Home/Federal/Federal Register/2025-17041

Proposed Rule2025-17041

Air Plan Approval; Arkansas; Regional Haze State Implementation Plan for the Second Implementation Period

Primary source

Metadata and text below are from the Federal Register, a public-domain U.S. government work. Always verify the official published version before relying on it for any legal matter.

Published

September 5, 2025

Issuing agencies

Environmental Protection Agency

Abstract

Pursuant to the Clean Air Act (CAA or the Act), the Environmental Protection Agency (EPA) is proposing to approve a State Implementation Plan (SIP) revision submitted by the State of Arkansas through the Division of Environmental Quality (DEQ) on August 8, 2022, and clarified by DEQ on July 29, 2025, as satisfying the requirements of the Act and the EPA's Regional Haze Rule (RHR) for visibility protection in mandatory Class I Federal areas (Class I areas) for the program's second implementation period. Arkansas' SIP submission addresses the requirement that states must revise their long-term strategies for making reasonable progress to prevent any future and remedy any existing man-made visibility impairment in the Class I areas. The EPA is taking this action pursuant to sections 110 and 169A of the CAA.

Full Text

<html>
<head>
<title>Federal Register, Volume 90 Issue 170 (Friday, September 5, 2025)</title>
</head>
<body><pre>
[Federal Register Volume 90, Number 170 (Friday, September 5, 2025)]
[Proposed Rules]
[Pages 43030-43067]
From the Federal Register Online via the Government Publishing Office [<a href="http://www.gpo.gov">www.gpo.gov</a>]
[FR Doc No: 2025-17041]

[[Page 43029]]

Vol. 90

Friday,

No. 170

September 5, 2025

Part II

Environmental Protection Agency

-----------------------------------------------------------------------

40 CFR Part 52

Air Plan Approval; Arkansas; Regional Haze State Implementation Plan
for the Second Implementation Period; Proposed Rule

Federal Register / Vol. 90, No. 170 / Friday, September 5, 2025 /
Proposed Rules

[[Page 43030]]

-----------------------------------------------------------------------

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 52

[EPA-R06-OAR-2022-0735; FRL-9405-01-R6]

Air Plan Approval; Arkansas; Regional Haze State Implementation
Plan for the Second Implementation Period

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

-----------------------------------------------------------------------

SUMMARY: Pursuant to the Clean Air Act (CAA or the Act), the
Environmental Protection Agency (EPA) is proposing to approve a State
Implementation Plan (SIP) revision submitted by the State of Arkansas
through the Division of Environmental Quality (DEQ) on August 8, 2022,
and clarified by DEQ on July 29, 2025, as satisfying the requirements
of the Act and the EPA's Regional Haze Rule (RHR) for visibility
protection in mandatory Class I Federal areas (Class I areas) for the
program's second implementation period. Arkansas' SIP submission
addresses the requirement that states must revise their long-term
strategies for making reasonable progress to prevent any future and
remedy any existing man-made visibility impairment in the Class I
areas. The EPA is taking this action pursuant to sections 110 and 169A
of the CAA.

DATES: Written comments must be received on or before October 6, 2025.

ADDRESSES: Submit comments, identified by Docket No. EPA-R06-OAR-2022-
0735, at <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="http://Regulations.gov">Regulations.gov</a>. The EPA may publish any comment received
to its public docket. Do not submit electronically any information that
is considered 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 with
multimedia submissions and should include all discussion points
desired. The EPA will generally not consider comments or their contents
located outside of the primary submission (i.e., on the web, cloud, or
other file sharing system). For additional submission methods, please
contact James E. Grady, 214-665-6745, <a href="/cdn-cgi/l/email-protection#46213427223f682c272b23350623362768212930">[email&#160;protected]</a>. For the full
EPA public comment policy, information about CBI or multimedia
submissions, and general guidance on making effective comments, please
visit <a href="https://www.epa.gov/dockets/commenting-epa-dockets">https://www.epa.gov/dockets/commenting-epa-dockets</a>.
Docket: The index to the docket for this action is available
electronically at <a href="http://www.regulations.gov">www.regulations.gov</a>. While all documents in the
docket are listed in the index, some information may not be publicly
available due to docket file size restrictions or content (e.g., CBI).

FOR FURTHER INFORMATION CONTACT: James E. Grady, EPA Region 6 Office,
Regional Haze and SO<INF>2</INF> Section, (214) 665-6745;
<a href="/cdn-cgi/l/email-protection#2146534045580f4b404c4452614451400f464e57">[email&#160;protected]</a>. We encourage the public to submit comments via
<a href="https://www.regulations.gov">https://www.regulations.gov</a>. Please call or email Mr. Grady or call Mr.
Bill Deese at 214-665-7253 if you need alternative access to material
indexed but not provided in the docket.

SUPPLEMENTARY INFORMATION: Throughout this document ``we,'' ``us,'' and
``our'' mean the EPA.

Table of Contents

I. What action is the EPA proposing?
II. Background and Requirements for Regional Haze Plans
A. Regional Haze Background
B. Roles of Agencies in Addressing Regional Haze
C. Previous Actions on Arkansas Regional Haze
D. Arkansas Regional Haze Planning Period II SIP Submittal
III. Requirements for Regional Haze Plans for the Second
Implementation Period
A. Long-Term Strategy
B. RPGs
C. Monitoring Strategy and Other State Implementation Plan
Requirements
D. Requirements for Periodic Reports Describing Progress Toward
the RPGs
E. Requirements for State and FLM Coordination
IV. EPA's Evaluation of Arkansas' Regional Haze Planning Period II
SIP Submittal
A. Identification of Class I Areas
1. Arkansas Class I Areas
2. Other State Class I Areas Affected by Arkansas Emissions
B. Calculations of Baseline, Current, and Natural Visibility
Conditions; Progress to Date; and the URP for Arkansas' Class I
Areas
C. Long-Term Strategy
1. EPA's Rationale To Evaluate the Long-Term Strategy
2. Source Selection Methodology
a. Key Pollutants and Source Categories
b. Area of Influence Analysis
3. Four Factor Analyses
a. Entergy White Bluff Power Plant
b. Entergy Independence Power Plant
c. FutureFuel Chemical Company
d. Domtar Ashdown Mill
e. SWEPCO Flint Creek Power Plant
f. Conclusion
4. Consultation Requirement With States
5. Documentation Requirement for Emission Reduction Measures
6. Five Additional Factors for Long-Term Strategy
D. RPGs
E. Reasonably Attributable Visibility Impairment (RAVI)
F. Monitoring Strategy and Other Implementation Plan
Requirements
G. Requirements for Periodic Reports Describing Progress Toward
the RPGs
H. State and FLM Coordination Requirements
V. Proposed Action
VI. Incorporation by Reference
VII. Statutory and Executive Order Reviews

I. What action is the EPA proposing?

On August 8, 2022, DEQ submitted its 2022 Arkansas Regional Haze
Planning Period II SIP submission to the EPA to satisfy the regional
haze program requirements for the second implementation period. The EPA
is proposing to find that the Arkansas regional haze SIP submission for
the second implementation period meets the applicable statutory and
regulatory requirements and, therefore, is proposing to approve
Arkansas' submission into its SIP. Specifically, the EPA is proposing
to approve Arkansas' 2022 SIP submission, clarified by DEQ on July 29,
2025, as satisfying the requirements of (1) 40 CFR 51.308(f)(1):
calculations of baseline, current, and natural visibility conditions,
progress to date, and the uniform rate of progress (URP); (2) 40 CFR
51.308(f)(2): long-term strategy; (3) 40 CFR 51.308(f)(3): reasonable
progress goals (RPGs); (4) 40 CFR 51.308(f)(4): reasonably attributable
visibility impairment (RAVI); (5) 40 CFR 51.308(f)(5) and 40 CFR
51.308(g)(1) through (5): progress report requirements; (6) 40 CFR
51.308(f)(6): monitoring strategy and other implementation plan
requirements; and (7) 40 CFR 51.308(i): Federal Land Manager (FLM)
consultation. The State's submission can be found in the docket of this
action.

II. Background and Requirements for Regional Haze Plans

A detailed history and background of the regional haze program is
provided in multiple prior EPA proposal actions.\1\ For additional
background, please refer to Section III, ``Overview of Visibility
Protection Statutory Authority, Regulation, and Implementation'' of the
2017 RHR revisions titled, ``Protection of Visibility: Amendments to
Requirements for State Plans.'' \2\ The following is an abbreviated
history and background of the regional haze

[[Page 43031]]

program and 2017 RHR as it applies to the current action.
---------------------------------------------------------------------------

\1\ See 90 FR 13516 (March 24, 2025).
\2\ See 82 FR 3078 (January 10, 2017) located at <a href="https://www.federalregister.gov/documents/2017/01/10/2017-00268/protection-of-visibility-amendments-to-requirements-for-State-plans#h-16">https://www.federalregister.gov/documents/2017/01/10/2017-00268/protection-of-visibility-amendments-to-requirements-for-State-plans#h-16</a>.
---------------------------------------------------------------------------

A. Regional Haze Background

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.\3\ CAA
section 169A(a)(1) 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.''
---------------------------------------------------------------------------

\3\ CAA 169A establishes visibility protection for mandatory
Class I Federal areas and CAA 162(a) statutorily designates these
areas as consisting of all national parks exceeding 6,000 acres, all
national wilderness areas and memorial parks exceeding 5,000 acres,
and all international parks that were in existence on August 7,
1977. 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.
---------------------------------------------------------------------------

Regional haze is visibility impairment that is produced by a
multitude of anthropogenic sources and activities which are located
across a broad geographic area that emit pollutants that impair
visibility. Visibility impairing pollutants predominantly include fine
particulates (PM<INF>2.5</INF>) and their precursors but also coarse
mass.\4\ (PM)<INF>2.5</INF> particles consist of sulfates
(SO<INF>4</INF>2-), nitrates (NO<INF>3</INF>\-\), organic
carbon, elemental carbon, and soil dust. Precursors that react in the
atmosphere to form PM<INF>2.5</INF> consist of 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>).
PM<INF>2.5</INF> impairs visibility by scattering and absorbing light,
which reduces the perception of clarity and color, as well as visible
distance.\5\
---------------------------------------------------------------------------

\4\ Particles greater than PM<INF>2.5</INF> but less than
PM<INF>10</INF> are referred to as coarse mass.
\5\ 40 CFR 51.301 states that 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 1 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 formula for the deciview
is dv=10*ln (b\ext\/10 Mm-1).
---------------------------------------------------------------------------

To address regional haze visibility impairment, the 1999 RHR
established an iterative planning process to implement CAA section
169(A)(b)(2) that requires a state in which any Class I area is located
or for a state ``the emissions from which may reasonably be anticipated
to cause or contribute to any impairment of visibility'' in a Class I
area to each periodically submit comprehensive SIP revisions to address
such impairment.\6\ On January 10, 2017, the EPA promulgated revisions
to the RHR, that apply for the second and subsequent implementation
periods. See 82 FR 3078 (January 10, 2017). 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).
---------------------------------------------------------------------------

\6\ 40 CFR 51.308(d), (f) 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.'' See also 40 CFR
51.308(b), (f) which establishes submission dates for iterative
regional haze SIP revisions; 64 FR 35714, 35768 (July 1, 1999).
---------------------------------------------------------------------------

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. In order 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),\7\
which include representation from state and tribal governments, the
EPA, and Federal Land Managers, 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.
---------------------------------------------------------------------------

\7\ RPOs are sometimes also referred to as ``multi-
jurisdictional organizations,'' or MJOs. For the purposes of this
notice, the terms RPO and MJO are synonymous.
---------------------------------------------------------------------------

The Central Regional Air Planning Association (CENRAP), one of the
five RPOs referred to, was a collaborative effort of tribal
governments, state governments and various federal agencies
representing the central states for the first planning period. Due to
lack of funding in 2011, CENRAP subsequently ceased to function, and
Arkansas now communicates through the Central States Air Resource
Agencies (CenSARA) with the other states that were part of CENRAP. The
CenSARA region includes the states of Arkansas, Iowa, Kansas,
Louisiana, Missouri, Nebraska, Oklahoma, Texas, and the local agencies
within these states. CenSARA promotes the exchange of ideas,
information, knowledge, experience and data, and develops strategies
for addressing air quality issues that may affect the CenSARA states.
CenSARA also conducts research and undertakes other activities as
necessary to provide CenSARA states with information to support the
development of sound air pollution control policy.

C. Previous Actions on Arkansas Regional Haze

The State of Arkansas submitted a regional haze SIP on September 9,
2008, intended to address the requirements of the first regional haze
implementation period. On August 3, 2010, the State submitted a SIP
revision with mostly non-substantive changes that addressed Arkansas
Pollution Control and Ecology Commission (APCEC) Regulation 19, Chapter
15. On September 27, 2011, the State submitted a supplemental letter
that clarified several aspects of the 2008 submittal. The EPA
collectively refers to the original 2008 submittal, the supplemental
letter, and the 2010 revision together as the 2008 Arkansas Regional
Haze SIP. On March 12, 2012, the EPA partially approved and partially
disapproved the 2008 Arkansas Regional Haze SIP.\8\ Specifically, the
EPA disapproved certain BART compliance dates; the State's
identification of certain BART-eligible sources and subject-to-BART
sources; certain BART determinations for NO<INF>X</INF>,
SO<INF>2</INF>, and PM<INF>10</INF>; the State's reasonable progress
analysis; and a portion of the State's long-term strategy. The
remaining provisions of the 2008 Arkansas Regional Haze SIP were
approved. The final partial disapproval started a 2-year FIP clock that
obligated the EPA to either approve a SIP revision and/or promulgate a
FIP to address the disapproved portions of the action.\9\ Because a SIP
revision addressing the deficiencies was not approved and the FIP clock
expired in April 2014, the EPA promulgated a FIP (the Arkansas

[[Page 43032]]

Regional Haze FIP) on September 27, 2016, to address the disapproved
portions of the 2008 Arkansas Regional Haze SIP.\10\ Among other
things, the FIP established SO<INF>2</INF>, NO<INF>X</INF>, and
PM<INF>10</INF> emission limits under the BART requirements for nine
units at six facilities: Arkansas Electric Cooperative Corporation
(AECC) Carl E. Bailey Plant Unit 1 Boiler; AECC John L. McClellan Plant
Unit 1 Boiler; American Electric Power/Southwestern Electric Power
Company (AEP/SWEPCO) Flint Creek Plant Boiler No. 1; Entergy Lake
Catherine Plant Unit 4 Boiler; Entergy White Bluff Plant Units 1 and 2
Boilers and the Auxiliary Boiler; and the Domtar Ashdown Mill Power
Boilers No. 1 and 2. The FIP also established SO<INF>2</INF> and
NO<INF>X</INF> emission limits under the reasonable progress
requirements for the Entergy Independence Plant Units 1 and 2.
---------------------------------------------------------------------------

\8\ 77 FR 14604 (March 12, 2012).
\9\ Under CAA section 110(c), the EPA is required to promulgate
a FIP within 2 years of the effective date of a finding that a state
has failed to make a required SIP submission or has made an
incomplete submission, or of the effective date that the EPA
disapproves a SIP in whole or in part. The FIP requirement is
terminated only if a state submits a SIP, and the EPA approves that
SIP as meeting applicable CAA requirements before promulgating a
FIP.
\10\ 81 FR 66332 (September 27,2016) as corrected on October 4,
2016 (81 FR 68319).
---------------------------------------------------------------------------

Following petitions for reconsideration submitted by the State,
industry, and ratepayers, on April 25, 2017, the EPA issued a partial
administrative stay of the effectiveness of the FIP for 90 days.\11\
During that period, Arkansas started to address the disapproved
portions of its regional haze SIP through several phases of SIP
revisions. On July 12, 2017, the State submitted its proposed Phase I
SIP revision (the Arkansas Regional Haze NO<INF>X</INF> SIP revision)
to address NO<INF>X</INF> BART requirements for all electric generating
units (EGUs) and the reasonable progress requirements with respect to
NO<INF>X</INF>. The Arkansas Regional Haze NO<INF>X</INF> SIP submittal
replaced all source-specific NO<INF>X</INF> BART determinations for
EGUs established in the FIP with reliance upon the Cross-State Air
Pollution Rule (CSAPR) emissions trading program for ozone
(O<INF>3</INF>) season NO<INF>X</INF> as an alternative to
NO<INF>X</INF> BART. The SIP submittal addressed the NO<INF>X</INF>
BART requirements for Bailey Unit 1, McClellan Unit 1, Flint Creek
Boiler No. 1, Lake Catherine Unit 4; White Bluff Units 1 and 2, and the
Auxiliary Boiler. The revision did not address NO<INF>X</INF> BART for
Domtar Ashdown Mill Power Boilers No. 1 and 2. On February 12, 2018, we
took final action to approve the Arkansas Regional Haze NO<INF>X</INF>
SIP revision and to withdraw the corresponding NO<INF>X</INF>
provisions of the FIP.\12\
---------------------------------------------------------------------------

\11\ 82 FR 18994 (April 25, 2017).
\12\ See 83 FR 5927 (February 12, 2018) final action. See also
82 FR 42627 (September 11, 2017) for the proposed approval.
---------------------------------------------------------------------------

The State submitted its Phase II SIP revision (the Arkansas
Regional Haze SO<INF>2</INF> and PM SIP revision) on August 8, 2018,
that addressed most of the remaining parts of the 2008 Arkansas
Regional Haze SIP that were disapproved in the March 12, 2012, action.
The August 8, 2018, SIP submittal was intended to replace the federal
SO<INF>2</INF> and PM<INF>10</INF> BART determinations as well as the
reasonable progress determinations established in the FIP with the
State's own determinations. Specifically, the SIP revision addressed
the applicable SO<INF>2</INF> and PM<INF>10</INF> BART requirements for
Bailey Unit 1; SO<INF>2</INF> and PM<INF>10</INF> BART requirements for
McClellan Unit 1; SO<INF>2</INF> BART requirements for Flint Creek
Boiler No. 1; SO<INF>2</INF> BART requirements for White Bluff Units 1
and 2; SO<INF>2</INF>, NO<INF>X</INF>, and PM<INF>10</INF> BART
requirements for the White Bluff Auxiliary Boiler; and included a
requirement that Lake Catherine Unit 4 not burn fuel oil until
SO<INF>2</INF> and PM BART determinations for the fuel oil firing
scenario are approved into the SIP by the EPA. The submittal addressed
the reasonable progress requirements with respect to SO<INF>2</INF> and
PM<INF>10</INF> emissions for Independence Units 1 and 2 and all other
sources in Arkansas. In addition, it established revised reasonable
progress goals (RPGs) for Arkansas' two Class I areas and revised the
State's long-term strategy provisions. The submittal did not address
BART and associated long-term strategy requirements for Domtar Ashdown
Mill Power Boilers No. 1 and 2. On September 27, 2019, we took final
action to approve a portion of the Arkansas Regional Haze
SO<INF>2</INF> and PM SIP revision and to withdraw the corresponding
parts of the FIP.\13\
---------------------------------------------------------------------------

\13\ See 84 FR 51033 (September 27, 2019) for final approval.
See also 83 FR 62204 (November 30, 2018) for proposed action and 84
FR 51056 (September 27, 2019) for the final FIP withdrawal action.
---------------------------------------------------------------------------

On August 13, 2019, DEQ submitted the Arkansas Regional Haze Phase
III SIP (Phase III SIP revision). The submittal contained a BART
alternative measure to address BART and the associated long-term
strategy requirements for two subject-to-BART sources (Power Boilers
No. 1 and 2) at the Domtar Ashdown Mill located in Ashdown, Arkansas.
On March 22, 2021, we withdrew the remaining portions of the 2016 FIP
and in a separate action approved the Arkansas Regional Haze Phase III
SIP revision as meeting the applicable regional haze BART alternative
provisions set forth in 40 CFR 51.308(e)(2) for the Domtar Ashdown
Mill.\14\ We also approved the reasonable progress components under 40
CFR 51.308(d)(1) relating to Domtar Power Boilers No. 1 and 2. With the
approved Phase III SIP revision addressing BART alternative
requirements and the previously approved Phase I and II SIP revision
requirements, Arkansas addressed all reasonable progress requirements
under section 51.308(d)(1) that were previously disapproved and
achieved a fully approved regional haze SIP for the first
implementation period.
---------------------------------------------------------------------------

\14\ See 86 FR 15104 (March 22, 2021) final action (effective
April 21, 2021). See also 85 FR 14847 (March 16, 2020) for proposed
approval.
---------------------------------------------------------------------------

Pursuant to 40 CFR 51.308(g), Arkansas was responsible for
submitting a 5-year progress report as a SIP revision for the first
implementation period, which it did on June 2, 2015. DEQ was also
required to include a determination of adequacy of the regional haze
SIP for the first implementation period as required under 40 CFR
51.308(h), at the same time as the progress report. On October 1, 2019,
the EPA approved the progress report into the Arkansas SIP as meeting
the applicable regional haze requirements set forth in section
51.308(g), and also approved the State's determination of adequacy
under 40 CFR 51.308(h) that no additional controls were needed.\15\
---------------------------------------------------------------------------

\15\ 84 FR 51986 (October 1, 2019).
---------------------------------------------------------------------------

D. Arkansas Regional Haze Planning Period II SIP Submittal

On August 8, 2022, DEQ submitted to the EPA the 2022 Arkansas
Regional Haze Planning Period II SIP revision (2022 Planning Period II
SIP) which is the subject of this action. It addresses the State's
regional haze obligations for the second implementation period (2018-
2028) under CAA sections 169A and 169B and the RHR at 40 CFR 51.308(f)
and (i). The 2022 Planning Period II SIP submittal contains: the
State's long-term strategy which includes analyses by DEQ and CenSARA
and assesses potential controls needed for selected sources to meet
reasonable progress, an assessment of progress made since the first
implementation period in reducing emissions of visibility impairing
pollutants, and the visibility improvement progress at its Class I
areas and nearby Class I areas. On July 29, 2025, DEQ submitted a
letter \16\ clarifying that its 2022 Planning Period II SIP submittal
demonstrates reasonable progress under the RHR and CAA without the
Administrative Order (LIS No. 22-084) for Entergy Independence. DEQ
requested in the letter for EPA to act on its submittal without the
inclusion of that Administrative Order.

[[Page 43033]]

This action provides EPA's evaluation of the 2022 SIP submittal which
we are proposing to approve as meeting the requirements of the CAA and
RHR for the second implementation period of the regional haze program.
---------------------------------------------------------------------------

\16\ See letter sent to EPA from DEQ signed by Secretary Khoury
(dated July 28, 2025) and included in the docket of this action.
---------------------------------------------------------------------------

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

A. Long-Term Strategy

Under the CAA and 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.
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. See CAA 169A(b)(2)(B). To this end, 40 CFR 51.308(f)
lays out the process by which states determine what constitutes their
long-term strategies, with the order of the requirements in 40 CFR
51.308(f)(1) through (f)(3) generally mirroring the order of the steps
in the reasonable progress analysis \17\ and (f)(4) through (f)(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
calculate the baseline (five-year average period of 2000-2004),
current, and natural visibility conditions (i.e., visibility conditions
without anthropogenic visibility impairment) for that area, as well as
the visibility improvement made to date and the uniform rate of
progress (URP). The URP is 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 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. 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, the
RHR at 40 CFR 51.308(f)(2)(iv) separately provides five ``additional
factors'' \18\ that states must consider in developing their long-term
strategies. 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.
---------------------------------------------------------------------------

\17\ The EPA explained in the 2017 RHR Revision 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.'' See 82 FR 3078, 3091 (January 10, 2017).
\18\ The five ``additional factors'' for consideration in 40 CFR
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.
---------------------------------------------------------------------------

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.\19\ This is accomplished
by considering the four reasonable progress 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.'' See
CAA 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 in order to satisfy the CAA's
reasonable progress mandate.'' \20\ Thus, for each source selected for
four-factor analysis, a state must consider a ``meaningful set'' of
technically feasible control options for reducing emissions of
visibility impairing pollutants.\21\ 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.\22\ Ultimately,
while states have discretion to reasonably weigh the factors and to
determine what level of control is needed, 40 CFR 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.''
---------------------------------------------------------------------------

\19\ CAA 169A(g)(1) provides that, ``in determining reasonable
progress there shall be taken into consideration'' the four
statutory factors. 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 planning period.
\20\ 82 FR 3078, 3091 (January 10, 2017).
\21\ ``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, the 2017 RHR Revision (82 FR
3078, 3088) explains that 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.''
\22\ See, e.g., Responses to Comments on Protection of
Visibility: Amendments to Requirements for State Plans; Proposed
Rule (81 FR 26942, May 4, 2016) (December 2016), Docket Number EPA-
HQ-OAR-2015-0531, U.S. Environmental Protection Agency at 186.
---------------------------------------------------------------------------

As explained previously, 40 CFR 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 40 CFR 51.308(f)(2), measures that are necessary to make
reasonable progress toward the national visibility goal must be
included in a state's long-term strategy and in its SIP.\23\ If the
outcome

[[Page 43034]]

of a four-factor analysis is that an emission reduction measure is
necessary to make reasonable progress toward remedying existing or
preventing future anthropogenic visibility impairment, that measure
must be included in the SIP.
---------------------------------------------------------------------------

\23\ 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. 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).
---------------------------------------------------------------------------

The characterization of information on each of the factors is also
subject to the documentation requirement in 40 CFR 51.308(f)(2)(iii).
The reasonable progress analysis is a technically complex exercise and
also a flexible one that provides states with bounded discretion to
design and implement approaches appropriate to their circumstances.
Given this flexibility, 40 CFR 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. Additionally, the RHR at 40 CFR 51.3108(f)(2)(iv)
separately provides five ``additional factors'' \24\ 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.
---------------------------------------------------------------------------

\24\ The five ``additional factors'' for consideration in
section 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, 40 CFR 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. 40 CFR
51.308(f)(2)(ii)(A) requires that 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. Additionally, 40 CFR
51.308(f)(2)(ii)(B) requires 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. 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, 40 CFR 51.308(f)(2)(ii)(C) requires that a
state must document in its SIP the actions taken to resolve the
disagreement. Under all circumstances, a state must document in its SIP
submission all substantive consultations with other contributing
states.

B. RPGs

RPGs ``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.'' \25\ 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
toward the statutory goal of preventing any future and remedying any
existing anthropogenic visibility impairment in the Class I areas. See
40 CFR 51.308(f)(2) to (3). While states are not legally obligated to
achieve the visibility conditions described in their RPGs, 40 CFR
51.308(f)(3)(i) requires that ``the long-term strategy and the RPGs
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.'' RPGs may also serve
as a metric for assessing the amount of progress a state is making
toward the national visibility goal. To support this approach, the RHR
requires states with Class I areas to compare the 2028 RPG on the most
impaired days to the corresponding 2028 point on the URP line
(representing visibility conditions in 2028 if visibility were to
improve at a linear rate from conditions in the 2000-2004 baseline
period to 2064 natural visibility conditions). If the 2028 RPG on the
most impaired days is above the 2028 URP point (i.e., if visibility
conditions are improving slower 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
section 51.308(f)(2)(i), that there are no additional emission
reduction measures for anthropogenic sources or groups of sources in
the state that would be reasonable to include in the long-term
strategy. See 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 slower than
the URP must 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.''
---------------------------------------------------------------------------

\25\ 82 FR 3078, 3091 (January 10, 2017).
---------------------------------------------------------------------------

C. 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 subsection 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. 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. See 40 CFR 51.308(f)(6), (f)(6)(i), and (f)(6)(iv).
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, as well as a statewide inventory documenting
such emissions. See 40 CFR 51.308(f)(6)(ii), (iii) and (v). 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. See 40 CFR 51.308(f)(6)(vi).

[[Page 43035]]

D. Requirements for Periodic Reports Describing Progress Toward the
RPGs

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.\26\ To this end, every state's SIP revision for the second
implementation period is required to assess changes in visibility
conditions and 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. See 40
CFR 51.308(g)(1) and (2).
---------------------------------------------------------------------------

\26\ 81 FR 26942, 26950 (May 4, 2016); 82 FR 3078, 3119 (January
10, 2017).
---------------------------------------------------------------------------

E. Requirements for State and FLM 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; pursuant to that consultation, the state must
include a summary of the FLM conclusions and recommendations in the
notice to the public. Consistent with this statutory requirement, 40
CFR 51.308(i) provides the requirements for State and FLM coordination.
Specifically, 40 CFR 51.308(i)(2) requires that states must ``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.'' In order 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. See
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, 5-year progress reports, and the implementation of
other programs having the potential to contribute to impairment of
visibility in Class I areas. See 40 CFR 51.308(i)(4).

IV. EPA's Evaluation of Arkansas' Regional Haze Planning Period II SIP
Submittal

Inthis section of this document, we describe Arkansas' 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 a state in which any Class I
area is located or for a state ``the emissions from which may
reasonably be anticipated to cause or contribute to any impairment of
visibility'' in a Class I area to each have a plan for making
reasonable progress toward the national visibility goal. The RHR
implements this statutory requirement at 40 CFR 51.308(f), which
provides that each state's plan ``must address regional haze in each
mandatory Class I Federal area located within the State and in each
mandatory Class I Federal area located outside the State that may be
affected by emissions from within the State,'' and (f)(2), which
requires each state's plan to include a long-term strategy that
addresses regional haze in such Class I areas.
The EPA concluded in the 1999 RHR that ``all states contain sources
whose emissions are reasonably anticipated to contribute to regional
haze in a Class I area,'' 64 FR 35721, and this determination was not
changed in the 2017 RHR. Critically, the statute and regulation both
require that the cause-or-contribute assessment consider all emissions
of visibility impairing pollutants from a state, as opposed to
emissions of a particular pollutant or emissions from a certain set of
sources.
1. Arkansas Class I Areas
To address 40 CFR 51.308(f), Arkansas identified two Class I areas
within its borders: the Caney Creek and Upper Buffalo Wilderness Areas.
Caney Creek Wilderness is located in Polk County, Arkansas, and covers
14,460 acres on the southern edge of the Ouachita National Forest and
protects a rugged portion of the Ouachita Mountains. The Caney Creek
Wilderness Area monitor (CACR1) is located at latitude 34.4544,
longitude -94.1429 in Polk County, Arkansas at an elevation of 683
meters (m) above mean sea level (MSL). Upper Buffalo Wilderness area,
located in Newton County, Arkansas, is an oak-hickory forest with
intermittent portions of shortleaf pine located in the Ozark National
Forest and offers 12,108 acres of boulder strewn and rugged scenery
along the Buffalo River. The Upper Buffalo Wilderness monitor (UPBU1)
is located 1 mile north of the U.S. Forest Service workstation near
Deer, AR at an elevation of 722 m above MSL.
2. Other State Class I Areas Affected by Arkansas Emissions
In addition to the two Class I areas in Arkansas, DEQ used an area
of influence analysis by Ramboll (see section IV.C.2.b for further
details) \27\ to identify Class I areas in and near the CenSARA region
that may be influenced by emissions from Arkansas. DEQ examined
distance-weighted residence time plots by Ramboll and applied a 0.05
percent threshold to the plots as a cutoff to identify areas of
influence. Based on the contour plot qualitative results,\28\ DEQ
identified the following four Class I areas for which emissions from
Arkansas sources may be reasonably anticipated to contribute to
visibility impairment: Hercules Glades Wilderness (Hercules Glades) in
Missouri; \29\ Mammoth Cave National Park (Mammoth Cave) in Kentucky;
\30\ Sipsey Wilderness (Sipsey) in Alabama; \31\ and Wichita Mountains
Wildlife Refuge (Wichita Mountains) in Oklahoma.\32\ In addition to the
Class I

[[Page 43036]]

areas DEQ identified using distance-weighted residence times, DEQ also
identified two additional Class I areas for which a particular source
within Arkansas may contribute to visibility impairment: Mingo National
Wildlife Refuge (Mingo) \33\ in Missouri was identified using the 2016
visibility impact surrogate (see section IV.C.2.b for further details)
and Shining Rock Wilderness (Shining Rock) \34\ in North Carolina was
identified through photochemical modeling. DEQ identified the Entergy
Independence Power Plant in Arkansas as meeting its threshold for a
reasonable progress analysis for Mingo in Missouri. The Visibility
Improvement State and Tribal Association of the Southeast (VISTAS) \35\
RPO also made a request of DEQ to perform a reasonable progress
analysis for the Entergy Independence Power Plant in Arkansas, as their
modeling showed impacts at Shining Rock in North Carolina. DEQ,
therefore, identified both Mingo and Shining Rock as Class I areas to
consider for its source selection. Mingo was included in the analysis
performed by Ramboll but Shining Rock in North Carolina was not
included since that Class I area is not in the CenSARA region or
adjacent to a CenSARA state. DEQ assessed state-by-state source
contributions to visibility impairment for the two Class I areas in
Arkansas (Caney Creek and Upper Buffalo) and also for the six Class I
areas in other states (Hercules Glades, Mammoth Cave, Mingo, Shining
Rock, Sipsey, and Wichita Mountains) affected by emissions from
Arkansas for the second planning period. DEQ also provided further
evaluation of the sources from these Class I areas in and outside
Arkansas by analyzing the key pollutants and then screening the main
sources contributing toward visibility impairment for possible emission
reduction controls. EPA provides our evaluation of DEQ's source
selection process \36\ and the overall long-term strategy \37\ for
these areas in section IV.C of this proposed action.
---------------------------------------------------------------------------

\27\ See area of influence report in Appendix B of 2022 Planning
Period II SIP submittal called 7AppB_Area of Influence Report
Prepared by Ramboll.pdf.
\28\ See All Trajectories Distance-Weighted Residence Times
contour plots for EWRT NO<INF>3</INF> and EWRT SO<INF>4</INF> for
the 20 percent Most Impaired Days in the 2022 Planning Period II
SIP: Figure III-10 for Hercules Glades; Figure III-20 for Mammoth
Cave; Figure III-29 for Mingo; Figure III-48 for Sipsey; and Figure
III-58 for Wichita Mountains. Note that air masses from Arkansas
were not within the 0.05 percent distance-weighted residence time
contour for Mingo on the most impaired days.
\29\ The Hercules Glades Wilderness Area located in southwestern
Missouri consists of 12,413 acres of open grasslands, forested
knobs, steep rocky hillsides, and narrow drainages. The area is
characterized by shallow, droughty soils and limestone outcrops. The
Hercules Glades monitor (HEGL1) is located at latitude 36.6137,
longitude -92.9220 in Missouri.
\30\ The Mammoth Cave National Park in south central Kentucky
consists of 51,303 acres in the Green River valley and contains the
world's longest known cave system. The Mammoth Cave monitor (MACA1)
is located at latitude 37.1317, longitude -86.1478 in Kentucky.
\31\ The Sipsey Wilderness consists of 12,646 acres in the
Bankhead National Forest. The Sipsey monitor (SIPS1) is located at
latitude 34.3433, longitude -87.3387 in Alabama.
\32\ The Wichita Mountains Wildlife Refuge in southwestern
Oklahoma consists of 8,900 acres of canyons and grasslands that
embrace the ancient Wichita Mountains. The Wichita Mountain monitor
(WIMO1) is located at latitude 34.7322, longitude -98.7129 Oklahoma.
\33\ The Mingo National Wildlife Refuge Wilderness Area in
southeastern Missouri consists of 7,730 acres of swamp, riparian
areas, and Ozark Plateau uplands. The Mingo monitor (MING1) is
located at latitude 36.9716, longitude -90.1432 in Missouri.
\34\ The Shining Rock Wilderness area consists of over 18,000
acres on the north side of the Pisgah Ledge in the Blue Ridge
Mountains in North Carolina. The Shining Rock monitor (SHRO1) is
located at latitude 35.3936, longitude -82.7743 in North Carolina.
\35\ VISTAS is responsible for convening and collaborating on
regional air quality analysis work necessary to support the
development of regional haze SIPs. It is made up of 10 states
(Alabama, Florida, Georgia, Kentucky, Mississippi, North Carolina,
South Carolina, Tennessee, Virginia, and West Virginia), the Eastern
Band of Cherokee Indians, and Knox County, Tennessee (representing
the 17 Southeastern local air agencies).
\36\ See source screening spreadsheet in Appendix C of 2022
Planning Period II SIP submittal called 7AppC_Arkansas Source
Screening Method Spreadsheet-v8.xlsx.
\37\ See 40 CFR 51.308(f)(2) for the long-term strategy
requirements. See also CAA 169A(b)(2)(B).
---------------------------------------------------------------------------

The EPA finds that DEQ has met the requirement in its 2022 Planning
Period II SIP submittal of identifying the Class I areas located both
within and outside Arkansas that may be affected by emissions from
within Arkansas.

B. Calculations of Baseline, Current, and Natural Visibility
Conditions; Progress to Date; and the URP for Arkansas' Class I Areas

Section 51.308(f)(1)(i) to (vi) requires DEQ to determine the
following for each Class I area located within Arkansas: (i) baseline
visibility conditions for the most impaired and clearest days, (ii)
natural visibility conditions for the most impaired and clearest days,
(iii) current visibility conditions for the most impaired and clearest
days, (iv) progress to date for the most impaired and clearest days,
(v) the differences between current visibility conditions and natural
visibility conditions, (vi) and the URP for each Class I area in the
state. 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. See 40 CFR 51.308(f)(1)(vi)(B).
DEQ reported the current visibility conditions and improvement
realized at Arkansas' Class I areas in its 2022 Planning Period II SIP
as required by 40 CFR 51.308(f)(1) and the 2018 Visibility Tracking
Guidance.\38\ DEQ relied on available IMPROVE monitoring data \39\ at
Caney Creek and Upper Buffalo Wilderness Areas and developed figures
showing visibility impairment trends. DEQ reported 2000-2019 annual
observed visibility data and 5-year rolling average data in deciviews
on the 20 percent clearest days and the 20 percent most impaired days
as compared to the glidepaths at these areas.\40\ DEQ also compared
charts of baseline (2000-2004), current (2015-2019),\41\ and natural
(2064) visibility conditions as measured by the IMPROVE monitors and
determined that current visibility (2015-2019) at each Class I area for
both the clearest and most impaired days has improved since the
baseline period (see Tables 1 and 2).\42\
---------------------------------------------------------------------------

\38\ See December 20, 2018, memo, ``Technical Guidance on
Tracking Visibility Progress for the Second Implementation Period of
the Regional Haze Program'' from Richard A. Wayland at the EPA
Office of Air Quality Planning and Standards, Research Triangle
Park. <a href="https://www.epa.gov/sites/default/files/2018-12/documents/technical_guidance_tracking_visibility_progress.pdf">https://www.epa.gov/sites/default/files/2018-12/documents/technical_guidance_tracking_visibility_progress.pdf</a>.
\39\ The Caney Creek IMPROVE monitor (CACR1) is located at
latitude 34.4544, longitude -94.1429 in Polk County, AR at an
elevation of 683 m above mean sea level (MSL). The Upper Buffalo
Wilderness IMPROVE monitor (UPBU1) is located 1 mile north of the
U.S. Forest Service workstation near Deer, AR at an elevation of 722
meters above MSL.
\40\ See Figures II-2 and II-3 (pages II-5 to 6) for visibility
progress at Caney Creek and Figures II-14 and II-15 (pages II-19 to
20) for visibility progress at Upper Buffalo in the 2022 Planning
Period II SIP.
\41\ The period for calculating ``current'' visibility
conditions is the most recent 5-year period for which data are
available.
\42\ See Tables II-1 and II-2 (page II-4) for Caney Creek and
Tables II-3 and II-4 (page II-18) for Upper Buffalo in the 2022
Planning Period II SIP for comparison of baseline, current, and
natural visibility conditions.

Table 1--Visibility at Arkansas Class I Areas for 20 Percent Clearest Days
----------------------------------------------------------------------------------------------------------------
Visibility (dv)
-----------------------------------------------------
Class I areas Baseline (2000- Current (2015- Natural conditions
2004) 2019) (2064)
----------------------------------------------------------------------------------------------------------------
Caney Creek Wilderness.................................... 11.24 7.79 4.23
Upper Buffalo Wilderness.................................. 11.71 8.17 4.18
----------------------------------------------------------------------------------------------------------------

[[Page 43037]]

Table 2--Visibility at Arkansas Class I Areas for 20 Percent Most Impaired Days
----------------------------------------------------------------------------------------------------------------
Visibility (dv)
-----------------------------------------------------
Class I areas Baseline (2000- Current (2015- Natural conditions
2004) 2019) (2064)
----------------------------------------------------------------------------------------------------------------
Caney Creek Wilderness.................................... 23.99 17.65 9.54
Upper Buffalo Wilderness.................................. 24.21 17.52 9.41
----------------------------------------------------------------------------------------------------------------

DEQ reported, for the most impaired and clearest days, the progress
made toward natural visibility conditions during the first planning
period from the baseline period (2000-2004) to the last 5-year average
from that period (2014-2018); and total progress made to date toward
natural visibility conditions from the baseline period (2000-2004) to
the current 5-year average period (2015-2019). The State also included
the visibility improvement that is still required at Caney Creek and
Upper Buffalo in order to meet natural conditions by 2064 (see Tables 3
and 4).

Table 3--Visibility Improvement Progress Toward Natural Visibility for 20 Percent Clearest Days at Arkansas'
Class I Areas
----------------------------------------------------------------------------------------------------------------
Additional progress
Progress during Total progress needed for natural
Class I areas planning period I * to date ** (dv) conditions [dagger]
(dv) (dv)
----------------------------------------------------------------------------------------------------------------
Caney Creek Wilderness.......................... 3.22 3.46 3.56
Upper Buffalo Wilderness........................ 3.51 3.54 3.99
----------------------------------------------------------------------------------------------------------------
* Difference between baseline (2000-2004) average conditions and 2014-2018 average conditions.
** Difference between baseline (2000-2004) average conditions and 2015-2019 average conditions.
[dagger] Difference between 2015-2019 average conditions and 2064 natural conditions.

Table 4--Visibility Improvement Progress Toward Natural Visibility for 20 Percent Most Impaired Days at
Arkansas' Class I Areas
----------------------------------------------------------------------------------------------------------------
Additional progress
Progress during Total progress needed for natural
Class I areas planning period I * to date ** (dv) conditions [dagger]
(dv) (dv)
----------------------------------------------------------------------------------------------------------------
Caney Creek Wilderness.......................... 5.70 6.34 8.11
Upper Buffalo Wilderness........................ 6.26 6.70 8.11
----------------------------------------------------------------------------------------------------------------
* Difference between baseline (2000-2004) average conditions and 2014-2018 average conditions.
** Difference between baseline (2000-2004) average conditions and 2015-2019 average conditions.
[dagger] Difference between 2015-2019 average conditions and 2064 natural conditions.

The URP is the uniform rate of visibility improvement (measured in
deciviews of improvement per year) that would need to be maintained
during each implementation period for the most impaired days in order
to attain natural visibility conditions by the end of 2064. The State
calculated the URP for Caney Creek and Upper Buffalo for the 20 percent
most impaired days, and developed linear glidepaths for each area
assuming a starting point of baseline visibility conditions in 2004 and
ending with natural conditions in 2064.\43\ The RHR allows states the
option to adjust the 2064 glidepath endpoints to account for both
international anthropogenic emissions and certain prescribed fire
impacts at each Class I area. In the EPA's September 2019 memo and
associated technical support document (EPA 2019 Memo and Modeling
TSD),\44\ the EPA used 2028 modeling results to quantify the
international anthropogenic and prescribed fire impacts \45\ at Class I
areas on the 20 percent most anthropogenically impaired days. This
linear tracking metric was used by the State to assess the amount of
progress toward visibility improvement over time in each Class I area
by comparing annual observed data and 5-year average visibility data to
the URP glidepath. Caney Creek's URP was revised to be -0.212 dv per
year based on an adjusted 2064 endpoint of 11.26 dv. Upper Buffalo's
URP was revised to be -0.206 dv per year based on an adjusted 2064
endpoint of 11.83 dv. The adjusted URP glidepath 2064 endpoints were
calculated by adding the contribution of international anthropogenic
emissions as modeled by EPA \46\ to the natural visibility conditions.
The total international anthropogenic contributions for Caney

[[Page 43038]]

Creek and Upper Buffalo Wilderness are 4.88 Mm-1 and 7.02
Mm-1, respectively. Table 5 shows the current 5-year rolling
average on the 20 percent most impaired days for 2015-2019 and the
adjusted 2028 URP value for the Arkansas Class I areas.
---------------------------------------------------------------------------

\43\ See Figures II-2 and II-14 in the 2022 Planning Period II
SIP for Caney Creek and Upper Buffalo's URP glidepaths on the 20
percent most impaired days.
\44\ See Memorandum titled, ``Availability of Modeling Data and
Associated Technical Support Document for the EPA's Updated 2028
Visibility Air Quality Modeling,'' from Richard A. Wayland, Director
of EPA's Air Quality Assessment Division, to EPA Regional Air
Division Directors (September 19, 2019). <a href="https://www.epa.gov/visibility/technical-support-document-epas-updated-2028-regional-haze-modeling">https://www.epa.gov/visibility/technical-support-document-epas-updated-2028-regional-haze-modeling</a>.
\45\ See EPA 2019 Modeling Memo (page 2, footnote 4). The
Regional Haze Rule also allows an adjustment of the glidepath
endpoint to account for certain prescribed fire impacts. Modeled
prescribed fire contributions were calculated by EPA, with results
presented in the modeling TSD. However, consistent with the focus of
the December 2018 Technical Guidance and the Administrator's
Regional Haze Roadmap, the glidepath adjustments presented only
include the international anthropogenic contributions. Additionally,
the prescribed fire impacts are relatively small (~0-5
Mm-1) compared to the international anthropogenic impacts
(~3-19 Mm-1). See the 2019 Modeling TSD at Table 5-1
(pages 44 and 52) for the impacts from prescribed fires at Caney
Creek (1.88 Mm-1) and at Upper Buffalo (3.68
Mm-1).
\46\ See EPA 2019 Modeling TSD, Table 5-2.

Table 5--Current Visibility Conditions and 2028 Adjusted URP Values for
20 Percent Most Impaired Days at Arkansas' Class I Areas
------------------------------------------------------------------------
Most current 2028 Adjusted URP
Class I areas (2015-2019) (dv) (dv)
------------------------------------------------------------------------
Caney Creek Wilderness............ 17.65 * 18.90
Upper Buffalo Wilderness.......... 17.52 ** 19.26
------------------------------------------------------------------------
* The unadjusted 2028 URP value at Caney Creek is 18.18 dv without
accounting for international anthropogenic and prescribed fire
contributions. See EPA 2019 Modeling TSD at 57, Table 5-2.
** The unadjusted 2028 URP value at Upper Buffalo is 18.32 dv without
accounting for international anthropogenic and prescribed fire
contributions. See EPA 2019 Modeling TSD at 64, Table 5-2.

The EPA is proposing to find that DEQ has met the requirements
under 40 CFR 51.308(f)(1) in the 2022 Planning Period II SIP submittal
for the two Class I areas located within Arkansas (the Caney Creek and
Upper Buffalo Wilderness areas) related to the calculations of
baseline, current, and natural visibility conditions for the most
impaired and clearest days; progress to date for the most impaired and
clearest days; differences between current and natural visibility
conditions; and the URP for the second implementation period.

C. Long-Term Strategy

Each state that has a Class I area within its borders or has
emissions that may affect visibility in a Class I area must develop a
long-term strategy for making reasonable progress toward the national
visibility goal. CAA 169A(b)(2)(B). The long-term strategy must include
the enforceable emissions limitations, compliance schedules, and other
measures that are necessary to make reasonable progress, as determined
pursuant to 51.308(f)(2)(i) through (iv). 40 CFR 51.308(f)(2). A
reasonable progress determination is based on applying the four
statutory 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. After considering the four
statutory factors, all measures that are determined to be necessary to
make reasonable progress must be in the long-term strategy. 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. The RHR provides states
flexibility in selecting sources, and to that end, section
51.308(f)(2)(i) requires States to provide a description of 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. In developing its long-term
strategy, a state must also consider the five additional factors in
section 51.308(f)(2)(iv). Each State must also document the technical
basis on which it is relying to determine the emission reduction
measures that are necessary to make reasonable progress in each
mandatory Class I area it affects. 40 CFR 51.308(f)(2)(iii). States may
rely on technical information developed by the RPOs of which they are
members to select sources for four-factor analysis and to conduct that
analysis, as well as to satisfy the documentation requirements under 40
CFR 51.308(f). Where an RPO has performed source selection and/or four-
factor analyses (or considered the five additional factors in 40 CFR
51.308(f)(2)(iv)) for its member states, those states may rely on the
RPO's analyses for the purpose of satisfying the requirements of 40 CFR
51.308(f)(2)(i) so long as the states have a reasonable basis to do so
and all state participants in the RPO process have approved the
technical analyses. 40 CFR 51.308(f)(2)(iii). States may also satisfy
the requirement of 40 CFR 51.308(f)(2)(ii) to engage in interstate
consultation with other states that have emissions that are reasonably
anticipated to contribute to visibility impairment in a given Class I
area under the auspices of intra- and inter-RPO engagement.
1. EPA's Rationale To Evaluate the Long-Term Strategy
In this section of this document, we summarize and evaluate
Arkansas' long-term strategy against the requirements of the CAA and
RHR for the second implementation period of the regional haze program.
As detailed further in sections IV.C.2 through 6 that follow, EPA is
proposing to approve Arkansas' long-term strategy under 40 CFR
51.308(f)(2), including the source selection methodology (see section
IV.C.2), the four factor analysis and determinations of the measures
necessary to make reasonable progress under section 51.308(f)(2)(i)
(see section IV.C.3); and other regional haze requirements for the
long-term strategy (51.308(f)(2)(ii) through (iv)) such as consultation
requirements (see section IV.C.4), documentation requirements (see
section IV.C.5), and analysis of the five additional factors (see
section IV.C.6).
In this proposed action, we note that it is the Agency's policy, as
announced in our recent approval of the West Virginia Regional Haze
SIP,\47\ that where visibility conditions for a Class I area impacted
by a State are below the 2028 URP and the State has also evaluated
potential control measures by considering the four statutory factors,
the State will have presumptively demonstrated reasonable progress for
the second planning period for that area. We acknowledge that this
reflects a change in policy as to how the URP should be used in the
evaluation of regional haze second planning period SIPs. However, we
find that this policy better aligns with the purpose of the statute and
RHR, which is achieving ``reasonable'' progress, not maximal progress,
toward Congress's natural visibility goal. We also note that we have
the discretion and authority to change policy.\48\
---------------------------------------------------------------------------

\47\ See EPA's final action for West Virginia's regional haze
SIP at 90 FR 29737 (July 7, 2025), and our notice of proposed
rulemaking at 90 FR 16478, 16483 (April 18, 2025) which describes
the policy. See also EPA's notice of proposed rulemaking for South
Dakota at 90 FR 20425 (May 14, 2025).
\48\ In FCC v. Fox Television Stations, Inc., the U.S. Supreme
Court plainly stated that an agency is free to change a prior policy
and ``need not demonstrate . . . that the reasons for the new policy
are better than the reasons for the old one; it suffices that the
new policy is permissible under the statute, that there are good
reasons for it, and that the agency believes it to be better.'' 566
U.S. 502, 515 (2009) (referencing Motor Vehicle Mfrs. Ass'n of
United States, Inc. v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29
(1983)). See also Perez v. Mortgage Bankers Assn., 135 S. Ct. 1199
(2015). However, the EPA believes that this policy aligns with the
purpose of the statute and RHR, which is achieving ``reasonable''
progress, not maximal progress, toward Congress' natural visibility
goal.

---------------------------------------------------------------------------

[[Page 43039]]

In developing the regulations required by CAA section 169A(b), we
established the concept of the URP for each Class I area. As previously
discussed, for each Class I area, there is a regulatory requirement to
compare the projected visibility impairment represented by the RPG at
the end of each planning period to the URP (e.g., in 2028 for the
second planning period).\49\ In the 2017 RHR Revisions, we also
addressed the role of the URP as it relates to a state's development of
its second planning period SIP.\50\ Specifically, in response to
comments suggesting that the URP should be considered a ``safe harbor''
and relieve states of any obligation to consider the four statutory
factors, we explained that the URP was not intended to be such a safe
harbor.\51\ Some commenters stated a desire for corresponding rule text
dealing with situations where RPGs are equal to or below the URP
glidepath. Several commenters stated that the URP glidepath should be a
``safe harbor,'' opining that states should be permitted to analyze
whether projected visibility conditions for the end of the
implementation period will be on or below the glidepath based on on-
the-way control measures, and that in such cases a four-factor analysis
should not be required.\52\ Other 2017 RHR comments indicated a similar
approach, such as ``a somewhat narrower entrance to a `safe harbor,'''
by suggesting that if current visibility conditions are already below
the end-of-planning-period point on the URP glidepath, a four-factor
analysis should not be required.\53\ We stated in our response that we
do not agree with either of these recommendations. The CAA requires
that each SIP revision contain long-term strategies for making
reasonable progress, and that in determining reasonable progress states
must consider the four statutory factors. Treating the URP as a safe
harbor would be inconsistent with the statutory requirement that states
assess the potential to make further reasonable progress towards
natural visibility goal in every implementation period.\54\
---------------------------------------------------------------------------

\49\ See 82 FR 3078, 3091-3092 (January 10, 2017). RPGs are a
regulatory construct that we developed to address statutory mandate
in section 169B(e)(1), which required our regulations to include
``criteria for measuring `reasonable progress' toward the national
goal.'' Under 40 CFR 51.308(f)(3)(ii), RPGs measure the progress
that is projected to be achieved by the control measures a state has
determined are necessary to make reasonable progress. Consistent
with the 1999 RHR, the RPGs are unenforceable, though they create a
benchmark that allows for analytical comparisons to the URP and mid-
implementation-period course corrections if necessary.
\50\ Id.
\51\ 82 FR 3099 (January 10, 2017).
\52\ Id.
\53\ Id.
\54\ Id.
---------------------------------------------------------------------------

Our policy is that as long as the visibility conditions, as
reflected in the projected 2028 RPGs, of the Class I areas impacted by
a state are below the 2028 URP values and the State evaluates the four
factors, the State has presumptively demonstrated that it has already
made reasonable progress for the second planning period for that
area.\55\ Indeed, we believe this policy also recognizes the
considerable improvements in visibility impairment that have been made
by a wide variety of state and federal programs in recent decades.
---------------------------------------------------------------------------

\55\ See EPA's final action for West Virginia's regional haze
SIP at 90 FR 29737 (July 7, 2025), and our notice of proposed
rulemaking at 90 FR 16478, 16483 (April 18, 2025) which describes
the policy.
---------------------------------------------------------------------------

Applying this policy in our evaluation of Arkansas' SIP submission
and as further detailed in the sections that follow, the EPA is
proposing to approve that the long-term strategy outlined in Arkansas'
2022 Planning Period II SIP submission is adequate to demonstrate
reasonable progress towards natural visibility at the Class I areas
impacted by emissions from Arkansas sources.
2. Source Selection Methodology
a. Key Pollutants and Source Categories
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. DEQ analyzed
key pollutants and source categories contributing toward visibility
impairment for the two Class I areas in Arkansas and for the Class I
areas in other states affected by emissions from Arkansas. DEQ's
selection of key pollutants and source categories for evaluation in its
reasonable progress analysis was based on examination of the
particulate species from anthropogenic emissions that dominate
visibility at the different Class I areas; relative contributions of
various sectors to the Arkansas emission inventory; and projected 2028
sector-based source apportionment results from EPA's modeling.\56\ DEQ
noted that this approach is consistent with the 2019 guidance which
provides that a state may focus on particulate species that contribute
the most to visibility impairment and then select only sources with
emissions of those dominant pollutants and their precursors.\57\
---------------------------------------------------------------------------

\56\ See page V-1 of the 2022 Planning Period II SIP.
\57\ See 2019 Guidance at 11.
---------------------------------------------------------------------------

DEQ relied on IMPROVE monitoring data at each Class I area and
developed figures showing annual visibility impairment trends from
2002-2019 tracked in deciviews and included the relative light
extinction compositions from contributing pollutant species for the
most impaired and clearest days. DEQ also developed figures showing
trends of selected daily light extinction data for 2019 with estimated
pollutant contributions corresponding to anthropogenic sources and
natural sources.\58\ The pollutant extinction compositions were made up
of varying amounts of ammonium sulfate, ammonium nitrate, coarse mass,
organic mass, elemental carbon, soil, and sea salt at each Class I
area. The 2002-2019 extinction data showed that visibility impairment
on the most impaired days at all of the identified Class I areas in and
outside of Arkansas were consistently dominated by ammonium sulfate,
ammonium nitrate, or both.\59\ In addition, the 2002-2019 data showed
that light-extinction on the most impaired days from ammonium nitrate
and ammonium sulfate was primarily attributable to anthropogenic
sources. Elemental carbon, which is primarily from anthropogenic
sources, makes up a small contribution to visibility impairment at the
Class I areas. The State reported that organic mass contributed more
than ammonium nitrate at Caney Creek but most of the organic mass was
attributable to natural sources.\60\ DEQ did not put weight on relative
contributions to visibility impairment on the clearest days in its
consideration of source selection since visibility impairment on the
clearest days has remained below baseline conditions. Based on these
monitor data observations, the State's strategy for addressing
visibility impairment focused on ammonium nitrate and ammonium sulfate
from anthropogenic sources in all Class I areas identified in

[[Page 43040]]

and outside Arkansas with the exceptions of Sipsey and Shining Rock
where its strategy focused on ammonium sulfate only since it was the
main contributing pollutant in those areas. The State focused on target
precursor pollutants for potential control as a strategy for reducing
these pollutants. The State identified SO<INF>2</INF> and
NH<INF>3</INF> precursor emissions for control since they are
associated with ammonium sulfate, and NO<INF>X</INF> precursor
emissions for control since it is associated with ammonium nitrate.
---------------------------------------------------------------------------

\58\ See chapter II and III of 2022 Planning Period II SIP for
the specific figures of light extinction data at each class I area:
Figures II-4 to 7 for Caney Creek; Figures II-16 to 19 for Upper
Buffalo; Figures III-2 to 5 for Hercules Glades; Figures III-12 to
15 for Mammoth Cave; Figures III-22 to 25 for Mingo Wilderness;
Figures III-31 to 34 for Shining Rock; Figures III-40 to 43 for
Sipsey; and Figures III-50 to 53 for Wichita Mountains.
\59\ See Table V-1 of 2022 Planning Period II SIP (page V-2):
Summary of Key Anthropogenic Particulate Species at each Class I
area.
\60\ See 2022 Planning Period II SIP (page V-2).
---------------------------------------------------------------------------

DEQ reviewed categorized NEI state-wide emissions by sector for
2011, 2014, and 2017 as well as 2020 continuous emissions monitoring
system (CEMS) emissions for EGUs.\61\ The pollutants inventoried were
SO<INF>2</INF>, NO<INF>X</INF>, and NH<INF>3</INF> (the targeted
precursor pollutants); as well as VOC (a precursor to a lesser extent),
and primary PM<INF>2.5</INF> which was not speciated but included all
particulate species directly emitted rather than just ammonium sulfate
and ammonium nitrate. These five pollutant inventories were categorized
under major anthropogenic source groupings but also included biogenic
sources. The anthropogenic source categories included EGU and non-EGU
point; nonpoint; on and non-road mobile sources; off-road mobile
sources (marine and rail); fires (agricultural, prescribed, wildfires,
residential wood combustion); oil and gas; anthropogenic dust; and
agricultural NH<INF>3</INF>. The 2017 NEI inventory was the most recent
comprehensive inventory of updated actual emissions available at the
time DEQ prepared its SIP. For source selection, DEQ emphasized the
2017 NEI emissions from these NEI datasets and summarized the relative
contribution of each sector to the total emissions in each pollutant
inventory. DEQ eliminated NH<INF>3</INF> and VOC as well as directly
emitted PM<INF>2.5</INF> from consideration because the majority of
emission categories in those inventories could not be controlled by the
State. Nearly all of the 2017 NH<INF>3</INF> emissions (98 percent)
came from sectors that DEQ does not have authority to regulate under
Arkansas law or from which DEQ is pre-empted from regulating by
EPA.\62\ As a result, DEQ eliminated NH<INF>3</INF> as a potential
precursor pollutant control to reduce ammonium sulfate in the State's
long-term strategy. Similarly, DEQ eliminated primary PM<INF>2.5</INF>
as a potential pollutant to control since 85 percent of primary
PM<INF>2.5</INF> emissions in 2017 came from sectors outside its
regulatory authority.\63\ DEQ also eliminated VOC controls since the
vast majority of 2017 annual VOC emissions in Arkansas are made up of
biogenic emissions (79%) which are not anthropogenic or controllable.
VOC emissions decreased from 2011 to 2017 across all other categories.
DEQ focused on SO<INF>2</INF> and NO<INF>X</INF> emissions for control
as a result. For 2017 SO<INF>2</INF> and NO<INF>X</INF> emissions, DEQ
reported that 89% (57,213 tpy) of the total 64,284 tpy SO<INF>2</INF>
emissions and 35% (68,608 tpy) of the total 196,022 tpy NO<INF>X</INF>
emissions in Arkansas came from sectors that DEQ does have authority to
regulate under Arkansas law, and that EGUs and non-EGU point source
sectors make up a large portion of these SO<INF>2</INF> and
NO<INF>X</INF> emissions.\64\
---------------------------------------------------------------------------

\61\ See 2022 Planning Period II SIP, Tables IV-4 to IV-7.
\62\ See Figure V-2 (page V-4) in the 2022 Planning Period II
SIP. The pie chart shows sector contributions to the NH<INF>3</INF>
inventory consisting of agricultural NH<INF>3</INF> (78 percent),
prescribed fire (11 percent), agricultural fire (6 percent),
wildfire (2 percent), and other (1 percent) for 98 percent total.
The chart also lists non-EGU point (1 percent) and on-road (1
percent).
\63\ See Figure V-1 (page V-3) in the 2022 Planning Period II
SIP. The pie chart shows sector contributions to the
PM<INF>2.5</INF> inventory consisting of prescribed fire (39
percent), anthropogenic dust (32 percent), non-EGU point (11
percent), wildfire (6 percent), nonpoint (4 percent), residential
wood combustion (4 percent), agricultural fires (1 percent), on-road
(1 percent), non-road (1 percent), and other (1 percent).
\64\ See Figures V-3 and V-4 (pages V-5 to 6) for a breakdown of
percent sector contributions to NO<INF>X</INF> and SO<INF>2</INF>
inventories; and Tables IV-4 and IV-5 showing the 2011, 2014, and
2017 categorized emissions of NO<INF>X</INF> and SO<INF>2</INF>
(pages IV-18 and IV-20) in the 2022 Planning Period II SIP.
---------------------------------------------------------------------------

DEQ also relied on EPA modeling analysis that provided projected
2028 visibility conditions and source sector contribution information.
Based on the EPA's 2028 modeling projections, DEQ included source
apportionment pie charts that represented the specific anthropogenic
emission sector contributions at the different Class I areas on the
most impaired days.\65\ DEQ indicated that the 2028 sector-wide
projections showed that the most prominent source categories
contributing to visibility impairment at the Class I areas in and
outside Arkansas are EGUs and non-EGU point sources with smaller
contributions coming from other U.S. anthropogenic sources. DEQ also
included the oil and gas sector as being a contributor at Wichita
Mountains. As a result, DEQ concluded that the source apportionment
data presented in the pie charts suggest that its strategy should focus
on emissions from EGUs, non-EGU point, and the oil and gas sector.\66\
Based on this modeling analysis; the 2002-2019 IMPROVE extinction data;
and the 2011, 2014, and 2017 categorized NEI state-wide emissions; DEQ
focused its reasonable progress analysis on stationary sources of
SO<INF>2</INF> and NO<INF>X</INF> for planning period II.
---------------------------------------------------------------------------

\65\ See chapters II and III of 2022 Planning Period II SIP for
figures of projected 2028 emission sectors: Figures II-8, II-20,
III-6, III-16, III-26, III-35, III-44, and III-53.
\66\ See 2022 Planning Period II SIP Table V-2: Summary of Key
Sectors Affecting Visibility Impairment in 2028
---------------------------------------------------------------------------

The EPA finds that DEQ's strategy to focus its reasonable progress
evaluation on stationary sources of NO<INF>X</INF> and SO<INF>2</INF>
in its 2022 Planning Period II SIP is reasonable for the second
planning period. DEQ adequately assessed the key pollutants and source
categories and formed the basis of its decision after weighing the
monitoring data, emission inventory trends of key precursor pollutants,
and projected 2028 source apportionment data.
b. Area of Influence Analysis
Through collaboration with CenSARA, Arkansas assessed state-by-
state contributions to visibility impairment for the two Class I areas
in Arkansas and for Class I areas in other states affected by emissions
from Arkansas. Arkansas relied on an area of influence (AOI) analysis
performed by Ramboll US Corporation (Ramboll) for the CenSARA states in
its 2022 Planning Period II SIP to identify possible regional source
locations impacting visibility. Ramboll performed the AOI analysis for
CenSARA Class I areas and for neighboring Class I areas that might
potentially be impacted by emissions from the CenSARA states. Ramboll
produced an AOI report \67\ that summarizes the approach of the
analysis and an AOI spreadsheet \68\ that the CenSARA states could use
to evaluate the results for specific Class I areas. The AOI analysis
used back-trajectory modeling \69\ to identify the geographic

[[Page 43041]]

areas and anthropogenic emission sources with a high probability of
impacting visibility at Class I areas within the CenSARA region and in
nearby states. The analysis focused on SO<INF>2</INF> and
NO<INF>X</INF> as the primary anthropogenic particulate species
precursors (for SO<INF>4</INF>2- and
NO<INF>3</INF>-, respectively) that impair visibility at the
Class I areas in the CenSARA region. The AOI analysis report generated
several metrics that states could use. Based on the individual back
trajectories on the 20 percent most impaired visibility days, Ramboll
carried out residence time analysis \70\ generating residence time
plots which graphically mapped trajectory paths for each IMPROVE
monitoring site. Ramboll extended the analysis by weighting the
residence times using various metrics like emissions, visibility
extinction, and distance-weighted approaches. Distance-weighted
residence time generally assessed the probability of air parcels
originating outside a given Class I area to reach a particular area
following a straight-line trajectory with constant speed from all
directions. Extinction-weighted residence time (EWRT) assessed
visibility extinction values attributable to specific pollutants
(NO<INF>X</INF> and SO<INF>2</INF> in this case) to help identify
geographical areas of influence for each pollutant at each Class I
area. The Ramboll report also examined the EWRT*Q/d metric which the
report identifies as the most comprehensive residence time metric
because it combines visibility extinction values and also considers the
distance-weighted emissions from the source to the Class I area. More
specifically, this metric considered point source emission
contributions from each facility to visibility impairment at each Class
I area by matching the EWRT with the facility-level emissions (Q) over
distance (d) of the 2016 actual and 2028 projected point source
emission inventories.\71\ To determine the total potential impact from
sources of SO<INF>2</INF> and NO<INF>X</INF> (precursors of
SO<INF>4</INF>\2-\ and NO<INF>3</INF>\-\, respectively), the EWRT
values for SO<INF>4</INF>2-1 and NO3- were
combined with emissions from sources of SO<INF>2</INF> and
NO<INF>X</INF>. CenSARA states chose to focus on EGU and non-EGU point
sources since these sources comprise major fractions of the
NO<INF>X</INF> and SO<INF>2</INF> emissions inventory. The EWRT*Q/d
values for each grid cell were normalized by the domain total and then
plotted for both 2016 and 2028 emissions. Arkansas applied a 0.05
percent extinction-weighted screening threshold to the 2016 EWRT
NO<INF>X</INF> results and 2016 EWRT SO<INF>2</INF> results for all
trajectory heights combined to identify pollutant-specific areas of
influence for each Class I area included in the AOI analysis.\72\ DEQ
included those sources for screening in the AOI for each Class I area
with an EWRT value greater than or equal to 0.05 percent for either
pollutant. DEQ summed the combined EWRT*Q/d values for NO<INF>X</INF>
and SO<INF>2</INF> to produce a surrogate value for total visibility
impact (the visibility impact surrogate) for each source in the AOI and
then ranked them from largest to smallest for each Class I area. This
allowed DEQ to identify the sources having the largest impact at each
Class I area by comprehensively considering all combinations of impacts
from the key pollutants from all stationary sources. DEQ used the AOI
analysis and EWRT*Q/d to identify sources that impact the Class I areas
in and around Arkansas and used that information to inform
consultations with other states and to select Arkansas sources for
additional analysis.
---------------------------------------------------------------------------

\67\ See area of influence report in Appendix B of 2022 Planning
Period II SIP submittal called 7AppB_Area of Influence Report
Prepared by Ramboll.pdf.
\68\ See screening spreadsheet in Appendix C of the 2022
Planning Period II SIP called 7AppC_Arkansas Source Screening Method
Spreadsheet-v8.xlsx. DEQ developed this from the CenSARA AOI
Analysis EWRT.QD 2016 All Trajectories Spreadsheet provided to
CenSARA states.
\69\ Back trajectory analyses estimate the most likely central
path of air masses that would arrive at a receptor at a given time
by accounting for the impact of wind direction and wind speed on
delivery of emissions to the receptor. A back trajectory analysis
for certain emissions starts at the Class I area and go backwards in
time to examine the path that emissions took to get to the Class I
areas. Ramboll ran HYSPLIT model for the 20 percent most
anthropogenically impaired days and developed 72-hour back
trajectories arriving at each of the IMPROVE sites at 06:00, 12:00,
18:00 and 24:00 from each Class I area following trajectory ending
altitudes of 100 m, 200 m, 500 m, and 1000 m.
\70\ A more sophisticated trajectory-based analysis technique
combines emissions, ambient PM data, and trajectory information.
Residence time represents the cumulative time that emission
trajectories would reside in each 36-km by 36-km grid square. This
approach selects sources for analysis using an approach that gives
each point source a score that takes into account the source's
emissions, the daily values of light extinction at a Class I area,
the distance between the source and a Class I area, and the relative
frequency with which wind trajectories indicate that each source is
upwind of the IMPROVE monitoring site.
\71\ The IMPROVE ``most anthropogenically impaired days'' data
for 2017 was not available at the time the area of interest report
was developed so the 2013-2017 period could not be used and the
2012-2016 period was used instead.
\72\ The RHR has no specific guidance on threshold values for
residence time, so Ramboll chose normalized percentages across
selected Class I areas and altitudes that represented a reasonable
range.
---------------------------------------------------------------------------

DEQ's evaluation of the visibility impact surrogate results for all
SO<INF>2</INF> and NO<INF>X</INF> sources in the 2016 AOI for Caney
Creek Wilderness Area indicates that stationary sources in 16 states
potentially contributed to visibility impairment on the most impaired
days, with sources in Texas, Arkansas, Louisiana, and Oklahoma
contributing the majority with 94 percent of the total visibility
impact surrogate in the 2016 AOI analysis results (46, 23, 13, and 12
percent, respectively).\73\ Stationary sources in 12 other states
combined for the remaining 6 percent contribution: Missouri, Illinois,
and Indiana contributed 3, 1, and 0.5 percent each while the remaining
nine states \74\ all combined to contribute 0.7 percent. DEQ's
evaluation of the visibility impact surrogate results for all sources
in the 2016 AOI for Upper Buffalo Wilderness Area indicated that
stationary sources in 16 states potentially contributed to visibility
impairment on the most impaired days, with Arkansas, Missouri, Texas,
Oklahoma, contributing the majority with 81 percent (48, 15, 9, and 9
percent, respectively).\75\ Louisiana and Illinois contributed 5 and 4
percent each while sources in the remaining ten states each contributed
3 percent or less: Iowa, Indiana, Kansas, Kentucky, Nebraska Minnesota,
Mississippi, South Dakota, Tennessee, and Wisconsin.
---------------------------------------------------------------------------

\73\ See Figure II-12 in the 2022 Planning Period II SIP (page
II-16) which shows each state's percent contribution to the total
visibility impact surrogate from all stationary sources in the 2016
AOI for Caney Creek Wilderness Area.
\74\ Iowa, Kansas, Kentucky, Minnesota, Mississippi, Nebraska,
North Dakota, Tennessee, and Wisconsin all combined contributed 0.7
percent of the total visibility impact surrogate from all stationary
sources.
\75\ See Figure II-24 in the 2022 Planning Period II SIP (page
II-27) which shows each state's percent contribution to the total
visibility impact surrogate from all stationary sources in the 2016
AOI for Upper Buffalo Wilderness Area.
---------------------------------------------------------------------------

DEQ used the 2016 results from the AOI analysis to select
stationary sources of SO<INF>2</INF> and NO<INF>X</INF> for
consideration for four-factor analyses. DEQ calculated the cumulative
percentage of AOI source impacts for each source and applied a
screening threshold of 70 percent of the cumulative percentage of 2016
AOI source impacts for NO<INF>X</INF> and SO<INF>2</INF> combined.\76\
Using this methodology, the stationary sources comprising 70 percent of
the cumulative percentage of AOI source impacts at each Arkansas Class
I area were identified for four-factor evaluation. The State reported
five facilities in Arkansas (three EGU power plants and two non-EGU
facilities) that were brought forward for further analysis by applying
the 70 percent screening threshold: \77\ White Bluff Power Plant,
Independence Power Plant, FutureFuel Chemical Co., Domtar Ashdown Mill,
and Flint Creek Power Plant. Out of Arkansas' total AOI sources impacts
at Caney Creek--Independence, White Bluff, and Domtar contributed 16
percent out of the 23 percent Arkansas total state contributions (69
percent of total Arkansas impacts).78 79 Out of Arkansas'
total AOI sources impacts at Upper Buffalo--Independence, White Bluff,

[[Page 43042]]

FutureFuel, and Flint Creek contributed 40 percent out of the 48
percent Arkansas total state contributions (85 percent of total
Arkansas impacts).80 81
---------------------------------------------------------------------------

\76\ See 2022 Planning Period II SIP Appendix C spreadsheet:
7AppC_Arkansas Source Screening Method Spreadsheet-v8.xlsx.
\77\ See Table V-3 of 2022 Planning Period II SIP.
\78\ See Figure II-12 in the 2022 Planning Period II SIP (page
II-16) which shows each state's percent contributions to visibility
impairment at Caney Creek Wilderness Area for all sources in the
AOI.
\79\ See 2022 Planning Period II SIP Appendix C spreadsheet
7AppC_Arkansas Source Screening Method Spreadsheet-v8.xlsx.
\80\ See Figure II-24 of the 2022 Planning Period II SIP (page
II-27) which shows each state's percent contributions to visibility
impairment at Upper Buffalo Wilderness Area for all sources in the
AOI.
\81\ See 2022 Planning Period II SIP Appendix C spreadsheet:
7AppC_Arkansas Source Screening Method Spreadsheet-v8.xlsx.
---------------------------------------------------------------------------

DEQ reported that it also considered a higher threshold of 80
percent for source selection during the early stages of the SIP
development process. The State noted that application of an 80 percent
threshold would result in additional Arkansas sources being brought
forward for analysis when compared to the 70 percent threshold, but
those additional sources would not have the potential to meaningfully
reduce contributions to visibility impairment because they would all
have minimal visibility impacts relative to the sources selected. In
contrast, the 70 percent threshold occurred at a natural break in the
data distribution and included the highest contributors to visibility
impairment at the Class I areas without ``unnecessarily'' bringing
forward additional sources with minimal-impact for four-factor
analysis. An 80 percent threshold would bring forward three additional
Arkansas sources forward for Caney Creek--Weyerhaeuser NR Company-
Dierks Mill, Albemarle Corporation-South Plant, and Ash Grove Cement
Company--Foreman Cement Plant--but each would only contribute 1 percent
or less to the AOI source impacts (1.13, 1.06, and 0.85 percent,
respectively).\82\ Similarly, an 80 percent threshold would bring
forward six additional Arkansas sources forward for Upper Buffalo--Dunn
Compressor Station, Domtar Ashdown Mill (which has already been
selected for four-factor analysis due to impacts at Caney Creek), Green
Bay Packaging-AR Kraft-Morrilton, Albemarle Corporation-South Plant,
SGL Carbon, LLC, and Plum Point Energy Station Unit 1--but each would
only contribute 0.5 percent or less to the AOI source impacts (0.53,
0.49, 0.48, 0.48, 0.46, and 0.43 percent, respectively).\83\
---------------------------------------------------------------------------

\82\ Id.
\83\ Id.
---------------------------------------------------------------------------

DEQ reported that the 70 percent threshold would also bring forward
18 sources in other states that impact Arkansas' Class I areas (see
Table 6).\84\ Therefore, DEQ considered those sources and sent out
consultation letters (``ask'' letters) to those states where the 18
facilities are located and requested that those states consider whether
performing a four-factor analysis was appropriate for each of those
sources in accordance with 40 CFR 51.308(f)(2)(i); and, if so, whether
any control measures for SO<INF>2</INF> or NO<INF>X</INF> would be
necessary to make reasonable progress toward natural visibility at
Caney Creek and Upper Buffalo during the second planning period. DEQ
also requested that each state share with them the results of any
analyses, including technical supporting documentation, and provide an
opportunity for consultation on the analyses and each state's long-term
strategy early enough in the process for DEQ to provide feedback. See
section IV.C.4 of this action which discusses Consultation Requirements
with States for further information.
---------------------------------------------------------------------------

\84\ See Table V-4 of 2022 Planning Period II SIP.

Table 6--Sources in Other States Impacting Arkansas' Class I Areas
----------------------------------------------------------------------------------------------------------------
State Facility Class I areas impacted
----------------------------------------------------------------------------------------------------------------
Texas............................... Martin Lake Electrical Station. --Caney Creek.
--Upper Buffalo.
AEP Pirkey..................... --Caney Creek.
--Upper Buffalo.
Welsh Power Plant.............. --Caney Creek
--Upper Buffalo.
WA Parish Electric Generating --Caney Creek.
Station.
Louisiana........................... CLECO Power LLC Dolet Hills.... --Caney Creek.
--Upper Buffalo.
Entergy Louisiana LLC--Roy S --Caney Creek.
Nelson Plant.
Oklahoma............................ Muskogee Generating Station.... --Caney Creek.
--Upper Buffalo.
Hugo Generating Station........ --Caney Creek.
--Upper Buffalo.
Grand River Energy Center...... --Upper Buffalo.
Missouri............................ Ameren Missouri Labadie Plant.. --Upper Buffalo.
Ameren Missouri Rush Island --Upper Buffalo.
Plant.
New Madrid Power Plant Marston. --Upper Buffalo.
City Utilities of Springfield --Upper Buffalo.
Missouri John Twitty Energy
Center.
Thomas Hill Energy Center Power --Upper Buffalo.
Division.
Illinois............................ Prairie Generating Station..... --Upper Buffalo.
Indiana............................. Indiana Michigan Power DBA AEP --Upper Buffalo.
Rockport.
Duke Energy Indiana LLC--Gibson --Upper Buffalo.
Genera.
Kentucky............................ Tennessee Valley Authority --Upper Buffalo.
(TVA)--Shawnee Fossil Plant.
----------------------------------------------------------------------------------------------------------------

DEQ performed a source screening sensitivity analysis which omitted
recently controlled or shut down SO<INF>2</INF> and NO<INF>X</INF>
emissions sources in Oklahoma and Texas from the 2016 inventory in the
AOI analysis to see if those changes (which occurred after 2016) would
impact the source selection results while maintaining the remainder of
the inventory.\85\ Specifically, DEQ zeroed out the emissions of three
major point sources in Texas that shutdown in 2018--the Sandow Steam
Electric Station, the Big Brown Steam Electric Station, and Monticello
Steam Electric Stations--and then used the 2019 emissions for the
Muskogee and Sooner Generating Stations in Oklahoma to reflect
SO<INF>2</INF> reductions from installed 2018 controls. DEQ performed
this sensitivity analysis for each Class I area

[[Page 43043]]

that contained at least one Arkansas source in the 2016 AOI and at
least one of the five revised emission sources. This included Caney
Creek and Upper Buffalo in Arkansas, Hercules Glades in Missouri, and
Wichita Mountains in Oklahoma. The State applied a 70 percent screening
threshold to the cumulative percentage of AOI impacts for
NO<INF>X</INF> and SO<INF>2</INF> combined based on the revised 2016
inventory. The AOI sensitivity analysis identified two additional
Arkansas sources that would be brought forward for consideration for
four-factor analysis based on adjustments to the 2016 inventory--
Weyerhaeuser NR Company--Dierks Mill (Dierks Mill) and Albemarle
Corporation--South Plant (Albemarle South). Dierks Mill is a sawmill
that processes lumber and wood residuals. It is 40 km from Caney Creek
and has one major NO<INF>X</INF> unit (100 tons per year (tpy) or
greater) and none for SO<INF>2</INF>. The NO<INF>X</INF> unit is a
wood-fired boiler with a rate of 249.0 MMBtu/hr. Albemarle South is a
chemical manufacturer that extracts bromine-containing brine from
geologic formations. It has one major SO<INF>2</INF> emission unit (100
tpy or greater) and none for NO<INF>X</INF>. Albemarle South burns tail
gas from a sulfur recovery plant that removes sulfur from sour gas
created from bromine separation from extracted brine. DEQ explained for
Dierks Mill that the wood-fired boiler has not operated since 2017 and
was removed from the permit in May 2020.\86\ DEQ does not anticipate
that retrofitting NO<INF>X</INF> post-combustion controls to be
reasonable even if operation had continued at Dierks Mill. DEQ also
explained that after a review of the RACT/BACT/LAER Clearinghouse
(RBLC) database,\87\ it could not identify technically feasible
SO<INF>2</INF> controls for Albemarle South that could be implemented
in conjunction with the existing tail gas incinerator. Based on this
assessment, DEQ determined that the revised 2016 inventory used in the
sensitivity analysis would not produce more potential for meaningfully
reducing contributions from Arkansas sources at Caney Creek or Upper
Buffalo. EPA notes that Dierks Mill and Albemarle South contribute 1.43
and 1.35 percent of the AOI source impacts at Caney Creek, and
negligible AOI source impacts at Upper Buffalo (0.03 and 0 percent,
respectively). Based on the State's assessment of the lack of
technically feasible controls as well as low contributing emissions,
DEQ concluded that source selection sensitivity adjustments would not
make a difference in the sources that DEQ would analyze. Therefore, DEQ
did not make adjustments to the emissions inventory used in the AOI
analysis and its source selection methodology.
---------------------------------------------------------------------------

\85\ See 2022 Planning Period II SIP Appendix E spreadsheet:
AppE_AR Screening
Method_V32_2016_InventoryOK_TX_Sensitivity_v9.xlsx.
\86\ See DEQ air permit No. 0023-AOP-R14 issued May 11, 2020.
\87\ RACT, or Reasonably Available Control Technology, is
required on existing sources in areas that are not meeting national
ambient air quality standards (i.e., non-attainment areas). BACT, or
Best Available Control Technology, is required on major new or
modified sources in clean areas (i.e., attainment areas). LAER, or
Lowest Achievable Emission Rate, is required on major new or
modified sources in non-attainment areas.
---------------------------------------------------------------------------

After considering all of the sources screened in the AOI study from
the different thresholds applied, and after considering potential
adjustments to the 2016 emission inventory used in the AOI analysis,
DEQ selected five Arkansas facilities to be included for four-factor
analysis (see Table 7). Originally, DEQ brought forward White Bluff in
its list of sources selected for a full four-factor analysis from the
70 percent screening threshold. However, after a partial four-factor
analysis evaluating the existing control measures for White Bluff, DEQ
determined in its 2022 Planning Period II SIP submittal that existing
control measures at White Bluff Power Plant are sufficient for
reasonable progress (see section IV.C.2.a for more details).\88\ For
each selected facility, DEQ identified the emission units that emit
SO<INF>2</INF> and/or NO<INF>X</INF> and identified existing controls
in place at each emission unit.
---------------------------------------------------------------------------

\88\ 2022 Planning Period II SIP (pages V-16 to 17).

Table 7--Arkansas Sources Selected for Four-Factor Analysis and Existing Controls
----------------------------------------------------------------------------------------------------------------
Class I areas Existing SO2 Existing NOX
Facility impacted Units controls controls
----------------------------------------------------------------------------------------------------------------
Entergy White Bluff Power Plant. --Caney Creek..... Two Coal-fired EGU --Low Sulfur Coal. Low NOX Burners
--Upper Buffalo... Boilers: (SN-01 --0.60 lb/MMBtu with Overfire
--Hercules Glades. and SN-02). SO2 limit for Air.
each unit..
Entergy Independence Power Plant --Upper Buffalo Two Coal-Fired EGU Low Sulfur Coal... Low NOX Burners
(26%). Boilers: (SN-01 with Overfire
--Hercules Glades and SN-02). Air.
(20%)..
--Caney Creek
(5%)..
--Mingo (3%)......
--Sipsey (1%).....
FutureFuel Chemical Co.......... --Upper Buffalo Three Coal-Fired None.............. None.
(3%). Industrial
--Hercules Glades Boilers: (6M01-
(2%).. 01).
--Caney Creek
(<1%)..
--Mingo (<1%).....
--Sipsey (<1%)....
Domtar Ashdown Mill............. --Caney Creek (5%) No. 2 Power Boiler Venturi Scrubbers. Overfire Air.
--Upper Buffalo No. 3 Power Boiler None.............. ..................
(<1%).. No. 2 Recovery None.
--Hercules Glades Boiler.
(<1%).. No. 3 Recovery
--Wichita Mtns Boiler..
(<1%)..
SWEPCO Flint Creek Power Plant.. --Upper Buffalo One Coal-Fired EGU --Novel Integrated --Low NOX Burners
(1%). Boiler (SN-01 Desulfurization with Overfire
--Hercules Glades Boiler). (Dry FGD). Air.
(1%).. --0.06 lb/MMBtu --0.23 lb/MMBtu.
--Caney Creek SO2 limit..
(<1%)..
----------------------------------------------------------------------------------------------------------------

EPA finds that the State's source selection methodology and the
criteria it used to determine which sources to select for four-factor
evaluation is reasonable for the second implementation period. DEQ
relied on a comprehensive robust approach for its source selection to
identify the geographic areas with anthropogenic emission sources with
a high probability of impacting visibility at the different Class I
areas. DEQ used the EWRT*Q/d metric which is the most comprehensive
residence time metric that combines visibility extinction values and
also considers the distance-weighted emissions from the source to the
Class I area. DEQ also relied on total

[[Page 43044]]

visibility impact surrogate values for each source (summed EWRT*Q/d
values for NO<INF>X</INF> and SO<INF>2</INF>) in the areas of
influence, which enabled the State to identify each state's percent
contribution to visibility impairment and the respective sources that
have the largest impact at each Class I area. DEQ appropriately
selected five facilities in Arkansas (Entergy White Bluff, Entergy
Independence, FutureFuel, Domtar Ashdown Mill, and Flint Creek) for
further analysis of potential emission reduction controls and
documented its rationale in selecting those sources after analyzing the
total source impacts from all contributing sources in Ramboll's AOI
source screening analysis. We find that the State adequately weighed
its decision after considering all sources screened from two different
applied thresholds (70 and 80 percent) and then considering potential
emission adjustments to the 2016 inventory. The State determined that
the 70 percent threshold was more reasonable compared to the 80 percent
threshold because it occurred at a natural break in the distribution
and included the highest contributors to visibility impairment at the
Class I areas. The 70 percent threshold also did not ``unnecessarily''
bring forward minimal-impact sources for four-factor analysis like the
80 percent threshold did. Any additional sources added above a 70
percent threshold would only contribute 1 percent or less to the AOI
source impacts at either of the two Arkansas Class I areas. The five
facilities selected with the 70 percent threshold represented a high
proportion of the emission impacts at each Class I area in Arkansas.
EPA notes that these sources contributed 16 out of the 23 percent AOI
source impacts at Caney Creek and 40 out of the 48 percent AOI source
impacts at Upper Buffalo. DEQ also performed a source screening
sensitivity analysis which omitted recently controlled or shut down
SO<INF>2</INF> and NO<INF>X</INF> emissions sources in Oklahoma and
Texas from the 2016 inventory, but those adjustments were not
incorporated because they did not impact source selection. The two
additional sources considered in the sensitivity analysis had minimal
potential impacts relative to the five initially selected sources and
the State did not identify any technically feasible controls for these
two sources. These analyses show that the five sources brought forward
from the 70 percent screening threshold represent a reasonable set of
sources to evaluate for potential control within Arkansas.
3. Four Factor Analyses
For each facility selected to undergo four-factor analysis, the
State identified potential emission reduction control strategies and
asked each selected facility (through information collection request
letters dated January 8, 2020) \89\ to assess whether the identified
controls by the State were technically feasible or not. If a strategy
was not technically feasible, facilities were to provide a robust
explanation explaining why.
---------------------------------------------------------------------------

\89\ See Appendices F through I of the 2022 Planning Period II
SIP for the regional haze four-factor analysis information
collection requests by DEQ which includes the identified
technologies to Independence, FutureFuel, Domtar, and Flint Creek.
DEQ did not send an information collection request to White Bluff
for the two coal-fired EGU Boilers (SN-01 and SN-02). As mentioned,
after a partial four-factor analysis evaluating the existing control
measures for White Bluff, DEQ determined in its 2022 Planning Period
II SIP submittal that existing control measures at White Bluff Power
Plant are sufficient for reasonable progress.
---------------------------------------------------------------------------

For each technically feasible control, facilities were directed to
provide information about the control effectiveness of each technology
for each emission unit ranked from highest to lowest control efficiency
(i.e., percentage SO<INF>2</INF> and/or NO<INF>X</INF> reduced).\90\
Facilities were asked to include resulting actual annual emission
reduction estimates (in tpy) that would be achieved through
implementation of each control strategy. This was determined by
calculating the difference in baseline and controlled emission rates in
pounds per hour (pph) or pounds per million British thermal units (lb/
MMBtu). Facilities were asked to provide baseline emission rates
annualized on a maximum monthly basis for the 2017-2019 period \91\ to
ensure that cost estimates would be based on appropriately sized
equipment. DEQ also directed facilities to provide additional
information for baseline emission rates annualized on an average
monthly emission rate basis to estimate the typical emission reductions
that may be achievable from each control. DEQ included a description of
the criteria it required for the facilities to use to evaluate the four
factors for each control measure being considered in its long-term
strategy and the underlying assumptions for each factor.
---------------------------------------------------------------------------

\90\ From EPA Menu of Control Measures which provides states
with information on a broad, though not comprehensive, listing of
potential emissions reduction measures, as well as relevant
information concerning the efficiency and cost effectiveness of the
measures. See <a href="https://www.epa.gov/sites/default/files/2016-02/menuofcontrolmeasures.xlsx">https://www.epa.gov/sites/default/files/2016-02/menuofcontrolmeasures.xlsx</a>.
\91\ A shorter baseline period (June 1, 2018-December 31, 2019)
was provided for Flint Creek because construction of low
NO<INF>X</INF> burners with separated over fire air was completed on
May 18, 2018, which reduced NO<INF>X</INF> emissions from the SN-01
Boiler.
\92\ See EPA Air Pollution Cost Control Manual Section 1--
Introduction, Chapter 2--Cost Estimation: Concepts and Methodology
(page 11). An alternate way of describing this method is the present
value cost that would have to be paid as a lump sum up front to
completely pay for a construction project.
\93\ See spreadsheet in Appendix J of 2022 Planning Period II
SIP called 7AppJ_DescStats_PP1 DetermCosts-v9.xlsx.
\94\ The 98th percentile means that for a given distribution, it
is equal to or higher than 98 percent of the rest of the
distribution.
---------------------------------------------------------------------------

For cost of compliance, DEQ instructed facilities to follow the EPA
Pollution Control Cost Manual overnight methodology \92\ which
estimates capital costs, annual operating/maintenance costs, and
annualized costs as if the project is completed ``overnight'' with no
interest incurring during construction. Facilities expressed the costs
in terms of annualized cost per ton of emissions reduced per year to
compare the different control options for the same source and across
different sources. DEQ noted that the amortization period should be
based on the time between when the strategy could reasonably be in
place and the remaining useful life of the emission control system. DEQ
reviewed the cost per ton information provided by the facilities for
the different identified control strategies and compared those results
to different cost thresholds based on dollar per ton ($/ton) values
that were incurred from past BART and reasonable progress
determinations from the first planning period.\93\ DEQ adjusted those
$/ton values to 2019 dollars using the Chemical Engineering Plant Cost
Index and then selected the 98th percentile \94\ as the threshold for
each emission unit type (see Table 8). The State selected the 98th
percentile $/ton metric because it is a robust approach that does not
give undue weight to the extreme tail of a distribution and ensures
that costs that have incurred multiple times from the first planning
period by sources of a similar type are captured. DEQ noted that the
different thresholds consider how imposed costs are financed and how
investments are recovered from the different emission unit types. DEQ
originally proposed to use a bank prime rate of 3.25 percent after
considering EPA comments received during the public comment period
concerning the rate at the time, but because of more recent upward
trends of the federal interest rate, DEQ revised its analyses and
calculated the annualized capital costs using the information provided
by the different facilities and a 7 percent interest rate.

[[Page 43045]]

Table 8--Cost Effectiveness Thresholds for Different Emission Unit Types
in 2019 Dollars
------------------------------------------------------------------------
Cost threshold
Equipment type ($/ton--98th
percentile)
------------------------------------------------------------------------
EGU Boiler.............................................. 5,086
Industrial Boiler....................................... 3,328
Kiln.................................................... 4,419
Smelter................................................. 1,041
------------------------------------------------------------------------

For the time necessary for compliance, DEQ directed facilities to
consider the time needed for a source to comply with a potential
control measure and to justify the time needed to install a control
measure as being reasonable. DEQ noted in its SIP submittal that a
reasonable time period to establish a compliance deadline is one in
which the source comes into compliance in an efficient manner without
unusual amounts of overtime, above-market wages and prices, or premium
charges for expedited delivery of control equipment. DEQ mentioned
that, in addition to establishing compliance schedules, the time
necessary for compliance may influence how capital costs of control
measures are annualized if the remaining useful life of an emission
unit is less than the life of the equipment involved.\95\
---------------------------------------------------------------------------

\95\ See 2022 Planning Period II SIP submittal (page V-15). See
also 2019 Guidance at 45.
---------------------------------------------------------------------------

For remaining useful life, DEQ instructed facilities to follow the
EPA Pollution Control Cost Manual on typical useful life values of
various emission control systems or should be based on enforceable
shutdown dates. DEQ noted that for purposes of its evaluation, the
remaining useful life was factored into the cost of compliance. DEQ
based the annualization of capital costs on the expected life of the
equipment involved for the potential control measures under evaluation
and consideration of any other requirements.\96\
---------------------------------------------------------------------------

\96\ Id.
---------------------------------------------------------------------------

For energy and non-air quality environmental impacts of compliance,
DEQ directed facilities to factor any costs associated with these
impacts into the cost of implementing the strategy, including without
limitation: permitting costs if other regulatory requirements are
triggered by the controls; costs associated with compliance with any
other regulatory requirements triggered by the controls; and cost of
waste disposal for wastes generated by proposed controls.
In addition to the four statutory factors, DEQ also included in its
evaluation of potential controls the context of historical visibility
improvement that has been achieved at the Arkansas' Class I areas, and
future 2028 anticipated visibility impairment in those areas.\97\
---------------------------------------------------------------------------

\97\ See 2022 Planning Period II SIP submittal (page V-16).
---------------------------------------------------------------------------

The facilities responded to DEQ's information collection requests
and provided reports with the requested information for each
technically feasible control.\98\ DEQ relied on the information
provided in the facility reports in its 2022 Planning Period II SIP
submittal and, based on the information provided, determined which
control measures would be necessary for each facility to make
reasonable progress for the second implementation period.
---------------------------------------------------------------------------

\98\ See Appendices F through I of the 2022 Planning Period II
SIP for the regional haze four-factor analysis information
collection requests by DEQ and the corresponding responses including
four-factor analyses for the identified technologies from
Independence, FutureFuel, Domtar, and Flint Creek. As mentioned,
after a partial four-factor analysis evaluating the existing control
measures for White Bluff, DEQ determined in its 2022 Planning Period
II SIP submittal that existing control measures at White Bluff Power
Plant are sufficient for reasonable progress. Therefore, DEQ did not
send an information collection request to White Bluff for the two
coal-fired EGU Boilers (SN-01 and SN-02).
---------------------------------------------------------------------------

a. Entergy White Bluff Power Plant
Facility Information. DEQ selected the White Bluff Power Plant
located in Jefferson County, Arkansas for further analysis. The State
identified two boilers (SN-01 and SN-02 Boilers) as major sources that
emitted a total of 18,336 tpy SO<INF>2</INF> emissions and a total of
9,719 tpy NO<INF>X</INF> emissions in 2016.
The boiler units are identical tangentially-fired 850 megawatt (MW)
boilers that have a maximum heat input capacity of 8,950 MMBtu/hr. Both
units burn sub-bituminous coal as a primary fuel and No. 2 fuel oil or
bio-diesel as the startup fuel at a maximum rate of 1,000 MMBtu/hr. The
boilers supply steam which feed turbine generators to produce
electricity.
Proposed Reasonable Progress Control Determination for Entergy
White Bluff. In the State's evaluation of controls for White Bluff,\99\
DEQ reported that both boilers burn low-sulfur coal to control
SO<INF>2</INF> emissions, are equipped with low NO<INF>X</INF> burners
with separated overfire air to control NO<INF>X</INF> emissions, and
are equipped with electrostatic precipitators \100\ to control PM
emissions. For SO<INF>2</INF> control, both boilers are subject to BART
and are required to comply with an SO<INF>2</INF> emission limit of
0.60 lb/MMBtu for each boiler on a thirty-boiler-operating-day rolling
average. This is based on fuel switching to lower sulfur coal by August
7, 2021, pursuant to an Administrative Order \101\ between DEQ and
Entergy as part of the approved 2018 Phase II SIP revision from the
first planning period.\102\ This state- and federally-enforceable
Administrative Order incorporates the requirements of a Settlement
Agreement and Consent Judgement (Consent Decree) \103\ that resolves
CAA claims brought by the Sierra Club. The Consent Decree and
Administrative Order also require both boilers to cease coal-fired
operations by no later than December 31, 2028, and was approved into
the State's SIP as a source-specific SIP requirement in the first
implementation period.\104\ DEQ considered that enforceable requirement
to cease coal-fired operations at White Bluff to be sufficient reason
to not perform a four-factor analysis for this source for the second
planning period. DEQ stated that additional NO<INF>X</INF> control
measures beyond the low NO<INF>X</INF> burners and low sulfur coal,
which have already been implemented at White Bluff to meet its
obligations under CSAPR for O<INF>3</INF> season NO<INF>X</INF>
allocations, are not cost-effective due to the plant's remaining useful
life. The annual cost of control measures evaluated during the first
planning period \105\ would only be expected to increase in an updated
reasonable progress analysis because White Bluff is nearer to its
termination of coal-fired operations date than it was in the previous
analysis. The technologies available to reduce NO<INF>X</INF> and
SO<INF>2</INF> at power plants, such as White Bluff, have not changed
since 2018. Because the low NO<INF>X</INF> burners installed at White
Bluff cannot be shut down temporarily, being an inherent part of the
equipment design, no separate emission limit is necessary for inclusion
in the SIP to ensure operation of the low NO<INF>X</INF>

[[Page 43046]]

burners. Lastly, if Entergy chooses to continue operations of the White
Bluff units after December 31, 2028, they must apply for a permit
revision to burn a different fuel. Such a permit revision would be
subject to new source review (NSR) requirements. If the change would
result in a significant increase in emissions, Prevention of
Significant Deterioration (PSD) and BACT requirements would be
triggered. The most likely fuel switch would be to natural gas, which
inherently emits much less SO<INF>2</INF> and NO<INF>X</INF> relative
to coal. Because of this reasoning, DEQ chose not to require White
Bluff to perform additional analysis on potential control technologies.
---------------------------------------------------------------------------

\99\ See 2022 Planning Period II SIP (pages V-16 to V-17).
\100\ See EPA Air Pollution Cost Control Manual Section 6--
Particulate Matter Controls Chapter 3--Electrostatic Precipitators
(page 3-4). An electrostatic precipitator is an air pollution
control device that functions by electrostatically charging
particles in a gas stream that passes through collection plates with
wires. The ionized particulate matter is attracted to and deposited
on the plates as the cleaner air passes through. A wet electrostatic
precipitator is designed to operate with water vapor saturated air
streams to remove liquid droplets such as sulfuric acid.
\101\ See Administrative Order (LIS No. 18-073), dated August 7,
2018.
\102\ See 84 FR 51033 (September 27, 2019) final approval.
\103\ Sierra Club and National Parks Conservation Association v.
Entergy Arkansas, inc., Entergy Power, LLC, and Entergy Mississippi,
Inc. Case No. 4:18-cv-00854-KGB (ED Ark., March 11, 2021).
\104\ See 84 FR 51033 (September 27, 2019).
\105\ Id. at 51033, 51040.
---------------------------------------------------------------------------

DEQ considered the potential cost of controls and the remaining
useful life of the SN-01 and SN-02 boilers and concluded that no
additional analysis is required, and no additional measures are
necessary to make reasonable progress for the second planning period at
Entergy White Bluff. In addition, the projected 2028 visibility
conditions at all Class I areas to which White Bluff contributes (Caney
Creek, Upper Buffalo, and Hercules Glades) are all below their
respective 2028 URP values. The EPA is proposing to find that Arkansas
demonstrated that it is making reasonable progress for the second
planning period without requiring any additional measures for White
Bluff.
b. Entergy Independence Power Plant
Facility Information: DEQ selected the Entergy Independence Power
Plant located in Independence County, Arkansas for further analysis.
Two coal-fired boilers (SN-01 and SN-02) were identified by the State
as major sources that emitted a total of 22,570 tpy SO<INF>2</INF>
emissions and a total of 9,864 tpy NO<INF>X</INF> emissions in 2016.
DEQ identified potential SO<INF>2</INF> and NO<INF>X</INF> control
technologies for each of these boilers in its January 8, 2020,
information collection request letter to Entergy Services LLC.\106\
---------------------------------------------------------------------------

\106\ See Appendix F-1 of the document: 7AppF__Entergy
Independence.pdf in Appendix F of the 2022 Planning Period II SIP
for DEQ's Information Collection Request to Entergy Independence.
---------------------------------------------------------------------------

The SN-01 and SN-02 Boilers are identical 900 MW boilers that were
installed in 1978. The SN-01 Boiler was placed into operation in 1983,
and the SN-02 Boiler was placed into operation in 1985. The boilers
operate using sub-bituminous coal as their primary fuel and no. 2 fuel
oil or bio-diesel as the start-up fuel. For NO<INF>X</INF> emissions,
both boilers operate with low NO<INF>X</INF> burners and separated
overfire air systems, which were installed in 2017 in order to assist
the facility in meeting its obligations under CSAPR for O<INF>3</INF>
season NO<INF>X</INF> allocations. The permit \107\ contains limits of
6,090 pph NO<INF>X</INF> and 0.7 lb/MMBtu NO<INF>X</INF> that apply to
both boilers. In addition, PM emissions are controlled with
electrostatic precipitators and subject to a PSD limit of 0.04 lb/
MMBtu.\108\ SO<INF>2</INF> emissions are subject to a limit of 0.60 lb/
MMBtu based on using low sulfur coal on a 30-boiler-operating-day
averaging period, which became effective on August 7, 2021, and was
incorporated into the SIP in the 2018 Phase II SIP revision from the
first planning period.\109\ CEMS measures SO<INF>2</INF> and
NO<INF>X</INF> emissions for these boilers.
---------------------------------------------------------------------------

\107\ See DEQ air permit No. 0449-AOP-R18 issued January 17,
2023.
\108\ This limit is for total suspended particulate (TSP), but
guidance makes clear that PM<INF>10</INF> is the appropriate metric
for the Title V permit threshold since TSP is no longer a regulated
pollutant. See EPA Memorandum from Deputy Director L.N. Wegman dated
October 16, 1995: ``Definition of Regulated Pollutant for
Particulate Matter for Purposes of Title V.''
\109\ See 83 FR 5927 (February 12, 2018) final action. See also
82 FR 42627 (September 11, 2017) for the proposed approval.
---------------------------------------------------------------------------

Technically Feasible Controls. Entergy responded to DEQ's
information collection request in a response letter dated April 7, 2020
(revised on July 24, 2020),\110\ which provided the facility's
evaluation of seven potential controls identified by DEQ. Based on the
information provided by Entergy, DEQ determined that four
SO<INF>2</INF> control options and two NO<INF>X</INF> controls would be
technically feasible for the boilers (see Table 9).
---------------------------------------------------------------------------

\110\ See Appendix F-2 of the document: 7AppF__Entergy
Independence.pdf in Appendix F of 2022 Planning Period II SIP for
the Entergy Independence Power Plant regional haze four-factor
analysis response letter to DEQ prepared by Trinity Consultants
(dated April 7, 2020). For follow up consultations and revisions
(see Appendices F-3 to F-7), DEQ requested that Entergy Services LLC
(July 21, 2020, email) review revised cost control calculations and
Entergy provided feedback in a July 24, 2020, email with an updated
version of the four factor analysis response to DEQ (dated July 23,
2020).
\111\ See EPA Air Pollution Cost Control Manual (seventh
edition) Section 5--SO<INF>2</INF> and Acid Gas Controls Chapter 1--
Wet and Dry Scrubbers for Acid Gas Control (page 1-9 to 1-10). WFGD
systems control SO<INF>2</INF> emissions using solutions containing
alkali reagents or sorbents such as limestone, lime, sodium-based
alkaline, or dual alkali-based sorbents. The sorbent reacts with the
SO<INF>2</INF> and falls to the bottom of the absorber tower where
it is collected and disposed of or recycled back into the system.
WFGD systems generally have the highest control efficiencies. New
WFGD systems can achieve SO<INF>2</INF> removal of 99 percent and
HCl removal of over 95 percent. Packed tower WFGD systems may
achieve efficiencies over 99 percent for some pollutant-solvent
systems.
\112\ See EPA Air Pollution Cost Control Manual (seventh
edition) Section 5--SO<INF>2</INF> and Acid Gas Controls Chapter 1--
Wet and Dry Scrubbers for Acid Gas Control (pages 1-4, 1-7, 1-10 to
1-11). SDA systems consist of an absorber vessel, a bag house
filter, an absorbent feeding tank, and an absorbent feeding system.
Absorbents such as lime and sodium bicarbonate are often used and
sprayed as a slurry into an absorber vessel. At high temperatures,
the water is rapidly vaporized and exits the stack. The absorbent
reacts with the acidic gases in the waste stream to form a byproduct
that is collected in a fabric filter. Spray dryers can achieve
typical SO<INF>2</INF> removal efficiencies of 85-95 percent and up
to 98 percent for new systems.
\113\ See EPA Air Pollution Cost Control Manual (seventh
edition) Section 5--SO<INF>2</INF> and Acid Gas Controls Chapter 1
(pages 1-11 to 1-12). DSI is a type of dry FGD system that is not a
standalone, add-on air pollution control system but a modification
to the combustion unit or ductwork where dry sorbent is injected
directly into the furnace or into the ductwork following the
furnace. Unlike the three other FGD systems, DSI can typically
achieve SO<INF>2</INF> control efficiencies ranging from 50 to 70
percent and has been used in power plants, biomass boilers, and
industrial applications.
\114\ DEQ considered DSI with and without a fabric filter in its
SIP. ``Enhanced DSI'' refers to DSI with a fabric filter and ``DSI''
refers to DSI without a fabric filter.
\115\ See EPA Air Pollution Cost Control Manual (seventh
edition) Section 4--NO<INF>X</INF> Controls Chapter 2--Selective
Catalytic Reduction (page 2-9). SCR systems include a NH<INF>3</INF>
storage and delivery system, NH<INF>3</INF> injection grid, and a
catalyst reactor. A nitrogen-based reducing agent, such as
NH<INF>3</INF> or urea-derived NH<INF>3,</INF> is injected into the
post-combustion flue gas. The reagent reacts selectively with the
flue gas NO<INF>X</INF> within a specific temperature range and in
the presence of the catalyst and oxygen to reduce the NO<INF>X</INF>
into molecular nitrogen (N<INF>2</INF>) and water vapor. SCR systems
can be designed for NO<INF>X</INF> removal efficiencies up close to
100 percent. In practice, commercial coal-, oil-, and natural gas-
fired SCR systems are often designed to meet control targets of over
90 percent. However, the reduction may be less than 90 percent when
SCR follows other NO<INF>X</INF> controls.
\116\ See EPA Air Pollution Cost Control Manual (seventh
edition) Section 4--NO<INF>X</INF> Controls Chapter 1--Selective
Non-Catalytic Reduction (page 1-9). SNCR systems have similar
equipment to reduce NO<INF>X</INF> emissions as SCR systems and both
utilize a reagent like urea or NH<INF>3,</INF> but SNCR relies on a
higher flue gas temperature at the point of injection instead of a
catalyst to reduce NO<INF>X.</INF> Efficiencies typically range from
30-70%.

Table 9--Identified Controls at Entergy Independence Power Plant for SN-01 and SN-02 Boilers and Feasibility
Determinations
----------------------------------------------------------------------------------------------------------------
Identified control
Unit Pollutant controlled technologies Technically feasible?
----------------------------------------------------------------------------------------------------------------
SN-01 and 02 Boilers............... SO2 and NOX........... Fuel Switch from Coal to No.
Gas.
SO2................... Wet Flue Gas Yes.
Desulfurization (WFGD)
\111\.
Spray Dry Absorber (SDA) Yes.
\112\.
Dry Sorbent Injection (DSI) Yes.
\113\.
Enhanced DSI \114\......... Yes.
NOX................... Select Catalytic Reduction Yes.
(SCR) \115\.
Select Non-Catalytic Yes.
Reduction (SNCR) \116\.
----------------------------------------------------------------------------------------------------------------

[[Page 43047]]

Fuel switchin from coal to natural gas was determined to be not
technically feasible because it would involve significant modifications
to the plant that have not been demonstrated in similarly sized units.
A switch to natural gas would also require constructing a new natural
gas supply pipeline to serve the site. For these reasons, fuel
switching to natural gas was not further evaluated as a potential
control strategy.
Control Effectiveness. DEQ determined the anticipated emission
reductions and control effectiveness for each of the six technically
feasible control technologies identified for the SN-01 and SN-02
Boilers as presented in Entergy's report (see Table 10).\117\ Entergy
provided baseline SO<INF>2</INF> and NO<INF>X</INF> emission rates on
both an annualized maximum monthly emission rate basis and an
annualized average monthly emission rate basis from the baseline period
of November 1, 2018, to December 31, 2019, for the SN-01 Boiler; and
January 1, 2018, to December 31, 2019, for the SN-02 Boiler. The
average monthly emission rate basis was used by DEQ to estimate the
potential emission reductions.
---------------------------------------------------------------------------

\117\ See Tables V-7 and V-8 (pages V-19 to V-20) of the 2022
Planning Period II SIP.

Table 10--Control Effectiveness and Expected Emission Reductions for the Technically Feasible Controls for the SN-01 and SN-02 Boilers at Entergy
Independence Power Plant
--------------------------------------------------------------------------------------------------------------------------------------------------------
Control Baseline rate Controlled rates Emission
Unit Identified Pollutant efficiency (%) (avg. monthly -------------------------------- reduction
technology [dagger] basis) (tpy) lb/MMBtu ** tpy [dagger] (tpy)
--------------------------------------------------------------------------------------------------------------------------------------------------------
SN-01 Boiler................... WFGD.............. SO2................ 92 9,945 0.04 841 9,104
SDA............... 87 9,945 0.06 1,261 * 8,684
Enhanced DSI...... 68 9,945 0.15 3,153 6,792
DSI............... 26 9,945 0.35 7,358 2,587
SCR............... NOX................ 66 3,423 0.055 1,156 2,267
SNCR.............. 20 3,423 0.13 2,733 690
SN-02 Boiler................... WFGD.............. SO2................ 92 10,672 0.04 887 9,786
SDA............... 88 10,672 0.06 1,330 9,342
Enhanced DSI...... 69 10,672 0.15 3,325 7,347
DSI............... NOX................ 27 10,672 0.35 7,759 2,914
SCR............... 62 3,180 0.055 1,219 1,961
SNCR.............. 9 3,180 0.13 2,882 298
--------------------------------------------------------------------------------------------------------------------------------------------------------
* EPA corrected this value in the table which was a typo by the State. See the revised cost spreadsheet in Appendix F of the 2022 Planning Period II
SIP: 7AppF_7 Entergy Independence Post-Comment Period Cost Calculation Revisions.xlsx.
** The bases for the controlled rates in lb/MMBtu were determined in previous analyses as stated in Entergy's revised July 2020 report (pages 2-2, 2-3,
and 3-1) for WFGD,\118\ SDA,\119\ DSI and enhanced DSI,\120\ and NOX Controls (SCR and SNCR).\121\
[dagger] EPA provided controlled rates in tpy (and resulting control efficiencies) from Entergy's revised report (pages 2-4 and 3-2) for a direct
comparison to the baseline tpy values provided by DEQ in Table V-8 of the 2022 Planning Period II SIP.

Cost of Compliance. DEQ reviewed the cost information of the
different identified control strategies provided by Entergy for the SN-
01 and SN-02 Boilers and compared the $/ton values to DEQ's $5,086/ton
cost threshold for EGU boilers (see Table 11). DEQ presented estimated
costs for the control strategies using Entergy's assumptions for
remaining useful life and equipment life in 2019 dollars.\122\ Entergy
---------------------------------------------------------------------------

\118\ The controlled emission rate of 0.04 lb/MMBtu for WFGD is
based on information presented in Entergy's October 2013 Revised
BART Five Factor Analysis for White Bluff Steam Electric Station
(pages 5-3 to 5-4), included in Appendix D of the Phase II SIP
revision from the first planning period.
\119\ The controlled emission rate for SDA is based on
information presented in the following first planning documents:
Entergy's August 18, 2017 Updated BART Five-Factor Analysis for
SO<INF>2</INF> for Unit 1 and 2, (pages 4-1 to 4-3), included in
Appendix D of the Phase II SIP revision from the first planning
period; Sargent & Lundy's (S&L's) August 3, 2017 White Bluff Dry FGD
Cost Estimate and Technical Basis, SL-01283, included in Appendix A
of Entergy's 2020 response to DEQ's information collection request;
and S&L's January 31, 2018 Independence Dry FGD Cost Estimate and
Technical Basis, SL-014308, included in Appendix A of Entergy's 2020
response to DEQ's four-factor information collection request.
\120\ The controlled emission rates for DSI and Enhanced DSI are
based on information presented in the following first planning
period documents: Entergy's August 2017 White Bluff BART report,
(pages 4-1 to 4-3); S&L's August 3, 2017, White Bluff DSI Cost
Estimate Basis Document, SL-014000, and White Bluff Enhanced DSI
Cost Estimate Basis Document, SL-014001, included in Appendix A of
Entergy's 2020 response to DEQ's four-factor information collection
request.
\121\ The controlled emission rates are based on information
presented in Entergy's October 2013 White Bluff BART report, (pages
6-3 to 6-4), and S&L's May 16, 2013, NO<INF>X</INF> Control
Technology Cost and Performance Study, Entergy Services, Inc.--White
Bluff and Lake Catherine, SL-011439, which is included in Appendix B
of Entergy's 2020 response to DEQ's four-factor information
collection request.
\122\ See Tables V-9 and V-10 (pages V-20 to V-22) of the 2022
Planning Period II SIP.

---------------------------------------------------------------------------

[[Page 43048]]

calculated the cost of compliance based on the assumption that the
Independence units will cease coal-fired operations by a cessation date
of December 31, 2030, as required in a Settlement Agreement and Consent
Judgement (Consent Decree) that was entered between Entergy and Sierra
Club.\123\ Based on that cessation date, Entergy used 5.42 years
remaining useful life for DSI and enhanced DSI; and 3.42 years
remaining useful life for all other technologies after consideration of
time necessary for compliance of the evaluated controls. DEQ also
calculated annual costs based on the expected life of the control
equipment in the event that these units would continue to operate with
no assumed operation cessation date. For equipment life, Entergy used
30 years for WFGD, SDA, DSI, Enhanced DSI, and SCR; and 20 years for
SNCR. In addition, DEQ revised its analyses and calculated the
annualized capital costs using the information provided by Entergy and
a 7 percent interest rate. Control cost calculations were completed
using average-monthly baseline emission rates. Cost effectiveness was
also evaluated based on an average of both boiler units because the
units perform an identical function and have the same design.
---------------------------------------------------------------------------

\123\ Sierra Club and National Parks Conservation Association v.
Entergy Arkansas, inc., Entergy Power, LLC, and Entergy Mississippi,
Inc. Case No. 4:18-cv-00854-KGB (ED Ark., March 11, 2021).

Table 11--Estimated Costs of Control Options for SN-01 and SN-02 Boilers (Escalated to 2019) *
----------------------------------------------------------------------------------------------------------------
Total annual costs ($MM/year) Cost-effectiveness ($/ton)
** -------------------------------
--------------------------------
Unit Control option Based on Based on Based on
remaining Based on remaining equipment life
useful life equipment life useful life
----------------------------------------------------------------------------------------------------------------
SN-01 Boiler.................. WFGD............ 173.97 69.43 19,109 7,627
SDA............. 138.35 40.09 15,931 4,616
Enhanced DSI.... 106.45 56.61 15,673 8,335
DSI............. 56.92 30.93 22,001 11,955
SCR............. 67.04 18.57 29,573 8,191
SNCR............ 9.56 7.41 13,861 10,739
SN-02 Boiler.................. WFGD............ 173.97 69.43 17,778 7,095
SDA............. 138.35 40.09 14,809 4,291
Enhanced DSI.... 106.45 56.61 14,489 7,706
DSI............. 56.92 30.93 19,532 10,613
SCR............. 67.04 18.57 34,188 9,469
SNCR............ 9.56 7.41 32,095 24,864
--------------------------------------------------
Boiler Average................ WFGD 18,444 7,361
SDA 15,370 4,454
Enhanced DSI 15,081 8,020
DSI 20,766 11,284
SCR 31,881 8,830
SNCR 22,978 17,802
----------------------------------------------------------------------------------------------------------------
* DEQ revised the cost and cost-effectiveness values obtained from Entergy's report. See spreadsheet in Appendix
F of the 2022 Planning Period II SIP: 7AppF_7 Entergy Independence Post-Comment Period Cost Calculation
Revisions.xlsx.
** The total annual cost values in Table V-9 of the 2022 Planning Period II SIP were transcribed incorrectly.
EPA updated the values to reflect the total annual costs from the spreadsheet in Appendix F.

The cost effectiveness based on a 2030 cessation date to end coal
operations was greater than the costs estimated based on the life of
the different control equipment. Under the assumption of a 2030
cessation date, all of the $/ton values for each of the control
strategies exceeded DEQ's $5,086/ton cost threshold for EGU boilers by
a large margin. In comparison, the $/ton values based on equipment life
all exceeded the cost threshold for EGU boilers except for SDA, which
when averaged over both boiler units, had a cost effectiveness of
$4,454/ton.
Time Necessary for Compliance. DEQ summarized the time estimates
provided by Entergy that would be needed for the different control
options and the basis for each (see Table 12).\124\
---------------------------------------------------------------------------

\124\ See Table V-11 (page V-23) of the 2022 Planning Period II
SIP.
\125\ See FIP Proposal: 80 FR 18944, 18993 (April 8, 2015).
\126\ See 2022 Planning Period II SIP Appendix G for the
FutureFuel Chemical Company regional haze four-factor analysis
response letter prepared by the facility.
\127\ 77 FR 20894, 20944 (April 6, 2012) and 81 FR 43894, 43907
(July 5, 2016), respectively.

Table 12--Time Needed To Comply for Control Options for SN-01 and SN-02
Boilers
------------------------------------------------------------------------
Time for
Control technology compliance Basis for compliance
(years)
------------------------------------------------------------------------
WFGD........................... 5 Time determined in 2016
FIP.\125\
SDA
Enhanced DSI................... 3 Similar estimate in
other analyses
(FutureFuel's response
to DEQ).\126\
DSI
SCR............................ 5 Precedent in Utah and
North Dakota
FIPs.\127\
SNCR
------------------------------------------------------------------------

[[Page 43049]]

The Energy and Non-Air Quality Environmental Impacts of Compliance.
DEQ reported that all of the SO<INF>2</INF> and NO<INF>X</INF> control
options would require waste removal and additional power requirements
that were both factored into the cost of compliance. WFGD and SDA
require increased water usage. WFGD generates large volumes of
wastewater and solid waste/sludge that must be managed and/or treated.
SDA utilizes lime slurry that would generate PM emissions that must be
controlled through use of a baghouse or ESP and then collected and
disposed of through landfilling.\128\ DSI processes would require
substantial storage and transportation. DSI fly ash could not be resold
for beneficial reuse due to the solubility of the sodium salts present
in the waste. SCR would require the disposal of spent catalyst waste.
SCR and SNCR systems would both require storage and transport of
NH<INF>3</INF>. Accidental release of unreacted NH<INF>3</INF> could
react with SO<INF>4</INF>2- and NO<INF>3</INF>-
in the atmosphere to form ammonium sulfate and ammonium nitrate which
are the predominant sources of regional haze. SCR and SNCR would both
require electricity from ancillary equipment that would increase
electrical demand to operate the systems.
---------------------------------------------------------------------------

\128\ Per Entergy's September 27, 2017, Analysis of Reasonable
Progress Arkansas Regional Haze Program First Planning Period
(``Entergy's September 2017 RP Report''), at 6-2, which is included
in Appendix F of Phase II of the first planning period SIP
revisions. Entergy has not indicated unusual circumstances that
would create greater problems than experienced elsewhere that Dry
FGD was utilized as BART. See also the 2018 Phase II SIP revision at
52.
---------------------------------------------------------------------------

Remaining Useful Life. As discussed, DEQ used 5.42 years remaining
useful life for DSI and enhanced DSI; and 3.42 years remaining useful
life for all other control technologies to annualize capital and
indirect costs. These assumptions were based on the time necessary for
compliance and an assumed 2030 cessation date to end coal-fired
operations at the SN-01 and SN-02 Boilers.\129\ As mentioned, DEQ also
evaluated the cost effectiveness based on equipment life of the
different control equipment.\130\ As part of the 2022 Planning Period
II SIP submittal, DEQ included an Administrative Order \131\ that it
entered with Entergy that would render the requirement to cease coal-
fired operations by no later than December 31, 2030, to be federally
enforceable upon final approval by EPA. However, on July 29, 2025,\132\
DEQ sent to EPA a letter determining that inclusion of the
Administrative Order was not needed to fulfill the CAA and RHR
requirements for the second planning period. DEQ requested in the
letter for EPA to approve the remainder of the 2022 Planning Period II
SIP submittal without the Administrative Order for Independence.
---------------------------------------------------------------------------

\129\ See 2022 Planning Period II SIP Appendix F for Entergy's
revised July 23, 2020, response to DEQ's Four-Factor Analysis
information collection request (page 2-4 and 3-2). These remaining
useful life estimates were based on Entergy's assumption of an EPA
approved SIP by July 31, 2022. The SIP is projected to be approved
beyond this date so the cost-effectiveness numbers will be even
higher than estimated in the SIP.
\130\ For equipment life, Entergy used 30 years for WFGD, SDA,
DSI, Enhanced DSI, and SCR; and 20 years for SNCR.
\131\ See Administrative Order (LIS No. 22-084) dated August 2,
2022, and included as part of the 2022 Planning Period II SIP
submittal.
\132\ See letter sent to EPA from DEQ signed by Secretary Khoury
(dated July 28, 2025) and included in the docket of this action.
---------------------------------------------------------------------------

Visibility Considerations. DEQ also evaluated Entergy
Independence's contribution to visibility impairment at the different
Class I areas within and outside Arkansas alongside its consideration
of the four statutory factors. DEQ noted that the AOI analysis
indicated that emissions from Independence impacted five Class I areas
(Caney Creek, Upper Buffalo, Hercules Glades, Mingo, and Sipsey) which
are all on track to make greater progress than the URP glidepath in
2028, even before consideration of potential controls for Independence.
Source apportionment from VISTAS modeling also indicated that
Independence was projected to contribute 1.04 percent of the total
SO<INF>4</INF>2- point source visibility impacts and 0.01
percent of total NO<INF>3</INF>- point source visibility
impacts on the most impaired days in 2028 at Shining Rock. However,
Shining Rock is also on track to make greater progress than the URP
glidepath in 2028 before consideration of potential controls for
Independence.
Proposed Reasonable Progress Control Determination for Entergy
Independence. DEQ determined in its 2022 Planning Period II SIP and
clarified in the July 29, 2025, letter to EPA that no additional
controls are necessary for Entergy Independence to make reasonable
progress during the second planning period. In making that
determination, the 2022 Planning Period II SIP outlines how the four
statutory factors were considered for control technologies that the
State identified to reduce SO<INF>2</INF> and NO<INF>X</INF> emissions
at the SN-01 and SN-02 Boilers. DEQ initially determined that
additional controls would not be cost effective because the cost-
effectiveness values for each control option, based on the required
December 31, 2030, cessation date from the consent decree and Agreed
Order, exceeded the cost threshold for EGU boilers. However, in its
July 29, 2025, letter sent to EPA, DEQ indicated that after
reconsidering its initial determination to include the Administrative
Order (LIS No. 22-084) for Entergy Independence, the SIP submittal
would meet the RHR and CAA requirements for the second planning period
without the requirements contained in the Administrative Order. DEQ
also noted in the letter that the Administrative Order's requirement to
cease coal use at Entergy Independence by December 31, 2030, was
previously set by a separate 2021 District Court order (Case No.
4:18cv854). In addition to DEQ's determination of no additional
controls needed, DEQ noted in its 2022 Planning Period II SIP that all
Class I areas for which Independence was within the AOI are on track to
make greater reasonable progress than the URP glidepath in 2028 before
any additional controls at Independence.
EPA is proposing to find that the State's determination of no
additional controls for the SN-01 and SN-02 Boilers at the Entergy
Independence Power Plant is reasonable and meets regional haze
requirements for the second planning period. After appropriately
identifying the boilers for potential controls, the State adequately
took into consideration the four statutory factors on the selected
control technologies and determined that the evaluated controls were
not necessary to make reasonable progress for the second planning
period. In addition to the four factor analyses of additional controls,
the Class I areas (Upper Buffalo, Hercules Glades, Caney Creek, Mingo,
Sipsey) \133\ impacted by Entergy Independence are projected to be
below their respective 2028 URP glidepath values with existing
controls. Therefore, we are proposing to find that Arkansas
demonstrated that it is making reasonable progress for the second
planning period without requiring any additional controls for the
Entergy Independence Power Plant.
---------------------------------------------------------------------------

\133\ See the 2022 Planning Period II SIP (page V-24). The
Entergy Independence Power Plant visibility surrogate value was 26
percent of the total source impacts for the Upper Buffalo AOI and 20
percent for the Hercules Glades AOI. Caney Creek, Mingo, and Sipsey
AOI total source impacts were each impacted by 5 percent, 3 percent,
and 1 percent, respectively, by Independence. See also 2022 Planning
Period II SIP Appendix C spreadsheet: 7AppC_Arkansas Source
Screening Method Spreadsheet-v8.xlsx.
---------------------------------------------------------------------------

c. FutureFuel Chemical Company
Facility Information. DEQ selected FutureFuel Chemical Company
(FutureFuel), located in Batesville, Arkansas for further analysis. A
three-

[[Page 43050]]

boiler system (collectively known as 6M01-01) was identified by the
State as a source that emitted a total of 2,132 tpy SO<INF>2</INF>
emissions and a total of 323 tpy NO<INF>X</INF> emissions in 2016.\134\
DEQ identified potential SO<INF>2</INF> and NO<INF>X</INF> control
technologies for each of the three boilers in its January 8, 2020,
information request letter to the facility.\135\
---------------------------------------------------------------------------

\134\ The three boilers emit 99 percent of the SO<INF>2</INF>
and 72 percent of the NO<INF>X</INF> from the facility There are
other emission units that emit SO<INF>2</INF> and NO<INF>X</INF>, or
both including: two natural gas-fired boilers, a regenerative
thermal oxidizer, thermal oxidizers and caustic scrubbers, a
chemical waste destructor, a flare, two hot oil systems, a diesel
glycol pump, two diesel waste disposal pumps, a diesel generator,
and a diesel fire water pump.
\135\ See Appendix G-1 of the document: 7AppG__FutureFuel_4-
factor.pdf in Appendix G of the 2022 Planning Period II SIP for
DEQ's Information Collection Request to Futurefuel Chemical Company.
---------------------------------------------------------------------------

The three-boiler system was installed in 1975, and each boiler is
rated for 70 MMBtu/hr. All three boilers share a common primary fuel
conveying system, a common ash handling system, and a common 200 ft
tall stack. The three boilers are balanced draft, coal-fired steam
generation boilers that have been fitted with atomizing nozzles to
facilitate burning of liquid chemical wastes. Each coal fired boiler is
equipped with its own ESP to control PM emissions. The units do not
have existing SO<INF>2</INF> or NO<INF>X</INF> emission controls but
are subject to emission limits for the three-boiler system of 1,391 pph
SO<INF>2</INF> (5,982.9 tpy) and 106 pph NO<INF>X</INF> (488.2 tpy),
contained in the facility's permit.\136\ FutureFuel is also subject to
a permit condition that prohibits combustion of coal with sulfur
content greater than 3.8 percent by weight. The three coal fired
boilers are also subject to 40 CFR part 63, subpart EEE, National
Emission Standards for Hazardous Air Pollutants (NESHAP) from Hazardous
Waste Combustors. Due to size and installation date, these boilers are
not subject to any of the NSPS requirements.
---------------------------------------------------------------------------

\136\ See DEQ air permit No. 1085-AOP-R-16 issued June 21, 2023.
---------------------------------------------------------------------------

Technically Feasible Controls. FutureFuel responded to DEQ's
information collection request in a response letter dated April 7, 2020
(with follow up consultations),\137\ which provided the facility's
evaluation of 15 potential controls identified by DEQ. Based on the
information provided by FutureFuel, DEQ determined that 12 of the
control measures would be technically feasible for the boilers (see
Table 13).
---------------------------------------------------------------------------

\137\ See Appendix G-2 of the document: 7AppG__FutureFuel_4-
factor.pdf in Appendix G of the 2022 Planning Period II SIP for the
FutureFuel Chemical Company regional haze four-factor analysis
response letter prepared by the facility. For follow up
consultations (see Appendices G-3 to G-7), DEQ requested FutureFuel
(July 20, 2020, email) to review the cost and cost-effectiveness
calculations; provide additional technical justifications regarding
the NPDES limit for the WFGD option; and provide feedback for not
choosing low sulfur coal less than 1.5 percent. The facility
provided feedback in a July 23, 2020, email.

Table 13--Identified Controls for Three Coal Fired Boilers at FutureFuel and Feasibility Determinations
----------------------------------------------------------------------------------------------------------------

----------------------------------------------------------------------------------------------------------------
Pollutant controlled Identified technology Technically
feasible?
----------------------------------------------------------------------------------------------------------------
SO2 and NOX............................. Fuel Switch from Coal to Retrofit 1 boiler......... yes
Gas.
Retrofit 3 boilers........ yes
Replace 1 boiler.......... yes
Replace 3 boilers......... yes
SO2..................................... Scrubber Strategies....... WFGD with Lime Slurry..... yes
WFGD with Sodium Hydroxide no
(NaOH).
SDA....................... yes
DSI....................... yes
Fuel Switch to Low Sulfur 2.5% Sulfur Content....... yes.
Coal.
2.0% Sulfur Content....... yes
1.5% Sulfur Content....... yes
Less than 1.5% Sulfur no
Content.
NOX..................................... Post Combustion Control of SCR....................... yes
Flue Gas.
SNCR...................... yes
Low-NOX Burners........... no
----------------------------------------------------------------------------------------------------------------

Three of the controls were not technically feasible. DEQ concluded
that WFGD utilizing NaOH reagent to scrub SO<INF>2</INF> gas in the
exit stream was technically infeasible because the facility could
exceed its National Pollution Discharge Elimination System (NPDES)
SO<INF>4</INF>2- permit limit of 70,000 ppd by 3,000 ppd due
to salt formation from NaOH addition. DEQ noted that it could
accommodate the additional 3,000 ppd SO<INF>4</INF>2- with a
permit modification but decided to assess lime slurry instead as an
alternative reagent since it is similar in cost and efficiency as NaOH.
DEQ noted that it considers its assessment of WFGD with lime slurry as
sufficient to apply to both reagents. DEQ determined that fuel
switching to low sulfur coal with a sulfur content less than 1.5
percent was technically infeasible after considering three coal supply
options. FutureFuel considered low sulfur coal from a nearby plant (0.5
percent sulfur content), coal from Wyoming Powder River Basin, and coal
from Uinta Basin. The local plant and the Powder River Basin coal
supplies were not usable for stoker style boilers because their heating
values and fusion temperatures are less than the design requirements of
FutureFuel's three coal-fired boilers which requires at least 11,000
Btu/lb and a minimum temperature of 2,550 [deg]F. Uinta Basin coal
supply had a sufficient heating value, but the coal did not meet the
minimum required fusion temperature and the distance of the plant would
require trucking fleet upgrades. Lastly, after reviewing the RBLC
database, DEQ determined that low NO<INF>X</INF> burners were
technically infeasible because they have not been implemented for
industrial coal fired stoker boilers as part of NSR. In addition, low
NO<INF>X</INF> burners are not listed as an available control strategy
for industrial coal-fired stoker boilers in EPA's Air Pollution Control
Cost Manual.\138\
---------------------------------------------------------------------------

\138\ See EPA Air Pollution Cost Control Manual Section 4--
NO<INF>X</INF> Controls Chapter 1--Selective Non-Catalytic Reduction
(page 1-2). Table 1.2, which identifies no available urea-based SNCR
for stoker-fired.
\139\ See Table V-12 (page V-29) of the 2022 Planning Period II
SIP.
---------------------------------------------------------------------------

Control Effectiveness. DEQ determined the anticipated emission
reductions and control effectiveness for each technically feasible
control

[[Page 43051]]

technology identified for the three coal-fired boilers (see Table
14).\139\ FutureFuel provided baseline SO<INF>2</INF> and
NO<INF>X</INF> emission rates annualized on both a maximum monthly
emission rate basis and an annualized average monthly emission rate
basis for the baseline period 2017-2019. Maximum monthly emissions are
used to ensure that cost estimates for control technologies have
appropriately sized equipment. DEQ used the annualized average monthly
emission rate basis to estimate the potential emission reductions for
each identified control technology. The average baseline emissions
rates for the three coal-fired boilers were calculated to be 2,171 tpy
SO<INF>2</INF> and 247 tpy NO<INF>X.</INF>

Table 14--Control Effectiveness and Expected Emission Reductions for Potential Controls for the Three Boiler
System
----------------------------------------------------------------------------------------------------------------
Control efficiency Baseline rate avg. Emission reductions (tpy)
(%) monthly basis (tpy) --------------------------------
Identified technology --------------------------------------------
SO2 NOX SO2 NOX SO2 NOX Both
----------------------------------------------------------------------------------------------------------------
Fuel Switch from Coal to Gas: *
Retrofit 1 boiler **........... 32 30 2,171 247 690 74 764
Retrofit 3 boilers............. 99 90 2,171 247 2,149 222 2,371
Replace 1 boiler **............ 32 30 2,171 247 690 74 764
Replace 3 boilers.............. 99 90 2,171 247 2,149 222 2,371
Scrubber Strategies:
WFGD with Lime Slurry.......... 94 N/A 2,171 N/A 2,041 N/A 2,041
SDA............................ 92 N/A 2,171 N/A 1,997 N/A 1,997
DSI............................ 40 N/A 2,171 N/A 868 N/A 868
Fuel Switch to Low Sulfur Coal:
2.5% Sulfur.................... 10 N/A 2,171 N/A 215 N/A 215
2.0% Sulfur.................... 27 N/A 2,171 N/A 591 N/A 591
1.5% Sulfur.................... 44 N/A 2,171 N/A 966 N/A 966
Post Combustion Control:
SCR............................ N/A 80 N/A 247 N/A 197 197
SNCR........................... N/A 40 N/A 247 N/A 99 99
----------------------------------------------------------------------------------------------------------------
* DEQ revised the cost of fuel for natural gas scenarios to reflect the incremental change in cost of using
natural gas compared to coals currently in use for boilers based on EIA data. See FutureFuel's revised cost
spreadsheets in Appendix G of the 2022 Planning Period II SIP: 7AppG_7_Futurefuel Post-Comment Period Cost
Calculation Revisions.xlsx.
** The SO2 emissions are estimated from fuel usage records based on feed stream analysis that assumes all sulfur
entering the boilers through fuel is emitted as SO2. The average emission rate for coal burned was 5.1 lb/
MMBtu (2,092 tons) and the average emission rate for all fuels burned during the baseline was 4.6 lb/MMBtu
(2,171 tons). For the option of retrofitting or replacing one boiler for natural gas, DEQ took the baseline
rate of 2,092 tpy for `coal burned' and multiplied that by a 33 percent control efficiency to give 690 tpy SO2
reduced. DEQ then applied the baseline rate of 2,171 tpy `for all fuels burned' to determine the SO2 control
efficiency for these options: 690 tpy / 2,171 tpy = 32 percent. Note that the values are rounded. See
spreadsheet in Appendix G of the 2022 Planning Period II SIP for details.

Cost of Compliance. DEQ reviewed the cost information of the
different identified control strategies provided by FutureFuel for the
three coal-fired boilers and compared the $/ton values to DEQ's $3,328/
ton cost threshold for industrial boilers (see Table 15).\140\ DEQ
revised its analyses and calculated the annualized capital costs using
the information provided by FutureFuel and a 7 percent interest rate.
After consultation with EPA and other states, DEQ also calculated cost-
effectiveness based on annual average emission rates for the three
coil-fired boilers instead of a max monthly basis. DEQ made various
revisions to the cost calculations provided by FutureFuel for
consistency with the EPA control cost manual and similar technology
assessments made during the first planning period for regional haze:
\141\
---------------------------------------------------------------------------

\140\ See Tables V-13 and V-14 (pages V-31 to V-32) of the 2022
Planning Period II SIP.
\141\ See FutureFuel's revised cost spreadsheets in Appendix G
of the 2022 Planning Period II SIP: 7AppG_7_Futurefuel Post-Comment
Period Cost Calculation Revisions.xlsx.
---------------------------------------------------------------------------

<bullet> Contingency costs were revised to 20 percent of total
capital investment.\142\
---------------------------------------------------------------------------

\142\ The EPA Control Cost Manual (Chapter 2, page 30) suggests
using 20 percent of total capital investment for contingency for
study level cost estimates and 5-15 percent for ``mature control
technologies.''
---------------------------------------------------------------------------

<bullet> AFUDC and owner's costs were removed consistent with EPA
Control Cost Manual overnight estimation methodology.\143\
---------------------------------------------------------------------------

\143\ EPA Control Cost Manual overnight estimation methodology
(Chapter 2, pages 11 and 17).
---------------------------------------------------------------------------

<bullet> All line-item costs estimated using total capital
investment were revised to reflect changes in contingency and removal
of the disallowed costs.\144\
---------------------------------------------------------------------------

\144\ Using formulas provided by the EPA Control Cost Manual
(Chapter 2, page 35): Administrative costs = 2 percent of capital
investment; Property tax = 1 percent of capital investment;
Insurance = 1 percent of capital investment.
---------------------------------------------------------------------------

<bullet> The cost of fuel for natural gas scenarios was revised to
reflect the incremental change in cost of using natural gas compared to
coal currently in use for boilers based on EIA data. The costs
associated with electrical, maintenance, operating and support labor,
permitting and compliance were removed because they do not represent
cost increases above the current cost of using coal.\145\
---------------------------------------------------------------------------

\145\ See email from Philip Antici on July 23, 2020, in Appendix
G for follow-up consultation about cost and cost-effectiveness.
---------------------------------------------------------------------------

<bullet> Costs for each lower sulfur content coal scenario were
revised to reflect the incremental cost of the scenario above current
costs for coal. The tax associated with the 1.5 percent sulfur coal
control scenario was adjusted to remove cost of transportation from the
taxable amount and costs were adjusted to reflect the incremental
increase in cost above current stocks for each of the lower sulfur coal
strategies (2.5, 2, and 1.5 percent).\146\
---------------------------------------------------------------------------

\146\ See email from Philip Antici on 7/23/2020 in Appendix G
for follow-up consultation about cost and cost-effectiveness; see
also spreadsheet titled 7AppG-5_FutureFuel Baseline Heat Input.xlsx
---------------------------------------------------------------------------

<bullet> Lastly, equipment life for each control technology was
revised to be consistent with EPA control cost manual and similar
technology assessments made during the first planning period for
regional haze.\147\
---------------------------------------------------------------------------

\147\ WFGD: 30 years; SDA: 30 years; DSI: 30 years; SCR: 30
years; and SNCR: 20 years.

[[Page 43052]]

Table 15--Estimated Costs of Controls of Three Coal-Fired Boilers (Escalated to 2019) \148\
----------------------------------------------------------------------------------------------------------------
Annual
Annualized operating & Indirect Cost
Identified technology capital maintenance annual costs Total annual effectiveness
investment ($/ costs ($/year) ($/year) ** costs ($/year) ($/ton)
year) ** **
----------------------------------------------------------------------------------------------------------------
Fuel Switch from Coal to Gas:
Retrofit 1 boiler........... 532,814 8,267,445 280,024 9,080,283 [dagger]
11,881
Retrofit 3 boilers.......... 1,029,535 24,758,948 588,801 26,377,284 [dagger]
11,124
Replace 1 boiler............ 680,133 8,267,445 353,147 9,300,725 [dagger]
12,170
Replace 3 boilers........... 1,082,258 24,758,948 614,970 26,456,177 [dagger]
11,156
Scrubber Strategies:
WFGD with Lime Slurry....... 5,594,635 3,043,215 4,388,002 13,025,851 6,383
SDA......................... 4,808,346 2,067,599 3,384,422 10,260,367 5,137
DSI......................... 4,737,737 921,467 2,643,393 8,302,597 9,561
Fuel Switch to Low Sulfur Coal:
2.5% Sulfur................. N/A 738,720 N/A [Dagger] 3,430
738,720
2.0% Sulfur................. N/A 1,282,500 N/A [Dagger] 2,171
1,282,500
1.5% Sulfur................. N/A 2,679,500 N/A [Dagger] 2,774
2,679,500
Post Combustion Control:
SCR......................... 3,725,537 541,053 1,992,806 6,259,396 31,720
SNCR........................ * 2,424,063 413,695 6,584 * 2,844,342 * 28,828
----------------------------------------------------------------------------------------------------------------
* EPA is correcting these cost values to reflect the revised 20-year life instead for SNCR. DEQ mentioned
revising the SNCR cost values to reflect a 20-year life but reported the cost/ton values in Table V-14 (page V-
32) of the 2022 Planning Period II SIP using a 30-year life instead.
** EPA is including these columns from DEQ's revised cost spreadsheet to give a breakdown of the total costs.
[dagger] DEQ reported the cost/ton values for fuel switching from coal to gas for SO2 only in Table V-14 (page V-
31) of the 2022 Planning Period II SIP. EPA is correcting these to reflect combined SO2 and NOX values in
DEQ's revised cost spreadsheet in Appendix G.
[Dagger] DEQ provided total annual cost calculations for switching to low sulfur coal based on quotes from coal
brokers in $/ton for each coal ($13.68/ton for 2.5 percent sulfur coal; $23.75/ton for 2 percent sulfur coal;
and $50.39/ton for 1.5 percent sulfur coal) and assuming a max usage of 50,000 tons each and an 8 percent
usage tax. For example, 2 percent sulfur coal total annual cost = $23.75/ton x 50,000 tons x 1.08 = $1,282,500/
year.

The cost effectiveness values showed that fuel switching to 2
percent sulfur content coal and fuel switching to 1.5 percent sulfur
content coal were below DEQ's $3,328/ton cost threshold for industrial
boilers and were found to be cost-effective strategies for FutureFuel.
The $/ton values of all other potential control strategies were above
DEQ's cost threshold. DEQ concluded that switching to 2 percent sulfur
content coal was the most cost-effective strategy. However, after
discussions with FutureFuel representatives and consideration of public
comments received on the proposed SIP, DEQ concluded that a commitment
by FutureFuel to switch to 1.5 percent sulfur content coal also offered
a cost-effective control with even greater visibility benefits for
Upper Buffalo and Hercules Glades Class I areas.
---------------------------------------------------------------------------

\148\ DEQ revised the cost values obtained from FutureFuel's
report in response to public comments. See DEQ's revised cost
spreadsheet in Appendix G of the 2022 Planning Period II SIP:
7AppG_7_Futurefuel Post-Comment Period Cost Calculation
Revisions.xlsx.
\149\ See Table V-15 (pages V-32 to V-33) of the 2022 Planning
Period II SIP.
---------------------------------------------------------------------------

Time Necessary for Compliance. DEQ reviewed the time estimates
provided by FutureFuel that would be needed for the different control
options to meet compliance deadlines for the three coal-fired boilers
and provided the times of compliance that were reasonable along with
the basis for each (see Table 16).\149\

Table 16--Time Needed To Comply for Control Options for the Coal-Fired
Boilers
------------------------------------------------------------------------
Time for
Identified technology compliance Basis for compliance
(years)
------------------------------------------------------------------------
Fuel Switch from Coal to Gas:
Retrofit one boiler........ 2 <bullet> All options
require time for
engineering design,
DEQ review and
approval, and
logistics for shipping
waste off-site.
Replace one boiler......... <bullet> Retrofitting
options also require
time for demolition of
old feed system,
installation of
natural gas system,
and optimization.
Retrofit all three boilers. 4 <bullet> Replacing
options also require
time for equipment
fabrication, delivery,
and construction.
Replace all three boilers.. 2.5
SO2 Scrubber Strategies:
WFGD with Lime Slurry...... 6 Time for engineering
design, DEQ review and
approval, vendor and
equipment selection,
demolition, delivery,
construction,
training, and startup.
SDA........................ 4
DSI........................ 3
Fuel Switch to Low Sulfur Coal:
2.5% Sulfur................ 3 Time to complete
contracts and exhaust
existing coal
stockpile.
2.0% Sulfur
1.5% Sulfur
NOX Post Combustion Controls:

[[Page 43053]]

SCR........................ * 4 Time necessary for
engineering design,
DEQ review and
approval, vendor and
equipment selection,
demolition or movement
of an existing
building, purchase and
installation of
equipment, training,
and start-up.
SNCR
------------------------------------------------------------------------
* This was recommended as 5 years in FutureFuel's Response to DEQ in
Appendix G of 2022 Planning Period II SIP (pages 43 and 46).

The Energy and Non-Air Quality Environmental Impacts of Compliance.
DEQ reported that

[…truncated; see source link]

View on FederalRegister.gov →Plain-text source

Indexed from Federal Register on September 5, 2025.

This is legal information, not legal advice. Laws vary by jurisdiction and change frequently. Always verify current law with official sources and consult a licensed attorney in your jurisdiction for advice on your specific situation.