[Federal Register Volume 82, Number 174 (Monday, September 11, 2017)]
[Proposed Rules]
[Pages 42627-42639]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2017-18661]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 52

[EPA-R06-OAR-2015-0189; FRL-9966-97-Region 6]


Approval and Promulgation of Implementation Plans; Arkansas; 
Approval of Regional Haze State Implementation Plan Revision and 
Withdrawal of Federal Implementation Plan for NOX for Electric 
Generating Units in Arkansas

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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SUMMARY: Pursuant to the Federal Clean Air Act (CAA or the Act), the 
Environmental Protection Agency (EPA) is proposing to approve a 
proposed revision to the Arkansas Regional Haze State Implementation 
Plan (SIP) submitted for parallel processing on July 12, 2017, by the 
State of Arkansas through the Arkansas Department of Environmental 
Quality (ADEQ). Specifically, the EPA is proposing to approve the 
State's proposed SIP revision, which addresses nitrogen oxide 
(NOX) requirements for the Arkansas Electric Cooperative 
Corporation (AECC) Bailey Plant Unit 1; AECC McClellan Plant Unit 1; 
the American Electric Power/Southwestern Electric Power Company (AEP/
SWEPCO) Flint Creek Plant Boiler No. 1; Entergy Arkansas, Inc. 
(Entergy) Lake Catherine Plant Unit 4; Entergy White Bluff Plant Units 
1 and 2 and the Auxiliary Boiler; and Entergy Independence Plant Units 
1 and 2. In conjunction with this proposed approval, we are proposing 
to withdraw federal implementation plan (FIP) emission limits for 
NOX that would otherwise apply to the nine aforementioned 
units.

DATES: Written comments must be received on or before October 11, 2017.

ADDRESSES: Submit your comments, identified by Docket No. EPA-R06-OAR-
2015-0189, at http://www.regulations.gov or via email to 
[email protected]. 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 you consider to be 
Confidential Business Information (CBI) or other information whose 
disclosure is restricted by statute. Multimedia submissions (audio, 
video, etc.) must be accompanied by a written comment. The written 
comment is considered the official comment and should include 
discussion of all points you wish to make. The EPA will generally not 
consider comments or comment contents located outside of the primary 
submission (i.e. on the web, cloud, or other file sharing system). For 
additional submission methods, please contact Dayana Medina, 
[email protected]. For the full EPA public comment policy, 
information about CBI or multimedia submissions, and general guidance 
on making effective comments, please visit http://www2.epa.gov/dockets/commenting-epa-dockets.
    Docket: The index to the docket for this action is available 
electronically at www.regulations.gov and in hard copy at the EPA 
Region 6, 1445 Ross Avenue, Suite 700, Dallas, Texas. While all 
documents in the docket are listed in the index, some information may 
be publicly available only at the hard copy location (e.g., copyrighted 
material), and some may not be publicly available at either location 
(e.g., CBI).

FOR FURTHER INFORMATION CONTACT: Dayana Medina, 214-665-7241, 
[email protected]. To inspect the hard copy materials, please 
schedule an appointment with Dayana Medina or Mr. Bill Deese at 214-
665-7253.

SUPPLEMENTARY INFORMATION: Throughout this document wherever ``we,'' 
``us,'' or ``our'' is used, we mean the EPA.

Table of Contents

I. Background
    A. The Regional Haze Program
    B. Our Previous Actions on Arkansas Regional Haze
    C. CSAPR as an Alternative to Source-Specific NOX 
BART
II. Our Evaluation of Arkansas' Proposed Regional Haze SIP Revision
    A. Reliance on CSAPR To Satisfy NOX BART
    B. Reasonable Progress Analysis for NOX
    1. Regional Particulate Source Apportionment Tool (PSAT) Data 
for Caney Creek and Upper Buffalo
    2. Arkansas Source PSAT Data for Caney Creek and Upper Buffalo
    3. Arkansas' Conclusions Regarding Key Pollutants and Source 
Category Contributions
    4. Our Evaluation of Arkansas' Analysis
    C. Required Consultation
III. Proposed Action
    A. Arkansas' Proposed Regional Haze SIP Revision
    B. Partial FIP Withdrawal
    C. Clean Air Act Section 110(l)
IV. Statutory and Executive Order Reviews

I. Background

A. The Regional Haze Program

    Regional haze is visibility impairment that is produced by a 
multitude of sources and activities that are located across a broad 
geographic area and emit fine particulates (PM2.5) (e.g., 
sulfates, nitrates, organic carbon (OC), elemental carbon (EC), and 
soil dust), and their precursors (e.g., sulfur dioxide 
(SO2), NOX, and in some cases, ammonia 
(NH3) and volatile organic compounds (VOCs)). Fine particle 
precursors react in the atmosphere to form PM2.5, which 
impairs visibility by scattering and absorbing light. Visibility 
impairment reduces the clarity, color, and visible distance that can be 
seen. PM2.5 can also cause serious adverse health effects 
and mortality in humans; it also contributes to environmental effects 
such as acid deposition and eutrophication.
    Section 169A of the CAA directs states to evaluate the use of 
retrofit controls at certain larger, often under-controlled, older 
stationary sources in order to address visibility impacts from

[[Page 42628]]

these sources. Specifically, section 169A(b)(2)(A) of the CAA requires 
states to revise their SIPs to contain such measures as may be 
necessary to make reasonable progress toward the natural visibility 
goal, including a requirement that certain categories of existing major 
stationary sources built between 1962 and 1977 procure, install, and 
operate the ``Best Available Retrofit Technology'' (BART). Larger 
``fossil-fuel fired steam electric plants'' are one of these source 
categories. Under the Regional Haze Rule, states are directed to 
conduct BART determinations for ``BART-eligible'' sources that may be 
anticipated to cause or contribute to any visibility impairment in a 
Class I area. Section 169A(g)(2) of the CAA establishes that in 
determining BART, states must take into consideration the following 
five factors: (1) Costs of compliance, (2) the energy and nonair 
quality environmental impacts of compliance, (3) any existing pollution 
control technology in use at the source, (4) the remaining useful life 
of the source, and (5) the degree of improvement in visibility which 
may reasonably be anticipated to result from the use of such 
technology. The evaluation of BART for electric generating units (EGUs) 
that are located at fossil-fuel fired power plants having a generating 
capacity in excess of 750 megawatts must follow the ``Guidelines for 
BART Determinations Under the Regional Haze Rule'' at appendix Y to 40 
CFR part 51 (hereinafter referred to as the ``BART Guidelines''). 
Rather than requiring source-specific BART controls, states also have 
the flexibility to adopt an emissions trading program or other 
alternative program as long as the alternative provides for greater 
progress towards improving visibility than BART.
    The vehicle for ensuring continuing progress towards achieving the 
natural visibility goal is the submission of a series of regional haze 
SIPs that contain long-term strategies to make reasonable progress 
towards natural visibility conditions and establish reasonable progress 
goals (RPGs) for every Class I area within the state. States have 
significant discretion in establishing RPGs,\1\ but are required to 
consider the following factors established in section 169A of the CAA: 
(1) The costs of compliance; (2) the time necessary for compliance; (3) 
the energy and non-air quality environmental impacts of compliance; and 
(4) the remaining useful life of any potentially affected sources. 
States must determine whether additional control measures beyond BART 
and other ``on the books'' controls are reasonable based on a 
consideration of the four reasonable progress factors. States must 
demonstrate in their SIPs how these factors are considered when 
selecting the RPGs for each applicable Class I area. We commonly refer 
to this as the ``reasonable progress analysis'' or ``four factor 
analysis.''
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    \1\ Guidance for Setting Reasonable Progress Goals under the 
Regional Haze Program, June 1, 2007, memorandum from William L. 
Wehrum, Acting Assistant Administrator for Air and Radiation, to EPA 
Regional Administrators, EPA Regions 1-10 (pp. 4-2, 5-1).
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    Additional information about the Regional Haze program can be found 
in the background sections of our previous proposed rulemakings on 
Arkansas regional haze.\2\
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    \2\ See 76 FR 64186 and 80 FR 18944.
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B. Our Previous Actions on Arkansas Regional Haze

    Arkansas submitted a SIP on September 9, 2008, to address the first 
regional haze implementation period. On August 3, 2010, Arkansas 
submitted a SIP revision with non-substantive revisions to the APCEC 
Regulation 19, Chapter 15; this Chapter identified the BART-eligible 
and subject-to-BART sources in Arkansas and established the BART 
emission limits for subject-to-BART sources. On September 27, 2011, the 
State submitted supplemental information to address the regional haze 
requirements. We are hereafter referring to these regional haze 
submittals collectively as the ``2008 Arkansas Regional Haze SIP.'' On 
March 12, 2012, we partially approved and partially disapproved the 
2008 Arkansas Regional Haze SIP.\3\ On September 27, 2016, we published 
a FIP addressing the deficiencies identified in the disapproved 
portions of the 2008 Arkansas Regional Haze SIP (the Arkansas Regional 
Haze FIP).\4\ Among other things, the FIP established NOX 
emission limits under the BART requirements for Bailey Unit 1; 
McClellan Unit 1; Flint Creek Boiler No. 1; Lake Catherine Unit 4; and 
White Bluff Units 1 and 2 and the Auxiliary Boiler. The FIP also 
established NOX emission limits under the reasonable 
progress requirements for Independence Units 1 and 2.
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    \3\ 77 FR 14604.
    \4\ 81 FR 66332; see also 81 FR 68319 (October 4, 2016) 
(correction).
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    In response to petitions submitted by the State of Arkansas and 
industry parties seeking reconsideration and an administrative stay of 
the final Arkansas Regional Haze FIP,\5\ in a letter dated April 14, 
2017, we announced the convening of a proceeding to reconsider several 
elements of the FIP, including the appropriate compliance dates for the 
NOX emission limits for Flint Creek Unit 1, White Bluff 
Units 1 and 2, and Independence Units 1 and 2.\6\ EPA also published a 
notice in the Federal Register on April 25, 2017, administratively 
staying the effectiveness of the 18-month NOX compliance 
dates in the FIP for these units for a period of 90 days.\7\ On July 
13, 2017, the EPA published a proposed rule that would extend the 
NOX compliance dates for Flint Creek Unit 1, White Bluff 
Units 1 and 2, and Independence Units 1 and 2, by 21 months to January 
27, 2020.\8\
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    \5\ See the docket associated with this proposed rulemaking for 
a copy of the petitions for reconsideration and administrative stay 
submitted by the State of Arkansas; Entergy Arkansas Inc., Entergy 
Mississippi Inc., and Entergy Power LLC (collectively ``Entergy''); 
AECC; and the Energy and Environmental Alliance of Arkansas (EEAA).
    \6\ See letter dated April 14, 2017, regarding ``Convening a 
Proceeding for Reconsideration of Final Rule, `Promulgation of Air 
Quality Implementation Plans; State of Arkansas; Regional Haze and 
Interstate Visibility Transport Federal Implementation Plan,' 
published September 7, 2016. 81 FR 66332.'' A copy of this letter is 
included in the docket, Docket No. EPA-R06-OAR-2015-0189.
    \7\ 82 FR 18994.
    \8\ 82 FR 32284.
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C. CSAPR as an Alternative to Source-Specific NOX BART

    In 2005, the EPA published the Clean Air Interstate Rule (CAIR), 
which required 27 states and the District of Columbia to reduce 
emissions of SO2 and NOX that significantly 
contribute to or interfere with maintenance of the 1997 national 
ambient air quality standards (NAAQS) for fine particulates and/or 8-
hour ozone in any downwind state.\9\ EPA demonstrated that CAIR would 
achieve greater reasonable progress toward the national visibility goal 
than would BART; therefore, states could rely on CAIR as an alternative 
to EGU BART for SO2 and NOX.\10\ Although 
Arkansas was subject to certain of the NOX requirements of 
CAIR, including the state-wide ozone season NOX budget but 
not the annual NOX budget, and although this would have been 
sufficient for Arkansas to rely on CAIR to satisfy NOX BART, 
it elected not to rely on CAIR in its 2008 Regional Haze SIP to satisfy 
the NOX BART requirement for its EGUs.
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    \9\ 70 FR 25161 (May 12, 2005).
    \10\ 70 FR 39104, 39139 (July 6, 2005).
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    On July 11, 2008, the D.C. Circuit found CAIR was fatally flawed 
and on December 23, 2008, the Court remanded CAIR to EPA without 
vacatur to ``preserve the environmental benefits

[[Page 42629]]

provided by CAIR''.\11\ In 2011, acting on the D.C. Circuit's remand, 
we promulgated the Cross-State Air Pollution Rule (CSAPR) to replace 
CAIR and issued FIPs to implement the rule in CSAPR-subject states.\12\ 
Arkansas EGUs are covered under CSAPR for ozone season 
NOX.\13\
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    \11\ North Carolina v. EPA, 531 F.3d 896, 901 (D.C. Cir. 2008), 
modified, 550 F.3d 1176, 1178 (D.C. Cir. 2008).
    \12\ 76 FR 48207 (August 8, 2011).
    \13\ 76 FR 82219 (December 30, 2011).
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    In 2012, we issued a limited disapproval of several states' 
regional haze SIPs because of reliance on CAIR as an alternative to EGU 
BART for SO2 and/or NOX.\14\ We also determined 
that CSAPR would provide for greater reasonable progress than BART and 
amended the Regional Haze Rule to allow for CSAPR participation as an 
alternative to source-specific SO2 and/or NOX 
BART for EGUs, on a pollutant-specific basis.\15\ As Arkansas did not 
rely on CAIR to satisfy the NOX BART requirements in the 
2008 Regional Haze SIP, Arkansas was not included in the EPA's limited 
disapproval of regional haze SIPs that relied on CAIR to satisfy 
certain regional haze requirements.\16\ As noted above, in the 2012 
rulemaking in which we promulgated those limited disapprovals, the EPA 
also promulgated FIPs to replace reliance on CAIR with reliance on 
CSAPR in many of those regional haze SIPs; however, Arkansas was 
likewise not included in that FIP action.
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    \14\ The limited disapproval triggered the EPA's obligation to 
issue a FIP or approve a SIP revision to correct the relevant 
deficiencies within 2 years of the final limited disapproval action. 
CAA section 110(c)(1); 77 FR 33642, at 33654 (June 7, 2012).
    \15\ See 40 CFR 51.308(e)(4).
    \16\ See 77 FR 33642, at 33654.
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    CSAPR has been subject to extensive litigation, and on July 28, 
2015, the D.C. Circuit issued a decision generally upholding CSAPR but 
remanding without vacating the CSAPR emissions budgets for a number of 
states.\17\ We are in the process of responding to the remand of these 
CSAPR budgets. On October 26, 2016, we finalized an update to the CSAPR 
rule that addresses the 1997 ozone NAAQS portion of the remand and also 
addresses the CAA requirements regarding interstate transport for the 
2008 ozone NAAQS.\18\ Additionally, three states, Alabama, Georgia, and 
South Carolina, have adopted or committed to adopt SIPs to replace the 
remanded FIPs and will continue the states' participation in the CSAPR 
program with the same budgets. On November 10, 2016, we proposed a rule 
intended to address the remainder of the Court's remand.\19\ This 
separate proposed rule includes a sensitivity analysis showing that the 
set of actions EPA has taken or expects to take in response to the D.C. 
Circuit's decision would not adversely impact the analytic 
demonstration for our 2012 determination that CSAPR participation meets 
the criteria to qualify as an alternative to BART. Based on that 
assessment, the EPA proposed that states may continue to rely on CSAPR 
as being better than BART on a pollutant-specific basis. As of the date 
of this proposed action, EPA has not yet finalized that proposed 
rulemaking. EPA can approve regional haze SIP submissions that rely on 
participation in CSAPR as an alternative to BART only after finalizing 
the November 2016 proposed rule or otherwise determining that 
participation in CSAPR remains a viable BART alternative.
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    \17\ Arkansas' ozone season NOX budget was not 
included in the remand. EME Homer City Generation v. EPA, 795 F.3d 
118, 138 (D.C. Cir. 2015).
    \18\ 81 FR74504 (October 26, 2016).
    \19\ 81 FR 78954 (November 10, 2016).
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II. Our Evaluation of Arkansas' Proposed Regional Haze SIP Revision

    On July 12, 2017, Arkansas submitted a proposed SIP revision with a 
request for parallel processing, addressing the NOX 
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, and Independence Units 1 and 2 (July 2017 Arkansas 
Regional Haze SIP). This proposed SIP revision is the subject of this 
proposed action, in conjunction with our proposed withdrawal of the 
emission limits for NOX that we promulgated in our September 
27, 2016 FIP for the same EGUs addressed in the proposed SIP revision. 
The EPA is proposing action on the SIP revision at the same time that 
ADEQ is completing the corresponding public comment and rulemaking 
process at the state level. The July 2017 SIP revision request will not 
be complete and will not meet all the SIP approvability criteria until 
the state completes the public process and submits the final, adopted 
SIP revision with a letter from the Governor or Governor's designee to 
EPA. The EPA is proposing to approve the SIP revision request after 
completion of the state public process and final submittal.
    Arkansas' July 2017 Regional Haze SIP revision proposal addresses 
certain portions of the 2008 Regional Haze SIP that were partially 
disapproved by EPA on March 12, 2012.\20\ The 2008 Regional Haze SIP 
included source-by-source NOX BART determinations for 
subject-to-BART EGUs in Arkansas. EPA's March 12, 2012 final action on 
the 2008 Regional Haze SIP included disapproval of the State's source-
by-source NOX BART determinations for these EGUs. These EGUs 
are Bailey Unit 1; McClellan Unit 1; Flint Creek Boiler No. 1; Lake 
Catherine Unit 4; White Bluff Units 1 and 2 and its auxiliary boiler. 
EPA's March 12, 2012 final action on the 2008 Regional Haze SIP also 
included a determination that the State did not satisfy the statutory 
and associated regulatory requirements for the reasonable progress 
analysis. We promulgated a FIP on September 27, 2016, that established 
source specific NOX BART emission limits for these seven 
EGUs and NOX emission limits under reasonable progress for 
Independence Units 1 and 2 to address the disapproved portions of the 
2008 Regional Haze SIP submittal.
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    \20\ 77 FR 14604.
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    Arkansas' July 2017 Regional Haze SIP revision addresses the 
NOX BART requirements for Arkansas' EGUs by relying on CSAPR 
as an alternative to BART. The July 2017 Regional Haze SIP revision 
proposal also makes the determination that no additional NOX 
emission controls for Arkansas sources, beyond participation in CSAPR's 
ozone season NOX trading program, are required for achieving 
reasonable progress in Arkansas. As noted above, the July 2017 Regional 
Haze SIP revision addresses NOX requirements for the same 
EGUs for which we established source-specific NOX emission 
limits in our September 27, 2016 FIP.

A. Reliance on CSAPR To Satisfy NOX BART

    Arkansas' 2017 Regional Haze SIP revision proposal relies on EPA's 
determination that CSAPR provides for greater reasonable progress than 
BART to address the NOX BART requirements for its EGUs. 
Consistent with 40 CFR 51.308(e)(4), Arkansas makes the determination 
that since the Arkansas EGUs are currently subject to the CSAPR 
requirements for ozone-season NOX, the State need not 
require subject-to-BART EGUs to install, operate, and maintain BART for 
NOX. We are proposing to find that it is appropriate for 
Arkansas to rely on participation in the CSAPR ozone season 
NOX trading program to satisfy the NOX BART 
requirements for Arkansas EGUs. EPA's 2012 determination and our 
November 2016 proposed determination that implementation of CSAPR meets 
the criteria for a BART alternative are based on an analytic 
demonstration that implementation of CSAPR across all states subject to 
CSAPR would result in

[[Page 42630]]

greater reasonable progress than BART toward restoring natural 
visibility conditions in relevant locations.\21\ Our proposed approval 
of Arkansas' 2017 Regional Haze SIP revision is dependent upon our 
November 10, 2016 proposed determination,\22\ which is based in part on 
the analysis we conducted for our 2012 determination that CSAPR is 
better than BART,\23\ but with updates to reflect the changes to CSAPR 
to address the Court's remand.
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    \21\ 77 FR 33642.
    \22\ 81 FR 78954.
    \23\ 77 FR 33642.
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    We are proposing to find that the NOX BART requirements 
for EGUs in Arkansas will be satisfied by participation in CSAPR's 
ozone season NOX program. Finalization of today's proposed 
SIP approval is dependent upon finalization of the November 10, 2016 
proposed finding that CSAPR continues to be better than BART or EPA 
otherwise determining that participation in CSAPR remains a viable 
alternative to source-specific BART.\24\
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    \24\ 81 FR 78954.
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B. Reasonable Progress Analysis for NOX

    In determining whether additional controls are necessary under the 
reasonable progress requirements and in establishing RPGs, a state must 
consider four statutory factors in section 169A(g)(1) of the CAA: (1) 
The costs of compliance, (2) the time necessary for compliance, (3) the 
energy and nonair quality environmental impacts of compliance, and (4) 
the remaining useful life of any existing source subject to such 
requirements.
    Arkansas' 2017 Regional Haze SIP revision includes a discussion of 
the key pollutants and source categories that contribute to visibility 
impairment in Arkansas Class I areas. In this SIP revision, Arkansas 
refers back to the 2008 Arkansas Regional Haze SIP, which included air 
quality modeling performed by the Central Regional Air Planning 
Association (CENRAP) in support of SIP development in the central 
states region.\25\ The CENRAP modeling included PSAT with CAMx version 
4.4, which was used to provide source apportionment by geographic 
regions and major source categories for pollutants that contribute to 
visibility impairment at each of the Class I areas in the central 
states region. Arkansas' 2017 Regional Haze SIP revision provides a 
discussion of region-wide PSAT results and also provides a discussion 
of Arkansas PSAT data. The conclusion that Arkansas' 2017 Regional Haze 
SIP revision draws from this re-presentation of the CENRAP modeling 
results is that sulfate (SO4) from point sources is the 
primary contributor to total light extinction at Arkansas Class I areas 
on the 20% worst days, whether looking at all regional sources or only 
Arkansas sources. In contrast, nitrate (NO3) is responsible 
for a much smaller proportion of total light extinction at Arkansas 
Class I areas. With regard to light extinction due to NO3, 
the PSAT results show that when looking at only Arkansas sources, the 
majority of the light extinction due to NO3 is clearly 
attributed to on-road mobile sources whereas looking at all region-wide 
sources the light extinction due to NO3 is nearly equally 
attributed to on-road mobile and point sources on the 20% worst days in 
2002. In particular, NO3 from Arkansas point sources 
contribute 0.36 inverse megameters (Mm-1) out of a total 
light extinction of approximately 115.87 Mm-1 at Caney Creek 
on the 20% worst days in 2002. NO3 from Arkansas point 
sources also contribute 0.18 Mm-1 out of a total light 
extinction of approximately 115 Mm-1 at Upper Buffalo on the 
20% worst days in 2002. In terms of percent contribution, 
NO3 from Arkansas point sources contribute approximately 
0.31% of the total light extinction at Caney Creek and 0.16% of the 
total light extinction at Upper Buffalo on the 20% worst days in 2002. 
NO3 from Arkansas area sources had an even smaller 
contribution to light extinction on the 20% worst days in 2002, 
contributing approximately 0.18 Mm-1 out of a total light 
extinction of approximately 115.87 Mm-1 at Caney Creek and 
0.11 Mm-1 out of a total light extinction of approximately 
115 Mm-1 at Upper Buffalo. In terms of percent contribution, 
NO3 from Arkansas area sources contribute approximately 
0.16% of the total light extinction at Caney Creek and 0.1% of the 
total light extinction at Upper Buffalo on the 20% worst days in 2002. 
Based on its evaluation of the CENRAP modeling results, Arkansas 
concludes that given the small amount of visibility impairment due to 
NO3 from Arkansas point sources, it does not expect that 
additional NOX controls on Arkansas point sources would 
yield meaningful visibility improvements at Arkansas Class I areas. 
Taking this into consideration and given that Arkansas EGUs are 
required to participate in the CSAPR ozone season NOX 
trading program, the state determines it is appropriate to screen out 
point sources in Arkansas from further evaluation of NOX 
controls under reasonable progress.
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    \25\ The central states region includes Texas, Oklahoma, 
Louisiana, Arkansas, Kansas, Missouri, Nebraska, Iowa, Minnesota, 
and the tribal governments within these states.
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1. Regional Particulate Source Apportionment Tool (PSAT) Data for Caney 
Creek and Upper Buffalo
    Arkansas' 2017 Regional Haze SIP revision explains that the region-
wide PSAT results show that on the 20% worst days in 2002, point 
sources are the primary contributor to total light extinction at 
Arkansas' Class I areas. Arkansas explains that point sources are 
responsible for approximately 60% of the total light extinction at each 
Arkansas Class I area on the 20% worst days in 2002.\26\ Area sources 
are the next largest contributor to total light extinction at Arkansas 
Class I areas, contributing approximately 13% and 16% of light 
extinction at Caney Creek and Upper Buffalo, respectively.\27\ The 
remaining source categories each contribute between 2% and 6% of total 
light extinction at Arkansas' Class I areas.
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    \26\ Point sources (considering sources both in and outside 
Arkansas) are responsible for approximately 81.04 Mm-1 
out of a total light extinction of 115.87 Mm-1 at Caney 
Creek and 77.8 Mm-1 out of a total light extinction of 
115 Mm-1 at Upper Buffalo on the 20% worst days in 2002. 
See Table 1 of the 2017 Arkansas Regional Haze SIP revision, page 
10.
    \27\ Area sources (considering sources both in and outside 
Arkansas) are responsible for approximately 17.81 Mm-1 
out of a total light extinction of 115.87 Mm-1 at Caney 
Creek and 20.46 Mm-1 out of a total light extinction of 
115 Mm-1 at Upper Buffalo on the 20% worst days in 2002. 
See Table 1 of the 2017 Arkansas Regional Haze SIP revision, page 
10.
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    Looking at the modeled relative contribution to light extinction 
from each species on the 20% worst days in 2002, the PSAT results show 
that SO4 contributes approximately 87.05 Mm-\1\ 
to the total light extinction at Caney Creek and 83.18 
Mm-\1\ to the total light extinction at Upper Buffalo, or 
approximately 72% and 69% of the total modeled light extinction at each 
Class I area, respectively. SO4 due to point sources 
(including point sources both in and outside Arkansas) contributes 75.1 
Mm-\1\ to the total light extinction at Caney Creek and 
72.17 Mm-\1\ at Upper Buffalo, or approximately 62% and 60% 
of the total light extinction at each Class I area on the 20% worst 
days in 2002, respectively. SO4 due to point sources is 
responsible for approximately 86% and 87% of the light extinction due 
to SO4 at Caney Creek and Upper Buffalo, respectively. The 
other source categories (i.e., natural, on-road, non-road, and area 
sources) each contribute much smaller proportions of light extinction 
due to SO4. By comparison, NO3 contributes 
approximately 13.78 Mm-\1\ to the total light extinction at 
Caney Creek and 13.3 Mm-1 at Upper Buffalo, or approximately 
11% of the total light extinction at each Class I area, respectively. 
Primary organic aerosols

[[Page 42631]]

(POA) contribute approximately 8%, elemental carbon (EC) contributes 
approximately 4%, soil contributes approximately 1%, and crustal 
material (CM) contributes approximately 3 to 5% of the total modeled 
visibility extinction at each Arkansas Class I area on the 20% worst 
days in 2002. NO3 due to on-road sources contributes 4.7 
Mm-\1\ and NO3 due to point sources contributes 
4.06 Mm-\1\ at Caney Creek, or approximately one-third of 
the light extinction due to NO3 at the Class I area. 
NO3 due to point sources contributes 3.93 Mm-\1\ 
and NO3 due to on-road sources contributes 4.14 
Mm-\1\ at Upper Buffalo, or approximately 30% to 31% of the 
light extinction due to NO3 at the Class I area. Area 
sources are the primary driver of light extinction attributed to POA, 
soil, and CM. Non-road and area sources are the primary drivers of 
light extinction attributed to EC.
    The PSAT results also show that point sources are projected to 
remain the primary contributor to light extinction at Arkansas' Class I 
areas on the 20% worst days in 2018, contributing approximately 45.27 
Mm-\1\ at Caney Creek and 43.02 Mm-\1\ at Upper 
Buffalo, or approximately 65% of total light extinction at Caney Creek 
and 61% of total light extinction at Upper Buffalo. Area sources are 
projected to continue being the second largest contributor to light 
extinction on the 20% worst days in 2018, contributing approximately 
16.96 Mm-\1\ at Caney Creek and 19.71 Mm-\1\ at 
Upper Buffalo, or approximately 24% of total light extinction at Caney 
Creek and 28% of total light extinction at Upper Buffalo. The PSAT 
results show that natural, on-road, and non-road sources are projected 
to continue to contribute a very small portion of total light 
extinction at Arkansas' Class I areas on the 20% worst days in 2018.
    Arkansas explains that the PSAT results show that the light 
extinction attributed to SO4 is projected to decrease by 
approximately 44% at Caney Creek and 45% at Upper Buffalo on the 20% 
worst days in 2018. However, SO4 is projected to continue 
being the primary driver of total light extinction at Arkansas Class I 
areas on the 20% worst days in 2018, and point sources are projected to 
continue being the primary source of light extinction due to 
SO4. SO4 due to point sources is projected to 
contribute approximately 39.83 Mm-\1\ at Caney Creek and 
37.09 Mm-\1\ at Upper Buffalo, or approximately 53% and 49% 
of total light extinction on the 20% worst days in 2018 at each Class I 
area, respectively. The other species (i.e., NO3, POA, EC, 
soil, and CM) are also projected to have reductions in their 
contribution to total light extinction at Caney Creek and Upper Buffalo 
in 2018. These species' relative contributions to total light 
extinction in 2018 are projected to remain much smaller than that of 
SO4. For example, NO3 is projected to contribute 
approximately 7.57 Mm-\1\ at Caney Creek and 9.22 
Mm-\1\ at Upper Buffalo on the 20% worst days in 2018, or 
approximately 10 to 12% of the total light extinction at each Class I 
area.
2. Arkansas Source PSAT Data for Caney Creek and Upper Buffalo
    In its 2017 Regional Haze SIP submittal, Arkansas explains that 
species attributed to Arkansas sources in particular contribute 
approximately 10% of total light extinction on the 20% worst days in 
2002 at Arkansas Class I areas,\28\ and are projected to contribute 
approximately 13% to 14% of total light extinction on the 20% worst 
days in 2018.\29\
---------------------------------------------------------------------------

    \28\ Arkansas sources contribute approximately 13.58 
Mm-\1\ out of a total light extinction of 115.87 
Mm-\1\ at Caney Creek on the 20% worst days in 2002, and 
13.46 Mm-\1\ out of a total light extinction of 115 
Mm-\1\ at Upper Buffalo. See Tables 1 and 3 of the 2017 
Arkansas Regional Haze SIP revision, pages 10 and 16.
    \29\ Arkansas sources contribute approximately 11.24 
Mm-\1\ out of a total light extinction of 69.55 
Mm-\1\ at Caney Creek on the 20% worst days in 2018, and 
12.02 Mm-\1\ out of a total light extinction of 70.79 
Mm-\1\ at Upper Buffalo. See Tables 2 and 4 of the 2017 
Arkansas Regional Haze SIP revision, pages 13 and 19.
---------------------------------------------------------------------------

    When considering only Arkansas sources, area sources are 
responsible for a greater portion of the visibility extinction than 
point sources on the 20% worst days in 2002 at Arkansas Class I areas. 
For example, Arkansas area sources contribute 5.03 Mm-\1\, 
or approximately 37% of the light extinction attributed to Arkansas 
sources at Caney Creek, and approximately 4% of total light extinction 
at the Class I area on the 20% worst days in 2002. Arkansas area 
sources also contribute 6.72 Mm-\1\, or approximately 50% of 
light extinction attributed to Arkansas sources at Upper Buffalo, and 
approximately 6% of the total light extinction at the Class I area on 
the 20% worst days in 2002. By comparison, Arkansas point sources 
contribute 3.85 Mm-\1\, or approximately 28% of the light 
extinction attributed to Arkansas sources at Caney Creek, and 
approximately 3% of the total light extinction at the Class I area on 
the 20% worst days in 2002. Arkansas point sources also contribute 3.25 
Mm-\1\, or approximately 24% of light extinction attributed 
to Arkansas sources at Upper Buffalo, and approximately 3% of the total 
light extinction at the Class I area on the 20% worst days in 2002. The 
other source categories in Arkansas each contribute between 7% and 14% 
to light extinction attributed to Arkansas sources at Caney Creek and 
Upper Buffalo.
    Looking at each species and their modeled relative contributions to 
light extinction at Arkansas Class I areas, SO4 from all 
Arkansas sources contributes 4.14 Mm-\1\ at Caney Creek and 
3.97 Mm-\1\ at Upper Buffalo, or approximately 3% of the 
total modeled light extinction at each Class I area on the 20% worst 
days in 2002. SO4 due to Arkansas point sources contributes 
2.94 Mm-\1\ at Caney Creek and 2.62 Mm-\1\ at 
Upper Buffalo, or approximately two-thirds of the light extinction 
attributed to SO4 from all Arkansas sources at each Class I 
area. POA from Arkansas sources contributes approximately 3% and 2% of 
the total light extinction on the 20% worst days in 2002 at Caney Creek 
and Upper Buffalo, respectively. NO3 from all Arkansas 
sources contributes 2.11 Mm-\1\ at Caney Creek and 1.07 
Mm-\1\ at Upper Buffalo, or approximately 2% and 1% of the 
total light extinction on the 20% worst days in 2002 at each Class I 
area, respectively. NO3 due to Arkansas on-road sources 
contributes 1.09 Mm-\1\ at Caney Creek and 0.54 
Mm-\1\ at Upper Buffalo, or approximately 50% of the light 
extinction attributed to NO3 from Arkansas sources at 
Arkansas Class I areas on the 20% worst days in 2002. NO3 
due to Arkansas point sources contributes 0.36 Mm-\1\ at 
Caney Creek and 0.18 Mm-\1\ at Upper Buffalo, or 
approximately 17% of the light extinction attributed to NO3 
from all Arkansas sources at each Class I area. EC from Arkansas 
sources contributes approximately 1% and soil from Arkansas sources 
contributes approximately 0.2% to the total light extinction at Caney 
Creek and Upper Buffalo on the 20% worst days in 2002. CM from Arkansas 
sources, primarily area sources, contribute approximately 1 and 2% of 
total light extinction at Caney Creek and Upper Buffalo, respectively.
    The PSAT results show that area sources are projected to continue 
having a larger impact on visibility extinction than point sources at 
Caney Creek and Upper Buffalo when only considering sources located in 
Arkansas on the 20% worst days in 2018. For example, Arkansas area 
sources are projected to contribute 4.84 Mm-\1\ at Caney 
Creek, or approximately 43% of the light extinction attributed to 
Arkansas sources at Caney Creek, and

[[Page 42632]]

approximately 6% of the total light extinction at that Class I area on 
the 20% worst days in 2018. Arkansas area sources are also projected to 
contribute 6.52 Mm-\1\ at Upper Buffalo, or approximately 
54% of the light extinction attributed to Arkansas sources at Upper 
Buffalo, and approximately 8% of the total light extinction at that 
Class I area on the 20% worst days in 2018. By comparison, Arkansas 
point sources are projected to contribute 4.05 Mm-\1\ at 
Caney Creek and 3.63 Mm-\1\ at Upper Buffalo, or 
approximately 36% of the light extinction attributed to Arkansas 
sources at Caney Creek and approximately 30% of the light extinction 
attributed to Arkansas sources at Upper Buffalo. Other source 
categories in Arkansas are projected to contribute between 2% and 9% 
each to light extinction from Arkansas sources at Arkansas Class I 
areas on the 20% worst days in 2018.
    The PSAT results also show that light extinction attributed to 
Arkansas NO3 sources is projected to decrease by 62% at 
Caney Creek and 41% at Upper Buffalo on the 20% worst days in 2018, 
largely due to a decrease in light extinction attributed to 
NO3 from Arkansas on-road sources. Overall light extinction 
due to SO4 from Arkansas sources (all source categories 
combined) is projected to decrease at Arkansas Class I areas. However, 
light extinction due to SO4 from point sources located in 
Arkansas is projected to increase by 4% at Caney Creek and 5% at Upper 
Buffalo on the 20% worst days in 2018. Arkansas' 2017 Regional Haze SIP 
revision states that even so, the contribution to total light 
extinction of SO4 from Arkansas point sources remains 
relatively small--3% of total light extinction at each Arkansas Class I 
area.
3. Arkansas' Conclusions Regarding Key Pollutants and Source Category 
Contributions
    Arkansas asserts that when only sources located in Arkansas are 
considered, light extinction due to area sources (all pollutant species 
considered) is greater compared to point sources for both Caney Creek 
and Upper Buffalo on the 20% worst days both in 2002 and in 2018. Even 
though area sources contribute a larger proportion of the total light 
extinction compared to other source categories when only Arkansas 
sources are considered, Arkansas asserts that the cost-effectiveness of 
controlling many individual small area sources is difficult to 
quantify. Therefore, Arkansas did not evaluate area sources for 
controls under reasonable progress.
    Arkansas also asserts that the region-wide PSAT data indicate that 
the relative regional contribution of SO4 to light 
extinction at Arkansas Class I areas is much higher than that of other 
pollutants on the 20% worst days. However, the PSAT results for 
Arkansas sources show that the relative contribution to light 
extinction of the various species due to Arkansas sources is not as 
weighted toward SO4 compared to the region-wide contribution 
results. Nevertheless, SO4 is still the species with the 
largest contribution to light extinction at Caney Creek and Upper 
Buffalo on the 20% worst days in both the regional contribution results 
and the Arkansas source contribution results. After examination of both 
region-wide PSAT data and data for Arkansas sources, Arkansas 
identifies SO4 as the key species contributing to light 
extinction at Caney Creek and Upper Buffalo. Since the primary driver 
of SO4 formation is emissions of SO2 from point 
sources when looking at both the regional PSAT data and the data for 
Arkansas sources, Arkansas states it will evaluate in a subsequent SIP 
revision large sources of SO2 to determine whether their 
emissions and proximity to Arkansas Class I areas warrant further 
analysis using the four statutory factors.
    Arkansas also asserts that only a very small proportion of total 
light extinction is due to NO3 from Arkansas sources and 
that this proportion has historically been driven by on-road sources, 
which are regulated by national vehicle emission standards. Arkansas 
points out that the PSAT data show that NO3 from Arkansas 
point sources contributes less than 0.5% of the total light extinction 
at Caney Creek and Upper Buffalo on the 20% worst days in 2002, and 
that this contribution is expected to decrease on the 20% worst days in 
2018. Arkansas asserts that the level of visibility impairment due to 
NO3 from Arkansas point sources is miniscule, and that the 
state therefore does not anticipate that additional NOX 
controls on Arkansas point sources would yield meaningful visibility 
improvements at Arkansas Class I areas. Additionally, Arkansas points 
out that Arkansas EGUs with a nameplate capacity of 25 megawatts (MW) 
or greater participate in the CSAPR ozone season NOX 
emissions trading program. Arkansas notes that the Independence 
facility's EGUs participate in CSAPR for ozone season NOX 
and also that the EPA promulgated NOX controls for this 
facility in the Arkansas Regional Haze FIP to ensure reasonable 
progress toward improving visibility. Arkansas makes the determination 
that because of the small impact at Arkansas Class I areas due to 
NO3 from Arkansas sources, participation of Arkansas EGUs in 
CSAPR for ozone season NOX satisfies the reasonable progress 
requirements for NOX for sources in Arkansas.
    Further, Arkansas states that the 2018 CSAPR trading program ozone 
season allocations for Arkansas EGUs add up to 3,708 NOX 
tons less than the 2016 ozone season NOX emissions from 
Arkansas EGUs.\30\ Arkansas also states that it anticipates that some 
EGUs will choose to install combustion controls to comply with CSAPR 
that would achieve emissions reductions year-round, not just in the 
ozone season. Therefore, Arkansas anticipates that the total annual 
NOX reductions associated with compliance with the 2018 
CSAPR ozone season trading program would be greater than 3,708 
NOX tons.
---------------------------------------------------------------------------

    \30\ See Appendix A of Arkansas' 2017 Regional Haze SIP 
submittal, which can be found in the docket associated with this 
proposed rulemaking.
---------------------------------------------------------------------------

4. Our Evaluation of Arkansas' Analysis
    We agree with Arkansas' assertion that when only sources located in 
Arkansas are considered, light extinction due to area sources (all 
pollutant species considered) is greater compared to that of point 
sources for both Caney Creek and Upper Buffalo on the 20% worst days in 
2002. In particular, light extinction due to Arkansas areas sources 
(all pollutant species considered) was 5.03 Mm-\1\ out of 
total light extinction of 115.87 Mm-\1\ at Caney Creek and 
6.72 Mm-\1\ out of total light extinction of 115 
Mm-\1\ at Upper Buffalo. By comparison, light extinction due 
to Arkansas point sources (all pollutant species considered) was 3.85 
Mm-\1\ out of total light extinction of 115.87 
Mm-\1\ at Caney Creek and 3.25 Mm-\1\ out of 
total light extinction of 115 Mm-\1\ at Upper Buffalo. We 
also agree that the cost of controlling many individual small area 
sources may be difficult to quantify, and we are therefore proposing to 
find that it is acceptable for Arkansas to choose not to evaluate area 
sources for controls under reasonable progress in this implementation 
period. This is consistent with EPA's decision not to conduct a four 
factor analysis of area sources under reasonable progress in this 
implementation period in the Arkansas Regional Haze FIP.\31\
---------------------------------------------------------------------------

    \31\ In the FIP we explained that the CENRAP CAMx modeling with 
PSAT showed that point sources are responsible for a majority of the 
light extinction at Arkansas Class I areas on the 20% worst days in 
2002 (this is taking into account all pollutant species and sources 
both in and outside Arkansas). We reasoned that since other source 
types (i.e., natural, on-road, non-road, and area) each contributed 
a much smaller proportion of the total light extinction at each 
Class I area, it was appropriate to focus only on point sources in 
our reasonable progress analysis for this implementation period. See 
80 FR 18944 and 81 FR 66332 at 66336. See also the ``Arkansas 
Regional Haze FIP Response to Comments (RTC) Document,'' pages 71-
99.

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

[[Page 42633]]

    We agree with Arkansas that the PSAT results for Arkansas sources 
show that the relative contribution to light extinction of 
SO4 on the 20% worst days at Arkansas Class I areas is not 
as great compared to the regional contribution results. However, 
SO4 is still the species with the largest contribution to 
light extinction at Caney Creek and Upper Buffalo on the 20% worst days 
in both the regional data and the Arkansas source data. Therefore, we 
agree with Arkansas' identification of SO4 as the key 
species contributing to light extinction at Caney Creek and Upper 
Buffalo on the 20% worst days. This is consistent with our finding in 
the Arkansas Regional Haze FIP that the CENRAP's CAMx modeling shows 
that SO4 from point sources is the driver of regional haze 
at Caney Creek and Upper Buffalo on the 20% worst days in both 2002 and 
2018.\32\
---------------------------------------------------------------------------

    \32\ 80 FR 18996.
---------------------------------------------------------------------------

    With regard to NOX, we also accept Arkansas' assertion 
that a very small proportion of total light extinction is due to 
NO3 from Arkansas sources and that this is driven by on-road 
sources. Because on-road sources are primarily regulated by national 
vehicle emission standards. we are proposing to find that it is 
reasonable for Arkansas to choose not to evaluate on-road sources for 
additional NOX control measures to address visibility 
impairment in this implementation period. This is consistent with EPA's 
decision not to conduct a four factor analysis of on-road mobile 
sources under reasonable progress in this implementation period in the 
Arkansas Regional Haze FIP.\33\
---------------------------------------------------------------------------

    \33\ See 80 FR 18944 and 81 FR 66332 at 66336. See also the 
``Arkansas Regional Haze FIP RTC Document,'' pages 71-99.
---------------------------------------------------------------------------

    Arkansas points out that the PSAT data show that NO3 
from Arkansas point sources contributes less than 0.5% of the total 
light extinction at Caney Creek and Upper Buffalo on the 20% worst days 
in 2002, and that this contribution is expected to decrease on the 20% 
worst days in 2018. NO3 from Arkansas point sources 
contributes 0.36 Mm-\1\ out of a total light extinction of 
115.87 Mm-\1\ at Caney Creek and 0.18 Mm-\1\ out 
of a total light extinction of 115 Mm-\1\ at Upper Buffalo 
on the 20% worst days in 2002. Arkansas considers this level of 
visibility impairment due to NO3 from Arkansas point sources 
to be miniscule. Although the 2017 Regional Haze SIP revision does not 
provide a discussion of data from the existing visibility monitoring 
network, the Interagency Monitoring of Protected Visual Environments 
(IMPROVE) monitoring network, we looked at recent IMPROVE monitor data 
to determine the level of contribution from NO3 to the 
monitored light extinction at Caney Creek and Upper Buffalo. The 
monitor data show that for the 20% most impaired days in 2013-2015, the 
average contribution of NO3 to total extinction (including 
Rayleigh) was approximately 9.43 Mm-\1\ out of a total 
average light extinction of 69.13 Mm-\1\ at Caney Creek and 
15.25 Mm-\1\ out of a total average light extinction of 
66.37 Mm-\1\ at Upper Buffalo. In terms of percent 
contribution, the average contribution of NO3 to total light 
extinction was approximately 14% at Caney Creek and 23% at Upper 
Buffalo.\34\ This consists of NO3 from all source categories 
(i.e., point, area, on-road, non-road, and natural) and from all 
sources, rather than just Arkansas sources. By comparison, the monitor 
data show that the average contribution of SO4 to total 
extinction was approximately 34.21 Mm-\1\ out of a total 
average light extinction of 69.13 Mm-\1\ at Caney Creek and 
28.19 Mm-\1\ out of a total average light extinction of 
66.37 Mm-\1\ at Upper Buffalo. In terms of percent 
contribution, the average contribution of SO4 to total light 
extinction was approximately 50% at Caney Creek and 43% at Upper 
Buffalo on the 20% most impaired days in 2013-2015. Based on the CENRAP 
PSAT data discussed above, we expect that a large proportion of 
NO3 from Arkansas sources is likely due to on-road sources 
and that the average percentage contribution of NO3 from 
Arkansas point sources at Arkansas Class I areas is considerably 
smaller than 14% at Caney Creek and 23% at Upper Buffalo. Taking into 
consideration that states have significant discretion in determining 
what sources to analyze for controls under reasonable progress, we are 
proposing to find that it is reasonable for Arkansas to reach the 
conclusion that, for the first implementation period, additional 
NOX controls for Arkansas point sources are not anticipated 
to yield meaningful visibility improvements at Arkansas Class I areas 
in view of the amount of visibility impairment attributed to these 
sources.
---------------------------------------------------------------------------

    \34\ See Excel spreadsheet titled 
``Nitrate_percentage_extinction_CACR_UPBU.xlsx.'' This spreadsheet 
is found in the docket associated with this proposed rulemaking.
---------------------------------------------------------------------------

    Arkansas' conclusions with regard to the percentage contribution to 
light extinction from NO3 on the 20% worst days is generally 
consistent with the findings we made in the Arkansas Regional Haze 
FIP.\35\ In the FIP, we made the finding that NO3 from point 
sources is not considered a driver of regional haze at Caney Creek and 
Upper Buffalo on the 20% worst days, contributing only approximately 3% 
of the total light extinction, as projected by CENRAP's CAMx source 
apportionment modeling.\36\ We also stated in the FIP proposal that 
because of the small contribution of NO3 from point sources 
to the total light extinction at Caney Creek and Upper Buffalo on the 
most impaired days, we did not expect that NOX controls 
under the reasonable progress requirements would offer as much 
improvement on the most impaired days compared to SO2 
controls.\37\ However, in the FIP, we decided to look at 2011 National 
Emissions Inventory (NEI) data for NOX for Arkansas point 
sources to determine if there are any large point sources that are 
reasonable candidates for evaluation under the four reasonable progress 
factors. Based on this assessment, we proceeded with an analysis of the 
four reasonable progress factors for NOX controls for the 
Independence facility as we reasoned that it is the second largest 
point source of NOX emissions in the state and potentially 
one of the largest single contributors to visibility impairment at 
Class I areas in Arkansas.\38\ We also conducted CALPUFF modeling to 
determine the maximum 98th percentile visibility impacts from the 
Independence facility and the predicted visibility improvement due to 
NOX controls at the facility. That analysis revealed that 
low NOX burner controls would be very cost-effective and 
would result in an improvement of the 98th percentile visibility 
impacts from the Independence facility at Caney Creek and Upper 
Buffalo, and we finalized NOX controls for the Independence 
facility under the reasonable progress requirements.\39\
---------------------------------------------------------------------------

    \35\ 81 FR 66332; see also 81 FR 68319 (October 4, 2016) 
(correction).
    \36\ 80 FR 18996.
    \37\ 80 FR 18996.
    \38\ 80 FR 18995.
    \39\ 81 FR 66332.
---------------------------------------------------------------------------

    In the July 2017 Regional Haze SIP revision, Arkansas takes a 
different, but nonetheless equally reasonable, approach to determine 
whether additional controls are necessary under reasonable progress. In 
its evaluation, Arkansas places greater emphasis on the

[[Page 42634]]

relative contributions of sources within Arkansas to light extinction 
at Caney Creek and Upper Buffalo rather than the relative contributions 
of all sources both in and outside Arkansas. Arkansas also focuses its 
assessment on the CENRAP's CAMx source apportionment modeling rather 
than conducting or relying on CALPUFF modeling, and reaches the 
conclusion that, for the first implementation period, additional 
NOX controls for Arkansas point sources are not anticipated 
to yield meaningful visibility improvements at Arkansas Class I areas 
on the 20% worst days in view of the amount of visibility impairment 
attributed to these sources. Additionally, Arkansas points out that the 
Independence facility and other EGUs in Arkansas with a nameplate 
capacity of 25 MW or greater are participating in CSAPR for ozone 
season NOX.\40\ Thus, NOX emissions from 
Independence and other Arkansas sources will be addressed under 
reasonable progress through EGU participation in the CSAPR ozone season 
NOX trading program. We believe that Arkansas is within its 
discretion to take the approach of focusing on the CENRAP's CAMx source 
apportionment modeling to help inform its decision regarding whether 
NOX controls under reasonable progress are warranted. Given 
the relatively small level of visibility impairment due to 
NOX3 from Arkansas point sources at Caney Creek and Upper 
Buffalo on the 20% worst days and considering that Arkansas EGUs are 
participating in CSAPR for ozone season NOX, we are 
proposing to find that Arkansas' decision to screen out Arkansas point 
sources from further evaluation of additional NOX controls 
is reasonable and we are proposing to approve Arkansas' determination 
that Arkansas EGU participation in CSAPR for ozone season 
NOX is sufficient to satisfy the reasonable progress 
requirements for NOX in Arkansas for the first 
implementation period. We find that Arkansas has addressed our concerns 
presented in our final partial disapproval \41\ of the 2008 Regional 
Haze SIP revision with respect to reasonable progress for 
NOX by providing additional analysis that shows that 
NOX emissions are not the driver of regional haze on the 20% 
worst days in Arkansas Class I areas and that further analysis of 
additional NOX controls for Arkansas sources under 
reasonable progress is therefore not warranted for the first 
implementation period considering that NOX emissions from 
Arkansas EGUs are addressed through participation in the CSAPR ozone 
season NOX trading program.
---------------------------------------------------------------------------

    \40\ 81 FR 74504.
    \41\ 77 FR 14604.
---------------------------------------------------------------------------

C. Required Consultation

    The Regional Haze Rule requires states to provide the designated 
Federal Land Managers (FLMs) with an opportunity for consultation at 
least 60 days prior to holding any public hearing on a SIP revision for 
regional haze for the first implementation period.\42\ Arkansas sent 
letters to the FLMs on June 14, 2017, providing notification of the 
proposed SIP revision and providing electronic access to the draft SIP 
revision and related documents.\43\ The Regional Haze Rule at section 
51.308(d)(3)(i) also provides that if a state has emissions that are 
reasonably anticipated to contribute to visibility impairment in a 
Class I area located in another state, the state must consult with the 
other state(s) in order to develop coordinated emission management 
strategies. Since Missouri has two Class I areas impacted by Arkansas 
sources, Arkansas sent a letter to the Missouri Department of Natural 
Resources (MDNR) on June 14, 2017, providing notification of the 
proposed SIP revision and providing electronic access to the draft SIP 
revision and related documents.\44\ Arkansas stated it will consider 
and respond to any comments received from the FLMs and from the MDNR on 
the proposed SIP revision before finalizing and submitting the final 
SIP revision to EPA.
---------------------------------------------------------------------------

    \42\ On January 10, 2017, the EPA revised the Regional Haze 
Rule, including the FLM consultation requirements at 40 CFR 
51.308(i)(2). See 82 FR 3078. However, these revisions to the 
Regional Haze Rule are intended to address requirements for the 
second implementation period rather than the first implementation 
period; Arkansas' 2017 Regional Haze SIP revision addresses regional 
haze requirements for the first implementation period. For the first 
implementation period, the Regional Haze Rule required states to 
provide the FLMs with an opportunity for consultation, in person and 
at least 60 days prior to holding any public hearing on an 
implementation plan (or plan revision) for regional haze. See 64 FR 
35714, at 35769.
    \43\ See Tab D of the 2017 Arkansas Regional Haze SIP revision, 
which can be found in the docket associated with this rulemaking.
    \44\ See Tab D of the 2017 Arkansas Regional Haze SIP revision, 
which can be found in the docket associated with this rulemaking.
---------------------------------------------------------------------------

    We are proposing to find that Arkansas has provided an opportunity 
for consultation to the FLMs and to the MDNR on the proposed SIP 
revision, as required under section 51.308(i)(2) and 51.308(d)(3)(i). 
Our final determination with respect to Arkansas' satisfaction of the 
consultation requirements under the Regional Haze Rule will be 
contingent upon Arkansas' appropriate consideration and responses to 
comments from the FLMs and the MDNR in the final SIP submission.

III. Proposed Action

A. Arkansas' Proposed Regional Haze SIP Revision

    The EPA has made the preliminary determination that the July 12, 
2017 proposed revisions to the Arkansas Regional Haze SIP and the 
request by the State for parallel processing are in accordance with the 
CAA and consistent with the CAA and the EPA's rule on regional haze. 
Therefore, the EPA proposes to approve the following revisions to the 
Arkansas Regional Haze SIP that were proposed for adoption on July 8, 
2017 and submitted for parallel processing on July 12, 2017: the 
NOX BART requirements for Bailey Unit 1; McClellan Unit 1; 
Flint Creek Boiler No. 1; Lake Catherine Unit 4; and White Bluff Units 
1 and 2 and the Auxiliary Boiler, will be satisfied by participation in 
CSAPR. We cannot finalize today's proposed SIP approval until we 
finalize the November 10, 2016 proposed finding that CSAPR continues to 
be better than BART \45\ or otherwise determine that participation in 
CSAPR remains a viable BART alternative because such a determination 
provides the basis for Arkansas to rely on CSAPR participation as an 
alternative to source specific EGU BART for NOX. Given the 
relatively small level of visibility impairment due to NO3 
from Arkansas point sources at Caney Creek and Upper Buffalo and 
considering that Arkansas EGUs are participating in CSAPR for ozone 
season NOX, we are proposing to find that Arkansas' decision 
not to conduct further analysis of additional NOX controls 
for Arkansas sources is reasonable and we are proposing to approve 
Arkansas' determination that Arkansas EGU participation in CSAPR for 
ozone season NOX is sufficient to satisfy the reasonable 
progress requirements for NOX in Arkansas for the first 
implementation period.
---------------------------------------------------------------------------

    \45\ 81 FR 78954.
---------------------------------------------------------------------------

    The EPA is proposing this action in parallel with the state's 
rulemaking process. We cannot take a final action until the state 
completes its rulemaking process, adopts its final regulations, and 
submits these final adopted regulations as a revision to the Arkansas 
SIP. If during the response to comments process, the final SIP revision 
is changed significantly from the proposed SIP revision upon which the 
EPA proposed, the EPA may have to withdraw our initial proposed rule 
and re-propose based on the final SIP submittal.

[[Page 42635]]

B. Partial FIP Withdrawal

    We are proposing to withdraw those portions of the Arkansas 
Regional Haze FIP at 40 CFR 52.173 that impose NOX 
requirements on 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; and Independence Units 1 and 2.\46\ We are proposing that these 
portions of the FIP will be replaced by the July 2017 Regional Haze SIP 
revision that we are proposing to approve in this action.
---------------------------------------------------------------------------

    \46\ The proposed amendatory language for this proposed revision 
of the earlier promulgated FIP is set forth at the end of this 
proposal. If the action is finalized as proposed, the final action 
will also present additional amendatory language reflecting our 
approval of the submitted SIP revision.
---------------------------------------------------------------------------

C. Clean Air Act Section 110(l)

    Section 110(l) of the CAA states that ``[t]he Administrator shall 
not approve a revision of a plan if the revision would interfere with 
any applicable requirement concerning attainment and reasonable further 
progress or any other applicable requirement of this chapter.'' \47\ 
EPA does not interpret section 110(l) to require a full attainment or 
maintenance demonstration before any changes to a SIP may be approved. 
Generally, a SIP revision may be approved under section 110(l) if EPA 
finds that it will at least preserve status quo air quality, 
particularly where the pollutants at issue are those for which an area 
has not been designated nonattainment.
---------------------------------------------------------------------------

    \47\ 42 U.S.C. 7410(l).
---------------------------------------------------------------------------

    We do not believe an approval of the 2017 Regional Haze SIP 
revision, as proposed, will interfere with CAA requirements for BART or 
reasonable progress because all areas in the state are designated as 
attainment for all NAAQS, and our proposal is supported by an 
evaluation that those CAA requirements are met. The SIP replaces 
federal determinations for source specific NOX emission 
limits for BART EGUs in Arkansas. Following promulgation of the FIP, 
EPA finalized an update to the CSAPR rule on October 26, 2016, that 
addresses the 1997 ozone NAAQS portion of the remand and the CAA 
requirements addressing interstate transport for the 2008 ozone 
NAAQS.\48\ On November 10, 2016, EPA proposed a rule intended to 
address the remainder of the court's remand, which also included an 
assessment of the impacts of the set of actions that the EPA has taken 
or expects to take in response to the D.C. Circuit's remand on our 2012 
demonstration that participation in CSAPR provides for greater 
reasonable progress than BART.\49\ Based on that assessment, the EPA 
proposed in the November 10, 2016 action that states may continue to 
rely on CSAPR as being better than BART on a pollutant-specific basis. 
As such, Arkansas now has the option to propose to rely on compliance 
with CSAPR to satisfy the NOX BART requirement for EGUs. 
Finalization of EPA's November 10, 2016, proposed finding that CSAPR 
continues to be better than BART \50\ or EPA otherwise determining that 
CSAPR remains a viable BART alternative will provide the basis for 
Arkansas to rely on CSAPR participation as an alternative to source 
specific EGU BART for NOX.
---------------------------------------------------------------------------

    \48\ 81 FR74504.
    \49\ 81 FR 78954.
    \50\ 81 FR 78954.
---------------------------------------------------------------------------

    With regard to reasonable progress, Arkansas has provided an 
analysis of anthropogenic sources of visibility impairment and arrived 
at the determination that Arkansas EGU participation in CSAPR for ozone 
season NOX is sufficient to satisfy the reasonable progress 
requirements for NOX in Arkansas for the first 
implementation period. The Independence facility, on which the FIP 
imposed NOX controls under the reasonable progress 
requirements, is subject to CSAPR for ozone season NOX. Even 
though we are withdrawing the source-specific NOX controls 
in the FIP for the Independence facility, its NOX emissions 
will still be addressed under the reasonable progress requirements 
through participation in the CSAPR ozone season NOX 
emissions trading program.
    We also believe that approval of the submitted SIP revision will 
not interfere with attainment and maintenance of the NAAQS within the 
state of Arkansas. No areas in Arkansas are currently designated 
nonattainment for any NAAQS pollutants. The SIP revision we are 
proposing to approve would allow Arkansas to rely on compliance with 
CSAPR to satisfy the NOX BART requirement for Arkansas EGUs 
as well as the reasonable progress requirements for NOX. 
Additionally, the CSAPR 2018 NOX ozone season allocations 
for Arkansas sources are more stringent than the 2017 allocations. As 
all areas are attaining the NAAQS even with current emissions levels, 
reductions in those levels as a result of compliance with the 2018 
NOX ozone season allocations will not interfere with 
attainment. Therefore, we do not deem this to be an instance where a 
full attainment or maintenance demonstration is needed to bolster our 
determination that approval of the submitted SIP revision would not 
interfere with attainment and maintenance of the NAAQS. We are not 
aware of any basis for concluding or demonstrating that Arkansas' July 
2017 Regional Haze SIP revision, when implemented, would interfere with 
the maintenance of the NAAQS in Arkansas.

IV. Statutory and Executive Order Reviews

    Under the CAA, the Administrator is required to approve a SIP 
submission that complies with the provisions of the Act and applicable 
Federal regulations. 42 U.S.C. 7410(k); 40 CFR 52.02(a). Thus, in 
reviewing SIP submissions, the EPA's role is to approve state choices, 
provided that they meet the criteria of the CAA. Accordingly, this 
action merely proposes to approve state law as meeting Federal 
requirements and does not impose additional requirements beyond those 
imposed by state law. For that reason, this action:
     Is not a ``significant regulatory action'' subject to 
review by the Office of Management and Budget under Executive Orders 
12866 (58 FR 51735, October 4, 1993) and 13563 (76 FR 3821, January 21, 
2011);
     Does not impose an information collection burden under the 
provisions of the Paperwork Reduction Act (44 U.S.C. 3501 et seq.);
     Is certified as not having a significant economic impact 
on a substantial number of small entities under the Regulatory 
Flexibility Act (5 U.S.C. 601 et seq.);
     Does not contain any unfunded mandate or significantly or 
uniquely affect small governments, as described in the Unfunded 
Mandates Reform Act of 1995 (Pub. L. 104-4);
     Does not have Federalism implications as specified in 
Executive Order 13132 (64 FR 43255, August 10, 1999);
     Is not an economically significant regulatory action based 
on health or safety risks subject to Executive Order 13045 (62 FR 
19885, April 23, 1997);
     Is not a significant regulatory action subject to 
Executive Order 13211 (66 FR 28355, May 22, 2001);
     Is not subject to requirements of section 12(d) of the 
National Technology Transfer and Advancement Act of 1995 (15 U.S.C. 272 
note) because this action does not involve technical standards; and
     Does not provide EPA with the discretionary authority to 
address, as appropriate, disproportionate human health or environmental 
effects, using practicable and legally permissible methods, under 
Executive Order 12898 (59 FR 7629, February 16, 1994).

[[Page 42636]]

    In addition, the SIP is not approved to apply on any Indian 
reservation land or in any other area where EPA or an Indian tribe has 
demonstrated that a tribe has jurisdiction. In those areas of Indian 
country, the proposed rule does not have tribal implications and will 
not impose substantial direct costs on tribal governments or preempt 
tribal law as specified by Executive Order 13175 (65 FR 67249, November 
9, 2000).

List of Subjects in 40 CFR Part 52

    Air pollution control, Best available retrofit technology, 
Environmental protection, Incorporation by reference, Intergovernmental 
relations, Nitrogen dioxide, Ozone, Regional haze, Reporting and 
recordkeeping requirements, Visibility.

    Dated: August 29, 2017.
Samuel Coleman,
Acting Regional Administrator, Region 6.

    Title 40, chapter I, of the Code of Federal Regulations is proposed 
to be amended as follows:

PART 52--APPROVAL AND PROMULGATION OF IMPLEMENTATION PLANS

0
1. The authority citation for part 52 continues to read as follows:

    Authority:  42 U.S.C. 7401 et seq.

Subpart E--Arkansas

0
2. Section 52.173 is amended by:
0
a. Revising paragraphs (c)(3) through (10) and (c)(12)
0
b. Removing paragraphs (c)(13) and (14)
0
c. Redesignating paragraphs (c)(15) through (29) as paragraphs (c)(13) 
through (27) and
0
d. Revising redesignated paragraphs (c)(14), (15), (17), (18), (20), 
(21), (22), (23) and (24)
    Revisions to read as follows:


Sec.  52.173  Visibility protection.

* * * * *
    (c) * * *
    (3) Emissions limitations for AECC Bailey Unit 1 and AECC McClellan 
Unit 1. The individual SO2 and PM emission limits for each 
unit are as listed in the following table.

------------------------------------------------------------------------
                               SO2 emission limit
            Unit                                      PM emission limit
------------------------------------------------------------------------
AECC Bailey Unit 1..........  Use of fuel with a    Use of fuel with a
                               sulfur content        sulfur content
                               limit of 0.5% by      limit of 0.5% by
                               weight.               weight.
AECC McClellan Unit 1.......  Use of fuel with a    Use of fuel with a
                               sulfur content        sulfur content
                               limit of 0.5% by      limit of 0.5% by
                               weight.               weight.
------------------------------------------------------------------------

    (4) Compliance dates for AECC Bailey Unit 1 and AECC McClellan 
Unit. The owner or operator of each unit must comply with the 
SO2 and PM requirements listed in paragraph (c)(3) of this 
section by October 27, 2021. As of October 27, 2016, the owner or 
operator of each unit shall not purchase fuel for combustion at the 
unit that does not meet the sulfur content limit in paragraph (c)(3) of 
this section. The owner or operator of each unit must comply with the 
requirement in paragraph (c)(3) of this section to burn only fuel with 
a sulfur content limit of 0.5% by weight by October 27, 2021.
    (5) Compliance determination and reporting and recordkeeping 
requirements for AECC Bailey Unit 1 and AECC McClellan Unit for SO2 and 
PM. To determine compliance with the SO2 and PM requirements 
listed in paragraph (c)(3) of this section, the owner or operator shall 
sample and analyze each shipment of fuel to determine the sulfur 
content by weight, except for natural gas shipments. A ``shipment'' is 
considered delivery of the entire amount of each order of fuel 
purchased. Fuel sampling and analysis may be performed by the owner or 
operator of an affected unit, an outside laboratory, or a fuel 
supplier. All records pertaining to the sampling of each shipment of 
fuel as described above, including the results of the sulfur content 
analysis, must be maintained by the owner or operator and made 
available upon request to EPA and ADEQ representatives.
    (6) Emissions limitations for AEP Flint Creek Unit 1 and Entergy 
White Bluff Units 1 and 2. The individual SO2 emission 
limits for each unit are as listed in the following table, as specified 
in pounds per million British thermal units (lb/MMBtu). The 
SO2 emission limits of 0.06 lb/MMBtu are on a rolling 30 
boiler-operating-day averaging period.

------------------------------------------------------------------------
                                                           SO2 emission
                                                            limit  (lb/
                          Unit                                MMBtu)
 
------------------------------------------------------------------------
AEP Flint Creek Unit 1..................................            0.06
Entergy White Bluff Unit 1..............................            0.06
Entergy White Bluff Unit 2..............................            0.06
------------------------------------------------------------------------

    (7) Compliance dates for AEP Flint Creek Unit 1 and Entergy White 
Bluff Units 1 and 2. The owner or operator of AEP Flint Creek Unit 1 
must comply with the SO2 emission limit listed in paragraph 
(c)(6) of this section by April 27, 2018. The owner or operator of 
White Bluff Units 1 and 2 must comply with the SO2 emission 
limit listed in paragraph (c)(6) of this section by October 27, 2021.
    (8) Compliance determination and reporting and recordkeeping 
requirements for AEP Flint Creek Unit 1 and Entergy White Bluff Units 1 
and 2. (i) For purposes of determining compliance with the 
SO2 emission limit listed in paragraph (c)(6) of this 
section for AEP Flint Creek Unit 1 and with the SO2 emission 
limits listed in paragraph (c)(6) of this section for White Bluff Units 
1 and 2, the emissions for each boiler-operating-day for each unit 
shall be determined by summing the hourly emissions measured in pounds 
of SO2. For each unit, heat input for each boiler-operating-
day shall be determined by adding together all hourly heat inputs, in 
millions of BTU. Each boiler-operating-day of the 30-day rolling 
average for a unit shall be determined by adding together the pounds of 
SO2 from that day and the preceding 29 boiler-operating-days 
and dividing the total pounds of SO2 by the sum of the heat 
input during the same 30 boiler-operating-day period. The result shall 
be the 30 boiler-operating-day rolling average in terms of lb/MMBtu 
emissions of SO2. If a valid SO2 pounds per hour 
or heat input is not available for any hour for a unit, that heat input 
and SO2 pounds per hour shall not be used in the calculation 
of the 30 boiler-operating-day rolling average for SO2. For 
each day, records of the total SO2 emitted that day by each 
emission unit and the sum of the hourly heat inputs for that day must 
be maintained by the owner or operator and made available upon request 
to EPA and ADEQ representatives. Records of the 30 boiler-operating-day 
rolling average for SO2 for each unit as described above 
must be maintained by the owner or operator for each boiler-operating-
day and made available upon request to EPA and ADEQ representatives.
    (ii) The owner or operator shall continue to maintain and operate a 
CEMS for SO2 on the units listed in paragraph (c)(6) of this 
section in accordance with 40 CFR 60.8 and 60.13(e), (f), and (h), and 
appendix B of part 60. The owner or operator shall comply with the 
quality assurance procedures for CEMS found in 40 CFR part 75. 
Compliance with the emission

[[Page 42637]]

limits for SO2 shall be determined by using data from a 
CEMS.
    (iii) Continuous emissions monitoring shall apply during all 
periods of operation of the units listed in paragraph (c)(6) of this 
section, including periods of startup, shutdown, and malfunction, 
except for CEMS breakdowns, repairs, calibration checks, and zero and 
span adjustments. Continuous monitoring systems for measuring 
SO2 and diluent gas shall complete a minimum of one cycle of 
operation (sampling, analyzing, and data recording) for each successive 
15-minute period. Hourly averages shall be computed using at least one 
data point in each fifteen-minute quadrant of an hour. Notwithstanding 
this requirement, an hourly average may be computed from at least two 
data points separated by a minimum of 15 minutes (where the unit 
operates for more than one quadrant in an hour) if data are unavailable 
as a result of performance of calibration, quality assurance, 
preventive maintenance activities, or backups of data from data 
acquisition and handling system, and recertification events. When valid 
SO2 pounds per hour emission data are not obtained because 
of continuous monitoring system breakdowns, repairs, calibration 
checks, or zero and span adjustments, emission data must be obtained by 
using other monitoring systems approved by the EPA to provide emission 
data for a minimum of 18 hours in each 24-hour period and at least 22 
out of 30 successive boiler operating days.
    (9) Emissions limitations for Entergy White Bluff Auxiliary Boiler. 
The individual SO2 and PM emission limits for the unit are 
as listed in the following table in pounds per hour (lb/hr).

------------------------------------------------------------------------
                                          SO2 emission
                 Unit                    limit  (lb/hr)    PM emission
                                                          limit  (lb/hr)
------------------------------------------------------------------------
Entergy White Bluff Auxiliary Boiler..           105.2              4.5
------------------------------------------------------------------------

    (10) Compliance dates for Entergy White Bluff Auxiliary Boiler. The 
owner or operator of the unit must comply with the SO2 and 
PM emission limits listed in paragraph (c)(9) of this section by 
October 27, 2016.
* * * * *
    (12) Emissions limitations for Entergy Lake Catherine Unit 4. The 
unit must not burn fuel oil until BART determinations are promulgated 
for the unit for SO2 and PM for the fuel oil firing scenario 
through a FIP and/or through EPA action upon and approval of revised 
BART determinations submitted by the State as a SIP revision.
* * * * *
    (14) Compliance dates for Domtar Ashdown Mill Power Boiler No. 1. 
The owner or operator of the boiler must comply with the SO2 
and NOX emission limits listed in paragraph (c)(13) of this 
section by November 28, 2016.
    (15) Compliance determination and reporting and recordkeeping 
requirements for Domtar Ashdown Paper Mill Power Boiler No. 1. (i)(A) 
SO2 emissions resulting from combustion of fuel oil shall be 
determined by assuming that the SO2 content of the fuel 
delivered to the fuel inlet of the combustion chamber is equal to the 
SO2 being emitted at the stack. The owner or operator must 
maintain records of the sulfur content by weight of each fuel oil 
shipment, where a ``shipment'' is considered delivery of the entire 
amount of each order of fuel purchased. Fuel sampling and analysis may 
be performed by the owner or operator, an outside laboratory, or a fuel 
supplier. All records pertaining to the sampling of each shipment of 
fuel oil, including the results of the sulfur content analysis, must be 
maintained by the owner or operator and made available upon request to 
EPA and ADEQ representatives. SO2 emissions resulting from 
combustion of bark shall be determined by using the following site-
specific curve equation, which accounts for the SO2 
scrubbing capabilities of bark combustion:

Y= 0.4005 * X - 0.2645

Where:
Y = pounds of sulfur emitted per ton of dry fuel feed to the boiler
X = pounds of sulfur input per ton of dry bark

    (B) The owner or operator must confirm the site-specific curve 
equation through stack testing. By October 27, 2017, the owner or 
operator must provide a report to EPA showing confirmation of the site 
specific-curve equation accuracy. Records of the quantity of fuel input 
to the boiler for each fuel type for each day must be compiled no later 
than 15 days after the end of the month and must be maintained by the 
owner or operator and made available upon request to EPA and ADEQ 
representatives. Each boiler-operating-day of the 30-day rolling 
average for the boiler must be determined by adding together the pounds 
of SO2 from that boiler-operating-day and the preceding 29 
boiler-operating-days and dividing the total pounds of SO2 
by the sum of the total number of boiler operating days (i.e., 30). The 
result shall be the 30 boiler-operating-day rolling average in terms of 
lb/day emissions of SO2. Records of the total SO2 
emitted for each day must be compiled no later than 15 days after the 
end of the month and must be maintained by the owner or operator and 
made available upon request to EPA and ADEQ representatives. Records of 
the 30 boiler-operating-day rolling averages for SO2 as 
described in this paragraph (c)(15)(i) must be maintained by the owner 
or operator for each boiler-operating-day and made available upon 
request to EPA and ADEQ representatives.
    (ii) If the air permit is revised such that Power Boiler No. 1 is 
permitted to burn only pipeline quality natural gas, this is sufficient 
to demonstrate that the boiler is complying with the SO2 
emission limit under paragraph (c)(13) of this section. The compliance 
determination requirements and the reporting and recordkeeping 
requirements under paragraph (c)(15)(i) of this section would not apply 
and confirmation of the accuracy of the site-specific curve equation 
under paragraph (c)(15)(i)(B) of this section through stack testing 
would not be required so long as Power Boiler No. 1 is only permitted 
to burn pipeline quality natural gas.
    (iii) To demonstrate compliance with the NOX emission 
limit under paragraph (c)(13) of this section, the owner or operator 
shall conduct stack testing using EPA Reference Method 7E once every 5 
years, beginning 1 year from the effective date of our final rule. 
Records and reports pertaining to the stack testing must be maintained 
by the owner or operator and made available upon request to EPA and 
ADEQ representatives.
    (iv) If the air permit is revised such that Power Boiler No. 1 is 
permitted to burn only pipeline quality natural gas, the owner or 
operator may demonstrate compliance with the NOX emission 
limit under paragraph (c)(13) of this section by calculating 
NOX emissions using fuel usage records and the applicable 
NOX emission factor under

[[Page 42638]]

AP-42, Compilation of Air Pollutant Emission Factors, section 1.4, 
Table 1.4-1. Records of the quantity of natural gas input to the boiler 
for each day must be compiled no later than 15 days after the end of 
the month and must be maintained by the owner or operator and made 
available upon request to EPA and ADEQ representatives. Records of the 
calculation of NOX emissions for each day must be compiled 
no later than 15 days after the end of the month and must be maintained 
by the owner or operator and made available upon request to EPA and 
ADEQ representatives. Each boiler-operating-day of the 30-day rolling 
average for the boiler must be determined by adding together the pounds 
of NOX from that day and the preceding 29 boiler-operating-
days and dividing the total pounds of NOX by the sum of the 
total number of hours during the same 30 boiler-operating-day period. 
The result shall be the 30 boiler-operating-day rolling average in 
terms of lb/hr emissions of NOX. Records of the 30 boiler-
operating-day rolling average for NOX must be maintained by 
the owner or operator for each boiler-operating-day and made available 
upon request to EPA and ADEQ representatives. Under these 
circumstances, the compliance determination requirements and the 
reporting and recordkeeping requirements under paragraph (c)(15)(iii) 
of this section would not apply.
* * * * *
    (17) SO2 and NOX Compliance dates for Domtar Ashdown Mill Power 
Boiler No. 2. The owner or operator of the boiler must comply with the 
SO2 and NOX emission limits listed in paragraph 
(c)(16) of this section by October 27, 2021.
    (18) SO2 and NOX Compliance determination and reporting and 
recordkeeping requirements for Domtar Ashdown Mill Power Boiler No. 2. 
(i) NOX and SO2 emissions for each day shall be 
determined by summing the hourly emissions measured in pounds of 
NOX or pounds of SO2. Each boiler-operating-day 
of the 30-day rolling average for the boiler shall be determined by 
adding together the pounds of NOX or SO2 from 
that day and the preceding 29 boiler-operating-days and dividing the 
total pounds of NOX or SO2 by the sum of the 
total number of hours during the same 30 boiler-operating-day period. 
The result shall be the 30 boiler-operating-day rolling average in 
terms of lb/hr emissions of NOX or SO2. If a 
valid NOX pounds per hour or SO2 pounds per hour 
is not available for any hour for the boiler, that NOX 
pounds per hour shall not be used in the calculation of the 30 boiler-
operating-day rolling average for NOX. For each day, records 
of the total SO2 and NOX emitted for that day by 
the boiler must be maintained by the owner or operator and made 
available upon request to EPA and ADEQ representatives. Records of the 
30 boiler-operating-day rolling average for SO2 and 
NOX for the boiler as described above must be maintained by 
the owner or operator for each boiler-operating-day and made available 
upon request to EPA and ADEQ representatives.
    (ii) The owner or operator shall continue to maintain and operate a 
CEMS for SO2 and NOX on the boiler listed in 
paragraph (c)(16) of this section in accordance with 40 CFR 60.8 and 
60.13(e), (f), and (h), and appendix B of part 60. The owner or 
operator shall comply with the quality assurance procedures for CEMS 
found in 40 CFR part 60. Compliance with the emission limits for 
SO2 and NOX shall be determined by using data 
from a CEMS.
    (iii) Continuous emissions monitoring shall apply during all 
periods of operation of the boiler listed in paragraph (c)(16) of this 
section, including periods of startup, shutdown, and malfunction, 
except for CEMS breakdowns, repairs, calibration checks, and zero and 
span adjustments. Continuous monitoring systems for measuring 
SO2 and NOX and diluent gas shall complete a 
minimum of one cycle of operation (sampling, analyzing, and data 
recording) for each successive 15-minute period. Hourly averages shall 
be computed using at least one data point in each fifteen-minute 
quadrant of an hour. Notwithstanding this requirement, an hourly 
average may be computed from at least two data points separated by a 
minimum of 15 minutes (where the unit operates for more than one 
quadrant in an hour) if data are unavailable as a result of performance 
of calibration, quality assurance, preventive maintenance activities, 
or backups of data from data acquisition and handling system, and 
recertification events. When valid SO2 or NOX 
pounds per hour emission data are not obtained because of continuous 
monitoring system breakdowns, repairs, calibration checks, or zero and 
span adjustments, emission data must be obtained by using other 
monitoring systems approved by the EPA to provide emission data for a 
minimum of 18 hours in each 24-hour period and at least 22 out of 30 
successive boiler operating days.
    (iv) If the air permit is revised such that Power Boiler No. 2 is 
permitted to burn only pipeline quality natural gas, this is sufficient 
to demonstrate that the boiler is complying with the SO2 
emission limit under paragraph (c)(16) of this section. Under these 
circumstances, the compliance determination requirements under 
paragraphs (c)(18)(i) through (iii) of this section would not apply to 
the SO2 emission limit listed in paragraph (c)(16) of this 
section.
    (v) If the air permit is revised such that Power Boiler No. 2 is 
permitted to burn only pipeline quality natural gas and the operation 
of the CEMS is not required under other applicable requirements, the 
owner or operator may demonstrate compliance with the NOX 
emission limit under paragraph (c)(16) of this section by calculating 
NOX emissions using fuel usage records and the applicable 
NOX emission factor under AP-42, Compilation of Air 
Pollutant Emission Factors, section 1.4, Table 1.4-1. Records of the 
quantity of natural gas input to the boiler for each day must be 
compiled no later than 15 days after the end of the month and must be 
maintained by the owner or operator and made available upon request to 
EPA and ADEQ representatives. Records of the calculation of 
NOX emissions for each day must be compiled no later than 15 
days after the end of the month and must be maintained and made 
available upon request to EPA and ADEQ representatives. Each boiler-
operating-day of the 30-day rolling average for the boiler must be 
determined by adding together the pounds of NOX from that 
day and the preceding 29 boiler-operating-days and dividing the total 
pounds of NOX by the sum of the total number of hours during 
the same 30 boiler-operating-day period. The result shall be the 30 
boiler-operating-day rolling average in terms of lb/hr emissions of 
NOX. Records of the 30 boiler-operating-day rolling average 
for NOX must be maintained by the owner or operator for each 
boiler-operating-day and made available upon request to EPA and ADEQ 
representatives. Under these circumstances, the compliance 
determination requirements under paragraphs (c)(18)(i) through (iii) of 
this section would not apply to the NOX emission limit.
* * * * *
    (20) PM compliance dates for Domtar Ashdown Mill Power Boiler No. 
2. The owner or operator of the boiler must comply with the PM BART 
requirement listed in paragraph (c)(19) of this section by November 28, 
2016.
    (21) Alternative PM Compliance Determination for Domtar Ashdown 
Paper Mill Power Boiler No. 2. If the air permit is revised such that 
Power Boiler

[[Page 42639]]

No. 2 is permitted to burn only pipeline quality natural gas, this is 
sufficient to demonstrate that the boiler is complying with the PM BART 
requirement under paragraph (c)(19) of this section.
    (22) Emissions limitations for Entergy Independence Units 1 and 2. 
The individual emission limits for each unit are as listed in the 
following table in pounds per million British thermal units (lb/MMBtu). 
The SO2 emission limits listed in the table as lb/MMBtu are 
on a rolling 30 boiler-operating-day averaging period.

------------------------------------------------------------------------
                                                           SO2 emission
                                                            limit  (lb/
                          Unit                                MMBtu)
 
------------------------------------------------------------------------
Entergy Independence Unit 1.............................            0.06
Entergy Independence Unit 2.............................            0.06
------------------------------------------------------------------------

    (23) Compliance dates for Entergy Independence Units 1 and 2. The 
owner or operator of each unit must comply with the SO2 
emission limits in paragraph (c)(22) of this section by October 27, 
2021.
    (24) Compliance determination and reporting and recordkeeping 
requirements for Entergy Independence Units 1 and 2. (i) For purposes 
of determining compliance with the SO2 emissions limit 
listed in paragraph (c)(22) of this section for each unit, the 
SO2 emissions for each boiler-operating-day shall be 
determined by summing the hourly emissions measured in pounds of 
SO2. For each unit, heat input for each boiler-operating-day 
shall be determined by adding together all hourly heat inputs, in 
millions of BTU. Each boiler-operating-day of the thirty-day rolling 
average for a unit shall be determined by adding together the pounds of 
SO2 from that day and the preceding 29 boiler-operating-days 
and dividing the total pounds of SO2 by the sum of the heat 
input during the same 30 boiler-operating-day period. The result shall 
be the 30 boiler-operating-day rolling average in terms of lb/MMBtu 
emissions of SO2. If a valid SO2 pounds per hour 
or heat input is not available for any hour for a unit, that heat input 
and SO2 pounds per hour shall not be used in the calculation 
of the applicable 30 boiler-operating-days rolling average. For each 
day, records of the total SO2 emitted that day by each 
emission unit and the sum of the hourly heat inputs for that day must 
be maintained by the owner or operator and made available upon request 
to EPA and ADEQ representatives. Records of the 30 boiler-operating-day 
rolling average for each unit as described above must be maintained by 
the owner or operator for each boiler-operating-day and made available 
upon request to EPA and ADEQ representatives.
    (ii) The owner or operator shall continue to maintain and operate a 
CEMS for SO2 on the units listed in paragraph (c)(22) in 
accordance with 40 CFR 60.8 and 60.13(e), (f), and (h), and appendix B 
of part 60. The owner or operator shall comply with the quality 
assurance procedures for CEMS found in 40 CFR part 75. Compliance with 
the emission limits for SO2 shall be determined by using 
data from a CEMS.
    (iii) Continuous emissions monitoring shall apply during all 
periods of operation of the units listed in paragraph (c)(22) of this 
section, including periods of startup, shutdown, and malfunction, 
except for CEMS breakdowns, repairs, calibration checks, and zero and 
span adjustments. Continuous monitoring systems for measuring 
SO2 and diluent gas shall complete a minimum of one cycle of 
operation (sampling, analyzing, and data recording) for each successive 
15-minute period. Hourly averages shall be computed using at least one 
data point in each fifteen-minute quadrant of an hour. Notwithstanding 
this requirement, an hourly average may be computed from at least two 
data points separated by a minimum of 15 minutes (where the unit 
operates for more than one quadrant in an hour) if data are unavailable 
as a result of performance of calibration, quality assurance, 
preventive maintenance activities, or backups of data from data 
acquisition and handling system, and recertification events. When valid 
SO2 pounds per hour emission data are not obtained because 
of continuous monitoring system breakdowns, repairs, calibration 
checks, or zero and span adjustments, emission data must be obtained by 
using other monitoring systems approved by the EPA to provide emission 
data for a minimum of 18 hours in each 24-hour period and at least 22 
out of 30 successive boiler operating days.
* * * * *

[FR Doc. 2017-18661 Filed 9-8-17; 8:45 am]
 BILLING CODE 6560-50-P