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

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

https://www.regulations.gov.

Follow the online instructions for submitting comments. Once submitted, comments cannot be edited or removed from

Regulations.gov.

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,

grady.james@epa.gov.

For the full EPA public comment policy, information about CBI or multimedia submissions, and general guidance on making effective comments, please visit

https://www.epa.gov/dockets/commenting-epa-dockets.

Docket:

The index to the docket for this action is available electronically at

www.regulations.gov.

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

2

Section, (214) 665-6745;

grady.james@epa.gov.

We encourage the public to submit comments via

https://www.regulations.gov.

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

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

https://www.federalregister.gov/documents/2017/01/10/2017-00268/protection-of-visibility-amendments-to-requirements-for-State-plans#h-16.

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

2.5

) and their precursors but also coarse mass.

4

(PM)

2.5

particles consist of sulfates (SO

4

2−

), nitrates (NO

3

−

), organic carbon, elemental carbon, and soil dust. Precursors that react in the atmosphere to form PM

2.5

consist of sulfur dioxide (SO

2

), nitrogen oxides (NO

X

), and, in some cases, volatile organic compounds (VOC) and ammonia (NH

3

). PM

2.5

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

2.5

but less than PM

10

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

X

, SO

2

, and PM

10

; 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

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

2

, NO

X

, and PM

10

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

2

and NO

X

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

X

SIP revision) to address NO

X

BART requirements for all electric generating units (EGUs) and the reasonable progress requirements with respect to NO

X

. The Arkansas Regional Haze NO

X

SIP submittal replaced all source-specific NO

X

BART determinations for EGUs established in the FIP with reliance upon the Cross-State Air Pollution Rule (CSAPR) emissions trading program for ozone (O

3

) season NO

X

as an alternative to NO

X

BART. The SIP submittal addressed the NO

X

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

X

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

X

SIP revision and to withdraw the corresponding NO

X

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

2

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

2

and PM

10

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

2

and PM

10

BART requirements for Bailey Unit 1; SO

2

and PM

10

BART requirements for McClellan Unit 1; SO

2

BART requirements for Flint Creek Boiler No. 1; SO

2

BART requirements for White Bluff Units 1 and 2; SO

2

, NO

X

, and PM

10

BART requirements for the White Bluff Auxiliary Boiler; and included a requirement that Lake Catherine Unit 4 not burn fuel oil until SO

2

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

2

and PM

10

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

2

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.

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

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).

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

In this 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

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

3

and EWRT SO

4

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.

https://www.epa.gov/sites/default/files/2018-12/documents/technical_guidance_tracking_visibility_progress.pdf

.

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

Class I areas

Visibility (dv)

Baseline

(2000-2004)

Current

(2015-2019)

Natural conditions

(2064)

Caney Creek Wilderness

11.24

7.79

4.23

Upper Buffalo Wilderness

11.71

8.17

4.18

Table 2—Visibility at Arkansas Class I Areas for 20 Percent Most Impaired Days

Class I areas

Visibility (dv)

Baseline

(2000-2004)

Current

(2015-2019)

Natural conditions

(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

Class I areas

Progress during

planning period I *

(dv)

Total progress

to date **

(dv)

Additional progress

needed for natural

conditions †

(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.

† 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

Class I areas

Progress during

planning period I *

(dv)

Total progress

to date **

(dv)

Additional progress

needed for natural

conditions †

(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.

† 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

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).

https://www.epa.gov/visibility/technical-support-document-epas-updated-2028-regional-haze-modeling.

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

Class I areas

Most current

(2015-2019)

(dv)

2028

Adjusted URP

(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.

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

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

2

and NH

3

precursor emissions for control since they are associated with ammonium sulfate, and NO

X

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

2

, NO

X

, and NH

3

(the targeted precursor pollutants); as well as VOC (a precursor to a lesser extent), and primary PM

2.5

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

3

. 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

3

and VOC as well as directly emitted PM

2.5

from consideration because the majority of emission categories in those inventories could not be controlled by the State. Nearly all of the 2017 NH

3

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

3

as a potential precursor pollutant control to reduce ammonium sulfate in the State's long-term strategy. Similarly, DEQ eliminated primary PM

2.5

as a potential pollutant to control since 85 percent of primary PM

2.5

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

2

and NO

X

emissions for control as a result. For 2017 SO

2

and NO

X

emissions, DEQ reported that 89% (57,213 tpy) of the total 64,284 tpy SO

2

emissions and 35% (68,608 tpy) of the total 196,022 tpy NO

X

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

2

and NO

X

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

3

inventory consisting of agricultural NH

3

(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

2.5

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

X

and SO

2

inventories; and Tables IV-4 and IV-5 showing the 2011, 2014, and 2017 categorized emissions of NO

X

and SO

2

(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

2

and NO

X

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

X

and SO

2

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

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

2

and NO

X

as the primary anthropogenic particulate species precursors (for SO

4

2−

and NO

3

−

, 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

X

and SO

2

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

2

and NO

X

(precursors of SO

4

2-

and NO

3

-

, respectively), the EWRT values for SO

4

2−1

and NO

3−

were combined with emissions from sources of SO

2

and NO

X

. CenSARA states chose to focus on EGU and non-EGU point sources since these sources comprise major fractions of the NO

X

and SO

2

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

X

results and 2016 EWRT SO

2

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

X

and SO

2

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

2

and NO

X

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

2

and NO

X

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

X

and SO

2

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,

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

2

or NO

X

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 Station

—Caney Creek.

Louisiana

CLECO Power LLC Dolet Hills

—Caney Creek.

—Upper Buffalo.

Entergy Louisiana LLC—Roy S Nelson Plant

—Caney Creek.

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 Plant

—Upper Buffalo.

New Madrid Power Plant Marston

—Upper Buffalo.

City Utilities of Springfield Missouri John Twitty Energy Center

—Upper Buffalo.

Thomas Hill Energy Center Power Division

—Upper Buffalo.

Illinois

Prairie Generating Station

—Upper Buffalo.

Indiana

Indiana Michigan Power DBA AEP Rockport

—Upper Buffalo.

Duke Energy Indiana LLC—Gibson Genera

—Upper Buffalo.

Kentucky

Tennessee Valley Authority (TVA)—Shawnee Fossil Plant

—Upper Buffalo.

DEQ performed a source screening sensitivity analysis which omitted recently controlled or shut down SO

2

and NO

X

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

2

reductions from installed 2018 controls. DEQ performed this sensitivity analysis for each Class I area

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

X

and SO

2

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

X

unit (100 tons per year (tpy) or greater) and none for SO

2

. The NO

X

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

2

emission unit (100 tpy or greater) and none for NO

X

. 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

X

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

2

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

2

and/or NO

X

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

Facility

Class I areas impacted

Units

Existing SO

2

controls

Existing NO

X

controls

Entergy White Bluff Power Plant

—Caney Creek

—Upper Buffalo.

—Hercules Glades.

Two Coal-fired EGU Boilers: (SN-01 and SN-02)

—Low Sulfur Coal

—0.60 lb/MMBtu SO

2

limit for each unit.

Low NO

X

Burners with Overfire Air.

Entergy Independence Power Plant

—Upper Buffalo (26%)

—Hercules Glades (20%).

—Caney Creek (5%).

—Mingo (3%).

—Sipsey (1%).

Two Coal-Fired EGU Boilers: (SN-01 and SN-02)

Low Sulfur Coal

Low NO

X

Burners with Overfire Air.

FutureFuel Chemical Co

—Upper Buffalo (3%)

—Hercules Glades (2%).

—Caney Creek (<1%).

—Mingo (<1%).

—Sipsey (<1%).

Three Coal-Fired Industrial Boilers: (6M01-01)

None

None.

Domtar Ashdown Mill

—Caney Creek (5%)

—Upper Buffalo (<1%).

—Hercules Glades (<1%).

—Wichita Mtns (<1%).

No. 2 Power Boiler

No. 3 Power Boiler

No. 2 Recovery Boiler

No. 3 Recovery Boiler.

Venturi Scrubbers

None.

Overfire Air.

None.

SWEPCO Flint Creek Power Plant

—Upper Buffalo (1%)

—Hercules Glades (1%).

—Caney Creek (<1%).

One Coal-Fired EGU Boiler (SN-01 Boiler)

—Novel Integrated Desulfurization (Dry FGD)

—0.06 lb/MMBtu SO

2

limit.

—Low NO

X

Burners with Overfire Air.

—0.23 lb/MMBtu.

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

visibility impact surrogate values for each source (summed EWRT*Q/d values for NO

X

and SO

2

) 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

2

and NO

X

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

2

and/or NO

X

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 https://www.epa.gov/sites/default/files/2016-02/menuofcontrolmeasures.xlsx.

91

A shorter baseline period (June 1, 2018-December 31, 2019) was provided for Flint Creek because construction of low NO

X

burners with separated over fire air was completed on May 18, 2018, which reduced NO

X

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.

Table 8—Cost Effectiveness Thresholds for Different Emission Unit Types in 2019 Dollars

Equipment type

Cost

threshold

($/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

2

emissions and a total of 9,719 tpy NO

X

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

2

emissions, are equipped with low NO

X

burners with separated overfire air to control NO

X

emissions, and are equipped with electrostatic precipitators

100

to control PM emissions. For SO

2

control, both boilers are subject to BART and are required to comply with an SO

2

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

X

control measures beyond the low NO

X

burners and low sulfur coal, which have already been implemented at White Bluff to meet its obligations under CSAPR for O

3

season NO

X

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

X

and SO

2

at power plants, such as White Bluff, have not changed since 2018. Because the low NO

X

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

X

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

2

and NO

X

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

2

emissions and a total of 9,864 tpy NO

X

emissions in 2016. DEQ identified potential SO

2

and NO

X

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

X

emissions, both boilers operate with low NO

X

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

3

season NO

X

allocations. The permit

107

contains limits of 6,090 pph NO

X

and 0.7 lb/MMBtu NO

X

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

2

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

2

and NO

X

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

10

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

2

control options and two NO

X

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

2

and Acid Gas Controls Chapter 1—Wet and Dry Scrubbers for Acid Gas Control (page 1-9 to 1-10). WFGD systems control SO

2

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

2

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

2

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

2

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

2

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

2

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

2

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

X

Controls Chapter 2—Selective Catalytic Reduction (page 2-9). SCR systems include a NH

3

storage and delivery system, NH

3

injection grid, and a catalyst reactor. A nitrogen-based reducing agent, such as NH

3

or urea-derived NH

3,

is injected into the post-combustion flue gas. The reagent reacts selectively with the flue gas NO

X

within a specific temperature range and in the presence of the catalyst and oxygen to reduce the NO

X

into molecular nitrogen (N

2

) and water vapor. SCR systems can be designed for NO

X

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

X

controls.

116

See

EPA Air Pollution Cost Control Manual (seventh edition) Section 4—NO

X

Controls Chapter 1—Selective Non-Catalytic Reduction (page 1-9). SNCR systems have similar equipment to reduce NO

X

emissions as SCR systems and both utilize a reagent like urea or NH

3,

but SNCR relies on a higher flue gas temperature at the point of injection instead of a catalyst to reduce NO

X.

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

Unit

Pollutant controlled

Identified control technologies

Technically

feasible?

SN-01 and 02 Boilers

SO

2

and NO

X

Fuel Switch from Coal to Gas

No.

SO

2

Wet Flue Gas Desulfurization (WFGD)

111

Yes.

Spray Dry Absorber (SDA)

112

Yes.

Dry Sorbent Injection (DSI)

113

Yes.

Enhanced DSI

114

Yes.

NO

X

Select Catalytic Reduction (SCR)

115

Yes.

Select Non-Catalytic Reduction (SNCR)

116

Yes.

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

2

and NO

X

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

Unit

Identified technology

Pollutant

Control

efficiency

(%) †

Baseline rate

(avg. monthly

basis)

(tpy)

Controlled rates

lb/MMBtu **

tpy †

Emission

reduction

(tpy)

SN-01 Boiler

WFGD

SO

2

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

NO

X

66

3,423

0.055

1,156

2,267

SNCR

20

3,423

0.13

2,733

690

SN-02 Boiler

WFGD

SO

2

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

NO

X

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 NO

X

Controls (SCR and SNCR).

121

† 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

2

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

X

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.

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) *

Unit

Control option

Total annual costs

($MM/year) **

Based on

remaining

useful life

Based on

equipment life

Cost-effectiveness

($/ton)

Based on

remaining

useful life

Based on

equipment 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

Control technology

Time for

compliance

(years)

Basis for compliance

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

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

DEQ reported that all of the SO

2

and NO

X

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

3

. Accidental release of unreacted NH

3

could react with SO

4

2−

and NO

3

−

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

4

2−

point source visibility impacts and 0.01 percent of total NO

3

−

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

2

and NO

X

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-

boiler system (collectively known as 6M01-01) was identified by the State as a source that emitted a total of 2,132 tpy SO

2

emissions and a total of 323 tpy NO

X

emissions in 2016.

134

DEQ identified potential SO

2

and NO

X

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

2

and 72 percent of the NO

X

from the facility There are other emission units that emit SO

2

and NO

X

, 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

2

or NO

X

emission controls but are subject to emission limits for the three-boiler system of 1,391 pph SO

2

(5,982.9 tpy) and 106 pph NO

X

(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?

SO

2

and NO

X

Fuel Switch from Coal to Gas

Retrofit 1 boiler

yes

Retrofit 3 boilers

yes

Replace 1 boiler

yes

Replace 3 boilers

yes

SO

2

Scrubber Strategies

WFGD with Lime Slurry

yes

WFGD with Sodium Hydroxide (NaOH)

no

SDA

yes

DSI

yes

Fuel Switch to Low Sulfur Coal

2.5% Sulfur Content

yes.

2.0% Sulfur Content

yes

1.5% Sulfur Content

yes

Less than 1.5% Sulfur Content

no

NO

X

Post Combustion Control of Flue Gas

SCR

yes

SNCR

yes

Low-NO

X

Burners

no

Three of the controls were not technically feasible. DEQ concluded that WFGD utilizing NaOH reagent to scrub SO

2

gas in the exit stream was technically infeasible because the facility could exceed its National Pollution Discharge Elimination System (NPDES) SO

4

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

4

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 °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

X

burners were technically infeasible because they have not been implemented for industrial coal fired stoker boilers as part of NSR. In addition, low NO

X

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

X

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

technology identified for the three coal-fired boilers (

see

Table 14).

139

FutureFuel provided baseline SO

2

and NO

X

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

2

and 247 tpy NO

X.

Table 14—Control Effectiveness and Expected Emission Reductions for Potential Controls for the Three Boiler System

Identified technology

Control efficiency

(%)

SO

2

NO

X

Baseline rate avg.

monthly basis

(tpy)

SO

2

NO

X

Emission reductions

(tpy)

SO

2

NO

X

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 SO

2

emissions are estimated from fuel usage records based on feed stream analysis that assumes all sulfur entering the boilers through fuel is emitted as SO

2.

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 SO

2

reduced. DEQ then applied the baseline rate of 2,171 tpy `for all fuels burned' to determine the SO

2

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.

• 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.”

• 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).

• 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.

• 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.

• Costs for each lower sulfur content coal scenario were revised to reflect the incremental cost of the

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