
should not be used to summarily reject controls that are reasonable
given the four statutory factors. 2021 Clarifications Memo at 13.
Ultimately, while states have discretion to reasonably weigh the
factors and to determine what level of control is needed, Sec.
51.308(f)(2)(i) provides that a state ``must include in its
implementation plan a description of . . . how the four factors were
taken into consideration in selecting the measure for inclusion in its
long-term strategy.''
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\38\ See, e.g., Responses to Comments on Protection of
Visibility: Amendments to Requirements for State Plans; Proposed
Rule (81 FR 26942, May 4, 2016), Docket ID No. EPA-HQ-OAR-2015-0531,
U.S. Environmental Protection Agency at 186; 2019 Guidance at 36-37.
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As explained above, Sec. 51.308(f)(2)(i) requires states to
determine the emission reduction measures for sources that are
necessary to make reasonable progress by considering the four factors.
Pursuant to Sec. 51.308(f)(2), measures that are necessary to make
reasonable progress towards the national visibility goal must be
included in a state's long-term strategy and in its SIP.\39\ If the
outcome of a four-factor analysis is a new, additional emission
reduction measure for a source, that new measure is necessary to make
reasonable progress towards remedying existing anthropogenic visibility
impairment and must be included in the SIP. If the outcome of a four-
factor analysis is that no new measures are reasonable for a source,
continued implementation of the source's existing measures is generally
necessary to prevent future emission increases and thus to make
reasonable progress towards the second part of the national visibility
goal: preventing future anthropogenic visibility impairment. See CAA
section 169A(a)(1). That is, when the result of a four-factor analysis
is that no new measures are necessary to make reasonable progress, the
source's existing measures are generally necessary to make reasonable
progress and must be included in the SIP. However, there may be
circumstances in which a state can demonstrate that a source's existing
measures are not necessary to make reasonable progress. Specifically,
if a state can demonstrate that a source will continue to implement its
existing measures and will not increase its emissions rate, it may not
be necessary to have those measures in the long-term strategy to
prevent future emissions increases and future visibility impairment.
The EPA's 2021 Clarifications Memo provides further explanation and
guidance on how states may demonstrate that a source's existing
measures are not necessary to make reasonable progress. See 2021
Clarifications Memo at 8-10. If the state can make such a
demonstration, it need not include a source's existing measures in the
long-term strategy or its SIP.
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\39\ States may choose to, but are not required to, include
measures in their long-term strategies beyond just the emission
reduction measures that are necessary for reasonable progress. See
2021 Clarifications Memo at 16. For example, states with smoke
management programs may choose to submit their smoke management
plans to the EPA for inclusion in their SIPs but are not required to
do so. See, e.g., 82 FR at 3108-09 (requirement to consider smoke
management practices and smoke management programs under 40 CFR
51.308(f)(2)(iv) does not require states to adopt such practices or
programs into their SIPs, although they may elect to do so).
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As with source selection, the characterization of information on
each of the factors is also subject to the documentation requirement in
Sec. 51.308(f)(2)(iii). The reasonable progress analysis, including
source selection, information gathering, characterization of the four
statutory factors (and potentially visibility), balancing of the four
factors, and selection of the emission reduction measures that
represent reasonable progress, is a technically complex exercise, but
also a flexible one that provides states with bounded discretion to
design and implement approaches appropriate to their circumstances.
Given this flexibility, Sec. 51.308(f)(2)(iii) plays an important
function in requiring a state to document the technical basis for its
decision making so that the public and the EPA can comprehend and
evaluate the information and analysis the state relied upon to
determine what emission reduction measures must be in place to make
reasonable progress. The technical documentation must include the
modeling, monitoring, cost, engineering, and emissions information on
which the state relied to determine the measures necessary to make
reasonable progress. This documentation requirement can be met through
the provision of and reliance on technical analyses developed through a
regional planning process, so long as that process and its output has
been approved by all state participants. In addition to the explicit
regulatory requirement to document the technical basis of their
reasonable progress determinations, states are also subject to the
general principle that those determinations must be reasonably moored
to the statute.\40\ That is, a state's decisions about the emission
reduction measures that are necessary to

[[Page 63038]]

make reasonable progress must be consistent with the statutory goal of
remedying existing and preventing future visibility impairment.
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\40\ See Arizona ex rel. Darwin v. U.S. EPA, 815 F.3d 519, 531
(9th Cir. 2016); Nebraska v. EPA, 812 F.3d 662, 668 (8th Cir. 2016);
North Dakota v. EPA, 730 F.3d 750, 761 (8th Cir. 2013); Oklahoma v.
EPA, 723 F.3d 1201, 1206, 1208-10 (10th Cir. 2013); cf. Nat'l Parks
Conservation Ass'n v. EPA, 803 F.3d 151, 165 (3d Cir. 2015); Alaska
Dep't of Envtl. Conservation v. EPA, 540 U.S. 461, 485, 490 (2004).
---------------------------------------------------------------------------

The four statutory factors (and potentially visibility) are used to
determine what emission reduction measures for selected sources must be
included in a state's long-term strategy for making reasonable
progress. Additionally, the RHR at 40 CFR 51.3108(f)(2)(iv) separately
provides five ``additional factors'' \41\ that states must consider in
developing their long-term strategies: (1) Emission reductions due to
ongoing air pollution control programs, including measures to address
reasonably attributable visibility impairment; (2) measures to reduce
the impacts of construction activities; (3) source retirement and
replacement schedules; (4) basic smoke management practices for
prescribed fire used for agricultural and wildland vegetation
management purposes and smoke management programs; and (5) the
anticipated net effect on visibility due to projected changes in point,
area, and mobile source emissions over the period addressed by the
long-term strategy. The 2019 Guidance provides that a state may satisfy
this requirement by considering these additional factors in the process
of selecting sources for four-factor analysis, when performing that
analysis, or both, and that not every one of the additional factors
needs to be considered at the same stage of the process. See 2019
Guidance at 21. The EPA provided further guidance on the five
additional factors in the 2021 Clarifications Memo, explaining that a
state should generally not reject cost-effective and otherwise
reasonable controls merely because there have been emission reductions
since the first planning period owing to other ongoing air pollution
control programs or merely because visibility is otherwise projected to
improve at Class I areas. Additionally, states generally should not
rely on these additional factors to summarily assert that the state has
already made sufficient progress and, therefore, no sources need to be
selected or no new controls are needed regardless of the outcome of
four-factor analyses. 2021 Clarifications Memo at 13.
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\41\ The five ``additional factors'' for consideration in Sec.
51.308(f)(2)(iv) are distinct from the four factors listed in CAA
section 169A(g)(1) and 40 CFR 51.308(f)(2)(i) that states must
consider and apply to sources in determining reasonable progress.
---------------------------------------------------------------------------

Because the air pollution that causes regional haze crosses state
boundaries, Sec. 51.308(f)(2)(ii) requires a state to consult with
other states that also have emissions that are reasonably anticipated
to contribute to visibility impairment in a given Class I area.
Consultation allows for each state that impacts visibility in an area
to share whatever technical information, analyses, and control
determinations may be necessary to develop coordinated emission
management strategies. This coordination may be managed through inter-
and intra-RPO consultation and the development of regional emissions
strategies; additional consultations between states outside of RPO
processes may also occur. If a state, pursuant to consultation, agrees
that certain measures (e.g., a certain emission limitation) are
necessary to make reasonable progress at a Class I area, it must
include those measures in its SIP. 40 CFR 51.308(f)(2)(ii)(A).
Additionally, the RHR requires that states that contribute to
visibility impairment at the same Class I area consider the emission
reduction measures the other contributing states have identified as
being necessary to make reasonable progress for their own sources. 40
CFR 51.308(f)(2)(ii)(B). If a state has been asked to consider or adopt
certain emission reduction measures, but ultimately determines those
measures are not necessary to make reasonable progress, that state must
document in its SIP the actions taken to resolve the disagreement. 40
CFR 51.308(f)(2)(ii)(C). The EPA will consider the technical
information and explanations presented by the submitting state and the
state with which it disagrees when considering whether to approve the
state's SIP. See id.; 2019 Guidance at 53. Under all circumstances, a
state must document in its SIP submission all substantive consultations
with other contributing states. 40 CFR 51.308(f)(2)(ii)(C).

D. Reasonable Progress Goals

Reasonable progress goals ``measure the progress that is projected
to be achieved by the control measures states have determined are
necessary to make reasonable progress based on a four-factor
analysis.'' 82 FR at 3091. Their primary purpose is to assist the
public and the EPA in assessing the reasonableness of states' long-term
strategies for making reasonable progress towards the national
visibility goal for Class I areas within the state. See 40 CFR
51.308(f)(3)(iii)-(iv). States in which Class I areas are located must
establish two RPGs, both in deciviews--one representing visibility
conditions on the clearest days and one representing visibility on the
most anthropogenically impaired days--for each area within their
borders. 40 CFR 51.308(f)(3)(i). The two RPGs are intended to reflect
the projected impacts, on the two sets of days, of the emission
reduction measures the state with the Class I area, as well as all
other contributing states, have included in their long-term strategies
for the second implementation period.\42\ The RPGs also account for the
projected impacts of implementing other CAA requirements, including
non-SIP based requirements. Because RPGs are the modeled result of the
measures in states' long-term strategies (as well as other measures
required under the CAA), they cannot be determined before states have
conducted their four-factor analyses and determined the control
measures that are necessary to make reasonable progress. See 2021
Clarifications Memo at 6.
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\42\ RPGs are intended to reflect the projected impacts of the
measures all contributing states include in their long-term
strategies. However, due to the timing of analyses, control
determinations by other states, and other on-going emissions
changes, a particular state's RPGs may not reflect all control
measures and emissions reductions that are expected to occur by the
end of the implementation period. The 2019 Guidance provides
recommendations for addressing the timing of RPG calculations when
states are developing their long-term strategies on disparate
schedules, as well as for adjusting RPGs using a post-modeling
approach. 2019 Guidance at 47-48.
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For the second implementation period, the RPGs are set for 2028.
Reasonable progress goals are not enforceable targets, 40 CFR
51.308(f)(3)(iii); rather, they ``provide a way for the states to check
the projected outcome of the [long-term strategy] against the goals for
visibility improvement.'' 2019 Guidance at 46. While states are not
legally obligated to achieve the visibility conditions described in
their RPGs, Sec. 51.308(f)(3)(i) requires that ``[t]he long-term
strategy and the reasonable progress goals must provide for an
improvement in visibility for the most impaired days since the baseline
period and ensure no degradation in visibility for the clearest days
since the baseline period.'' Thus, states are required to have emission
reduction measures in their long-term strategies that are projected to
achieve visibility conditions on the most impaired days that are better
than the baseline period and that show no degradation on the clearest
days compared to the clearest days from the baseline period. The
baseline period for the purpose of this comparison is the baseline
visibility condition--the annual average visibility condition for the
period 2000-2004. See 40 CFR 51.308(f)(1)(i), 82 FR at 3097-98.
So that RPGs may also serve as a metric for assessing the amount of
progress a state is making towards the national visibility goal, the
RHR

[[Page 63039]]

requires states with Class I areas to compare the 2028 RPG for the most
impaired days to the corresponding point on the URP line (representing
visibility conditions in 2028 if visibility were to improve at a linear
rate from conditions in the baseline period of 2000-2004 to natural
visibility conditions in 2064). If the most impaired days RPG in 2028
is above the URP (i.e., if visibility conditions are improving more
slowly than the rate described by the URP), each state that contributes
to visibility impairment in the Class I area must demonstrate, based on
the four-factor analysis required under 40 CFR 51.308(f)(2)(i), that no
additional emission reduction measures would be reasonable to include
in its long-term strategy. 40 CFR 51.308(f)(3)(ii). To this end, 40 CFR
51.308(f)(3)(ii) requires that each state contributing to visibility
impairment in a Class I area that is projected to improve more slowly
than the URP provide ``a robust demonstration, including documenting
the criteria used to determine which sources or groups [of] sources
were evaluated and how the four factors required by paragraph (f)(2)(i)
were taken into consideration in selecting the measures for inclusion
in its long-term strategy.'' The 2019 Guidance provides suggestions
about how such a ``robust demonstration'' might be conducted. See 2019
Guidance at 50-51.
The 2017 RHR, 2019 Guidance, and 2021 Clarifications Memo also
explain that projecting an RPG that is on or below the URP based on
only on-the-books and/or on-the-way control measures (i.e., control
measures already required or anticipated before the four-factor
analysis is conducted) is not a ``safe harbor'' from the CAA's and
RHR's requirement that all states must conduct a four-factor analysis
to determine what emission reduction measures constitute reasonable
progress. The URP is a planning metric used to gauge the amount of
progress made thus far and the amount left before reaching natural
visibility conditions. However, the URP is not based on consideration
of the four statutory factors and therefore cannot answer the question
of whether the amount of progress being made in any particular
implementation period is ``reasonable progress.'' See 82 FR at 3093,
3099-3100; 2019 Guidance at 22; 2021 Clarifications Memo at 15-16.

E. Monitoring Strategy and Other State Implementation Plan Requirements

Section 51.308(f)(6) requires states to have certain strategies and
elements in place for assessing and reporting on visibility. Individual
requirements under this section apply either to states with Class I
areas within their borders, states with no Class I areas but that are
reasonably anticipated to cause or contribute to visibility impairment
in any Class I area, or both. A state with Class I areas within its
borders must submit with its SIP revision a monitoring strategy for
measuring, characterizing, and reporting regional haze visibility
impairment that is representative of all Class I areas within the
state. SIP revisions for such states must also provide for the
establishment of any additional monitoring sites or equipment needed to
assess visibility conditions in Class I areas, as well as reporting of
all visibility monitoring data to the EPA at least annually. Compliance
with the monitoring strategy requirement may be met through a state's
participation in the Interagency Monitoring of Protected Visual
Environments (IMPROVE) monitoring network, which is used to measure
visibility impairment caused by air pollution at the 156 Class I areas
covered by the visibility program. 40 CFR 51.308(f)(6), (f)(6)(i),
(f)(6)(iv). The IMPROVE monitoring data is used to determine the 20%
most anthropogenically impaired and 20% clearest sets of days every
year at each Class I area and tracks visibility impairment over time.
All states' SIPs must provide for procedures by which monitoring
data and other information are used to determine the contribution of
emissions from within the state to regional haze visibility impairment
in affected Class I areas. 40 CFR 51.308(f)(6)(ii) and (iii). Section
51.308(f)(6)(v) further requires that all states' SIPs provide for a
statewide inventory of emissions of pollutants that are reasonably
anticipated to cause or contribute to visibility impairment in any
Class I area; the inventory must include emissions for the most recent
year for which data are available and estimates of future projected
emissions. States must also include commitments to update their
inventories periodically. The inventories themselves do not need to be
included as elements in the SIP and are not subject to the EPA's review
as part of the Agency's evaluation of a SIP revision.\43\ All states'
SIPs must also provide for any other elements, including reporting,
recordkeeping, and other measures, that are necessary for states to
assess and report on visibility. 40 CFR 51.308(f)(6)(vi). Per the 2019
Guidance, a state may note in its regional haze SIP that its compliance
with the Air Emissions Reporting Rule (AERR) in 40 CFR part 51, subpart
A satisfies the requirement to provide for an emissions inventory for
the most recent year for which data are available. To satisfy the
requirement to provide estimates of future projected emissions, a state
may explain in its SIP how projected emissions were developed for use
in establishing RPGs for its own and nearby Class I areas.\44\
---------------------------------------------------------------------------

\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\
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\46\ Wyoming 2022 SIP submission at 20, 35-57.
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Grand Teton National Park, established in 1929, occupies 305,504
acres along the Teton Range and Jackson Lake. It is adjacent to the
Teton Wilderness Area to the northeast and is 6 miles south of
Yellowstone National Park. In 2018, Grand Teton National Park had
3,491,151 visitors.
Yellowstone National Park became the world's first national park on
March 1, 1872, and occupies 2,020,625 acres \47\ in northwestern
Wyoming, overlapping into Montana and Idaho. In 2018, Yellowstone
National Park had 4,114,999 visitors.
---------------------------------------------------------------------------

\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. <a href="https://www.epa.gov/visibility/list-areas-protected-regional-haze-program">https://www.epa.gov/visibility/list-areas-protected-regional-haze-program</a>.
---------------------------------------------------------------------------

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\
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\50\ Wyoming 2022 SIP submission at Figures 6-9 and 6-10
(YELL2), Figures 6-18 and 6-19 (NOAB1), and Figures 6-26 and 6-27
(BRID1).
\51\ Wildland prescribed fires are those conducted with the
objective to establish, restore, and/or maintain sustainable and
resilient wildland ecosystems, to reduce the risk of catastrophic
wildfires, and/or to preserve endangered or threatened species
during which appropriate basic smoke management practices were
applied.
\52\ Wyoming 2022 SIP submission at 239-242.
\53\ Wyoming 2022 SIP submission at 70-106.
---------------------------------------------------------------------------

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 (NO<INF>X</INF>, SO<INF>2</INF>,
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
NO<INF>X</INF> and SO<INF>2</INF> 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 NO<INF>X</INF> and
SO<INF>2</INF>, 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 SO<INF>2</INF>
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 NO<INF>X</INF>
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
NO<INF>X</INF> and SO<INF>2</INF> 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 SO<INF>2</INF> emission limit of the 2012
Mercury and Air Toxics Standards (MATS); (2) LNB/SOFA NO<INF>X</INF>
emission controls installed in 2010 (Unit 1), 2006 (Unit 2), 2007 (Unit
3), and 2008 (Unit 4); and (3) SCR NO<INF>X</INF> emission controls
installed in 2015 (Unit 3) and 2016 (Unit 4). PacifiCorp also
referenced plant-wide monthly-block NO<INF>X</INF> and SO<INF>2</INF>
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
SO<INF>2</INF> emission limit of the 2012 MATS rule for power

[[Page 63044]]

plants; (2) NO<INF>X</INF> and SO<INF>2</INF> 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
NO<INF>X</INF> 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 NO<INF>X</INF>
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 NO<INF>X</INF> and SO<INF>2</INF>
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 SO<INF>2</INF>
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 NO<INF>X</INF> and SO<INF>2</INF> 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 SO<INF>2</INF>
emission limit of the 2012 MATS rule; and (2) LNB/SOFA NO<INF>X</INF>
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
NO<INF>X</INF> and SO<INF>2</INF> 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 NO<INF>X</INF>, SO<INF>2</INF>, 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 NO<INF>X</INF> and SO<INF>2</INF> controls,
but not for PM controls. The State did not evaluate Unit 1 for further
NO<INF>X</INF> emissions controls because it is equipped with SCR,
which the State asserts is the best available control technology (BACT)
for NO<INF>X</INF>. The State evaluated SCR as the technically feasible
option for further NO<INF>X</INF> emissions control on Units 2 and 3
(table 7). For further SO<INF>2</INF> 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 SO<INF>2</INF> 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
SO<INF>2</INF> emissions. For SO<INF>2</INF> 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 NO<INF>X</INF> 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
SO<INF>2</INF> emissions have declined by over 780 tons/year between
the three units, SO<INF>2</INF> 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 SO<INF>2</INF> control, LNB/SOFA for
NO<INF>X</INF> 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 SO<INF>2</INF> 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 SO<INF>2</INF> emission limit of the 2012 MATS
rule; and (2) a baghouse retrofit for PM emissions control installed in
2010. PacifiCorp argued that these SO<INF>2</INF> 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 NO<INF>X</INF> and SO<INF>2</INF> controls.
Table 9 describes the installed NO<INF>X</INF>, SO<INF>2</INF>, 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 NO<INF>X</INF> control at Unit 4 (table 10). DSI was not
evaluated for SO<INF>2</INF> control because, according to the State,
scrubber upgrades are more effective than DSI for incremental pollution
control; no further SO<INF>2</INF> 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
NO<INF>X</INF>, SO<INF>2</INF>, 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 NO<INF>X</INF>, SO<INF>2</INF>,
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 NO<INF>X</INF> 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 SO<INF>2</INF> emissions control on the coal-
fired boilers; no further SO<INF>2</INF> 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 SO<INF>2</INF> 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 NO<INF>X</INF>,
SO<INF>2</INF>, 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
NO<INF>X</INF> emissions (from approximately 900 tons/year to
approximately 600 tons/year), SO<INF>2</INF> 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, NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF>, SO<INF>2</INF>,
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 SO<INF>2</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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
NO<INF>X</INF> 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 NO<INF>X</INF>, SO<INF>2</INF>,
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 NO<INF>X</INF> 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 SO<INF>2</INF> 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 SO<INF>2</INF> 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
NO<INF>X</INF> emissions remained steady (at approximately 400 tons/
year), while SO<INF>2</INF> emissions consistently declined (from
approximately 1,800 tons/year to approximately 700 tons/year). For the
D Boiler, NO<INF>X</INF> emissions also remained steady (at
approximately 600 tons/year), while SO<INF>2</INF> emissions
consistently declined (from approximately 3,500 tons/year to
approximately 1,000 tons/year). Wyoming stated that NO<INF>X</INF> and
SO<INF>2</INF> 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 NO<INF>X</INF> emissions control
on the nine compressor engines (table 21). For further SO<INF>2</INF>
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 NO<INF>X</INF> emissions controls on the nine compressor engines to
be three to five years after the SIP is approved. For SO<INF>2</INF>
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 SO<INF>2</INF> 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 SO<INF>2</INF> 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 SO<INF>2</INF> emissions from the
incinerator are expected to continue to decrease. The figures show
consistent declines in NO<INF>X</INF> emissions between 2016-2020 for
all compressor engines except EC8, which showed a slight increase.
Overall, Wyoming concluded that NO<INF>X</INF> and SO<INF>2</INF>
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
SO<INF>2</INF>, NO<INF>X</INF>, and PM<INF>10</INF>. Emissions from
Granger may affect the visibility in two Class I areas in Wyoming
(table 32).
Table 23 describes the installed NO<INF>X</INF>, SO<INF>2</INF>,
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 NO<INF>X</INF>
control (table 24), trona injection prior to ESP for further
SO<INF>2</INF> 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.
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[[Page 63053]]

Table 26--Summary of Granger PM Cost Analysis
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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 SO<INF>2</INF> 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 NO<INF>X</INF>,
SO<INF>2</INF>, and PM<INF>10</INF> 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 NO<INF>X</INF>,
SO<INF>2</INF>, and PM emission limits \94\ and emissions trends for
the boilers over five years (2016-2020). The figures show that boiler
UIN-14 NO<INF>X</INF> emissions dropped (from approximately 630 tons/
year to approximately 120 tons/year), as did SO<INF>2</INF> 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 NO<INF>X</INF>
(from approximately 675 tons/year to approximately 150 tons/year),
SO<INF>2</INF> (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 NO<INF>X</INF>, SO<INF>2</INF>, 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.
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\94\ Wyoming Permit Number 0021849. Emission limits for each
boiler, UIN-14 and UIN-15, are 985.5 tons/year for NO<INF>X</INF>,
284.7 tons/year for SO<INF>2</INF>, and 118.3 tons/year for PM.
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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\
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\95\ This facility is addressed at pages 178-82 and appendix J
of the Wyoming 2022 SIP submission.
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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
(CO<INF>2</INF>), hydrogen sulfide (H<INF>2</INF>S), 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).
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\96\ Train 1 was decommissioned and decoupled from Train 2.
Wyoming 2022 SIP submission at 178.
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Relying on information submitted by the facility (attached as
appendix J to the Wyoming 2022 SIP submission), the State evaluated wet
scrubbers for SO<INF>2</INF> emissions control on Trains 2 and 3 (table
27).\97\ It noted that the Lost Cabin Gas Plant is currently
controlling SO<INF>2</INF> 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 NO<INF>X</INF> and PM
emissions control measures, reasoning that NO<INF>X</INF> and PM
account for a small fraction of total emissions from the facility.\99\
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\97\ Flaring emissions were not included in the SO<INF>2</INF>
control analysis because SO<INF>2</INF> 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 SO<INF>2</INF> emissions, including addition
of a sulfur tank vapor thermal oxidized in 2017, improved tail gas
unit cooling on Train 2, addition of a flare H<INF>2</INF>S 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 NO<INF>X</INF> and
PM<INF>10</INF> 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 SO<INF>2</INF>
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 SO<INF>2</INF> emissions trends for Trains 2 and 3
over five years (2016-2020). The figures show that SO<INF>2</INF>
emissions from Train 2 consistently increased (from approximately 125
tons/year to approximately 275 tons/year), while SO<INF>2</INF>
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 SO<INF>2</INF> emissions from 2014
to 2018 of 1,553.6 tons/year (which represents total SO<INF>2</INF>
actual emissions, including those from flaring), as well as a permitted
allowable SO<INF>2</INF> emission reduction of 389.6 tons/year.
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\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.
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Wyoming concluded that installing wet scrubbers for SO<INF>2</INF>
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 SO<INF>2</INF> emissions to decrease year-over-year as
production continues to decline at an approximate rate of 4 to 5
percent, with overall SO<INF>2</INF> 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
SO<INF>2</INF> 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

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