Document ID: EPA-R06-OAR-2015-0189-0186
Agency: epa
Document Type: Rule
Title: AR020.0186 Air Quality State Implementation Plans; Approval and Promulgation: State of Arkansas; Regional Haze and Interstate Visibility Transport Federal Implementation Plan, Final rule, 91 pages.  NOTE: In the DATES section, this final rule is effective on October 27, 2016, NOT October 27, 2017. We will publish a notice in the Federal Register with the corrected effective date shortly.
Posted Date: 2016-09-27T04:00Z

[Federal Register Volume 81, Number 187 (Tuesday, September 27, 2016)]
[Rules and Regulations]
[Pages 66331-66421]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2016-22508]

[[Page 66331]]

Vol. 81

Tuesday,

No. 187

September 27, 2016

Part II

Environmental Protection Agency

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40 CFR Part 52

Promulgation of Air Quality Implementation Plans; State of Arkansas; 
Regional Haze and Interstate Visibility Transport Federal 
Implementation Plan; Final Rule

  Federal Register / Vol. 81 , No. 187 / Tuesday, September 27, 2016 / 
Rules and Regulations  

[[Page 66332]]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 52

[EPA-R06-OAR-2015-0189; FRL-9952-03-Region 6]

Promulgation of Air Quality Implementation Plans; State of 
Arkansas; Regional Haze and Interstate Visibility Transport Federal 
Implementation Plan

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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SUMMARY: The Environmental Protection Agency (EPA) is promulgating a 
final Federal Implementation Plan (FIP) addressing the requirements of 
the Regional Haze Rule and interstate visibility transport for the 
portions of Arkansas' Regional Haze State Implementation Plan (SIP) 
that EPA disapproved in a final rule published in the Federal Register 
on March 12, 2012. In that action, we partially approved and partially 
disapproved the State's plan to implement the regional haze program for 
the first planning period. This final rule addresses the Regional Haze 
Rule's requirements for Best Available Retrofit Technology (BART), 
reasonable progress, and a long-term strategy (LTS), as well as the 
requirements of the Clean Air Act (CAA or Act) regarding interference 
with other states' programs for visibility protection (interstate 
visibility transport) triggered by the issuance of the 1997 ozone 
National Ambient Air Quality Standards (NAAQS) and the 1997 fine 
particulate matter (PM2.5) NAAQS. The FIP includes sulfur 
dioxide (SO2), nitrogen oxide (NOX), and 
particulate matter (PM) emission limits for nine units located at six 
facilities to address BART requirements (these limits also satisfy 
reasonable progress requirements for these sources); and SO2 
and NOX emission limits for two units located at one power 
plant to address the reasonable progress requirements. We also provide 
reasonable progress goals (RPGs) for Arkansas' Class I areas. We are 
prepared to work with the State on a SIP revision that would replace 
some or all elements of the FIP.

DATES: This final rule is effective on October 27, 2017.

ADDRESSES: The EPA has established a docket for this action under 
Docket ID No. EPA-R06-OAR-2015-0189. All documents in the docket are 
listed on the http://www.regulations.gov Web site. Publicly available 
docket materials are available either electronically through http://www.regulations.gov or in hard copy at EPA Region 6, 1445 Ross Avenue, 
Suite 700, Dallas, Texas 75202-2733.

FOR FURTHER INFORMATION CONTACT: Ms. Dayana Medina at 214-665-7241; or 
Medina.dayana@epa.gov.

SUPPLEMENTARY INFORMATION: Throughout this document wherever ``we,'' 
``us,'' or ``our'' is used, we mean the EPA. Also throughout this 
document, when we refer to the Arkansas Department of Environmental 
Quality (ADEQ), we mean Arkansas.

Table of Contents

I. Introduction
II. History of State Submittals and Our Actions
    A. State Submittals and EPA Actions
    B. EPA's Authority To Promulgate a FIP
III. Summary of Our Proposed Rule
    A. Regional Haze
    B. Interstate Visibility Transport
IV. Summary of Our Final FIP
    A. Regional Haze
    1. Identification of BART-Eligible and Subject-to-BART Sources
    2. BART Determinations
    3. Reasonable Progress Analysis
    4. Long Term Strategy
    B. Interstate Visibility Transport
V. Summary and Analysis of Major Issues Raised by Commenters
    A. General Comments
    B. Entergy's Alternative Strategy for White Bluff and 
Independence
    C. Reasonable Progress Goals and Reasonable Progress Analysis
    D. Control Levels and Emission Limits
    E. Domtar Ashdown Mill Repurposing Project
    F. Other Compliance Dates
    G. Compliance Demonstration Requirements
    H. Reliance on CSAPR Better than BART
    I. Cost
    J. Modeling
    K. Legal
    L. Interstate Visibility Transport
VI. Final Action
    A. Regional Haze
    B. Interstate Visibility Transport
VII. Statutory and Executive Order Reviews

I. Introduction

    The purpose of Federal and state regional haze plans is to achieve 
a national goal, declared by Congress, of restoring and protecting 
visibility at 156 Federal Class I areas across the United States, most 
of which are national parks and wilderness areas with scenic vistas 
enjoyed by the American public. The national goal, as described in CAA 
Section 169A, is ``the prevention of any future, and the remedying of 
any existing, impairment of visibility in mandatory Class I Federal 
areas which impairment results from man-made air pollution.'' States 
are required to submit SIPs that ensure reasonable progress toward the 
national goal of remedying anthropogenic visibility impairment in 
Federal Class I areas. Arkansas has two Federal Class I areas, the 
Caney Creek Wilderness Area (Caney Creek) and Upper Buffalo Wilderness 
Area (Upper Buffalo). Please refer to our previous rulemaking on the 
Arkansas Regional Haze SIP for additional background information 
regarding the CAA, regional haze, and the Regional Haze Rule.\1\
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    \1\ 76 FR 64186, October 17, 2011 (proposed action); and 77 FR 
14604, March 12, 2012 (final action).
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    In our previous action on the Arkansas Regional Haze SIP, we 
approved a number of elements but disapproved others.\2\ In this final 
action, we are addressing these disapproved elements. We are 
establishing BART emission limits for nine units at six facilities that 
contribute to visibility impairment at Caney Creek and Upper Buffalo in 
Arkansas, as well as the Hercules-Glades Wilderness Area (Hercules-
Glades) and the Mingo National Wildlife Refuge (Mingo) in Missouri. 
These facilities are subject to BART controls for emissions of 
SO2, NOX, and PM. The BART sources are the 
Arkansas Electric Cooperative Corporation Carl E. Bailey Generating 
Station (AECC Bailey) Unit 1; Arkansas Electric Cooperative Corporation 
John L. McClellan Generating Station (AECC McClellan) Unit 1; American 
Electric Power (AEP) Flint Creek Power Plant Unit 1; Entergy White 
Bluff Plant Units 1, 2, and Auxiliary Boiler; Entergy Lake Catherine 
Plant Unit 4; and Domtar Ashdown Mill Power Boilers Nos. 1 and 2. In 
addition, we are establishing SO2 and NOX 
emission limits for the Entergy Independence Plant Units 1 and 2 
pursuant to the reasonable progress and long-term strategy provisions 
of the Regional Haze Rule. We have calculated numerical RPGs for Caney 
Creek and Upper Buffalo that reflect the visibility improvement 
anticipated by 2018 from the combination of control measures from the 
approved portion of the Arkansas Regional Haze SIP and this FIP.
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    \2\ 77 FR 14604.
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    We are also making a finding that the combination of the approved 
portion of the Arkansas Regional Haze SIP and this FIP satisfy the 
requirements of CAA section 110(a)(2)(D)(i)(II) with respect to 
visibility (interstate visibility transport requirement) for the 1997 
8-hour ozone and 1997 PM2.5 NAAQS. This provision of the CAA 
requires that each state's SIP have adequate provisions to prohibit in-
state emissions from interfering with measures required to protect 
visibility in any other state. To address this requirement, the SIP 
must address the

[[Page 66333]]

potential for interference with visibility protection caused by the 
pollutant (including precursors) to which the new or revised NAAQS 
applies. In our March 12, 2012 final action on the Arkansas Regional 
Haze SIP, we also partially approved and partially disapproved the SIP 
submittal with respect to the interstate transport visibility 
requirement under CAA section 110(a)(2)(D)(i)(II). This FIP fully 
addresses the deficiencies we identified in our final action on the 
Arkansas Regional Haze SIP with respect to the interstate visibility 
transport requirement under CAA section 110(a)(2)(D)(i)(II) for the 
1997 8-hour ozone and 1997 PM2.5 NAAQS.
    In this document, we summarize our responses to comments received 
during our comment period on our proposed rule and indicate where we 
have made adjustments based on the comments and additional information 
we received. In some cases, we have adjusted the emission limits, 
compliance deadlines, and requirements for testing and demonstration of 
compliance in response to information received during the comment 
period. We also received several comments, from Entergy and Sierra 
Club, after the close of the comment period, which included new 
information on an alternative approach for White Bluff. We do not 
address these late comments in our rulemaking and they are not a basis 
for our decision in this action. We do note that the new information 
regarding an alternative approach may have promise with respect to 
addressing the BART requirements for White Bluff, and we encourage the 
State to consider it as it develops a SIP revision to replace our FIP.
    EPA is promulgating this partial FIP to address the deficiencies in 
the Arkansas Regional Haze SIP and the SIP revision submitted by the 
State to address the interstate visibility transport requirements.\3\ 
The State retains its authority to submit a revised state plan 
consistent with CAA and Regional Haze Rule requirements. EPA stands 
ready to work with the State on a SIP revision that would replace some 
or all elements of the FIP.
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    \3\ These deficiencies are discussed in our March 12, 2012 final 
action on the Arkansas Regional Haze SIP and SIP revision to address 
the interstate visibility transport requirements. See 77 FR 14604.
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II. History of State Submittals and Our Actions

A. State Submittals and EPA Actions

    Arkansas submitted a SIP to address the regional haze requirements 
for the first planning period on September 23, 2008. On August 3, 2010, 
Arkansas submitted a SIP revision that addressed the Arkansas Pollution 
Control and Ecology Commission (APCEC) Regulation 19, Chapter 15, which 
is the State rule that identifies the BART-eligible and subject-to-BART 
sources in Arkansas and establishes the BART emission limits that 
subject-to-BART sources are required to comply with. On September 27, 
2011, the State submitted supplemental information related to regional 
haze. We are hereafter referring to these regional haze submittals 
collectively as the ``Arkansas Regional Haze SIP.'' On April 2, 2008, 
Arkansas submitted a SIP revision to address the interstate visibility 
transport requirement of CAA section 110(a)(2)(D)(i)(II) for the 1997 
8-hour ozone and 1997 PM2.5 NAAQS. On October 17, 2011, we 
published our proposed partial approval and partial disapproval of the 
Arkansas Regional Haze SIP and the interstate visibility transport 
SIP.\4\ Our final rule partially approving and partially disapproving 
the Arkansas Regional Haze SIP and interstate visibility transport SIP 
was published on March 12, 2012.\5\ We explained in our proposed and 
final actions on the Arkansas Regional Haze SIP that we elected not to 
promulgate a FIP concurrently with our partial disapproval action 
because ADEQ expressed its intent to revise the disapproved portions of 
the SIP and we therefore wanted to provide the state time to submit a 
SIP revision.\6\
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    \4\ 76 FR 64186.
    \5\ 77 FR 14604.
    \6\ See 76 FR 64186, 64188 (proposed action) and 77 FR 14604, 
14672 (final action).
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    Our final partial disapproval of the Arkansas RH SIP and interstate 
visibility transport SIP started a 2-year FIP clock such that we have 
an obligation to approve a SIP revision and/or promulgate a FIP to 
address the disapproved portions of the SIP within 2 years of our final 
partial disapproval action. We began working in 2012 with ADEQ and the 
affected facilities to revise the disapproved portions of the SIP. 
However, a SIP revision was not submitted and the FIP clock expired in 
April 2014. On April 8, 2015, we proposed a FIP to address the 
disapproved portions of the Arkansas Regional Haze SIP and interstate 
visibility transport SIP.\7\ On May 1, 2015, we published a notice 
extending the public comment period for our FIP proposal and announcing 
the availability in the docket of supplemental modeling we performed 
for the Entergy Independence Plant following the April 8, 2015 
publication of our FIP proposal.\8\ On July 23, 2015, we published a 
notice reopening the public comment period for our FIP proposal by 15 
days in response to a request we received from the Domtar Ashdown Mill 
so that the facility would be able to complete modeling work and submit 
to us information it deemed to be essential and related to a 
significant aspect of the proposed FIP requirements for the Domtar 
Ashdown Mill.\9\ The reopening of the comment period also allowed other 
interested persons additional time to submit comments to us on our FIP 
proposal. On April 4, 2016, we published a notice and welcomed comment 
on supplemental information added to the docket which we relied on in 
our FIP proposal published on April 8, 2015, but which was 
inadvertently omitted from the docket at the time we proposed our 
FIP.\10\ Our notice published on April 4, 2016, also reopened the 
public comment period for our FIP proposal until May 4, 2016, but 
strictly limited the reopening of the comment period to our 
calculations of the revised RPGs, as presented in the spreadsheet we 
made available at that time in the docket.\11\ In this action, we are 
finalizing our FIP proposal published on April 8, 2015, and the 
associated aforementioned supplemental notices.
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    \7\ 80 FR 18944.
    \8\ 80 FR 24872.
    \9\ 80 FR 43661.
    \10\ 81 FR 19097.
    \11\ See the spreadsheet titled ``Caney Creek and Upper Buffalo 
Wilderness Areas Reasonable Progress Goals (CACR UPBU RPG 
analysis.xlsx),'' which is available in the docket for our 
rulemaking.
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B. EPA's Authority To Promulgate a FIP

    Under CAA section 110(c), EPA is required to promulgate a FIP at 
any time within 2 years of the effective date of a finding that a state 
has failed to make a required SIP submission or has made an incomplete 
submission, or of the date that EPA disapproves a SIP in whole or in 
part. The FIP requirement is terminated only if a state submits a SIP, 
and EPA approves that SIP as meeting applicable CAA requirements before 
promulgating a FIP. CAA section 302(y) defines the term ``Federal 
implementation plan'' in pertinent part, as a plan (or portion thereof) 
promulgated by EPA ``to fill all or a portion of a gap or otherwise 
correct all or a portion of an inadequacy'' in a SIP, and which 
includes enforceable emission limitations or other control measures, 
means or techniques (including economic incentives, such as marketable 
permits or auctions or emissions allowances).

[[Page 66334]]

    As discussed above, in a final action published on March 12, 2012, 
we disapproved in part the Arkansas Regional Haze SIP and the SIP 
submitted by the state to address the interstate visibility transport 
requirement of CAA section 110(a)(2)(D)(i)(II) for the 1997 8-hour 
ozone and 1997 PM2.5 NAAQS.\12\ That final action became 
effective on April 11, 2012. Therefore, EPA is required under CAA 
section 110(c) to promulgate a FIP for the portions of the Arkansas 
Regional Haze SIP and the SIP submittal to address the interstate 
visibility transport requirement of CAA section 110(a)(2)(D)(i)(II) for 
the 1997 8-hour ozone and 1997 PM2.5 NAAQS that we 
disapproved on March 12, 2012.
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    \12\ 77 FR 14604.
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III. Summary of Our Proposed Rule

    In this section, we provide a summary of our proposed rule that was 
published in the Federal Register on April 8, 2015,\13\ and the 
associated supplemental notices published on May 1, 2015,\14\ and April 
4, 2016,\15\ as background for understanding this final action. Our 
electronic docket at www.regulations.gov contains Technical Support 
Documents (TSDs) and other materials that supported our proposal and 
supplemental notices.
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    \13\ 80 FR 18944.
    \14\ 80 FR 24872.
    \15\ 81 FR 19097.
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A. Regional Haze

    Our FIP proposal addressed the disapproved portions of the Arkansas 
Regional Haze SIP and interstate visibility transport SIP. In our March 
12, 2012 final action on the Arkansas Regional Haze SIP, we disapproved 
some of the state's BART determinations and we also determined that the 
SIP did not include the required analysis of the four reasonable 
progress factors. Therefore, we partially disapproved the state's LTS 
for Caney Creek and Upper Buffalo and also disapproved the RPGs 
established by the state.
    CAA section 169A(b)(2)(A) requires states to revise their SIPs to 
contain such measures as may be necessary to make reasonable progress 
towards 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,'' as determined by the state or EPA in the case of 
a plan promulgated under section 110(c) of the CAA. Under the Regional 
Haze Rule, states are directed to conduct BART determinations for such 
``BART-eligible'' sources that may be anticipated to cause or 
contribute to any visibility impairment in a Class I area. Rather than 
requiring source-specific BART controls, states or EPA in a FIP also 
have the flexibility to adopt an emissions trading program or other 
alternative program as long as the alternative provides greater 
reasonable progress towards improving visibility than BART. CAA section 
169(g)(2) and the Regional Haze Rule at 40 Code of Federal Regulations 
(CFR) Sec.  51.308(e)(1)(A) provide that in determining BART, the state 
or EPA in a FIP shall take into consideration the following factors: 
Costs of compliance, the energy and nonair quality environmental 
impacts of compliance, any existing pollution control technology in use 
at the source, the remaining useful life of the source, and the degree 
of improvement in visibility which may reasonably be anticipated to 
result from the use of such technology. We commonly refer to these as 
the BART factors, or the five statutory factors. CAA section 169(g)(1) 
and Sec.  51.308(d)(1) also require that in determining reasonable 
progress, there shall be taken into consideration the costs of 
compliance, the time necessary for compliance, the energy and nonair 
quality environmental impacts of compliance, and the remaining useful 
life of any existing source subject to such requirements. We commonly 
refer to these as the reasonable progress factors, or the four 
statutory factors. Consistent with the requirement in CAA section 
169A(b) that states include in their regional haze SIP a 10--15 year 
strategy for making reasonable progress, Sec.  51.308(d)(3) requires 
that states include a LTS in their regional haze SIPs. The LTS is the 
compilation of all control measures a state will use during the 
implementation period of the specific SIP submittal to meet any 
applicable RPGs. The LTS must include enforceable emissions 
limitations, compliance schedules, monitoring and recordkeeping 
requirements, and various supporting documentation and analyses to 
ensure that the SIP or FIP will provide reasonable progress toward the 
national goal of natural visibility conditions.
    Our FIP proposal included proposed BART determinations for nine 
units at six facilities and proposed reasonable progress determinations 
for two units at one facility in Arkansas. These determinations 
resulted in proposed emission limits, compliance schedules, and other 
requirements for these sources. The proposed regulatory language was 
included under Part 52 at the end of that document. We also addressed 
the RPGs, as well as the LTS requirements. Lastly, we proposed that the 
approved measures in the Arkansas Regional Haze SIP and measures in our 
proposed FIP would adequately address the interstate transport of 
pollutants that affect visibility requirement for the 1997 8-hour ozone 
and 1997 PM2.5 NAAQS.
    Georgia Pacific-Crossett Mill 6A and 9A Power Boilers: In our FIP 
proposal, we proposed to find that the Georgia Pacific-Crossett Mill 6A 
Boiler is a BART-eligible source, but not subject to BART. We also 
proposed to find that the 9A Boiler, which the State had previously 
determined was BART-eligible, is not subject to BART. Our proposed 
determinations were based on the company's newly provided analysis and 
documentation, including BART screening modeling conducted in 2011 by 
Georgia Pacific based on revised emission limits from a permit issued 
on May 23, 2012, and using 2001, 2002, and 2003 meteorology. The 
modeling showed the maximum visibility impact from the boilers was 
0.359 deciviews (dv) at Caney Creek, which is below the 0.5 dv 
threshold the state used in the Arkansas Regional Haze SIP to identify 
subject-to-BART sources. Prior to issuing our FIP proposal, we had 
communicated to ADEQ our concern with relying on the company's BART 
screening modeling that was based on revised emission limits from a 
permit issued in 2012, without documentation that these emission limits 
were representative of the baseline period emissions.\16\ To address 
our concern, the company provided estimates of maximum 24-hour emission 
rates for the 6A and 9A Boilers from the 2001-2003 baseline period to 
demonstrate that these emission rates were lower than the revised 
emission limits that it modeled in its 2011 BART screening 
modeling.\17\ This indicated that the 2011 BART screening modeling that 
was based on allowable emissions was conservative in terms of 
representing the impact that the source had on visibility in the 2001-
2003 period, the period that matters for the subject-to-BART 
determination, and we proposed to find that it is reasonable to 
conclude based on the modeling analysis and documentation provided by 
Georgia Pacific that the 6A and 9A Boilers had visibility impacts below 
0.5

[[Page 66335]]

dv during the 2001-2003 baseline period and are therefore not subject 
to BART.
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    \16\ See file titled ``Region 6 feedback on Georgia Pacific 6A 
and 9A Boilers_3-4-2013,'' which is found in the docket associated 
with this rulemaking.
    \17\ As discussed in our proposal, Georgia Pacific estimated the 
maximum 24-hour emission rates using daily fuel usage data and 
emission factors from AP-42, Compilation of Air Pollutant Emission 
Factors. See 80 FR 18944, 18948.
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    AECC Bailey Unit 1: We proposed that BART for SO2 and PM 
is the use of fuels with 0.5% or lower sulfur content by weight. We 
also proposed to require that, after the effective date of the final 
rule, the facility shall not purchase fuel that does not meet the 
sulfur content requirement, but to allow the facility 5 years to burn 
its existing supply of No. 6 fuel oil, in accordance with any operating 
restrictions enforced by ADEQ. We proposed to require the facility to 
comply with the requirement to use fuels with 0.5% or lower sulfur 
content by weight no later than 5 years from the effective date of the 
final rule. We proposed that BART for NOX is the existing 
emission limit in the permit of 887 lb/hr, which would not necessitate 
the installation of additional controls. We proposed to require the 
source to comply with this emission limit for BART purposes as of the 
effective date of the final rule.
    AECC McClellan Unit 1: We proposed that BART for SO2 and 
PM is the use of fuels with 0.5% or lower sulfur content by weight. We 
also proposed to require that, after the effective date of the final 
rule, the facility shall not purchase fuel that does not meet the 
sulfur content requirement, but to allow the facility 5 years to burn 
its existing supply of No. 6 fuel oil, in accordance with any operating 
restrictions enforced by ADEQ. We proposed to require the source to 
comply with the requirement to use fuels with 0.5% or lower sulfur 
content by weight no later than 5 years from the effective date of the 
final rule. We proposed that BART for NOX are the existing 
emission limits in the permit of 869.1 lb/hr for natural gas firing and 
705.8 lb/hr for fuel oil firing, which would not necessitate the 
installation of additional controls. We proposed to require the source 
to comply with these emission limits for BART purposes as of the 
effective date of the final rule.
    AEP Flint Creek Unit 1: We proposed that BART for SO2 is 
an emission limit of 0.06 lb/MMBtu on a 30 boiler-operating-day rolling 
average, which is consistent with the installation and operation of a 
type of dry flue gas desulfurization (FGD or ``scrubbers'') system 
called Novel Integrated Desulfurization (NID) technology. We stated 
that the full compliance time of 5 years allowed under the CAA and 
Regional Haze Rule is appropriate for a new scrubber retrofit, and 
proposed to require the source to comply with this emission limit no 
later than 5 years from the effective date of the final rule. We 
proposed that BART for NOX is an emission limit of 0.23 lb/
MMBtu on a 30 boiler-operating-day rolling average, which is consistent 
with the installation and operation of new low NOX burners 
(LNB) with overfire air (OFA). We proposed to require the source to 
comply with this emission limit no later than 3 years from the 
effective date of the final rule.
    Entergy White Bluff Units 1 and 2: We proposed that BART for 
SO2 for Units 1 and 2 is an emission limit of 0.06 lb/MMBtu 
on a 30 boiler-operating-day rolling average, consistent with the 
installation and operation of dry FGD or another control technology 
that achieves that level of control. We proposed to require the source 
to comply with this emission limit no later than 5 years from the 
effective date of the final rule. We proposed that BART for 
NOX for Units 1 and 2 is an emission limit of 0.15 lb/MMBtu 
on a 30 boiler-operating-day rolling average, consistent with the 
installation and operation of LNB with separated overfire air (SOFA). 
We proposed to require the source to comply with this emission limit no 
later than 3 years from the effective date of the final rule.
    Entergy White Bluff Auxiliary Boiler: We proposed that the existing 
emission limit in the permit of 105.2 lb/hr is BART for SO2, 
the existing emission limit of 32.2 lb/hr is BART for NOX, 
and the existing emission limit of 4.5 lb/hr is BART for PM for the 
Auxiliary Boiler. These emission limits would not necessitate the 
installation of additional controls. We proposed to require the source 
to comply with these emission limits for BART purposes as of the 
effective date of the final rule.
    Entergy Lake Catherine Unit 4: We proposed that BART for 
NOX for the natural gas-firing scenario is an emission limit 
of 0.22 lb/MMBtu on a 30 boiler-operating-day rolling average, 
consistent with the installation and operation of burners out of 
service (BOOS). We proposed to require the source to comply with this 
emission limit no later than 3 years from the effective date of the 
final rule. We invited public comment specifically on whether this 
proposed NOX emission limit is appropriate or whether an 
emission limit based on more stringent NOX controls would be 
appropriate. We did not propose BART determinations for the fuel oil-
firing scenario for Lake Catherine Unit 4 in light of the source's 
commitment to submit to Arkansas a five-factor BART analysis for the 
fuel oil-firing scenario, to then be submitted to us as a SIP revision 
for approval, before any fuel oil combustion takes place at Unit 4. We 
proposed that fuel oil-firing is not allowed to take place at Lake 
Catherine Unit 4 until BART determinations are promulgated for 
SO2, NOX, and PM for the fuel oil-firing scenario 
through our approval of a SIP revision and/or promulgation of a FIP.
    Domtar Ashdown Mill Power Boiler No. 1: We proposed that BART for 
SO2 is an emission limit of 21.0 lb/hr on a 30 boiler-
operating-day averaging basis, where boiler-operating-day is defined as 
a 24-hour period between 12 midnight and the following midnight during 
which any fuel is fed into and/or combusted at any time in the Power 
Boiler. This emission limit is consistent with the Power Boiler's 
baseline emissions and would not necessitate additional controls. We 
proposed to require the source to comply with this emission limit as of 
the effective date of the final rule. We proposed to require the source 
to use a site-specific curve equation,\18\ provided to us by the 
facility, to calculate the SO2 emissions from Power Boiler 
No. 1 when combusting bark for purposes of demonstrating compliance 
with the BART requirement, and to confirm the curve equation using 
stack testing no later than 1 year from the effective date of the final 
rule. We also proposed that to calculate the SO2 emissions 
from fuel oil combustion for purposes of demonstrating compliance with 
the BART requirement, the facility must assume that the SO2 
inlet \19\ is equal to the SO2 being emitted at the stack. 
We invited public comment on whether this method of demonstrating 
compliance with the proposed SO2 BART emission limit for 
Power Boiler No. 1 is appropriate.
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    \18\ The curve equation is Y = 0.4005 * X-0.2645, where Y = 
pounds of sulfur emitted per ton dry fuel feed to the boiler and X = 
pounds of sulfur input per ton of dry bark. The purpose of this 
equation is to factor in the degree of SO2 scrubbing 
provided by the combustion of bark.
    \19\ We define SO2 inlet to be the SO2 
content of the fuel delivered to the fuel inlet of the combustion 
chamber.
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    We proposed that BART for NOX is an emission limit of 
207.4 lb/hr on a 30 boiler-operating-day rolling average, where boiler-
operating-day is defined as a 24-hour period between 12 midnight and 
the following midnight during which any fuel is fed into and/or 
combusted at any time in the Power Boiler. This emission limit is 
consistent with the Power Boiler's baseline emissions and would not 
necessitate additional controls. We proposed to require the source to 
comply with this emission limit as of the effective date of the final 
rule. To demonstrate compliance with this NOX BART emission 
limit, we proposed to require the source to conduct annual stack

[[Page 66336]]

testing. We invited public comment on the appropriateness of this 
method for demonstrating compliance with the proposed NOX 
BART emission limit for Power Boiler No. 1.
    Domtar Ashdown Mill Power Boiler No. 2: We proposed that BART for 
SO2 is an emission limit of 0.11 lb/MMBtu on a 30 boiler-
operating-day rolling average, which we estimated is representative of 
operating the existing venturi scrubbers at 90% control efficiency and 
can be achieved through the installation of scrubber pump upgrades and 
use of additional scrubbing reagent. We indicated that boiler-
operating-day is defined as a 24-hour period between 12 midnight and 
the following midnight during which any fuel is fed into and/or 
combusted at any time in the Power Boiler. We invited public comment 
specifically on the appropriateness of our proposed SO2 
emission limit. We proposed to require compliance with this BART 
emission limit no later than 3 years from the effective date of the 
final action, but invited public comment on the appropriateness of a 
compliance date anywhere from 1-5 years. We also proposed to require 
the source to demonstrate compliance with this emission limit using the 
existing continuous emissions monitoring system (CEMS).
    We proposed that BART for NOX is an emission limit of 
345 lb/hr on a 30 boiler-operating-day rolling averaging basis, 
consistent with the installation and operation of LNB. We indicated 
that boiler-operating-day is defined as a 24-hour period between 12 
midnight and the following midnight during which any fuel is fed into 
and/or combusted at any time in the Power Boiler. We proposed to 
require compliance with this emission limit no later than 3 years from 
the effective date of the final rule, and invited public comment on the 
appropriateness of this compliance date. We also proposed to require 
the source to demonstrate compliance with this emission limit using the 
existing CEMS.
    Power Boiler No. 2 is subject to the Boiler Maximum Achievable 
Control Technology (MACT) standards for PM required under CAA section 
112, and found at 40 CFR part 63, subpart DDDDD--National Emission 
Standards for Hazardous Air Pollutants for Major Sources: Industrial, 
Commercial, and Institutional Boilers and Process Heaters. We proposed 
to find that the current Boiler MACT PM standard satisfies the PM BART 
requirement for Power Boiler No. 2. We also proposed that the same 
method for demonstrating compliance with the Boiler MACT PM standard is 
to be used for demonstrating compliance with the PM BART emission 
limit. We proposed to require the source to comply with this emission 
limit for BART purposes as of the effective date of the final rule.
    Proposed Reasonable Progress Determinations: In our proposed rule, 
we explained that the Central Regional Air Planning Association 
(CENRAP) CAMx modeling with Particulate Source Apportionment Tool 
(PSAT) showed that point sources are responsible for a majority of the 
light extinction at Arkansas Class I areas, contributing approximately 
60% of the total light extinction at each Class I area on the 20% worst 
days in 2002. Point sources contributed 81.04 Mm-\1\ out of 
133.93 Mm-\1\ of light extinction at Caney Creek and 77.80 
Mm-\1\ out of 131.79 Mm-\1\ of light extinction 
at Upper Buffalo on the average across the 20% worst days in 2002. 
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, we decided to focus only on point 
sources in our reasonable progress analysis for this planning period.
    As a starting point in our analysis to determine whether additional 
controls on Arkansas sources are necessary to make reasonable progress 
in the first regional haze planning period, we examined the most recent 
SO2 and NOX emissions inventories for point 
sources in Arkansas. Based on the 2011 National Emissions Inventory 
(NEI), the Entergy White Bluff Plant, the Entergy Independence Plant, 
and the AEP Flint Creek Power Plant are the three largest point sources 
of SO2 and NOX emissions in Arkansas.\20\ The 
combined annual emissions from these three sources make up 
approximately 84% of the statewide SO2 point-source 
emissions and 55% of the statewide NOX point-source 
emissions. As our proposed rule included SO2 and 
NOX emission limits under BART for White Bluff Units 1 and 2 
and Flint Creek Unit 1 that are anticipated to result in a substantial 
reduction in SO2 and NOX emissions from these 
facilities, we proposed to determine that it is appropriate to 
eliminate these three units from further consideration of additional 
controls under the reasonable progress requirements for the first 
planning period. The Entergy Independence Plant is not subject to BART, 
and its emissions were 30,398 SO2 tons per year (tpy) and 
13,411 NOX tpy based on the 2011 NEI. The Entergy 
Independence Plant is the second largest source of SO2 and 
NOX point-source emissions in Arkansas, accounting for 
approximately 36% of the SO2 point-source emissions and 21% 
of the NOX point-source emissions in the State. In our 
proposal, we explained that it is appropriate to focus our reasonable 
progress analysis on the Entergy Independence Power Plant because it is 
a significant source of SO2 and NOX, as it is the 
second largest point source for both NOX and SO2 
emissions in the State. We explained that our proposed SO2 
and NOX controls under BART for White Bluff Units 1 and 2 
and Flint Creek Unit 1 and our evaluation of controls under reasonable 
progress for the Independence facility would address a sufficient 
amount of SO2 and NOX point source emissions in 
the State in this first planning period. The fourth largest 
SO2 and NOX point sources in Arkansas are the 
Future Fuel Chemical Company, with emissions of 3,421 SO2 
tpy, and the Natural Gas Pipeline Company of America #308, with 
emissions of 3,194 NOX tpy (2011 NEI). In comparison to the 
SO2 and NOX emissions from the top three point 
sources (i.e., White Bluff, Independence, and Flint Creek), emissions 
from these two facilities and remaining point sources in the state are 
relatively small. Therefore, we did not evaluate other Arkansas point 
sources in our reasonable progress analysis. We explained that it is 
therefore appropriate to defer the consideration and evaluation of any 
additional sources under reasonable progress to future regional haze 
planning periods.
---------------------------------------------------------------------------

    \20\ See NEI 2011 v1. A spreadsheet containing the emissions 
inventory is found in the docket for our proposed rulemaking.
---------------------------------------------------------------------------

    We conducted source-specific reasonable progress analyses of 
potential SO2 and NOX controls for Independence 
Units 1 and 2 and conducted CALPUFF modeling to assess the baseline 
visibility impacts from the facility and potential visibility benefits 
of controls. Based on these analyses, we proposed two options in the 
alternative for satisfying the reasonable progress requirements for 
Independence Units 1 and 2. Under Option 1, we proposed to establish 
both SO2 and NOX emission limits. We proposed to 
require compliance with an SO2 emission limit of 0.06 lb/
MMBtu for Independence Units 1 and 2 based on a 30 boiler-operating-day 
rolling average basis, consistent with the installation and operation 
of dry FGD. We proposed to require Independence Units 1 and 2 to comply 
with this emission limit no later than 5 years from the effective date 
of the final rule. We proposed to require compliance with a 
NOX emission limit of 0.15 lb/MMBtu on a 30 boiler-
operating-day averaging basis,

[[Page 66337]]

consistent with the installation and operation of LNB/SOFA. We proposed 
to require Independence Units 1 and 2 to comply with this emission 
limit no later than 3 years from the effective date of the final rule.
    We proposed to require SO2 controls based on our 
evaluation of the four reasonable progress factors, our CALPUFF 
modeling of the anticipated benefits of controls, and the existing 
CENRAP CAMx modeling. Specifically, we proposed that dry FGD was cost-
effective and would provide considerable visibility improvement on the 
days where Independence has the largest impacts at nearby Class I 
areas. Additionally, the CENRAP CAMx modeling showed that on most of 
the 20% worst days in 2002, total extinction is dominated by sulfate at 
both Caney Creek and Upper Buffalo.\21\ Therefore, we concluded that 
the substantial SO2 emissions reductions that would be 
achieved by our proposed SO2 controls for Independence Units 
1 and 2 would accordingly reduce visibility extinction at Arkansas' 
Class I areas on the 20% worst days.
---------------------------------------------------------------------------

    \21\ See Arkansas Regional Haze SIP, Appendix 8.1--``Technical 
Support Document for CENRAP Emissions and Air Quality Modeling to 
Support Regional Haze State Implementation Plans,'' sections 3.7.1 
and 3.7.2. See the docket for this rulemaking for a copy of the 
Arkansas Regional Haze SIP.
---------------------------------------------------------------------------

    We also proposed to require NOX controls under Option 1 
based on our evaluation of the four reasonable progress factors, our 
CALPUFF modeling of the anticipated benefits of controls, and the 
existing CENRAP CAMx modeling. Specifically, we proposed that LNB/SOFA 
was very cost-effective and would provide considerable visibility 
improvement on the days where Independence has the largest impacts at 
nearby Class I areas. In addition, the CENRAP CAMx modeling showed that 
total extinction at Caney Creek was dominated by nitrate on 4 of the 
days that comprise the 20% worst days in 2002, while a significant 
portion of the total extinction at Upper Buffalo was due to nitrate on 
2 of the days that comprise the 20% worst days in 2002.\22\ Therefore, 
we concluded that our proposed NOX controls on Independence 
Units 1 and 2 would improve visibility on some of the 20% worst days. 
In the alternative, we proposed under Option 2 to require only 
SO2 controls for Independence Units 1 and 2 under the CAA's 
reasonable progress requirements. Our reasoning for proposing to 
require only SO2 controls under Option 2 was that nitrate 
from point sources is not a primary contributor to the total light 
extinction at Arkansas Class I areas on most of the 20% worst days, so 
NOX controls would not offer as much visibility improvement 
on the most impaired days as SO2 controls. In our proposed 
rule, we specifically solicited public comment on Options 1 and 2.
---------------------------------------------------------------------------

    \22\ See Arkansas Regional Haze SIP, Appendix 8.1--``Technical 
Support Document for CENRAP Emissions and Air Quality Modeling to 
Support Regional Haze State Implementation Plans,'' section 3.7.1 
and 3.7.2. See the docket for this rulemaking for a copy of the 
Arkansas Regional Haze SIP.
---------------------------------------------------------------------------

    In addition to Options 1 and 2, we also solicited public comment on 
any alternative SO2 and NOX control measures that 
would address the regional haze requirements for Entergy White Bluff 
Units 1 and 2 and Entergy Independence Units 1 and 2 for this planning 
period. We noted that this could include, but was not limited to, a 
combination of early unit shutdowns and other emissions control 
measures that would achieve greater reasonable progress than the BART 
and reasonable progress requirements we proposed for these four units 
in our proposed rule.
    On May 1, 2015, we published a notice in the Federal Register 
announcing supplemental modeling that we conducted for Independence 
Units 1 and 2, and extending the comment period to allow interested 
persons additional time to provide comments on the supplemental 
modeling.\23\ We performed the supplemental modeling after receiving a 
letter dated April 13, 2015, that revealed that we made an error in the 
modeled location of the Entergy Independence facility.\24\ The 
supplemental modeling included the corrected facility location. We 
provided a summary of our supplemental modeling for Independence Units 
1 and 2 in the docket for our proposed rulemaking.\25\ In the summary, 
we provided a comparison of our previous CALPUFF modeling for 
Independence Units 1 and 2 (i.e., the modeling that was presented in 
our proposed rule published on April 8, 2015) and our supplemental 
modeling. We noted that the modeled visibility benefits from our 
proposed SO2 controls (dry FGD) for Independence were the 
same or larger in the supplemental modeling. The largest difference was 
an increase of 0.29 dv in the modeled visibility benefit from 
SO2 controls at Upper Buffalo. The largest modeled benefit 
from NOX controls was at Caney Creek and was approximately 
the same in the supplemental modeling. Modeled visibility benefits from 
NOX controls at the three other Class I areas were slightly 
smaller in the supplemental modeling. The change in location of the 
modeled facility resulted in different transport patterns from the 
facility to the Class I areas, which resulted in the modeled 98th 
percentile visibility impacts being more driven by sulfate impacts. 
Therefore, the benefits from NOX controls on the 98th 
percentile days were slightly reduced. In addition, whereas our 
previous modeling of the control scenario that included both dry FGD 
and LNB/SOFA controls showed visibility benefits ranging from 1.18 to 
1.48 dv at each Class I area, the supplemental modeling showed larger 
visibility benefits ranging from 1.40 to 1.52 dv at each Class I area. 
After reviewing the supplemental modeling, we did not change our 
proposed reasonable progress controls for Independence Units 1 and 2.
---------------------------------------------------------------------------

    \23\ 80 FR 24872.
    \24\ April 13, 2015 letter from Mr. Bill Bumpers to Mr. Guy 
Donaldson, Chief, Air Planning Section, EPA Region 6, ``Entergy 
Arkansas Inc. (EAI) request for extension of comment period on EPA-
R06-OAR-2015-0189-0001.'' This document is found in the docket for 
this rulemaking.
    \25\ See document titled ``Summary of Additional Modeling for 
Entergy Independence,'' dated April 20, 2015. This document is found 
in the docket for this rulemaking.
---------------------------------------------------------------------------

    Proposed Reasonable Progress Goals: We proposed RPGs for Caney 
Creek and Upper Buffalo that reflected the anticipated visibility 
conditions resulting from the combination of control measures from the 
approved portion of the 2008 Arkansas Regional Haze SIP and our FIP 
proposal. As explained more fully in our proposal, we adjusted the 2018 
RPGs modeled by CENRAP using a scaling methodology that adjusted 
visibility extinction components in proportion to emission changes. We 
recognized that this method was not refined, but explained that it 
allowed us to incorporate the additional emission reductions achieved 
through the FIP into the states' RPGs. Based on this methodology, we 
proposed revised RPGs for the first planning period for the 20% worst 
days of 22.27 dv for Caney Creek and 22.33 dv for Upper Buffalo.
    Our proposed revised RPGs and our methodology for calculating the 
revised RPGs were discussed in detail in our FIP proposal and in our 
technical support documentation,\26\ which was made available in the 
docket when the proposed rule was published on April 8, 2015. However, 
a spreadsheet containing the actual calculations of our proposed 
revised RPGs for the 20% worst days for the Caney Creek and Upper 
Buffalo Wilderness Areas was inadvertently omitted from the docket. On 
April 4, 2016, we published a notice in the Federal Register announcing 
the

[[Page 66338]]

availability in the docket of the spreadsheet containing the actual 
calculations of our proposed revised RPGs for the 20% worst days for 
the Caney Creek and Upper Buffalo Wilderness Areas.\27\ The notice also 
reopened the comment period for our FIP proposal until May 4, 2016, but 
strictly limited the reopening of the comment period to our 
calculations of the revised RPGs, as presented in the spreadsheet we 
made available at that time in the docket.\28\
---------------------------------------------------------------------------

    \26\ See ``Technical Support Document for EPA's Proposed Action 
on the Arkansas Regional Haze Federal Implementation Plan'' at page 
147.
    \27\ 81 FR 19097.
    \28\ See the document titled ``Caney Creek and Upper Buffalo 
Wilderness Areas Reasonable Progress Goals (CACR UPBU RPG 
analysis.xlsx),'' which is available in the docket for our 
rulemaking.
---------------------------------------------------------------------------

    Long-Term Strategy: We proposed to find that provisions in the 
approved portion of the Arkansas Regional Haze SIP and our FIP proposal 
fulfilled the requirements of 40 CFR 51.308(d)(3), which requires 
emission limitations, compliance schedules, monitoring and 
recordkeeping requirements, and various supporting documentation and 
analyses to ensure that the SIP or FIP will provide reasonable progress 
toward the national goal. Specifically, we proposed to promulgate 
emission limits, compliance schedules, and other requirements for 
Arkansas' BART sources and the two units at the Independence facility 
to address the long-term strategy requirement.

B. Interstate Visibility Transport

    Among other things, CAA section 110(a)(2)(D)(i)(II) requires that 
all SIPs contain adequate provisions to prohibit emissions that will 
interfere with measures required to protect visibility in other states. 
We refer to this as the interstate transport visibility requirement. 
Our proposed FIP included emission limits for Arkansas sources under 
the BART and reasonable progress requirements that would ensure a level 
of emissions reductions at least as great as what surrounding states 
relied on in developing their regional haze SIPs. We proposed that the 
combination of the measures in the approved portions of the Arkansas 
Regional Haze SIP and our FIP proposal would satisfy the visibility 
requirement of CAA section 110(a)(2)(D)(i)(II) for the 1997 8-hour 
ozone and 1997 PM2.5 NAAQS.

IV. Summary of Our Final FIP

    Below, we present a summary of our final Arkansas Regional Haze 
FIP. In this section, we provide a summary of our final BART 
determinations, reasonable progress determinations, revised RPGs, LTS 
provisions, and interstate transport provisions. This final FIP 
includes emission limits, compliance schedules, and requirements for 
equipment maintenance, monitoring, testing, recordkeeping, and 
reporting for all affected sources and units.
    We note that we are finalizing our FIP with certain changes to our 
proposal in response to comments we received during the public comment 
period. In particular, we are finalizing a bifurcated NOX 
BART emission limit for White Bluff Units 1 and 2; we are finalizing an 
SO2 BART emission limit for the Domtar Ashdown Mill Power 
Boiler No. 1 in the form of lb/day based on a 30 boiler-operating-day 
average instead of lb/hr based on a 30 boiler-operating-day average; 
and we are finalizing an SO2 BART emission limit for the 
Domtar Ashdown Mill Power Boiler No. 2 in the form of lb/hr based on a 
30 boiler-operating-day average instead of lb/MMBtu based on a 30 
boiler-operating-day average. In light of information we received 
during the public comment period, we are also adjusting the compliance 
dates for some of our BART determinations. We are requiring AEP Flint 
Creek Unit 1 to comply with the SO2 BART emission limit 
within 18 months of the effective date of this final action, instead of 
the 5-year compliance date we proposed. We are requiring AEP Flint 
Creek Unit 1 and White Bluff Units 1 and 2 to comply with the 
NOX BART emission limit within 18 months of the effective 
date of this final action, instead of the 3-year compliance date we 
proposed. We are requiring the Domtar Ashdown Mill to comply with the 
SO2 and NOX BART emission limits for Power Boiler 
No. 1 and the PM BART emission limit for Power Boiler No. 2 within 30 
days from the effective date of this final action instead of on the 
date of the final action. We are requiring the Domtar Ashdown Mill to 
comply with the SO2 and NOX BART emission limits 
for Power Boiler No. 2 within 5 years of the effective date of this 
final action, instead of the 3-year compliance date we proposed. We are 
making some adjustments to the requirements for demonstrating 
compliance, testing, reporting, and recordkeeping for SO2 
and NOX BART for the Domtar Ashdown Mill Power Boiler No. 1 
and for SO2, NOX, and PM BART for Power Boiler 
No. 2. We are also revising the definition of boiler-operating-day as 
it applies to Power Boilers No. 1 and 2 under this FIP.
    We are finalizing SO2 and NOX controls under 
reasonable progress for Independence Units 1 and 2 (our proposed Option 
1). In response to comments we received during the public comment 
period, we are finalizing a bifurcated NOX emission limit 
for Independence Units 1 and 2 and are requiring the source to comply 
with the NOX emission limit within 18 months of the 
effective date of this final action instead of the 3-year compliance 
date we proposed. We are also providing revised RPGs for Arkansas' 
Class I areas that reflect anticipated visibility conditions at the end 
of the implementation period in 2018 rather than the anticipated 
visibility conditions once the FIP has been fully implemented.
    These changes to our proposal are discussed in more detail in the 
subsections that follow and in our separate Response to Comment (RTC) 
document, which can be found in the docket for this final rulemaking. 
The final regulatory language for the FIP is under Part 52 at the end 
of this notice.
    The final FIP requires that subject-to-BART sources comply with the 
emission limits contained in Table 1 below and that the Independence 
Plant comply with the emission limits contained in Table 2 below. We 
are determining that the BART emission limits for the sources listed in 
Table 1 are also sufficient for reasonable progress. Throughout this 
section of the final rule, we specify the averaging basis of each 
emission limit and associated compliance dates.

                                       Table 1--Final BART Emission Limits
----------------------------------------------------------------------------------------------------------------
                                          Final SO2 emission       Final NOX emission
                 Unit                           limit                    limit           Final PM emission limit
----------------------------------------------------------------------------------------------------------------
Bailey Unit 1........................  0.5% limit on sulfur     887 lb/hr \a\..........  0.5% limit on sulfur
                                        content of fuel                                   content of fuel
                                        combusted.                                        combusted.
McClellan Unit 1.....................  0.5% limit on sulfur     869.1 lb/hr \b\/705.8    0.5% limit on sulfur
                                        content of fuel          lb/hr \b\.               content of fuel
                                        combusted.                                        combusted.

[[Page 66339]]

 
Flint Creek Unit 1...................  0.06 lb/MMBtu..........  0.23 lb/MMBtu..........  EPA approved the
                                                                                          state's BART
                                                                                          determination in March
                                                                                          12, 2012 final action
                                                                                          (77 FR 14604).
White Bluff Unit 1...................  0.06 lb/MMBtu..........  0.15 lb/MMBtu \c\/671    EPA approved the
                                                                 lb/hr \d\.               state's BART
                                                                                          determination in March
                                                                                          12, 2012 final action
                                                                                          (77 FR 14604).
White Bluff Unit 2...................  0.06 lb/MMBtu..........  0.15 lb/MMBtu \c\/671    EPA approved the
                                                                 lb/hr \d\.               state's BART
                                                                                          determination in March
                                                                                          12, 2012 final action
                                                                                          (77 FR 14604).
White Bluff Auxiliary Boiler.........  105.2 lb/hr \a\........  32.2 lb/hr \a\.........  4.5 lb/hr \a\.
Lake Catherine Unit 4 \e\............  EPA approved the         0.22 lb/MMBtu..........  EPA approved the
                                        state's BART                                      state's BART
                                        determination in March                            determination in March
                                        12, 2012 final action                             12, 2012 final action
                                        (77 FR 14604).                                    (77 FR 14604).
Domtar Ashdown Mill Power Boiler No.   504 lb/day \f\.........  207.4 lb/hr \f\........  EPA approved the
 1.                                                                                       state's BART
                                                                                          determination in March
                                                                                          12, 2012 final action
                                                                                          (77 FR 14604).
Domtar Ashdown Mill Power Boiler No.   91.5 lb/hr.............  345 lb/hr..............  PM BART shall be
 2.                                                                                       satisfied by relying
                                                                                          on the applicable PM
                                                                                          standard under 40 CFR
                                                                                          part 63, subpart DDDDD
                                                                                          \g\.
----------------------------------------------------------------------------------------------------------------
\a\ Existing emission limit; we do not anticipate that the facility will have to install any additional control
  to comply with this emission limit.
\b\ Existing emission limit; we do not anticipate that the facility will have to install any additional control
  to comply with this emission limit. Emission limit of 869.1 lb/hr applies to the natural gas-firing scenario;
  emission limit of 705.8 lb/hr applies to the fuel oil-firing scenario.
\c\ Emission limit of 0.15 lb/MMBtu applies when unit is operated at 50% or greater of the unit's maximum heat
  input rating.
\d\ Emission limit of 671 lb/hr applies when the unit is operated at less than 50% of the unit's maximum heat
  input rating.
\e\ Emission limit for NOX applies to the natural gas-firing scenario. The unit shall not burn fuel oil until
  BART determinations for SO2, NOX, and PM are promulgated for the unit for the fuel oil-firing scenario through
  EPA approval of a SIP revision or a FIP.
\f\ Emission limit is representative of baseline emissions; we do not anticipate that the facility will have to
  install any additional control to comply with this emission limit.
\g\ The facility shall rely on the applicable PM standard under 40 CFR part 63, subpart DDDDD--National Emission
  Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers
  and Process Heaters, as revised, to satisfy the PM BART requirement.

   Table 2--Final Reasonable Progress Emission Limits for Sources not
                             Subject to BART
------------------------------------------------------------------------
                                  Final SO2 emission  Final NOX emission
              Unit                       limit               limit
------------------------------------------------------------------------
Independence Unit 1.............  0.06 lb/MMBtu.....  0.15 lb/MMBtu \a\/
                                                       671 lb/hr \b\.
Independence Unit 2.............  0.06 lb/MMBtu.....  0.15 lb/MMBtu \a\/
                                                       671 lb/hr \b\.
------------------------------------------------------------------------
\a\ Emission limit of 0.15 lb/MMBtu applies when unit is operated at 50%
  or greater of the unit's maximum heat input rating.
\b\ Emission limit of 671 lb/hr applies when the unit is operated at
  less than 50% of the unit's maximum heat input rating.

A. Regional Haze

1. Identification of BART-Eligible and Subject-to-BART Sources
    We are finalizing our determination that the Georgia-Pacific 
Crossett Mill 6A Boiler is a BART-eligible source, but is not subject 
to BART. We are also finalizing our determination that the 9A Boiler, 
which the State had previously determined is BART-eligible, is not 
subject to BART. These determinations are based on the company's newly 
provided analysis and documentation, as described above and in our 
proposal. Therefore, the CAA and Regional Haze Rule do not require BART 
determinations for the 6A and 9A Boilers.
2. BART Determinations
a. AECC Bailey Unit 1
    Bailey Unit 1 burns primarily natural gas, but is also permitted to 
burn fuel oil. Our proposal explains why the source needs to retain the 
flexibility to use fuel oil. Taking into consideration the BART 
factors, we are finalizing BART determinations and emission limits for 
SO2, NOX, and PM as proposed. Our final BART 
determination for SO2 and PM is the use of fuels with 0.5% 
or lower sulfur content by weight. After the effective date of this 
final rule, the facility shall not purchase fuel for use in Unit 1 that 
does not meet this sulfur-content requirement. We are allowing the 
facility 5 years to burn its existing supply of No. 6 fuel oil in 
accordance with any operating restrictions enforced by ADEQ. Providing 
this time period will avoid creating an incentive for the source to 
burn large amounts of this fuel during a short period, which could 
affect visibility on individual days more adversely. We are requiring 
the facility to comply with the requirement to use only fuels with 0.5% 
or lower sulfur content by weight no later than 5 years from the 
effective date of this final rule. We discussed in detail in our 
proposal the cost effectiveness and projected visibility improvement of 
switching from the baseline fuel to fuels with a sulfur content by 
weight of 0.5% or lower, and also present this information in Tables 3 
and 4.\29\ We are not making changes to the analysis we presented in 
our proposal of the cost and visibility improvement of this control 
measure. As discussed in our proposal, the cost of switching from the 
baseline fuel to fuels with a sulfur content by weight of 0.5% or lower 
is within the range of what we consider to be cost effective for BART 
and it is projected to result in considerable visibility improvement at 
the affected Class I areas.\30\ We are finalizing this BART 
determination for SO2 and PM as proposed.
---------------------------------------------------------------------------

    \29\ See also 80 FR 18944, 18951, and 18955.
    \30\ 80 FR 18944, 18952, 18956.

[[Page 66340]]

  Table 3--AECC Bailey Unit 1--Cost Effectiveness of Switching to Fuel
                  With Sulfur Content of 0.5% or Lower
------------------------------------------------------------------------
                                                            No. 6 Fuel
                                                             oil--0.5%
                        Pollutant                         sulfur content
                                                              ($/ton)
------------------------------------------------------------------------
SO2.....................................................           2,559
PM......................................................           2,997
------------------------------------------------------------------------

 Table 4--AECC Bailey Unit 1--Summary of the 98th Percentile Visibility
Impacts And Improvement of Switching to Fuel With Sulfur Content of 0.5%
                                or Lower
------------------------------------------------------------------------
                                                         Visibility
                                                      improvement from
                                                   baseline ([Delta]dv)--
                                      Baseline      reflects improvement
                                     visibility       from SO2 and PM
           Class I area                impact            reductions
                                     ([Delta]dv)
                                                  ----------------------
                                                    No. 6 Fuel oil--0.5%
                                                       sulfur content
------------------------------------------------------------------------
Caney Creek......................           0.330               0.188
Upper Buffalo....................           0.348               0.221
Hercules-Glades..................           0.368               0.233
Mingo............................           0.379               0.209
Cumulative Visibility Improvement  ..............               0.851
 ([Delta]dv).....................
------------------------------------------------------------------------

    Our final BART determination for NOX is an emission 
limit of 887 lb/hr, which is the existing emission limit and does not 
necessitate the installation of additional controls. The source must 
comply with the NOX emission limit for BART purposes as of 
the effective date of this final rule.
b. AECC McClellan Unit 1
    AECC McClellan Unit 1 burns primarily natural gas, but is also 
permitted to burn fuel oil. Our proposal explains why the source needs 
to retain the flexibility to use fuel oil. Taking into consideration 
the BART factors, we are finalizing BART determinations and emission 
limits for SO2, NOX, and PM as proposed. Our 
final BART determination for SO2 and PM is the use of fuels 
with 0.5% or lower sulfur content by weight. After the effective date 
of this final rule, the facility shall not purchase fuel for use in 
Unit 1 that does not meet this sulfur content requirement. We are 
allowing the facility 5 years to burn its existing supply of No. 6 fuel 
oil, in accordance with any operating restrictions enforced by ADEQ. We 
are requiring the facility to comply with the requirement to use only 
fuels with 0.5% or lower sulfur content by weight no later than 5 years 
from the effective date of this final rule. Providing this time period 
will avoid creating an incentive for the source to burn large amounts 
of this fuel during a short period, which could affect visibility on 
individual days more adversely. We discussed in detail in our proposal 
the cost effectiveness and projected visibility improvement of 
switching from the baseline fuel to fuels with a sulfur content by 
weight of 0.5% or lower, and also present this information in Tables 5 
and 6.\31\ We are not making changes to the analysis we presented in 
our proposal of the cost and visibility improvement of this control 
measure. As discussed in our proposal, the cost of switching from the 
baseline fuel to fuels with a sulfur content by weight of 0.5% or lower 
is within the range of what we consider to be cost effective for BART 
and it is projected to result in considerable visibility improvement at 
the affected Class I areas.\32\ We are finalizing this BART 
determination for SO2 and PM as proposed.
---------------------------------------------------------------------------

    \31\ See also 80 FR 18944, 18958, 18959, and 18962.

 Table 5--AECC McClellan Unit 1--Cost Effectiveness of Switching to Fuel
                  With Sulfur Content of 0.5% or Lower
------------------------------------------------------------------------
                                                            No. 6 Fuel
                                                             oil--0.5%
                        Pollutant                         sulfur content
                                                              ($/ton)
------------------------------------------------------------------------
SO2.....................................................           3,823
PM......................................................           4,553
------------------------------------------------------------------------

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

    \32\ 80 FR 18944, 18959, 18962.

[[Page 66341]]

     Table 6--AECC McClellan Unit 1--Summary of the 98th Percentile
   Visibility Impacts And Improvement of Switching to Fuel With Sulfur
                        Content of 0.5% or Lower
------------------------------------------------------------------------
                                                         Visibility
                                                      improvement from
                                                   baseline ([Delta]dv)--
                                      Baseline      reflects improvement
                                     visibility       from SO2 and PM
           Class I area                impact            reductions
                                     ([Delta]dv)
                                                  ----------------------
                                                    No. 6 Fuel oil--0.5%
                                                       sulfur content
------------------------------------------------------------------------
Caney Creek......................           0.622                 0.3
Upper Buffalo....................           0.266                0.12
Hercules-Glades..................           0.231               0.116
Mingo............................           0.228               0.092
Cumulative Visibility Improvement  ..............               0.628
 ([Delta]dv).....................
------------------------------------------------------------------------

    Our final BART determination for NOX is an emission 
limit of 869.1 lb/hr for natural gas firing and 705.8 lb/hr for fuel 
oil firing, which are the existing emission limits and do not 
necessitate the installation of additional controls. The source must 
comply with the NOX emission limits for BART purposes as of 
the effective date of the final rule.
c. AEP Flint Creek Unit 1
    Taking into consideration the BART factors, we are finalizing our 
determination that BART for SO2 is an emission limit of 0.06 
lb/MMBtu on a 30 boiler-operating-day rolling average, which is 
consistent with the installation and operation of NID technology (a 
type of dry scrubbing system). As discussed in detail in our RTC 
document, we are not making changes to the analysis we presented in our 
proposal of the cost and visibility improvement of this control 
measure. We discussed in our proposal that the cost of NID on Flint 
Creek Unit 1 is estimated to be $3,845/SO2 ton removed, 
which is within the range of what we consider to be cost effective for 
BART, and it is projected to result in considerable visibility 
improvement at the affected Class I areas (see Table 7).\33\ Therefore, 
we are finalizing this SO2 BART emission limit as proposed.
---------------------------------------------------------------------------

    \33\ 80 FR 18944, 18966.

     Table 7--AEP Flint Creek Unit 1--Summary of the 98th Percentile
          Visibility Impacts And Improvement of NID Technology
------------------------------------------------------------------------
                                             Baseline       Visibility
                                            visibility      improvement
              Class I area                    impact       from baseline
                                            ([Delta]dv)     ([Delta]dv)
------------------------------------------------------------------------
Caney Creek.............................           0.963           0.615
Upper Buffalo...........................           0.965           0.464
Hercules-Glades.........................           0.657           0.345
Mingo...................................           0.631           0.414
Cumulative Visibility Improvement         ..............           1.838
 ([Delta]dv)............................
------------------------------------------------------------------------

    In our proposal, we stated that we believed that the maximum 
compliance time of 5 years allowed under the CAA and Regional Haze Rule 
was appropriate for a new scrubber retrofit and proposed to require the 
source to comply with this emission limit no later than 5 years from 
the effective date of the final rule.\34\ We received comments during 
the public comment period that brought to our attention that the 
Arkansas Public Service Commission (PSC) has determined that dry 
scrubber installation at Flint Creek is in the public interest and that 
the installation of NID controls is already underway and anticipated by 
the company to be completed by May 29, 2016. The Arkansas PSC requires 
Flint Creek to provide quarterly reports on the progress of the 
installation of these controls, which are publicly available online on 
the Arkansas PSC Web site.\35\ The first quarterly report submitted by 
the company to the Arkansas PSC is dated March 26, 2014, and stated 
that the FGD project includes the installation of an Alstom NID system 
to comply with the Mercury and Air Toxics Standards (MATS) Rule and in 
anticipation of the BART requirements. The report also stated that the 
company established design, procurement, and construction schedules to 
bring the upgraded plant fully on line by May 29, 2016. The most recent 
quarterly report available on the Arkansas PSC Web site is dated March 
10, 2016, and covers the fourth quarter in 2015. This report indicated 
that the company still expected that the upgraded plant would be fully 
on line by May 29, 2016. We verified the status of the installation of 
the controls with the company, who confirmed that installation of the 
NID controls was completed in June 2016, and that the plant is now 
operating with those controls.\36\ We proposed a 5-year compliance date 
without knowing that installation of these controls was well underway. 
After carefully considering

[[Page 66342]]

the comments we received, we have determined that a 5-year compliance 
date is not appropriate because the CAA requires that sources comply 
with BART as expeditiously as practicable.\37\ Therefore, we are 
finalizing a shorter compliance date.\38\ The information that has been 
made available to us during the comment period indicates that Flint 
Creek intends to operate the NID system to comply with the alternative 
SO2 emission limit under the Utility MATS rule. The 
applicable MATS SO2 emission limit is 0.2 lb/MMBtu. The 
SO2 emission limit we are requiring in our FIP to satisfy 
the SO2 BART requirement is 0.06 lb/MMBtu. The comments and 
documentation submitted to us indicate that the company intends to use 
the same NID system to comply with MATS and the SO2 BART 
requirement. We expect that in order to achieve an emission rate of 
0.06 lb/MMBtu, additional scrubbing reagent would be needed beyond that 
required to meet the 0.2 lb/MMBtu emission limit the company was 
required to meet by April 2016 under MATS. We also recognize that it is 
possible that the reagent handling system installed to meet the 0.2 lb/
MMBtu emission limit would need some upgrades in order to accommodate 
the additional scrubbing reagent that would be needed to achieve the 
more stringent 0.06 lb/MMBtu emission limit we are requiring in this 
FIP. Therefore, to allow the facility sufficient time to secure the 
additional scrubbing reagent that would be needed to comply with the 
SO2 BART emission limit and to make any necessary upgrades 
to the reagent handling system, we are finalizing an 18-month 
compliance date for Flint Creek Unit 1 to comply with the 
SO2 BART requirement. We believe that this will provide 
sufficient time for the facility to be able to achieve the 
SO2 BART requirement while still meeting the statutory 
mandate that BART controls be installed and operated as expeditiously 
as practicable.
---------------------------------------------------------------------------

    \34\ 80 FR 18944, 18967.
    \35\ See the Arkansas PSC Web site at http://www.apscservices.info/efilings/docket_search.asp. The quarterly 
reports the company is required to submit to the Arkansas PSC are 
available by searching for docket No. 12-008-U.
    \36\ See file titled ``Record of Call--Flint Creek_August 10 
2016,'' which is found in the docket for this rulemaking.
    \37\ CAA section 169A(b)(2)(A).
    \38\ The shorter compliance timeframe we are finalizing is a 
logical outgrowth of our proposal based on the comments received, 
which are discussed in more detail elsewhere in the final rule and 
our RTC document. See Int'l Union, UMW, 407 F.3d at 1259; Fertilizer 
Inst., 935 F.2d at 1311; Chocolate Mfrs. Ass'n, 755 F.2d 1098.
---------------------------------------------------------------------------

    Taking into consideration the BART factors, we are finalizing our 
determination that BART for NOX is an emission limit of 0.23 
lb/MMBtu on a 30 boiler-operating-day rolling average, which is 
consistent with the installation and operation of new LNB/OFA. In 
response to comments we received on our initial cost analysis presented 
in our proposal, we have revised our cost estimate for LNB/OFA for AEP 
Flint Creek Unit 1. Based on this revision to our cost analysis, we 
find that LNB/OFA is estimated to cost $1,258/NOX ton 
removed, which is even more cost effective (lower $/ton) than we 
estimated in our proposal. LNB/OFA is also projected to result in 
considerable visibility improvement at the affected Class I areas (see 
Table 8). As we discuss in our RTC document, after revising our cost 
analysis of NOX controls for AEP Flint Creek, we find that 
the additional cost of more stringent controls such as SNCR and SCR is 
not justified by the incremental visibility benefits of the more 
stringent controls. Therefore, we are finalizing the NOX 
BART emission limit as proposed, consistent with installation of LNB/
OFA controls.

     Table 8--AEP Flint Creek Unit 1--Summary of the 98th Percentile
              Visibility Impacts And Improvement of LNB/OFA
------------------------------------------------------------------------
                                             Baseline       Visibility
                                            visibility      improvement
              Class I area                    impact       from baseline
                                            ([Delta]dv)     ([Delta]dv)
------------------------------------------------------------------------
Caney Creek.............................           0.963           0.081
Upper Buffalo...........................           0.965           0.026
Hercules-Glades.........................           0.657           0.024
Mingo...................................           0.631           0.014
Cumulative Visibility Improvement         ..............           0.145
 ([Delta]dv)............................
------------------------------------------------------------------------

    We received comments from the company requesting that we extend our 
proposed 3-year compliance date for the NOX BART requirement 
to 5 years to allow sufficient time for planning, selection of 
engineering and design professionals, vendors, contractors, permitting, 
start up and commissioning, and coordinating and scheduling unit 
outages. We also received comments from an environmental group stating 
that we should shorten the compliance date because the typical 
installation timeframe for low NOX burners is 6-8 months 
from bid evaluation through startup of the technology. The 
environmental group also indicated that the company may have already 
started the process of installing LNB/OFA controls in anticipation of 
the BART requirement. We do not have information corroborating that the 
installation of these controls is already underway, but we agree with 
the environmental group that LNB/OFA can be installed within a 6-8 
month timeframe. The company did not provide specific information to 
support its contention that a longer compliance date that extends 
beyond the 6-8 month typical installation timeframe for LNB/OFA, 
measured from bid evaluation, is needed for AEP Flint Creek. Although 
we agree that 6-8 months is the typical installation timeframe for LNB/
OFA controls, in determining the appropriate compliance date we have 
also taken into consideration that we are finalizing NOX 
emission limits that are based on LNB/OFA or LNB/SOFA controls for a 
total of five EGUs in this FIP and that the installation of these 
controls will require outage time. These five EGUs combined accounted 
for approximately 45% of the state's 2015 heat input.\39\ Because of 
the heavy reliance on these EGUs for electricity generation in the 
state, we recognize that it may be difficult to schedule outage time to 
install LNB/OFA or LNB/SOFA on all five of these units within the 
typical installation timeframe of 6-8 months and at the same time 
supply adequate electricity to meet demand in the state. As we discuss 
in section V.F. of this final rule, in light of these unique 
circumstances, we believe that it is appropriate to finalize an 18-
month compliance date for these EGUs to comply with the NOX 
emission limits required by this FIP. This compliance date provides the 
affected utilities considerable time beyond typical LNB/

[[Page 66343]]

OFA installation timeframes to install these controls and comply with 
their NOX emission limits.
---------------------------------------------------------------------------

    \39\ These five EGUs are White Bluff Units 1 and 2, Independence 
Units 1 and 2, and Flint Creek Unit 1.
---------------------------------------------------------------------------

    Several commenters submitted comments stating that Arkansas is 
subject to the Cross State Air Pollution Rule (CSAPR) for ozone season 
NOX, so we should rely on CSAPR to satisfy the 
NOX BART requirement instead of promulgating source-specific 
NOX BART determinations. In the same way that a state 
subject to CSAPR for ozone season NOX has the discretion to 
decide whether to conduct source-specific BART determinations for 
NOX or to rely on EPA's 2012 finding that CSAPR is better 
than BART, EPA has the same discretion in promulgating a FIP. Our 
decision to propose source-specific NOX BART determinations 
for Arkansas was reasonable for multiple reasons: It is the approach 
Congress chose in the statute itself; it is consistent with Arkansas' 
earlier decision to conduct source-specific BART determinations in lieu 
of relying on the Clean Air Interstate Rule (CAIR) to meet the BART 
requirements; and at the time of our proposed action, it properly 
accounted for uncertainty in the CSAPR better-than-BART regulation 
created by ongoing litigation regarding the CSAPR program. Further, 
subsequent to our proposal, the D.C Circuit Court issued a July 2015 
decision upholding CSAPR but remanding without vacatur a number of the 
Rule's state NOX and SO2 emissions budgets. 
Arkansas' ozone season NOX budget is not itself affected by 
the remand. However, the Court's remand of the affected states' 
emissions budgets has implications for CSAPR better-than BART, since 
the demonstration underlying that rulemaking relied on the emission 
budgets of all states subject to CSAPR, including those that the D.C. 
Circuit remanded, to establish that CSAPR provides for greater 
reasonable progress than BART. As of the time EPA is taking this action 
to finalize Arkansas' Regional Haze FIP, we are in the process of 
acting on the Court's remand consistent with the planned response we 
outlined in a June 2016 memorandum.\40\ For these reasons, which we 
discuss in more detail in our RTC document, we are finalizing source-
specific NOX BART determinations for AEP Flint Creek Unit 1 
and other Arkansas EGUs subject to BART. As we have noted throughout 
this document, we are willing to work with ADEQ to develop a SIP 
revision that could replace our FIP. Such a SIP revision will need to 
meet the CAA and EPA's Regional Haze regulations. In its SIP revision, 
ADEQ may elect to rely on CSAPR to satisfy the NOX BART 
requirements for Arkansas' EGUs instead of doing source-specific 
NOX BART determinations. Such an approach could be 
appropriate if, as we expect, the uncertainty created by the D.C. 
Circuit's remand of the affected states' emission budgets will shortly 
be resolved.
---------------------------------------------------------------------------

    \40\ https://www3.epa.gov/airtransport/CSAPR/pdfs/CSAPR_SO2_Remand_Memo.pdf.
---------------------------------------------------------------------------

d. White Bluff Units 1 and 2
    Taking into consideration the BART factors, we are finalizing our 
determination that BART for SO2 for White Bluff Units 1 and 
2 is an emission limit of 0.06 lb/MMBtu on a 30 boiler-operating-day 
rolling average, consistent with the installation and operation of dry 
FGD or another control technology that achieves that level of control. 
We are requiring the source to comply with this emission limit no later 
than 5 years from the effective date of the final rule. In response to 
comments we received on our initial cost analysis presented in our 
proposal, we have revised our cost estimate for dry FGD for White Bluff 
Units 1 and 2. Based on this revision to our cost analysis, we find 
that dry FGD is estimated to cost $2,565/SO2 ton removed at 
Unit 1 and $2,421/SO2 ton removed at Unit 2. Although these 
cost estimates are slightly higher than we estimated in our proposal, 
we continue to find these controls to be cost effective and would 
result in considerable visibility improvement (see Table 9).\41\ 
Therefore, we are finalizing the SO2 BART emission limit as 
proposed.
---------------------------------------------------------------------------

    \41\ See also 80 FR 18944, 18972.

Table 9--Entergy White Bluff Units 1 and 2--Summary of the 98th Percentile Visibility Impacts And Improvement of
                                                     Dry FGD
----------------------------------------------------------------------------------------------------------------
                                                        White Bluff Unit 1              White Bluff Unit 2
                                                 ---------------------------------------------------------------
                                                     Baseline       Visibility       Baseline       Visibility
                  Class I area                      visibility      improvement     visibility      improvement
                                                      impact       from baseline      impact       from baseline
                                                    ([Delta]dv)     ([Delta]dv)     ([Delta]dv)     ([Delta]dv)
----------------------------------------------------------------------------------------------------------------
Caney Creek.....................................           1.628           0.813           1.695           0.754
Upper Buffalo...................................           1.140           0.762           1.185           0.767
Hercules-Glades.................................           1.041           0.683           1.061           0.645
Mingo...........................................           0.887           0.620           0.903           0.593
Cumulative Visibility Improvement ([Delta]dv)...  ..............           2.878  ..............           2.759
----------------------------------------------------------------------------------------------------------------

    Several commenters requested that we rely on CSAPR to satisfy the 
NOX BART requirement for Arkansas EGUs in our final FIP. We 
discuss in section V.H. of this final rule that we have concluded for a 
number of reasons that it would not be appropriate to rely on CSAPR as 
an alternative to NOX BART for EGUs in Arkansas at this 
time. Therefore, we are finalizing source-specific NOX BART 
determinations for all Arkansas EGUs, including White Bluff Units 1 and 
2. We proposed that BART for NOX for Units 1 and 2 is an 
emission limit of 0.15 lb/MMBtu on a 30 boiler-operating-day rolling 
average, consistent with the installation and operation of LNB/SOFA. We 
received comments from the company stating that White Bluff Units 1 and 
2 are no longer expected to be able to consistently meet our proposed 
NOX emission limit of 0.15 lb/MMBtu over a 30-boiler-
operating-day period based on LNB/SOFA controls. We have determined 
that the company has provided sufficient information to substantiate 
that the units are not expected to be able to meet our proposed 
NOX emission limit of 0.15 lb/MMBtu when the units are 
primarily operated at less than 50% of their operating capacity. In 
particular, LNB/SOFA is expected to achieve optimal NOX 
control when the boiler is operated from 50-100% steam flow because the 
heat input across this range is sufficient to safely redirect a 
substantial portion of combustion air through the overfire air 
registers. This allows the combustion

[[Page 66344]]

zone airflow to be sub-stoichiometric and oxygen to be reduced to the 
point where much of the elemental nitrogen in the fuel and combustion 
air can pass through the boiler without converting to NOX. 
When a boiler is operated below the 50-100% capacity range, 
NOX concentrations on a lb/MMBtu basis can be elevated due 
to the lower heat input rating, even though the pounds of 
NOX emitted per hour are less due to the reduced amount of 
fuel and air. In light of the information provided by the company, we 
are finalizing a bifurcated NOX emission limit for each 
unit, where our proposed 0.15 lb/MMBtu emission limit will address 
emissions when the unit is operated at high capacities and a mass-based 
emission limit will address emissions when the unit is operated at low 
capacities. The bifurcated emission limits we are finalizing are a 
logical outgrowth of our proposal based on the company's comments, 
which are discussed in more detail elsewhere in the final rule and our 
RTC document.\42\
---------------------------------------------------------------------------

    \42\ A final rule is a logical outgrowth of the proposed rule 
``if interested parties should have anticipated that the change was 
possible, and thus reasonably should have filed their comments on 
the subject during the notice-and-comment period.'' Int'l Union,UMW 
v. MSHA, 407 F.3d 1250, 1259 (D.C. Cir. 2005) (internal quotations 
omitted); see also, Fertilizer Inst. v. EPA, 935 F.2d 1303, 1311 
(D.C. Cir. 1991). No additional notice or opportunity to comment is 
necessary where, as here, the final rule is ``in character with the 
original scheme,'' and does not ``substantially depart [] from the 
terms or substance'' of the proposal. Chocolate Mfrs. Ass'n v. 
Block, 755 F.2d 1098 (4th Cir. 1985).
---------------------------------------------------------------------------

    We are requiring White Bluff Units 1 and 2 to each meet a 
NOX emission limit of 0.15 lb/MMBtu on a 30 boiler-
operating-day rolling average, where the average is to be calculated by 
including only the hours during which the unit was dispatched at 50% or 
greater of maximum capacity. In this particular case, the 30 boiler-
operating-day rolling average is to be calculated for each unit by the 
following procedure: (1) Summing the total pounds of NOX 
emitted during the current boiler-operating day and the preceding 29 
boiler-operating days, including only emissions during hours when the 
unit was dispatched at 50% or greater of maximum capacity; (2) summing 
the total heat input in MMBtu to the unit during the current boiler-
operating day and the preceding 29 boiler-operating days, including 
only the heat input during hours when the unit was dispatched at 50% or 
greater of maximum capacity; and (3) dividing the total pounds of 
NOX emitted as calculated in step 1 by the total heat input 
to the unit as calculated in step 2.
    In addition to the 0.15 lb/MMBtu emission limit that is intended to 
control NOX emissions when the units are operated at 50% or 
greater of maximum capacity, we are establishing a limit in lb/hr that 
applies when the units are operated at lower capacity. The company 
suggested an emission limit of 1,342.5 lb/hr on a 30 boiler-operating-
day rolling average applicable at all times regardless of the capacity 
at which the unit is operated. Based on the information available to 
us, we find that an emission limit of 1,342.5 lb/hr is too high to 
appropriately control NOX emissions when the units are 
operated at low capacities. It appears that the company calculated the 
emission limit by multiplying the 0.15 lb/MMBtu limit by the maximum 
heat input rating for each unit (8,950 MMBtu/hr), which yielded 1,342.5 
lb/hr. We find that an emission limit of 1,342.5 lb/hr would be 
appropriate when the unit is operated at high capacities considering 
that the limit was calculated based on the unit's maximum heat input 
rating. However, such an emission limit would not be sufficiently 
protective or appropriate when the unit is operated at lower capacities 
since the mass of NOX emitted is expected to be lower 
compared to operation at high capacity. To address this concern, we 
calculated a new emission limit of 671 lb/hr that is based on 50% of 
the unit's maximum heat input rating, and is applicable only when the 
unit is being operated at less than 50% of maximum heat input rating. 
We calculated this limit by multiplying 0.15 lb/MMBtu by 50% of the 
maximum heat input rating for each unit (i.e., 50% of 8,950 MMBtu/hr, 
or 4,475 MMBtu/hr). This emission limit is on a rolling 3-hour average, 
where the average is to be calculated by including emissions only for 
the hours during which the unit was dispatched at less than 50% of 
maximum capacity (i.e., hours when the heat input to the unit is less 
than 4,475 MMBtu). We are not establishing a lb/hr emission limit that 
applies when the units are operated at 50% or greater of maximum heat 
input rating because the 0.15 lb/MMBtu emission limit will address 
NOX emission during those operating conditions. We discussed 
in our proposal that the cost of LNB/SOFA on White Bluff Units 1 and 2 
is estimated to be $350/NOX ton removed for Unit 1 and $340/
NOX ton removed for Unit 2,\43\ which we consider to be very 
cost effective, and it would also result in considerable visibility 
improvement at the affected Class I areas (see Table 10).\44\ 
Therefore, we are finalizing the NOX BART emission limits as 
described above.
---------------------------------------------------------------------------

    \43\ Our cost analysis and visibility modeling analysis for LNB/
SOFA for White Bluff Units 1 and 2, as presented in our proposal, is 
based on an emission limit of 0.15 lb/MMBtu on a 30 boiler-
operating-day rolling average. As discussed in this final action, we 
received new information from Entergy that indicates that the source 
expects to be operating at less than 50% load more frequently and 
therefore no longer expects to be able to meet our proposed 
NOX emission limit. We are therefore finalizing the 
bifurcated NOX emission limit described in this final 
action. We recognize that the comments submitted by Entergy indicate 
that some of the assumptions used to calculate the cost 
effectiveness of NOX controls for White Bluff may not 
exactly apply to future operations. However, because we found LNB/
SOFA controls to be very cost effective, we expect that even if the 
change in operation of the source were known more precisely and were 
taken into account in our calculation of the cost ($/ton), these 
controls would continue to be cost effective. Therefore, we are not 
revising our cost effectiveness calculations or visibility 
improvement modeling of LNB/SOFA for White Bluff Units 1 and 2.
    \44\ 80 FR at 18972.
---------------------------------------------------------------------------

    As discussed in section V.F. of this final rule, in response to 
comments we received, we are shortening the compliance date for the 
NOX BART requirement for White Bluff Units 1 and 2 from our 
proposed 3 years to 18 months.

 Table 10--Entergy White Bluff Units 1 And 2--Summary of the 98th Percentile Visibility Impacts and Improvement
                                                   of LNB/SOFA
----------------------------------------------------------------------------------------------------------------
                                                        White Bluff Unit 1              White Bluff Unit 2
                                                 ---------------------------------------------------------------
                                                     Baseline       Visibility       Baseline       Visibility
                  Class I area                      visibility      improvement     visibility      improvement
                                                      impact       from baseline      impact       from baseline
                                                    ([Delta]dv)     ([Delta]dv)     ([Delta]dv)     ([Delta]dv)
----------------------------------------------------------------------------------------------------------------
Caney Creek.....................................           1.628           0.166           1.695           0.225
Upper Buffalo...................................           1.140           0.101           1.185           0.139

[[Page 66345]]

 
Hercules-Glades.................................           1.041           0.176           1.060           0.190
Mingo...........................................           0.887           0.038           0.903           0.047
Cumulative Visibility Improvement ([Delta]dv)...  ..............           0.481  ..............           0.601
----------------------------------------------------------------------------------------------------------------

    In our proposal, we also solicited public comment on any 
alternative SO2 and NOX control measures that 
could address the regional haze requirements for Entergy White Bluff 
Units 1 and 2 and Entergy Independence Units 1 and 2 for this planning 
period. We received comments from the company during the public comment 
period that proposed one alternative strategy,\45\ but we determined 
that this alternative strategy would not adequately address the BART 
and reasonable progress requirements for the affected units. We discuss 
this issue in more detail elsewhere in this final rule and in our RTC 
document.
---------------------------------------------------------------------------

    \45\ As described in section I. of this notice, Entergy also 
submitted a comment after the close of the comment period, 
indicating that Entergy intends that a second alternative described 
in the late comment, involving only White Bluff, is a replacement 
for the multi-unit alternative previously described in its timely 
comments. Because the late comment is not a basis for our decision 
making in this final rule, we are responding in this final rule and 
in our RTC document to the alternative proposal described in the 
comments that Entergy filed during the comment period.
---------------------------------------------------------------------------

e. White Bluff Auxiliary Boiler
    We are finalizing our determination that the existing emission 
limit of 105.2 lb/hr is BART for SO2, the existing emission 
limit of 32.2 lb/hr is BART for NOX, and the existing 
emission limit of 4.5 lb/hr is BART for PM for the Auxiliary Boiler. We 
do not expect these emission limits to require the installation of 
additional controls. We are requiring the White Bluff Auxiliary Boiler 
to comply with these emission limits as of the effective date of this 
final rule.
f. Entergy Lake Catherine Unit 4
    Taking into consideration the BART factors, we are finalizing our 
determination that BART for NOX for the natural gas-firing 
scenario is an emission limit of 0.22 lb/MMBtu on a 30 boiler-
operating-day rolling average, consistent with the installation and 
operation of BOOS. As discussed in more detail in our RTC document, we 
are not making changes to the analysis presented in our proposal of the 
cost and visibility improvement of this control measure. We discussed 
in our proposal that the cost of BOOS on Lake Catherine Unit 4 is 
estimated to be $138/NOX ton removed, which we consider to 
be very cost effective, and it is also projected to result in 
considerable visibility improvement at the affected Class I areas (see 
Table 11).\46\ Therefore, we are finalizing the NOX BART 
emission limit as proposed. We are requiring the source to comply with 
this emission limit no later than 3 years from the effective date of 
this final rule.
---------------------------------------------------------------------------

    \46\ 80 FR 18944, 18978.

 Table 11--Entergy Lake Catherine Unit 4--Summary of the 98th Percentile
               Visibility Impacts and Improvement of BOOS
------------------------------------------------------------------------
                                             Baseline       Visibility
                                            visibility      improvement
              Class I area                    impact       from baseline
                                            ([Delta]dv)     ([Delta]dv)
------------------------------------------------------------------------
Caney Creek.............................           1.371           0.596
Upper Buffalo...........................           0.532           0.248
Hercules-Glades.........................           0.387           0.175
Mingo...................................           0.429           0.196
Cumulative Visibility Improvement         ..............           1.215
 ([Delta]dv)............................
------------------------------------------------------------------------

    We are also finalizing our determination that Lake Catherine Unit 4 
shall not burn any fuel oil unless or until Arkansas submits a SIP 
revision that contains BART determinations for SO2, 
NOX, and PM for the fuel oil-firing scenario for Unit 4 and 
we approve these BART determinations into the SIP or we promulgate such 
BART determinations in a FIP. We are finalizing this determination in 
light of the fact that Unit 4 has not combusted any fuel oil in over 10 
years and the company's commitment to not burn any fuel oil at Unit 4 
until Arkansas submits the SIP revision described above.
g. Domtar Ashdown Mill Power Boiler No. 1
    In response to comments received from the company, we are 
finalizing an SO2 BART emission limit in the form of lb/day 
instead of lb/hr for Power Boiler No. 1. Specifically, we are 
finalizing an SO2 BART emission limit of 504 lb/day averaged 
over a rolling 30 boiler-operating-day period instead of the proposed 
emission limit of 21.0 lb/hr averaged over a rolling 30 boiler-
operating-day period. According to the company, the calculation of 
hourly SO2 emissions using hourly fuel throughput 
information is not a workable approach for Power Boiler No. 1, where 
the practice is to use monthly fuel throughput information that is 
reconciled at the end of each month to determine monthly fuel usage. 
The company believes an emission limit in terms of lb/day is better 
suited to the mill's methodology for determining fuel usage at Power 
Boiler No. 1. We agree

[[Page 66346]]

with the company and are finalizing an SO2 BART emission 
limit of 504 lb/day averaged over a rolling 30 boiler-operating-day 
period. This emission limit is consistent with the Power Boiler's 
baseline emissions and would not necessitate additional controls.\47\ 
We are also finalizing our determination that the mill must demonstrate 
compliance with the SO2 BART emission limit by using a site-
specific curve equation (provided to us by the facility) to calculate 
SO2 emissions from Power Boiler No. 1 when combusting bark, 
and that the mill must confirm the accuracy of the site-specific curve 
equation using stack testing.\48\ Further, we are finalizing our 
determination that for purposes of demonstrating compliance with the 
emission limit for BART for SO2 when combusting fuel oil, 
the mill shall assume that the SO2 inlet is equal to the 
SO2 being emitted at the stack, where SO2 inlet 
is defined to be the SO2 content of the fuel delivered to 
the fuel inlet of the combustion chamber.
---------------------------------------------------------------------------

    \47\ The lb/day emission limit we are finalizing is a logical 
outgrowth of our proposal based on the company's comments, which are 
discussed in more detail elsewhere in the final rule and our RTC 
document. See Int'l Union, UMW, 407 F.3d at 1259; Fertilizer Inst., 
935 F.2d at 1311; Chocolate Mfrs. Ass'n, 755 F.2d 1098.
    \48\ The curve equation is Y = 0.4005 * X-0.2645, where Y = 
pounds of sulfur emitted per ton dry fuel feed to the boiler and X = 
pounds of sulfur input per ton of dry bark. The purpose of this 
equation is to factor in the degree of SO2 scrubbing 
provided by the combustion of bark.
---------------------------------------------------------------------------

    We are finalizing a NOX BART emission limit of 207.4 lb/
hr for Power Boiler No. 1 as proposed. This emission limit is 
consistent with the Power Boiler's baseline emissions, and we expect 
that compliance with this emission limit will not necessitate the 
installation of additional controls. In response to comments we 
received from the company, we are revising our proposed method for 
demonstrating compliance with the NOX BART emission limit. 
We proposed that, to demonstrate compliance with the NOX 
BART emission limit, the facility must conduct annual stack testing. 
The company submitted comments stating that it generally agreed that 
stack testing was an appropriate method for demonstrating compliance, 
but it disagreed that our proposed frequency of an annual stack testing 
was appropriate. The company noted that historical NOX stack 
test data from 2001-2005 and 2010 for Power Boiler 1 showed the 
NOX emissions were fairly consistent. After carefully 
considering the company's comments, we agree that the results of these 
previous stack tests demonstrate that an annual stack test is not 
warranted. Therefore, we are finalizing a requirement that the facility 
demonstrate compliance with the NOX BART emission limit for 
Power Boiler No. 1 by conducting stack testing once every 5 years, 
beginning no later than 1 year from the effective date of our final 
action.
    In response to comments we received from the company, we are 
finalizing one alternative method for demonstrating compliance with the 
SO2 and NOX BART emission limits for Power Boiler 
No. 1. The company submitted comments stating that it may decide in the 
near future to convert Power Boiler No. 1 to burn only natural gas. 
After carefully considering the company's comments, we are making the 
determination that if the company makes the decision to convert Power 
Boiler No. 1 to burn only pipeline quality natural gas and its 
preconstruction air permit is revised to reflect that Power Boiler No. 
1 is permitted to burn only pipeline quality natural gas, the company 
will have demonstrated that the boiler is complying with the 
SO2 BART emission limit. Once the air permit is revised to 
reflect that Power Boiler No. 1 is allowed to burn only pipeline 
quality natural gas, the reporting and recordkeeping requirements 
associated with our SO2 BART emission limit would no longer 
be applicable. We find this alternative method for demonstrating 
compliance with the SO2 BART emission limit to be 
appropriate given that SO2 emissions due to natural gas 
combustion are negligible. This alternative method for compliance 
demonstration will ensure that the facility is not unnecessarily 
burdened with calculating SO2 emissions and with 
recordkeeping and reporting requirements when SO2 emissions 
from Power Boiler No. 1 are anticipated to be negligible. We are also 
making the determination that if the preconstruction air permit is 
revised to reflect that Power Boiler No. 1 is permitted to burn only 
pipeline quality natural gas, the facility may demonstrate compliance 
with the NOX emission limit by calculating NOX 
emissions using AP-42 emission factors and fuel usage records. Under 
this scenario, the facility would not be required to demonstrate 
compliance with the NOX BART emission limit for Power Boiler 
No. 1 through stack testing. We also note that after the close of the 
comment period for our proposal, we became aware that Power Boiler No. 
1 has already switched to burn only natural gas and that the facility 
submitted a permit renewal application to ADEQ that will reflect that 
the power boiler is permitted to burn only natural gas. We believe that 
the alternative methods for compliance demonstration we are finalizing 
are appropriate and addresses the mill's concerns.\49\
---------------------------------------------------------------------------

    \49\ The alternative methods for demonstrating compliance we are 
finalizing for Power Boiler No. 1 are a logical outgrowth of our 
proposal based on the company's comments, which are discussed in 
more detail elsewhere in the final rule and our RTC document. See 
Int'l Union,UMW, 407 F.3d at 1259; Fertilizer Inst., 935 F.2d at 
1311; Chocolate Mfrs. Ass'n, 755 F.2d 1098.
---------------------------------------------------------------------------

    In response to comments we received from the company, we are 
revising our definition of ``boiler-operating-day'' as it applies to 
Power Boilers Nos. 1 and 2 under this FIP. The company commented that 
for mill operation purposes, it defines boiler-operating-day as ``a 24-
hr period between 6 a.m. and 6 a.m. the following day during which any 
fuel is fed into and/or combusted at any time in the power boiler.'' 
After carefully considering the comment, we agree with the company that 
it is reasonable and appropriate to harmonize our definition of a 
boiler-operating day with that of the mill to avoid any unnecessary 
modification or reprogramming of Power Boilers 1 and 2. Therefore, for 
purposes of BART for Power Boilers No. 1 and 2, we are defining a 
boiler-operating-day as a 24-hour period between 6 a.m. and 6 a.m. the 
following day during which any fuel is fed into and/or combusted at any 
time in the power boiler. The 30-day rolling average for Power Boiler 
No. 1 shall 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 will be the 30 boiler-operating-day rolling average in terms of 
lb/day emissions of SO2.\50\
---------------------------------------------------------------------------

    \50\ The revised definition of ``boiler operating day'' as it 
applies to these two units is a logical outgrowth of our proposal 
based on the company's comments, which are discussed in more detail 
elsewhere in the final rule and our RTC document. See Int'l 
Union,UMW, 407 F.3d at 1259; Fertilizer Inst. v. EPA, 935 F.2d at 
1311; and Chocolate Mfrs. Ass'n, 755 F.2d 1098.
---------------------------------------------------------------------------

    In response to comments we received from the company, we are also 
revising our proposed compliance dates for SO2 and 
NOX BART for Power Boiler No. 1. The company submitted 
comments requesting that we finalize a compliance date of 30 days after 
the effective date of the final rule instead of requiring the source to 
comply with BART as of the effective date of the final rule. The 
company noted this would provide additional time for it to prepare 
compliance records. We determined that the company's request is 
reasonable and

[[Page 66347]]

would allow the mill to prepare applicable compliance records and 
adjust recordkeeping systems without unduly delaying compliance with 
the BART emission limits. Therefore, we are requiring Power Boiler No. 
1 to comply with the SO2 and NOX BART emission 
limits no later than 30 days from the effective date of this final 
rule.\51\
---------------------------------------------------------------------------

    \51\ The revised compliance date is a logical outgrowth of our 
proposal based on the company's comments. See Int'l Union,UMW, 407 
F.3d at 1259; Fertilizer Inst, 935 F.2d at 1311; and Chocolate Mfrs. 
Ass'n, 755 F.2d 1098.
---------------------------------------------------------------------------

h. Domtar Ashdown Mill Power Boiler No. 2
    In response to comments we received from the company, we are 
finalizing an emission limit of 91.5 lb/hr based on a 30 boiler-
operating-day rolling average instead of 0.11 lb/MMBtu. As discussed in 
our proposal, Domtar provided monthly average data for 2011, 2012, and 
2013 on monitored SO2 emissions from Power Boiler No. 2, 
mass of the fuel burned for each fuel type, and the percent sulfur 
content of each fuel type burned.\52\ Based on the information provided 
by Domtar, we found that the monthly average SO2 control 
efficiency of the existing venturi scrubbers for the 2011-2013 period 
ranged from 57% to 90%. The information provided also indicated that 
the facility could add more scrubbing solution to achieve greater 
SO2 removal than what is currently being achieved. We 
proposed that it is feasible for the facility to use additional 
scrubbing solution to consistently achieve at least a 90% 
SO2 removal on a monthly average basis. To determine the 
controlled emission rate that corresponds to the operation of the 
existing venturi scrubbers at a 90% removal efficiency, we first 
determined the SO2 emission rate that corresponds to the 
operation of the scrubbers at the current average control efficiency 
(i.e., baseline control efficiency) of approximately 69%. Based on the 
emissions data provided by Domtar, we determined that Power Boiler No. 
2's annual average SO2 emission rate for the years 2011-2013 
was 280.9 lb/hr. This annual average SO2 emission rate 
corresponds to the operation of the scrubbers at a 69% removal 
efficiency. We also estimated that 100% uncontrolled emissions would 
correspond to an emission rate of approximately 915 lb/hr. Application 
of a 90% control efficiency to the uncontrolled rate results in a 
controlled emission rate of 91.5 lb/hr, or 0.11 lb/MMBtu based on the 
boiler's maximum heat input of 820 MMBtu.\53\ We thus proposed that 
BART for SO2 for Power Boiler No. 2 is an emission limit of 
0.11 lb/MMBtu on a 30 boiler-operating-day rolling average.
---------------------------------------------------------------------------

    \52\ 80 FR 18944, 18984.
    \53\ 80 FR at 18984.
---------------------------------------------------------------------------

    During the public comment period, the company submitted comments 
requesting that we finalize an SO2 BART emission limit that 
is on a lb/hr basis instead of lb/MMBtu. The company correctly noted 
that we used the boiler's maximum heat input rating of 820 MMBtu/hr to 
determine the proposed emission limit in terms of lb/MMBtu. The company 
brought to our attention that the use of the maximum heat input rating 
is not representative of typical boiler operating conditions, which are 
lower than the maximum heat input capability. We have determined that 
finalizing an emission limit in terms of lb/hr is appropriate and will 
address the company's concern.\54\ Therefore, we are finalizing an 
SO2 emission limit of 91.5 lb/hr on a 30 boiler-operating-
day rolling average for Power Boiler No. 2. Because the SO2 
emission limit we are finalizing is based on converting our proposed 
emission limit of 0.11 lb/MMBtu to an emission limit in the form of lb/
hr, we find that our final emission limit is expected to achieve the 
same level of SO2 reduction as 0.11 lb/MMBtu, which is what 
we assumed in our analysis of cost and visibility improvement. 
Therefore, we are not making changes to the analysis we presented in 
our proposal of the cost and visibility improvement of this control 
measure.\55\ The use of additional scrubbing reagent with scrubber pump 
upgrades on the existing venturi scrubbers to meet an emission limit of 
91.5 lb/hr is estimated to cost $1,411/SO2 ton removed, and 
it is projected to result in considerable visibility improvement at the 
affected Class I areas (see Table 12). Taking into consideration the 
BART factors, we are finalizing this SO2 emission limit. In 
response to comments we received from the company, we are also revising 
our definition of ``boiler-operating-day'' as it applies to Power 
Boilers No. 1 and 2 for BART purposes.
---------------------------------------------------------------------------

    \54\ The lb/hr emission limits we are finalizing is a logical 
outgrowth of our proposal based on the company's comments, which are 
discussed in more detail elsewhere in the final rule and our RTC 
document. See Int'l Union,UMW, 407 F.3d at 1259; Fertilizer Inst, 
935 F.2d at 1311; and Chocolate Mfrs. Ass'n, 755 F.2d 1098.
    \55\ 80 FR at 18984, 18985.

   Table 12--Domtar Power Boiler No. 2--Summary of the 98th Percentile
Visibility Impacts and Improvement of Using Additional Scrubbing Reagent/
                         Scrubber Pump Upgrades
------------------------------------------------------------------------
                                                             Estimated
                                             Baseline       visibility
              Class I area                  visibility      improvement
                                              impact       from baseline
                                            ([Delta]dv)     ([Delta]dv)
------------------------------------------------------------------------
Caney Creek.............................           0.844           0.139
Upper Buffalo...........................           0.146            0.05
Hercules-Glades.........................           0.105           0.048
Mingo...................................           0.065           0.025
Cumulative Visibility Improvement         ..............           0.262
 ([Delta]dv)............................
------------------------------------------------------------------------

    We also received comments from Domtar expressing uncertainty as to 
whether our proposed SO2 emission limit for Power Boiler No. 
2 can be met by upgrading the scrubber pumps and using additional 
scrubbing solution to consistently achieve our proposed SO2 
emission limit. However, we have determined that aside from expressing 
general uncertainty, Domtar did not provide any information that 
demonstrates that it is not technically feasible to meet our proposed 
SO2 emission limit, which is based on a 30 boiler-operating-
day rolling average. We also received comments from Domtar disagreeing 
with our use of 2011-2013 as the baseline years for calculating our 
proposed SO2 emission limit for Power Boiler No. 2. Domtar 
asked that we instead use 2001-2003 as the baseline period for 
calculating the SO2 emission limit, which would result in an 
emission limit of 155 lb/hr instead of

[[Page 66348]]

91.5 lb/hr. Domtar pointed out that in more recent years (after the 
2001-2003 period), the mill voluntarily reduced its SO2 
emissions and that using a more recent period to calculate the BART 
emission limit results in a more stringent emission limit.
    As discussed in more detail elsewhere in this final rule and in our 
RTC document, we disagree that it is appropriate to use 2001-2003 as 
the baseline period for purposes of calculating the SO2 BART 
emission limit for Power Boiler No. 2. One of the factors we are 
required to take into consideration in making a BART determination is 
whether there is any existing pollution control equipment in use at the 
source. Power Boiler No. 2 is currently equipped with venturi scrubbers 
for control of SO2 emissions, and in our BART analysis, we 
evaluated upgrades to the existing scrubbers. As we discussed in our 
proposal, in determining whether upgrades to the existing scrubbers are 
technically feasible and whether additional SO2 control 
could be achieved, it was necessary for us to first determine the 
current control efficiency of the scrubbers. For purposes of 
determining the current control efficiency of the scrubbers, we believe 
the most reasonable and appropriate approach is to rely on recent data 
instead of older data from the 2001-2003 period. Therefore, we relied 
on 2011-2013 monthly average data on monitored SO2 
emissions, records of mass of fuel burned for each fuel type, and the 
percent sulfur content of each fuel type burned to estimate the current 
average control efficiency (i.e., baseline control efficiency) of the 
scrubbers, which we found to be approximately 69%. We find that because 
the baseline control efficiency of the existing scrubbers (i.e., 69%) 
corresponds to emissions data from 2011-2013, it is reasonable and 
appropriate to rely on emissions data from the same period to calculate 
the emission limit that corresponds to increasing the control 
efficiency from the baseline level of approximately 69% up to 90%. 
Therefore, we are not using 2001-2003 as the baseline period for 
purposes of calculating the SO2 emission limit for Power 
Boiler No. 2.
    We proposed to require the facility to demonstrate compliance with 
the SO2 emission limit for Power Boiler No. 2 using the 
existing CEMS. We are finalizing this method for demonstrating 
compliance with the SO2 BART emission limit for Power Boiler 
No. 2. During the public comment period for our proposal, Domtar 
submitted comments stating that due to a repurposing project the mill 
is currently undergoing, the mill's steam demands may change and Power 
Boiler No. 2 may be converted to burn only natural gas, mothballed, or 
shut down in the near future. After carefully considering the comments 
submitted to us, we have determined that in light of the repurposing 
project the mill is currently undergoing and the possibility of Power 
Boiler No. 2 being converted to burn only natural gas, it is 
appropriate to provide the facility with flexibility in how it must 
demonstrate compliance with the SO2 emission limit for Power 
Boiler No. 2. Therefore, we are providing one alternative method for 
demonstrating compliance with the SO2 BART emission limit: 
The owner or operator may demonstrate compliance with this emission 
limit by switching Power Boiler No. 2 to burn only pipeline quality 
natural gas provided that the preconstruction air permit is revised so 
as to permit combustion of only pipeline quality natural gas at Power 
Boiler No. 2. Therefore, if Power Boiler No. 2 is switched to burn only 
pipeline quality natural gas and the company's air permit is revised to 
reflect this, it would satisfy the requirement for demonstrating 
compliance with the boiler's SO2 BART emission limit, and 
the related reporting and recordkeeping requirements would not be 
applicable.\56\
---------------------------------------------------------------------------

    \56\ The alternative method to demonstrate compliance with the 
SO2 emission limit is a logical outgrowth of our proposal 
based on the company's comments, which are discussed in more detail 
elsewhere in the final rule and our RTC document. See Int'l Union, 
UMW, 407 F.3d at 1259; Fertilizer Inst, 935 F.2d at 1311; and 
Chocolate Mfrs. Ass'n, 755 F.2d 1098.
---------------------------------------------------------------------------

    Taking into consideration the BART factors, we are finalizing our 
determination that BART for NOX for Power Boiler No. 2 is an 
emission limit of 345 lb/hr on a 30 boiler-operating-day rolling 
average basis, which is consistent with the installation and operation 
of LNB. We are not making changes to the analysis we presented in our 
proposal of the cost and visibility improvement of this control 
measure.\57\ As discussed in our proposal, the cost of LNB on Power 
Boiler No. 2 is estimated to cost $1,951/NOX ton removed, 
and it is projected to result in considerable visibility improvement at 
the most impacted Class I area (see Table 13). We are finalizing this 
NOX emission limit as proposed.
---------------------------------------------------------------------------

    \57\ 80 FR 18944, 18987.

   Table 13--Domtar Power Boiler No. 2--Summary of the 98th Percentile
                Visibility Impacts and Improvement of LNB
------------------------------------------------------------------------
                                                             Estimated
                                             Baseline       visibility
              Class I area                  visibility      improvement
                                              impact       from baseline
                                            ([Delta]dv)     ([Delta]dv)
------------------------------------------------------------------------
Caney Creek.............................           0.844           0.181
Upper Buffalo...........................           0.146           0.014
Hercules-Glades.........................           0.105           0.011
Mingo...................................           0.065           0.005
Cumulative Visibility Improvement         ..............           0.211
 ([Delta]dv)............................
------------------------------------------------------------------------

    We proposed to require the facility to demonstrate compliance with 
this NOX emission limit using the existing CEMS. We are 
finalizing this method for demonstrating compliance. As discussed 
above, during the public comment period for our proposal, Domtar 
submitted comments stating that due to a repurposing project the mill 
is currently undergoing, the mill's steam demands may change and Power 
Boiler No. 2 may be converted to burn only natural gas, mothballed, or 
shut down in the near future. After carefully considering the comments 
submitted to us, we have determined that it is appropriate to provide 
the facility with flexibility in how it must demonstrate compliance 
with the NOX emission limit for Power Boiler No. 2. 
Therefore, we are providing one alternative method

[[Page 66349]]

for demonstrating compliance with the NOX BART emission 
limit: If Power Boiler No. 2 is switched to burn only natural gas and 
the facility's preconstruction air permit is revised such that Power 
Boiler No. 2 is permitted to burn only natural gas, the facility may 
demonstrate compliance with the NOX emission limit by 
calculating emissions using AP-42 emission factors and fuel usage 
records provided that the operation of the CEMS is no longer required 
by any other applicable requirements. Under these circumstances, the 
facility would not be required to use the existing CEMS to demonstrate 
compliance with the NOX BART emission limit.\58\
---------------------------------------------------------------------------

    \58\ The alternative method to demonstrate compliance with the 
NOX emission limit is a logical outgrowth of our proposal 
based on the company's comments, which are discussed in more detail 
elsewhere in the final rule and our RTC document. See Int'l Union, 
UMW, 407 F.3d at 1259; Fertilizer Inst, 935 F.2d at 1311; and 
Chocolate Mfrs. Ass'n, 755 F.2d 1098.
---------------------------------------------------------------------------

    As discussed above, in response to comments we received from 
Domtar, we are also revising our definition of ``boiler-operating-day'' 
as it applies to Power Boilers No. 1 and 2 for BART purposes. For 
purposes of SO2 and NOX BART for Power Boilers 
No. 1 and 2, we are defining a boiler-operating-day as a 24-hour period 
between 6 a.m. and 6 a.m. the following day during which any fuel is 
fed into and/or combusted at any time in the power boiler.
    We proposed to require the Domtar Ashdown Mill to comply with the 
SO2 and NOX BART emission limits no later than 3 
years from the effective date of our final action, but invited public 
comment on this issue in our proposal. We received comments from Domtar 
requesting that we finalize a 5-year compliance date in light of the 
repurposing project the mill is currently undergoing. The repurposing 
project involves converting a non-BART paper machine at the mill into a 
fluff pulp line and may significantly affect the mill's steam demands 
and ultimately determine the future operating scenario for Power Boiler 
No. 2. The comments submitted by Domtar indicate that after the 
repurposing and reconfiguration of the mill systems is complete and 
fully operational and the mill has learned how to operate and optimize 
in its newly configured state, it will be able to determine steam 
demands and will then decide the future operating scenario for Power 
Boiler No. 2. Our understanding from the comments submitted is that 
this decision is expected to be made in late 2018, but that additional 
time will be needed after this to implement the future operating 
scenario selected by the mill for Power Boiler No. 2, which could 
include switching fuels, mothballing or retiring the boilers, or 
continued operation under current operating conditions. It is not EPA's 
intention to place an undue burden on the Domtar Ashdown Mill by 
requiring a compliance date that may not provide sufficient time for 
the mill to install controls or otherwise make the necessary operating 
changes to meet the boiler's BART emission limits after it has made a 
final decision on the future operating scenario for Power Boiler No. 2. 
We believe that a 3-year compliance date is generally sufficient for 
installation of the controls that the SO2 and NOX 
BART emission limits we are requiring can be achieved with. However, 
due to the special circumstances in this case, which we discuss in 
section V.E of this final rule, we believe it is reasonable and 
appropriate to establish a longer compliance date. Therefore, we are 
requiring the mill to comply with the SO2 and NOX 
BART emission limits no later than 5 years from the effective date of 
this final rule. We believe that this adequately addresses the 
commenter's concerns while complying with the CAA mandate that 
compliance with BART requirements must be as expeditiously as 
practicable, but in no event later than 5 years after promulgation of 
this FIP.
    We are finalizing our determination that Domtar must satisfy the PM 
BART requirement by relying on the applicable Boiler MACT PM standard 
as revised.\59\ We proposed that the same method for demonstrating 
compliance with the Boiler MACT PM standard must be used for 
demonstrating compliance with the PM BART emission limit. We proposed 
to require the source to comply with this emission limit for BART 
purposes as of the effective date of the final rule. During the public 
comment period, we received comments from Domtar seeking clarification 
regarding the requirements for compliance demonstration, reporting, and 
recordkeeping for our proposed PM BART determination for Power Boiler 
No. 2. Domtar requested that we ensure that the requirements for 
compliance demonstration, testing, reporting, and recordkeeping under 
the Boiler MACT standard for PM are consistent with those associated 
with the PM BART emission limit for Power Boiler No. 2. As the Domtar 
Ashdown Mill will be relying on compliance with the Boiler MACT PM 
standard to satisfy the PM BART requirement for Power Boiler No. 2, we 
believe that there is no need for a separate set of requirements for 
compliance demonstration, testing, monitoring, recordkeeping, and 
reporting to satisfy the PM BART requirement. This was our position at 
proposal, but we recognize that the regulatory text in our proposal may 
not have conveyed this clearly. Therefore, to provide clarification, we 
are revising the regulatory requirements of our FIP found under 40 CFR 
52.173(c) that apply to Power Boiler No. 2 for PM BART to state that 
the mill shall rely on compliance with the Boiler MACT PM standard 
under 40 CFR part 63 Subpart DDDDD to satisfy the PM BART requirement 
for Power Boiler No. 2. In other words, compliance with the Boiler MACT 
PM standard applicable to Power Boiler No. 2 is sufficient to 
demonstrate compliance with the PM BART requirement. Additionally, we 
are also clarifying that Power Boiler No. 2 must satisfy the PM BART 
requirement by relying on the Boiler MACT PM standard that it is 
subject to at any given time, such that if the MACT PM standard and/or 
the compliance demonstration and recordkeeping requirements are revised 
in the future, the boiler must rely on those revised requirements to 
satisfy the PM BART requirement.
---------------------------------------------------------------------------

    \59\ Boiler MACT standards are required under CAA section 112, 
and are found at 40 CFR part 63, subpart DDDDD--National Emission 
Standards for Hazardous Air Pollutants for Major Sources: 
Industrial, Commercial, and Institutional Boilers and Process 
Heaters.
---------------------------------------------------------------------------

    In response to comments we received from the company, we are 
revising our proposed compliance date for PM BART for Power Boiler No. 
2. The company submitted comments requesting that we finalize a 
compliance date of 30 days after the effective date of the final rule 
instead of requiring the source to comply with BART as of the effective 
date of the final rule. The company noted that this would provide 
additional time for it to prepare compliance records. We determined 
that the company's request is reasonable and would provide the mill 
with additional time to understand the applicable BART requirements and 
to prepare compliance records and adjust recordkeeping systems without 
unduly delaying compliance with the BART emission limit. Therefore, we 
are requiring Power Boiler No. 2 to comply with the PM BART emission 
limit no later than 30 days from the effective date of this final 
rule.\60\
---------------------------------------------------------------------------

    \60\ The revised compliance date is a logical outgrowth of our 
proposal based on the company's comments, which are discussed in 
more detail elsewhere in the final rule and our RTC document.

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

[[Page 66350]]

3. Reasonable Progress Analysis
a. Four-Factor Analysis
    In our proposed rule, we explained that the CENRAP CAMx modeling 
with PSAT showed that sulfate from all source categories combined 
contributed 87.05 inverse megameters (Mm-\1\) out of 133.93 
Mm-\1\ of light extinction at Caney Creek on the average 
across the 20% worst days in 2002, which is approximately 65% of the 
total light extinction. At Upper Buffalo, sulfate from all source 
categories combined contributed 83.18 Mm-\1\ out of 131.79 
Mm-\1\ of light extinction at Upper Buffalo on the average 
across the 20% worst days in 2002, which is approximately 63% of the 
total light extinction. Nitrate from all source categories combined 
contributed 13.78 Mm-\1\ out of 133.93 Mm-\1\ of 
light extinction at Caney Creek and 13.30 Mm-\1\ out of 
131.79 Mm-\1\ of light extinction at Upper Buffalo, which is 
approximately 10% of the total light extinction at each Class I area on 
the average across the 20% worst days in 2002. The CENRAP CAMx modeling 
showed that on most of the 20% worst days in 2002, total extinction was 
dominated by sulfate at both Caney Creek and Upper Buffalo.\61\ 
Additionally, total extinction at Caney Creek was dominated by nitrate 
on 4 of the days that comprise the 20% worst days in 2002, while a 
significant portion of the total extinction at Upper Buffalo on 2 of 
the days that comprise the 20% worst days in 2002 was due to 
nitrate.\62\ Given their contribution to visibility impairment on the 
20% worst days, we consider both SO2 and NOX to 
be key pollutants contributing to visibility impairment at Arkansas 
Class I areas, so it is appropriate to consider both SO2 and 
NOX controls in our reasonable progress analysis.
---------------------------------------------------------------------------

    \61\ See Arkansas Regional Haze SIP, Appendix 8.1--``Technical 
Support Document for CENRAP Emissions and Air Quality Modeling to 
Support Regional Haze State Implementation Plans,'' sections 3.7.1 
and 3.7.2. See the docket for this rulemaking for a copy of the 
Arkansas Regional Haze SIP.
    \62\ See Arkansas Regional Haze SIP, Appendix 8.1--``Technical 
Support Document for CENRAP Emissions and Air Quality Modeling to 
Support Regional Haze State Implementation Plans,'' section 3.7.1 
and 3.7.2. See the docket for this rulemaking for a copy of the 
Arkansas Regional Haze SIP.
---------------------------------------------------------------------------

    In our proposal, we explained that point sources are responsible 
for a majority of the total light extinction at each Class I area, 
contributing approximately 60% of the total light extinction. Point 
sources contributed 81.04 Mm-\1\ out of 133.93 
Mm-\1\ of light extinction at Caney Creek and 77.80 
Mm-\1\ out of 131.79 Mm-\1\ of light extinction 
at Upper Buffalo on the average across the 20% worst days in 2002. 
Because 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, we decided to focus only on point 
sources in our reasonable progress analysis for this planning period. 
Sulfate from point sources contributed 75.1 Mm-\1\ out of 
133.93 Mm-\1\ of light extinction at Caney Creek and 72.17 
Mm-\1\ out of 131.79 Mm-\1\ of light extinction 
at Upper Buffalo on the average across the 20% worst days in 2002, 
which is approximately 56% of the total light extinction at Caney Creek 
and 55% of the total light extinction at Upper Buffalo. Nitrate from 
point sources contributed 4.06 Mm-\1\ out of 133.93 
Mm-\1\ of light extinction at Caney Creek and 3.93 
Mm-\1\ out of 131.79 Mm-\1\ of light extinction 
at Upper Buffalo, which is approximately 3% of the total light 
extinction at each Class I area. Sulfate from Arkansas point sources 
contributed 2.20% of the total light extinction at Caney Creek and 
1.99% at Upper Buffalo, and nitrate from Arkansas point sources 
contributed 0.27% of the total light extinction at Caney Creek and 
0.14% at Upper Buffalo. We explained in our proposal that 
SO2 emissions (a sulfate precursor) are the principal driver 
of regional haze on the 20% worst days in Arkansas' Class I areas, as 
visibility impairment in 2002 on the 20% worst days was largely due to 
sulfate from point sources. We also explained that on the 20% worst 
days in 2018, sulfate from Arkansas' point sources is projected to 
contribute 3.58% of the total light extinction at Caney Creek and 3.20% 
at Upper Buffalo, while nitrate from Arkansas' point sources is 
projected to contribute 0.29% of the total light extinction at Caney 
Creek and 0.25% at Upper Buffalo. Based on the CENRAP 2018 visibility 
projections, sulfate from point sources is expected to continue being 
the principal driver of regional haze on the 20% worst days at 
Arkansas' Class I areas.
    As a starting point in our analysis to determine whether additional 
controls on Arkansas sources are necessary to make reasonable progress 
in the first regional haze planning period, we examined the most recent 
SO2 and NOX emissions inventories for point 
sources in Arkansas. In our examination of the SO2 and 
NOX emissions inventories for Arkansas' point sources, we 
found that the number of point sources in Arkansas that emit 
SO2 and NOX emissions is relatively small. 
Furthermore, a very small portion of the point sources in the state are 
responsible for a large portion of the statewide SO2 and 
NOX point-source emissions. Specifically, White Bluff, 
Independence, and Flint Creek are the three largest emitters of 
SO2 and NOX point-source emissions in the state 
and are collectively responsible for approximately 84% of the 
SO2 point source emissions and 55% of the NOX 
point-source emissions in the state.\63\ As our proposed rule included 
SO2 and NOX emission limits under BART for White 
Bluff Units 1 and 2 and Flint Creek Unit 1 that are anticipated to 
result in a substantial reduction in SO2 and NOX 
emissions from these facilities, we proposed to determine that it is 
appropriate to eliminate these two facilities from further 
consideration of additional controls under the reasonable progress 
requirements for the first planning period. The Entergy Independence 
Plant is not subject to BART, and its emissions were 30,398 
SO2 tpy and 13,411 NOX tpy based on the 2011 NEI. 
The Entergy Independence Plant is the second largest source of 
SO2 and NOX point-source emissions in Arkansas, 
accounting for approximately 36% of the SO2 point-source 
emissions and 21% of the NOX point-source emissions in the 
state. In our proposal, we explained that it was appropriate to focus 
our reasonable progress analysis on the Entergy Independence Power 
Plant because it is a significant source of SO2 and 
NOX as the second largest emitter of NOX and 
SO2 point-source emissions in the State. Consequently, 
addressing White Bluff and AEP Flint Creek under the BART requirements 
and Independence under the reasonable progress requirements will 
address a large proportion of the visibility impacts due to Arkansas 
point sources at Caney Creek and Upper Buffalo.
---------------------------------------------------------------------------

    \63\ 80 FR 18944, 18991.
---------------------------------------------------------------------------

    We also found that the remaining point sources in the state had 
much lower SO2 and NOX emissions than these 
facilities. For example, the point source with the fourth highest 
SO2 emissions is Future Fuel Chemical Company, which 
contributes approximately 4.1% of the total SO2 point-source 
emissions in the state (i.e., 3,420 SO2 tons out of 
statewide SO2 point source emissions of 83,883 
SO2 tons). The point source with the fourth highest 
NOX emissions is the Natural Gas Pipeline Company of America 
#308, which contributes approximately 5.1% of the total NOX 
point source emissions in the state (i.e., 3,194 NOX tons 
out of statewide NOX point source emissions of 62,984 
NOX tons). Based on the much smaller magnitude of these 
sources'

[[Page 66351]]

emissions, we determined that the remaining point sources in the state 
are less likely to be significant contributors to regional haze (both 
on an actual and percentage basis) and thus did not warrant closer 
evaluation during this planning period. Because such a small number of 
point sources in Arkansas are responsible for a such large portion of 
the statewide SO2 and NOX point-source emissions 
in the state, we concluded that photochemical modeling or other more 
exhaustive analyses that we have performed in other regional haze 
actions were unnecessary to identify sources in Arkansas to evaluate 
under reasonable progress. In contrast, in states such as Texas where 
the universe of point sources is much larger and the distribution of 
SO2 and NOX emissions is very widespread, an 
evaluation of the state's emissions inventory alone was not sufficient 
to reveal the best potential candidates for evaluation under reasonable 
progress. For this reason, we explained in our Texas Regional Haze FIP 
that, due to the challenges presented by the geographic distribution 
and number of sources in Texas, the CAMx photochemical model was best 
suited for identifying sources to evaluate for reasonable progress 
controls.\64\ We did not encounter these challenges in our Arkansas 
Regional Haze FIP and therefore did not conduct photochemical modeling.
---------------------------------------------------------------------------

    \64\ 81 FR 296 (January 5, 2016).
---------------------------------------------------------------------------

    In our reasonable progress analysis for Independence, we considered 
the four statutory factors under CAA section 169A(g)(1) and 40 CFR 
51.308(d)(1)(i)(A): The costs of compliance, the time necessary for 
compliance, the energy and nonair quality environmental impacts of 
compliance, and the remaining useful life of any existing source 
subject to such requirements. Alongside the four statutory factors, we 
also considered the visibility improvement of controls. Although 
visibility is not one of the four mandatory factors explicitly listed 
for consideration under CAA section 169A(g)(1) or 40 CFR 
51.308(d)(1)(i)(A), states or EPA have the option of considering the 
projected visibility benefits of controls in determining if the 
controls are necessary to make reasonable progress. In our proposal, we 
explained that SO2 emissions are the principal driver of 
regional haze on the 20% worst days in Arkansas' Class I areas. While 
point source NOX emissions are not the principal contributor 
to visibility extinction on the 20% worst days at Arkansas' Class I 
areas, NOX is nevertheless a key pollutant since 
NOX emissions contributed considerably to visibility 
impairment on a portion of the 20% worst days in 2002 based on CENRAP's 
CAMx source apportionment modeling. Further, our assessment of the 
Independence facility using CALPUFF dispersion modeling, which assesses 
the 98th percentile visibility impairment caused by the facility, 
indicated that Independence is potentially one of the largest single 
contributors to visibility impairment at Class I areas in Arkansas.\65\ 
Therefore, we determined that it was appropriate to evaluate the 
Independence facility for both SO2 and NOX 
controls under reasonable progress.
---------------------------------------------------------------------------

    \65\ 80 FR 24872.
---------------------------------------------------------------------------

    Based on our reasonable progress analysis under 40 CFR 
51.308(d)(1), we discussed in our proposal that SO2 and 
NOX controls at Independence would be cost-effective and 
would result in meaningful visibility benefits at Arkansas' Class I 
areas based on the maximum (98th percentile) facility impacts using 
CALPUFF dispersion modeling. Although the reasonable progress 
provisions of the Regional Haze Rule place emphasis on the 20% worst 
days, the CAA goal of remedying visibility impairment due to 
anthropogenic emissions encompasses all days. Thus, states and EPA have 
the discretion to consider the visibility impacts of sources and the 
visibility benefit of controls on days other than the 20% worst days in 
making their decisions, such as the days on which a given facility has 
its own largest impacts. Even if the days on which a given facility has 
its largest impacts are not the same as the 20% of days with the worst 
visibility overall, the facility's impacts will still need to be 
addressed for Arkansas' Class I areas to achieve the goal of natural 
visibility conditions. The Eighth Circuit previously addressed state 
and EPA use of CALPUFF for reasonable progress purposes.\66\
---------------------------------------------------------------------------

    \66\ North Dakota v. EPA, 730 F.3d 750, 764-66 (8th Cir. 2013) 
(discussing reasonable progress determination for the Antelope 
Valley station).
---------------------------------------------------------------------------

    Based on our consideration of the four reasonable progress factors 
and the visibility impacts from Independence and the visibility 
improvement of controls, we proposed two alternative options for 
reducing emissions at Independence Units 1 and 2. Under Option 1, we 
proposed to require both SO2 and NOX controls. 
Under Option 2, we proposed to require only SO2 controls. We 
solicited public comment on our two proposed options. In addition to 
Options 1 and 2, we also solicited public comment on any alternative 
SO2 and NOX control measures that could address 
the regional haze requirements for White Bluff Units 1 and 2 and 
Independence Units 1 and 2 for this planning period.
    We received many comments opposed to our proposal to establish any 
controls on Independence to achieve reasonable progress. Many of these 
comments stated that it was not necessary to control or even evaluate 
Arkansas' sources under the CAA and Regional Haze Rule's reasonable 
progress requirements because Arkansas' Class I areas are projected to 
be below the uniform rate of progress (URP) in 2018 and because 
Arkansas' Class I areas are on track to meet the RPGs established by 
the state in the Arkansas Regional Haze SIP. As discussed in section 
V.C. of this final rule and in our RTC document, we have an obligation 
under the CAA and the Regional Haze Rule to conduct an analysis of the 
four reasonable progress factors. This obligation applies even when a 
Class I area is below the URP and even when monitoring data show that a 
Class I area is meeting or is projected to meet the RPG previously 
established by the state. The CAA and Regional Haze Rule are clear that 
the determination of what controls are necessary to make reasonable 
progress (and whose emission reductions dictate the RPGs) must be 
determined based on the four-factor analysis. See CAA section 
169A(b)(2) & (g)(1); 40 CFR 51.308(d)(1)(i). Neither the CAA nor the 
Regional Haze Rule divest states or EPA of the authority and obligation 
to conduct a four-factor analysis for sources contributing 
significantly to visibility impairment based on existing or projected 
future visibility conditions at affected Class I areas. We discussed 
above and also in section V of this final rule that our four factor 
analysis focused on the Independence Plant because it is a significant 
source of visibility impairing pollutants, as it is the second largest 
source of SO2 and NOX point-source emissions in 
Arkansas.\67\ The largest and third largest sources of SO2 
and NOX point-source emissions in Arkansas are White Bluff 
and Flint Creek, for which we are requiring controls under the BART 
requirements in this final rule. In comparison to the SO2 
and NOX emissions from the three largest point sources 
(i.e., White Bluff, Independence, and Flint Creek), emissions from the 
remaining point sources in the state are relatively small and are less 
likely to be significant contributors to regional haze, both on an 
actual and percentage basis. Therefore,

[[Page 66352]]

our reasonable progress analysis focused on the Independence Plant. As 
discussed in our proposal and throughout this final notice, based on 
our analysis of the four reasonable progress factors and our 
consideration of the baseline visibility impacts from Independence and 
the visibility improvement of potential controls, we determined that 
SO2 and NOX controls at Independence would be 
cost-effective and would result in meaningful visibility benefits at 
Arkansas' Class I areas, and therefore find that they are reasonable 
controls and are necessary to make reasonable progress.
---------------------------------------------------------------------------

    \67\ The Independence Plant accounts for approximately 36% of 
the SO2 point-source emissions and 21% of the 
NOX point-source emissions in Arkansas (2011 NEI).
---------------------------------------------------------------------------

    Other comments we received stated that Arkansas' point sources have 
a very small impact on visibility impairment at Arkansas' Class I areas 
on the 20% worst days and that we should therefore not require any 
controls at Independence under the reasonable progress requirements. At 
a minimum, these commenters argued, the contribution to visibility 
impairment at Arkansas' Class I areas on the 20% worst days from point-
source nitrate emissions was insignificant, so NOX controls 
for Independence were unnecessary. After carefully considering these 
comments, we continue to believe that Arkansas' point sources have a 
significant contribution to visibility impairment at Arkansas Class I 
areas on the 20% worst days. As we discuss in section V.J. of this 
final rule, CAMx source apportionment modeling conducted by Entergy 
Arkansas Inc.\68\ (Entergy) and submitted to us during the public 
comment period showed that the contribution to visibility impairment 
due to emissions from the Independence facility alone are projected to 
be approximately 1.3% of the total visibility impairment during the 20% 
worst days in 2018 at each Arkansas Class I area. Considering that the 
CAMx photochemical modeling takes into account the emissions of 
thousands of sources, both in Arkansas and outside of the state, we 
consider this to be a significant contribution to visibility impairment 
at each Class I area and a large portion (approximately one-third) of 
the total contribution from all Arkansas point sources that can be 
addressed through installation of controls on two units at a single 
facility. The CAMx modeling also showed that at Upper Buffalo, the 
Independence facility's contribution to visibility impairment is 
greater than the contribution from all of the subject-to-BART sources 
addressed in this final action combined. In terms of deciviews, the 
average impact from Independence over the 20% worst days, based on 
Entergy's CAMx modeling and adjusted to natural background conditions, 
is over 0.5 dv at each of the Arkansas Class I areas. Together, the 
modeling results from Entergy's CAMx modeling and the CALPUFF modeling 
demonstrate that controls will provide meaningful visibility benefits 
toward the goal of natural visibility conditions.
---------------------------------------------------------------------------

    \68\ Entergy Arkansas Inc. is one of the owners of White Bluff 
Units 1 and 2 and Independence Units 1 and 2. The company submitted 
CAMx photochemical modeling as part of its comments submitted during 
the public comment period. These and all other comments we received 
are found in the docket associated with this rulemaking.
---------------------------------------------------------------------------

    While the majority of the visibility impacts due to Independence on 
the 20% worst days are due to SO2, we note that 
NOX emissions from the facility also have impacts on the 20% 
worst days. The CAMx source apportionment modeling submitted by Entergy 
showed that NOX emissions from Independence are responsible 
for 30-40% of the visibility impairment in Arkansas' Class I areas on 2 
of the 20% worst days (i.e., 2 out of the 21 days that are the 20% 
worst of the days with Interagency Monitoring of Protected Visual 
Environments (IMPROVE) monitoring data). We expect that installation of 
NOX controls on Independence will provide visibility 
improvement on this portion of the 20% worst days and will also provide 
meaningful visibility improvement on the 98th percentile day, as shown 
by the CALPUFF dispersion modeling. After carefully considering all 
comments submitted to us during the comment period, we are finalizing 
both SO2 and NOX controls for Independence Units 
1 and 2 to make reasonable progress at Arkansas' Class I areas (i.e., 
proposed Option 1), because both SO2 and NOX are 
key pollutants contributing to visibility impairment, and because we 
have determined that these controls are cost effective and will provide 
for significant visibility benefits towards the goal of natural 
visibility conditions at Arkansas' Class I areas.
    In response to comments we received on our initial cost analysis 
presented in our proposal, we have revised our cost estimate for dry 
FGD for Independence Units 1 and 2. Based on this revision to our cost 
analysis, we find that dry FGD is estimated to cost $2,853/
SO2 ton removed at Unit 1 and $2,634/SO2 ton 
removed. Although these cost estimates are slightly higher than we 
estimated in our proposal, we continue to find these controls to be 
cost effective and well within the range of cost of controls found to 
be reasonable by EPA and the States in other regional haze actions. Dry 
FGD controls on Independence are also expected to result in 
considerable visibility improvement at Arkansas' Class I areas based on 
CALPUFF modeling of the maximum (98th percentile) visibility impacts 
from the facility (see Table 14).\69\ As dry FGD will eliminate a 
majority of the SO2 emissions from Independence,\70\ we 
anticipate that on the 20% worst days these controls will also 
accordingly eliminate a majority of the visibility impairment due to 
SO2 emissions from Independence. Taking into consideration 
the four reasonable progress factors and the visibility benefit of dry 
FGD controls, we conclude that these are reasonable controls and are 
therefore necessary to make reasonable progress. We are finalizing an 
SO2 emission limit of 0.06 lb/MMBtu for Independence Units 1 
and 2 based on a 30 boiler-operating-day rolling average basis, which 
is consistent with the installation and operation of dry FGD. We are 
requiring the facility to comply with this emission limit no later than 
5 years from the effective date of this final rule.
---------------------------------------------------------------------------

    \69\ 80 FR 24872.
    \70\ As discussed in our proposal, dry FGD controls on 
Independence Units 1 and 2 are expected to reduce facility-wide 
SO2 emissions by 26,902 tpy from a baseline emission rate 
of 29,780 tpy (i.e., Units 1 and 2 combined). See 80 FR 18944, 
18993.

[[Page 66353]]

  Table 14--Entergy Independence Plant--Summary of the 98th Percentile
       Baseline Visibility Impacts and Improvement Due to Dry FGD
                             [Facility-wide]
------------------------------------------------------------------------
                                           Facility-wide
                                             baseline       Visibility
              Class I area                  visibility      improvement
                                              impact       from baseline
                                            ([Delta]dv)     ([Delta]dv)
------------------------------------------------------------------------
Caney Creek.............................           2.512           1.096
Upper Buffalo...........................           2.264           1.178
Cumulative Visibility Improvement at      ..............           2.274
 Arkansas' Class I areas ([Delta]dv)....
------------------------------------------------------------------------

    As discussed in our proposal, LNB/SOFA controls on Independence are 
estimated to cost $401/NOX ton removed at Unit 1 and $436/
NOX ton removed at Unit 2,\71\ which we consider to be very 
cost effective and well within the range of cost of controls found to 
be reasonable by EPA and the States in other regional haze actions. 
LNB/SOFA controls on Independence are also expected to provide 
considerable visibility benefits based on CALPUFF modeling of the 
maximum (98th percentile) visibility impacts from the facility (see 
Table 15).\72\ As LNB controls will eliminate a large portion of the 
NOX emissions from Independence,\73\ we anticipate that 
these controls will also accordingly eliminate a large portion of the 
visibility impairment due to NOX emissions from Independence 
on a portion of the 20% worst days. Taking into consideration the four 
reasonable progress factors and the visibility benefit of LNB/SOFA 
controls, we conclude that these are reasonable controls and are 
therefore necessary to make reasonable progress. As such, we are 
requiring NOX controls for Independence Units 1 and 2 under 
the reasonable progress requirements.
---------------------------------------------------------------------------

    \71\ Our cost analysis and visibility modeling analysis for LNB/
SOFA for Independence Units 1 and 2, as presented in our proposal, 
is based on an emission limit of 0.15 lb/MMBtu on a 30 boiler-
operating-day rolling average. As discussed in this final action, we 
received new information from Entergy that indicates that the source 
expects to be operating at less than 50% load more frequently and 
therefore no longer expects to be able to meet our proposed 
NOX emission limit. We are therefore finalizing the 
bifurcated NOX emission limit described in this final 
action. We recognize that the comments submitted by Entergy indicate 
that some of the assumptions used to calculate the cost 
effectiveness of NOX controls for Independence may not 
exactly apply to future operations. However, because we found LNB/
SOFA controls to be very cost effective, we expect that even if the 
change in operation of the source were known more precisely and were 
taken into account in our calculation of the cost ($/ton), these 
controls would continue to be cost effective. Therefore, we are not 
revising our cost effectiveness calculations or visibility 
improvement modeling of LNB/SOFA for Independence Units 1 and 2.
    \72\ 80 FR 24872.
    \73\ As discussed in our proposal, LNB/SOFA controls on 
Independence Units 1 and 2 are expected to reduce facility-wide 
NOX emissions by 5,927 tpy from a baseline emission rate 
of 12,713 tpy (i.e., Units 1 and 2 combined). See 80 FR 18944, 
18996.

  Table 15--Entergy Independence Plant--Summary of the 98th Percentile
       Baseline Visibility Impacts and Improvement Due to LNB/SOFA
                             [Facility-wide]
------------------------------------------------------------------------
                                           Facility-wide
                                             baseline       Visibility
              Class I area                  visibility      improvement
                                              impact       from baseline
                                            ([Delta]dv)     ([Delta]dv)
------------------------------------------------------------------------
Caney Creek.............................           2.028           0.459
Upper Buffalo...........................           2.003           0.198
Cumulative Visibility Improvement at      ..............           0.657
 Arkansas' Class I areas ([Delta]dv)....
------------------------------------------------------------------------

    We received comments from the company stating that Independence 
Units 1 and 2 are no longer expected to be able to consistently meet 
our proposed NOX emission limit of 0.15 lb/MMBtu over a 30-
boiler-operating-day period based on LNB/SOFA controls.\74\ We have 
determined that the company has provided sufficient information to 
substantiate that the units are not expected to be able to meet our 
proposed NOX emission limit of 0.15 lb/MMBtu when the units 
are primarily operated at less than 50% of their operating capacity. 
Therefore, we are finalizing a ``bifurcated'' NOX emission 
limit for each unit.\75\ We are requiring Independence Units 1 and 2 to 
meet a NOX emission limit of 0.15 lb/MMBtu on a 30 boiler-
operating-day rolling average, where the average is to be calculated by 
including only the hours during which the unit was dispatched at 50% or 
greater of maximum capacity. In this particular case, the 30 boiler-
operating-day rolling average is to be calculated for each unit by the 
following procedure: (1) Summing the total pounds of NOX 
emitted during the current boiler operating day and the preceding 29 
boiler operating days, including only emissions during hours when the 
unit was dispatched at 50% or greater of maximum capacity; (2) summing 
the total heat input in MMBtu to the unit during the current boiler 
operating day and the preceding 29 boiler operating days, including 
only the heat input during hours when the unit was dispatched at 50% or 
greater of maximum capacity; and (3) dividing the total pounds of 
NOX emitted as

[[Page 66354]]

calculated in step 1 by the total heat input to the unit as calculated 
in step 2. In addition to this limit that is intended to control 
NOX emissions when the units are operated at 50% or greater 
of maximum capacity, we are also establishing a limit in lb/hr that 
applies only when the units are operated at lower capacity. We are 
requiring Independence Units 1 and 2 to meet an emission limit of 671 
lb/hr on a rolling 3-hour average, where the average is to be 
calculated by including emissions only for the hours during which the 
unit was dispatched at less than 50% of the unit's maximum heat input 
rating (i.e., hours when the heat input to the unit is less than 4,475 
MMBtu). We calculated this emission limit by multiplying 0.15 lb/MMBtu 
by 50% of the maximum heat input rating for each unit (i.e., 50% of 
8,950 MMBtu/hr, or 4,475 MMBtu/hr). As discussed in section V.F. in 
this final rule, in response to comments we received, we are shortening 
the compliance date for the NOX emission limit for 
Independence Units 1 and 2 from our proposed 3 years to 18 months.
---------------------------------------------------------------------------

    \74\ Entergy submitted comments on this issue that are 
applicable to both White Bluff and Independence. We discuss and 
address these comments in more detail elsewhere in this final rule.
    \75\ The bifurcated emission limit is a logical outgrowth of our 
proposal based on the company's comments, which are discussed in 
more detail elsewhere in the final rule and our RTC document. See 
Int'l Union, UMW, 407 F.3d at 1259; Fertilizer Inst, 935 F.2d at 
1311; and Chocolate Mfrs. Ass'n, 755 F.2d 1098.
---------------------------------------------------------------------------

    We also received comments during the public comment period from 
Entergy that presented an alternative multi-unit approach to address 
the regional haze requirements for White Bluff Units 1 and 2 and 
Independence Units 1 and 2.\76\ The company's alternative approach 
consisted of the following: Requiring White Bluff Units 1 and 2 and 
Independence Units 1 and 2 to comply with an SO2 emission 
limit of 0.60 lb/MMBtu on a 30 boiler-operating-day rolling average 
beginning in 2018; requiring White Bluff Units 1 and 2 and Independence 
Units 1 and 2 to comply with a NOX emission limit of 1,342.5 
lb/hr on a 30 boiler-operating-day rolling average based on the 
installation of LNB/SOFA within 3 years; and ceasing coal combustion at 
White Bluff Units 1 and 2 in 2027 and 2028. We note that we do not 
interpret Entergy's comments as suggesting that we adopt the elements 
in its alternative that are unique to White Bluff as an alternative to 
our proposed BART emission limits at the facility unless we also 
conclude that the remaining elements address any reasonable progress 
requirements for Independence. After carefully considering the comments 
we received specifically on this issue, we do not believe the 
comprehensive multi-unit strategy as presented by the company has 
potential to satisfy the BART requirements for White Bluff Units 1 and 
2 and the reasonable progress requirements for Independence Units 1 and 
2. We address this in more detail elsewhere in this final rule.
---------------------------------------------------------------------------

    \76\ As described in section I. of this notice, Entergy also 
submitted a comment after the close of the comment period, 
indicating that Entergy intends that a second alternative described 
in the late comment, involving only White Bluff, is a replacement 
for the multi-unit alternative previously described in its timely 
comments. Because the late comment is not a basis for our decision 
making in this final rule, we are responding in this final rule and 
in our RTC document to the alternative proposal described in the 
comments that Entergy filed during the comment period.
---------------------------------------------------------------------------

b. RPGs for Caney Creek and Upper Buffalo
    We proposed RPGs for the 20% worst days for Caney Creek and Upper 
Buffalo of 22.27 dv and 22.33 dv, respectively that reflected the 
anticipated visibility conditions resulting from the combination of 
control measures from the approved portion of the 2008 Arkansas 
Regional Haze SIP and our FIP proposal. We received comments on our 
proposal indicating that our proposed RPGs for the 20% worst days for 
Caney Creek and Upper Buffalo improperly incorporated visibility 
improvements that would not occur until after 2018. After considering 
these comments, we agree that the RPGs should reflect anticipated 
visibility conditions at the end of the implementation period in 2018 
rather than the anticipated visibility conditions once the FIP has been 
fully implemented. This approach is consistent with the purpose of RPGs 
and the direction provided in our 2007 Reasonable Progress 
Guidance.\77\
---------------------------------------------------------------------------

    \77\ ``Guidance for Setting Reasonable Progress Goals Under the 
Regional Haze Program,'' dated June 1, 2007. We refer to this 
guidance as the ``2007 Reasonable Progress Guidance'' throughout 
this final notice.
---------------------------------------------------------------------------

    Section 169B(e)(1) of the CAA directed the Administrator to 
promulgate regulations that ``include[e] criteria for measuring 
`reasonable progress' toward the national goal.'' Consequently, we 
promulgated 40 CFR 51.308(d)(1) as part of the Regional Haze Rule. This 
provision directs states to develop RPGs for the most and least 
impaired days to ``measure'' the progress that will be achieved by the 
control measures in the state's long-term strategy ``over the period of 
the implementation plan.'' \78\ The current implementation period ends 
in 2018. RPGs ``are not directly enforceable'' like the emission 
limitations in the long-term strategy.\79\ Rather, they fulfill two key 
purposes: (1) Allowing for comparisons between the progress that will 
be achieved by the state's long-term strategy and the URP,\80\ and (2) 
providing a benchmark for assessing the adequacy of a state's SIP in 5-
year periodic reports.\81\ Consequently, in our 2007 Reasonable 
Progress Guidance, we indicated that states could consider the ``time 
necessary for compliance'' factor by ``adjust[ing] the RPG to reflect 
the degree of improvement in visibility achievable within the period of 
the first SIP if the time needed for full implementation of a control 
measure (or measures) will extend beyond 2018.'' \82\ In other words, 
RPGs need not reflect the visibility improvement anticipated from all 
of the control measures deemed necessary to make reasonable progress 
(as a result of the four-factor analysis) and included in the long-term 
strategy.
---------------------------------------------------------------------------

    \78\ 40 CFR 51.308(d)(1).
    \79\ 40 CFR 51.308(d)(1)(iv).
    \80\ 40 CFR 51.308(d)(1)(ii).
    \81\ 40 CFR 51.308(g)-(h).
    \82\ ``Guidance for Setting Reasonable Progress Goals Under the 
Regional Haze Program,'' at 5-2.
---------------------------------------------------------------------------

    In this instance, we are taking final action on the Arkansas 
Regional Haze FIP 9 years after the state's initial SIP submission was 
due.\83\ As a result, only some of the control measures that we have 
determined are necessary to satisfy the BART and reasonable progress 
requirements will be installed by the end of 2018. Some controls will 
not be installed until 2021. Because RPGs are only unenforceable 
analytical benchmarks, we think that it is appropriate to follow the 
recommendation in our 2007 Reasonable Progress Guidance and finalize 
RPGs that represent the visibility conditions anticipated on the 20% 
worst days at Caney Creek and Upper Buffalo by 2018. These RPGs are 
listed in the table below: 84 85
---------------------------------------------------------------------------

    \83\ We discuss in section II.A of this final rule the history 
of the state's submittals and our actions.
    \84\ These RPGs are calculated using the same methodology 
described in our proposal and TSD. See ``CACR UPBU RPG analysis 
2018.xlsx'' for additional information on the calculation of the 
RPGs.
    \85\ The RPGs we are finalizing in this rulemaking for Caney 
Creek and Upper Buffalo are a logical outgrowth of our proposed RPGs 
based on comments we received, which are discussed in more detail 
elsewhere in the final rule and our RTC document. See Int'l Union, 
UMW, 407 F.3d at 1259; Fertilizer Inst., 935 F.2d at 1311; and 
Chocolate Mfrs. Ass'n v. Block, 755 F.2d 1098.

 Table 16--Reasonable Progress Goals for 2018 for Caney Creek and Upper
                                 Buffalo
------------------------------------------------------------------------
                                                           2018 RPG 20%
                      Class I area                          Worst days
                                                               (dv)
------------------------------------------------------------------------
Caney Creek.............................................           22.47
Upper Buffalo...........................................           22.51
------------------------------------------------------------------------

[[Page 66355]]

4. Long-Term Strategy
    We are finalizing our determination that the provisions in this 
final rule, in combination with provisions in the approved portion of 
the Arkansas Regional Haze SIP, fulfill the Regional Haze Rule's long-
term strategy requirements. The long-term strategy must include 
enforceable emissions limitations, compliance schedules, and other 
measures as necessary to achieve reasonable progress at Class I areas 
impacted by emissions from Arkansas. In this final rule, we are 
promulgating emission limits, compliance schedules, and other 
requirements for nine units subject to BART and for two reasonable 
progress units.

B. Interstate Visibility Transport

    We are finalizing our determination that the control measures in 
the approved portion of the Arkansas Regional Haze SIP and our final 
FIP are adequate to prevent Arkansas' emissions from interfering with 
other states' required measures to protect visibility. Thus, the 
combined measures from both plans satisfy the interstate transport 
visibility requirement of CAA section 110(a)(2)(D)(i)(II) for the 1997 
8-hour ozone and the 1997 PM2.5 NAAQS.

V. Summary and Analysis of Major Issues Raised by Commenters

    We received comments at the public hearing held in Little Rock, as 
well as comments submitted electronically on www.regulations.gov and 
through the mail. The full text of comments we received from commenters 
is included in the publicly posted docket associated with this action 
at www.regulations.gov. Our RTC document, which is also included in the 
docket associated with this action, provides detailed responses to all 
significant comments received, and is a part of the administrative 
record for this action. Below we provide summaries of the more 
significant comments received and our responses to them. Our RTC 
document is organized similarly to the structure of this section (e.g., 
Cost, Modeling, etc.). Therefore, if additional information is desired 
concerning how we addressed a particular comment, the reader should 
refer to the appropriate section in the RTC document.

A. General Comments

    Comment: We received 238 comments in support of our rulemaking, 
specifically regarding the requirements to control SO2, 
NOX, and PM emissions from Arkansas' subject-to-BART 
sources, and to control emissions from the Independence facility 
pursuant to the Regional Haze Rule's reasonable progress requirements. 
Most of these commenters also expressed support for our proposed Option 
1, which consists of both SO2 and NOX controls 
for Independence Units 1 and 2. These comments were from members 
representing various organizations and members of the general public. 
At the public hearing in Little Rock, Arkansas, 40 people expressed 
general support for the plan. The speakers at the public hearings 
included members of various organizations and members of the general 
public. Some of these commenters also stated that we should transition 
away from coal-fired power and that retrofitting these plants and 
allowing them to continue operating is not a sound long-term solution, 
but does signal progress in Arkansas towards cleaner energy sources.
    Response: We thank the commenters for participating in the 
rulemaking and acknowledge their support of this action. As discussed 
in section IV. of this final rule, we are finalizing SO2, 
NOX, and PM controls for six facilities under the BART 
requirements and we are finalizing both SO2 and 
NOX controls for Independence under the reasonable progress 
requirements (proposed Option 1). Under the Regional Haze Rule, we are 
authorized to require affected sources to meet emission limits for 
visibility impairing pollutants (i.e., SO2, NOX, 
and PM), but we are not authorized to dictate what type of technology 
the source must employ to meet those emission limits and we are not 
authorized to force sources to retire or to stop burning fossil fuels. 
However, sources may choose to voluntarily retire or switch fuels in 
order to comply with our emission limits.
    Comment: We received one email from a citizen that opposed our 
proposal. The commenter expressed that it is not fair that we are 
requiring sources in Arkansas to spend a large amount of money in 
retrofits when other countries are not held to the same standards. The 
commenter questioned why other countries are given additional time to 
meet requirements. The commenter also expressed concern that our 
proposed controls would result in a higher electric bill that could 
mean no electricity for some people.
    Response: We acknowledge the commenter's concerns. Consistent with 
the CAA, the regional haze program is concerned with remedying existing 
and preventing future impairment of visibility caused by manmade air 
pollution in mandatory Class I Federal areas (located in this country). 
Our action requires particular Arkansas sources to control emissions 
that impact visibility at Arkansas and Missouri Class I areas. Our 
action does not in any way expect Arkansas to make up for emissions 
from international sources. On the other hand, as we discussed in the 
preamble to the Regional Haze Rule, ``the States should not consider 
the presence of emissions from foreign sources as a reason not to 
strive to ensure reasonable progress in reducing any visibility 
impairment caused by sources located within their jurisdiction.'' \86\ 
While the goal of the regional haze program is to restore natural 
visibility conditions at Class I areas by 2064, the rule requires only 
that reasonable progress be made towards the goal during each planning 
period. In cases where it is not reasonable to meet the rate of 
progress needed to attain the goal by 2064, the Regional Haze Rule 
requires a state to demonstrate that this rate of progress is not 
reasonable, and that the state's selected rate of progress is 
reasonable for that planning period. While there is no indication at 
this time that emissions from international sources are anticipated to 
prevent Arkansas from attaining the goal of natural visibility 
conditions at its Class I areas, we recognize that in some cases it may 
not be possible to attain the goal by 2064 because of impacts from new 
or persistent international emissions sources or impacts from sources 
where reasonable controls are not available. However, states are still 
required to demonstrate that they are establishing a reasonable rate of 
progress that includes implementation of reasonable measures within the 
state to address visibility impairment in an effort to make progress 
towards the natural visibility goal during each planning period. We 
acknowledge the commenter's concern regarding potential increases in 
electricity rates. While our consideration of cost under the Regional 
Haze Rule is limited to the direct costs incurred by sources, 
consistent with the CAA's and Rule's source-specific focus, we are very 
sensitive to the ramifications of our actions and we seek to select the 
most cost-effective options when we propose and finalize these 
controls.
---------------------------------------------------------------------------

    \86\ 64 FR 35714, 35755 (July 1, 1999).
---------------------------------------------------------------------------

    Comment: ADEQ submitted comments stating that it concurs with our 
proposed determination that the Georgia Pacific-Crossett Mill 6A and 9A 
Boilers are not subject to BART.
    Response: We appreciate ADEQ's support of our proposed 
determination. As discussed in section IV. of this final action, we are 
finalizing our determination that the Georgia Pacific-

[[Page 66356]]

Crossett Mill 6A and 9A Power Boilers are not subject to BART.

B. Entergy's Alternative Strategy for White Bluff and Independence

    Comment: Entergy proposes an alternative multi-unit strategy to 
address the regional haze requirements for four units that it states 
EPA should adopt instead of finalizing the proposed controls for the 
four units. The alternative multi-unit strategy involves meeting an 
emission limit of 0.60 lb/MMBtu on a 30-day rolling average at White 
Bluff Units 1 and 2 and Independence Units 1 and 2 by 2018; ceasing 
coal combustion at White Bluff Units 1 and 2 by 2027 and 2028; and 
installing LNB/SOFA at White Bluff Units 1 and 2 and Independence Units 
1 and 2 within 3 years. Based on Entergy's modeling, the company says 
it believes its alternative multi-unit proposal achieves virtually the 
same visibility benefit as the FIP proposal and that the alternative 
proposal would ensure that Arkansas' Class I areas remain below the URP 
glidepath. Entergy argues that the difference in the haze index between 
the proposed FIP controls and Entergy's alternative multi-unit strategy 
is too trivial to justify a $2 billion investment at White Bluff and 
Independence for the installation of dry FGD.
    Response: After carefully considering the comments we received, we 
have determined that we cannot approve Entergy's alternative proposal 
consistent with the Clean Air Act and Regional Haze rule. This 
determination is based on our conclusion that the alternative is not a 
better than BART alternative, does not meet the BART requirement for 
White Bluff Units 1 and 2, does not meet the reasonable progress 
requirements, and does not provide for the same visibility benefits as 
the FIP while delaying a majority of the visibility benefits until 
several years later than the FIP. Below, we discuss our assessment of 
the merits of Entergy's alternative proposal as an alternative approach 
for both meeting the BART requirements of section 308(e) for White 
Bluff and meeting the requirements of sections 308(d)(1) and 308(d)(3) 
regarding reasonable progress.
    As an initial matter, we note that Entergy does not appear to be 
proposing that we apply the provisions of sections 308(e)(2) and 
308(e)(3) to determine that its multi-unit strategy is an alternative 
program that provides more reasonable progress than BART. To the extent 
that this is Entergy's proposal, we cannot approve Entergy's multi-unit 
plan as an alternative to BART because it does not meet the 
requirements of section 308(e)(2)(iii) that ``all necessary emission 
reductions take place during the first planning period,'' i.e., by 
December 31, 2018. Moreover, Entergy does not argue that its 
alternative would provide for ``greater'' reasonable progress towards 
achieving natural visibility conditions, only that its proposal would 
result in ``virtually the same'' visibility benefits. Thus, our 
assessment discussed below considers only the requirements of section 
308(e)(1), which contains the source-specific BART requirements, in 
considering the provisions of Entergy's alternative proposal applicable 
to White Bluff.
    Entergy proposes that White Bluff Units 1 and 2 would meet an 
SO2 interim emission limit of 0.6 lb/MMBtu on a rolling 30-
day average from 2018 through 2027/2028, when coal combustion at the 
two units would cease.\87\ We note that the 0.6 lb/MMBtu interim 
emission limit is only slightly lower than the units' current 
SO2 emission rates. The maximum monthly SO2 
emission rates for White Bluff Units 1 and 2 in 2009-2013 were 0.653 
lb/MMBtu and 0.679 lb/MMBtu, respectively.\88\ Thus, under Entergy's 
alternative proposal, White Bluff Units 1 and 2 would continue to 
operate for the remainder of the first planning period and throughout 
most of the second planning period at near the current emission rate, 
with only a slight actual reduction in SO2 emissions. 
Because section 308(e)(1) and the BART guidelines require that a 
subject-to-BART source install and operate the best available emission 
reduction technology based on the five statutory factors, it is 
necessary to consider whether there are any additional SO2 
control measures, such as dry sorbent injection (DSI), that constitute 
BART during this interim period. Entergy has argued that with this 
limited remaining period of coal combustion, the cost per ton of 
SO2 emissions reduction for dry scrubbers would be too high 
for it to be selected as BART for White Bluff. While we agree that a 
shorter remaining useful life might result in a conclusion that dry 
scrubbers are not cost effective, as part of the BART analysis, 
technically feasible control technologies beyond the interim 
SO2 emission limit the company has proposed must be 
evaluated to determine if they are cost effective for use in the period 
before coal combustion ceases. In particular, DSI has a relatively low 
capital cost and may be cost effective even if operated for a short 
period of time.\89\ Under Entergy's proposed strategy, White Bluff 
Units 1 and 2 would cease coal combustion towards the end of the second 
planning period. Therefore, it would be necessary to consider and 
evaluate DSI as a possible interim BART control option for White Bluff 
Units 1 and 2. Because Entergy has provided no analysis to demonstrate 
that there is no more effective interim SO2 control that 
would constitute BART, the company's proposed strategy is not adequate 
to ensure that the BART requirements for White Bluff Units 1 and 2 will 
be met.
---------------------------------------------------------------------------

    \87\ Although not specified in Entergy's written comments, the 
company met with us and confirmed that the interim emission limit 
would be met by combusting lower sulfur coal. See file titled 
``Record of Meeting October 27 2015,'' which is found in the docket 
for this rulemaking.
    \88\ 80 FR 18944, 18970; see also the spreadsheet titled ``White 
Bluff R6 cost revisions2,'' which is found in the docket for this 
rulemaking.''
    \89\ For example, Florida evaluated a shutdown option by 
December 31, 2020 for two BART units. After reviewing the Florida 
Regional Haze SIP, we concluded that the State should have evaluated 
DSI as a as a possible interim BART control option during the 
interim before the units shut down. We ultimately approved Florida's 
determination after evaluating the cost-effectiveness of DSI and 
concluding that such controls were not cost-effective in light of 
the remaining useful life of the units. See 78 FR 53250, 53261 
(August 29, 2013).
---------------------------------------------------------------------------

    Even if it were not necessary to evaluate DSI or if we found it to 
not be cost effective for use at White Bluff in the interim period 
before coal combustion ceases, Entergy's alternative proposal would 
still not satisfy the BART requirements for White Bluff because it does 
not propose SO2 and NOX emission limits after 
coal combustion ceases or otherwise propose adopting a binding 
requirement to burn only natural gas or completely shut down the units. 
Entergy proposes to cease coal combustion at White Bluff Units 1 and 2 
in 2027/2028, but its comments do not specify the operating conditions 
of White Bluff Units 1 and 2 after coal combustion ceases. The type of 
fuel White Bluff is permitted to burn after ceasing coal combustion 
will impact the emissions reductions actually achieved under Entergy's 
alternative proposal. Exhibit C to Entergy's comments indicates that 
the company assumes in its visibility modeling that SO2 and 
NOX emissions from White Bluff Units 1 and 2 will be zero 
under the company's alternative proposal (i.e., ``Entergy's proposed 
controls'' scenario).\90\ If Entergy's alternative proposal had 
included accepting a binding requirement to burn only natural gas at 
White Bluff Units 1 and 2 after coal combustion ceases, or a binding 
requirement to completely shut down the units, then we would

[[Page 66357]]

agree that it would be appropriate to assume that SO2 
emissions from White Bluff will be zero beginning in 2027/2028. 
Similarly, if Entergy's alternative proposal had included accepting a 
binding requirement to completely shut down White Bluff, then we would 
agree that it would be appropriate to assume that NOX 
emissions from White Bluff will be zero beginning in 2027/2028.
---------------------------------------------------------------------------

    \90\ See ``Regional Haze Modeling Assessment Report,'' dated 
August 4, 2015, submitted as Exhibit C to Entergy Arkansas Inc.'s 
comments.
---------------------------------------------------------------------------

    Although, as we have already established, Entergy's alternative 
proposal cannot constitute a BART alternative because all necessary 
emission reductions will not take place during the first implementation 
period and the alternative proposal also does not satisfy the source-
specific BART requirements of section 308(e)(1) for White Bluff, in 
response to Entergy's comment that its alternative proposal would 
achieve almost the same level of visibility benefit as the FIP, we 
compared the potential impacts of Entergy's proposal to our FIP. 
Despite the ambiguity in the comments submitted by Entergy regarding 
its alternative proposal, for purposes of assessing the visibility 
impacts of the company's proposed approach we have assumed that post-
2028 SO2 and NOX emissions from White Bluff Units 
1 and 2 will be zero under Entergy's alternative proposal. In Table 17, 
we compare the total annual SO2 emissions reductions that 
would result under our FIP and under Entergy's alternative proposal 
when the alternative proposal is fully implemented in 2028 (i.e., when 
coal combustion has ceased at White Bluff).\91\ For consistency and to 
allow for direct comparison to our FIP proposal, in estimating the 
SO2 emissions reductions anticipated to result from 
Entergy's alternative proposal we have assumed the same SO2 
baseline emissions we used for White Bluff and Independence in our 
proposal.\92\ As shown in Table 17, although Entergy's alternative 
proposal would, after 2027/2028, achieve slightly greater 
SO2 reductions at White Bluff Units 1 and 2 than our FIP 
proposal, it would achieve substantially lower SO2 
reductions at Independence Units 1 and 2. Under Entergy's proposed 
approach, Independence Units 1 and 2 would be subject to an 
SO2 emission limit of 0.6 lb/MMBtu on a rolling 30-day 
average beginning in 2018.\93\ This emission limit is only slightly 
lower than the current SO2 emission rates from Independence 
Units 1 and 2. The maximum monthly SO2 emission rates for 
Independence Units 1 and 2 in 2009-2013 were 0.631 lb/MMBtu and 0.612 
lb/MMBtu, respectively.\94\ We have no basis to assume that future 
emissions would be different from current rates in the absence of new 
SIP or FIP requirements, and so these current emission rates are the 
appropriate baseline for comparing strategies, rather than the 
currently permitted emission rates, which are higher. As such, under 
Entergy's proposal these units would continue to operate with minimal 
SO2 emissions reductions. Unlike Entergy's proposed approach 
with respect to White Bluff, the proposed limits for Independence would 
not be interim emission limits. The company's alternative proposal does 
not include any further SO2 controls for Independence Units 
1 and 2, such as DSI or the eventual cessation of coal combustion. In 
contrast, we expect our proposed SO2 emission limit of 0.06 
lb/MMBtu would significantly and permanently reduce SO2 
emissions from Independence Units 1 and 2. As shown in Table 17, our 
FIP proposal would achieve substantially greater SO2 
emissions reductions at Independence than Entergy's alternative 
proposal. We estimate that the additional SO2 emissions 
reductions that our FIP proposal would achieve at Independence compared 
to Entergy's alternative strategy are 11,621 SO2 tpy at Unit 
1 and 12,591 SO2 tpy at Unit 2. In light of the minimal 
SO2 emissions reductions that would be achieved at 
Independence under the company's proposed strategy, we expect that 
there would be correspondingly minimal visibility improvement with 
respect to the SO2 controls it proposes for Independence.
---------------------------------------------------------------------------

    \91\ The SO2 emissions reductions expected to result 
from our FIP will take place several years earlier than any 
significant SO2 reductions under Entergy's alternative 
proposal. However, for purposes of comparing the long-term emissions 
reductions under the FIP and under the Entergy alternative, we are 
assessing the annual emissions reductions that will take place 
beginning in 2028, when the Entergy alternative would be fully 
implemented.
    \92\ In our proposal, for purposes of estimating the annual 
SO2 emissions reductions due to controls on White Bluff 
Units 1 and 2 and Independence Units 1 and 2, we assumed an 
SO2 emissions baseline that was determined by examining 
annual SO2 emissions for the years 2009-2013, eliminating 
the year with the highest emissions and the year with the lowest 
emissions, and obtaining the average of the three remaining years. 
See 80 FR 18944, 18971, and 18992.
    \93\ Although not specified in Entergy's written comments, the 
company met with us and confirmed that this emission limit would be 
met by combusting lower sulfur coal. See file titled ``Record of 
Meeting October 27 2015,'' which is found in the docket for this 
rulemaking.
    \94\ See the spreadsheet titled ``White Bluff R6 cost 
revisions2,'' which is found in the docket for this rulemaking.

 Table 17--Comparison of Annual SO2 Emissions Reductions From White Bluff Units 1 and 2 and Independence Units 1
                                                      and 2
                                                   [Post-2028]
----------------------------------------------------------------------------------------------------------------
                                                                                                  Additional SO2
                                                   SO2 Baseline                       Entergy        emissions
                                                     emissions    FIP Proposal--    alternative     reductions
                      Unit                             (tpy)        annual SO2      proposal--      achieved by
                                                                  reductions \1\    annual SO2     FIP proposal
                                                                                  reductions \2\
----------------------------------------------------------------------------------------------------------------
White Bluff Unit 1..............................          15,816          14,363          15,816         (1,453)
White Bluff Unit 2..............................          16,697          15,221          16,697         (1,476)
Independence Unit 1.............................          14,269          12,912           1,291          11,621
Independence Unit 2.............................          15,511          13,990           1,399          12,591
                                                 ---------------------------------------------------------------
    Total--All four units combined (SO2 tpy)....          62,293          56,486          35,203          21,283
----------------------------------------------------------------------------------------------------------------
\1\ These SO2 reductions will begin taking place no later than 5 years from the effective date of this final
  FIP.
\2\ This takes into account the full SO2 reductions that would take place under Entergy's alternative proposal;
  a small amount of SO2 reductions would begin taking place in 2018, but the majority of these SO2 reductions
  would begin taking place in 2027/2028.

    As shown in Table 17, considering the four units combined, we 
estimate that our FIP proposal would achieve annual emissions 
reductions of 21,283 SO2 tpy more than Entergy's alternative 
proposal. With regard to visibility benefits, Entergy does not assert 
that its alternative proposal would provide equal or greater visibility 
benefits

[[Page 66358]]

relative to our proposed FIP once the alternative is fully realized in 
the period after 2027/2028. Entergy states only that its alternative 
proposal would provide almost the same visibility benefit as our 
proposed FIP post-2027/2028. However, as illustrated in Table 17, it is 
clear that annual emissions would be significantly higher under the 
Entergy alternative and that the long-term visibility benefits of the 
Entergy alternative proposal would be significantly smaller than those 
of the proposed and final FIP. As we explained above, Entergy assumes 
in its visibility improvement projections that SO2 and 
NOX emissions from White Bluff Units 1 and 2 will be zero 
under the company's alternative proposal. The assumption of zero 
SO2 emissions from White Bluff after coal combustion ceases 
would be appropriate only if Entergy's alternative proposal involves 
accepting a binding requirement to burn only natural gas or permanently 
shut down after coal combustion ceases. With respect to NOX 
emissions from all four units of White Bluff and Independence, 
Entergy's multi-unit strategy includes the same level of NOX 
control as our FIP proposal prior to the cessation of coal combustion 
at White Bluff in 2027/2028. Since Entergy's explanation of its 
alternative proposal does not specify the operating conditions of White 
Bluff Units 1 and 2 when coal combustion ceases in 2027/2028, we find 
that the assumption of zero NOX emissions is also not 
adequately supported. However, even if we accept Entergy's assumption 
that NOX emissions from White Bluff will be zero after coal 
combustion ceases and that its alternative proposal would thus achieve 
greater NOX reductions compared to our FIP proposal, given 
the dominance of visibility impact from sulfate compared to nitrate at 
the affected Class I areas in Arkansas, the higher visibility impacts 
due to sulfate under the Entergy alternative proposal would more than 
outweigh any extra nitrate-related visibility benefit. Entergy's own 
CAMx modeling shows that even assuming zero SO2 and 
NOX emissions from White Bluff once it ceases coal 
combustion, its multi-unit alternative proposal would achieve less 
visibility benefit than the FIP controls at Arkansas' Class I areas, 
most significantly at Upper Buffalo where the benefit from Entergy's 
proposal is approximately only 66% of the benefit from the FIP (i.e., 
1.54 dv visibility benefit from the FIP compared to 0.97 dv from 
Entergy's alternative proposal).\95\
---------------------------------------------------------------------------

    \95\ We discuss this, as well as Entergy's ranked statistical 
analysis and its photochemical modeling, in more detail elsewhere in 
this final rule and in our RTC document.
---------------------------------------------------------------------------

    We also note that Entergy does not appear to be requesting in the 
comments submitted during the comment period that we adopt the elements 
in its alternative proposal that are unique to White Bluff as an 
alternative to our proposed BART emission limits at the facility unless 
we also conclude that the remaining elements address any reasonable 
progress requirements for Independence. In other words, Entergy's 
comments provide no indication that it is willing to accept a binding 
requirement to cease coal combustion at White Bluff by 2027/2028, 
unless we also accept the elements of its alternative proposal that are 
applicable to Independence as satisfying the reasonable progress 
requirements. Even if we had interpreted Entergy's comments as 
requesting that we adopt the elements in its alternative proposal that 
are unique to White Bluff as an alternative to our proposed BART 
emission limits at the facility without these elements being linked to 
the remaining elements addressing the reasonable progress requirements 
for Independence, we conclude that we would not be able to incorporate 
the Entergy alternative proposal into the final FIP as a way of meeting 
the BART requirement for White Bluff for the reasons already discussed 
above.\96\
---------------------------------------------------------------------------

    \96\ We explain in an earlier part of our response why Entergy's 
alternative proposal does not satisfy the source-specific BART 
requirements of section 308(e)(1) for White Bluff.
---------------------------------------------------------------------------

    Similarly, we also conclude that we cannot consider Entergy's 
proposal to meet the reasonable progress requirements with respect to 
Independence if Independence is considered in isolation. SO2 
emissions are the primary driver of regional haze in Arkansas' Class I 
areas on the 20% worst days and Independence is the second largest 
source of SO2 emissions in Arkansas.\97\ As explained in our 
proposal, our consideration of the four reasonable progress factors and 
consideration of visibility impacts and visibility improvement of 
controls for Independence revealed that dry scrubbers on Independence 
Units 1 and 2 are cost effective. These controls would provide 
significant visibility improvement as projected by our CALPUFF modeling 
focusing on the 98th percentile impacts from the source. We also 
discuss in section V.J. of this final rule and in our RTC document that 
the results of Entergy's CAMx photochemical modeling, which estimates 
the visibility impacts from Independence during the average of the 20% 
worst days, confirm and provide additional support to our determination 
that Independence significantly impacts visibility at Arkansas' Class I 
areas. Since Entergy's alternative proposal includes minimal 
SO2 control for Independence, thus omitting controls that we 
found to be cost effective and that are anticipated to result in 
considerable visibility benefits at Arkansas' Class I areas, we 
conclude that the elements of Entergy's alternative proposal that are 
specific to Independence do not satisfy the reasonable progress 
requirements.
---------------------------------------------------------------------------

    \97\ CENRAP CAMx modeling shows that on most of the 20% worst 
days in 2002, total extinction is dominated by sulfate at both Caney 
Creek and Upper Buffalo. Therefore, SO2 emissions are 
considered the primary driver of haze in Arkansas' Class I areas. 
However, as discussed elsewhere in this final rule and in our RTC 
document, we consider both SO2 and NOX to be 
key visibility impairing pollutants in Arkansas' Class I areas. See 
Arkansas Regional Haze SIP, Appendix 8.1--``Technical Support 
Document for CENRAP Emissions and Air Quality Modeling to Support 
Regional Haze State Implementation Plans,'' sections 3.7.1 and 
3.7.2. See the docket for this rulemaking for a copy of the Arkansas 
Regional Haze SIP.
---------------------------------------------------------------------------

    We recognize that ceasing coal combustion at White Bluff Units 1 
and 2 could result in greater nonair environmental benefits and in more 
emission reductions of mercury and other hazardous air pollutants and 
CO2/CO2e than our proposed FIP. However, in 
assessing Entergy's alternative proposal, we do not find it necessary 
to weigh the nonair quality environmental benefits with the other 
statutory factors since we ultimately find that we cannot accept 
Entergy's alternative proposal because it does not satisfy the 
requirements of the Regional Haze Rule. As discussed earlier in our 
response, we conclude that Entergy's proposal does not satisfy the 
requirements to be considered a better-than-BART alternative under 
sections 308(e)(2) and 308(e)(3); does not satisfy the source-specific 
BART requirements under section 308(e)(1) for White Bluff; does not 
satisfy the reasonable progress requirements under section 308(d)(1); 
and does not provide for the same visibility benefits as the FIP, while 
delaying a majority of the visibility benefits until several years 
later than the FIP. For these reasons, we cannot adopt Entergy's 
alternative approach in lieu of our FIP.
    In response to Entergy's comment regarding the cost to install dry 
FGD and as discussed in more detail in our RTC document, we have 
revised our cost calculations of SO2 controls for White 
Bluff Units 1 and 2 in response to the comments received on our initial 
cost

[[Page 66359]]

analysis.\98\ As we discuss in more detail elsewhere in this final 
rule, based on our consideration of the five BART factors, we have 
determined that controls consistent with dry scrubber and LNB/SOFA 
installation are BART for White Bluff Units 1 and 2. After revising our 
cost estimates, we continue to believe that dry scrubber controls and 
LNB/SOFA controls are cost effective at White Bluff Units 1 and 2 and 
would result in significant visibility improvement at Arkansas' Class I 
areas based on our CALPUFF modeling of the 98th percentile visibility 
impacts from the facility.\99\
---------------------------------------------------------------------------

    \98\ Based on our revised cost analysis, we have found that dry 
scrubbers on White Bluff are estimated to cost $2,565/SO2 
ton removed at Unit 1 and $2,421/SO2 ton removed at Unit 
2.
    \99\ See 80 FR at 18972, 18974. Our FIP proposal provides a 
detailed discussion of the visibility improvement of these controls 
based on our CALPUFF modeling.
---------------------------------------------------------------------------

    As we discuss in more detail elsewhere in this final rule, based on 
our consideration of the four reasonable progress factors and of the 
visibility impacts and visibility improvement of controls on 
Independence, we have determined that dry scrubbers and LNB/SOFA 
controls on Independence Units 1 and 2 are necessary to make reasonable 
progress at Arkansas' Class I areas. We have also revised our cost 
calculations of SO2 controls for these units in response to 
the comments received on our initial cost analysis, and we continue to 
believe that both dry scrubber and LNB/SOFA controls are cost 
effective.\100\ We also find that these controls on Independence would 
provide significant visibility improvement as projected by our CALPUFF 
modeling that focuses on the 98th percentile impacts from the 
facility.\101\ Additionally, the CAMx photochemical modeling submitted 
by Entergy shows that the contribution to visibility impairment due to 
baseline emissions from the Independence facility alone are projected 
to be approximately 1.3% of the total visibility impairment during the 
average 20% worst days in 2018 at each Arkansas Class I area. We 
consider this to be a significant contribution to visibility impairment 
at each Class I area and a large portion (approximately one-third) of 
the total contribution from all Arkansas point sources. The results of 
Entergy's CAMx modeling confirm and provide additional support to our 
determination that Independence significantly impacts visibility at 
Arkansas' Class I areas. While the majority of the visibility impacts 
due to Independence on the 20% worst days are due to SO2, we 
note that NOX emissions from the facility also have impacts 
on the 20% worst days. Entergy's CAMx modeling shows that nitrate from 
Independence is responsible for 30-40% of the visibility impairment in 
Arkansas' Class I areas on 2 of the 20% worst days.\102\ We expect that 
installation of cost-effective NOX controls on Independence 
would provide visibility improvement on this portion of the 20% worst 
days, and as such, are requiring both SO2 and NOX 
controls under the reasonable progress requirements.
---------------------------------------------------------------------------

    \100\ Based on our revised cost analysis, we have found that dry 
scrubbers on Independence are estimated to cost $2,853/
SO2 ton removed at Unit 1 and $2,634/SO2 ton 
removed at Unit 2. After revising our cost estimates, we continue to 
believe that these controls are cost effective.
    \101\ 80 FR 24872.
    \102\ This means 2 out of the 21 days that are the 20% worst of 
the days with IMPROVE monitoring data.
---------------------------------------------------------------------------

    We are requiring White Bluff Units 1 and 2 under BART and 
Independence Units 1 and 2 under reasonable progress to each meet an 
SO2 emission limit of 0.06 lb/MMBtu on a 30 boiler-
operating-day rolling average. We are requiring White Bluff Units 1 and 
2 under BART and Independence Units 1 and 2 under reasonable progress 
to each meet a NOX emission limit of 0.15 lb/MMBtu on a 30 
boiler-operating-day rolling average, where the average is to be 
calculated by including only the hours during which the unit is 
dispatched at 50% or greater of maximum capacity. In addition, we are 
requiring White Bluff Units 1 and 2 under BART and Independence Units 1 
and 2 under reasonable progress to each meet a NOX emission 
limit of 671 lb/hr on a rolling 3-hour average, where the average is to 
be calculated by including emissions only for the hours during which 
the unit was dispatched at less than 50% of the unit's maximum heat 
input rating (i.e., hours when the heat input to the unit is less than 
4,475 MMBtu).
    We do note that if Arkansas submits a regional haze SIP revision to 
replace our FIP, the state has the discretion to consider an approach 
to address the BART requirements for White Bluff that involves ceasing 
coal combustion at Units 1 and 2 by 2027/2028, but an approvable SIP 
revision must also include consideration and evaluation of DSI as a 
possible interim BART control option. With respect to Independence, a 
strategy that includes controls for Independence similar to the 
elements of Entergy's alternative proposal that are specific to White 
Bluff (i.e., interim SO2 controls, ceasing coal combustion 
in the near future, and NOX controls) would also have 
potential merit with respect to addressing the reasonable progress 
requirements for Independence Units 1 and 2. The state may consider 
submitting a SIP revision that includes such a strategy for 
Independence to replace our FIP.
    With regard to the comment that Entergy's alternative multi-unit 
strategy would ensure that Arkansas' Class I areas remain below the URP 
glidepath, we discuss in section V.C. of this final rule and in our RTC 
document that being on or below the URP glidepath does not mean that 
the BART requirements for White Bluff Units 1 and 2 and the reasonable 
progress requirements for Independence Units 1 and 2 are automatically 
satisfied.
    Comment: Several commenters noted that as part of a multi-unit plan 
to improve visibility and to better manage its generation assets for 
reliability and costs, Entergy proposed in comments submitted to EPA to 
cease burning coal at White Bluff Units 1 and 2 by 2027 and 2028, one 
unit per year, and is prepared to take an enforceable commitment to 
that effect. The commenters stated that the CAA and the Regional Haze 
Rule require EPA and states to consider the remaining useful life of a 
source in BART determinations, which factors into the cost of 
compliance in the BART analysis. The commenters argue that as a result 
of Entergy's alternative proposal, EPA's proposed BART determination 
for White Bluff Units 1 and 2 has been rendered inapplicable, requiring 
EPA to undertake a new BART analysis to address the now reduced 
remaining useful coal-fired life of the units. The commenters noted 
that comments submitted by Entergy contain a revised dry FGD cost 
analysis from Sargent & Lundy (S&L) that takes into account current 
costs for dry FGD installation and argue that when the appropriate dry 
scrubber costs from the S&L analysis are considered, operating the dry 
FGD systems at White Bluff for only 6 or 7 years would result in a cost 
effectiveness of over $7,500 to $8,500 per ton at the White Bluff 
units, which is several times higher than EPA estimates and not cost 
effective.
    Response: Entergy's comments propose a multi-unit strategy as an 
alternative to the proposed FIP. As discussed above, we do not 
interpret Entergy's comments submitted during the comment period as 
requesting that we adopt the elements in its alternative that are 
unique to White Bluff as an alternative to our proposed BART emission 
limits for the facility unless we also conclude that the remaining 
elements address any reasonable progress requirements for

[[Page 66360]]

Independence. As we discuss in a previous response, we do not find that 
the comprehensive multi-unit alternative proposal as presented by the 
company satisfies the BART requirements for White Bluff Units 1 and 2 
and the reasonable progress requirements for Independence Units 1 and 
2. A chief element of Entergy's alternative is its proposal to cease 
coal combustion at White Bluff Units 1 and 2. It is unclear whether 
this would mean the shutdown or the repowering of White Bluff Units 1 
and 2. Regardless of this ambiguity, a number of commenters have argued 
that because of Entergy's proposal, we should use a shorter remaining 
life in assessing the costs of controls at White Bluff. If we were to 
assume that Entergy were proposing changes at White Bluff regardless of 
our action regarding Independence, we could include in our final FIP an 
enforceable requirement for the shutdown (or repowering) and take that 
change into consideration as part of a BART determination. The BART 
Guidelines state that where unit shutdown affects the BART 
determination, the shutdown date should be assured by a federally or 
state-enforceable restriction preventing further operation.\103\ 
Although we could include such a requirement in our FIP, the comments 
we received from Entergy during the public comment period do not 
indicate that it intends to cease coal combustion at White Bluff Units 
1 and 2 at this time absent a broader agreement on appropriate controls 
for both White Bluff and Independence. As such, we do not consider it 
appropriate to include a requirement in our FIP to cease coal 
combustion at White Bluff Units 1 and 2 in our rule unless we were to 
also accept the Entergy proposal as meeting all requirements with 
respect to Independence.\104\ Therefore, we consider it appropriate to 
assume a remaining useful life of 30 years for White Bluff Units 1 and 
2 when determining BART for these units. We address specific comments 
regarding the White Bluff cost analysis in the section of this final 
rule where we discuss cost issues.
---------------------------------------------------------------------------

    \103\ See Appendix Y to 40 CFR part 51--Guidelines for BART 
Determinations Under the Regional Haze Rule, section IV.D.4.k.
    \104\ Additionally, as discussed above, Entergy did not submit 
sufficient information to demonstrate that there are no additional 
SO2 control measures, such as DSI, that constitute BART 
even in light of a limited remaining useful life for White Bluff.
---------------------------------------------------------------------------

C. Reasonable Progress Goals and Reasonable Progress Analysis

    Comment: Several commenters stated that EPA lacks evidence of a 
sufficient need to evaluate additional controls under reasonable 
progress for Arkansas point sources. These commenters argued that 
before evaluating controls under reasonable progress, EPA must first 
determine that further actions are necessary in Arkansas beyond BART to 
ensure that visibility improvement is continuing on or below the glide 
path for each affected Class I area. These commenters cited to the CAA 
and EPA guidance which they believe support their position that 
reductions beyond BART should not be required because the impacted 
Class I areas are at or below their glide paths. The commenters also 
pointed to ADEQ's ``State Implementation Plan Review for the Five-Year 
Regional Haze Progress Report'' \105\ as evidence that Caney Creek and 
Upper Buffalo will be below the glide path in 2018. They claimed that 
EPA ignores ADEQ's Five-Year Progress SIP revision, which they argued 
demonstrates that Arkansas has achieved 73% of the 2018 RPG it 
established for Caney Creek (3.88 dv of improvement) and 66% of the 
2018 RPG it established for Upper Buffalo (3.75 dv of improvement). The 
commenters argued that as a result of emission reductions achieved 
through regional and national programs, including MATS, CAIR, and 
CSAPR, future Clean Air Act programs such as implementation of the 1-
hour SO2 NAAQS, the revised ozone NAAQS and the Clean Power 
Plan, as well as the reductions for White Bluff and Independence that 
Entergy is proposing and the BART controls that EPA has proposed for 
the other sources in Arkansas, there is every reason to project 
continued improvement in visibility in Caney Creek and Upper Buffalo 
well beyond 2018.
---------------------------------------------------------------------------

    \105\ Available at http://www.adeq.state.ar.us/air/planning/pdfs/ar_5yr_prog_rep_review-final-6-2-2015.pdf.
---------------------------------------------------------------------------

    Response: EPA disagrees with the comment that we can only evaluate 
controls under reasonable progress if further controls beyond BART are 
needed to be on or below the URP glidepath for a Class I area. 
Specifically, commenters cited section 169A(b)(2) of the Act, which 
requires regional haze regulations to ``contain such emission limits, 
schedules of compliance and other measures as may be necessary to make 
reasonable progress toward meeting the national goal.'' These 
commenters interpret the term ``reasonable progress'' to be defined as 
being on or below the URP glidepath, and that as long as a Class I area 
is on or below the URP glidepath, additional controls are not necessary 
under the reasonable progress requirements. This interpretation is 
incorrect and does not take into account other, more explicit, 
statutory and regulatory language. The CAA requires reasonable progress 
determinations to be based on consideration of ``the costs of 
compliance, the time necessary for compliance, the energy and nonair 
quality environmental impacts of compliance, and the remaining useful 
life of any existing source subject to such requirements.'' CAA section 
169A(g)(1). The regional haze regulations under 40 CFR 
51.308(d)(1)(i)(A) also require consideration of these four statutory 
factors in establishing the RPGs and a demonstration showing how these 
factors were taken into account.
    We commonly refer to the evaluation of these four statutory factors 
as the ``four-factor analysis'' or ``reasonable progress analysis.'' 
The statute and regulations are both clear that the states or EPA in a 
FIP have the authority and obligation to evaluate the four reasonable 
progress factors and that the decision regarding the controls required 
to make reasonable progress and the establishment of the RPG must be 
based on these factors identified in the CAA section 169A(g)(1) and the 
Regional Haze regulations under Sec.  51.308(d)(1)(i)(A). While the 
regulations require that a state must also consider the URP glidepath 
in establishing the RPGs, this should not be interpreted to mean that 
the URP can or should be automatically adopted as the RPG without 
completing the requisite analysis of the four statutory factors. It 
also should not be interpreted to mean that a set of controls 
sufficient to achieve the URP is automatically sufficient for an 
approvable long-term strategy. Clearly, a state's obligation to set 
reasonable progress goals based on CAA section 169A(g)(1) and Sec.  
51.308(d)(1) applies in all cases, without regard to the Class I area's 
position on the URP. Since an evaluation of the factors is required 
regardless of the Class I area's position on the glidepath, this 
necessarily means that the CAA and the Regional Haze regulations 
envisioned that controls could be required under reasonable progress 
even when a Class I area is on or below the URP glidepath. There is 
nothing in the CAA or Regional Haze regulations that suggests that a 
State's obligation, or EPA's in a FIP, to ensure reasonable progress 
can be met by just meeting the URP.\106\
---------------------------------------------------------------------------

    \106\ 77 FR 14604, 14629.
---------------------------------------------------------------------------

    Some commenters also argue that the EPA's 2007 Reasonable Progress

[[Page 66361]]

Guidance suggests that controls under reasonable progress are not 
necessary if a Class I area is on or below the URP glidepath. The 
specific part of the Reasonable Progress Guidance that some of the 
---------------------------------------------------------------------------
commenters point to states that:

    Given the significant emissions reductions that we anticipate to 
result from BART, the CAIR, and the implementation of other CAA 
programs, including the ozone and PM2.5 NAAQS, for many 
States [determining the amount of emission reductions that can be 
expected from identified sources or source categories as a result of 
requirements at the local, State, and federal levels during the 
planning period of the SIP and the resulting improvements in 
visibility at Class I areas] will be an important step in 
determining your RPG, and it may be all that is necessary to achieve 
reasonable progress in the first planning period for some 
States.\107\
---------------------------------------------------------------------------

    \107\ ``Guidance for Setting Reasonable Progress Goals Under the 
Regional Haze Program,'' at 4-1.

    We see nothing in the Reasonable Progress Guidance indicating that 
additional controls can only be required if further action beyond BART 
is needed to remain on or below the URP glidepath. Nor do we see 
anything in the Reasonable Progress Guidance indicating that a state 
(or EPA) is exempt from completing the four factor analysis if a Class 
I area is on or below the URP glidepath. As discussed above, the CAA 
and Regional Haze regulations are clear that an evaluation of the four 
statutory factors is required, and this requirement applies regardless 
of the Class I area's position on the glidepath. We noted in our FIP 
proposal that the preamble to the Regional Haze Rule states that the 
URP does not establish a ``safe harbor'' for the state in setting its 
---------------------------------------------------------------------------
progress goals:

    If the State determines that the amount of progress identified 
through the [URP] analysis is reasonable based upon the statutory 
factors, the State should identify this amount of progress as its 
reasonable progress goal for the first long-term strategy, unless it 
determines that additional progress beyond this amount is also 
reasonable. If the State determines that additional progress is 
reasonable based on the statutory factors, the State should adopt 
that amount of progress as its goal for the first long-term 
strategy.\108\
---------------------------------------------------------------------------

    \108\ 80 FR at 18992.

    Being projected to meet the URP for 2018 does not justify 
dismissing the analysis required under CAA section 169A(g)(1) and Sec.  
51.308(d)(1) in determining reasonable progress and establishing the 
RPGs, nor does it automatically mean that no additional controls beyond 
BART are required under reasonable progress. The URP is an analytical 
requirement created by regulation to ensure that states consider the 
possibility of setting an ambitious reasonable progress goal. Its 
purpose is to complement, not usurp, the reasonable progress analysis. 
Based on the analysis of the four statutory factors required under the 
CAA and Regional Haze regulations, a state (or EPA in a FIP) may 
determine that a greater or lesser amount of visibility improvement 
than what is reflected in the URP is necessary to demonstrate 
reasonable progress.\109\ Based on our analysis of the factors under 
CAA section 169A(g)(1) and Sec.  51.308(d)(1), along with consideration 
of the visibility improvement of controls, we determined that there are 
reasonable controls available for Independence that would be cost-
effective and would result in meaningful visibility benefit at 
Arkansas' Class I areas. Because we have identified that additional 
progress (beyond the amount reflected in the URP) is reasonable based 
on the statutory factors and our consideration of the visibility 
impacts, we are required to adopt that amount of progress under the 
reasonable progress requirements. It is for this reason, we are 
requiring controls on Independence. It is not, as some commenters 
contend, ``for the sole purpose of achieving emissions reductions.''
---------------------------------------------------------------------------

    \109\ 64 FR 35714, 35732.
---------------------------------------------------------------------------

    We note that our conclusion here is consistent with our final 
action on the Arkansas Regional Haze SIP, where we disapproved 
Arkansas' RPGs specifically because the state established its RPGs 
without conducting an evaluation of the four statutory factors and did 
so based on the fact that its Class I areas are below the URP 
glidepath. In the preamble to our final action on the Arkansas Regional 
Haze SIP, we were clear that an evaluation of the four statutory 
factors is required regardless of the Class I area's position on the 
URP glidepath:

    [B]eing on the ``glidepath'' does not mean a state is allowed to 
forego an evaluation of the four statutory factors when establishing 
its RPGs. Based on an evaluation of the four statutory factors, 
states may determine that RPGs that provide for a greater rate of 
visibility improvement than would be achieved with the URP for the 
first implementation period are reasonable.\110\
---------------------------------------------------------------------------

    \110\ 77 FR at 14629.

    Our final action on the Arkansas Regional Haze SIP was published in 
the Federal Register on March 12, 2012, and became effective on April 
11, 2012. We reiterate in this final action that the CAA and Regional 
Haze regulations require an analysis of the four reasonable progress 
factors regardless of a Class I area's position on the URP and that 
being below the glide path does not automatically mean that no controls 
are necessary under reasonable progress.
    With regard to the comment contending that we are ignoring data 
from ADEQ's Five-Year Progress Report SIP revision, we note that 
Arkansas submitted the first 5-year report to EPA in June 2015, and 
that we are not addressing that SIP revision within this action.\111\ 
The 5-year progress report is a separate requirement from the regional 
haze SIP required for the first and subsequent planning periods, and it 
has separate content and criteria for review. We are therefore not 
obligated to consider or take action on the 5-year progress report at 
the same time we promulgate our FIP.
---------------------------------------------------------------------------

    \111\ We anticipate taking action on ADEQ's Five Year Progress 
Report SIP revision in a separate, future action.
---------------------------------------------------------------------------

    We acknowledge that recent IMPROVE monitoring data indicate there 
has been visibility improvement in Arkansas' Class I areas. But even 
assuming that the current trend in visibility improvement will 
continue, as the commenter argues, this does not divest us from our 
authority and obligation to conduct a reasonable progress analysis, nor 
does it justify the dismissal of controls for Independence that we have 
determined, pursuant to that analysis, are cost-effective and would 
result in meaningful visibility benefit at Arkansas' Class I areas. The 
commenters point out that even without the BART and reasonable progress 
controls required by our FIP, Caney Creek has achieved 73% and Upper 
Buffalo has achieved 66% of their respective 2018 RPGs established by 
Arkansas based on 5-year average data from IMPROVE monitors as of 2011. 
However, even if we had approved these RPGs (which we did not), 
achieving or being projected to achieve the RPG does not necessarily 
demonstrate that a state has satisfied its requirements under BART and 
reasonable progress. The state or EPA must complete the requisite 
analyses to determine appropriate controls and emission limits under 
the BART and reasonable progress requirements, and must adopt and 
enforce these controls and emission limits. The numeric RPGs are 
calculated by taking into account the visibility improvement 
anticipated from these enforceable emission limitations and other 
control measures (including BART, reasonable progress, and other ``on 
the books'' controls). The Regional Haze Rule provides that these 
emission limitations and control measures are what is enforceable, not 
the RPGs

[[Page 66362]]

themselves.\112\ Thus, the RPGs are intended to provide a degree of 
transparency regarding the rate of improvement in visibility 
anticipated for each Class I area over the planning period of the 
SIP.\113\
---------------------------------------------------------------------------

    \112\ 64 FR 35714, 35733.
    \113\ The RPGs are intended to provide the state or EPA's best 
estimate of the amount of visibility improvement in deciviews 
anticipated for each Class I area over the planning period of the 
SIP or FIP.
---------------------------------------------------------------------------

    As noted above, we disapproved Arkansas' RPGs in our March 12, 2012 
final action on the Arkansas Regional Haze SIP \114\ because the state 
did not complete the required four-factor analysis in establishing the 
RPGs. Further, the state's RPGs were based on BART determinations that 
were not in accordance with the CAA and Regional Haze regulations. As 
such, the State's RPGs are not a reflection of the controls necessary 
to make reasonable progress, and any arguments upholding or suggesting 
that the state's RPGs are appropriate or adequate are outside the scope 
of this action. That Arkansas' Class I areas are on track to achieve 
the disapproved RPGs by 2018 does not mean that the reasonable progress 
requirements have been satisfied, nor does it justify no additional 
controls under reasonable progress.
---------------------------------------------------------------------------

    \114\ 77 FR 14604.
---------------------------------------------------------------------------

    Comment: Some commenters argued that our FIP proposal was improper 
because it adopted an individual source-based approach to setting RPGs, 
and that this is inconsistent with the CAA. Another commenter claimed 
that EPA failed to explain how factors required to be considered in 
setting the RPGs, which are themselves not enforceable, could somehow 
be used to require specific enforceable limits for a single plant.
    Response: While our FIP does consider and ultimately apply controls 
on an individual source basis to assure reasonable progress, this is 
consistent with the CAA, our regulations, and past EPA guidance. The 
four statutory factors under CAA Section 169A(g) and 40 CFR 
51.308(d)(1)(i)(A) are directed to the listed possible features or 
consequences of potential emission control measures for sources, 
including individual stationary sources. The CAA and the Regional Haze 
regulations expressly set forth that the reasonable progress analysis 
must consider the ``compliance'' time and costs for ``potentially 
affected sources.'' A state determines the rate of progress that is 
reasonable for a Class I area after taking into account the four 
statutory factors-- as applied to specific sources or groups of 
sources--to determine what additional controls should be required in 
its regional haze SIP. Thus, individual stationary sources may be 
subject to emission limits and source specific analysis when 
determining whether additional controls are necessary to make 
reasonable progress.
    The commenter's suggestion that because the RPGs are not themselves 
enforceable we cannot require specific enforceable limits for a single 
plant is not consistent with the requirement that each regional haze 
SIP or FIP include enforceable emissions limitations as necessary to 
ensure that the SIP or FIP will provide reasonable progress toward the 
national goal of natural visibility conditions. The numeric RPGs 
established by the state or EPA represent the best estimate of the 
degree of visibility improvement that will result in 2018 from changes 
in emissions inventories, changes driven by the particular set of 
control measures the state has adopted in its regional haze SIP or EPA 
in a regional haze FIP to address visibility, as well as all other 
enforceable measures expected to reduce emissions over the period of 
the SIP from 2002 to 2018.\115\ Thus, the RPGs are intended to provide 
a degree of transparency regarding the rate of improvement in 
visibility anticipated for each Class I area over the planning period 
of the SIP. But the RPGs themselves are not enforceable.\116\ EPA 
cannot enforce an RPG in the sense of seeking to apply penalties on a 
state for failing to meet the RPG or obtaining injunctive relief to 
require a state to achieve its RPG. However, the long-term strategy can 
and must contain emission limits and other control measures that apply 
to specific sources under the reasonable progress requirements, and 
that are themselves enforceable. The fact that the RPGs are not 
enforceable does not mean that we cannot conduct a source-specific 
evaluation of the reasonable progress factors or require source-
specific emission limits under the reasonable progress requirements.
---------------------------------------------------------------------------

    \115\ 64 FR at 35733.
    \116\ See 51.308(d)(1)(v).
---------------------------------------------------------------------------

    Comment: EPA treated Independence Units 1 and 2 as if they were 
subject-to-BART units by ignoring whether controls at the units are 
needed to improve visibility and looking only at whether controls are 
cost effective. EPA's failure to assess and document the contribution 
to visibility impairment at any relevant Class I area from any Arkansas 
point source, including Independence, is contrary to past rulemakings 
and is inconsistent with the detailed approach taken by EPA Region 6 in 
its promulgation of the Texas Regional Haze FIP. The Independence plant 
was apparently singled out by EPA for additional pollution controls 
under reasonable progress, while other non-BART emission sources were 
not. EPA does not provide any explanation for its selective treatment 
in this case other than noting that the Independence is among the top 
three largest point sources in the state. EPA's justification for 
imposing SO2 and NOX emission limits on 
Independence is not based on rational policy, legal, or environmental 
grounds and, as a result, it is arbitrary and capricious. EPA's primary 
justification for proposing reasonable progress limits at Independence 
is that ``it would be unreasonable to ignore a source representing more 
than a third of the State's SO2 emissions and a significant 
portion of NOX point source emissions.'' EPA further 
supports its conclusion that emission limits based on the installation 
of major control technology are justified based on a finding that the 
proposed controls at Independence are cost effective. However, the fact 
that a source, which is not subject to BART, may have significant 
SO2 or NOX emissions, or that it would be cost 
effective to control such emissions, is irrelevant for reasonable 
progress purposes. This is an inapplicable and inadequate justification 
to identify sources for control under a reasonable progress analysis. 
EPA did not appropriately analyze which sources, if any, should be 
controlled for reasonable progress and did not follow the procedures it 
has regularly used in other regional haze FIPs.
    Response: We did not treat Independence as if it were a subject-to-
BART source, nor did we ignore whether controls at the facility are 
needed to improve visibility, or only look at whether controls are cost 
effective. Under the CAA and 40 CFR 51.308(d)(1), we must consider the 
following four factors in our reasonable progress analysis: (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 potentially affected sources. These 
are the factors we took into consideration in our proposal. As we 
discuss in our proposal and elsewhere in this final rule, although 
visibility is not one of the four mandatory factors explicitly listed 
for consideration under CAA section 169A(g)(1) or 40 CFR 
51.308(d)(1)(i)(A), states or EPA have the option of considering the 
projected visibility

[[Page 66363]]

benefits of controls in determining if the controls are necessary to 
make reasonable progress. We modeled both the baseline visibility 
impacts from the Independence facility and the visibility benefit of 
controls using CALPUFF dispersion modeling. Based on our consideration 
of the four reasonable progress factors as well as the baseline 
visibility impacts from Independence and the visibility improvement of 
potential controls, we determined that reasonable controls for 
SO2 and NOX are available for Independence Units 
1 and 2 that are cost effective and would result in a large amount of 
visibility improvement in Arkansas' Class I areas in terms of the 98th 
percentile impacts from the source.\117\ Therefore, the claim that we 
ignored whether controls at the units are needed to improve visibility 
is incorrect.
---------------------------------------------------------------------------

    \117\ CAMx source apportionment modeling was submitted to us by 
Entergy Arkansas Inc. during the comment period. This modeling shows 
that Independence has significant visibility impacts in Arkansas 
Class I areas on the 20% worst days, and further supports our 
decision to require controls for Independence under reasonable 
progress. We discuss Entergy Arkansas Inc.'s photochemical modeling 
and the visibility impacts due to SO2 and NOX 
from Independence on the 20% worst days elsewhere in this final 
rule.
---------------------------------------------------------------------------

    We also disagree that the fact that a non-BART source has 
significant SO2 or NOX emissions, or that it 
would be cost-effective to control such emissions, is irrelevant in 
determining what sources to take a closer look at and evaluate under 
reasonable progress. As noted above, the cost of compliance is one of 
the statutory factors that EPA is required to consider in a reasonable 
progress analysis, meaning that the cost effectiveness of potential 
controls is not irrelevant for reasonable progress purposes. 
Significant SO2 or NOX emissions from a source is 
generally an indication that there may be significant visibility 
impacts at nearby Class I areas and that installation of more effective 
controls, if any are available, may result in substantial emissions 
reductions and meaningful visibility improvement. As noted above, 
states and EPA have the option of considering the projected visibility 
benefits of controls in determining if the controls are necessary to 
make reasonable progress. Therefore, we find that consideration of a 
source's emissions and whether it would be cost-effective to control 
such emissions is appropriate and relevant for reasonable progress 
purposes.
    The commenter makes the incorrect claim that our primary 
justification for imposing emission limits under reasonable progress 
for Independence Units 1 and 2 is that it would be unreasonable to 
ignore a source representing more than a third of the state's 
SO2 emissions and a significant portion of NOX 
point source emissions. While we did state in our FIP proposal that it 
would be unreasonable to ignore a source representing more than a third 
of the state's SO2 emissions and a significant portion of 
NOX point source emissions, the commenters took this 
statement out of context. The full citation from our FIP proposal 
referenced by the commenters is the following:

    We believe it is appropriate to evaluate Entergy Independence 
even though Arkansas Class I areas and those outside of Arkansas 
most significantly impacted by Arkansas sources are projected to 
meet the URP for the first planning period. This is because we 
believe that in determining whether reasonable progress is being 
achieved, it would be unreasonable to ignore a source representing 
more than a third of the State's SO2 emissions and a 
significant portion of NOX point source emissions.\118\
---------------------------------------------------------------------------

    \118\ 80 FR at 18992.

    As evidenced by the full citation from our FIP proposal, the fact 
that we considered it unreasonable to ignore a source representing more 
than a third of the State's SO2 emissions and a significant 
portion of NOX point source emissions was our primary 
justification for looking more closely and evaluating the Independence 
plant in our reasonable progress analysis. It was not, as the commenter 
contends, our justification for imposing controls on Independence. As 
we discuss in our FIP proposal and elsewhere in this final action, our 
decision to require controls on Independence is based on our analysis 
under Sec.  51.308(d)(1), as required by the CAA and Regional Haze 
Rule.
    We do not agree with the commenter's allegation that we did not 
appropriately analyze what sources, if any, should be controlled under 
reasonable progress. To the extent that the commenter contends that our 
process for determining which sources should be evaluated under 
reasonable progress was incorrect because we did not conduct 
photochemical modeling, such argument is incorrect. To the extent that 
the commenter contends that we treated the Independence facility like a 
BART source because we evaluated it under the reasonable progress 
requirements without conducting photochemical modeling to identify 
potential sources to evaluate under reasonable progress, this is also 
incorrect. We are not required to conduct photochemical modeling in a 
reasonable progress analysis. Our 2007 Reasonable Progress Guidance 
states that ``The RHR gives States wide latitude to determine 
additional control requirements, and there are many ways to approach 
identifying additional reasonable measures; however, you must at a 
minimum, consider the four statutory factors.'' \119\ The states or EPA 
in the context of a FIP have wide discretion in deciding what 
approaches, methods, and tools to use in identifying source categories, 
specific point sources, or pollutants to evaluate for additional 
controls under the reasonable progress requirements, provided that a 
reasonable rationale for the approach used is provided. There are a 
number of different approaches states or EPA in the context of a FIP 
have used in identifying sources for reasonable progress evaluation, 
but they usually center around the general premise of evaluating the 
biggest sources and/or the biggest impactors on visibility. While the 
states or EPA have the discretion to consider visibility in a 
reasonable progress analysis, photochemical modeling is not required 
for purposes of conducting a reasonable progress analysis.
---------------------------------------------------------------------------

    \119\ ``Guidance for Setting Reasonable Progress Goals Under the 
Regional Haze Program,'' at 4-2.
---------------------------------------------------------------------------

    Our FIP proposal provided a detailed explanation of how we 
determined what sources to evaluate for controls under reasonable 
progress, and we provided a reasonable rationale for the approach we 
used. The first step in our analysis involved determining what source 
categories or specific point sources it would be appropriate to look at 
more closely and evaluate under the reasonable progress requirements in 
Sec.  51.308(d)(1) to determine if additional controls are necessary. 
We explained in our proposal that it was appropriate to focus our 
analysis on point sources since the other source categories (i.e., 
natural, on-road, non-road, and area) each contribute a much smaller 
proportion of the total light extinction at each Class I area in 
Arkansas based on the CENRAP CAMx modeling.\120\ At Caney Creek, point 
sources contribute 81.04 Mm-1 out of a total light 
extinction of 133.93 Mm-1 on the average across the 20% 
worst days in 2002, or approximately 60.5% of the total light 
extinction. At Upper Buffalo, point sources contribute 77.80 
Mm-1 out of a total light extinction of 131.79 
Mm-1 on the average across the 20% worst days in 2002, or 
approximately 59% of the total light extinction. In comparison, area 
sources, which are the source category with the next highest 
contribution to the total light extinction at each Class I area, 
contribute approximately 13.3% of the total light

[[Page 66364]]

extinction at Caney Creek and 15.5% at Upper Buffalo. The remaining 
source categories each contribute less than 6% of the total light 
extinction at each Class I area. Therefore, we concluded that it was 
appropriate to focus our analysis on point sources.
---------------------------------------------------------------------------

    \120\ See 80 FR 18944, 18989.
---------------------------------------------------------------------------

    The CENRAP CAMx modeling shows that on most of the 20% worst days 
in 2002, total extinction was dominated by sulfate at both Caney Creek 
and Upper Buffalo.\121\ Additionally, total extinction at Caney Creek 
was dominated by nitrate on 4 of the days that comprise the 20% worst 
days in 2002 and a significant portion of the total extinction at Upper 
Buffalo on 2 of the days that comprise the 20% worst days in 2002 was 
due to nitrate.\122\ The CENRAP CAMx modeling also shows that sulfate 
from point sources was responsible for approximately 54.8% of the total 
visibility impairment at Upper Buffalo and 56.1% at Caney Creek on the 
20% worst days in 2002. Nitrate from point sources was responsible for 
approximately 3% of the total visibility impairment at each Class I 
area on the 20% worst days in 2002. As such, although SO2 
emissions are the primary contributor to regional haze in Arkansas' 
Class I areas on the 20% worst days, NOX emissions are also 
a key contributor. Thus, consistent with our Guidance for Setting 
Reasonable Progress Goals Under the Regional Haze Program,\123\ we 
found it appropriate to evaluate both SO2 and NOX 
controls under reasonable progress.
---------------------------------------------------------------------------

    \121\ See Arkansas Regional Haze SIP, Appendix 8.1--``Technical 
Support Document for CENRAP Emissions and Air Quality Modeling to 
Support Regional Haze State Implementation Plans,'' sections 3.7.1 
and 3.7.2. See the docket for this rulemaking for a copy of the 
Arkansas Regional Haze SIP.
    \122\ See Arkansas Regional Haze SIP, Appendix 8.1--``Technical 
Support Document for CENRAP Emissions and Air Quality Modeling to 
Support Regional Haze State Implementation Plans,'' section 3.7.1 
and 3.7.2. See the docket for this rulemaking for a copy of the 
Arkansas Regional Haze SIP.
    \123\ ``Guidance for Setting Reasonable Progress Goals Under the 
Regional Haze Program,'' at 2-3 and 3-1.
---------------------------------------------------------------------------

    We explained in our FIP proposal that as a starting point in our 
analysis to determine whether additional controls on Arkansas point 
sources are reasonable in the first regional haze planning period, we 
examined the most recent SO2 and NOX emissions 
inventories for point sources in Arkansas (NEI 2011 v1).\124\ We 
reasoned that examination of the emissions inventories is appropriate 
because significant SO2 or NOX emissions from a 
source are generally an indication that it may be having significant 
visibility impacts at nearby Class I areas and that installation of 
controls may result in substantial emissions reductions and meaningful 
visibility improvement. We did not conduct photochemical modeling or 
other more exhaustive analyses to identify potential candidates to 
evaluate under reasonable progress, and while we recognize that this 
approach is different from the approaches and methods that we have used 
or approved in other regional haze actions, we find that the approach 
we are taking in this action is appropriate given the specific 
circumstances. In particular, our examination of the SO2 and 
NOX emissions inventories for Arkansas' point sources 
revealed that the number of point sources that emit SO2 and 
NOX emissions is relatively small. Furthermore, a very small 
portion of the point sources in the state is responsible for a large 
portion of the statewide SO2 and NOX point source 
emissions. Specifically, White Bluff, Independence, and Flint Creek are 
collectively responsible for approximately 84% of the SO2 
point source emissions and 55% of the NOX point source 
emissions in the state. Consequently, addressing these sources under 
the regional haze program will address a large proportion of the 
visibility impacts due to Arkansas point sources. We are requiring 
SO2 and NOX controls for White Bluff and Flint 
Creek under the BART requirements in this final action, which will 
substantially reduce emissions from these two facilities. The 
Independence Plant, which is not a subject-to-BART source, contributes 
approximately 36.2% of the total SO2 point source emissions 
in the state (30,398 SO2 tons out of total SO2 
point source emissions of 83,883 SO2 tons, based on the 2011 
NEI).\125\ This source also contributes approximately 21.3% of the 
total NOX point source emission in the state (13,411 
NOX tons out of total NOX point source emissions 
of 62,984 NOX tons). Based on this examination, we 
determined that the magnitude of emissions from the Independence Plant 
warranted further evaluation of the source to determine if it is a 
significant contributor to regional haze in Arkansas' Class I areas and 
whether controls at the facility are needed based on an analysis under 
Sec.  51.308(d)(1).
---------------------------------------------------------------------------

    \124\ 80 FR at 18991.
    \125\ See NEI 2011 v1. A spreadsheet containing the emissions 
inventory is found in the docket for our proposed rulemaking.
---------------------------------------------------------------------------

    After White Bluff, Independence, and Flint Creek, the remaining 
point sources in the state have much lower SO2 and 
NOX emissions than these facilities. In other words, the 
magnitude of SO2 and NOX emissions from point 
sources in Arkansas drops off considerably after the top 3 emitters. We 
stated the following in our proposal:

    The fourth largest SO2 and NOX point 
sources in Arkansas are the Future Fuel Chemical Company, with 
emissions of 3,421 SO2 tpy, and the Natural Gas Pipeline 
Company of America #308, with emissions of 3,194 NOX tpy 
(2011 NEI). In comparison to the emissions of the top three sources, 
emissions from these two facilities are relatively small. Therefore, 
we are not proposing controls in this first planning period for 
these two facilities because we believe it is appropriate to defer 
the consideration of any additional sources besides Independence to 
future regional haze planning periods.\126\
---------------------------------------------------------------------------

    \126\ 80 FR at 18992.

    Future Fuel Chemical Company, the point source with the fourth 
highest SO2 emissions (after White Buff, Independence, and 
Flint Creek), contributes approximately 4.1% of the total 
SO2 point source emissions in the state (3,420 
SO2 tons out of total SO2 point source emissions 
of 83,883 SO2 tons, based on the 2011 NEI). The Natural Gas 
Pipeline Company of America #308, the point source with the fourth 
highest NOX emissions, contributes approximately 5.1% of the 
total NOX point source emission in the state 3,194 
NOX tons out of total NOX point source emissions 
of 62,984 NOX tons, based on the 2011 NEI). Based on the 
much smaller magnitude of these sources' emissions, we determined that 
the remaining point sources in the state are less likely to be 
significant contributors to regional haze, and thus did not warrant 
closer evaluation under reasonable progress in this planning period. As 
such, we found that it is appropriate to evaluate Independence for 
controls under reasonable progress. The claim that we arbitrarily 
singled out Independence and that we provided no explanation as to why 
we did not evaluate other point sources under reasonable progress is 
not supported by the record in this action.
    Because our examination of the Arkansas emissions inventory 
revealed that the number of point sources that emit SO2 and 
NOX emissions is relatively small and that a very small 
portion of the point sources in the state are responsible for a large 
portion of the statewide SO2 and NOX point source 
emissions, we concluded that photochemical modeling or other more 
exhaustive analyses that we have performed in other regional haze 
actions were unnecessary to identify point sources to evaluate under 
reasonable progress. In contrast, in states such as Texas, where the 
universe of point

[[Page 66365]]

sources is much larger and the distribution of SO2 and 
NOX emissions is very widespread, an evaluation of the 
state's emissions inventory alone was not sufficient to reveal the best 
potential candidates for evaluation under reasonable progress. For this 
reason, we explained in our Texas Regional Haze FIP that due to the 
challenges presented by the geographic distribution and number of 
sources in Texas, the CAMx photochemical model was best suited for 
identifying sources to evaluate for reasonable progress controls.\127\ 
We did not encounter these challenges in the development of our 
reasonable progress analysis for Arkansas and therefore did not conduct 
photochemical modeling.
---------------------------------------------------------------------------

    \127\ 81 FR 296.
---------------------------------------------------------------------------

    We do note that while we did not conduct photochemical modeling to 
identify Arkansas point sources to evaluate under reasonable progress, 
Entergy conducted CAMx source-apportionment modeling and submitted it 
during the comment period. Entergy's CAMx source apportionment modeling 
showed that emissions from the Independence facility alone are 
projected to contribute approximately 1.3% of the total visibility 
impairment in 2018 on the 20% worst days at each Arkansas Class I area. 
This is a large portion (approximately one-third) of the total 
contribution from all Arkansas point sources, and we consider it to be 
a significant contribution to visibility impairment Arkansas' Class I 
areas on the 20% worst days. The CAMx modeling also showed that at 
Upper Buffalo, the Independence facility's contribution to visibility 
impairment is greater than the contribution from all of the subject-to-
BART sources addressed in this final action combined. In terms of 
deciviews, the average impact from Independence over the 20% worst 
days, based on Entergy's CAMx modeling and adjusted to natural 
background conditions, is over 0.5 dv at the Arkansas Class I areas. 
The results of Entergy's CAMx modeling confirm and provide additional 
support to our determination that Independence significantly impacts 
visibility at Arkansas' Class I areas.
    Additionally, we note that because of the controls required during 
this planning period, we expect that the impact from the facilities in 
Arkansas that were not controlled and not specifically evaluated in the 
first planning period will become larger on a percentage basis. These 
sources will become the largest impacting sources and should be 
considered for analysis under reasonable progress in future planning 
periods. The methodology we used here thus allows a consistent 
procedure to identify facilities for additional control analysis in 
this and future planning periods and ensures continuing progress 
towards the goal of natural visibility conditions.
    To the extent the commenter contends that additional controls under 
reasonable progress cannot or should not be evaluated or required 
unless controls beyond BART are needed for Arkansas to be on or below 
the URP glidepath or to meet the RPGs established by the state (which, 
in the case of Arkansas, we disapproved in a previous final action), 
this is incorrect. As we discuss elsewhere in this section of the final 
rule and in our RTC document, there is nothing in the CAA or Regional 
Haze regulations that suggests that a State's obligations to ensure 
reasonable progress can be met simply by being on or below the URP 
glidepath or meeting the state's RPGs.\128\
---------------------------------------------------------------------------

    \128\ See 77 FR at 14629.
---------------------------------------------------------------------------

    Comment: EPA's own analysis counsels against imposing additional 
controls on the Independence Plant. EPA asserts that CENRAP modeling 
shows that sulfate from all point sources is projected to contribute to 
57% of the total light extinction at Caney Creek on the worst 20% days 
in 2018 and 43% of the total light extinction at Upper Buffalo. Nitrate 
from all point sources is projected to account for only 3% of the total 
light extinction at the Class I areas. However, the CENRAP modeling 
also projects that sulfate from Arkansas point sources will be 
responsible for only 3.58% of the total light extinction at Caney Creek 
and 3.20% at Upper Buffalo. The contribution of nitrate from Arkansas 
point sources to visibility impairment is even more insignificant, 
accounting for only 0.29% of the total light extinction at Caney Creek 
and 0.25% at Upper Buffalo. The Independence Plant's share of emissions 
to this minimal contribution from Arkansas point sources is even 
smaller. Despite these very small contributions, EPA's proposal 
concludes that SO2 and NOX controls at the 
Independence Plant are warranted and reasonable. EPA lacks evidence of 
a sufficient need to evaluate additional controls for Arkansas point 
sources and lacks a sufficient basis to justify additional controls.
    Response: The commenter appears to believe that the CENRAP modeling 
shows that the visibility impacts on the 20% worst days from Arkansas 
point sources, and from Independence in particular, are very small. We 
disagree that these visibility impacts are insignificant. As we discuss 
above, Entergy's CAMx source apportionment modeling showed that the 
contribution to visibility impairment due to emissions from the 
Independence facility alone are projected to be approximately 1.3% of 
the total visibility impairment during the 20% worst days in 2018 at 
each Arkansas Class I area. This is a large portion (approximately one-
third) of the total contribution from all Arkansas point sources, and 
we consider this to be a significant contribution to visibility 
impairment. Entergy's CAMx modeling also showed that at Upper Buffalo, 
the Independence facility's contribution to visibility impairment is 
greater than the contribution from all of the subject-to-BART sources 
addressed in this final action combined. In terms of deciviews, the 
average impact from Independence over the 20% worst days, based on 
Entergy's CAMx modeling and adjusted to natural background conditions, 
is over 0.5 dv at the Arkansas Class I areas. The results from 
Entergy's CAMx modeling confirm and provide additional support to our 
determination that the source significantly impacts visibility at 
Arkansas' Class I areas and should be evaluated for controls under 
reasonable progress.
    As discussed in our proposal and elsewhere in this final rule, we 
have found that dry scrubbers for SO2 control are cost 
effective and are expected to provide significant visibility 
improvements to the facility's 98th percentile visibility impacts as 
shown by our CALPUFF modeling. We have also found that NOX 
controls in the form of LNB/SOFA on Independence are very cost 
effective and are expected to provide considerable visibility 
improvements to the 98th percentile visibility impacts.
    Based on Entergy's CAMx modeling, SO2 emissions are 
responsible for a majority of the visibility impacts from Independence 
on the 20% worst days and NOX emissions are responsible for 
30-40% of the visibility impairment on 2 of the 20% worst days.\129\ 
The controls we are requiring will significantly reduce SO2 
and NOX emissions from Independence, and accordingly, we 
expect that they will also significantly reduce the significant 
visibility impacts from the facility on the 20% worst days. Therefore, 
we disagree that these controls are not necessary and/or that they 
would not improve visibility in Arkansas Class I areas. Based on our 
consideration of the four reasonable progress factors and of the 
visibility improvement of controls, we are

[[Page 66366]]

requiring both SO2 and NOX controls for 
Independence Units 1 and 2 under the reasonable progress requirements.
---------------------------------------------------------------------------

    \129\ This means 2 out of the 21 days that are the 20% worst of 
the days with IMPROVE monitoring data.
---------------------------------------------------------------------------

    Comment: The RPG and URP in the Arkansas Regional Haze SIP should 
be accepted as presented by the State since ADEQ's Five Year Progress 
Report SIP revision demonstrates that Arkansas is on track to achieve 
its RPGs and is below the URP glidepath. EPA's disapproval of the 
Arkansas Regional Haze SIP submitted to EPA in 2008 was not due to lack 
of reasonable progress to achieve visibility improvement or for missing 
the URP. It was disapproved primarily because the underlying emissions 
were based on presumptive limits and no BART evaluations had been 
conducted. EPA's proposed FIP and the controls for Independence only 
serve to achieve greater emissions reductions than in the Arkansas 
Regional Haze SIP. Therefore, EPA should not look beyond BART eligible 
units to achieve greater visibility improvements. EPA should not simply 
use the regional haze program as leverage to impose emissions 
reductions that have little benefit to the purpose of the rule to 
improve visibility.
    Response: We disagree that we should accept Arkansas' RPGs as 
presented in the Arkansas Regional Haze SIP submitted to us in 2008. We 
partially approved and partially disapproved the Arkansas Regional Haze 
SIP in our final action published on March 12, 2012.\130\ In that final 
action, we disapproved a large portion of the state's BART 
determinations, as well as the state established RPGs. We disapproved 
the state's RPGs because they were based on BART determinations that 
were not made in accordance with the CAA and Regional Haze regulations 
and also because in establishing the RPGs, the state did not conduct 
the reasonable progress analysis required under the CAA and Sec.  
51.308(d)(1). As discussed in a separate response, the state decided to 
forego an evaluation of the four statutory factors, stating that there 
was no need for such an evaluation since Arkansas' Class I areas are 
below the URP glidepath. In foregoing the reasonable progress analysis, 
the state did not demonstrate that the RPGs it established were a 
reflection of the amount of visibility improvement necessary to make 
reasonable progress. Our final action disapproving Arkansas' RPGs for 
Caney Creek and Upper Buffalo became effective on April 11, 2012. Any 
arguments upholding or suggesting that the state's RPGs are appropriate 
or adequate are outside the scope of this action.
---------------------------------------------------------------------------

    \130\ 77 FR 14604.
---------------------------------------------------------------------------

    Under section 110(c) of the Act, whenever we disapprove a mandatory 
SIP submission in whole or in part, we are required to promulgate a FIP 
within two years unless we approve a SIP revision correcting the 
deficiencies before promulgating a FIP. To date, Arkansas has not 
submitted a SIP revision following our partial disapproval, and EPA is 
already past-due on its action per the statutory deadlines. In 
addition, EPA is under an August 31, 2016 court ordered deadline to 
either finalize a FIP or approve a SIP to address the regional haze 
requirements and the interstate visibility transport requirements. 
Therefore, the purpose of our FIP is to correct the deficiencies in the 
SIP and conduct the required analyses and establish emission limits in 
accordance with the CAA and the Regional Haze Rule. One of the required 
analyses we must conduct in this FIP is the consideration of the four 
statutory factors to determine if additional controls are needed to 
make reasonable progress. We discuss in a separate response that the 
reasonable progress requirements under CAA section 169A(g)(1) and our 
Regional Haze regulations at Sec.  51.308(d)(1) cannot be satisfied by 
merely being below the URP glidepath and/or meeting the RPGs previously 
established by the state. The states or EPA in a FIP must conduct an 
analysis of the four statutory factors regardless of the Class I area's 
position on the URP glidepath. Based on our consideration of the four 
statutory factors and of the baseline visibility impacts from 
Independence and the visibility improvement of potential controls, we 
determined that reasonable controls for SO2 and 
NOX are available for Independence Units 1 and 2 that are 
cost effective and would result in a large amount of visibility 
improvement in Arkansas' Class I areas in terms of the 98th percentile 
impacts from the source. Additionally, as we discuss in section V.J of 
this final rule, CAMx source apportionment modeling submitted to us by 
Entergy during the comment period shows that Independence has 
significant visibility impacts in Arkansas' Class I areas on the 20% 
worst days, and further supports our decision to require controls for 
Independence under reasonable progress. Therefore, the claim that the 
SO2 and NOX controls we are requiring for 
Independence Units 1 and 2 only serve to achieve greater emissions 
reductions that have little benefit to the purpose of the Regional Haze 
Rule to improve visibility are incorrect. Because we have identified 
through our reasonable progress analysis that additional controls are 
reasonable, we are requiring these controls for Independence Units 1 
and 2. We address elsewhere in this final rule and in the RTC document 
comments related to ADEQ's 5-year Progress Report SIP revision.
    Comment: EPA's imposition of costly controls on BART-ineligible 
sources like the Independence plant, based only on what it claims is 
``reasonable,'' is economically wasteful and effectively re-writes the 
definition of what sources are BART eligible. Under the regional haze 
program, BART controls may be imposed on (1) major stationary sources 
in 26 listed categories, (2) that existed on August 7, 1977, (3) but 
were not in operation prior to August 7, 1962, and (4) emit air 
pollutants ``which may reasonably be anticipated to cause or contribute 
to any impairment of visibility'' at Class I areas. Under the proposed 
rule, the first three of these statutory and regulatory criteria would 
be rendered a nullity. According to EPA, it may impose BART controls on 
any facility, regardless of when it was built or when it began 
operating, so long as EPA determines it to be ``reasonable.'' EPA has 
effectively adopted a presumption that at least some BART-ineligible 
sources should be subject to BART unless those pollution controls are 
cost prohibitive. Such a presumption ignores the statute and re-writes 
EPA's own regulations.
    Response: We are requiring controls on Independence under the 
reasonable progress requirements, not under the BART requirements. 
Clean Air Act section 169A required us to promulgate regulations 
directing the States to revise their SIPs to include emission limits 
and other measures as necessary to make ``reasonable progress.'' \131\ 
Congress defined reasonable progress based on the consideration of four 
statutory factors: The costs of compliance, the time necessary for 
compliance, the energy and nonair quality environmental impacts of 
compliance, and the remaining useful life of any existing source 
subject to such requirements.\132\ We commonly refer to our analysis of 
these four statutory factors as a reasonable progress analysis. 
Congress also directed EPA to promulgate regulations requiring BART for 
a specific universe of older sources, and again provided a set of 
statutory factors States must consider: The costs of compliance, the 
energy and nonair

[[Page 66367]]

quality environmental impacts of compliance, any existing pollution 
control technology in use at the source, the remaining useful life of 
the source, and the degree of improvement in visibility which may 
reasonably be anticipated to result from the use of such 
technology.\133\ We note that many of the factors that must be 
considered in a BART analysis must also be considered in the reasonable 
progress analysis. Therefore, some commenters may mistakenly believe 
that we are somehow stretching the BART analysis to impose BART 
controls on Independence Units 1 and 2. This is not the case. As 
discussed in our proposal and elsewhere in this final rule, in our 
reasonable progress analysis, we considered the reasonable progress 
statutory factors as well as the visibility improvement of potential 
controls. Although visibility is not one of the four mandatory factors 
explicitly listed for consideration under CAA section 169A(g)(1) or 40 
CFR 51.308(d)(1)(i)(A), states and EPA have the option of considering 
the projected visibility benefits of controls in determining if the 
controls are necessary to make reasonable progress. We discuss this in 
more detail in our proposal and in our RTC document. Based on our 
analysis of the four statutory factors and consideration of the 
visibility improvement of controls, we have determined that there are 
SO2 and NOX controls available for Independence 
Units 1 and 2 that are cost-effective and would result in considerable 
visibility benefit at Arkansas' Class I areas, and are therefore 
requiring these controls under reasonable progress.
---------------------------------------------------------------------------

    \131\ CAA section 169A(b)(2).
    \132\ CAA section 169A(g)(1).
    \133\ CAA section 169A(b)(2)(A), (g)(2).
---------------------------------------------------------------------------

    To the extent the commenter believes that we treated the 
Independence Plant as if it were subject to BART in performing a 
source-specific reasonable progress analysis, this is incorrect. As we 
discuss elsewhere in this section of the final rule, individual 
stationary sources may be subject to source-specific analysis when 
determining whether additional controls are necessary to make 
reasonable progress. To the extent the commenter believes that only 
sources subject to BART can be looked to for emission reductions to 
promote reasonable progress, this is incorrect. If that were the case, 
then States, or EPA acting as necessary in the place of a State, would 
have little to no room for additional progress and even less need for 
sequential planning periods to build on past progress.
    Comment: Some commenters claim that we inappropriately took a ``cut 
and paste'' approach in estimating the cost of controls for 
Independence in our reasonable progress analysis.
    Response: We explained in our FIP proposal that White Bluff and 
Independence are sister facilities with nearly identical units. We 
explained that we verified that the two plants are sister facilities by 
constructing a master spreadsheet that contains information concerning 
ownership, location, boiler type, environmental controls, and other 
pertinent information.\134\ The cost of compliance is a factor that is 
required for consideration under both a BART and a reasonable progress 
analysis. Due to the similarities in the facilities and the identical 
requirement for consideration of the cost of controls under reasonable 
progress and BART, our use of the total annualized costs of controls on 
White Bluff Units 1 and 2 in our cost analysis for Independence Units 1 
and 2 was a reasonable approach. We do note that we used actual 
emissions data from Independence Units 1 and 2 to estimate the emission 
reductions expected to take place from the controls we evaluated and to 
calculate the cost effectiveness ($/ton removed) of controls for 
Independence Units 1 and 2. Thus, the total annual cost of controls on 
Independence was the only aspect of our reasonable progress analysis 
where we relied on our cost analysis for White Bluff. Our consideration 
of the remaining reasonable progress factors (time necessary for 
compliance, energy and nonair quality environmental impacts of 
compliance, and the remaining useful life of any potentially affected 
sources), as well as the visibility impacts of Independence and 
improvement due to controls on the facility, was specific to the 
Independence facility.\135\ We modeled both the baseline visibility 
impacts from the Independence facility and the visibility benefit of 
controls using CALPUFF dispersion modeling. Based on our consideration 
of the four reasonable progress factors and the modeled visibility 
improvement of controls, we determined that reasonable controls for 
SO2 and NOX are available for Independence Units 
1 and 2 that are cost effective and would result in a large amount of 
visibility improvement in Arkansas' Class I areas in terms of the 98th 
percentile impacts from the source.\136\
---------------------------------------------------------------------------

    \134\ 80 FR at 18992.
    \135\ 80 FR at 18996.
    \136\ Entergy Arkansas Inc. submitted CAMx source apportionment 
modeling during the comment period. This modeling shows that 
Independence has significant visibility impacts in Arkansas Class I 
areas on the 20% worst days, and further supports our decision to 
require controls for Independence under reasonable progress. We 
discuss Entergy Arkansas Inc.'s photochemical modeling and the 
visibility impacts due to SO2 and NOX from 
Independence on the 20% worst days elsewhere in this final rule and 
in our RTC document.
---------------------------------------------------------------------------

    Comment: The CAA's regional haze program tasks states with making 
reasonable progress toward the elimination of man-made visibility 
impairment, for which EPA has set a goal of 2064 with required progress 
milestones. Accordingly, the CAA's regional haze program contemplates 
gradual visibility improvements along a ``glide path'' toward the 2064 
goal. This program does not require immediate and costly reductions in 
the first planning period or any subsequent planning period that go 
beyond what is needed to make ``reasonable progress,'' as determined by 
a state based on its assessment of the four statutory factors. Thus, it 
neither requires nor authorizes the front-loading of extensive control 
requirements. Delaying consideration of controls on Independence until 
the next planning period is a more reasonable approach that would allow 
for the consideration of updated information, such as control equipment 
characteristics and costs, emissions reductions attributable to other 
regulatory and market drivers, and contemporaneous monitoring and 
meteorological conditions, which would allow the coordination of these 
important investment and regulatory decisions with the implementation 
of other pending regulations. This approach would also give states and 
regulated entities the opportunity to conduct integrated compliance 
planning in ways that are consistent with provision of reliable and 
affordable electric power. EPA should withdraw its proposed controls 
for Independence Units 1 and 2.
    Response: We agree that the regional haze program contemplates 
gradual visibility improvements over several planning periods. Those 
gradual improvements are guided by the principle that controls found to 
be reasonable in a given planning period should be required now, rather 
than in some unspecified future planning period. That is the very 
nature of ``reasonable progress.'' For that reason, we do not consider 
the controls we proposed and those we finalize in this action as being 
frontloading. As we discuss in several sections throughout this final 
rule, our cost analysis indicates that the SO2 and 
NOX controls we are requiring for Independence Units 1 and 2 
are cost effective and well within the range of cost of controls found 
to be reasonable by EPA and the

[[Page 66368]]

states in other regional haze actions for this first planning period. 
Arkansas did not comply with certain aspects of the Regional Haze Rule 
and thus portions of its Regional Haze SIP submitted to us in 2008 were 
not approvable, including the state's reasonable progress 
determinations and RPGs.\137\ We therefore have an obligation to 
promulgate this FIP to address the disapproved portions of the State's 
SIP submission. Pursuant to CAA section 169A(g)(1) and our Regional 
Haze regulations at Sec.  51.308(d)(i)(A), we conducted an evaluation 
of additional controls under a reasonable progress analysis that 
considered the four statutory factors. As discussed in our proposal and 
throughout this final rule, based on the demonstrations we developed 
pursuant to the CAA and Sec.  51.308(d)(1) and our consideration of the 
visibility impacts from Independence and the visibility improvement of 
potential controls, we determined that there are reasonable and cost-
effective SO2 and NOX controls available for 
Independence that would result in considerable visibility benefit at 
Arkansas' Class I areas. Under the CAA and the Regional Haze 
regulations, if we determine that additional controls are reasonable 
based on the consideration of the four statutory factors, we must 
require those controls. Therefore, we are requiring SO2 and 
NOX controls for Independence Units 1 and 2 under reasonable 
progress.
---------------------------------------------------------------------------

    \137\ 77 FR 14604.
---------------------------------------------------------------------------

    Comment: EPA applied dollar per ton cost-effectiveness estimates 
and visibility improvement rates for the proposed controls on 
Independence that are out of line with the standards applied in other 
regional haze actions. Specifically, EPA's proposal attempts to justify 
a cost-effectiveness of dry FGD at Independence Plant totaling $2,477/
SO2 ton removed for Unit 1 and $2,686/SO2 ton 
removed for Unit 2. This far exceeds the cost-effectiveness standards 
reviewed and approved by EPA for the Kentucky\138\ and North Carolina 
Regional Haze SIPs.\139\ In its approval of the Kentucky Regional Haze 
SIP, EPA approved the use of a $2,000 per ton SO2 screening 
threshold. In its approval of the North Carolina Regional Haze SIP, EPA 
approved the state's decision not to implement additional controls 
under reasonable progress despite the finding that there are potential 
controls with cost effectiveness ranging from $912 to $1,922 per ton of 
SO2 removed. EPA's proposed controls for Independence are 
inconsistent with these other regional haze actions.
---------------------------------------------------------------------------

    \138\ 76 FR 78194, 78206 (December 16, 2011).
    \139\ 77 FR 11858, 11870 (February 28, 2012).
---------------------------------------------------------------------------

    Response: In response to comments we received during the comment 
period, we have revised our cost analysis for SO2 controls 
for Independence and estimate that these controls cost $2,853/
SO2 ton removed for Unit 1 and $2,634/SO2 ton 
removed for Unit 2. Although slightly higher than the cost 
effectiveness estimates we presented in our proposal, we continue to 
consider these controls to be cost effective and well within the range 
of cost of controls found to be reasonable by EPA and the states in 
other regional haze actions. We disagree with the statement that our 
proposal to require SO2 controls for Independence is 
inconsistent with our approvals of the Kentucky and North Carolina 
Regional Haze SIPs. Additionally, the factual contexts of both of these 
actions are easily distinguished from context in which we assessed 
potential reasonable progress controls for Independence.
    The commenter contends that in our proposed approval of the 
Kentucky Regional Haze SIP, we approved the state's use of a $2,000/
SO2 ton threshold. This is incorrect. In the preamble of our 
proposed approval of the Kentucky Regional Haze SIP, we discussed that 
the state identified 10 units for evaluation under reasonable progress, 
and that 9 of these were EGUs subject to CAIR. The remaining facility, 
Century Aluminum, is not an EGU. We further discussed that for the 
limited purpose of evaluating the cost of compliance for the reasonable 
progress assessment in this first regional haze SIP for the non-EGU 
Century Aluminum, Kentucky concluded that it was not equitable to 
require non-EGUs to bear a greater economic burden than EGUs for a 
given control strategy. As a result, Kentucky decided to use CAIR as a 
guide, using a cost of $2,000/ton of SO2 reduced as a 
threshold for cost-effectiveness for that particular non-EGU source. 
Kentucky found that the cost effectiveness of the SO2 
control as suggested by the VISTAS control cost spreadsheet for 
potlines 1-4 at Century Aluminum is $14,207/ton of SO2 
removed. The State thus concluded that, based on the high cost on a $/
ton basis, there are no cost-effective SO2 reasonable 
progress controls available for the Century Aluminum units for the 
first implementation period. We proposed to approve Kentucky's 
determination, but we also stated the following concerning our position 
on Kentucky's use of a $2,000/SO2 ton threshold:

    Although the use of a specific threshold for assessing costs 
means that a state may not fully consider available emissions 
reduction measures above its threshold that would result in 
meaningful visibility improvement, EPA believes that the Kentucky 
SIP still ensures reasonable progress. In proposing to approve 
Kentucky's reasonable progress analysis, EPA is placing great weight 
on the fact that there is no indication in the SIP submittal that 
Kentucky, as a result of using a specific cost effectiveness 
threshold, rejected potential reasonable progress measures that 
would have had a meaningful impact on visibility in its Class I 
area.\140\
---------------------------------------------------------------------------

    \140\ 76 FR at 78206.

    It is clear in our proposed approval that we were not approving or 
otherwise advocating Kentucky's use of a $2,000/SO2 ton 
threshold in the reasonable progress analysis. On the contrary, we 
expressed concern that the use of a specific threshold for assessing 
cost may result in a state not fully considering potential reasonable 
control measures above that threshold that would have meaningful 
visibility improvement on its Class I areas. Furthermore, our 
statements in the proposal indicate that had there been evidence of 
more affordable controls available above the $2,000/SO2 ton 
threshold used by the state that provide meaningful visibility 
improvement at the Class I areas, we might have arrived at a different 
decision concerning the approvability of Kentucky's reasonable progress 
analysis for SO2.
    North Carolina took a similar approach to that of Kentucky in its 
SO2 reasonable progress analysis by relying on a cost 
threshold when deciding on measures for its non-EGUs. North Carolina 
set this threshold based on the estimated cost of compliance with its 
Clean Smokestacks Act, a law establishing a state-wide cap on 
SO2 and NOX emissions from the State's two major 
utilities. In our proposed approval of the North Carolina Regional Haze 
SIP, we discussed that the state identified 11 units (non-EGU) for 
evaluation. We noted that North Carolina decided that for the limited 
purpose of evaluating the cost of compliance for non-EGUs in the 
SO2 reasonable progress assessment for the first 
implementation period, it was not equitable to require non-EGUs to bear 
a greater economic burden than EGUs for a given control strategy and 
therefore also used a cost-effectiveness threshold for its non-EGUs. 
North Carolina's threshold was based on ``[t]he facility-by-facility 
cost for EGUs under [the Clean Smokestacks Act which] ranged from 912 
to 1,922 dollars per ton of SO2 removed,'' a statement which 
the commenters appear to have misinterpreted to mean that North

[[Page 66369]]

Carolina rejected potential reasonable progress measures with costs 
falling within this range.\141\ Rather, upon conducting cost 
evaluations for the non-EGUs and determining that the costs of controls 
exceeded its threshold, North Carolina concluded that there were no 
cost-effective reasonable progress SO2 controls available 
for the first implementation period. We proposed to approve North 
Carolina's determination, but we also stated the following concerning 
our position on North Carolina's use of a specific cost-effectiveness 
threshold:
---------------------------------------------------------------------------

    \141\ 77 FR at 11870.

    Although the use of a specific threshold for assessing costs 
means that a state may not fully consider available emissions 
reduction measures above its threshold that would result in 
meaningful visibility improvement, EPA believes that the North 
Carolina SIP still ensures reasonable progress. In proposing to 
approve North Carolina's reasonable progress analysis, EPA is 
placing great weight on the fact that there is no indication in the 
SIP submittal that North Carolina, as a result of using a specific 
cost effectiveness threshold, rejected potential reasonable progress 
measures that would have had a meaningful impact on visibility in 
its Class I areas.\142\
---------------------------------------------------------------------------

    \142\ 77 FR 11858, 11872.

    As in the case of Kentucky, it is clear that in our proposed 
approval of North Carolina's reasonable progress determination, we were 
not approving or otherwise advocating North Carolina's use of that 
specific cost-effectiveness threshold in the reasonable progress 
analysis. Therefore, we disagree that our requirement of SO2 
controls for Independence Units 1 and 2 under reasonable progress is 
inconsistent with our actions on the Kentucky and North Carolina 
Regional Haze SIPs.
    Comment: EPA's decision to evaluate and propose NOX 
controls at the Independence Plant stands completely opposite its 
decision not to even evaluate similar controls for Texas' point sources 
despite similar visibility conditions. EPA elected not to evaluate 
Texas point sources for NOX controls because modeling 
suggested that impacts from the sources on the 20% worst days were 
``primarily due to sulfate emissions.'' \143\ In Arkansas, EPA was even 
more explicit in stating that ``visibility impairment is not projected 
to be significantly impacted by nitrate on the 20% worst days at Caney 
Creek or Upper Buffalo.'' \144\ However, the agency nevertheless 
evaluated and proposed NOX controls for the Independence 
Plant Units 1 and 2. The arbitrary nature of this aspect of EPA's 
proposal is further evidenced by the low projection for anticipated 
visibility improvement due to the NOX controls. For 
instance, EPA rejected installation of SCR controls under reasonable 
progress where it was projected to result in 0.41 dv improvement at 
affected Class I areas in the Arizona Regional Haze FIP proposal, 
whereas it is proposing to require NOX controls on 
Independence that are projected to result in visibility improvement of 
0.461 dv in the Arkansas Regional Haze FIP proposal.
---------------------------------------------------------------------------

    \143\ 79 FR 74818, 74873 (December 16, 2014).
    \144\ 80 FR at 18966.
---------------------------------------------------------------------------

    Response: This comment, and our response to it, illustrate the very 
fact-specific nature of individual evaluations and decisions under the 
regional haze program. It is critical to understand the full context of 
each decision. In each one, the EPA applies the requirements of the 
statute and regulations in a consistent manner, but the different 
facts--unique to each state and facility--inevitably lead to different 
outcomes. We agree that in our Texas FIP action we noted that on the 
20% worst days, the impacts from the EGUs we evaluated under reasonable 
progress were primarily due to sulfate emissions. We also agree that in 
our Arkansas FIP proposal we acknowledged that the CENRAP modeling 
demonstrates that sulfate is the primary driver of regional haze in 
Arkansas' Class I areas on the 20% worst days. This does not mean that 
NOX is not a key pollutant contributing to regional haze 
impairment in both states. For instance, the CENRAP CAMx modeling shows 
that total extinction at Caney Creek is dominated by nitrate on 4 of 
the days that comprise the 20% worst days in 2002, and a significant 
portion of the total extinction at Upper Buffalo on 2 of the days that 
comprise the 20% worst days in 2002 is due to nitrate.\145\
---------------------------------------------------------------------------

    \145\ See Arkansas Regional Haze SIP, Appendix 8.1-- ``Technical 
Support Document for CENRAP Emissions and Air Quality Modeling to 
Support Regional Haze State Implementation Plans,'' section 3.7.1 
and 3.7.2. See the docket for this rulemaking for a copy of the 
Arkansas Regional Haze SIP.
---------------------------------------------------------------------------

    As a key pollutant, we considered NOX controls under 
reasonable progress in both Texas and Arkansas. In our Texas FIP, we 
considered NOX controls under reasonable progress for the 
Works No. 4 Glass Plant but ultimately did not require those controls 
based on the emission reductions already occurring at the facility, the 
anticipated lifetime of the furnaces, and the fact that Furnace No. 2 
had undergone rebricking within the past few years. Although we 
determined it was reasonable to not require additional controls for 
Works No. 4 Glass Plant at this time, we encouraged Texas to consider 
additional controls when Furnace No. 2 is scheduled for its next 
rebricking. We also found that in Texas all the EGUs that we evaluated 
for controls under reasonable progress had existing LNB for control of 
NOX emissions. This is in contrast to Independence, which is 
the second largest source of NOX point source emissions in 
Arkansas and is not currently equipped with any NOX 
controls. As such, Independence was a more compelling candidate for 
evaluation of NOX controls than were the EGUs in Texas that 
we evaluated for controls under reasonable progress.
    As NOX is a visibility impairing pollutant and 
Independence is responsible for a very large portion of the point 
source NOX emissions in the state (approximately 
21.3%),\146\ we determined that it was reasonable to evaluate 
NOX controls under reasonable progress in our Arkansas FIP 
proposal. We conducted CALPUFF modeling and found that the Independence 
Plant has significant visibility impacts in Arkansas' Class I areas due 
to NOX emissions based on the 98th percentile visibility 
impacts from the facility, and also found that LNB/SOFA would improve 
these visibility impacts.\147\ We also found that LNB/SOFA is very cost 
effective ($401/ton removed for Unit 1 and $436/ton removed for Unit 
2). For these reasons, we proposed LNB/SOFA for Independence Units 1 
and 2 under Option 1. In addition, we discuss in more detail elsewhere 
in this final rule and in our RTC document that Entergy submitted CAMx 
photochemical modeling during the public comment period showing that 
nitrate from Independence is responsible for 30-40% of the visibility 
impairment in Arkansas' Class I areas on 2 out of the 20% worst days in 
2018. We expect that the installation of NOX controls at 
Independence, which we found to be very cost effective, would provide 
visibility improvement on this portion of the 20% worst days, thereby 
assuring reasonable progress toward the goal of natural visibility 
conditions. Based on

[[Page 66370]]

our consideration of the four statutory factors and the visibility 
improvement available from controls, we have determined that there are 
reasonable NOX controls available for Independence that are 
cost effective and would result in considerable visibility improvement. 
Therefore, we are requiring these controls.
---------------------------------------------------------------------------

    \146\ See NEI 2011 v1. A spreadsheet containing the emissions 
inventory is found in the docket for our proposed rulemaking.
    \147\ Although the reasonable progress provisions of the 
Regional Haze Rule place emphasis on the 20% worst days, the CAA 
goal of remedying visibility impairment due to anthropogenic 
emissions encompasses all days. Thus, states and EPA have the 
discretion to consider the visibility impacts of sources and the 
visibility benefit of controls on days other than the 20% worst days 
in making their decisions, such as the days on which a given 
facility has its own largest (98th percentile) impacts. Because 
Independence has significant 98th percentile visibility impacts, 
these impacts will need to be addressed to achieve the CAA goal of 
remedying visibility impairment due to anthropogenic emissions.
---------------------------------------------------------------------------

    We disagree that our decision to require NOX controls 
for Independence is inconsistent with our Arizona FIP proposal. In that 
action, we proposed that neither SCR nor SNCR was required to achieve 
reasonable progress for Springerville Units 1 and 2 in this regional 
haze planning period because:

    [w]hile the cost per ton for SNCR may be reasonable, the 
projected visibility benefits are relatively small (0.18 dv at the 
most affected area). The projected visibility benefits of SCR are 
larger (0.41 dv at the most affected area), but we do not consider 
them sufficient to warrant the relatively high cost of controls for 
purposes of RP in this planning period. However, these units should 
be considered for additional NOX controls in future 
planning periods.\148\
---------------------------------------------------------------------------

    \148\ 79 FR 9318, 9360 (February 18, 2014).

    The ``relatively high cost'' of SCR controls we refer to in that 
statement is $6,829/ton NOX removed for Springerville Unit 1 
and $6,085/ton NOX removed for Springerville Units 2.\149\ 
Thus, our decision to not propose SCR at Springerville Units 1 and 2 
was not because we considered the visibility benefits to be too small, 
as the commenter appears to believe. Instead, it was because we 
determined that, under these circumstances, this level of visibility 
improvement was not sufficient to warrant the cost per ton of emissions 
reduced. In contrast, we found that the cost of LNB/SOFA at 
Independence Units 1 and 2 is significantly lower ($401/ton removed for 
Unit 1 and $436/ton removed for Unit 2), and we determined that 0.459 
dv visibility improvement on a facility wide basis warranted the cost 
of these controls. Therefore, we disagree that the NOX 
controls we proposed and are finalizing in this action for Independence 
Units 1 and 2 in any way contradict our proposed Arizona Regional Haze 
FIP.
---------------------------------------------------------------------------

    \149\ 79 FR 9318, 9359.
---------------------------------------------------------------------------

    Comment: The overarching requirement of the CAA's haze provisions 
is for each state's plan to include ``emission limits, schedules of 
compliance and other measures as may be necessary to make reasonable 
progress.'' CAA section 169A(b)(2). The statute defines reasonable 
progress to account for four factors: The cost of controls, the time 
needed to install controls, energy and nonair quality environmental 
impacts of controls, and the remaining useful life of the source. CAA 
section 169A(g)(1) and 40 CFR 51.308(d)(1)(i)(A). EPA's implementing 
regulations require each state with a Class I area to set an RPG for 
each area within its borders based on considering the four statutory 
factors for reasonable progress. Each state must also determine the 
uniform rate of progress. If a state sets a reasonable progress goal 
that provides for less progress than the URP, the state must 
demonstrate that achieving the URP is unreasonable and that its 
alternative goal is reasonable. Moreover, each state must consult with 
other states that contribute to haze in the host state's Class I areas. 
Neither the statute nor the regulations exempts states from the 
required reasonable progress analysis merely because a Class I area is 
on the glidepath to achieving the URP. To the contrary, EPA's long-
standing interpretation of the regional haze rule is that ``the URP 
does not establish a `safe harbor' for the state in setting its 
progress goals.'' \150\ If it is reasonable to make more progress than 
the URP, a state must do so, as EPA explained in the 1999 Regional Haze 
Rule.\151\ Having disapproved Arkansas' regional haze plan, EPA has an 
obligation to conduct a reasonable progress analysis for Caney Creek 
and Upper Buffalo based on a consideration of the four statutory 
factors for reasonable progress. 40 CFR 51.308(d)(1).
---------------------------------------------------------------------------

    \150\ 79 FR 74818, 74834.
    \151\ 64 FR at 35714, 35732.
---------------------------------------------------------------------------

    Response: We agree with this comment with regard to our obligation 
to conduct a reasonable progress analysis for sources in Arkansas 
regardless of the Class I areas' position on the URP glidepath.

D. Control Levels and Emission Limits

    Comment: Assuming EPA proceeds with BART for the Ashdown Mill, EPA 
should revise the proposed SO2 limit for Power Boiler 2 from 
0.11 lb/MMBTU to 155 lb/hr on a 30-day boiler operating day. There are 
a number of concerns with EPA's proposed limit of 0.11 lb/MMBTU: It is 
too stringent, it is based on the use of an inappropriate baseline 
(2011-2013), and assumes the existing control equipment can 
continuously operate at the upper range of its capability (90% 
efficiency) over long periods of time, without supporting data or other 
documentation. First, in the methodology to calculate the proposed BART 
limit, EPA used data from 2011-2013 for determining the proposed BART 
limit, instead of using 2001-2003 as the baseline. No justification is 
given for not using 2001-2003 as the baseline, or why the particular 
years EPA selected are better than the BART baseline years or legally 
appropriate. Deviating from the 2001-2003 BART baseline is appropriate 
if significant changes were made to the emission units or permit 
conditions were imposed that prevent a unit from operating at the BART 
baseline emission value. However, this is not the case for Power Boiler 
2. The BART 2001-2003 baseline information is representative of Power 
Boiler 2's potential operations. The fact that the Ashdown Mill 
voluntarily elected to operate at a lower SO2 level 
subsequent to the 2001-2003 baseline period is not relevant. Moreover, 
by not utilizing the BART 2001-2003 baseline actual emissions in 
establishing the proposed BART SO2 limit, EPA penalizes the 
Ashdown Mill for its voluntary SO2 emission reductions 
undertaken on its own initiative since the BART baseline period. Here, 
the mill voluntarily reduced SO2 emissions by over 40% since 
the BART baseline years prior to the proposed BART requirements. Using 
the actual emission data from the BART baseline period of 2001-2003, 
gives the mill credit for its early voluntary action. Second, EPA 
wrongly applied the maximum rated heat input capacity of 820 MMBTU/hr 
when it converted from a lb/hr limit to a lb/MMBTU limit. The use of 
the maximum heat input rating is not representative of average 
(typical) boiler operating conditions, which are lower than the maximum 
heat input capability. The actual average heat input during the 2001-
2003 baseline period is 586 MMBTU/hr. In this situation, the use of 
actual emission data and maximum rated heat input to calculate the 
proposed SO2 BART limit is inappropriate and an inaccurate 
methodology which creates significant concerns. EPA should instead 
establish an SO2 emission limit in terms of lb/hr. Third, 
based on monthly SO2 information for the 2011-2013 period, 
EPA estimated that the SO2 control efficiency for the 
existing scrubber on Power Boiler 2 to be approximately 69% and that 
the existing scrubber may achieve on a short-term basis an 
SO2 control efficiency of 90%. However, there is no 
documentation showing that the scrubber can sustain this maximum 
performance level on a long term basis. EPA should revise the 
methodology for calculating the SO2 BART emission limit for 
Power Boiler No. 2 by using 2001-2003 actual emissions as the baseline; 
assuming the existing scrubbers operated at a 69% control efficiency 
during the 2001-2003

[[Page 66371]]

baseline period; calculating an SO2 emission limit in lb/hr 
based on 2001-2003 baseline actual emissions and a 90% control 
efficiency. Based on this approach, EPA should revise the proposed 
SO2 limit for Power Boiler 2 from 0.11 lb/MMBTU to 155 lb/hr 
on a 30-day boiler operating day.
    Response: We disagree that an emission limit of in an emission 
limit of 155 lb/hr on a 30 boiler-operating-day satisfies the 
SO2 BART requirement for Power Boiler No. 2. As discussed in 
our proposal, we requested information from the facility to determine 
if upgrades to the existing scrubbers are technically feasible and if 
they would be cost effective and provide meaningful visibility benefit. 
This assessment first required us to determine the current control 
efficiency of the scrubbers. Because our BART analysis involved 
determining the current control efficiency of the existing scrubbers, 
we found that the most reasonable approach was to use data that reflect 
the current control efficiency of the existing scrubbers, as opposed to 
2001-2003 data. In order to conduct our BART analysis, we requested 
monthly average data for 2011, 2012, and 2013 on monitored 
SO2 emissions from Power Boiler No. 2, mass of the fuel 
burned for each fuel type, and the percent sulfur content of each fuel 
type burned.\152\ These were the three most recent full calendar years 
of data available at the time we conducted our BART analysis. For these 
reasons, our use of 2011-2013 as the baseline for calculating the 
current control efficiency of the existing scrubbers and our proposed 
SO2 BART limit for Power Boiler No. 2 was appropriate and 
justified. As discussed in detail in our proposal, based on the 
emissions data and fuel usage data Domtar provided to us, we estimated 
that the current control efficiency of the existing scrubbers is 
approximately 69% based on 2011-2013 data.\153\ The data also indicated 
that the existing scrubbers could achieve up to 90% removal efficiency. 
As discussed in our proposal, Domtar indicated that the scrubbers are 
currently operated in a manner that allows for compliance with 
permitted emission limits.\154\ In other words, the facility generally 
uses only the amount of scrubbing solution needed to comply with 
permitted emission limits. The information the facility provided 
indicated that it would be possible to add more scrubbing solution to 
achieve greater SO2 removal than required to meet the 
boiler's existing SO2 permit limit; specifically, the 
information indicated that additional scrubbing reagent can be added to 
increase the control efficiency of the existing scrubbers to 90%.\155\
---------------------------------------------------------------------------

    \152\ See 80 FR at 18984. See also August 29, 2014 letter from 
Annabeth Reitter, Corporate Manager of Environmental Regulation, 
Domtar, to Dayana Medina, U.S. EPA Region 6. A copy of this letter 
and an Excel file attachment titled ``Domtar 2PB Monthly 
SO2 Data,'' are found in the docket for our proposed 
rulemaking.
    \153\ See 80 FR at 18984. See also the spreadsheet titled 
``Domtar 2PB Monthly SO2 Data.'' This spreadsheet was 
included as an attachment to the August 29, 2014 letter from 
Annabeth Reitter, Corporate Manager of Environmental Regulation, 
Domtar, to Dayana Medina, U.S. EPA Region 6. See also the 
spreadsheet titled ``Domtar PB No2--Cost Effectiveness 
calculations.'' Copies of these documents can be found in the docket 
for this proposed rulemaking.
    \154\ 80 FR at 18983, 18984.
    \155\ 80 FR at 18984.
---------------------------------------------------------------------------

    We agree that we applied the boiler's maximum heat input rating of 
820 MMBtu/hr when we calculated our proposed limit of 0.11 lb/MMBtu, 
and based on information provided by the commenter, we acknowledge that 
use of the maximum heat input rating is not representative of average 
(typical) boiler operating conditions. To address the commenter's 
concern, we are finalizing an SO2 BART limit for Power 
Boiler No. 2 in terms of lb/hr. As we discussed in our proposal, based 
on the emissions data we obtained from Domtar, we determined that the 
No. 2 Power Boiler's annual average SO2 emission rate for 
the years 2011-2013 was 280.9 lb/hr.\156\ This annual average 
SO2 emission rate corresponds to the operation of the 
scrubbers at a 69% removal efficiency. We also estimated that 100% 
uncontrolled emissions would correspond to an emission rate of 
approximately 915 lb/hr. Application of 90% control to this emission 
rate results in a controlled emission rate of 91.5 lb/hr.\157\ We 
recognize that the boiler's SO2 emissions are currently 
lower than they were in the 2001-2003 period, and that had we used 
2001-2003 data to calculate the current control efficiency and 
SO2 BART emission limit, as the commenter requests, this 
would have resulted in a less stringent emission limit. However, as 
discussed above, the most reasonable approach is to use recent data in 
our calculation of an appropriate SO2 BART emission limit. 
As Domtar is requesting an emission limit in terms of lb/hr, we are 
finalizing for SO2 BART for Power Boiler No. 2 an emission 
limit of 91.5 lb/hr on a 30 boiler operating day. We believe this 
emission limit reflects operation of the scrubbers at 90% control 
efficiency and addresses the SO2 BART requirement for Power 
Boiler No. 2.
---------------------------------------------------------------------------

    \156\ See 80 FR at 18984. See also the spreadsheet titled 
``Domtar 2PB Monthly SO2 Data.'' This spreadsheet was 
included as an attachment to the August 29, 2014 letter from 
Annabeth Reitter, Corporate Manager of Environmental Regulation, 
Domtar, to Dayana Medina, U.S. EPA Region 6. See also the 
spreadsheet titled ``No2 Boiler_Monthly Avg SO2 emission 
rate and calculations.'' Copies of these documents can be found in 
the docket for our rulemaking.
    \157\ See 80 FR at 18984. See also the spreadsheet titled ``No2 
Boiler Monthly Avg SO2 emission rate and calculations.'' 
A copy of this spreadsheet can be found in the docket for our 
rulemaking.
---------------------------------------------------------------------------

    We believe it reasonable to set the emission limit using baseline 
emissions resulting from recent/current fuels. Given that we don't find 
it appropriate to use emissions from the 2001-2003 period to calculate 
the SO2 emission limit, the control efficiency from that 
period is irrelevant. What is relevant are the current uncontrolled 
SO2 emissions and the possible control efficiency of the 
existing scrubbers, which is what we considered in our BART analysis. 
We found in our analysis that during the 2011-2013 period, the company 
was able to achieve an average monthly control efficiency of 90% and 
find that this level of control is reasonable, and can be achieved by 
the use of sufficient reagent to achieve the lower level. We also note 
that the commenter did not provide additional information to support 
the claim that the existing scrubbers cannot consistently achieve the 
level of control efficiency necessary to meet an emission limit of 91.5 
lb/hr.
    Comment: The NOX emission limits proposed for the units 
at White Bluff and Independence are based on the emission rate for LNB/
SOFA of 0.15 lb/MMBtu that Entergy proposed in the Revised White Bluff 
BART Analysis. At the time Entergy submitted the Revised White Bluff 
BART Analysis in October 2013, which EPA relied on in developing its 
FIP proposal, all four of the coal-fired units at White Bluff and 
Independence were operated as base load units and spent the 
overwhelming majority of their operating time at loads of greater than 
50% of unit capacity. Since submitting the Revised White Bluff BART 
Analysis, Entergy transitioned to MISO in December 2013. MISO utilizes 
an economic dispatch model to determine which EGUs within its service 
territory are dispatched to operate and the operating load (MW) for 
each unit. Beginning in December 2014, the units at both White Bluff 
and Independence began to be dispatched primarily as load-following 
units. Since December 2014, the White Bluff and Independence units have 
been dispatched less frequently and, when dispatched, have spent 
significantly more time at low operating rates of less than 50% of unit 
capacity. The data for 2015 (through June 30) reflects a significant 
increase in the percentage of time that each unit is dispatched at less

[[Page 66372]]

than 50% of operating capacity. Three of the four units have spent 
greater than 40% of their 2015 operating hours at less than 50% of 
capacity, and the two Independence units have spent nearly half of 
their operating time at less than 50% of capacity. This change in 
dispatch coincided with a sharp drop in natural gas prices. This drop 
in gas prices to near $3 per MMBtu has been sustained since December 
2014, and Entergy has no reason to expect any significant increase in 
gas pricing in the near future. This change in dispatch for the units 
at both White Bluff and Independence is significant with regard to 
NOX emissions as the LNB/SOFA system is designed to operate 
primarily in the range of 50-100% of unit load. Entergy has selected 
Foster Wheeler as the LNB/SOFA vendor for White Bluff and has only been 
able to obtain a guarantee of less than 0.15 lb/MMBtu for operating 
loads in the range of 50-100% of unit capacity. Since the available 
emission guarantee does not cover unit operation at less than 50% of 
capacity, Entergy requested a memorandum from Foster Wheeler regarding 
the impact of unit operation at less than 50% capacity on 
NOX emission rates. Based on input from the LNB/SOFA vendor, 
Entergy does not believe that the proposed emission rate of 0.15 lb/
MMBtu is consistently achievable under all operating conditions. Even 
with a 30-day averaging period for the proposed limit, a unit which is 
frequently dispatched at less than 50% of capacity may not be able to 
achieve compliance. This was not perceived as an issue at the time that 
the Revised White Bluff BART Analysis was prepared and submitted to 
ADEQ by Entergy as, historically and at that time, the units were 
operated almost exclusively as base-load units and spent less than 10% 
of their operating time at less than 50% of unit capacity. In the 
current dispatch environment, with some units spending nearly 50% of 
their operating time outside of the control range for LNB/SOFA, Entergy 
can no longer be confident that the units will be able to achieve 
compliance with a limit of 0.15 lb/MMBtu on a 30-day rolling average 
basis. The concern arises from low-load operation during which periods 
of higher NOX emissions, on a lb/MMBtu basis, would not be 
expected to correspond to an increase in the maximum mass emission rate 
(lb/hr) from the units as any increase in the emission rate on a lb/
MMBtu basis would be expected to be more than offset by the lower unit 
operating rate in MMBtu/hr to arrive at a mass emission rate (lb/hr).
    To address the potential for a higher NOX emission rate 
(lb/MMBtu basis) at operating rates of less than 50% of unit capacity, 
Entergy proposes a rolling 30-boiler operating day average emission 
rate of 1,342.5 lb NOX/hr at each coal-fired unit at White 
Bluff and Independence. In the alternative, if EPA believes that a lb/
MMBtu limit is necessary for the units, Entergy proposes a bifurcated 
NOX emission limit for each unit at both White Bluff and 
Independence as follows: (1) For all unit operation (0-100% of 
capacity) require an emission limit of 1,342.5 lb NOX/hr, 
based on a rolling 30-boiler operating day average; and (2) for unit 
operation at 50-100% of capacity, require an emission limit of 0.15 lb 
NOX/MMBtu, based on a rolling 30-boiler operating day 
average, to include only those hours for which the unit was dispatched 
at 50% or greater of maximum capacity. This alternative approach would 
ensure that the units are operated in compliance with the LNB/SOFA 
design within the control range of 50-100% of capacity while providing 
Entergy with flexibility in demonstrating compliance. The lb/hr limit, 
which would apply to all operating hours, will ensure that the 30-day 
average emission rates remain below those on which both EPA and Entergy 
relied to project visibility improvements from the proposed 
NOX emission reductions.
    Response: We acknowledge the information provided by the commenter. 
We understand the commenter's concerns that because of recent changes 
in dispatch of the units, White Bluff Units 1 and 2 and Independence 
Units 1 and 2 are no longer expected to be able to consistently meet 
our proposed NOX emission limit of 0.15 lb/MMBtu over a 30-
boiler-operating-day period based on LNB/SOFA controls. We believe the 
commenter has provided sufficient information to substantiate that the 
units are not expected to be able to meet our proposed NOX 
emission limit of 0.15 lb/MMBtu when the units are primarily operated 
at less than 50% of their operating capacity. In particular, the 
information provided by the commenter indicates that LNB/SOFA achieves 
optimal NOX control when the boiler is operated from 50 to 
100% steam flow because the heat input across this range is sufficient 
to safely redirect a substantial portion of combustion air through the 
overfire air registers.\158\ This allows the combustion zone airflow to 
be sub-stoichiometric and oxygen to be reduced to the point where much 
of the elemental nitrogen in the fuel and combustion air can pass 
through the boiler without oxidizing (i.e., converting to 
NOX). When a boiler is operated below the 50 to 100% 
capacity range, NOX concentrations on a lb/MMBtu basis can 
be elevated due to the lower heat input rating, even though the pounds 
of NOX emitted (i.e., on a mass basis) is less due to the 
reduced amount of fuel and air. In light of the information provided by 
the commenter, we believe it is appropriate to promulgate a bifurcated 
NOX emission limit for each unit, as suggested by the 
commenter.
---------------------------------------------------------------------------

    \158\ See comments submitted during the comment period by 
Entergy Arkansas Inc., including Exhibit G to Entergy's comments. 
These and all other comments and associated attachments submitted 
during the public comment period are found in the docket associated 
with this rulemaking.
---------------------------------------------------------------------------

    Therefore, in this FIP we are requiring White Bluff Units 1 and 2 
and Independence Units 1 and 2 to each meet a NOX emission 
limit of 0.15 lb/MMBtu on a 30 boiler-operating-day rolling average, 
where the average is to be calculated by including only the hours 
during which the unit was dispatched at 50% or greater of maximum 
capacity, as requested by the commenter. Specifically, the 30 boiler-
operating-day rolling average is to be calculated for each unit by the 
following procedure: (1) Summing the total pounds of NOX 
emitted during the current boiler-operating-day and the preceding 29 
boiler-operating-days, including only emissions during hours when the 
unit was dispatched at 50% or greater of maximum capacity; (2) summing 
the total heat input in MMBtu to the unit during the current boiler-
operating-day and the preceding 29 boiler-operating-days, including 
only the heat input during hours when the unit was dispatched at 50% or 
greater of maximum capacity; and (3) dividing the total pounds of 
NOX emitted as calculated in step 1 by the total heat input 
to the unit as calculated in step 2. In addition to this limit that is 
intended to control NOX emissions when the units are 
operated at 50% or greater of maximum capacity, we are establishing a 
limit in lb/hr for periods in which the units are operated at less than 
50% capacity. However, the 1,342.5 lb/hr emission limit suggested by 
the commenter is too high to appropriately control NOX 
emissions when the units are operated at low capacities. There is no 
indication in the comments submitted that the 1,342.5 lb/hr emission 
limit suggested by the

[[Page 66373]]

commenter was based on a vendor guarantee. The commenter did not 
explain how the 1,342.5 lb/hr limit was calculated, but it appears that 
it was calculated by multiplying the 0.15 lb/MMBtu limit by the maximum 
heat input rating for each unit (8,950 MMBtu/hr), which yielded 1,342.5 
lb/hr. An emission limit of 1,342.5 lb/hr would be appropriate when the 
unit is operated at high capacities considering that the limit was 
calculated based on the unit's maximum heat input rating. However, such 
an emission limit would not be sufficiently protective or appropriate 
when the unit is operated at lower capacities when it is expected that 
NOX emissions on a mass basis would be lower compared to 
operation at high capacity. To address this concern, we have calculated 
a new emission limit of 671 lb/hr that is based on 50% of the unit's 
maximum heat input rating, and is applicable only when the unit is 
being operated at less than 50% of the unit's maximum heat input 
rating. We calculated this limit by multiplying 0.15 lb/MMBtu by 50% of 
the maximum heat input rating for each unit (i.e., 50% of 8,950 MMBtu/
hr, or 4,475 MMBtu/hr). This limit is on a rolling 3-hour average, 
where the average is to be calculated by including emissions only from 
the hours during which the unit was operated at less than 50% of the 
unit's maximum heat input rating (i.e., hours when the heat input to 
the unit is less than 4,475 MMBtu). We are not establishing a lb/hr 
emission limit that applies when the units are operated at 50% or 
greater of the unit's maximum heat input rating because there is no 
need for it since the 0.15 lb/MMBtu limit will address NOX 
emission during those operating conditions.
    As such, we are requiring White Bluff Units 1 and 2 and 
Independence Units 1 and 2 to each meet a NOX emission limit 
of 0.15 lb/MMBtu on a 30 boiler-operating-day rolling average, where 
the average is to be calculated by including only the hours during 
which the unit was dispatched at 50% or greater of maximum capacity, as 
requested by the commenter. In addition, we are requiring White Bluff 
Units 1 and 2 and Independence Units 1 and 2 to each meet a 
NOX emission limit of 671 lb/hr on a rolling 3-hour average 
that applies only to the hours when the unit is operated at less than 
50% of the unit's maximum heat input rating. We believe that these 
limits address the commenter's concern of not being able to meet the 
lb/MMBtu emission limit when the unit is being operated at lower 
capacities, and will also ensure that NOX emissions are 
appropriately controlled when the units are operated at higher 
capacities, as well as when they are operated at lower capacities.
    Comment: Assuming EPA proceeds with BART for the Domtar Ashdown 
Mill, the mill conceptually agrees with the proposed BART 
SO2 limit for Power Boiler 1 of 21.0 lb/hr on a 30-day 
averaging basis with no add-on control. However, based on the 
methodology the mill uses to determine fuel usage, the emission limit 
needs to be expressed in an alternative form to better match with the 
compliance averaging time of 30 days. Calculation of hourly 
SO2 emissions using hourly fuel usage information is not a 
workable approach for Power Boiler 1, where the facility's practice is 
to use monthly fuel usage information that is reconciled at the end of 
each month based on fuel inventory records. Records of daily fuel usage 
may be adjusted at the end of the month as part of the reconciliation 
process. Therefore, Domtar requests the BART limit of 21.0 lb/hr be 
expressed as 504 lb/day.
    Response: After carefully considering this comment we have 
determined that Domtar's request for an SO2 BART emission 
limit in terms of lb/day is reasonable. An emission limit in terms of 
lb/day will be better suited for the mill's methodology of using 
monthly fuel throughput information. Therefore, as requested by the 
facility, we are finalizing an SO2 BART emission limit of 
504 lb/day for Power Boiler No. 1.

E. Domtar Ashdown Mill Repurposing Project

    Comment: The Domtar Ashdown Mill is in the process of re-purposing 
and is in a state of transition. Once the re-purposing and re-
configuration is complete and the mill is fully operational, the mill 
will need to decide if Power Boiler 1 will continue with full or 
intermittent operation, and if so what fuels will be used, or will be 
retired. If the boiler is fuel switched to natural gas or the boiler 
retired, the SO2 BART limit will be unnecessary along with 
the associated monitoring, recordkeeping and reporting requirements for 
the SO2 BART limit. The Ashdown Mill is requesting EPA 
include in the FIP final rule an alternate compliance option that 
removes all of SO2 BART related requirements for Power 
Boiler 1 if this boiler is switched to burn only natural gas. If Power 
Boiler 1 is switched to burn only natural gas, requirements for NOx 
testing also need to be removed and an alternate NOX BART 
compliance option needs to be developed to allow compliance to be based 
on the use of AP-42 emission factors and fuel use records. If Power 
Boiler 1 is retired, there is no need to retain the SO2 and 
NOX BART limits and associated requirements, and an 
alternate BART compliance option should address this retirement 
scenario as well.
    Response: We proposed an SO2 BART emission limit of 21.0 
lb/hr for Power Boiler No. 1. As discussed in section IV. of this final 
rule, we are finalizing an emission limit in terms of lb/day, as 
requested by Domtar. We proposed to find that to demonstrate compliance 
with this SO2 BART emission limit, the facility was required 
to use a site-specific curve equation (provided to us by the facility) 
to calculate the SO2 emissions from Power Boiler No. 1 when 
combusting bark, and to confirm the curve equation using stack 
testing.\159\ We also proposed to find that to calculate the 
SO2 emissions from Power Boiler No. 1 when combusting fuel 
oil, the facility must assume that the SO2 inlet is equal to 
the SO2 being emitted at the stack.\160\ In our proposal we 
invited public comment specifically on the issue of whether our 
proposed method of demonstrating compliance is appropriate.
---------------------------------------------------------------------------

    \159\ 80 FR 18944, 18980.
    \160\ 80 FR at 18980.
---------------------------------------------------------------------------

    We note that we became aware that Power Boiler No. 1 wished to burn 
only natural gas after the end of the comment period for our proposal, 
and that the facility has submitted a permit renewal application to 
ADEQ that will reflect this enforceable change.\161\ We do not agree 
that the SO2 BART emission limit becomes ``unnecessary'' 
when a unit is switched to burn only natural gas. The Regional Haze 
regulations define BART as an emission limitation based on the degree 
of reduction achievable through the application of the best system of 
continuous emission reduction for each pollutant which is emitted by an 
existing stationary facility.\162\ Therefore, a BART emission limit is 
still applicable and is required regardless if the unit switches to 
natural gas. However, the repurposing project the mill is currently 
undergoing and the fact that the facility's air permit will be revised 
such that Power Boiler No. 1 will be permitted to burn only natural gas 
render it appropriate to provide the facility with flexibility in 
demonstrating compliance with the SO2 emission limit. 
Therefore, in addition to the method we proposed for demonstrating 
compliance with the SO2 BART emission limit for Power Boiler 
No. 1, we are also finalizing one alternative method for

[[Page 66374]]

demonstrating compliance: The owner or operator may demonstrate 
compliance with the SO2 emission limit by switching Power 
Boiler No. 1 to burn only pipeline quality natural gas. Therefore, if 
the facility's air permit is revised to reflect that Power Boiler No. 1 
is permitted to burn only pipeline quality natural gas, this would 
satisfy the requirement for demonstrating compliance with the boiler's 
SO2 BART emission limit, and the reporting and recordkeeping 
requirements would be waived. We are revising proposed Sec.  52.173 to 
reflect this.
---------------------------------------------------------------------------

    \161\ See file ``Record of Meeting_March 10 2016,'' which can be 
found in the docket for this rulemaking.
    \162\ 40 CFR 51.301.
---------------------------------------------------------------------------

    We are finalizing our determination that NOX BART for 
Power Boiler No. 1 is an emission limit of 207.4 lb/hr. We proposed 
that to demonstrate compliance with this NOX BART emission 
limit, the facility was required to conduct annual stack testing. In 
response to a separate comment provided by Domtar, in our final FIP we 
are requiring stack testing every five years instead of annually to 
demonstrate compliance with the NOX BART emission limit. The 
repurposing project the mill is currently undergoing and the fact that 
the facility's air permit will be revised such that Power Boiler No. 1 
will be permitted to burn only natural gas render it appropriate to 
provide the facility with flexibility in demonstrating compliance with 
the NOX emission limit. Therefore, we are also providing one 
alternative method for demonstrating compliance with the NOX 
emission limit: If the facility's air permit is revised to reflect that 
Power Boiler No. 1 is permitted to burn only pipeline quality natural 
gas, the facility may demonstrate compliance with the NOX 
emission limit by calculating emissions using AP-42 emission factors 
and fuel usage records. Under these circumstances, the facility would 
not be required to demonstrate compliance with the NOX BART 
emission limit for Power Boiler No. 1 through stack testing. We are 
revising proposed Sec.  52.173 to reflect this.
    With regard to the request that we include a provision in our FIP 
that removes all SO2 and NOX BART related 
requirements for Power Boiler 1 if this boiler is permanently retired 
in the future, we noted above that the Regional Haze regulations define 
BART as an emission limitation based on the degree of reduction 
achievable through the application of the best system of continuous 
emission reduction for each pollutant which is emitted by an existing 
stationary facility. The BART emission limits and applicable 
requirements continue to apply regardless if a BART source is 
mothballed or retired/shut down without being dismantled, 
decommissioned, and having the air permit revoked. In the event that 
the BART source is permanently shut down, dismantled, decommissioned, 
and the permit revoked in the future, the process for removing the BART 
emission limits and applicable requirements would necessarily involve a 
request by the company for partial FIP withdrawal or a SIP revision 
from the State in the event that we have approved a SIP revision that 
replaces our FIP. We are committed to work with ADEQ and the facility 
to partially withdraw our FIP with respect to the emission limits for 
the BART unit or revise the SIP if at some point in the future the 
company decides to permanently shut down, dismantle, and decommission 
the boiler and surrender the air permit.
    Further, we consider the conditions under which a unit is 
permanently retired and the mechanism by which this is made enforceable 
to be critical. Because the company has not decided if and when Power 
Boiler No. 1 will be permanently retired or decided what the conditions 
of the retirement will be, we believe that it is reasonable and 
appropriate to wait until the company makes these decisions instead of 
including a provision in our FIP that waives the BART recordkeeping 
requirements in anticipation that the unit's permanent retirement will 
take place under certain conditions and made enforceable through a 
particular mechanism that may be different from what ultimately takes 
place.
    Comment: If Power Boiler 2 is fuel switched to natural gas or 
retired as part of the Domtar Ashdown Mill's repurposing project, there 
is no need to retain the SO2 and PM BART limits and the 
associated monitoring, recordkeeping and reporting requirements for the 
SO2 and PM BART limits. The Ashdown Mill requests that EPA 
include in the FIP final rule an alternative compliance option which 
removes the SO2 and PM BART limits and the associated 
requirements if the boiler is fuel switched to natural gas or 
permanently retired. Additionally, if Power Boiler 2 is fuel switched 
to natural gas as part of the Domtar Ashdown Mill's repurposing 
project, the NOX BART requirements need to be modified to 
require compliance based on the use of AP-42 emission factors and fuel 
use records. The requirement to operate and maintain a NOX 
CEM needs to be removed. If Power Boiler 2 is retired, all the BART 
requirements are unnecessary. The Ashdown Mill requests that EPA 
include alternate compliance options in the FIP final rule provisions 
to address these potential scenarios.
    Response: We are finalizing an SO2 BART emission limit 
of 91.5 lb/hr and we are finalizing our determination that compliance 
with the Boiler MACT PM standard as revised satisfies the PM BART 
requirement for Power Boiler No. 2. We proposed to require the facility 
to demonstrate compliance with the SO2 emission limit for 
Power Boiler No. 2 using the existing CEMS, and to demonstrate 
compliance with the PM emission limit using the same method that is 
used for demonstrating compliance with the Boiler MACT PM standard. We 
are finalizing these methods for demonstrating compliance with the 
SO2 and PM emission limits for Power Boiler No. 2. With 
regard to the commenter's request that we include an alternate 
compliance option in our FIP that removes the SO2 and PM 
BART limits if the boiler is switched to natural gas, we do not have 
the authority to do this. The Regional Haze regulations define BART as 
an emission limitation based on the degree of reduction achievable 
through the application of the best system of continuous emission 
reduction for each pollutant which is emitted by an existing stationary 
facility.\163\ The BART emission limits are still applicable and are 
required regardless if the unit is switched to natural gas. However, 
the repurposing project the mill is currently undergoing and the 
possibility of Power Boiler No. 2 being converted to burn only natural 
gas render it appropriate to provide the facility with flexibility in 
demonstrating compliance with the SO2 and PM emission limits 
for Power Boiler No. 2. Therefore, we are providing one alternative 
method for demonstrating compliance with the SO2 and PM 
emission limits: The owner or operator may demonstrate compliance with 
these emission limits by switching Power Boiler No. 2 to burn only 
natural gas. Therefore, if Power Boiler No. 2 is switched to burn only 
pipeline quality natural gas, and the air permit is revised to reflect 
this change, this would satisfy the requirement for demonstrating 
compliance with the boiler's SO2 and PM BART emission 
limits, and the related reporting and recordkeeping requirements would 
be waived. Under these circumstances, the SO2 and PM BART 
determinations for Power Boiler No. 2 would continue to apply but the 
facility would be able to demonstrate compliance with these emission 
limits by virtue of switching to natural gas and it would not be 
required to use the existing CEMS to demonstrate

[[Page 66375]]

compliance with the SO2 BART emission limit. We are revising 
proposed Sec.  52.173 to reflect this.
---------------------------------------------------------------------------

    \163\ 40 CFR 51.301.
---------------------------------------------------------------------------

    We are requiring Power Boiler No. 2 to meet an emission limit of 
345 lb/hr to satisfy the NOX BART requirement. We proposed 
to require the facility to demonstrate compliance with this 
NOX emission limit using the existing CEMS, and we are 
finalizing this method for demonstrating compliance. However, the 
repurposing project the mill is currently undergoing and the 
possibility of Power Boiler No. 2 being converted to burn natural gas 
only render it appropriate to provide the facility with flexibility in 
demonstrating compliance with the NOX emission limit. 
Therefore, we are providing one alternative method for demonstrating 
compliance with the NOX emission limit: If Power Boiler No. 
2 is switched to burn only pipeline quality natural gas, and the air 
permit is revised to reflect this, the facility may demonstrate 
compliance with the NOX emission limit by calculating 
emissions using AP-42 emission factors and fuel usage records. Under 
these circumstances, the facility would not be required to use the 
existing CEMS to demonstrate compliance with the NOX BART 
emission limit. We are revising proposed Sec.  52.173 to reflect this.
    We do not have the authority to include in our FIP a provision that 
removes all SO2, NOX, and PM BART requirements 
for Power Boiler No. 2 if it is permanently retired in the future. As 
noted above, the Regional Haze regulations define BART as an emission 
limitation based on the degree of reduction achievable through the 
application of the best system of continuous emission reduction for 
each pollutant which is emitted by an existing stationary facility. The 
BART emission limits and applicable requirements continue to apply 
regardless if a BART source is mothballed or retired/shut down without 
being dismantled, decommissioned, and having the air permit revoked. In 
the event that the BART source is permanently shut down, dismantled, 
decommissioned, and the permit revoked in the future, the process for 
removing the BART emission limits and applicable requirements would 
necessarily involve a request for a partial FIP withdrawal or a SIP 
revision in the event that we have approved a SIP revision that 
replaces our FIP. We are committed to work with ADEQ and the facility 
to partially withdraw our FIP with respect to the emission limits for 
the BART unit or revise the SIP if at some point in the future the 
company decides to permanently shut down, dismantle, and decommission 
the boiler and surrender the air permit.
    Further, we consider the conditions under which a unit is 
permanently retired and the mechanism by which this is made enforceable 
to be critical. Because the company has not decided if and when Power 
Boiler No. 2 will be permanently retired or decided what the conditions 
of the retirement will be, we believe that it is reasonable and 
appropriate to wait until the company makes these decisions instead of 
including a provision in our FIP that waives the BART recordkeeping 
requirements in anticipation that the unit's permanent retirement will 
take place under certain conditions and made enforceable through a 
particular mechanism that may be different from what ultimately takes 
place.
    Comment: EPA proposes to require compliance with the SO2 
BART emission limit for Power Boiler 2 within 3 years of the effective 
date of the final rule. EPA also proposes compliance with the 
NOX BART emission limit within 3 years of the effective date 
of the final rule. With the mill transformation and re-purposing 
project and all of the work associated with this huge undertaking, the 
Ashdown Mill needs a 5-year compliance window from the effective date 
of the final rule for the SO2 and NOX BART 
requirements for Power Boiler 2 (assuming EPA decides to proceed with 
BART for the mill). As announced in late 2014, the mill is converting a 
paper machine to produce fluff pulp. This transformation project is 
being driven by the continued decline in the demand for paper products. 
Power 1 and Power Boiler 2 are part of the mill's steam generating 
components, and are operated to produce steam that is needed for the 
manufacturing of pulp and paper products. It is anticipated that this 
mill transformation project may significantly affect mill steam demands 
reducing the amount of steam needed from Power Boiler 1 and 2. 
Ultimately, this transformation project may determine future use of 
Power Boiler 2. Once the re-purposing and re-configuration of the mill 
systems is complete and fully operational, the mill will decide whether 
Power Boiler 2 will continue with full or intermittent operation, if 
so, using what fuels, or will it be permanently retired. In order to 
make this decision, the mill will need to go through the startup, 
initial operation and a shakedown period with the new fluff pulp 
process. Since this is a significant change for the mill it is 
uncertain how long it will take to learn how to operate and to optimize 
in this newly configured state. The mill will then need at least 2 
winter cycles to understand what the maximum steam demand requirements 
will be for the newly configured mill. The re-purposing project is 
scheduled to be completed and the newly configured mill is anticipated 
to start-up in late 2016. The mill will operate through the winter of 
2016-2017 and will be learning how to operate and optimize the new 
process. The winter of 2017-2018 will be the first real indicator of 
what winter steam demands will be in the re-purposed state. For the 
purposes of selecting an appropriate BART compliance schedule and 
future mill operations, the understanding of how the Power Boilers will 
operate and on what fuels is essential. The project schedule will set 
these key decision points in late 2018. Once the decision on mill steam 
needs and boiler utilization is made, additional time is required to 
implement the boiler scenario selected by the mill. These scenarios 
could range from the mothballing or retiring Power Boilers 1 or 2 to 
shifting fuels. In addition, changes involving the combustion of the 
NCG gases and the shared biomass feed system also need to be determined 
and new systems engineered and permitted, as needed. Another factor to 
be considered is determining the ability of the existing SO2 
scrubber to continuously operate at 90% removal on a long-term basis. 
If Power Boiler 2 continues to use solid fuels, additional time is 
needed to optimize the existing scrubber to consistently perform at 
this higher level of control efficiency on a long-term basis. Given the 
mill's interconnected nature as well as the complex aspects of the re-
purposing project, a 5-year compliance schedule for achieving the 
SO2 BART and NOX BART requirements for Power 
Boiler 2 is essential.
    Response: We have reconsidered the SO2 and 
NOX BART compliance dates for Power Boiler No. 2 in response 
to this comment. We understand the commenter's concerns with respect to 
how the transformation and repurposing project the mill is currently 
undertaking may significantly affect mill steam demands and may 
ultimately determine future use of Power Boiler No. 2. We understand 
that the mill will decide the future use of Power Boiler No. 2, 
including whether it will be converted to other fuels or permanently 
retired, after the repurposing and reconfiguration of the mill systems 
is complete and fully operational and after the mill has learned how to 
operate and to optimize in its newly configured state. Our 
understanding from the comments is that Ashdown Mill expects

[[Page 66376]]

to make this decision in late 2018, but that additional time will be 
needed to implement the boiler scenario selected by the mill, which 
could include switching fuels, mothballing or retiring the boilers, or 
continued operation and combustion of solid fuels and installation of 
air pollution controls to meet the BART emission limits. It is not 
EPA's intention to place an undue burden on the Domtar Ashdown Mill by 
requiring a compliance date that may not provide sufficient time for 
the mill to install controls or otherwise make the necessary operating 
changes to meet the boiler's BART emission limits. While we believe 
that a 3-year compliance date is generally sufficient for installation 
of the controls on which the BART emission limits are based, due to the 
special circumstances in this case we believe that it is reasonable and 
appropriate to establish a longer compliance date particularly since it 
could avoid unnecessary investment in a scrubber that may be no longer 
needed due shutdown or fuel switch. Therefore, we are requiring that 
the mill comply with the SO2 and NOX BART 
emission limits no later than 5 years from the effective date of this 
final rule and have amended the proposed regulatory text to reflect 
this change. We believe that this adequately addresses the commenter's 
concerns while in keeping with the CAA mandate that compliance with 
BART requirements must be as expeditiously as practicable but in no 
event later than 5 years after promulgation of this FIP.

F. Other Compliance Dates

    Comment: EPA proposed compliance with the SO2 and 
NOX BART limits for Power Boiler 1 and for the PM BART limit 
for Power Boiler No. 2 to be on the effective date of the final rule. 
Should EPA proceed with imposing these BART limits, the Ashdown Mill 
requests the compliance date be changed to 30 calendar days after 
effective date of the final rule. That will give the mill additional 
time to prepare the compliance records if there is a short period 
between when the rule is promulgated and the effective date, especially 
if the effective date of the final rule falls on a weekend or a 
holiday. In addition, if any confusion exists regarding exactly when 
the effective date is, the cushion of 30 days helps to provide more 
certainty. This extra time will be needed if EPA finalizes any changes 
to definitions or other requirements that require the Ashdown to adjust 
recordkeeping systems.
    Response: We are finalizing a NOX BART emission limit of 
207.4 lb/hr for Power Boiler No. 1, which is what we proposed. We 
proposed an SO2 BART emission limit of 21.0 lb/hr for Power 
Boiler No. 1, and as discussed in section IV. of this final rule, we 
are finalizing an emission limit of 504 lb/day. We are finalizing our 
determination that compliance with the Boiler MACT PM standard 
satisfies the PM BART requirement for Power Boiler No. 2. As discussed 
elsewhere in this section of the final rule, we are finalizing some 
changes to the definitions and BART requirements for Power Boiler No. 
1. After carefully considering this comment, we have determined that 
extending the compliance dates associated with the aforementioned BART 
emission limits for Power Boiler No. 1 is appropriate because it is a 
reasonable request that will allow the owner or operator of the 
affected facility to prepare applicable compliance records and adjust 
recordkeeping systems without unduly delaying compliance with the BART 
requirement. Therefore, we are revising the compliance dates we 
proposed for the SO2 and NOX BART emission limits 
for Power Boiler No. 1 and the PM BART requirement for Power Boiler No. 
2 such that the owner or operator must comply with these emission 
limits no later than 30 calendar days from the effective date of the 
final rule.
    Comment: EPA's proposed BART requirements will require installation 
of new emission controls on utility electric generation resources at a 
significant cost. The utilities will pass these costs on to Arkansas 
ratepayers. The Ashdown Mill, like other energy intensive 
manufacturers, will be affected by the increasing cost of electric 
power needed to operate our processes. EPA should also consider other 
emerging regulatory initiatives that will be driving substantial 
changes to major coal burning facilities. Manufacturing facilities, 
such as the Ashdown Mill, are undertaking major transformation projects 
that potentially may result in a move away from coal and other emerging 
regulations targeting utilities are likely to further reduce coal 
burning and further remove visibility concerns. A practical alternative 
to EPA's proposed compliance dates is for EPA to use its discretion 
under the Regional Haze Rule and delay the Arkansas BART requirements 
for all sources for five years. This will align compliance timelines so 
that the full effects of all of these regulatory changes will be known. 
Facilities affected by these other requirements can plan holistic 
compliance strategies rather than being compelled to follow an 
expensive and potentially wasteful piecemeal approach. Using the 
maximum 5-year window allowed under BART will provide the Ashdown Mill 
the time to determine if coal will continue as a fuel for the facility. 
It will also provide the other affected sources in Arkansas with time 
to address the Clean Power Plan strategies and other significant 
regulatory programs that may also remove coal as a fuel. The effect of 
allowing a full 5-year compliance program will thereby minimize the 
potential for stranded assets and minimize the cost increases on 
companies and on ratepayers. This approach is further compelled by the 
fact that Arkansas is more than meeting its ``glide path'' as discussed 
above.
    Response: We acknowledge the commenter's concerns related to the 
potential increase in utility rates for Arkansas ratepayers as well as 
to potential requirements related to other CAA and EPA regulatory 
actions. We agree that multiple regulatory actions are pending that 
will affect the power sector and that regulatory development should be 
coordinated when possible while still meeting the statutory and 
regulatory requirements for compliance. We also recognize the 
importance of long-term and coordinated planning on the parts of owners 
of industrial sources that are subject to BART. However, we disagree 
that our FIP presents a tight or unreasonable regulatory timeline. It 
is an appropriate timeline for cost-effective control measures needed 
to meet the regional haze requirements.
    The CAA and Regional Haze Rule require the installation and 
operation of BART, in particular, to be carried out expeditiously. The 
CAA defines the term ``as expeditiously as practicable'' to mean ``as 
expeditiously as practicable but in no event later than five years 
after the date of approval of a [Regional Haze] plan revision. . . .'' 
\164\ Therefore, we do not have the authority to delay compliance dates 
across the board for all subject-to-BART sources in Arkansas to allow 
time for greater certainty regarding requirements associated with other 
CAA and regulatory requirements. We also disagree that ADEQ's finding 
that Arkansas Class I areas are projected to be below the URP glidepath 
in 2018 is sufficient justification for delaying the compliance dates 
for all subject-to-BART sources in Arkansas. We address other more 
specific comments related to this issue in a separate response.
---------------------------------------------------------------------------

    \164\ CAA section 169A(b)(2)(A) and (g)(4).
---------------------------------------------------------------------------

    In determining what is ``as expeditiously as practicable'' for 
installation and operation of a particular control technology, the 
states and EPA

[[Page 66377]]

usually consider the amount of time it generally takes to install and 
operate that type of technology at similar sources and the compliance 
dates that have been required for the installation and operation of the 
same type of control technology at similar sources in other regional 
haze actions, especially if there are no source-specific considerations 
or other special circumstances that would prevent the source from 
installing and operating the control technology within the same amount 
of time. For example, where a particular control technology can 
generally be installed and operated in 3 years, and where there are no 
source-specific considerations or other special circumstances that 
would affect the facility's ability to install and operate the control 
technology within that time frame, it would not be in accordance with 
the CAA and the Regional Haze Rule to allow a 5-year compliance period 
because that would not be as expeditiously as practicable. 
Additionally, considering that most other states already have plans in 
place that fully address the regional haze requirements, it would be 
inequitable and contrary to the intent of the CAA and the Regional Haze 
Rule to further delay implementation of regional haze requirements in 
Arkansas by allowing a 5-year compliance date across the board for all 
of Arkansas' subject-to-BART sources. Therefore, we disagree that it is 
appropriate for us to allow a 5-year compliance date for all subject-
to-BART sources in Arkansas, rather than establishing deadlines 
consistent with the facts and regulatory requirements in each instance.
    We do note that we are revising some of the compliance dates we 
proposed in response to source-specific considerations raised in other 
comments. We address these comments in separate responses.
    Comment: If EPA's final SO2 BART determination for Flint 
Creek Unit 1 is based on installation of a NID dry scrubber, EPA should 
impose a shorter compliance deadline, as required by the Act. EPA's 
proposed FIP requires Flint Creek Unit 1 to comply with the 
SO2 BART determination within five years from the effective 
date of the final rule. Yet the statute requires a source to comply 
with BART as expeditiously as possible, but no later than five years 
from the effective date of EPA's action on the regional haze plan.\165\ 
AEP could install a NID scrubber at Flint Creek much more expeditiously 
than five years from the effective date of the rule. The utility has 
already obtained an Arkansas PSC order finding that NID dry scrubber 
installation is in the public interest.\166\ ADEQ has already issued a 
Title V air permit for scrubber construction and operation at Flint 
Creek.\167\ Further, it appears that on-site construction of the NID 
scrubber has begun, and that the Flint Creek owners intend to operate 
it by May 29, 2016, in order to comply with EPA's MATS rule.\168\ Thus, 
given that AEP is currently installing the NID scrubber with a May 2016 
planned operation date, EPA's five-year SO2 BART compliance 
deadline does not comply with the statutory requirement that BART 
controls be installed ``as expeditiously as practicable,'' \169\ Since 
AEP is installing the NID scrubber for MATS as well as BART compliance, 
EPA should require SO2 BART compliance at Flint Creek by no 
later than May 29, 2016.
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    \165\ 40 CFR 51.308(e)(1)(iv).
    \166\ See 7/10/2013 SWEPCO News Release, SWEPCO Receives 
Arkansas Commission Approval for Flint Creek Plant Project, at 
https://www.swepco.com/info/news/viewRelease.aspx?releaseID=1424.
    \167\ See Stamper Report at 14 (citing October 25, 2013 Permit 
No. 0276-AOP-R6 at 5 (Ex. 29 to Stamper Report)).
    \168\ Stamper Report at 14 (citing Flint Creek Retrofit Project, 
SWEPCO News & Info Site at https://swepco.com/info/projects/FlintCreek/; March 26, 2014 Independent Monitor Report for AEP Flint 
Creek Plant Unit 1, submitted to the Arkansas Public Service 
Commission under Docket No. 12-008-U, at (Ex. 30 to Stamper 
Report)).
    \169\ CAA section 169A(b)(2)(A).
---------------------------------------------------------------------------

    Response: We acknowledge the information provided by the commenter 
regarding AEP Flint Creek's plans to complete installation of the NID 
system in 2016 in order to comply with 40 CFR part 63, subpart UUUUU--
National Emission Standards for Hazardous Air Pollutants: Coal- and 
Oil-Fired Electric Utility Steam Generating Units, otherwise known as 
the Utility MATS Rule. MATS establishes emission limits for three 
categories of pollutants: Mercury, acid gases (HCl and SO2), 
and non-mercury hazardous air pollutant (HAP) metals. To address acid 
gases, an EGU must comply with an HCl emission limit unless it is 
equipped with a wet or dry FGD or DSI and an SO2 CEMS, in 
which case it has the option of complying with an alternative 
SO2 emission limit. The applicable alternative 
SO2 emission limit is 0.2 lb/MMBtu.
    The commenter has made us aware that the Arkansas PSC has 
determined that dry scrubber installation at Flint Creek is in the 
public interest and that the installation of those controls is already 
underway and anticipated by the company to be complete by May 29, 2016. 
The commenter also points to the air permit issued to Flint Creek by 
ADEQ on October 25, 2013, which allows for the installation and 
operation of new control equipment and associated material handling 
systems to comply with the requirements of the Utility MATS Rule. These 
controls include a NID system on Unit 1. The AEP-SWEPCO Web site also 
indicates that the installation of these scrubber controls is driven by 
MATS and future Regional Haze rules.\170\ A timeline provided on the 
Web site states that construction of these controls began in October 
2013 and that installation will be complete and the facility will be 
operating with these controls by the end of May 2016. In addition, the 
commenter has made us aware that the Arkansas PSC requires Flint Creek 
to provide quarterly reports on the progress of the installation of 
these controls. The first report the company submitted to the Arkansas 
PSC is dated March 26, 2014, and stated that the FGD project includes 
the installation of an Alstom NID system to comply with MATS and in 
anticipation of the BART requirements. The report also stated that the 
NID system and associated equipment are to be constructed at Flint 
Creek Unit 1, and that the company established design, procurement, and 
construction schedules to bring the upgraded plant fully on line by May 
29, 2016. The commenter provided the report as an attachment to the 
comments submitted, but this and all other quarterly reports the 
company submitted to the Arkansas PSC are available online.\171\ The 
most recent quarterly report available on the Arkansas PSC Web site is 
dated March 10, 2016, and covers the fourth quarter in 2015. This 
report indicated that the company still expected the upgraded plant to 
be fully on line by May 29, 2016. We verified the status of the 
installation of the controls with the company, who confirmed that 
installation of the NID controls was completed in June 2016, and that 
the plant is now operating with those controls.\172\
---------------------------------------------------------------------------

    \170\ https://www.swepco.com/info/projects/FlintCreek/.
    \171\ See the Arkansas PSC Web site at http://www.apscservices.info/efilings/docket_search.asp. The quarterly 
reports the company is required to submit to the Arkansas PSC are 
available by searching for docket No. 12-008-U.
    \172\ See file titled ``Record of Call- Flint Creek_August 10 
2016,'' which is found in the docket for this rulemaking.
---------------------------------------------------------------------------

    After carefully considering the information the commenter has 
brought to our attention, we no longer believe that a 5-year compliance 
date is appropriate for the SO2 BART controls

[[Page 66378]]

we are requiring for Flint Creek. We agree with the commenter that BART 
controls must be installed as expeditiously as practicable. CAA section 
169A(b)(2)(A). Therefore, we are finalizing a shorter compliance date. 
The information made available to us during the comment period, as 
discussed above, indicates that Flint Creek intends to operate the NID 
system to comply with the alternative SO2 emission limit 
under the Utility MATS rule. The applicable SO2 emission 
limit is 0.2 lb/MMBtu. The SO2 emission limit we are 
requiring in our FIP to satisfy the BART requirement is 0.06 lb/MMBtu. 
As indicated in the information and other documentation the commenter 
provided, the company plans to use the same NID system to comply with 
MATS and to comply with the facility's SO2 BART requirement. 
We expect that to achieve an emission rate of 0.06 lb/MMBtu, additional 
scrubbing reagent would be needed beyond that required to meet the 0.2 
lb/MMBtu emission limit the company is required to meet by April 2016 
under MATS. We also recognize that it is possible that the reagent 
handling system installed to meet the 0.2 lb/MMBtu emission limit would 
need some upgrades in order to accommodate the additional scrubbing 
reagent that would be needed to achieve the more stringent 0.06 lb/
MMBtu emission limit we are requiring in this FIP. Therefore, to allow 
the facility sufficient time to secure the additional scrubbing reagent 
that would be needed to comply with the SO2 BART emission 
limit and to make any necessary upgrades to the reagent handling 
system, we are finalizing an 18-month compliance date for Flint Creek 
Unit 1 to comply with the SO2 BART requirement. We believe 
this is will provide sufficient time for the facility to be able to 
achieve the SO2 BART requirement while still meeting the 
statutory mandate that BART controls be installed as expeditiously as 
practicable.
    Comment: If EPA's final NOX BART determination for White 
Bluff is based on installation of a SCR with LNB/SOFA, EPA should 
require a NOX BART compliance date for SCR at White Bluff of 
no later than within 3 years of the final rule's effective date, which 
would represent the expeditious implementation required by CAA section 
169A(b)(2)(A). The NOX BART compliance date for LNB/SOFA 
should be 8 months from the final rule's effective date. If EPA 
finalizes its proposal to require LNB/SOFA only as NOX BART 
for White Bluff, EPA should require compliance within 8 months of the 
final rule's effective date. Eight months is sufficient time for 
installation of these controls. These same comments apply and should be 
extended to EPA's reasonable progress determination for NOX 
for Independence Units 1 and 2.
    Response: We are requiring White Bluff Units 1 and 2 and 
Independence Units 1 and 2 to each meet a NOX emission limit 
of 0.15 lb/MMBtu on a 30 boiler-operating-day rolling average, where 
the average is to be calculated by including only the hours during 
which the unit was dispatched at 50% or greater of maximum capacity. In 
addition, we are requiring each unit to meet a NOX emission 
limit of 671 lb/hr on a rolling 3-hour average that is applicable only 
when the unit is being operated at less than 50% of the unit's maximum 
heat input rating. These emission limits are consistent with the 
installation and operation of LNB/SOFA controls. In light of the 
comment, we have reconsidered the compliance date for the 
NOX BART requirements for White Bluff Units 1 and 2 and for 
the NOX controls under reasonable progress for Independence 
Units 1 and 2. Based on the supporting information provided by the 
commenter, we agree with the commenter that 6-8 months is the typical 
installation timeframe for LNB/OFA controls.\173\ However, in 
determining the appropriate compliance date for these NOX 
controls, we have also taken into consideration that we are finalizing 
NOX emission limits that are based on LNB/OFA or LNB/SOFA 
controls for a total of five EGUs in this FIP and that the installation 
of these controls will require outage time. These five EGUs are Flint 
Creek Unit 1, White Bluff Units 1 and 2, and Independence Units 1 and 
2, and combined they accounted for approximately 45% of the state's 
2015 heat input. Because of the heavy reliance on these EGUs for 
electricity generation in the state, we recognize that it may be 
difficult to schedule outage time to install LNB/OFA or LNB/SOFA on all 
five of these Arkansas units within the typical installation timeframe 
of 6-8 months and at the same time supply adequate electricity to meet 
demand in the state. In light of these unique circumstances, we find 
that it is appropriate to finalize an 18-month compliance date for 
White Bluff Units 1 and 2, Independence Units 1 and 2, and Flint Creek 
Unit 1 to comply with the NOX emission limits required by 
this FIP. This compliance date provides the affected utilities 
sufficient time beyond typical LNB/OFA installation timeframes to 
install these controls and comply with their NOX emission 
limits, while safeguarding the continuity of Arkansas' electricity 
supply.
---------------------------------------------------------------------------

    \173\ See comments and exhibits submitted by Earthjustice, the 
National Parks Conservation Association, and Sierra Club, dated 
August 7, 2015. These and all other comments submitted during the 
public comment period are found in the docket associated with this 
rulemaking.
---------------------------------------------------------------------------

    We address comments contending that we should require SCR controls 
on White Bluff and Independence elsewhere in this final rule and in our 
RTC document.
    Comment: One commenter noted that the proposed FIP would require 
Flint Creek Unit 1 to comply with the NOX BART requirement 
within 3 years of the effective date of the rule. The commenter argued 
that if EPA's final NOX BART determination for Flint Creek 
is based on installation of LNB/OFA, EPA should establish a shorter 
compliance deadline since compliance with BART is required as 
expeditiously as practicable.\174\ The commenter contends that AEP has 
been planning for the installation of LNB/OFA and that construction has 
already begun. The commenter argues that since the utility is currently 
installing LNB/OFA with a May 2016 planned operation date, EPA should 
require a NOX BART compliance date of no later than May 2016 
in order to ensure the expeditious implementation required by law.
---------------------------------------------------------------------------

    \174\ 40 CFR 51.308(e)(1)(iv).
---------------------------------------------------------------------------

    AEP/SWEPCO, which is one of the owners of Flint Creek, also 
commented on our proposed NOX BART compliance date for Flint 
Creek Unit 1. The company stated that if EPA does not rely on CSAPR to 
satisfy the NOX BART requirement for EGUs in Arkansas, it 
supports EPA's determination of LNB/OFA controls as BART and the 
associated limits proposed by EPA. But the company stated that the 
proposed 3-year compliance timeframe is unreasonable. The company 
stated that the compliance time frame must allow for planning, 
selection of engineering and design professionals, vendors, 
contractors, permitting, start up and commissioning, and coordinating 
and scheduling unit outages. The company also argued that since EPA has 
allowed installation schedules up to 5 years in other states, we should 
allow such a time frame here.
    Response: We are finalizing our determination that NOX 
BART for AEP Flint Creek Unit 1 is an emission limit of 0.23 lb/MMBtu 
on a 30 boiler-operating-day rolling average, which is consistent with 
the installation and operation of LNB/OFA. The commenter has not 
provided sufficient information to corroborate the claim that 
installation of LNB/OFA at Flint Creek Unit 1 is

[[Page 66379]]

expected to be completed by May 2016. We acknowledge that on July 10, 
2013, the Arkansas PSC filed an order agreeing that the installation of 
additional environmental controls at Flint Creek Unit 1, including LNB/
OFA to meet the NOX BART requirement, is in the public 
interest.\175\ In the attachments to the comment, the commenter points 
to a news article that references a January 21, 2014 report submitted 
by AEP/SWEPCO to the Arkansas PSC.\176\ In that January 21, 2014 
report, AEP/SWEPCO announces that construction of environmental 
controls at Flint Creek commenced on January 20, 2014.\177\ However, 
the January 21, 2014 report does not specify if this includes 
construction of LNB/OFA. While we acknowledge that there is publicly 
available information indicating that the company planned to complete 
installation of a NID system and activated carbon injection by May 2016 
to comply with the Utility MATS rule, there is no information available 
to us corroborating that the expected date of LNB/OFA installation was 
also May 2016. In fact, the comments submitted by AEP/SWEPCO indicate 
that the company has not begun installation of these controls.\178\ 
With regard to AEP/SWEPCO's request that we extend the compliance date 
to 5 years, we have determined that the company has not provided any 
information regarding any special circumstances specific to the 
facility that sets it apart from other facilities and that would 
prevent it from completing installation of controls within typical 3-
year LNB/OFA installation timeframes.
---------------------------------------------------------------------------

    \175\ See Arkansas Public Service Commission, Docket No. 12-008-
U, Order No. 14, dated July 10, 2013. A copy of the order can be 
found at http://www.apscservices.info/pdf/12/12-008-u_227_1.pdf.
    \176\ See the document titled ``Technical Support Document to 
Comments of Conservation Organizations,'' which is an attachment to 
the comments submitted by Earthjustice, the National Parks 
Conservation Association, and Sierra Club. These and all other 
comments submitted during the public comment period are found in the 
docket associated with this rulemaking.
    \177\ http://www.apscservices.info/pdf/12/12-008-u_238_1.pdf.
    \178\ See the comments submitted by AEP-SWEPCO, dated July 15, 
2015 and August 7, 2015. These and all other comments submitted 
during the public comment period are found in the docket associated 
with this rulemaking.
---------------------------------------------------------------------------

    Additionally, as discussed in a previous response, we agree that 
LNB/OFA can typically be installed within a 6-8 month timeframe. 
However, in determining the appropriate compliance date for these 
NOX controls, we have also taken into consideration that we 
are finalizing NOX emission limits that can be achieved by 
the installation of LNB/OFA or LNB/SOFA controls for a total of 5 EGUs 
in this FIP. Because of the heavy reliance on these EGUs for 
electricity generation in the state and because it may be difficult to 
schedule outage time to install these controls on all five of these 
units within the typical installation timeframe of 6-8 months without 
disrupting the supply of electricity in the state, we are finalizing an 
18-month compliance date for Flint Creek Unit 1 and the other EGUs to 
comply with the NOX emission limits required by this FIP.

G. Compliance Demonstration Requirements

    Comment: For purposes of BART for the Domtar Ashdown Mill Power 
Boiler No. 1 and Power Boiler No. 2, EPA is defining boiler operating 
day as a 24-hour period between 12 midnight and the following midnight 
during which any fuel is fed into and/or combusted at any time in the 
power boiler, consistent with the guidelines for utility boilers. 
However, the Ashdown Mill boilers are industrial boilers, not utility 
boilers. The Ashdown Mill defines a mill operating day to be a 24-hour 
period between 6 a.m. and 6 a.m. the following day. All of the mill's 
systems for Power Boilers No. 1 and 2 are programmed around this 
definition of a mill operating day and modification of these systems 
would require a significant amount of effort and would require the 
gathering and maintaining of multiple sets of records. Assuming EPA 
proceeds with BART for the Ashdown Mill, the mill requests that for 
Power Boiler No. 1 and Power Boiler No. 2 a boiler operating day be 
defined as ``a 24-hr period between 6 a.m. and 6 a.m. the following day 
during which any fuel is fed into and/or combusted at any time in the 
power boiler.'' Harmonizing the definitions of a boiler operating day 
and a mill operating day does not increase costs for the mill, reduces 
confusion for the mill operators, eliminates the need for maintaining 
multiple sets of records, and eliminates the need for changes to 
existing monitoring systems. We believe EPA is authorized or can use 
its discretion to define a boiler operating day for the Ashdown Mill to 
be consistent with the mill's boiler operating day definition.
    Response: After carefully considering the comment, we agree that 
Domtar's request is reasonable and that it is appropriate to harmonize 
the definitions of a boiler operating day and a mill operating day to 
avoid any unnecessary modification or reprogramming of Power Boilers 1 
and 2. To accommodate Domtar's request, for purposes of Power Boiler 1 
and Power Boiler 2, in this final action we are defining a boiler 
operating day as ``a 24-hr period between 6 a.m. and 6 a.m. the 
following day during which any fuel is fed into and/or combusted at any 
time in the power boiler.'' We are revising proposed Sec.  52.173 to 
reflect this.
    Comment: EPA proposed to require compliance with the BART 
NOX limit for the Domtar Ashdown mill Power Boiler No. 1 be 
demonstrated with an annual stack test. Domtar agrees in general that 
stack testing is an appropriate method for demonstrating compliance. 
However, EPA's proposal to require stack testing annually is not 
appropriate. Historical NOX stack test data from 2001, 2002, 
2003, 2004, 2005, and 2010 for Power Boiler 1 show NOX 
emissions to be fairly consistent. Based on the numerous previous stack 
tests, conducting stack tests annually is not warranted. Should EPA 
proceed with BART for the Ashdown Mill, the facility is requesting that 
stack testing to demonstrate compliance with the BART NOX 
limit be required every 5 years instead of annually, which is 
consistent with the Ashdown Mill's Title V permit requirements.
    Response: After carefully considering the comment, we have 
reconsidered our proposed requirement of annual stack testing. We agree 
that the results of the NOX stack testing conducted by 
Domtar for Power Boiler No. 1 demonstrate that NOX emissions 
have historically remained well below the NOX emission limit 
we are finalizing for the boiler.\179\ Therefore, we agree with the 
company that it is appropriate to require stack testing every 5 years 
instead of annually. In our final action we are requiring that the 
facility demonstrate compliance with the NOX BART emission 
limit for Power Boiler No. 1 by conducting stack testing every five 
years, beginning no later than 1 year from the effective date of our 
final action. As discussed in a separate response, we are also 
providing one alternative method for demonstrating compliance with the 
NOX BART emission limit for Power Boiler No. 1. 
Specifically, if the facility's air permit is revised to reflect that 
Power Boiler No. 1 is permitted to burn only natural gas, the facility 
may demonstrate compliance with the NOX emission limit by 
calculating emissions using AP-42 emission factors and fuel usage 
records. Under these circumstances, the

[[Page 66380]]

facility would not be required to demonstrate compliance with the 
NOX BART emission limit for Power Boiler No. 1 through stack 
testing. We are revising proposed Sec.  52.173 to reflect this.
---------------------------------------------------------------------------

    \179\ See Excel file titled ``Email from Domtar Regarding NOx 
Stack Test for PB1,'' found in the docket for this final rule. The 
data provided by Domtar indicate that out of the stack testing 
conducted in 2001, 2002, 2003, 2004, 2005, and 2010, the highest 
NOX emission rate from Power Boiler No. 1 was 171.3 lb/
hr, compared to the 207.4 lb/hr NOX emission limit we are 
finalizing.
---------------------------------------------------------------------------

    Comment: Assuming EPA proceeds with BART for the Domtar Ashdown 
Mill, the mill agrees with the proposed BART PM limit of 0.44 lb/MMBTU 
for Power Boiler No. 2 based on the MACT standard for the ``biomass 
hybrid suspension grate'' sub-category contained in the 2013 Boiler 
MACT final rule. The Ashdown Mill agrees with EPA's approach of relying 
on the Boiler MACT standards for PM to satisfy the PM BART requirement. 
However, for this streamlined BART approach, EPA must also ensure that 
the monitoring, recordkeeping, reporting requirements for PM BART are 
consistent with the monitoring, recordkeeping and reporting 
requirements under Boiler MACT. Deviating from the MACT requirements 
will result in additional administrative burden for the facility in 
maintaining ``multiple sets of compliance books.'' It also will create 
confusion for external stakeholders if different values and information 
are being reported.
    Response: We generally agree with the comment. We proposed to find 
that the Domtar Ashdown Mill may rely on compliance with the Boiler 
MACT PM standard to satisfy the PM BART requirement for Power Boiler 
No. 2, and we did not intend for our FIP to establish requirements for 
compliance demonstration, monitoring, recordkeeping, and reporting 
different from those the mill is already required to comply with under 
the Boiler MACT PM standard. In our proposal, our intent was to propose 
requirements for compliance demonstration, monitoring, recordkeeping, 
and reporting for the PM BART limit for Power Boiler No. 2 that are 
consistent with those under the Boiler MACT PM standard. However, the 
commenter has brought to our attention that only some of the compliance 
demonstration, monitoring, recordkeeping, and reporting requirements 
associated with the Boiler MACT PM standard were included under our 
proposed Sec.  52.173(c)(21) and (22) and that it appeared that we were 
proposing a separate and distinct set of requirements associated with 
our PM BART determination for Power Boiler No.2. Therefore, to ensure 
clarity and consistency, we are revising the regulatory text found 
under 40 CFR 52.173(c) that applies to Power Boiler No. 2 for PM BART 
to state that the mill shall rely on compliance with the Boiler MACT PM 
standard under 40 CFR part 63 Subpart DDDDD as revised to satisfy the 
PM BART requirement for Power Boiler No. 2. We interpret this to mean 
that compliance with the applicable Boiler MACT PM standard as revised 
is sufficient to demonstrate compliance with the PM BART requirement. 
We are not establishing a separate set of requirements for compliance 
demonstration, monitoring, recordkeeping, and reporting (i.e., in 
addition to those already required under the Boiler MACT PM standard, 
as revised), that Power Boiler No. 2 is required to comply with to 
satisfy the PM BART requirement.

H. Reliance on CSAPR Better Than BART

    Comment: Arkansas is subject to a Cross-State Air Pollution Rule 
(CSAPR, also referred to as the Transport Rule) FIP for ozone-season 
NOX. EPA should not require sources that are subject to the 
CSAPR FIP to also install BART or additional emissions controls based 
on a reasonable progress analysis. The Regional Haze Rule allows states 
to implement an alternative program in lieu of BART so long as the 
alternative program has been demonstrated to achieve greater reasonable 
progress toward the national visibility goal than would BART.\180\ EPA 
published CSAPR as a replacement to CAIR on August 8, 2011.\181\ In the 
final Transport rule, EPA demonstrated that CSAPR would make greater 
reasonable progress toward national visibility goals than would 
BART.\182\ EPA concluded in the final Transport rule that a state in 
the CSAPR region whose EGUs are subject to the requirements of the 
CSAPR trading program for ozone season NOX may rely on EPA's 
finding that CSAPR makes greater reasonable progress than source-
specific NOX BART. Despite EPA's demonstration that CSAPR 
makes greater reasonable progress than source-specific BART, EPA makes 
no mention of CSAPR emissions controls in the FIP proposal and requires 
source specific NOX BART for Arkansas EGUs that are covered 
by CSAPR. The approach that EPA has proposed for Arkansas is 
inconsistent with that taken for other states. EPA promulgated FIPs to 
replace reliance on CAIR with reliance on CSAPR for the following 
states: Georgia, Indiana, Iowa, Kentucky, Michigan, Missouri, Ohio, 
Pennsylvania, South Carolina, Tennessee, Virginia and West Virginia. 
Similarly, Virginia is revising the Virginia Regional Haze SIP to rely 
on the Virginia CSAPR FIP to meet BART and reasonable progress 
requirements for SO2 and NOX. Perhaps most 
noteworthy, EPA has proposed reliance on CSAPR in states that border 
Arkansas. The Texas-Oklahoma Regional Haze FIP proposal does not 
require BART for sources that are subject to CSAPR.\183\ In that FIP 
proposal, EPA reiterates its position that ``CSAPR, like CAIR, provides 
for greater reasonable progress towards the national goal than would 
BART,'' \184\ and proposes replacing reliance on CAIR with reliance on 
the trading programs of CSAPR as an alternative to SO2 and 
NOX BART for Texas EGUs.\185\ Not only is EPA requiring 
Arkansas EGUs covered by CSAPR to control emissions under BART in the 
FIP proposal, but EPA has not even considered CSAPR as an option for 
making reasonable progress. Even if EPA ultimately rejected CSAPR as a 
means to meet the reasonable progress requirements under the Regional 
Haze Rule, EPA is required to cogently explain why it has exercised its 
discretion in a given manner. EPA's failure to consider CSAPR is 
arbitrary and capricious in light of its treatment of other states. EPA 
should withdraw the FIP proposal and remove the source-specific 
NOX BART requirements for Arkansas EGUs that are covered by 
CSAPR in any subsequently proposed plan.
---------------------------------------------------------------------------

    \180\ 40 CFR 51.308(e); 77 FR 33642.
    \181\ 76 FR 48208.
    \182\ 77 FR 33642 (June 7, 2012).
    \183\ Approval and Promulgation of Implementation Plans; Texas 
and Oklahoma; Regional Haze State Implementation Plans; Interstate 
Transport State Implementation Plan To Address Pollution Affecting 
Visibility and Regional Haze; Federal Implementation Plan for 
Regional Haze and Interstate Transport of Pollution Affecting 
Visibility, 79 FR 74818.
    \184\ 79 FR 74818, 74851.
    \185\ 79 FR 74818, 74853.
---------------------------------------------------------------------------

    Response: Arkansas EGUs are subject to CSAPR for ozone season 
NOX, and we acknowledge that a state in the CSAPR region 
whose EGUs are subject to the requirements of the CSAPR trading program 
for ozone season NOX may rely on CSAPR to satisfy the 
NOX BART requirement for its EGUs. However, when standing in 
the shoes of a state and promulgating a FIP, EPA has the same 
discretion as the state to choose to either conduct source-specific 
BART determinations or to rely on EPA's 2012 finding that CSAPR is 
better than BART. Our decision to make source-specific NOX 
BART determinations for Arkansas is reasonable for multiple reasons: It 
is the approach Congress chose in the statute itself; \186\ it is 
consistent with Arkansas' earlier decision to conduct

[[Page 66381]]

source-specific NOX BART determinations in lieu of relying 
on CAIR to meet the BART requirements; and at the time of our proposed 
action, it properly accounted for uncertainty in the CSAPR better-than-
BART regulation created by ongoing litigation regarding the CSAPR 
program. Further explanation of these reasons is given below.
---------------------------------------------------------------------------

    \186\ See CAA section 169A(g)(2) in which Congress defined the 
five factor analysis for determining BART but did not expressly 
provide for an alternative to source by source BART.
---------------------------------------------------------------------------

    The Regional Haze regulations provide generally that ``[a] State 
may opt'' to rely on an emissions trading program rather than to 
require source-specific BART controls.\187\ More specifically, in 2005 
EPA revised the Regional Haze regulations to provide that a state 
subject to CAIR ``need not require affected BART-eligible EGUs to 
install, operate, and maintain BART.'' \188\ Following the D.C. 
Circuit's vacatur and remand of CAIR,\189\ EPA issued CSAPR as a 
replacement rule. EPA revised its regulations in 2012 to allow states 
to rely on CSAPR in lieu of source-specific BART.\190\
---------------------------------------------------------------------------

    \187\ 40 CFR 51.308(e)(2).
    \188\ 70 FR 39104, 39156 (July 6, 2005).
    \189\ North Carolina v. EPA, 531 F.3d 896 (D.C. Cir. 2008).
    \190\ 77 FR 33642.
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    In its 2008 regional haze SIP submittal, Arkansas decided to not 
rely on CAIR to satisfy the NOX BART requirement for its 
EGUs.\191\ In our Regional Haze FIP proposal for Arkansas, we did not 
rely on CSAPR (the follow up rule to CAIR) to satisfy the 
NOX BART requirement for EGUs because we chose to follow the 
same source-specific approach to NOX BART that Arkansas 
selected in its Regional Haze SIP submittal. In addition, litigation 
surrounding CSAPR was ongoing at the time that we issued our proposed 
Arkansas Regional Haze FIP. CSAPR was issued in 2011, but on December 
30, 2011, the D.C. Circuit stayed the rule prior to implementation. The 
D.C. Circuit subsequently vacated CSAPR, an action later reversed by 
the Supreme Court in 2014. The case was then remanded to the D.C. 
Circuit. Then, after our April 2015 Regional Haze FIP proposal, the 
D.C. Circuit issued a July 2015 decision in EME Homer City Generation 
v. EPA \192\ upholding CSAPR but remanding without vacatur a number of 
the Rule's state NOX and SO2 emissions budgets. 
Arkansas' ozone season NOX budget is not itself affected by 
the remand. However, the Court's remand of the affected states' 
emissions budgets has implications for CSAPR better-than BART, since 
the demonstration underlying that rulemaking relied on the emission 
budgets of all states subject to CSAPR, including those that the D.C. 
Circuit remanded, to establish that CSAPR provides for greater 
reasonable progress than BART. As of the time EPA is taking this action 
to finalize Arkansas' Regional Haze FIP, we are in the process of 
acting on the Court's remand consistent with the planned response we 
outlined in a June 2016 memorandum.\193\
---------------------------------------------------------------------------

    \191\ As Arkansas did not rely on CAIR to satisfy requirements 
in the regional haze SIP, Arkansas is not included in the EPA's 
limited disapproval of regional haze SIPs that relied on CAIR to 
satisfy certain regional haze requirements. See 77 FR 33642, at 
33654. In that same rulemaking, the EPA 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.
    \192\ 795 F.3d 118 (DC Cir 2015).
    \193\ https://www3.epa.gov/airtransport/CSAPR/pdfs/CSAPR_SO2_Remand_Memo.pdf.
---------------------------------------------------------------------------

    Our final action on the Arkansas Regional Haze FIP is consistent 
with our final action on the Texas Regional Haze FIP. Although we 
proposed to rely on CSAPR to address the NOX BART 
requirements for EGUs in Texas, we did not finalize that portion of our 
proposed Texas FIP given the uncertainty arising from the remand of the 
CSAPR budgets for Texas and other states.\194\ In light of the above, 
the comments that we are treating Arkansas differently than other 
states where EPA relied on CSAPR to meet the BART requirements are no 
longer applicable.
---------------------------------------------------------------------------

    \194\ 81 FR 296, 302.
---------------------------------------------------------------------------

    As we have noted throughout this document, we are willing to work 
with ADEQ to develop a SIP revision that could replace our FIP. Such a 
SIP revision will need to meet the CAA and EPA's Regional Haze 
regulations. In its SIP revision, ADEQ may elect to rely on CSAPR to 
satisfy the NOX BART requirements for Arkansas' EGUs instead 
of doing source-specific NOX BART determinations. Such an 
approach could be appropriate if, as we expect, the uncertainty created 
by the D.C. Circuit's remand of the affected states' emission budgets 
will shortly be resolved.
    With regard to the comment that we should not require EGUs that are 
covered under CSAPR to also install additional emissions controls under 
reasonable progress analysis, we disagree. In our 2012 finding that 
CSAPR is better than BART, we stated that states with EGUs covered 
under CSAPR may rely on CSAPR to satisfy the BART requirement. However, 
controls under reasonable progress are a separate requirement from 
BART, and we disagree that states can rely on CSAPR to satisfy the 
reasonable progress requirements under Sec.  51.308(d)(1). As explained 
in the 2005 rulemaking addressing reliance on CAIR, our determination 
that a trading program provides for greater reasonable progress than 
BART is not a determination that the trading program satisfies all 
reasonable progress requirements.\195\
---------------------------------------------------------------------------

    \195\ 70 FR 39104, 39143; see also 77 FR 33642, 33653.
---------------------------------------------------------------------------

I. Cost

    We received numerous comments related to the cost analyses we 
proposed. These comments were received from both industry and 
environmental groups, and covered all aspects of our cost analyses.
    We received comments from industry concerning our proposed scrubber 
cost analyses that objected to our use of the IPM cost algorithms that 
Sargent and Lundy (S&L) developed under contract to us. As we discuss 
in our TSD, we programmed the Spray Dryer Absorber (SDA--a type of dry 
scrubber), and wet FGD cost algorithms, as employed in version 5.13 of 
our IPM model, into spreadsheets in our analysis of various aspects of 
the Entergy White Bluff and Independence scrubber cost analyses.\196\ 
Industry stated these cost algorithms were not accurate enough to 
warrant their use in individual unit-by-unit cost analyses, do not 
consider site-specific costs, and that our use of them violated our 
Control Cost Manual. Environmental groups supported our use of the IPM 
cost algorithms, and employed them as well in costing scrubber and SCR 
control costs to support their own comments. In response, we conclude 
that the IPM cost algorithms provide reliable, study-level, unit-
specific costs for regulatory cost analysis such as required for BART 
and reasonable progress.\197\
---------------------------------------------------------------------------

    \196\ See discussion beginning on pages 9 and 20 of our TSD 
Appendix A.
    \197\ We believe that the IPM cost algorithms provide study 
level accuracy. See pdf page 17 of our Control Cost Manual: 
``[a]``study'' level estimate [has] a nominal accuracy of  30% percent. According to Perry's Chemical Engineer's 
Handbook, a study estimate is `. . . used to estimate the economic 
feasibility of a project before expending significant funds for 
piloting, marketing, land surveys, and acquisition . . . [However] 
it can be prepared at relatively low cost with minimum data.'''
---------------------------------------------------------------------------

    We received comments relating to our critique of Entergy's White 
Bluff dry scrubber cost analysis. These primarily involved claims that 
we (1) improperly escalated Entergy's own cost analyses, (2) improperly 
excluded costs, (3) under-estimated O&M costs, (4) improperly 
calculated the SO2 baseline, (5) improperly excluded 
``Allowance for Funds Used During Construction''

[[Page 66382]]

(AFUDC) and owner's costs, and (6) improperly extended our White Bluff 
scrubber cost analyses to the Independence facility. In response to 
these comments, we have made some minor adjustments to our White Bluff 
scrubber cost analyses, but those changes do not change our proposal 
that scrubbers remain cost-effective for the White Bluff facility, and 
by extension to the Independence facility.
    We received comments from environmental groups concerning the White 
Bluff, Independence, and Flint Creek facilities that (1) generally 
supported our proposed control suite, (2) criticized us in some cases 
for not proposing stricter control levels, (3) criticized our control 
cost analyses for being too conservative in some cases and/or 
containing errors, and (4) criticized us in some cases for not 
requiring earlier compliance. These groups also generally opposed our 
BART determination for Lake Catherine Unit 4.
    Below we present a summary of our responses to the more significant 
comments we received that relate to our proposed cost analyses.
    Comment: S&L states we significantly under-estimated the direct 
Operating and Maintenance (``O&M'') costs projected for the scrubbers 
by using its Integrated Planning Model (``IPM'') Spray Dryer Absorber 
(``SDA'') cost model to scale the O&M costs rather than estimating 
these costs using current utility pricing information. S&L stated that 
our use of the IPM cost algorithms was not in keeping with our Control 
Cost Manual and because of the limited number of site-specific inputs, 
the IPM cost algorithms provide order-of-magnitude control system cost 
estimates, but do not provide case-by-case project-specific cost 
estimates meeting the requirements of the BART Guidelines, nor do the 
IPM equations incorporate the cost estimating methodology described in 
the Control Cost Manual.
    Response: We disagree with S&L. As we discuss in our TSD,\198\ we 
needed to adjust Entergy's O&M costs for its White Bluff SDA model 
because of a mismatch between Entergy's SO2 emission 
baseline and the SO2 inlet it assumed in the design of its 
scrubber (discussed in our response to another comment). Entergy costed 
a scrubber capable of treating a SO2 level of 2.0 lbs/MMBtu, 
when it historically burned coal that averaged less than 0.6 lbs/MMBtu 
from 2009-2013. This had the effect of worsening the cost effectiveness 
(increasing the $/ton) over what it would have been had Entergy 
designed it to treat the coal it historically burned. We could not 
directly adjust Entergy's O&M costs because Entergy's O&M cost 
estimates were based on an S&L economic model from May 2008, which it 
did not supply.\199\ These issues, which we discuss in our responses to 
comments elsewhere, dictated a revision to Entergy's cost estimate. We 
were left with no choice but to seek an alternative means of estimating 
Entergy's O&M costs, in order to address the mismatch described above. 
We utilized the IPM SDA cost model that Entergy's own contractor 
designed for us.
---------------------------------------------------------------------------

    \198\ See Section 3.1 in Appendix A of our TSD.
    \199\ See Section 2.7 in Appendix A of our TSD.
---------------------------------------------------------------------------

    We disagree that our cost estimates were not in keeping with the 
Control Cost Manual. As we stated in our TSD Appendix A, we relied on 
the methods and principles contained within the Control Cost Manual, 
namely the use of the overnight costing method. In fact, the Control 
Cost Manual does not include any method for estimating the costs 
specific to any of the SO2 control equipment evaluated in 
this action. We note our technique of relying on a publicly available 
control cost tool is similar to the strategy the states themselves 
employed in the development of their SIPs. For instance, as explained 
in the Texas SIP, the ADEQ used the control strategy analysis completed 
by the CENRAP, which depended on the EPA AirControlNET tool \200\ to 
develop cost per ton estimates. We have used IPM cost models to 
estimate BART costs in other similar rulemakings including our Arizona 
Regional Haze FIPs,\201\ the Wyoming Regional Haze FIP,\202\ and to 
supplement our analysis in the Oklahoma FIP.\203\ S&L used real world 
cost data to construct its cost algorithms and confirm their validity. 
These cost models have been updated and maintained since their 
introduction in 2010 and we have been continuously using them since 
that time. These control costs are based on databases of actual control 
project costs and account for project specifics such as unit size, coal 
type, gross heat rate, and retrofit factor. The costs further require 
unit specific inputs such as reagent cost, waste disposal cost, 
auxiliary power cost, labor cost, gross load, and emission information. 
We believe that the IPM cost models provide reliable study-level, unit-
specific costs for regulatory cost analysis such as required for BART 
and reasonable progress. We are confident enough in the basic 
methodology behind the S&L cost algorithms that in our recent update of 
the SCR chapter of the Control Cost Manual \204\ we presented an 
example costing methodology that is based on the IPM S&L SCR 
algorithms, which were developed using a similar methodology to the wet 
FGD, SDA, and DSI cost algorithms discussed herein. Lastly, we note 
that Entergy used a number of general approximations when estimating 
the wet scrubbing costs for White Bluff, as we describe in our 
TSD.\205\ We conclude that our approach is in keeping with the Control 
Cost Manual and is sufficiently accurate for its intended purpose.
---------------------------------------------------------------------------

    \200\ Our AirControlNET tool is out of date and no longer 
supported.
    \201\ 77 FR 42852 (July 20, 2012).
    \202\ Memorandum from Jim Staudt to Doug Grano, EPA, Re: Review 
of Estimated Compliance Costs for Wyoming Electricity Generating 
Units (EGUs)--Revision of Previous Memo, February 7, 2013, EPA-R08-
OAR-2012-0026-0086_Feb 7, 2013.
    \203\ 76 FR 81728 (December 28, 2011).
    \204\ https://www3.epa.gov/ttn/ecas/cost_manual.html.
    \205\ See discussion beginning on page 19 of Appendix A to our 
TSD.
---------------------------------------------------------------------------

    Comment: Entergy disagreed with our approach for escalating a 2013 
scrubber cost analysis for its White Bluff facility to 2015, rather 
than obtaining a revised cost estimate. Entergy claims this caused us 
to underestimate our scrubber cost estimate by $36,322,881 (total for 
both units). Entergy also disagreed with our application of the 
Chemical Engineering Plant Cost Index (CEPCI) indices in several 
instances from 2008 that de-escalated costs, resulting in lower costs 
in 2013 as compared to 2008. Entergy states that our cost calculations 
ignored the updated 2012 direct annual costs it provided, and instead 
included the 2008 costs. In a subsequent comment, Entergy calculates an 
escalation rate of 4.7%, based on a comparison of a revised 2013 quote 
to a 2009 quote, and applies that escalation rate along with other 
corrections to various cost line items in concluding that we 
underestimated the cost of installing scrubbers at the White Bluff 
facility by $42,607,547 per unit.
    Response: For our proposal, we used Entergy's revised BART analysis 
for the White Bluff facility, as submitted by it on October 14, 2013, 
because at the time it was the latest information available to us.\206\ 
In our proposal, our control cost analysis used the same basic 
information that Entergy previously presented to us in 2013. As we 
describe in Appendix A of our TSD, Entergy stated that it received two 
different SDA cost estimates for White Bluff: An early 2009 Sargent and 
Lundy (S&L) estimate with a total contractor cost of $291,930,000, and 
a December 2009

[[Page 66383]]

estimate from Alstom of $247,856,184. Entergy stated that unlike the 
S&L quote, the Alstom estimate was not itemized and only included a 
total price. Entergy used the 2009 Alstom price quote as the basis for 
its BART cost analysis for White Bluff by increasing it by 10%, and 
scaling the S&L itemized cost to match the 110% adjusted Alstom total 
price. As we describe in our RTC, we critiqued certain aspects of 
Entergy's use of this information. For example, Entergy mistakenly 
included certain NOX controls in its 2013 cost analysis. It 
also failed to document certain BOP costs that we had no choice but to 
exclude. However, between the 2009 S&L and the 2009 Alstom quotes, and 
with these corrections, we were able to construct a reasonable control 
cost estimate. In so doing, we used the same 2009 Alstom total, and the 
Alstom payment schedule for its quote, as the actual Alstom quote was 
not supplied and no better information was presented by Entergy. 
Because Entergy's 2013 cost estimate used 2009 Alstom pricing, we had 
no choice but to escalate it to 2013--more recent information was not 
available.
---------------------------------------------------------------------------

    \206\ See section 2.1 of Appendix A to our TSD.
---------------------------------------------------------------------------

    Entergy did not provide its updated 2015 cost estimate, which it 
references in its comment, until after our proposal. Entergy's 2015 
report uses updated 2013 pricing from Alstom as its basis. As we 
discuss in our RTC, we reviewed this 2015 cost analysis and found that 
it presents problems that prevent us from using it, primarily because 
it is undocumented.
    In this comment, Entergy attempts to use its newly submitted 2015 
cost analysis to discredit the escalation technique we employed to 
adjust its previous 2013 cost analysis. It does so without even 
presenting the 2013 Alstom quote on which it states the 2015 cost 
estimate relies. Thus, we have no basis to conclude that the costs 
Entergy presents in its first table above even cover the same scope of 
work. This is an important consideration and a different scope can 
cause a significant difference in cost. Entergy itself noted this when 
it used a revised BOP estimate to adjust its 2009 Alstom quote because 
the scope had changed. Even different cost estimates received in the 
same year can result in significantly different totals. For instance, 
as we also note in our TSD, Entergy stated that it received two 
different SDA cost estimates for White Bluff: An early 2009 S&L 
estimate with a total contractor cost of $291,930,000, and a December 
2009 estimate from Alstom of $247,856,184.\207\ We note that the 
difference between these two quotes is $44,073,816, which is more than 
Entergy calculates in its first table above is the difference between 
our escalated 2013 quote ($261,581,119) and its revised 2015 cost 
estimate, based on the its 2013 Alstom quote ($297,904,000).
---------------------------------------------------------------------------

    \207\ See section 2.1 of Appendix A to our TSD.
---------------------------------------------------------------------------

    Escalation from one year's cost basis to another \208\ is not only 
allowed by the Control Cost Manual, it is a required procedure in order 
to allow an apples-to-apples comparison between control cost analyses. 
Our use of the Chemical Engineering Plant Cost Index (CEPCI) is a 
standard method of escalating costs,\209\ and one that power companies 
have also used on numerous occasions. Entergy itself has used the CEPCI 
in an attempt to escalate its costs. Unfortunately, as we explain in 
our TSD, Entergy did so incorrectly and we corrected that error.\210\ 
We certainly prefer revised vendor quotations to escalating older cost 
estimates. However, when revised vendor quotes are not available as in 
this case, we have no choice but to escalate older cost estimates in 
order to bring the cost basis to the present.
---------------------------------------------------------------------------

    \208\ Note that escalation during the construction period is 
disallowed, however, because that is not a part of the overnight 
method.
    \209\ Vatavuk, William, M., ``Updating the CE Plant Cost 
Index,'' Chemical Engineering, January 2002.
    \210\ See section 2.6 of Appendix A to our TSD.
---------------------------------------------------------------------------

    Entergy also apparently objects to any escalation technique that 
results in a reduction in a future year's cost basis, holding it up as 
evidence of our error.\211\ This is a fundamental misunderstanding of 
escalation. For instance, although the Composite CE index usually 
increases from year to year, it does occasionally decrease, due to 
various broad economic factors, such as it did from 2008 to 2009, and 
again from 2011 to 2013. This is mainly due to broad economic factors 
that influence the cost of raw materials, supply and demand, vendor 
profit, etc. Thus, Entergy's objection over the ``de-escalation'' of 
cost from 2008 to 2013 is entirely misplaced. In other words, 
escalation is escalation: Most of the time it is positive but sometimes 
it is negative. We therefore do not agree with Entergy's objections to 
our escalation technique. We take up the issue of Entergy's 2015 cost 
estimate in our response to another comment.
---------------------------------------------------------------------------

    \211\ Entergy's reference to de-escalated costs.
---------------------------------------------------------------------------

    Entergy states that our cost calculations ignored the updated 2012 
direct annual costs provided by Entergy, and instead included the 2008 
costs. As noted in the first sentence of our response to this comment, 
we were constrained to use Entergy's revised BART analysis for the 
White Bluff facility, as submitted by Entergy on October 14, 2013 
(hereafter referred to as the ``2013 SDA Cost Analysis''). These costs 
employed a 2008 vintage total direct annual cost, as we indicate in 
Appendix A of our TSD.\212\ Regarding its direct annual costs, Entergy 
further states, ``The cost estimates were scaled to reflect 2012 
dollars.'' \213\ We therefore agree that Entergy did provide what it 
stated was 2012 vintage direct annual costs. We did not use those costs 
because Entergy incorrectly escalated them from 2008, as we discuss 
above. For instance, Entergy presented its 2008 direct annual cost as 
$7,901,369. It then ``scaled'' them to 2012 using a 2008 CEPCI index of 
530.7 and a 2012 CEPCI index of 593.6, resulting in a 2012 value of 
$8,837,861. As we discuss in Appendix A of our TSD, Entergy appears to 
have incorrectly used the January monthly CEPCI value for each year 
instead of the annual CEPCI value. Entergy should have used a 2008 
CEPCI index of 575.4 and a 2012 CEPCI index of 584.6, resulting in a 
2012 escalated direct annual cost of $8,027,703 ($7,901,369 x 584.6/
575.4). As we also discuss in our TSD, because we were conducting our 
analysis later, we escalated Entergy's 2008 direct annual cost to 2013, 
resulting in a value of $7,790,140 ($7,901,369 x 567.3/575.4). These 
facts appear to have been ignored by Entergy in its comment. We 
therefore have no choice but to disagree with Entergy's comment 
concerning our not using its 2012 direct annual cost.
---------------------------------------------------------------------------

    \212\ See section 2.7 of Appendix A to our TSD.
    \213\ Revised Bart Five Factor Analysis, White Bluff Steam 
Electric Station, Redfield, Arkansas (AFIN 35-00110). Appendix A, 
SDA cost analysis, June 2013, Appendix A.
---------------------------------------------------------------------------

    Comment: Entergy and Nucor stated that we improperly excluded AFUDC 
and owner's costs from our White Bluff control cost analysis. Entergy 
also objects to our disallowance of certain BOP costs.
    Response: As we have noted in a number of our FIPs, AFUDC and 
Owner's Costs are not valid costs under our Control Cost Manual 
methodology. We invite the commenters to examine our response to 
similar comments we received in response to those actions.\214\
---------------------------------------------------------------------------

    \214\ See, e.g., ``Response to Technical Comments for Sections E 
through H of the Federal Register Notice for the Oklahoma Regional 
Haze and Visibility Transport Federal Implementation Plan,'' Docket 
No. EPA-R06-OAR-2010-0190, 12/13/2011.
---------------------------------------------------------------------------

    In Appendix A to our TSD, we noted that Entergy used BOP costs from 
a 2008 S&L quote to supplement its adjusted 2009 Alstom quote in its 
2013 SDA cost analysis for the White Bluff BART determination. However, 
due to a lack of documentation, it appeared that a number of items were 
either not appropriate for a SO2 scrubber, or were

[[Page 66384]]

already covered as part of the Alstom quote. As discussed in detail in 
our RTC document, we removed those items from our proposed SDA cost 
analysis and invited Entergy to supply additional documentation to 
verify these costs. S&L now points to an S&L Report #012831, which 
contains a 2015 White Bluff SDA cost estimate, for that documentation. 
First, Entergy states that its 2015 SDA cost estimate is based on a 
2013 Alstom quote. As with the 2009 Alstom quote it used to support its 
2013 SDA cost analysis, Entergy did not provide this Alstom quote. 
Consequently, we have no way of verifying Entergy's 2015 cost 
calculations or to conclude that their scopes are the same. Therefore, 
we have no choice but to conclude that Entergy has not demonstrated 
that our removal of costs associated with the reagent preparation 
enclosure and reagent handling system and ductwork was incorrect. 
Similarly, we continue to find that Entergy has not documented certain 
BOP indirect costs, miscellaneous contract labor, Entergy internal 
costs, and capital suspense.
    We do agree that Entergy has provided documentation for other 
costs, including demonstrating that recalibration of the CEMS and 
painting of the chimney are justified, and we have adjusted our White 
Bluff scrubber cost analysis accordingly. Other costs that were 
calculated as percentages of the equipment, material, and labor costs 
were similarly adjusted. We have revised our cost analysis to include 
these adjustments, and have determined that dry scrubbers are estimated 
to cost $2,565/SO2 ton removed at Unit 1 and $2,421/
SO2 ton removed at Unit 2.\215\ Revising these costs did not 
change our final determination that dry scrubbers are cost-effective 
for the White Bluff facility.
---------------------------------------------------------------------------

    \215\ See the file, ``White Bluff_R6 cost revisions2-
revised.xlsx'' in our docket.
---------------------------------------------------------------------------

    Comment: S&L objects to our approach of calculating an 
SO2 baseline for the White Bluff and Independence 
facilities, in which we eliminated the high and low annual emission 
values from 2009 to 2013, and averaged the remaining values. S&L 
presents four alternative approaches in which a straight five year 
average from 2009 to 2013, and different three year averages from 2009 
to 2013 are examined for White Bluff Units 1 and 2 and Independence 
Units 1 and 2, and concludes that in all cases, at least one of the 
alternative approaches would have resulted in lower baseline 
SO2 emissions for one of the units.
    Response: We disagree with S&L that we erred in the procedure we 
used in estimating baseline emissions for our BART and reasonable 
progress scrubber upgrade cost analyses. We calculated our baseline 
SO2 emissions by first acquiring the 2009 to 2013 emissions 
as reported to us by the facilities in question.\216\ We reasonably 
eliminated the high and low values from the 2009-2013 emissions to 
better address potential yearly variations in in coal sulfur data, 
capacity usage, etc., and to make the baseline more representative of 
plant operations and thereby provide the basis for a more accurate 
estimate of the cost effectiveness of controls. The fact that S&L can 
construct alternative approaches to our baseline calculation that 
result in lower emissions estimates does not invalidate our BART and 
reasonable progress approaches. As can be seen from an examination of 
S&L's own data, regardless of whether a 3-year average or a 5-year 
average of a particular set of years is employed, the resulting 
emissions baselines are all similar. In fact, for three out of four 
units, one of S&L's alternative approaches would have produced higher 
SO2 emissions baselines, which if used would have resulted 
in the cost analyses we performed being even more cost-effective. We 
believe that the procedure we used is in compliance with the BART 
Guidelines, which states:
---------------------------------------------------------------------------

    \216\ http://ampd.epa.gov/ampd/

    How do I calculate baseline emissions?
    1. The baseline emissions rate should represent a realistic 
depiction of anticipated annual emissions for the source. In 
general, for the existing sources subject to BART, you will estimate 
the anticipated annual emissions based upon actual emissions from a 
baseline period.
    2. When you project that future operating parameters (e.g., 
limited hours of operation or capacity utilization, type of fuel, 
raw materials or product mix or type) will differ from past 
practice, and if this projection has a deciding effect in the BART 
determination, then you must make these parameters or assumptions 
into enforceable limitations. In the absence of enforceable 
limitations, you calculate baseline emissions based upon 
continuation of past practice.\217\
---------------------------------------------------------------------------

    \217\ 70 FR 39104, 39167.

    Regarding the baseline used in our Independence reasonable progress 
analysis, our 2007 Reasonable Progress Guidance notes the similarity 
between some of the reasonable progress factors and the BART factors 
contained in Sec.  51.308(e)(1)((ii)(A), and suggests that the BART 
Guidelines be consulted regarding cost, energy and nonair quality 
environmental impacts, and remaining useful life.\218\ We are therefore 
relying on our BART Guidelines for assistance in interpreting those 
reasonable progress factors, as applicable. One of these areas is in 
the calculation of the baseline emissions in determining cost 
effectiveness.
---------------------------------------------------------------------------

    \218\ ``Guidance for Setting Reasonable Progress Goals Under the 
Regional Haze Program,'' at 5-1.
---------------------------------------------------------------------------

    The difference between our baseline calculations and any of the 
alternative procedures S&L outlines is small and would not change our 
conclusions for the White Bluff BART determinations and the 
Independence reasonable progress determinations.
    Comment: S&L objects to our extending our White Bluff scrubber cost 
analysis to the Independence facility on the basis of the similarity of 
the two facilities. S&L states that our use of EIA information, 
satellite photographs and other points of comparison are inadequate to 
account for potential site-specific differences between the two 
facilities, such as operating data, O&M practices, underground utility 
interferences, geotechnical differences, and seismic differences.
    Response: While there are likely differences between the two 
facilities that would have some minor impact on the scrubber cost 
analyses, we reasonably concluded based on the information available to 
us that there were enough similarities between the facilities to make 
our approach appropriate. As we discuss in our TSD:

    The White Bluff and Independence facilities are sister 
facilities. According to EIA,\219\ the boilers were manufactured by 
Combustion Engineering with in-service dates of 1980 and 1981 for 
White Bluff, and 1983 and 1985 for Independence. All four units are 
tangentially firing boilers having nameplate capacities of 900 MW 
and similar gross ratings. As we indicate above, all four units burn 
coal from the Powder River Basin of Wyoming with similar 
characteristics. All four units employ cold side electrostatic 
precipitators for particulate collection. Other pertinent 
characteristics are similar.\220\
---------------------------------------------------------------------------

    \219\ See ``EIA Consolidated Data_WB and IND_Y2012.xlsx.''
    \220\ See document titled ``AR RH FIP TSD Appendix A--White 
Bluff and Independence SO2 Cost Analysis,'' found in the 
docket for this rulemaking.

    We further presented satellite photographs to demonstrate that the 
layout of these facilities are extremely similar. We consequently 
expect that the differences Entergy describes in its comments result in 
minor differences in the cost to install and operate scrubbers. As we 
have discussed in our response to another comment, the Control Cost 
Manual explains that the sole input required for making an ``order of 
magnitude'' estimate is the control

[[Page 66385]]

system's capacity (often measured by the maximum volumetric flow rate 
of the gas passing through the system). Such an estimate, for example, 
could be obtained from the cost reported in dollars per megawatt ($/MW) 
or dollars per million BTUs fired ($/MMBtu), metrics that are widely 
reported in the literature. The Control Cost Manual indicates that 
``the costs and estimating methodology in this Manual are directed 
toward the `study' estimate with a nominal accuracy of +/-30% 
percent.'' This is the long-standing rule of thumb for cost estimate 
accuracy used by the EPA for regulatory cost effectiveness analyses. We 
see nothing in Entergy's comments that would suggest that the 
differences between these two facilities are so significant they would 
impact this required level of accuracy. Indeed, Entergy does not 
attempt to estimate the capital costs of these differences or otherwise 
provide a cost estimate specific to the Independence facility in 
support of its argument that it was inappropriate for us to extend our 
White Bluff scrubber cost analysis to the Independence facility.
    Comment: Entergy objects to our correction to its White Bluff 
scrubber control cost analysis to adjust the cost for a scrubber 
designed to treat a 2.0 lb/MMBtu coal to 0.68 lbs/MMBtu to account for 
the lower sulfur coal it has historically burned. Entergy states that 
we correctly assumed that the 2.0 lb/MMBtu design basis for the White 
Bluff scrubber was to preserve fuel flexibility, but our conclusions 
that, ``either (1) this higher cost be balanced against its greater 
SO2 reduction potential, or (2) that the scrubber system's 
capability and cost be adjusted down to match the facility's historical 
emissions'' are without basis and inconsistent with the BART 
guidelines. Entergy also concludes that its assumption that a 2.0 lb/
MMBtu scrubber inlet was in error and a 1.2 lb/MMBtu inlet assumption 
is now appropriate. Entergy presents SO2 emission data in 
support of its position that our 0.68 lbs/MMBtu coal assumption was 
incorrect and recalculates its O&M and capital costs. Lastly, Entergy 
states that in correcting its scrubber control cost analysis to account 
for a 0.68 lbs/MMBtu coal, we misapplied a correction factor to our 
total direct and indirect costs.
    Response: As we noted in our TSD, ``either (1) this higher cost be 
balanced against its greater SO2 reduction potential, or (2) 
that the scrubber system's capability and cost be adjusted down to 
match the facility's historical emissions.'' Entergy chose to do 
neither and costed a scrubber capable of treating a coal far in excess 
of what it historically burned, but continued to base the capabilities 
of the scrubber on its historical SO2 baseline. Thus, either 
Entergy's annualized cost (the ``$'') or its tons reduced (the 
``tons'') in the $/ton cost effectiveness calculation are 
misrepresented. Our approach was to recalculate Entergy's scrubber cost 
to bring its scrubber design in line with the coal it has historically 
burned. Entergy could have taken the alternative approach of 
calculating a new baseline on the basis of its higher sulfur design 
coal, but it chose not to do so. We see nothing in Entergy's comments 
that would cause us to conclude our reasoning was in error. With regard 
to Entergy's concerns with the 0.68 lbs/MMBtu baseline that we use, it 
appears the SO2 emission data Entergy presented was hourly 
data, which should not be used to design a scrubber that would have to 
meet a 30-BOD average. Our analysis indicates the individual hourly 
data fluctuations Entergy presents are inconsequential. Further, an 
examination of the running 30-BOD average indicates that our decision 
to fix the mismatch between Entergy's scrubber costs and its historical 
SO2 baseline on the basis of a SO2 inlet of 0.68 
lbs/MMBtu is reasonable.
    In apparent agreement with our basic approach, Entergy recalculates 
its variable and fixed O&M costs on the basis of 0.68 lb/MMBtu fuel 
sulfur levels. We note that our own variable and fixed O&M costs are 
actually greater, adding to the conservativeness of our calculation. To 
illustrate the small difference in capital costs associated with the 
revised design basis (1.2 lb/MMBtu versus 0.68 lb/MMBtu), Entergy then 
performs a sensitivity analysis and concedes there is a ``small 
difference in capital costs associated with the revised design basis 
(1.2 lb/MMBtu versus 0.68 lb/MMBtu). . . .'' This conclusion is borne 
out by our own figures, which indicate there is a small difference in 
capital costs to even the 2.0 lbs/MMBtu case; the capital, engineering 
and construction costs, which cover the fundamental design parameter of 
a scrubber--gas flow rate--were only changed by less than 5%. In sum, 
Entergy's assertion that our cost analysis improperly designed the 
White Bluff scrubber system is without merit and would make an 
insignificant difference in the final outcome.
    Lastly, we agree with Entergy that we misapplied a correction 
factor to our total direct and indirect costs. We incorporate that 
correction in our final SDA cost analysis for the White Bluff and 
Independence facilities, which we discuss in more detail in our 
response to other comments. This correction has a relatively minor 
impact on the overall cost analysis.
    Comment: The Sierra Club supported our proposal regarding 
SO2 for the White Bluff and Independence facilities, but 
concluded that our proposed SO2 emission rate of 0.06 lbs/
MMBtu on a 30-BOD average should have been stricter at 0.04 lbs/MMBtu, 
based on wet scrubbing. The Sierra Club also agrees with our assessment 
that Entergy included undocumented costs in its White Bluff scrubber 
cost estimate.
    The Sierra Club's consultant performed a cost analysis of dry and 
wet scrubber systems, including Alstom's NID circulating dry scrubber, 
and concluded that our White Bluff scrubber cost analysis was 
conservative, that scrubbers are cost effective compared to controls 
required pursuant to other BART determinations, and that we should have 
required compliance in 3 years instead of 5 years.
    Response: We confirm that we intended to construct conservative 
cost estimates. With some minor disagreements with the Sierra Club, we 
generally agree that an independent cost analysis such as it presents 
does support our basic position that scrubbers are cost effective at 
both the White Bluff and Independence facilities. However, as we 
discuss in our RTC document, we disagree that in this specific instance 
wet scrubbers are more cost effective than dry scrubbers. Our scrubber 
cost analyses was built off of the analyses supplied by Entergy, and we 
determined that wet scrubbers were significantly less cost effective--
again, in the specific cases of the White Bluff and Independence 
facilities for BART and reasonable progress respectively. We disagree 
with the SO2 baseline Sierra Club uses in its cost analysis, 
rendering its scrubber cost analysis and ours not directly comparable. 
Consequently, we disagree that an SO2 emission rate of 0.04 
lbs/MMBtu averaged over a 30-boiler-operating-day period, based on a 
wet scrubber cost analysis, is appropriate for either the White Bluff 
or Independence facilities. We agree that in some cases scrubbers can 
be installed in less than the 5 years that we proposed. However, this 
is site-specific and, in this case, we have found that installation 
within 5 years is as expeditious as practicably possible.
    We agree that the Alstom NID circulating dry scrubber is a 
promising SO2 control option. We reviewed NID in our 
preliminary work but ultimately decided not to evaluate it as a control 
because we had no relevant operating data and no method to estimate 
costs.

[[Page 66386]]

    After addressing all comments from Entergy and the Sierra Club 
concerning our White Bluff and Independence scrubber cost analyses, we 
made several minor corrections.\221\ Below we summarize those 
corrections:
---------------------------------------------------------------------------

    \221\ Those corrections are contained in the file, ``White 
Bluff_R6 cost revisions2-revised.xlsx,'' which appears in our 
docket.

Table 18--Corrections to Our Cost-Effectiveness Calculations for Dry FGD
                    for White Bluff and Independence
------------------------------------------------------------------------
                                          Proposed cost-    Final cost-
                  Unit                     effectiveness   effectiveness
                                              ($/ton)         ($/ton)
------------------------------------------------------------------------
White Bluff Unit 1......................          $2,227          $2,565
White Bluff Unit 2......................           2,101           2,421
Independence Unit 1.....................           2,477           2,853
Independence Unit 2.....................           2,286           2,634
------------------------------------------------------------------------

    We find that these revised cost-effectiveness calculations do not 
change our proposed findings for BART and reasonable progress for these 
units.
    In addition, we have examined the effect of adding back in a number 
of the BOP and other costs we excluded (based on these costs being 
either disallowed by the Control Cost Manual, or having lacked 
documentation from Entergy). This exercise also appears in the file 
``White Bluff_R6 cost revisions2-revised.xlsx.'' These costs include:
     BOP Costs associated with the reagent prep enclosure and 
the reagent handling system, totaling $21,229,000.
     BOP Costs associated with the flue gas system ductwork, 
totaling $1,754,000.
     BOP indirect costs of $8,474,666 (escalated to 2013).
     Miscellaneous contract labor costs of $4,448,074 
(escalated to 2013).
     Entergy internal costs of $19,482,518 (escalated to 2013).
     Capital suspense costs of $8,101,226 (escalated to 2013).

  Table 19--Alternate Cost-Effective Calculations for Dry FGD on White
                         Bluff and Independence
                       [Include disallowed costs]
------------------------------------------------------------------------
                                                          Alternate cost-
                          Unit                             effectiveness
                                                              ($/ton)
------------------------------------------------------------------------
White Bluff Unit 1......................................          $3,013
White Bluff Unit 2......................................           2,843
Independence Unit 1.....................................           3,351
Independence Unit 2.....................................           3,093
------------------------------------------------------------------------

    We continue to believe that these costs are either disallowed by 
the Control Cost Manual, or are properly disallowed because they lack 
documentation from Entergy. We have presented this information to 
indicate that these disallowed costs have a relatively minor effect on 
the final cost effectiveness. Although our final decision regarding 
BART and reasonable progress for the White Bluff and Independence units 
does not rest upon these cost-effectiveness calculations that include 
the disallowed costs, had our final decision rested on these cost-
effectiveness calculations, we would have reached the same conclusions 
regarding BART and reasonable progress for these units.
    Comment: The Sierra Club stated that the NOX emission 
limit of 0.15 lbs/MMBtu based on LNB/SOFA we proposed for White Bluff 
Units 1 and 2 does not satisfy BART. The Sierra Club asserted that 
NOX BART for these units should have been based on SCR. The 
Sierra Club's consultant concluded that we overestimated the costs of 
SCR and underestimated the visibility benefits of SNCR and SCR. The 
consultant's conclusions are based on cost-effectiveness calculations 
developed by the consultant, which rely on the S&L IPM SCR Cost Module 
and assume an achievable NOX emission rate of 0.04 lb/MMBtu 
for LNB/SOFA plus SCR. The Sierra Club stated that LNB/SOFA can be 
installed in much shorter timeframe than the 3 years we proposed. The 
Sierra Club also stated that we should have evaluated SNCR and SCR for 
the Independence facility.
    Response: We have a number of disagreements with the Sierra Club's 
consultant concerning the SCR cost analysis provided, including the 
NOX baseline and the emission limit, which are outlined in 
detail in our RTC document. After addressing those issues, we do not 
believe that the cost effectiveness of SCR or SNCR fall within a range 
that justifies the relatively small incremental visibility improvement 
(over our NOX BART determination based on LNB/SOFA) that 
would result from the installation of SNCR or SCR at the White Bluff 
facility. As we discussed in our proposal,\222\ our modeling indicated 
that the visibility improvement at several Class I areas from the 
installation of LNB/SOFA at the Independence facility was of a similar 
magnitude as the same controls at the White Bluff facility, and 
cumulatively (i.e., at all Class I areas combined) the visibility 
improvement of the controls at Independence was lower than at White 
Bluff. Therefore, we reasoned that since White Bluff and Independence 
are sister facilities with near identical units, the cost effectiveness 
of SCR or SNCR at Independence would likely not fall within a range 
that justifies the relatively small incremental visibility improvement 
(over LNB/SOFA) that would result from installation of these controls. 
Therefore, we did not evaluate SCR or SNCR controls for Independence. 
As we discuss in a separate response, after carefully considering the 
comments we have received, we are finalizing an 18-month compliance 
date for the NOX emission limits we are establishing for 
White Bluff Units 1 sand 2 under BART and Independence Units 1 and 2 
under reasonable progress.
---------------------------------------------------------------------------

    \222\ See our supplemental NOX modeling results for 
the Independence facility in 80 FR 24872 vs. our NOX 
modeling results for the White Bluff facility in 80 FR at 18974.
---------------------------------------------------------------------------

    Comment: The Sierra Club and others stated that the costs of both a 
wet and a dry scrubber are reasonable at the two Independence units. 
The Sierra noted our proposed costs are reasonable in other reasonable 
progress determinations that it summarizes. The Sierra Club's 
consultant independently calculated the costs of scrubbers at 
Independence Units 1 and 2 and concluded that those calculations 
confirm that a scrubber is cost-effective. The consultant also noted 
that the significant visibility improvement from a scrubber at 
Independence Units 1 and 2 would equal or exceed the visibility 
improvement from other reasonable

[[Page 66387]]

progress controls we have previously approved. The Sierra Club's 
consultant also incorporated comments for the White Bluff facility 
regarding time for installation and control level.
    Response: We take no position on the separate cost analysis that 
the Sierra Club's consultant has conducted for dry and wet scrubbers 
and that uses to conclude that our cost analyses are reasonable. We 
agree that our finding that the control costs are reasonable, given the 
visibility improvements achieved, is consistent with other EPA actions. 
We refer the Sierra Club's consultant to our responses to other similar 
comments regarding the White Bluff facility scrubber concerning control 
level and installation time.
    Comment: The Sierra Club and others stated that our proposal that 
SO2 BART for AEP Flint Creek is a NID dry scrubber is 
appropriate, but argued that a NID dry scrubber is even more cost-
effective than what AEP and EPA have estimated. The Sierra Club's 
consultant presented cost analyses for wet and NID scrubbing for Flint 
Creek, based on the IPM cost algorithms we used in our recent Texas-
Oklahoma FIP. In so doing, the consultant applied the SDA cost 
algorithm to NID, citing to documentation that indicates that NID may 
be 1-2% lower in cost to an SDA system. The Sierra Club's consultant 
argues that both wet and dry scrubbers are capable of even greater 
levels of control than what we assumed.
    Response: As we discuss in our TSD,\223\ we noted a number of 
issues with AEP's NID and wet scrubber cost analyses that if corrected 
would have resulted in more favorable (lower $/ton) cost-effectiveness 
values. Nevertheless, even disregarding those errors, we concluded that 
NID was cost-effective and worth the visibility benefit that will 
result from its installation. We also determined that wet scrubbing 
would remain less cost-effective than NID, and was not worth the small 
additional visibility that would result from its installation in this 
particular instance.
---------------------------------------------------------------------------

    \223\ See page 65 of our TSD: ``[W]e believe that AEP's 
escalation of the cost of controls to 2016 dollars has likely 
resulted in the over estimation of the average cost-effectiveness 
values. Therefore, we believe a wet scrubber and NID are more cost-
effective (i.e., less dollars per ton of SO2 removed) 
than estimated by AEP (see table above). However, we did not adjust 
the cost numbers and cost-effectiveness values because we do not 
believe that doing so would change our proposed BART determination. 
We believe that the average cost-effectiveness of both control 
options was likely over-estimated and the costs associated with a 
wet scrubber would continue to be higher than the costs associated 
with NID if the estimates were adjusted, yet the installation and 
operation of a wet scrubber is projected to result in minimal 
incremental visibility improvement over NID.
---------------------------------------------------------------------------

    We extensively analyzed the performance potential of wet scrubbers 
in our recent Texas-Oklahoma FIP.\224\ We concluded that a control 
level of 98%, not to go below an emission rate of 0.04 lbs/MMBtu on a 
30-BOD average, was a reasonable lower level of control. We applied the 
same reasoning to our Arkansas proposal. As we discuss in our response 
to another comment, although we regard NID as a promising technology 
that may in fact be capable of greater levels of control than what we 
have assumed, there is no real long-term monitoring data to 
substantiate such a conclusion. Therefore, because we have concluded 
that in this instance the cost-effectiveness of wet scrubbers is not 
justified by their relatively small additional visibility benefit, we 
disagree that SO2 BART for Flint Creek Unit 1 should be 
0.04, based on the performance of a wet scrubber.
---------------------------------------------------------------------------

    \224\ See response to comment beginning on page 310 of our 
Response to Comments for the Federal Register Notice for the Texas 
and Oklahoma Regional Haze State Implementation Plans; Interstate 
Visibility Transport State Implementation Plan to Address Pollution 
Affecting Visibility and Regional Haze; and Federal Implementation 
Plan for Regional Haze, Docket No. EPA-R06-OAR-2014-0754, 12/9/2015.
---------------------------------------------------------------------------

    Comment: The Sierra Club and others stated that the LNB/OFA 
proposal for Flint Creek does not satisfy NOX BART, which 
should have been based on SCR. The Sierra Club stated that we and AEP 
used very conservative assumptions that inflated the cost of the SCRs 
and SNCRs as NOX BART options for Flint Creek. The Sierra 
Club's consultant stated that the 20-year life assumed in AEP's SCR 
cost analysis should have been 30 years, and that the assumed level of 
control should have been 0.04 lbs/MMBtu. The consultant then performed 
an SCR control cost analysis and concluded that the cost effectiveness 
was within a range we have previously found to be acceptable in other 
BART determinations. The Sierra Club's consultant also stated that AEP 
overestimated the cost of SNCR because it based it on a reduction of 
from 0.31 lbs/MMBtu to 0.2 lbs/MMBtu, when in fact, the first-in-line 
LNB/OFA controls would have already reduced the NOX to 0.23 
lbs/MMBtu, resulting in a lesser loading to the SNCR system and 
reducing its operating costs.
    Response: We note that we provided comments to ADEQ,\225\ which 
included a recommendation that 30 years should be used as an equipment 
life for SNCR. AEP did not adopt this recommendation in its September 
2013 BART analysis for the Flint Creek facility. We agree with the 
Sierra Club's consultant that AEP overestimated the cost of SNCR 
because its calculation based it on a reduction of from 0.31 lbs/MMBtu 
to 0.2 lbs/MMBtu. We have corrected this error, and the error in AEP 
SWEPCO's assumed 20-year equipment life, and recalculated the SNCR cost 
effectiveness for Flint Creek. We calculated that SNCR + LNB/OFA has a 
revised cost-effectiveness of $1,346/ton, as opposed to cost 
effectiveness of $1,258/ton for LNB/OFA alone. Also, we calculated that 
the incremental cost effectiveness of SNCR + LNB/OFA over LNB/OFA alone 
is $1,581/ton. We then re-applied the BART five factors, with emphasis 
on cost and visibility improvement. The incremental visibility 
improvement of SNCR + LNB/OFA over LNB/OFA alone is 0.033 dv at Caney 
Creek and ranges from 0.005 to 0.01 dv at each of the other affected 
Class I areas. As discussed in our proposal, we consider the 
incremental visibility improvement of SNCR + LNB/OFA to be relatively 
small at Caney Creek and to be very small in the remaining three 
affected Class I areas. We conclude that despite the improvement in the 
cost-effectiveness of SNCR + LNB/OFA over LNB/OFA alone, under these 
circumstances the resulting relatively small incremental visibility 
improvement is still not worth the additional cost of the more 
stringent controls.
---------------------------------------------------------------------------

    \225\ See email from Dayana Medina to Mary Pettyjohn on 8/21/13.
---------------------------------------------------------------------------

    Regarding the Sierra Club's consultant's SCR control cost analysis, 
we do not believe that a NOX emission limit of 0.04 lbs/
MMBtu has been maintained on a 30 boiler-operating-day average at other 
similar facilities. We conclude that, as we did in our New Mexico FIP, 
a 30 boiler-operating-day NOX average of 0.05 lbs/MMBtu is 
an appropriate assumption for SCR installation at the Flint Creek 
facility. We also note that the maximum visibility improvement due to 
SCR at Flint Creek based on the modeled rate of 0.067 lb/MMBtu was 
0.245 dv, which occurred at Caney Creek. If we make reasonable, 
conservative adjustments to the anticipated visibility benefit, based 
on a control level of 0.055 lbs/MMBtu rather than the modeled rate of 
0.067 lbs/MMBtu,\226\ we estimate that the resulting visibility 
improvement at Caney Creek would be no higher than

[[Page 66388]]

0.26 dv.\227\ Based on this adjustment, the incremental visibility 
improvement of SCR + LNB/OFA over SNCR + LNB/OFA is 0.146 dv. Even 
accepting the Sierra Club's consultant's SCR cost analysis of $3,511/
ton (which would be higher were it revised using a controlled 
NOX rate of 0.05 lbs/MMBtu) and taking into consideration 
the adjustments we have made to the cost analysis for SNCR + LNB/OFA, 
the incremental cost effectiveness of SCR + LNB/OFA over SNCR + LNB/OFA 
is $4,969/ton. In the context of this BART determination, we do not 
consider the relatively small incremental visibility improvement to be 
worth the incremental cost of the SCR installation.
---------------------------------------------------------------------------

    \226\ Modeled emission rates were based on a maximum heat input 
of 6,324 MMBtu/hr multiplied by the anticipated control rate (e.g. 
0.067 lb/MMBtu) Baseline emissions determined from 2001-2003 CAMD 
data were 1,945 lb/hr, approximately 0.308 lb/MMbtu.
    \227\ Modeled visibility benefit at CACR over baseline from SCR 
at 0.067lb/MMbtu was 0.245 dv. SCR at 0.055 lb/MMBtu would result in 
an additional reduction in emissions from baseline of only 4%. 
Assuming a linear relationship between emission and visibility 
impacts, this would also result in an increase in visibility benefit 
of only 4%.
---------------------------------------------------------------------------

    Comment: The Sierra Club and others stated that the Lake Catherine 
Unit 4 BART analysis failed to accurately consider compliance costs, 
non-environmental impacts, and the degree of visibility improvement. 
The Sierra Club further stated we underestimated the cost of BOOS and 
overestimated the costs of low NOX burners, over-fired air, 
SNCR, and SCR. The Sierra Club's consultant also alleges that the 
documentation to support the Lake Catherine NOX BART 
analysis is incomplete. Lastly, the Sierra Club stated that our cost-
effectiveness analysis should be based on a capacity calculation that 
depends on time of operation, and our proposal to use a 10% capacity is 
unenforceable. Had we used a higher capacity factor, the Sierra Club 
reasons that the increase in NOX emissions removed by the 
various pollution control equipment would have improved their cost-
effectiveness (lower $/ton), making them more attractive.
    Response: The Sierra Club's consultant raises a number of issues 
pertaining to missing documentation or errors in Entergy's 
NOX BART analysis for Lake Catherine Unit 4, on which we 
relied on in making our BART decision. We reviewed the issues raised by 
the Sierra Club's consultant in detail in our RTC document and conclude 
they are unfounded or lack documentation. We conducted an analysis of 
Lake Catherine's data on heat input, operational time, and 
NOX emissions to investigate the correlation between heat 
input and operational time to NOX emissions, and further 
conclude that capacity calculations for the Lake Catherine Unit 4 
should be based on heat input and not operational time. Lastly, we 
calculate the historical capacity for the Lake Catherine Unit 4 as 
follows:

           Table 20--Lake Catherine Unit 4 Historical Capacity
------------------------------------------------------------------------
                                                             Capacity
                          Year                              factor  (%)
------------------------------------------------------------------------
2001....................................................            28.2
2002....................................................            24.2
2003....................................................            11.3
2004....................................................             3.7
2005....................................................             4.7
2006....................................................             0.6
2007....................................................             0.8
2008....................................................             2.3
2009....................................................             2.8
2010....................................................             3.5
2011....................................................             2.9
2012....................................................            14.3
2013....................................................            11.1
2014....................................................             2.0
2015....................................................             3.9
------------------------------------------------------------------------

    We agree that the Lake Catherine Unit 4 historical capacity has 
sometimes exceeded the 10% capacity Entergy has assumed in its control 
cost analyses. However, the average from the last ten years of data 
(2006 to 2015) has been 4.4%. Typically, we place the most emphasis on 
the last five years of data, and our recent practice has been to 
discard the high and low values and average the remaining three 
years.\228\ Applying that procedure to the Lake Catherine Unit 4 
capacity factor results in a value of 6.0%. Alternatively, calculating 
a straight average of the last five years results in a value of 6.8%. 
Thus, we disagree that we erred in accepting Entergy's assumption of a 
10% capacity factor in its control cost analysis. We note that in its 
response to us, Entergy stated, ``If future capacity factors change, 
ADEQ and EPA may impose further NOX emission reductions on 
Unit 4, if necessary, in later planning periods to show reasonable 
progress.'' We believe that is an appropriate strategy and we will re-
examine Lake Catherine's historical capacity in our review of Arkansas' 
next regional haze SIP.
---------------------------------------------------------------------------

    \228\ This was our approach in calculating the SO2 
baselines used in our recent TX-OK FIP.
---------------------------------------------------------------------------

    Comment: We received comments from Nucor, Entergy and Conway 
Corporation stating that we should have used the dollar per deciview 
($/dv) metric to weigh the cost versus the visibility benefit of 
controls for the White Bluff and Independence facilities. The Sierra 
Club supported our position that we are not required to use this 
metric.
    Response: The BART Guidelines require that cost effectiveness be 
calculated in terms of annualized dollars per ton of pollutant removed, 
or $/ton.\229\ The BART Guidelines list the $/deciview metric as an 
optional cost effectiveness measure that can be employed along with the 
required $/ton metric for use in a BART evaluation. The metric can be 
useful in comparing control strategies or as additional information in 
the BART determination process; however, due to the complexity of the 
technical issues surrounding regional haze, we have never recommended 
the use of this metric as a cutpoint or threshold in making BART 
determinations or reasonable progress determinations. We note that to 
use the $/deciview metric as the main determining factor would most 
likely require the development of thresholds of acceptable costs per 
deciview of improvement for BART and reasonable progress determinations 
for both single and multiple Class I analyses. We have not developed 
such thresholds for use in BART or reasonable progress determinations. 
Generally speaking, while the $/deciview metric can be useful if 
thoughtfully applied, we view the use of this metric as suggesting a 
level of precision in the calculation of visibility impacts that is not 
justified in many cases. While we did not use a $/deciview metric in 
the BART and reasonable progress determinations we make in this FIP, we 
did, however, consider the visibility benefits and costs of control 
together, as noted above by weighing the costs in light of the 
predicted visibility improvement. We have addressed this issue in a 
number of our previous actions since we first discussed this issue in 
our Oklahoma FIP,\230\ and our position with regard to the $/deciview 
metric was reviewed and upheld in Oklahoma v. EPA, 723 F.3d 1201 by the 
Tenth Circuit which ruled:
---------------------------------------------------------------------------

    \229\ 70 FR at 39167.
    \230\ Response to Technical Comments for Sections E. through H. 
of the Federal Register Notice for the Oklahoma Regional Haze and 
Visibility Transport Federal Implementation Plan, Docket No. EPA-
R06-OAR-2010-0190, 12/13/2011, pdf 116.

    Oklahoma first suggests EPA should not have rejected the 
visibility analysis it conducted in the SIP, which used the dollar-
per-deciview method. This argument is misguided. The EPA rejected 
the SIP because of the flawed cost estimates. When promulgating its 
own implementation plan, it did not need to use the same metric as 
Oklahoma. The guidelines merely permit the BART-determining 
authority to use dollar per deciview as an optional method of 
evaluating cost effectiveness. See 40 CFR pt. 51 app. 
Y(IV)(E)(1).\231\ And in the final rule, the EPA

[[Page 66389]]

explained why it did not use the dollar-per-deciview metric used by 
Oklahoma. ``Generally speaking, while the metric can be useful if 
thoughtfully applied, we view the use of the $/deciview metric as 
suggesting a level of precision in the calculation of visibility 
impacts that is not justified in many cases.'' 76 Fed. Reg. at 
81,747. The EPA has never mandated the use of this metric, and has 
not developed ``thresholds of acceptable costs per deciview 
improvement.'' Id. While the federal land managers have developed 
thresholds, these thresholds were apparently developed without input 
from the EPA and without notice-and-comment review. EPA Br. at 54 n. 
13. In light of this, we do not find it arbitrary or capricious that 
the EPA chose not to use the dollar-per-deciview metric in 
evaluating BART options in creating the FIP. We therefore also 
conclude that any argument by the petitioners that the dollar-per-
deciview measurement proves the scrubbers are not cost effective 
lacks merit. See Pet. Reply Br. at 16.
---------------------------------------------------------------------------

    \231\ We note, however, that in both its final rule and in its 
brief the EPA asserts that the guidelines require the use of the 
dollar-per-ton metric in evaluating cost effectiveness. The 
guidelines themselves are a bit unclear. In the section on cost 
effectiveness, the guidelines mention only the dollar-per-ton 
metric. 40 CFR pt. 51 app. Y(IV)(D)(4)(c). However, the guidelines 
later state that in evaluating alternatives, ``we recommend you 
develop a chart (or charts) displaying for each of the 
alternatives'' that includes, among other factors, the cost of 
compliance defined as ``compliance--total annualized costs ($), cost 
effectiveness ($/ton), and incremental cost effectiveness ($/ton), 
and/or any other cost-effectiveness measures (such as $/deciview).'' 
Id. app.Y(IV)(E)(1) (emphasis added).

    We see no reason to deviate from our view of the $/deciview metric 
here.

J. Modeling

1. Cumulative Visibility Impairment
    Comment: Several commenters opposed the use of a ``cumulative 
deciviews'' or ``total'' visibility improvement metric and claim the 
``cumulative deciviews'' metric has no basis in the CAA and EPA's 
regulations. It also allegedly mischaracterizes visibility improvements 
in Class I areas. Determinations instead should be based on the 
predicted visibility improvements at individual Class I areas. 
Furthermore, the cumulative metric is deceptive and provides no 
information that could be used to assess whether any single Class I 
area would experience perceivable visibility improvements as a result 
of BART or reasonable progress controls, and may mask the fact that no 
individual Class I area would experience any discernible visibility 
improvement from control of emissions at any particular source. The 
cumulative metric represents an illusory visibility benefit; it is an 
improvement that cannot be perceived and therefore provides no 
indication of whether the proposed controls will contribute to the goal 
of the regional haze program: To reduce human perception of visibility 
impairment in Class I areas. The only purpose of the cumulative 
visibility improvement indicator is to imply that facilities are having 
a large impact across numerous Class I areas, but this indicator can be 
deceptive if it includes imperceptible visibility improvements for some 
Class I areas.
    The commenters also suggest that the use of a ``total dv'' metric 
is inconsistent with BART guidelines (40 CFR part 51 Appendix Y, 
IV.D.5) that state it is appropriate to model impacts at the nearest 
Class I area as well as other nearby Class I areas to determine where 
the impacts are greatest. Modeling at other Class I areas may be 
unwarranted if the highest modeled effects are observed at the nearest 
Class I area. The commenters claim the analysis should be focused on 
the visibility impacts at the most impacted area, not all areas. Other 
commenters supported the use of the cumulative visibility metric, 
stating that it is appropriate and lawful, and within the spirit of the 
statutory mandate and expressly permissible within the regulation to 
consider cumulative impacts.
    Response: We agree with the comments supporting the consideration 
of cumulative visibility impacts and benefits. We disagree with the 
other commenters that cumulative improvement over multiple areas is an 
inappropriate metric, or that examining a single Class I area is 
sufficient. The cumulative improvement metric (i.e., the simple sum of 
impacts or improvements over all the affected Class I areas) is not 
intended to correspond to a single human's perception at a given time 
and place. The approach is simply one way of assessing improvements at 
multiple areas, for consideration along with other visibility metrics. 
Another approach would be to simply list visibility improvements at the 
various areas, and qualitatively weigh the number of areas and the 
magnitudes of the improvements. The cumulative sum is simply an easily 
understood and objective way of weighing cumulative visibility 
improvement, as part of the overall control evaluation along with the 
visibility improvement at each impacted Class I area. As noted by some 
comments, we have calculated cumulative visibility in a number of 
Regional Haze actions evaluating the benefits of controls under BART 
and when visibility is considered in the reasonable progress analysis. 
Furthermore, the FLMs have provided comments in support of the use of 
this metric in past actions.\232\
---------------------------------------------------------------------------

    \232\ For example, see 76 FR 52388, 52429 (August 22, 2011).
---------------------------------------------------------------------------

    The comment opposing cumulative modeling does not provide the full 
context when citing to the BART guidelines. The portion referred to by 
the commenter discusses the development of a modeling protocol and 
establishing the receptors to model. The full portion of the BART 
Guidelines that the commenter referenced states:

    The receptors that you use should be located in the nearest 
Class I area with sufficient density to identify the likely 
visibility effects of the source. For other Class I areas in 
relatively close proximity to a BART-eligible source, you may model 
a few strategic receptors to determine whether effects at those 
areas may be greater than at the nearest Class I area. For example, 
you might chose to locate receptors at these areas at the closest 
point to the source, at the highest and lowest elevation in the 
Class I area, at the IMPROVE monitor, and at the approximate 
expected plume release height. If the highest modeled effects are 
observed at the nearest Class I area, you may choose not to analyze 
the other Class I areas any further as additional analyses might be 
unwarranted.\233\
---------------------------------------------------------------------------

    \233\ 40 CFR 51 Appendix Y, IV.D.5.

    This section of the BART Guidelines addresses how to determine 
visibility impacts as part of the BART determination. Several 
paragraphs later in the BART Guidelines it states: ``You have 
flexibility to assess visibility improvements due to BART controls by 
one or more methods. You may consider the frequency, magnitude, and 
duration components of impairment,'' emphasizing the flexibility in 
method and metrics that exists in assessing the net visibility 
improvement.
    In fully considering the visibility benefits anticipated from the 
use of an available control technology as one of the factors in 
selection of BART, it is appropriate to account for visibility benefits 
across all affected Class I areas and the BART guidelines provide the 
flexibility to do so. One approach as noted above is to qualitatively 
consider, for example, the frequency, magnitude, and duration of 
impairment at each and all affected Class I areas. Where a source 
significantly impacts more than one Class I areas, the cumulative 
visibility metric is one way to take magnitude of the impacts of the 
source into account.
    With respect to our analysis of controls under reasonable progress, 
we rely on our Reasonable Progress Guidance.\234\ Our Reasonable 
Progress Guidance notes the similarity between some of the reasonable 
progress factors and the BART factors contained in Sec.  
51.308(e)(1)((ii)(A), and suggests that

[[Page 66390]]

the BART Guidelines be consulted regarding cost, energy and nonair 
quality environmental impacts, and remaining useful life. We are 
therefore relying on our BART Guidelines for assistance in interpreting 
those reasonable progress factors, as applicable.
---------------------------------------------------------------------------

    \234\ ``Guidance for Setting Reasonable Progress Goals Under the 
Regional Haze Program,'' June 1, 2007.
---------------------------------------------------------------------------

    Also, similar to a BART analysis, we are also considering the 
projected visibility benefit in our analysis following the BART 
guidelines and the use of CALPUFF.\235\ We rely on the BART Guidelines 
here and in other actions evaluating reasonable progress controls 
because they provide a reasonable and consistent approach regarding 
visibility modeling. This includes the flexibility in metrics that 
exists in assessing the net visibility improvement, and the use of 
cumulative visibility, along with visibility impacts at individual 
Class I areas, as one way to take magnitude of the impacts of the 
source into account where a source evaluated under reasonable progress 
significantly impacts more than one Class I area.
---------------------------------------------------------------------------

    \235\ As we explain in our proposed action (80 FR at 18993): 
``While visibility is not an explicitly listed factor to consider 
when determining whether additional controls are reasonable under 
the reasonable progress requirements, the purpose of the four-factor 
analysis is to determine what degree of progress toward natural 
visibility conditions is reasonable. Therefore, it is appropriate to 
consider the projected visibility benefit of the controls when 
determining if the controls are needed to make reasonable 
progress''. See 79 FR at 74838, 74840, and 74874.
---------------------------------------------------------------------------

    For each subject-to-BART source and the source evaluated for 
reasonable progress controls, we evaluated the visibility impacts from 
the source and benefits of controls at four separate Class I areas. In 
addition to providing the visibility impacts and potential benefits at 
each Class I area in the proposal, we also summed the impact and 
improvement across the four Class I areas. The results show that some 
sources significantly impact visibility at more than one Class I area, 
emission reductions result in visibility benefits at all impacted class 
I areas, and in some situations, the largest visibility benefits from 
controls can occur at Class I areas other than the most impacted.
    Therefore, consistent with the BART Guidelines, and based upon 
these facts, we determined additional analyses were not only warranted 
but necessary. The BART Guidelines only indicate that additional 
analyses may be unwarranted at other Class I areas, and in no way 
exclude such analyses, as the commenter suggests. We concluded that a 
quantitative analysis of visibility impacts and benefits at only the 
most impacted area would not be sufficient to fully assess the impacts 
and benefits of controlling emissions from the sources evaluated for 
BART and reasonable progress.
    Nothing in the Regional Haze Rule suggests that a state (or EPA in 
issuing a FIP) should ignore the full extent of the visibility impacts 
and improvements from controls at multiple Class I areas. Given that 
the national goal of the program is to improve visibility at all Class 
I areas, it would be short-sighted to limit the evaluation of the 
visibility benefits of a control to only the most impacted Class I 
area. We believe such information is useful in quantifying the overall 
benefit of controls. As discussed in our proposal, we evaluated the 
statutory factor, visibility benefits anticipated due to controls, at 
each Class I area in making BART determinations and considered the 
visibility benefits in consideration of controls for reasonable 
progress.
2. Imperceptible Visibility Improvement
    Comment: EPA must withdraw the proposed FIP because the FIP would 
only achieve visibility improvements below one deciview, which is not 
discernible to the naked eye. Commenters state that the CAA only 
provides EPA with the authority to regulate the ``impairment of 
visibility.'' \236\ Visibility extends only to things that humans can 
see with their naked eyes.\237\ By extension, EPA only has authority to 
regulate the impairments of visibility that are perceptible to the 
human eye. Under both the plain language and dictionary definitions of 
``visibility,'' the statute does not provide EPA with the authority to 
regulate haze below a single deciview, which would be invisible to the 
naked eye. Since the Proposed FIP will only achieve visibility 
improvements smaller than one deciview, the EPA lacks authority to 
revise the RPGs suggested by Arkansas, and it should withdraw the 
Proposed FIP.
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    \236\ CAA section 169A (``Congress hereby declares as a national 
goal the prevention of any future, and the remedying of any 
existing, impairment of visibility in mandatory class I Federal 
areas which impairment results from manmade air pollution.) 
(emphasis added).
    \237\ E.g. Webster's Third New International Dictionary 2557 
(1981) (``visible'' means ``capable of being seen''; ``visibility'' 
means ``the degree or extent to which something is visible . . . 
[by] the observer's eye unaided by special optical devices'').
---------------------------------------------------------------------------

    Commenters also state that the EPA may not require a source ``to 
spend millions of dollars for new technology that will have no 
appreciable effect on haze in any Class I area.'' Am. Corn Growers 
Ass'n. v. EPA \238\ (vacating EPA's BART determinations because EPA 
left open the possibility that it could require a source to install 
technologies even when those technologies had no appreciable effect on 
visibility). Yet the EPA requires certain stationary sources of immense 
value to the State of Arkansas and its citizens to install controls 
that will cost billions of dollars in order to achieve imperceptible 
visibility improvements.
---------------------------------------------------------------------------

    \238\ Am. Corn Growers Ass'n v. EPA, 291 F.3d 1, 7 (D.C. Cir. 
2002).
---------------------------------------------------------------------------

    Response: We disagree with commenters that the Regional Haze Rule 
requires that controls on a source or group of sources result in 
perceptible visibility improvement.\239\ We believe, for reasons we 
have outlined in our proposal and elsewhere in our response to 
comments, that the controls we proposed under our FIP will result in 
significant improvements in visibility at a number of Class I areas. In 
a situation where the installation of BART may not result in a 
perceptible improvement in visibility, the visibility benefit may still 
be significant, as explained by the Regional Haze Rule:
---------------------------------------------------------------------------

    \239\ It is generally recognized that a change in visibility of 
1.0 deciview is humanly perceptible.

    Even though the visibility improvement from an individual source 
may not be perceptible, it should still be considered in setting 
BART because the contribution to haze may be significant relative to 
other source contributions in the Class I area. Thus, we disagree 
that the degree of improvement should be contingent upon 
perceptibility. Failing to consider less-than-perceptible 
contributions to visibility impairment would ignore the CAA's intent 
to have BART requirements apply to sources that contribute to, as 
well as cause, such impairment.\240\
---------------------------------------------------------------------------

    \240\ 70 FR 39104, 39129.

    Section 169A of the CAA requires that certain major sources that 
emit any pollutant which may reasonably be anticipated to cause or 
contribute to visibility impairment in Class I Areas install BART. The 
following factors must be taken into account in determining BART: The 
costs of compliance, the energy and nonair quality environmental 
impacts of compliance, any existing pollution control technology in use 
at the source, the remaining useful life of the source, and the degree 
of improvement in visibility which may reasonably be anticipated to 
result from the use of such technology.\241\
---------------------------------------------------------------------------

    \241\ CAA section 169A(g)(2).
---------------------------------------------------------------------------

    The CAA also requires that in determining reasonable progress there 
shall be taken into consideration the costs of compliance, the time 
necessary for compliance, the energy and nonair

[[Page 66391]]

quality environmental impacts of compliance, and the remaining useful 
life of any existing source subject to such requirements. Our 2007 
Reasonable Progress Guidance \242\ notes the similarity between some of 
the reasonable progress factors and the BART factors contained in Sec.  
51.308(e)(1)(ii)(A), and suggests that the BART Guidelines be consulted 
regarding cost, energy and nonair quality environmental impacts, and 
remaining useful life. We are therefore relying on our BART Guidelines 
for assistance in interpreting those reasonable progress factors, as 
applicable, including visibility improvement even though it may not be 
perceptible from an individual source. Also, similar to a BART 
analysis, we are also considering the projected visibility benefit in 
our analysis of reasonable progress controls following the BART 
guidelines.\243\ We rely on the BART Guidelines here and in other 
actions evaluating reasonable progress controls because they provide a 
reasonable and consistent approach regarding visibility modeling.
---------------------------------------------------------------------------

    \242\ ``Guidance for Setting Reasonable Progress Goals Under the 
Regional Haze Program,'' June 1, 2007.
    \243\ As we explain in our proposed action (80 FR at 18993): 
``While visibility is not an explicitly listed factor to consider 
when determining whether additional controls are reasonable under 
the reasonable progress requirements, the purpose of the four-factor 
analysis is to determine what degree of progress toward natural 
visibility conditions is reasonable. Therefore, it is appropriate to 
consider the projected visibility benefit of the controls when 
determining if the controls are needed to make reasonable 
progress''. See also 79 FR at 74838, 74840, and 74874.
---------------------------------------------------------------------------

    We accordingly disagree that selection of control measures under 
BART or for reasonable progress should be contingent upon perceptible 
visibility improvement. As we stated in our previous rulemaking 
addressing the BART determinations in Oklahoma:

    Given that sources are subject to BART based on a contribution 
threshold of no greater than 0.5 deciviews, it would be inconsistent 
to automatically rule out additional controls where the improvement 
in visibility may be less than 1.0 deciview or even 0.5 deciviews. A 
perceptible visibility improvement is not a requirement of the BART 
determination because visibility improvements that are not 
perceptible may still be determined to be significant.\244\
---------------------------------------------------------------------------

    \244\ 76 FR 81728, 81739.

    The Regional Haze Rule provides that BART-eligible sources with a 
0.5 dv impact at a Class I area ``contribute'' to visibility impairment 
and must be analyzed for BART controls. BART determining authorities, 
however, are free to establish thresholds less than 0.5 dv. 
Consequently, even though the visibility improvement from controlling 
an individual source may not be perceptible, it should still be 
considered because the contribution to haze may be significant when the 
aggregate contribution of other sources in the Class I area is taken 
into account and because the contribution to haze from the source may 
be significant relative to other source contributions in the Class I 
area. Thus, in our visibility improvement analysis for BART sources and 
in consideration of visibility benefits from controls under our 
reasonable progress analysis, we have not considered perceptibility as 
a threshold criterion for considering improvements in visibility to be 
meaningful.
    We have considered visibility improvement in a holistic manner, 
taking into account all reasonably anticipated improvements in 
visibility, and the fact that, in the aggregate, improvements from 
controls on multiple sources (either under BART or reasonable progress) 
will contribute to visibility progress towards the goal of natural 
visibility conditions. Visibility impacts below the thresholds of 
perceptibility cannot be ignored because regional haze is produced by a 
multitude of sources and activities which are located across a broad 
geographic area. In this action, we found that the required cost-
effective controls reduce visibility impairment from those BART sources 
that contribute or cause visibility impairment at nearby Class I areas 
and result in meaningful visibility benefits towards the goal of 
natural visibility conditions. Similarly, we also found that the 
required cost-effective controls at the Entergy Independence facility 
reduce visibility impairment from the source with the largest potential 
visibility impacts (among all Non-BART sources) and result in 
meaningful visibility benefits towards the goal of natural visibility 
conditions.
    The commenter mischaracterizes a statement made by the D.C. Circuit 
Court of Appeals in Am. Corn Growers Ass'n. v. EPA. The statement made 
by the Court is as follows: ``[U]nder EPA's take on the statute, it is 
therefore entirely possible that a source may be forced to spend 
millions of dollars for new technology that will have no appreciable 
effect on the haze in any Class I area.'' \245\ The Court made this 
statement in reviewing EPA's approach to the BART requirements in the 
Regional Haze Rule promulgated in 1999 which did not require the 
source-specific assessment of a BART eligible source's visibility 
impacts at any step of the BART process.\246\
---------------------------------------------------------------------------

    \245\ Am. Corn Growers Ass'n v. EPA, 291 F.3d 1, 7 (D.C. Cir. 
2002).
    \246\ Id.
---------------------------------------------------------------------------

    The Court disagreed with the approach used by EPA to determine what 
BART eligible sources are reasonably anticipated to cause or contribute 
to regional haze and therefore subject to BART.\247\ The approach in 
the Regional Haze Rule required a State to analyze ``the degree of 
visibility improvement that would be achieved in each mandatory Class I 
Federal area as a result of the emission reductions achievable from all 
sources subject to BART located within the region that contributes to 
visibility impairment in the Class I area.'' \248\ The Court held that 
the Rule's treatment of ``the degree of improvement in visibility which 
may reasonably be anticipated to result from the use of such 
technology'' factor infringed on states' authority with respect to BART 
determinations under the Act.\249\ The Court noted that the Act does 
not assign a specific weight with which to consider each factor, it 
solely mandates that all the factors be considered in making a BART 
determination.\250\ The Court's issue was not with the weight, or lack 
thereof, placed on this factor by EPA. It found issue with what it 
considered to be ``dramatically'' different treatment of the visibility 
factor by EPA. Id. While the court in American Corn Growers Ass'n. v. 
EPA found that we had impermissibly constrained State authority, it did 
so because it found that we forced States to require BART controls 
without first assessing a source's particular contribution to 
visibility impairment. This is not the case with our action in 
Arkansas. In response to this court decision and to address these 
concerns we finalized revised Regional Haze Regulations and Guidelines 
for Best Available Retrofit Technology (BART) Determinations.\251\
---------------------------------------------------------------------------

    \247\ Id. at 7-8.
    \248\ 40 CFR 51.308(e)(1)(ii)(B).
    \249\ Id.
    \250\ 291 F.3d at 6.
    \251\ 70 FR 39104.
---------------------------------------------------------------------------

    Our analysis does not give greater weight to one factor over 
another; rather, we considered all five BART factors fully, revealing 
that the cost and visibility factors were the two most important 
factors in our decisions. In American Corn Growers Ass'n. v. EPA, the 
D.C. Circuit Court faulted how EPA assessed the statutory fifth factor 
of visibility improvement in a BART determination by using a regional, 
multi-source, group approach to assessing the visibility improvement 
factor, while assessing the other four

[[Page 66392]]

statutory BART factors on a source-specific basis. Here, we did not 
give greater weight to our consideration of visibility improvement or 
consider the visibility in a different fashion from the other factors. 
All BART factors were evaluated on a source-specific basis.
    The Court also noted that it is the State's and not EPA's duty to 
determine what BART is (provided that the State's determination 
complies with the Act and EPA guidelines.\252\). When EPA promulgates a 
FIP, it is acting in the place of the State, and thus has the same 
authority a state has when the state promulgates a SIP. It is therefore 
our duty to determine what BART is since we are proposing a FIP for 
Arkansas. We must also consider the same factors that the State is 
mandated to consider by the CAA. The ``degree of improvement in 
visibility which may reasonably be anticipated to result from the use 
of such [best available retrofit] technology'' is just one of several 
factors the State, or EPA in the case of a FIP, must consider in 
determining what BART is for a specific source.
---------------------------------------------------------------------------

    \252\ 291 F. 3d at 8-9.
---------------------------------------------------------------------------

    We also disagree with commenter's statement that we required 
emissions reductions just for the sake of doing so under the guise of 
imperceptible visibility improvements or solely for the sake of 
reducing emissions. As discussed above, we considered all the statutory 
factors, including the ``degree of improvement in visibility which may 
reasonably be anticipated to result from the use of such [best 
available retrofit] technology'' in our BART determinations. We do not 
consider perceptibility as a threshold criterion for considering 
improvements in visibility to be meaningful. Failing to consider less-
than-perceptible contributions to visibility impairment would ignore 
the CAA's intent to have BART requirements apply to sources that 
contribute to, as well as cause, such impairment.
    Comment: One commenter stated that the visibility benefits of some 
of the required controls either individually or in combination will 
result in perceptible visibility benefits. They also comment that the 
regional haze regulations reflect EPA's finding that the Congressional 
goal of eliminating haze can be achieved only by tackling the multitude 
of sources that contribute to haze in national parks and wilderness 
areas. For this reason, EPA has stated that ``visibility improvement 
does not need to be perceptible to be deemed significant for BART 
purposes.'' \253\
---------------------------------------------------------------------------

    \253\ 79 FR 5032, 5120 (January 30, 2014).
---------------------------------------------------------------------------

    Response: We agree with the commenter. As we discuss in response to 
comments above, the Regional Haze Rule does not require that controls 
on a source or group of sources result in perceptible visibility 
improvement. We also agree that in some cases required controls either 
individually or in combination with other required controls will result 
in perceptible visibility improvements at impacted Class I areas on 
some days.
3. Model Selection
    Comment: CALPUFF modeling cannot be used to justify controls at 
Independence under the reasonable progress requirements. Using CALPUFF, 
a single source model, for evaluating the reasonable progress benefits 
of installing controls at Independence is misplaced and clearly in 
error. EPA must demonstrate that additional controls are rational and 
economically justifiable and that the amount of progress that would 
result will be ``reasonable based upon the statutory factors.'' CALPUFF 
is overly simplistic and greatly overstates the effect of single source 
emissions.\254\ CALPUFF also fails to show the effects of multiple 
sources, and is much less sophisticated in its treatment of the 
chemical interactions of the different pollutants in the atmosphere 
than CAMx. The commenters also state that the use of CALPUFF does not 
reflect the interaction of pollutants in the atmosphere as accurately 
as CAMx does.
---------------------------------------------------------------------------

    \254\ BART Guidelines, 70 FR 39104, 39121 (``there are other 
features of our recommended modeling approach that are likely to 
overstate the actual visibility effects of an individual source. 
Most important, the simplified chemistry in the model tends to 
magnify the actual visibility effects of that source.'')
---------------------------------------------------------------------------

    EPA used CALPUFF and did not perform refined, multi-state modeling 
to determine the amount of visibility improvements that would be 
achieved through the installation of controls because it would be 
difficult, time-consuming, and expensive. Instead, the Agency took a 
``thumbnail'' approach in an attempt to justify the proposed controls 
based on how long it would take to achieve background levels.
    EPA recognized in their action on Texas regional haze that CAMx, a 
photochemical transport 3-dimensional grid model, is a more appropriate 
modeling tool for reasonable progress purposes.\255\ BART analyses 
assess the impact of a single facility based on the maximum or 98th 
percentile impacts, regardless of whether the Class I area was actually 
experiencing high visibility impairment on any given day. Since CALPUFF 
does not conduct an analysis considering all the emissions from all 
potential sources, some of the days with the worst model-predicted 
concentrations could be days that are not significantly impaired. 
Reasonable progress modeling using a photochemical model, such as CAMx, 
allows EPA to evaluate impacts from a source (with all other sources 
included in the modeling) on a Class I area's best and worst days.\256\
---------------------------------------------------------------------------

    \255\ Proposed Texas Regional Haze FIP, 79 FR 74818, 74877, 
74878.
    \256\ Id. at 74878.
---------------------------------------------------------------------------

    The draft EPA Modeling Guidance for Demonstrating Attainment of Air 
Quality Goals for Ozone, PM2.5, and Regional Haze (Dec. 2014) (``Draft 
Modeling Guidance'') discusses the use of photochemical grid models. 
The Draft Modeling Guidance specifically notes that ``a modeling based 
demonstration of the impacts of an emissions control scenario . . . as 
part of a regional haze assessment usually necessitates the application 
of a chemical transport grid model.'' \257\ Throughout the Draft 
Modeling Guidance, the discussion is focused on items specific to 
photochemical grid models such as CAMx, including emissions 
inventories, supporting models, pre-processors, and applying a model to 
changes in visibility.
---------------------------------------------------------------------------

    \257\ Draft Modeling Guidance at 22. The Draft Modeling Guidance 
is available at http://www.epa.gov/scram001/guidance/guide/Draft_O3-PMRH_Modeling_Guidance-2014.pdf.
---------------------------------------------------------------------------

    Notably, EPA recently issued a proposal, which would remove CALPUFF 
from EPA's preferred list of air dispersion models in its Guideline on 
Air Quality Models \258\ (``Guideline''). Although EPA states that the 
proposed changes to the Guideline would not affect its recommendation 
that CALPUFF be used in the BART determination process, EPA made no 
such assurances regarding the use of CALPUFF for a reasonable progress 
analysis. EPA's proposal emphasizes the use of chemical transport 
models for assessing visibility impacts from a single source or small 
group of sources.
---------------------------------------------------------------------------

    \258\ Appendix W to 40 CFR part 51.
---------------------------------------------------------------------------

    EPA's Interagency Workgroup on Air Quality Modeling Phase 3 Summary 
Report: Long Range Transport and Air Quality Related Values \259\ makes 
clear that CALPUFF should not be used for a reasonable progress 
analysis.
---------------------------------------------------------------------------

    \259\ Docket ID EPA-HQ-OAR-2015-0310-0004.
---------------------------------------------------------------------------

    Another commenter, EarthJustice, states that the other commenter's 
assessment of the methodology used for Texas sources is incorrect. In 
fact, EPA also used an emission ``scaling'' approach to determine the 
effects of various control scenarios for their evaluation of Texas 
sources that is

[[Page 66393]]

similar to that currently being applied for the evaluation of the 
sources in Arkansas. EPA Region 6 did not run the CAMx model repeatedly 
to determine the overall visibility effects of controlling individual 
sources.
    Response: The commenters confuse the single source analysis for 
evaluating the visibility impact and benefits of controls on units at 
the Independence facility and the analysis to estimate the visibility 
benefits of all controls on the 20% worst days in establishing a new 
reasonable progress goal for 2018. We utilized CALPUFF modeling 
following the same modeling protocol relied on for the BART analyses to 
assess the visibility impacts and potential benefits of controls for 
the units at the Independence facility. For estimating the total 
visibility benefit from all controls and estimating a new reasonable 
progress goal that reflects those controls, we relied on the CENRAP's 
2018 CAMx modeling results, including source apportionment results, and 
the projected emission inventories, and scaled the results as described 
in the TSD. While we acknowledge that this approach is not as refined 
an estimate as would be attained in performing a new photochemical 
modeling run, it is based on scaling of earlier photochemical modeling 
results and not on CALPUFF modeling, as the commenter suggests. We 
disagree with the commenter's characterization of our analysis as a 
``thumbnail'' approach and noted in our proposal that similar 
approaches have been used in other actions in Hawaii and Arizona. As 
discussed in the proposed action, our determination that controls were 
reasonable for the Independence units was based on our evaluation of 
the four factors and including consideration of the visibility benefit 
of controls. For consideration of the visibility benefits, we relied on 
the results of our CALPUFF modeling, the CENRAP CAMx source 
apportionment results, and point source emission inventory data that 
initially identified the Independence facility as having the greatest 
potential to impact visibility at nearby Class I areas among all 
sources not already controlled under the BART requirements.
    The 2005 BART Guidelines recommended the use of CALPUFF for 
assessing visibility (secondary chemical impacts) but noted that 
CALPUFF's chemistry was fairly simple. The visibility results from 
CALPUFF could be used as one of the five factors in a BART evaluation 
and the impacts should be utilized in a somewhat relative sense because 
CALPUFF was not explicitly approved for full chemistry 
calculations.\260\ The BART guidelines also provided the option to 
potentially use photochemical grid models (such as CAMx) in the future 
if modeling tools available were appropriate and EPA approved of the 
technical approaches and how the model would be utilized.\261\ Appendix 
W gives us discretionary authority in the selection of what models to 
use for visibility assessments with modeling systems, and models such 
as CALPUFF, CMAQ, REMSAD, and CAMx have all been used for that purpose. 
Specifically for single-source reasonable progress assessments similar 
to that done here for Independence, CALPUFF has been used for the 
majority of sources, while CAMx has been used in some situations, most 
notably and as noted by the commenter, in evaluating specific Texas 
sources for reasonable progress. In 2006/7, EPA OAQPS and EPA Region 6 
consulted with FLM representatives and approved Texas' BART screening 
modeling protocol using source apportionment tools in CAMx.\262\
---------------------------------------------------------------------------

    \260\ 70 FR 39104, 39123, 39124. ``We understand the concerns of 
commenters that the chemistry modules of the CALPUFF model are less 
advanced than some of the more recent atmospheric chemistry 
simulations. To date, no other modeling applications with updated 
chemistry have been approved by EPA to estimate single source 
pollutant concentrations from long range transport.'' and in 
discussion of using other models with more advanced chemistry it 
continues, ``A discussion of the use of alternative models is given 
in the Guideline on Air Quality in appendix W, section 3.2.''
    \261\ 70 FR at 39123, 39124. ``The use of other models and 
techniques to estimate if a source causes or contributes to 
visibility impairment may be considered by the State, and the BART 
guidelines preserve a State's ability to use other models. Regional 
scale photochemical grid models may have merit, but such models have 
been designed to assess cumulative impacts, not impacts from 
individual sources. Such models are very resource intensive and time 
consuming relative to CALPUFF, but States may consider their use for 
SIP development in the future as they are adapted and demonstrated 
to be appropriate for single source applications.''
    \262\ See Appendix 9-4: CAMx Modeling Protocol, Screening 
Analysis of Potentially BART-Eligible Sources in Texas of the Texas 
regional haze SIP.
---------------------------------------------------------------------------

    Under the BART guidelines, CALPUFF should be used as a screening 
tool and appropriate consultation with the reviewing authority is 
required to use CALPUFF in a BART determination as part of a SIP or 
FIP. The BART Guideline cited and referred to EPA's Guideline on Air 
Quality Models (Appendix W) \263\ which includes provisions to obtain 
approval through consultation with the reviewing authority. Moreover, 
we also note that in EPA's document entitled Guidance on the Use of 
Models and Other Analyses for Demonstrating Attainment of Air Quality 
Goals for Ozone, PM2.5, and Regional Haze (EPA-454/B-07-
002), that Appendix W does not identify a particular modeling system as 
`preferred' for modeling conducted in support of state implementation 
plans under 40 CFR 51.308(b). A model should meet several general 
criteria for it to be a candidate for consideration. These general 
criteria are consistent with the requirements of 40 CFR 51.112 and 40 
CFR 51, Appendix W. Therefore, it is correct to interpret that no model 
system is considered `preferred' under 40 CFR 51, Appendix W, Section 
3.1.1 (b) for either secondary particulate matter or for visibility 
assessments. Under this general framework, we followed the general 
recommendation in Appendix Y to use CALPUFF as a screening technique 
since the modeling system has not been specifically approved for 
chemistry. The use of CALPUFF is subject to Appendix W requirements in 
section 3.0(b), 4, and 6.2.1(e) which includes an approved protocol to 
use the current version.
---------------------------------------------------------------------------

    \263\ 40 CFR part 51 Appendix W, Guideline on Air Quality 
Models, 70 FR 68218 (November 9, 2005).
---------------------------------------------------------------------------

    We and some states have used CALPUFF to model visibility benefits 
as part of the reasonable progress analysis, and have used largely the 
same methodology as in BART modeling (i.e. use of 24 hour or hourly 
maximum emissions, a ``clean'' background condition, and a maximum or 
98th percentile metric).\264\ This approach provides information on the 
relative visibility benefits of controls to inform the evaluation of 
cost-effectiveness as part of the four factor analysis and has the 
benefit that it is immediately comparable to modeling used for BART 
determinations. Compared to a CAMx modeling exercise, CALPUFF modeling 
of one or more sources requires much less resources and time. However, 
the CALPUFF approach models the impacts from the single facility with 
limited chemistry and focuses on the maximum impacts from the source 
rather than the visibility impairment on the 20% worst days. We agree 
with the commenter that the CAMx model may be better suited for 
evaluating the average visibility impairment due to individual sources 
during the 20% worst days as part of reasonable progress analysis. 
Photochemical models, like the CAMx model, provide a complete 
representation of emissions, chemistry, transport, and deposition, 
while CALPUFF treats a single source with simplified chemistry and 
parameterized physical processes. Furthermore, the

[[Page 66394]]

CAMx model can be used to evaluate a large number of individual 
sources, and there are concerns in using CALPUFF for modeling impacts 
at distances much greater than 300 km from the source. In our analysis 
of source-specific impacts of Texas sources, we determined that CAMx 
was best suited for the complex analysis that we needed to perform in 
evaluating a large number of sources (38 separate facilities for our 
initial analysis) at distances from impacted Class I areas much larger 
than 300km, and in focusing on the 20% worst days. We discuss our 
selection of CAMx modeling in our Texas analysis in depth in the RTC 
document that accompanies that action.\265\ As noted by EarthJustice, 
we did not perform a final CAMx model scenario to obtain the new RPGs 
in our Texas action, and instead relied on a scaling analysis similar 
to the methodology used in this action to adjust the CENRAP modeled RPG 
values based on the source apportionment data and emissions data 
available. As discussed above, RPGs were adjusted in actions in 
Arizona, Hawaii, Texas/Oklahoma and in this action by estimating the 
visibility improvement due to required controls based on scaling the 
anticipated emission reductions and the source apportionment modeling. 
In Texas/Oklahoma, source-specific source apportionment data and 
emissions were utilized. In the other states, emissions and source-
apportionment data on a state and source category level were utilized.
---------------------------------------------------------------------------

    \264\ For example see summary of the reasonable progress 
analyses for specific sources in Arizona (79 FR 9353), North Dakota 
(76 FR 58631), Montana (77 FR 24065), and Wyoming (78 FR 34785).
    \265\ Texas Regional Haze FIP, EPA Response to Comments 
Document, available at www.regulations.gov, Document ID: EPA-R06-
OAR-2014-0754-0087.
---------------------------------------------------------------------------

    Consistent with the examples discussed above,\266\ in evaluating 
the sources in Arkansas, we determined that CALPUFF was adequate since 
we determined that only one source needed to be assessed for a 
reasonable progress evaluation, and that source was well within the 
recommended range for CALPUFF modeling of under 300km from the Class I 
areas of interest. In fact, three of the four impacted Class I areas 
lie within 200km of the source. We discuss comments concerning why our 
reasonable progress screening analysis focused on NOX and 
SO2 emissions from Arkansas point sources and our 
determination that additional analysis was necessary for the 
Independence facility in response to comments elsewhere in this 
document. In evaluating visibility impacts and benefits for those 
sources subject to BART, we relied on CALPUFF modeling prepared by the 
facilities. Utilizing CALPUFF for the reasonable progress analysis on 
Independence provided for a consistent approach for all facilities and 
allowed for direct comparison of the visibility impacts and benefits 
across all facilities impacted by the proposed rulemaking. In some 
situations, the CALPUFF modeled maximum or 98th percentile impacts of 
the facility may not coincide with the days that make up the worst 20% 
monitored days at the Class I area. Therefore, the visibility benefits 
modeled by CALPUFF are not directly comparable to the visibility 
benefits that would be anticipated on the 20% worst days from those 
specific controls. However, our analysis of the CENRAP 2018 CAMx 
photochemical modeling showed that: On the 20% worst days, Arkansas 
point sources contribute significantly to visibility impairment at 
Arkansas' Class I areas (greater than 4% of total visibility impairment 
at each Arkansas Class I area); review of the emission inventory 
revealed that a very small number of point sources are responsible for 
the majority of the point source emissions of NOX and 
SO2 and therefore a very small number of point sources are 
responsible for the portion of visibility impairment due to Arkansas 
point sources on the 20% worst days; and the Independence facility is 
one of the very largest emission sources and it is located relatively 
close (under 200 km) to three Class I areas. Therefore, we identified 
Independence as having the greatest potential to impact visibility on 
the 20% worst days based on emissions and location and should be 
evaluated for reasonable progress controls. We determined that CALPUFF 
modeling was appropriate and sufficient to provide information on the 
degree of visibility benefits of controls on Independence to inform the 
reasonable progress assessment. Through our evaluation of the four 
statutory factors, we identified cost-effective controls. We then 
considered visibility benefits of the cost-effective controls. We 
conducted CALPUFF modeling to determine the level of visibility impacts 
and benefits anticipated by SO2 and NOX controls 
at nearby impacted Class I areas, evaluating the 98th percentile 
visibility impacts.\267\
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    \266\ For example see summary of the reasonable progress 
analyses for specific sources in Arizona (79 FR 9321, 9353), North 
Dakota (76 FR 58570, 58631 (September 21, 2011)), Montana (77 FR 
23988, 24065 (April 20, 2012)), and Wyoming (78 FR 34738, 34785 
(June 10, 2013)).
    \267\ See Summary of Additional Modeling for Entergy 
Independence and Appendix C to the TSD.
---------------------------------------------------------------------------

    As we discuss elsewhere in this final rule, Entergy submitted CAMx 
model results as part of their comments. The modeled contribution to 
visibility impairment due to baseline emissions from the Independence 
facility alone were approximately 1.3% of the total visibility 
impairment at each Arkansas Class I area. In terms of deciviews, the 
average impact over the 20% worst days based on Entergy's CAMx modeling 
(adjusting to natural background conditions) is over 0.5 dv at the 
Arkansas Class I areas and even larger at the Class I areas in 
Missouri. These results estimate the visibility impacts from the source 
on the 20% worst days and confirm and provide additional support to our 
determination that Independence significantly impacts visibility, both 
in terms of maximum visibility impairment and visibility impairment on 
the 20% worst days, and that emissions controls provide for meaningful 
visibility benefits towards the goal of natural visibility conditions. 
In conclusion, both approaches, CALPUFF and CAMx, support the 
determination that the required controls are reasonable.
    The commenter cites the BART guidelines and asserts that EPA 
recognizes that the CALPUFF model is overly simplistic and overstates 
the effect of single-source emissions. This is not an accurate 
characterization. EPA recognized the uncertainty in the CALPUFF 
modeling results when EPA made the decision, in the final BART 
Guidelines, to recommend that the model be used to estimate the 98th 
percentile visibility impairment rather than the highest daily impact 
value. We made the decision to consider the less conservative 98th 
percentile primarily because the chemistry modules in the CALPUFF model 
are simplified and likely to provide conservative (higher) results for 
peak impacts. Since CALPUFF's simplified chemistry could lead to model 
over predictions and thus be conservative, EPA decided to use the less 
conservative 98th percentile.\268\ While recognizing the limitations of 
the CALPUFF model in the preamble, EPA concluded that, for the specific 
purposes of the Regional Haze Rule's BART provisions, CALPUFF is 
sufficiently reliable to inform the decision making process.\269\ More 
recent evaluations demonstrate that the CALPUFF model can both under-
predict and over-predict visibility impacts. For example, the 2012 
ENVIRON report on

[[Page 66395]]

Comparison of Single-Source Air Quality Assessment Techniques for 
Ozone, PM2.5, other criteria pollutants and AQRVs found that CALPUFF 
predicted highest 24-hr nitrate and sulfate concentrations lower than 
those predicted by the CAMx photochemical grid model in some areas 
within the modeling domain.\270\ In a presentation for the 2010 annual 
Community Modeling and Analysis System conference, Anderson et al. 
(2010) \271\ found that the CALPUFF model frequently predicted lower 
nitrate concentrations compared to the CAMx photochemical grid model 
which has a much more rigorous treatment of photochemical reactions. As 
we stated in promulgating the BART Guidelines, we are confident that 
CALPUFF distinguishes, comparatively, the relative contributions from 
sources such that the differences in source configurations, sizes, 
emission rates, and visibility impacts are well-reflected in the model 
results.\272\
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    \268\ ``Most important, the simplified chemistry in the model 
tends to magnify the actual visibility effects of that source. 
Because of these features and the uncertainties associated with the 
model, we believe it is appropriate to use the 98th percentile--a 
more robust approach that does not give undue weight to the extreme 
tail of the distribution.''
    \269\ 70 FR at 39123.
    \270\ Comparison of Single[hyphen]Source Air Quality Assessment 
Techniques for Ozone, PM2.5, other Criteria Pollutants 
and AQRVs, ENVIRON, September 2012.
    \271\ Anderson, B., K. Baker, R. Morris, C. Emery, A. Hawkins, 
E. Snyder ``Proof-of-Concept Evaluation of Use of Photochemical Grid 
Model Source Apportionment Techniques for Prevention of Significant 
Deterioration of Air Quality Analysis Requirements'' Presentation 
for Community Modeling and Analysis System (CMAS) 2010 Annual 
Conference, (October 11-15, 2010) can be found at http://www.cmascenter.org/conference/2010/agenda.cfm.
    \272\ 70 FR 39104, 39122.
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    With regard to comments concerning the draft EPA modeling Guidance 
for Demonstrating Attainment of Air Quality Goals for Ozone, PM2.5, and 
Regional Haze (Dec. 2014), the commenter confuses the single-source 
analysis to evaluate visibility impacts and benefits of controls on an 
individual source with the analysis of overall visibility conditions at 
a Class I area due to the complete emission control strategy for all 
sources developed under the reasonable progress and long-term strategy 
requirements. The draft modeling guidance (as does the current guidance 
\273\) discusses the projection of overall visibility conditions and 
the need for photochemical grid modeling to account for all emission 
sources to model current visibility conditions and project future 
visibility conditions in response to the overall emission control 
scenarios. The section of the modeling guidance on regional haze \274\ 
describes the recommended modeling analysis to assess overall future 
visibility improvement relative to the uniform rate of progress or 
``glidepath'' (for each Class I area) as part of a reasonable progress 
analysis, and does not discuss source-specific analyses that may be 
completed to inform a reasonable progress assessment.\275\ Because the 
CALPUFF model only evaluates visibility impacts from a single-source or 
a limited group of sources, it is not capable of projecting overall 
visibility conditions due to all sources and controls. Consistent with 
this draft guidance and the current guidance, CENRAP and Arkansas 
utilized CAMx and CMAQ modeling to project future visibility conditions 
for 2018 for establishment of the RPGs and comparison with the URP. 
Similarly, we utilized the CENRAP CAMx model results and adjusted them 
based on source apportionment and emissions data, to estimate the new 
RPGs for the Arkansas Class I areas considering the anticipated changes 
in emissions due to all required controls. We discuss the selection of 
models for assessing individual visibility impacts and benefits of 
controls above.
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    \273\ 2007 EPA modeling Guidance for Demonstrating Attainment of 
Air Quality Goals for Ozone, PM2.5, and Regional Haze.
    \274\ Draft EPA modeling Guidance for Demonstrating Attainment 
of Air Quality Goals for Ozone, PM2.5, and Regional Haze 
(December 2014) Section 4.8 ``What Is The Recommended Modeling 
Analysis for Regional Haze?''
    \275\ Draft EPA modeling Guidance for Demonstrating Attainment 
of Air Quality Goals for Ozone, PM2.5, and Regional Haze (December 
2014) at 173: ``The modeling can be used to determine the predicted 
improvement in visibility and whether the visibility levels are on, 
above, or below the glidepath. It cannot by itself determine the 
reasonable progress goals or determine whether the reasonable 
progress goal is met, and it does not satisfy the requirements for 
the statutory four factor analysis. See the Regional Haze Rule and 
related guidance documents for more information on the four factor 
analysis, including control strategy analysis for single sources.''
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    The commenters cite to the proposed revisions to the Guideline on 
Air Quality Models (Appendix W) \276\ and the IWAQM Phase 3 modeling 
report \277\ and assert that they support the conclusion that the use 
of CALPUFF for Independence was inappropriate. We disagree with the 
commenter. As we discuss above, we agree with the commenter that the 
CAMx model, may be better suited for a reasonable progress analysis in 
certain situations. Proposed revisions to Appendix W discuss removing 
the requirement to use CALPUFF for long-range transport assessments and 
as a preferred model due to the need to provide flexibility in 
estimating single-source secondary pollutant impacts and concerns about 
management and maintenance of the CALPUFF modeling code.\278\ These 
proposed changes do not affect EPA's recommendation that States use 
CALPUFF to determine the applicability and level of BART in regional 
haze implementation plans. The proposed changes also do not preclude 
the use of CALPUFF for any other non-BART analysis, such as long-range 
transport PSD increment assessment, but recognize that modern chemical 
transport models have evolved sufficiently and provide a credible 
platform for estimating potential visibility impacts from a single or 
small group of emission sources.\279\ The proposed Appendix W rule 
simply proposes to remove CALPUFF as a preferred model. If the proposed 
changes are finalized, CALPUFF or any other model can still be used for 
non-BART analyses with the appropriate justification as an 
``alternative model''.
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    \276\ 80 FR 45340 (July 29, 2015).
    \277\ Interagency Workgroup on Air Quality Modeling Phase 3 
Summary Report: Long Range Transport and Air Quality Related Values.
    \278\ 80 CFR 45340, 45349: ``In order to provide the user 
community flexibility in estimating single-source secondary 
pollutant impacts and given the availability of more appropriate 
modeling techniques, such as photochemical transport models (which 
address limitations of models like CALPUFF [37]), the EPA is 
proposing that the Guideline no longer contain language that 
requires the use of CALPUFF or another Lagrangian puff model for 
long-range transport assessments. Additionally, the EPA is proposing 
to remove the CALPUFF modeling system as an EPA-preferred model for 
long-range transport due to concerns about the management and 
maintenance of the model code given the frequent change in ownership 
of the model code since promulgation in the previous version of the 
Guideline. [38] The EPA recognizes that long-range transport 
assessments may be necessary in certain limited situations for PSD 
increment. For these situations, the EPA is proposing a screening 
approach where CALPUFF along with other appropriate screening tools 
and methods may be used to support long-range transport PSD 
increment assessments''
    \279\ 80 FR at 45349.
---------------------------------------------------------------------------

    The IWAQM Phase 3 modeling report \280\ discusses in detail the 
difference between the CALPUFF analysis typically followed under BART 
and the use of photochemical grid models for assessing reasonable 
progress and overall visibility conditions. The report does not 
identify a preferred model for single-source analysis but rather 
identifies the difference between the modeling approaches and cautions 
that the model results are not directly comparable.\281\ The report 
also states

[[Page 66396]]

that puff-models, such as CALPUFF, are not suited for reasonable 
progress demonstrations assessing overall visibility conditions and 
improvement because they are only able to model a single or small group 
of sources. Accordingly, we utilized CAMx model results to project 
overall future visibility conditions and establish the new RPGs in our 
reasonable progress demonstration. We used CALPUFF visibility modeling 
along with our evaluation of the costs of controls to inform our 
decision on the reasonableness of controls at the Independence 
facility. We also used CALPUFF visibility modeling as only one factor 
to inform our decisions on BART for subject-to-BART facilities. We also 
note that both the proposed revisions and the IWAQM report were 
published after the proposed rule for Arkansas regional haze was 
published and well before the technical analysis and modeling were 
completed.
---------------------------------------------------------------------------

    \280\ Interagency Workgroup on Air Quality Modeling Phase 3 
Summary Report: Long Range Transport and Air Quality Related Values 
(July 2015).
    \281\ IWAQM Phase 3 Report (July 2015) at 9: ``In sum, the 
differences in the types of models, the inputs to the models, and 
how the models and model results are used means that the results 
from a BART determination or similar modeling using CALPUFF cannot 
be directly compared to estimated impacts of emissions controls from 
a single source on a reasonable progress goal. If recommended 
procedures change for either BART determination impact assessments 
or reasonable progress goal impact assessments the comparability 
between approaches would also change. Photochemical grid models 
could be applied to estimate single source impacts and post-
processed in a manner consistent with requirements for a BART-like 
assessment but Lagrangian puff models are not ideal for reasonable 
progress demonstrations since they typically characterize one or a 
small group of sources''
---------------------------------------------------------------------------

    We address comments concerning the contribution to visibility 
impairment from Arkansas point sources and the benefit of controls on 
Independence on Arkansas Class I areas elsewhere. We find that the 
contribution to visibility impairment from Arkansas point sources to be 
significant and that controls on Independence will result in meaningful 
visibility improvements towards the goal of natural visibility 
conditions and addresses a significant portion of the visibility 
impairment due to Arkansas sources.
    Comment: Use of CALPUFF modeling does not support EPA's 
determination to require controls at the three coal-fired power plants. 
EPA's reliance on CALPUFF modeling results to make regulatory decisions 
in this case is not justified due to CALPUFF's well-known 
overestimation of visibility impacts.\282\ Under the circumstances 
here, it is highly likely that CALPUFF overestimated the visibility 
impacts of White Bluff, Flint Creek and Independence by at least five 
(5) times. One component of this overestimation is the failure to 
incorporate the puff splitting option within the CALPUFF model into the 
development of visibility results. CALPUFF's overestimation of 
visibility impacts by a factor of 2-10 times under similar 
circumstances has been previously identified \283\ and is described 
with specific reference to EPA's Proposed FIP for Arkansas in a report 
by Dr. Richard T. McNider.\284\ Dr. McNider's report explains that the 
CALPUFF protocols used in the Proposed FIP fail to account for several 
well-known meteorological phenomena and processes, and causes it to 
overestimate visibility impacts. The Hoffnagle report demonstrates that 
CALPUFF modeling has not been validated by real world observations and 
that the current regulatory version of CALPUFF used by EPA is 
outdated.\285\ Consequently, CALPUFF is not ``sufficiently accurate to 
make determinations of deciview differences of 1 deciview.'' \286\
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    \282\ Coincidentally, the EPA Administrator on July 14, 2015, 
signed a proposed notice to remove CALPUFF as a model for long-range 
transport in EPA's Guideline on Air Quality Models in Docket No. 
EPA-HQ-OAR-2015-0310.
    \283\ See Exhibit 19 to Nucor's comments, Hoffnagle, G., 
``Accuracy of Visibility Protocol Modeling in BART Evaluations'' 
(June 15, 2012); EPA Docket EPA-R08-OAR-2011-0851.
    \284\ See, McNider, R. ``Inadequacy of CALPUFF and CALMET 
Protocols for Visibility Impact Analysis in the Arkansas RHR FIP,'' 
July 13, 2015, attached hereto as Exhibit 20 to Nucor's comments.
    \285\ Hoffnagle, Exhibit 19 at p. 4.
    \286\ Hoffnagle, Exhibit 19 at p. 23.
---------------------------------------------------------------------------

    It is inappropriate to utilize CALPUFF as a screening tool to 
qualify a source as subject to BART and subsequently use it to 
determine a facility's required implementation of a control technology 
at a significant financial cost. EPA in its final regional haze rules 
stated that ``because of the scale of the predicted impacts from these 
sources, CALPUFF is an appropriate or a reasonable application to 
determine whether such a facility can reasonably be anticipated to 
cause or contribute to any impairment of visibility. In other words, to 
find that a source with a predicted maximum impact greater than 2 to 3 
deciviews meets the contribution threshold adopted by the States does 
not require the degree of certainty in the results of the model that 
might be required for other regulatory purposes.'' \287\
---------------------------------------------------------------------------

    \287\ 70 FR 39104, 39123.
---------------------------------------------------------------------------

    EPA's visibility analysis in the Proposed FIP systematically 
overstates both the baseline visibility impacts of White Bluff, Flint 
Creek and Independence, and the visibility benefits that would result 
from installation of EPA's required controls.\288\ EPA's Proposed FIP 
presumes greater accuracy and precision than is reasonable or that may 
be expected from CALPUFF under the circumstances here. EPA has failed 
to update its model or to address any of these deficiencies considering 
currently available state-of-the-art modeling science. EPA's 
consideration of visibility impacts is fundamentally flawed and should 
be withdrawn and corrected.
---------------------------------------------------------------------------

    \288\ As well as the other sources that were modeled using 
CALPUFF.
---------------------------------------------------------------------------

    EPA's admission that CALPUFF is a reasonable tool to evaluate a 
facility's visibility impacts only if those impacts exceed 2 to 3 
deciviews, combined with the inability of the model to make accurate 
determinations below the 1 deciview threshold of perceptibility, 
discredits the results of the visibility analyses in the Proposed FIP. 
For these reasons, EPA has not adequately explained how the baseline 
and subsequent controlled visibility analyses in the Proposed FIP 
justify the selected control technologies.
    Response: In promulgating the 2005 BART guidelines, we responded to 
comments concerning the limitations and appropriateness of using 
CALPUFF. There we respond:

    CALPUFF is the best modeling application available for 
predicting a single source's contribution to visibility impairment. 
It is the only EPA-approved model for use in estimating single 
source pollutant concentrations resulting from the long range 
transport of primary pollutants. In addition, it can also be used 
for some purposes, such as the visibility assessments addressed in 
today's rule, to account for the chemical transformation of 
SO2 and NOX. As explained above, simulating 
the effect of precursor pollutant emissions on PM2.5 
concentrations requires air quality modeling that not only addresses 
transport and diffusion, but also chemical transformations. CALPUFF 
incorporates algorithms for predicting both. At a minimum, CALPUFF 
can be used to estimate the relative impacts of BART-eligible 
sources. We are confident that CALPUFF distinguishes, comparatively, 
the relative contributions from sources such that the differences in 
source configurations, sizes, emission rates, and visibility impacts 
are well-reflected in the model results.

    The use of CALPUFF in the context of the Regional Haze rule 
provides results that can be used in a relative manner and are only one 
factor in the overall BART determination. We determined the visibility 
results from CALPUFF could be used as one of the five factors in a BART 
evaluation and the impacts should be utilized somewhat in a relative 
sense because CALPUFF was not explicitly approved for full chemistry 
calculations.\289\
---------------------------------------------------------------------------

    \289\ 70 FR at 39123, 39124. ``We understand the concerns of 
commenters that the chemistry modules of the CALPUFF model are less 
advanced than some of the more recent atmospheric chemistry 
simulations. To date, no other modeling applications with updated 
chemistry have been approved by EPA to estimate single source 
pollutant concentrations from long range transport.'' and in 
discussion of using other models with more advanced chemistry it 
continues, ``A discussion of the use of alternative models is given 
in the Guideline on Air Quality in appendix W, section 3.2.''

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[[Page 66397]]

    EPA's modeling in this action was consistent with the BART 
Guidelines and Appendix W. In recommending the use of CALPUFF for 
assessing source specific visibility impacts, EPA recognized that the 
model had certain limitations but concluded that ``[f]or purposes of 
the regional haze rule's BART provisions . . . CALPUFF is sufficiently 
reliable to inform the decision-making process.'' \290\ To the extent 
that the comment takes issue with the provisions in the BART Guidelines 
for use of CALPUFF, the legal deadline for challenging the use of 
CALPUFF has passed.
---------------------------------------------------------------------------

    \290\ 70 FR at 39123.
---------------------------------------------------------------------------

    The commenters also refer to the 2005 Rule where we discuss the use 
of CALPUFF as a screening tool to qualify a source as subject to BART 
\291\ and claim that we state that CALPUFF is only a reasonable tool 
when impacts exceed 2 to 3 deciviews. This is incorrect. The commenters 
fail to note that later in that same section we also discuss the 
recommended use of CALPUFF to evaluate visibility benefits of controls. 
There we state:
---------------------------------------------------------------------------

    \291\ 70 FR at 39123.

``. . . we also recommend that the States use CALPUFF as a screening 
application in estimating the degree of visibility improvement that 
may reasonably be expected from controlling a single source in order 
to inform the BART determination. As we noted in 2004, this estimate 
of visibility improvement does not by itself dictate the level of 
control a State would impose on a source; ``the degree of 
improvement in visibility which may reasonably be anticipated to 
result from the use of [BART]'' is only one of five criteria that 
the State must consider together in making a BART determination.'' 
\292\
---------------------------------------------------------------------------

    \292\ 70 FR at 39123.

    With respect to our analysis of controls under reasonable progress, 
we rely on our Reasonable Progress Guidance.\293\ Our Reasonable 
Progress Guidance notes the similarity between some of the reasonable 
progress 4 statutory factors and the BART 5 statutory factors contained 
in the Act and repeated in the Guidance, and suggests that the BART 
Guidelines be consulted regarding cost, energy and nonair quality 
environmental impacts, and remaining useful life. We are therefore 
relying on our BART Guidelines for assistance in interpreting those 
reasonable progress factors, as applicable.
---------------------------------------------------------------------------

    \293\ ``Guidance for Setting Reasonable Progress Goals Under the 
Regional Haze Program,'' June 1, 2007.
---------------------------------------------------------------------------

    Also, similar to a BART analysis, we are considering the projected 
visibility benefit in our reasonable progress analysis following the 
BART guidelines and the use of CALPUFF.\294\ We rely on the BART 
Guidelines here and in other actions evaluating reasonable progress 
controls because they provide a reasonable and consistent approach 
regarding visibility modeling.
---------------------------------------------------------------------------

    \294\ As we explain in our proposed action (80 FR at 18993): 
``While visibility is not an explicitly listed factor to consider 
when determining whether additional controls are reasonable under 
the reasonable progress requirements, the purpose of the four-factor 
analysis is to determine what degree of progress toward natural 
visibility conditions is reasonable. Therefore, it is appropriate to 
consider the projected visibility benefit of the controls when 
determining if the controls are needed to make reasonable 
progress''. See 79 FR at 74838, 74840, and 74874.
---------------------------------------------------------------------------

    We also disagree with the commenters conclusions concerning CALPUFF 
model performance and assertions that model predictions are 
overestimated by a factor of 5. We note that our regulations do not 
allow for the calibration of model results to try to adjust for 
potential biases as suggested by the commenter.\295\
---------------------------------------------------------------------------

    \295\ App. W, Section 7.2.9(a) ``. . . Therefore, model 
calibration is unacceptable.''
---------------------------------------------------------------------------

    As discussed more fully in the RTC document, the CALPUFF model can 
both under-predict and over-predict visibility impacts. While 
recognizing the limitations of the CALPUFF model in the Preamble of the 
Regional Haze Rule EPA concluded that, for the specific purposes of the 
Regional Haze Rule's BART provisions, CALPUFF is sufficiently reliable 
to inform the decision making process.\296\
---------------------------------------------------------------------------

    \296\ 70 FR at 39123.
---------------------------------------------------------------------------

    We disagree with the commenter's assertion that we were incorrect 
in not utilizing the puff-splitting option \297\ and that this resulted 
in an overestimation of model results. Tests conducted by the EPA and 
the FLM's have shown that the CALPUFF puff-splitting algorithm does not 
behave in the manner posited in Dr. McNider's document.\298\ As 
discussed in detail in the RTC document, multiple evaluations of puff-
splitting show that visibility impacts (and thus concentrations) both 
increased and decreased across various Class I areas impacted by the 
source. These results are contrary to the claims of the commenter that 
CALPUFF overpredicts downwind concentrations at distances beyond 100 km 
and that the use of puff-splitting would result in lower 
concentrations. Furthermore, commenters have not provided any 
additional CALPUFF modeling to support their claims concerning model 
performance using the non-default puff splitting option.
---------------------------------------------------------------------------

    \297\ CALPUFF contains an optional puff splitting algorithm that 
can further account for vertical wind shear effects across 
individual puffs when this is of specific concern. Dispersion and 
transport can act on separate puffs generated from the original 
puff. This option is not part of the regulatory default set-up.
    \298\ See CALPUFF_SJGS_SPLIT_summary.xls.
---------------------------------------------------------------------------

    The commenter refers to the Hoffnagle report (Ex. 19 of Nucor 
comments) to support claims that the CALPUFF model overpredicts 
concentrations, that the model is unreliable beyond 200km, and that the 
modeling is not sufficiently accurate to make determinations of 
deciview differences of 1 dv. We disagree with the conclusions of the 
Hoffnagle report and note significant flaws in that analysis. We also 
note that all the large EGU sources modeled in this action are less 
than 200 km for at least one Class I area. We specifically address 
Hoffnagle's analysis of modeled to measured results in response to 
comments elsewhere where we address comments concerning the ``margin of 
error'' of the model and case study comparisons of CALPUFF modeled 
values to measured values.
    We disagree with the commenter that the model we utilized is 
outdated. We used the regulatory version of the CALPUFF model.\299\ We 
disagree that the newer versions of CALPUFF should be used in this 
action to determine potential visibility impacts. The newer version(s) 
of CALPUFF have not received the level of review required for use in 
regulatory actions subject to EPA approval and consideration in a BART 
decision making process. Based on our review of the available evidence 
we do not consider these newer versions of CALPUFF to have been shown 
to be sufficiently documented, technically valid, and reliable for use 
in a BART decision making process.
---------------------------------------------------------------------------

    \299\ On December 4, 2013, EPA approved an update to v5.8.4 that 
contains bug fixes to the previous version. See December 3, 2013 
CALPUFF Update Memo for a discussion of model changes.
---------------------------------------------------------------------------

    The commenters also refer to the proposed revisions to the 
Guideline on Air Quality Models (Appendix W). Proposed revisions to 
Appendix W discuss removing the requirement to use CALPUFF for long-
range transport assessments and as a preferred model due to the need to 
provide flexibility in estimating single-source secondary pollutant 
impacts and concerns about management and maintenance of the CALPUFF 
modeling code.\300\ These

[[Page 66398]]

proposed changes do not affect EPA's recommendation that States use 
CALPUFF to determine the applicability and level of BART in regional 
haze implementation plans. The proposed changes also do not preclude 
the use of CALPUFF for any other non-BART analysis. The proposed 
changes to the Appendix W rule simply propose to remove CALPUFF as a 
preferred model for long-range transport assessments. If the proposed 
changes are finalized, CALPUFF or any other model can still be used 
with the appropriate justification as an ``alternative model'' for 
long-range transport assessments.
---------------------------------------------------------------------------

    \300\ 80 CFR at 45349: ``In order to provide the user community 
flexibility in estimating single-source secondary pollutant impacts 
and given the availability of more appropriate modeling techniques, 
such as photochemical transport models (which address limitations of 
models like CALPUFF [37]), the EPA is proposing that the Guideline 
no longer contain language that requires the use of CALPUFF or 
another Lagrangian puff model for long-range transport assessments. 
Additionally, the EPA is proposing to remove the CALPUFF modeling 
system as an EPA-preferred model for long-range transport due to 
concerns about the management and maintenance of the model code 
given the frequent change in ownership of the model code since 
promulgation in the previous version of the Guideline. [38] The EPA 
recognizes that long-range transport assessments may be necessary in 
certain limited situations for PSD increment. For these situations, 
the EPA is proposing a screening approach where CALPUFF along with 
other appropriate screening tools and methods may be used to support 
long-range transport PSD increment assessments.''
---------------------------------------------------------------------------

    Finally, the CAMx modeling provided by Entergy Arkansas provides 
additional information that directly contradicts the commenter's 
assertion that CALPUFF greatly overestimates visibility impacts by at 
least a factor of 5. As we discuss elsewhere in this final rule, the 
CAMx visibility modeling estimates a maximum visibility impact (limited 
to only the days comprising the 20% worst days and based on annual 
emissions) of over 1.5 dv from the Independence facility at both Caney 
Creek and Upper Buffalo. For the White Bluff facility, the CAMx maximum 
visibility impact is approximately 3.5 dv at Caney Creek and 0.8 dv at 
Upper Buffalo. In some situations, the CALPUFF modeled maximum or 98th 
percentile impacts of the facility may not coincide with the days that 
make up the worst 20% monitored days at the Class I area, therefore the 
true maximum impact considering all days based on CAMx modeling could 
be even higher. This compares to a CALPUFF modeled visibility 98th 
percentile impact (based on maximum emissions) due to the Independence 
facility of 2.5 dv at Caney Creek and 2.3 at Upper Buffalo. For White 
Bluff, the CALPUFF modeled impact (98th percentile) is approximately 
3.3 dv at Caney Creek and 2.3 dv at Upper Buffalo.
    We address more general comments concerning the use of CALPUFF 
modeling and model uncertainty in separate response to comments.
4. Margin of Error in CALPUFF Modeling
    Comment: Commenters stated that BART requires that states (or EPA 
in the case of a federal implementation plan) consider ``the degree of 
improvement in visibility which may reasonably be anticipated to result 
from the use of such technology.'' \301\ The Ninth Circuit, in National 
Parks Conservation Association v. EPA, Case No. 12-73710, 2015 WL 
3559149 at 8 (9th Cir. June 9, 2015), held that the estimated 
visibility improvement was less than CALPUFF's margin of error, and 
thus, EPA had no basis to believe that BART controls in that case could 
``reasonably be anticipated'' to improve visibility. The Clean Air Act 
does not require visibility improvements that cannot be reasonable 
anticipated. Visibility improvements that are less than the margin of 
error are not ``reasonably anticipated'' and found to be invalid by the 
Ninth Circuit in National Parks Conservation Association.\302\ In the 
proposal, EPA dictates the imposition of control equipment for 
emissions reduction under BART in instances where CALPUFF predicted 
minor visibility improvements. EPA did so without first undertaking any 
site specific analytical analysis to determine if the visibility 
improvements were in fact within the CALPUFF margin of error.
---------------------------------------------------------------------------

    \301\ CAA section 169A(g)(2).
    \302\ 80 FR at 18968.
---------------------------------------------------------------------------

    The CAA does not require visibility improvements that cannot be 
reasonably anticipated. Conversely, visibility improvements that are 
less than the margin of error were expressly found to be invalid. Until 
such time as EPA can provide assurance that the CALPUFF model is a 
reliable indicator of visibility projections, many of the numerical 
projections contained in the Proposed FIP are themselves, unreliable. 
For this reason, the Proposed FIP is flawed and is overly expansive and 
should be withdrawn.
    Response: We disagree with the commenter's characterization of the 
Ninth Circuit decision regarding the ``margin of error'' of the CALPUFF 
model. The Ninth Circuit decision cited did not rule on any specific 
issue related to CALPUFF or the ``margin of error.'' Rather, the court 
ruled on a procedural error that EPA did not respond to the comment 
received regarding the CALPUFF margin of error in its rulemaking as 
required under the law.\303\
---------------------------------------------------------------------------

    \303\ ``Concurring, Judge Berzon wrote separately to emphasize 
her understanding that the lead opinion is not impugning the EPA's 
use of the CALPUFF model generally, but only requiring a 
sufficiently reasoned response to a particular comment regarding 
CALPUFF's usefulness in these specific circumstances.'' Nat'l Parks 
Conservation Ass'n vs. EPA.
---------------------------------------------------------------------------

    In response to the court's finding in American Corn Growers Ass'n. 
v. EPA \304\ that we failed to provide an option for BART evaluations 
on an individual source-by-source basis, we had to identify the 
appropriate analytical tools to estimate single-source visibility 
impacts. The 2005 BART Guidelines recommended the use of CALPUFF for 
assessing visibility (secondary chemical impacts) but noted that 
CALPUFF's chemistry was fairly simple and the model has not been fully 
tested for secondary formation and thus is not fully approved for 
secondary-formed particulate. In the preamble of the final 2005 BART 
guidelines we identify CALPUFF as the best available tool for analyzing 
the visibility effects of individual sources, but we also recognized 
that it is a model that includes certain assumptions and 
uncertainties.\305\ Evaluation of CALPUFF model performance for 
dispersion (no chemistry) to case studies using inert tracers has been 
performed.\306\ It was concluded from these case studies the CALPUFF 
dispersion model had performed in a reasonable manner, and had no 
apparent bias toward over or under prediction, so long as the transport 
distance was limited to less than 300km.307 308
---------------------------------------------------------------------------

    \304\ Am. Corn Growers Ass'n v. EPA, 291 F.3d 1 (D.C. Cir. 
2002).
    \305\ 70 FR at 39121.
    \306\ See ``more recent series of comparisons has been completed 
for a new model, CALPUFF (Section A.3). Several of these field 
studies involved three-to-four hour releases of tracer gas sampled 
along arcs of receptors at distances greater than 50km downwind. In 
some cases, short-term concentration sampling was available, such 
that the transport of the tracer puff as it passed the arc could be 
monitored. Differences on the order of 10 to 20 degrees were found 
between the location of the simulated and observed center of mass of 
the tracer puff. Most of the simulated centerline concentration 
maxima along each arc were within a factor of two of those 
observed.'' 68 FR 18440, 18458 (April 15, 2003), 2003 Revisions to 
Appendix W, Guideline on Air Quality Models
    \307\ Interagency Workgroup on Air Quality Modeling (IWAQM) 
Phase 2 Summary Report and Recommendations for Modeling Long-Range 
Transport Impacts. Publication No. EPA-454/R-98-019. Office of Air 
Quality Planning & Standards, Research Triangle Park, NC. 1998.
    \308\ 68 FR 18440, 18458, 2003 Revisions to Appendix W, 
Guideline on Air Quality Models.
---------------------------------------------------------------------------

    In promulgating the 2005 BART guidelines, we responded to comments 
concerning the limitations and

[[Page 66399]]

---------------------------------------------------------------------------
appropriateness of using CALPUFF. There we respond:

    CALPUFF is the best modeling application available for 
predicting a single source's contribution to visibility impairment. 
It is the only EPA-approved model for use in estimating single 
source pollutant concentrations resulting from the long range 
transport of primary pollutants. In addition, it can also be used 
for some purposes, such as the visibility assessments addressed in 
today's rule, to account for the chemical transformation of 
SO2 and NOX. As explained above, simulating 
the effect of precursor pollutant emissions on PM2.5 
concentrations requires air quality modeling that not only addresses 
transport and diffusion, but also chemical transformations. CALPUFF 
incorporates algorithms for predicting both. At a minimum, CALPUFF 
can be used to estimate the relative impacts of BART-eligible 
sources. We are confident that CALPUFF distinguishes, comparatively, 
the relative contributions from sources such that the differences in 
source configurations, sizes, emission rates, and visibility impacts 
are well-reflected in the model results.

    In the 2003 revisions to the Guideline on Air Quality Models, 
CALPUFF was added as an approved model for long-range transport of 
primary pollutants. At that time, we considered approving CALPUFF for 
assessing the impact from secondary pollutants but determined that it 
was not appropriate in the context of a PSD review because the impact 
results could be used as the sole determinant in denying a permit.\309\ 
However, the use of CALPUFF in the context of the Regional Haze rule 
provides results that can be used in a relative manner and are only one 
factor in the overall BART determination. We determined the visibility 
results from CALPUFF could be used as one of the five factors in a BART 
evaluation and the impacts should be utilized somewhat in a relative 
sense because CALPUFF was not explicitly approved for full chemistry 
calculations.\310\
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    \309\ 68 FR 18440.
    \310\ 70 FR at 39123, 39124. ``We understand the concerns of 
commenters that the chemistry modules of the CALPUFF model are less 
advanced than some of the more recent atmospheric chemistry 
simulations. To date, no other modeling applications with updated 
chemistry have been approved by EPA to estimate single source 
pollutant concentrations from long range transport,'' and in 
discussion of using other models with more advanced chemistry it 
continues, ``A discussion of the use of alternative models is given 
in the Guideline on Air Quality in appendix W, section 3.2.''
---------------------------------------------------------------------------

    We also recognized the uncertainty in the CALPUFF modeling results 
when we made the decision, in the final BART Guidelines, to recommend 
that the model be used to estimate the 98th percentile visibility 
impairment rather than the highest daily impact value. We made the 
decision to consider the less conservative 98th percentile primarily 
because the chemistry modules in the CALPUFF model are simplified and 
likely to provide conservative (higher) results for peak impacts. Since 
CALPUFF's simplified chemistry could lead to model over predictions and 
thus be conservative, EPA decided to use the less conservative 98th 
percentile.\311\ Examining the distribution of CALPUFF modeled 
visibility impacts, it can be seen that the few values at the extreme 
of the distribution are much higher than the rest of the values.\312\ 
Therefore, in recognizing some of the limitations of the CALPUFF model, 
we determined that use of the maximum modeled impact may be overly 
conservative and recommended the use of the 98th percentile value.
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    \311\ ``Most important, the simplified chemistry in the model 
tends to magnify the actual visibility effects of that source. 
Because of these features and the uncertainties associated with the 
model, we believe it is appropriate to use the 98th percentile--a 
more robust approach that does not give undue weight to the extreme 
tail of the distribution.'' 70 FR 39104, 39121.
    \312\ See figures for Lake Catherine and Domtar in our response 
to comments on the ``Margin of Error'' analysis in the RTC document
---------------------------------------------------------------------------

    We disagree with the commenter's general statement that there is an 
acknowledged over-prediction of the CALPUFF model or an acknowledged 
inaccuracy at low levels, and that the actual visibility impacts from 
the BART sources are lower. The CALPUFF model can both under-predict 
and over-predict visibility impacts when compared to photochemical grid 
model. For example, the 2012 ENVIRON report on Comparison of Single-
Source Air Quality Assessment Techniques for Ozone, PM2.5, other 
criteria pollutants and AQRVs found that CALPUFF predicted highest 24-
hr nitrate and sulfate concentrations lower than those predicted by the 
CAMx photochemical grid model in some areas within the modeling 
domain.\313\ In a presentation for the 2010 annual Community Modeling 
and Analysis System conference, Anderson et al. (2010) \314\ found that 
the CALPUFF model frequently predicted lower nitrate concentrations 
compared to the CAMx photochemical grid model, which has a much more 
rigorous treatment of photochemical reactions. As discussed above, 
model evaluations examining how the model captures the transport and 
diffusion of pollutants showed that the model performed in a reasonable 
manner for modelled distances less than 300 km.\315\ The selection of 
the 98th percentile value rather than the maximum value was made to 
address concerns that the maximum may be overly conservative.
---------------------------------------------------------------------------

    \313\ Comparison of Single[hyphen]Source Air Quality Assessment 
Techniques for Ozone, PM2.5, other Criteria Pollutants 
and AQRVs, ENVIRON, September 2012.
    \314\ Anderson, B., K. Baker, R. Morris, C. Emery, A. Hawkins, 
E. Snyder ``Proof-of-Concept Evaluation of Use of Photochemical Grid 
Model Source Apportionment Techniques for Prevention of Significant 
Deterioration of Air Quality Analysis Requirements'' Presentation 
for Community Modeling and Analysis System (CMAS) 2010 Annual 
Conference, (October 11-15, 2010) can be found at http://www.cmascenter.org/conference/2010/agenda.cfm.
    \315\ 68 FR at 18458, 2003 Revisions to Appendix W, Guideline on 
Air Quality Models.
---------------------------------------------------------------------------

    The CALPUFF modeling following the BART guidelines and using the 
98th percentile value does not lend itself to model performance 
evaluations of the type suggested by the commenters (see comments below 
concerning the ``Margin of error'' analysis), comparing measured 
visibility impairment at a specific time and place to modeled 
impairment at that same time and place to derive some ``margin of 
error'' in the modeled estimates. The BART modeling is a worst case 
assessment, utilizing maximum emissions,\316\ assumptions of background 
ammonia and ozone, and simplified chemistry, modeled over a period of 
three years.\317\ The modeling also does not capture the effect of 
competition with other emission sources for the available ammonia. The 
goal of this modeling is to estimate the maximum anticipated impact 
from the source in the vicinity of a Class I area (typically an area on 
the order of several hundred square miles or more), and not to provide 
an estimate of downwind concentrations or visibility conditions for a 
specific place at a specific time.
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    \316\ 70 FR at 39129, ``We believe the maximum 24hour modeled 
impact can be an appropriate measure in determining the degree of 
visibility improvement expected from BART reductions (or for BART 
applicability)''
    \317\ 70 FR 39104, 39107-3918 of BART Rule. For assessing the 
fifth factor, the degree of improvement in visibility from various 
BART control options, the States may run CALPUFF or another 
appropriate dispersion model to predict visibility impacts. 
Scenarios would be run for the pre-controlled and post-controlled 
emission rates for each of the BART control options under review. 
The maximum 24-hour emission rates would be modeled for a period of 
three or five years of meteorological data.
---------------------------------------------------------------------------

    CALPUFF uses a pseudo-first-order chemical reaction mechanism to 
model the conversion of SO2 to SO4 and 
NOX (NO + NO2) to NO3. We find the 
representation of key chemical conversions of precursors to 
PM2.5 in CALPUFF are appropriate for estimating a worst-case 
scenario for this particular source and region. We note that small 
changes in emission levels will not significantly perturb the available 
ammonia. Therefore, the relative difference between two scenarios with 
similar emissions will not be overly

[[Page 66400]]

influenced by assumptions of background concentrations of ammonia.
    The utility of the model used must be judged based on the available 
data, the known limitations or simplifications inherent to the model, 
and the purpose of the modeling or manner in which the model results 
are used in informing decisions. The use of the 98th percentile value 
and considering a minimum of three years of meteorological data within 
CALPUFF provides a snapshot of the worst case visibility impacts, 
simulating impacts (based on maximum emissions and assumed ammonia 
concentrations) on a day when modeled meteorological conditions are 
most conducive to formation and transport of visibility impairing 
pollutants to a receptor within a Class I area. While there is some 
uncertainty in the absolute visibility impacts and benefits due to the 
model and some of the simplifications and assumptions used in the BART 
guideline modeling approach, the relative level of impact is a reliable 
assessment of the degree of visibility impacts and benefit from 
controls. Any uncertainties in meteorological conditions that govern 
the transport and diffusion of pollutants are less important in 
comparing impacts between two control scenarios, since the same effects 
will be included in both the base and the control scenario model 
simulations. CALPUFF modeling will be better at predicting changes in 
visibility impairment due to the application of controls than at 
predicting the absolute visibility impacts. BART determinations are 
only made for sources that have already been shown to reasonably be 
anticipated to cause or contribute to any visibility impairment in a 
Class I area. Modeling of control scenarios is used to estimate the 
amount that this visibility impact can be reduced due to a reduction in 
emissions. The modeling of these control scenarios is done in a manner 
that holds all variables constant except for the emissions of the 
pollutant of interest. A relative reduction in visibility impact due to 
a change in emissions is an indication that visibility benefits are 
reasonably anticipated to occur. The modeled magnitude of the 
visibility improvement is not a determinative factor in the BART 
determination, but only one factor and is considered on a relative 
basis to the baseline impact and the benefits of other controls. The 
relative visibility benefit of all controls is weighed along with the 
absolute and relative costs of controls, energy and nonair 
environmental impacts, any existing controls, and the remaining useful 
life of the source. As stated above, we are confident that CALPUFF 
distinguishes, comparatively, the relative contributions from sources 
such that the differences in source configurations, sizes, emission 
rates, and visibility impacts are well-reflected in the model results.
    CALPUFF visibility modeling, performed using the regulatory CALPUFF 
model version and following all applicable guidance and EPA/FLM 
recommendations, provides a consistent tool for comparison with the 0.5 
dv subject-to-BART threshold. The CALPUFF model, as recommended in the 
BART guidelines, has been used for almost every single-source BART 
analysis in the country and has provided a consistent basis for 
assessing the degree of visibility benefit anticipated from controls as 
one of the factors under consideration in a five-factor BART analysis. 
Since almost all states have completed their BART analyses and have 
either approved SIPs or FIPs in place, there is a large set of 
available data on modeled visibility impacts and benefits, and how 
those model results were utilized to screen out sources and as part of 
the five-factor analysis in making BART control determinations for 
comparison with.
    Comment: Trinity Consultants completed a quantitative analysis to 
evaluate the margin of error in the CALPUFF model for Lake Catherine 
Unit 4 and Domtar Ashdown Mill.\318\ Trinity calculated the average 
difference between modeled values obtained using CALPUFF (including the 
CENRAP background) and IMPROVE monitored values for Caney Creek and 
Upper Buffalo. Trinity compared the regional haze design value format 
of average W20 days visibility for this analysis.
---------------------------------------------------------------------------

    \318\ ``Evaluation of the CALPUFF Modeling System Margin of 
Error Report for BART Analysis, Domtar A. W. LLC, Ashdown Mill'' 
Prepared by Trinity Consultants, August 2015 and ``Evaluation of the 
CALPUFF Modeling System Margin of Error Report for BART Analysis, 
Entergy Arkansas, Inc., Lake Catherine Plant'' Prepared by Trinity 
Consultants, August 2015.
---------------------------------------------------------------------------

    In its analysis, the pre-BART impact from Lake Catherine Unit 4 at 
Caney Creek and Upper Buffalo is inconsequential when compared with the 
IMPROVE measurements, which capture the impact of all other sources, 
including Lake Catherine, on the Class I areas.
    The proposed NOX BART controls for Lake Catherine Unit 4 
will result in visibility improvements that are even more 
inconsequential and cannot accurately be predicted by CALPUFF. Based on 
Trinity's analysis, the minimum calculated margin of error for CALPUFF 
for Lake Catherine Unit 4 is 0.93 dv. The CALPUFF modeling predicted 
visibility improvement associated with EPA's proposed BART controls for 
Lake Catherine Unit 4 at Caney Creek and Upper Buffalo falls within the 
minimum calculated margin of error for CALPUFF for Lake Catherine Unit 
4. Similarly, the predicted visibility improvements associated with the 
imposition of the proposed BART requirements for Power Boiler 2 at the 
Domtar Ashdown Mill fall within the CALPUFF model's margin of error. As 
such, the visibility improvements at each of these Class I areas 
associated with the proposed BART controls cannot ``reasonably be 
anticipated.'' \319\ Accordingly, EPA has not adequately demonstrated 
that it is appropriate to require controls on Lake Catherine Unit 4 or 
Power Boiler 2 at the Domtar Ashdown Mill.
---------------------------------------------------------------------------

    \319\ CAA section 169A(g)(2); see NPCA, 788 F.3d 1134, 1146-47.
---------------------------------------------------------------------------

    These analyses include a discussion of work performed by TRC 
Environmental Corporation, including a June 2012 paper prepared by Gale 
Hoffnagle that discusses several case studies that compared CALPUFF 
modeled values to measured values from the IMPROVE monitoring 
network.\320\ The commenters state that PPL Montana relied on this 
study in its successful challenge to the Montana FIP for its argument 
that EPA failed to explain why it could reasonably anticipate a 
visibility improvement when the improvement was within CALPUFF's margin 
of error.\321\
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    \320\ Gale F. Hoffnagle, Accuracy of Visibility Protocol 
Modeling in BART Evaluations, TRC Environmental Corporation, June 
15, 2012.
    \321\ National Parks Conservation Ass'n v. EPA, 788 F.3d 1134, 
1146-47 (9th Cir. 2015).
---------------------------------------------------------------------------

    Response: The commenters mischaracterize the Ninth Circuit decision 
regarding the ``margin of error'' of the model. The commenter suggests 
that the Court agreed that the anticipated visibility benefits in that 
case were within the margin of error of the model. This is incorrect. 
The Ninth Circuit decision cited did not rule on any specific issue 
related to CALPUFF. Rather, the court ruled on a procedural error that 
EPA did not respond to the comment received regarding the CALPUFF 
margin of error in its rulemaking as required under the law.\322\ Here 
and elsewhere in our response to comments we address a very similar 
comment with respect to

[[Page 66401]]

CALPUFF modeling for Arkansas sources, as well as the commenter's 
analysis claiming to estimate the ``margin of error''.
---------------------------------------------------------------------------

    \322\ ``Concurring, Judge Berzon wrote separately to emphasize 
her understanding that the lead opinion is not impugning the EPA's 
use of the CALPUFF model generally, but only requiring a 
sufficiently reasoned response to a particular comment regarding 
CALPUFF's usefulness in these specific circumstances.'' Nat'l Parks 
Conservation Ass'n vs. EPA.
---------------------------------------------------------------------------

    The Trinity analysis \323\ purports to calculate a ``margin of 
error'' of the CALPUFF modeling for Lake Catherine. In general, the 
commenter's analysis adds CALPUFF model results for a specific source 
or sources with CAMx model results and compares this value to 
visibility conditions derived from monitored data at each Class I area. 
This analysis is flawed for many reasons as discussed in detail in our 
RTC document and fails to provide any assessment of the ability of the 
CALPUFF model to evaluate the degree of visibility improvement that may 
be expected from available control technology to inform BART and 
reasonable progress evaluations. Whether or not the modeled visibility 
impacts or benefits lie below this calculated ``margin of error'' is 
immaterial to any assessment of whether or not the visibility 
impairment or benefits from controls can reasonably be anticipated to 
occur. BART determinations are only made for sources that have already 
been shown to reasonably be anticipated to cause or contribute to any 
visibility impairment in a Class I area. Modeling of control scenarios 
is used to estimate the amount that this visibility impact can be 
reduced due to a reduction in emissions. The modeling of these control 
scenarios is done in a manner that holds all variables constant except 
for the emissions of the pollutant of interest. A relative reduction in 
visibility impact due to a change in emissions is an indication that 
visibility benefits are reasonably anticipated to occur. The modeled 
magnitude of the visibility improvement is not the determinative factor 
in the BART determination, but only one factor and is considered on a 
relative basis to the baseline impact and the benefits of other 
controls. The relative visibility benefit of all controls is weighed 
along with the absolute and relative costs of controls, energy and 
nonair environmental impacts, any existing controls, and the remaining 
useful life of the source. As discussed elsewhere in this section of 
the final rule, we are confident that CALPUFF distinguishes, 
comparatively, the relative contributions from sources such that the 
differences in source configurations, sizes, emission rates, and 
visibility impacts are well-reflected in the model results.
---------------------------------------------------------------------------

    \323\ Evaluation of the CALPUFF Modeling System Margin of Error 
for a BART Analysis, Entergy Services, Inc.--Lake Catherine Plant, 
available as Exhibit H to comments submitted by Entergy Arkansas, 
Inc.
---------------------------------------------------------------------------

    We respond to specific comments concerning each separate case study 
in our RTC document.
5. Reasonable Progress Analysis for Entergy Independence
    Comment: Entergy contracted with Trinity to perform regional haze 
modeling using CAMx and PSAT based on the modeling originally developed 
for CENRAP. This modeling was performed to assess the proposed control 
options for Independence units 1 and 2, as well as White Bluff units 1 
and 2. In addition to the baseline scenario modeling, the FIP scenario 
(proposed controls in EPA's FIP) and Entergy's proposed control 
approach consisting of installed LNB/SOFA on Independence, and the 
cessation of coal combustion at White Bluff were modeled.
    Entergy stated that EPA's own analysis counsels against imposing 
emission limits on Independence. EPA asserts that CENRAP modeling shows 
that sulfate from all point sources included in the regional modeling 
is projected to contribute to 57% of the total light extinction at 
Caney Creek on the W20 days in 2018 and 43% of the total light 
extinction at Upper Buffalo.\324\ However, EPA recognizes that the 
CENRAP modeling also demonstrates that sulfate from all (elevated and 
low level) Arkansas point sources is projected to be responsible for 
only 3.58% of the total light extinction at Caney Creek and 3.20% at 
Upper Buffalo.\325\ The contribution of Arkansas point sources' nitrate 
emissions to visibility impairment at Arkansas' Class I areas is even 
more insignificant. According to EPA's analysis, nitrate from all point 
sources included in the regional modeling is projected to account for 
only 3% of the total light extinction at the Caney Creek and Upper 
Buffalo Class I areas, with nitrate from Arkansas point sources being 
responsible for only 0.29% of the total light extinction at Caney Creek 
and 0.25% at Upper Buffalo.\326\ The Independence units' share of 
emissions to this minimal contribution from Arkansas point sources to 
visibility impairment at Caney Creek and Upper Buffalo is even less.
---------------------------------------------------------------------------

    \324\ 80 FR 18944, 18990.
    \325\ Id.
    \326\ Id.
---------------------------------------------------------------------------

    Entergy's CAMx modeling confirms that Independence's contribution 
to visibility impairment is insignificant in both Class I areas. 
Independence is projected to contribute to only 0.119 dv of visibility 
impairment at Caney Creek and Upper Buffalo on W20 days in 2018.\327\ 
This reflects only one half of one percent of the visibility 
impairment, based on modeling, on the W20 days in either Caney Creek or 
Upper Buffalo. Yet, based on such a miniscule contribution and with no 
credible explanation, EPA arbitrarily concludes that SO2 and 
NOX controls at Independence are warranted.
---------------------------------------------------------------------------

    \327\ See Figures 9 and 10 of Entergy Arkansas Inc. Comments On 
the Proposed Regional Haze and Interstate Visibility Transport 
Federal Implementation Plan for Arkansas available in the docket for 
this action.
---------------------------------------------------------------------------

    Response: We disagree with the commenter's assertion that the 
contribution to visibility impairment from Entergy Independence is 
``insignificant'' or ``minimal.'' For example, as the commenter states, 
the CENRAP source apportionment data show that sulfate from Arkansas 
point sources are projected to be responsible for 3.58% of the total 
light extinction at Caney Creek and 3.20% at Upper Buffalo in 2018. As 
we discuss in our proposal, based on 2011 NEI data, the Entergy 
Independence Plant is the second largest source of both SO2 
and NOX point source emissions in Arkansas, accounting for 
approximately 36% of the SO2 point-source emissions and 21% 
of the point source NOX emissions in the State.\328\ 
Therefore, a significant portion of the total visibility impairment on 
the 20% worst days, on the order of 1% or more, can be expected to be 
attributable to SO2 emissions from a single facility, the 
Independence facility. As we discuss in more detail elsewhere, given 
their contribution to visibility impairment on the 20% worst days, we 
consider both SO2 and NOX to be key pollutants 
contributing to visibility impairment at Arkansas' Class I areas. Our 
CALPUFF modeling evaluating the baseline 98th percentile impacts 
confirmed that the Independence facility was estimated to impact 
visibility at levels much larger than the level considered to ``cause'' 
visibility impairment (greater than 1 dv) at nearby Class I areas, 
ranging from 2.512 dv at Caney Creek, to 1.859 dv at Mingo. CALPUFF 
modeling also showed that anticipated visibility benefits from 
SO2 and NOX controls at the facility exceeded 1 
dv at each of the four impacted Class I areas. Although we recognize 
that Independence is not a subject to BART source, for comparison 
purposes we note that the threshold used for visibility impacts to

[[Page 66402]]

determine whether facilities are subject to BART is 0.5 dv.\329\
---------------------------------------------------------------------------

    \328\ 80 FR at 18991.
    \329\ ``As a general matter, any threshold that you use for 
determining whether a source ``contributes'' to visibility 
impairment should not be higher than 0.5 deciviews.'' BART 
Guidelines, App. Y to 40 CFR 51.
---------------------------------------------------------------------------

    We disagree with the commenter that the CAMx modeling submitted by 
the commenter confirms that contributions to visibility impairment from 
the Independence facility are insignificant. When properly assessed, as 
detailed in the RTC document, the commenter's CAMx modeling supports 
and reinforces our finding that visibility impairment from Entergy 
Independence is significant and emission reductions will result in 
meaningful visibility benefits towards the goal of natural visibility 
conditions. Entergy's CAMx modeling shows a visibility impact of 0.12 
dv at both Caney Creek and Upper Buffalo when compared to 2018 
``dirty'' or ``degraded'' background conditions. The commenter then 
calculates that this 0.12 dv impact is 0.5% of the total 23 dv 
visibility impairment. As discussed in the RTC document, the deciview 
scale is a logarithmic function of extinction, and therefore the 
calculations by the commenter are incorrect because they are based on 
deciview values and must be performed based on light extinction to 
properly calculate the percent contribution to visibility impairment. 
Spreadsheets submitted by the commenter present the light extinction 
attributable to each source (in inverse megameters) based on the 
results of their CAMx source apportionment modeling and calculate the 
percent contribution to total visibility impairment at each Class I 
area.\330\ The commenter is incorrect in its statement that the impact 
from the Independence facility is one half of one percent; it is in 
fact, based on their own modeling and calculation, approximately 1.3% 
of the total visibility impairment at each Arkansas Class I area. 
Considering that the CAMx photochemical modeling takes into account the 
emissions of thousands of sources, both in Arkansas and outside of the 
state, we consider this to be a significant contribution to visibility 
impairment at each Class I area and a large portion (approximately one-
third) of the total contribution from all Arkansas point sources that 
can be addressed through installation of controls on two units at a 
single facility. The CAMx modeling also showed that at Upper Buffalo, 
the Independence facility's contribution to visibility impairment is 
greater than the contribution from all of the subject-to-BART sources 
addressed in this final action combined.
---------------------------------------------------------------------------

    \330\ See ``Entergy Scenario 01 Contribution 2015-
1124_FINAL.xlsx,'' ``Avg_Impacts'' tab, column ``AA'' for Caney 
Creek and Upper Buffalo Class I areas. We summarize these results in 
the RTC document.
---------------------------------------------------------------------------

    Furthermore, the deciview visibility impacts for individual sources 
should be assessed based on natural ``clean'' background visibility 
conditions. The deciview improvement based on the 2018 background 
conditions provides an estimate of the amount of benefit that can be 
anticipated in 2018 and the impact a control/emission reduction may 
have on the established RPG for 2018. However, this estimate based on 
degraded or ``dirty'' background conditions underestimates the 
visibility improvement that would be realized for the control options 
under consideration. The source impacts and the potential benefits of 
controls must be considered relative to a light extinction level that 
represents a clean/natural background, rather than the current 
visibility conditions or projected visibility conditions at the end of 
the planning period.\331\ The need for consideration of visibility 
impacts and benefits relative to clean/natural conditions was explained 
in the preamble to the final BART Guidelines:
---------------------------------------------------------------------------

    \331\ This recommended approach to the treatment of background 
air quality when quantifying source impacts and potential benefits 
from additional measures is different than the approach to 
background air quality when projecting how all emission reductions 
measures combined will determine visibility conditions at the end of 
the implementation period, i.e., how background assumptions relate 
to the RPGs. It is not appropriate to consider only the amount by 
which a potential measure or combination of measures would change 
the projected overall deciview index value as of the end of the 
implementation period, i.e., the degree by which the RPGs would 
differ with and without the control being included in the LTS. The 
RPGs are values that will be compared in a progress report to actual 
visibility conditions, and accordingly must represent the expected 
actual overall visibility conditions. Estimates of source impacts 
and measure benefits have a different purpose, which is to help 
guide decisions on the control of individual sources.

    Using existing conditions as the baseline for single source 
visibility impact determinations would create the following paradox: 
The dirtier the existing air, the less likely it would be that any 
control is required. This is true because of the nonlinear nature of 
visibility impairment. In other words, as a Class I area becomes 
more polluted, any individual source's contribution to changes in 
impairment becomes geometrically less. Therefore the more polluted 
the Class I area would become, the less control would seem to be 
needed from an individual source. . . . Such a reading would render 
the visibility provisions meaningless, as EPA and the States would 
be prevented from assuring ``reasonable progress'' and fulfilling 
the statutorily-defined goals of the visibility program. Conversely, 
measuring improvement against clean conditions would ensure 
reasonable progress toward those clean conditions.\332\
---------------------------------------------------------------------------

    \332\ 70 FR at 39124.

    The same logic applies to the evaluation of visibility impacts and 
benefits for sources examined for controls for reasonable progress. 
Accordingly, the EPA has used clean background conditions in evaluating 
the benefits of controls on individual reasonable progress sources and 
has disapproved reasonable progress decisions by states that relied on 
modeling employing dirty background conditions.\333\ This approach has 
been upheld by the Eighth Circuit.\334\
---------------------------------------------------------------------------

    \333\ The EPA has followed this logic in the North Dakota (77 FR 
20894, April 6, 2012), Montana (77 FR 57864, September 18, 2012), 
Arizona (79 FR 52420, September 3, 2014), and Texas (81 FR 296, 
January 5, 2016) FIPs and partial disapprovals of North Dakota (77 
FR 20894, April 6, 2012) and Texas (81 FR 296, January 5, 2016).
    \334\ North Dakota v. EPA, 730 F.3d 750, 764-766 (8th Cir. 
2013). ``Although the State was free to employ its own visibility 
model and to consider visibility improvement in its reasonable 
progress determinations, it was not free to do so in a manner that 
was inconsistent with the CAA. Because the goal of Sec.  169A is to 
attain natural visibility conditions in mandatory Class I Federal 
areas, see CAA section 169A(a)(1), and EPA has demonstrated that the 
visibility model used by the State would serve instead to maintain 
current degraded conditions, we cannot say that EPA acted in a 
manner that was arbitrary, capricious, or an abuse of discretion by 
disapproving the State's reasonable progress determination based 
upon its cumulative source visibility modeling.''
---------------------------------------------------------------------------

    We note that while CALPUFF results are not directly comparable to 
CAMx model results due to differences in metrics, models and model 
inputs,\335\ CALPUFF visibility impacts are also calculated based on 
natural or ``clean'' background conditions.
---------------------------------------------------------------------------

    \335\ Some of the major differences are: (1) CALPUFF uses 
maximum 24-hour emission rates, while CAMx uses annual average 
emission rates; (2) CALPUFF focuses on the day with the 98th 
percentile highest visibility impact from the source being 
evaluated, whereas CAMx focuses on the average visibility impacts 
across the 20% worst days regardless of whether the impacts from a 
specific facility are large or small; and (3) CAMx models all 
sources of emissions in the modeling domain, which includes all of 
the continental U.S., whereas CALPUFF only models the impact of 
emissions from one facility without explicit chemical interaction 
with other sources' emissions.
---------------------------------------------------------------------------

    We recalculated the average modeled visibility impact for the 20% 
worst days based on the commenter's CAMx modeled average visibility 
impact for the 20% worst days using a clean background approach (using 
annual average natural conditions background).\336\ The Independence 
facility (units 1 and 2 combined) has impacts greater than 0.5 dv at 
both

[[Page 66403]]

Caney Creek and Upper Buffalo on average across the 20% worst days on a 
``clean'' background basis based on CAMx modeling submitted by the 
commenter.\337\ These CAMx model results for the average across the 20% 
worst days show that the Independence facility contributes 
significantly to visibility impairment on the 20% worst days and 
controls will result in meaningful visibility benefit towards the goal 
of natural visibility conditions. Furthermore, the maximum visibility 
impact on an individual day within the subset of days that make up the 
20% worst days are much larger. Facility-wide visibility impacts from 
Independence exceed 1 dv at each Arkansas Class I area. We note that in 
some situations, the days that CALPUFF model maximum or 98th percentile 
value impacts of the facility occur may not coincide with any of the 
days that make up the days in the worst 20% days at the Class I area 
and the visibility impacts modeled by CALPUFF are not directly 
comparable to the visibility benefits that would be anticipated on the 
20% worst days. See our complete RTC document for additional 
information on calculated visibility impacts from the Entergy 
facilities based on the commenter's CAMx modeling results.
---------------------------------------------------------------------------

    \336\ Deciview impacts are calculated using the following 
equation: [Delta]dv = 10 ln((bbackground+ 
bsource)/bbackground), where b is extinction 
(Mm-1) and [Delta]dv is the delta-deciview visibility 
impact.
    \337\ See ``Entergy Arkansas CAMx--EPA calcs max and clean 
background.xlsx,'' available in the docket for this action.
---------------------------------------------------------------------------

    Comment: The level of improvement expected from EPA's proposed 
controls for Independence is virtually insignificant and does not 
justify the costs of controls. The BART-type evaluation for 
NOX for the Independence Power Plant Units 1 and 2 would 
result in visibility improvements ranging from 0.148 to 0.459 dv with a 
cumulative improvement of 0.978 dv. EPA recognized that these 
improvements were relatively small and proposed an option (Option 2) 
that did not include the LNB/SOFA NOX controls for Units 1 
and 2. EPA, however, did not recognize that the Independence facility 
is subject to CSAPR and that NOX reductions ``better than 
BART'' would already be achieved by participation in that program 
without specifically requiring the LNB/SOFA in the FIP.
    For SO2 emissions for Independence Units 1 and 2, EPA 
estimated improvements with dry FGD ranging from 1.045 to 1.178 dv with 
a cumulative benefit of 4.375 dv. Three of the four class I areas would 
realize visibility improvements barely discernible to the human eye 
(<1.1 dv). The best improvement is for Upper Buffalo and is only 1.178 
dv. It is not appropriate to use the cumulative values as a 
representation of the visibility benefit of adding controls since only 
the improvement at each particular Class I area could actually be 
recognized. This level of visibility improvement is virtually 
insignificant and does not justify the costs associated with adding a 
dry FGD and, therefore, does not meet the statutory RPG requirement for 
proper consideration of the cost of controls and so is not 
``reasonable.''
    Response: We disagree with the commenter and do not believe that 
visibility improvements from NOX controls ranging from 0.128 
to 0.459 dv are relatively small. Given that sources are subject to 
BART based on a contribution threshold of no greater than 0.5 
deciviews, it would be inconsistent to consider an improvement in 
visibility of nearly 0.5 dv to be insignificant or small for reasonable 
progress. In our proposed action, we noted that ``The single source 
CALPUFF modeling shows that sizeable reductions to the maximum 98th 
percentile visibility impact from the Independence facility may be 
achieved through NOX controls.'' \338\ Furthermore, total 
modeled extinction at Caney Creek is dominated by nitrate on 4 of the 
days that comprise the 20% worst days in 2002, and a significant 
portion of the total extinction at Upper Buffalo on 2 of the days that 
comprise the 20% worst days in 2002 is due to nitrate.\339\ Both 
NOX and SO2 are key pollutants that contribute to 
visibility impairment at the Arkansas Class I areas. Because we have 
identified these two pollutants as key, we are obligated to determine 
which sources or source categories are responsible for emitting these 
pollutants and evaluate them for reasonable progress. Independence is 
the second largest point source of both SO2 and 
NOX in the State.\340\ Therefore, we evaluated it for 
reasonable progress controls for both pollutants. We recognized, 
however, that at this time, even though NOX emissions are a 
key pollutant, point source NOX emissions are not the main 
contributors to visibility impairment on the average of the 20% worst 
days at Arkansas' Class I areas in 2018, as projected by CAMx source 
apportionment modeling.'' \341\ Even though we recognized that 
NOX emissions are a key pollutant to reaching the regional 
haze goals, and that the visibility benefits from NOX 
controls were sizeable, we took comment on two options because the 
visibility impairment due to Arkansas point source emissions on the 
average of the 20% worst days were primarily due to sulfate emissions. 
We also found that significant reductions could be achieved very cost 
effectively through the implementation of low NOX burners. 
In our final action, we have determined that it is appropriate to 
require the NOX controls as proposed under Option 1 because 
the goal of the long-term strategy and reasonable progress requirements 
is to improve visibility and make progress towards natural conditions 
and NOX is a key pollutant impacting visibility at the 
Arkansas Class I areas. We used a shorthand term, ``driver,'' in our 
proposal discussing SO2, and did not mean to imply that 
NOX was not also a key pollutant. While point source 
NOX emissions are not the primary contributor to impairment 
on most of the 20% worst days, NOX is a key contributor to 
visibility on other days of the year and on some days that make up the 
20% worst days (in 2002, IMPROVE monitor data shows that two days that 
make up the 20% worst days at Upper Buffalo and three days at Caney 
Creek are more significantly impacted by nitrate than sulfate). So in 
considering reasonable progress factors, we have determined that 
because NOX and SO2 are both key visibility 
impairing pollutants, for Independence there are technically feasible 
and cost effective controls available for both SO2 and 
NOX and those controls will provide significant visibility 
improvement. Therefore, both SO2 and NOX controls 
are reasonable and necessary to eventually achieve the national goal. 
We have determined that it is appropriate to reduce NOX 
emissions and finalize Option 1. As to the comment that we did not 
recognize ``better than BART'' coverage due to CSAPR, we address this 
comment elsewhere in a separate response to comment.
---------------------------------------------------------------------------

    \338\ 80 FR at 18995.
    \339\ See Arkansas Regional Haze SIP, Appendix 8.1-- ``Technical 
Support Document for CENRAP Emissions and Air Quality Modeling to 
Support Regional Haze State Implementation Plans,'' section 3.7.1 
and 3.7.2. See the docket for this rulemaking for a copy of the 
Arkansas Regional Haze SIP.
    \340\ See 80 FR at 18991, Table 59.
    \341\ 80 FR at 18995.
---------------------------------------------------------------------------

    With respect to the anticipated visibility improvement due to 
SO2 controls, we consider visibility benefits ranging from 
1.045 to 1.178 dv at each Class I area to be significant. We note that 
the Regional Haze Rule provides that sources with a 0.5 dv impact at a 
Class I area ``contribute'' to visibility impairment and must be 
analyzed for BART controls, and that source with a 1.0 dv impact at a 
Class I area to ``cause'' visibility impairment. Given

[[Page 66404]]

that sources are subject to BART based on a contribution threshold of 
no greater than 0.5 deciviews and visibility impacts greater than 1.0 
deciview are considered a level to be ``causing'' visibility 
impairment, it would be inconsistent to consider a potential 
improvement in visibility of greater than twice the BART threshold to 
be insignificant.
    Furthermore, as discussed elsewhere throughout this final rule, 
results of Entergy Arkansas' CAMx modeling with source apportionment 
provide additional support that the Independence facility has 
significant impacts on visibility at nearby Class I areas on the 20% 
worst days and that controlling these units would result in significant 
visibility benefits towards the goal of natural visibility conditions. 
We address comments concerning the consideration of cumulative 
visibility benefits and imperceptible visibility benefits elsewhere.
    Comment: EPA's CALPUFF modeling indicates that the SO2 
and NOX emission limits proposed for Independence will 
result in a 1.952 dv improvement in Caney Creek and a 1.782 dv 
improvement in Upper Buffalo. However, this range is vastly overstated. 
Based on the current monitored visibility levels in Caney Creek and 
Upper Buffalo, the W20 days show that the visibility impairment in 2018 
will be approximately 23 to 24 dv. EPA recognizes that sulfate from all 
of Arkansas' point sources are projected to be responsible for only 
about 3.6% of total light extinction at Arkansas' Class I areas based 
on CENRAP modeling.\342\ This means that sulfate from all Arkansas 
point sources are projected to be responsible for only about 0.81-0.86 
dv of impairment (23-24 dv x 3.6%). For nitrates, EPA projects that 
Arkansas point source emissions will account for, at most, 0.29% of the 
total light extinction at Arkansas' Class I areas. Independence's 
SO2 and NOX emissions contribute only a portion 
to the sulfate and nitrate percentages estimated from Arkansas point 
sources. It would, therefore, be impossible for the SO2 and 
NOX limits proposed for Independence to result in deciview 
improvements at Caney Creek and Upper Buffalo of 1.952 dv and 1.782 dv, 
respectively. This simple example demonstrates the obvious flaw in 
EPA's use of CALPUFF for its reasonable progress analysis and, thus, 
its justification for imposing emission limits on Independence despite 
the fact that the Class I areas are below the URP.
---------------------------------------------------------------------------

    \342\ 80 FR at 18990.
---------------------------------------------------------------------------

    Based on CALPUFF modeling, EPA's proposed BART limits will result 
in projected combined visibility benefits of approximately 4.3 dv at 
Caney Creek. Based on Entergy's statistical projection of the haze 
index in Caney Creek, that would result in a haze index of 15.76 dv, 
which would put Caney Creek closer to natural background levels than 
the glide path. The URP would not reach that haze level until 
approximately 2048.\343\ Indeed, even if you ascribed the CALPUFF-
projected benefits to Caney Creek based on the recent IMPROVE levels 
(approximately 22 dv between 2009 and 2012), the projected haze index 
would drop to 17.7 dv, which indicates no further action should be 
needed to remain below the URP until approximately 2038.
---------------------------------------------------------------------------

    \343\ The projected haze index at Upper Buffalo of 18.05 dv 
would keep Upper Buffalo below the glide path until approximately 
2038--the end of the third planning period.
---------------------------------------------------------------------------

    If EPA insists on relying on CALPUFF to evaluate the projected 
visibility benefits of requiring controls on Independence, it must be 
consistent and use CALPUFF to evaluate the need for such controls for 
purposes of demonstrating reasonable progress. As demonstrated in 
Figures 11 and 12, controls at Independence cannot be justified for 
reasonable progress based on the CALPUFF results, which predict an 
improvement of several deciviews solely from BART controls.
    Response: As more fully explained above and in the RTC Document, 
the commenter's analysis fails to account for the fact that deciviews 
are a logarithmic function of extinction, that CALPUFF results are for 
the maximum impact (98th percentile impact from each source) in 
contrast to the CENRAP projected visibility conditions that are for the 
average visibility over the 20% worst days, and also fails to 
differentiate between deciview values calculated based on natural 
background conditions (as the CALPUFF results are) and the deciview 
values relative to a degraded or dirty background.
    First, the commenter incorrectly estimates that the impact from 
sulfate point source emissions in Arkansas is 0.81-0.86 dv. Because the 
deciview metric is a logarithmic function of extinction, the percent 
extinction cannot be directly applied to the total deciview impairment. 
Recalculating the impact from sulfate point sources to correct for this 
error yields approximately a 0.32 dv impact based on a ``dirty'' 
background 2018 projected visibility conditions and 0.92 dv based on a 
natural background approach.
    Second, 0.92 dv represents the estimated deciview improvement from 
eliminating sulfate emissions at all point sources in Arkansas (based 
on typical or average emissions) on average across the 20% worst days, 
as defined by the 20% worst days of monitored visibility at Caney 
Creek. This CAMx derived value is not directly comparable to the 
CALPUFF modeled 1.952 dv improvement from controls on both units at 
Independence, due to differences in models, model inputs and metrics. 
CALPUFF modeling following the BART guidelines and recommended protocol 
provides an estimate of the maximum (98th percentile) visibility 
benefit based on 24-hr maximum actual emissions modeled over a period 
of three years. The CAMx modeling results presented by the commenter 
represent the average visibility impacts over the 20% worst days (as 
defined by monitored data) based on modeling actual emissions levels. 
In addition, CALPUFF uses an estimated constant background ammonia 
level and does not account for the competition for ammonia due to 
emissions from other sources. A maximum value of 1.952 dv for 
visibility benefits of controlling Independence based on CALPUFF 
modeling is not inconsistent with an estimated 0.92 dv impact from all 
sulfate point source emissions averaged over the 20% worst days. In 
general, the maximum value could be several times larger than the 
average over the 20% worst days (representing the average visibility 
over the 73 days, or 24 monitored days with the worst visibility). 
Furthermore, the maximum value as modeled by CALPUFF is based on 
maximum 24-hr emissions, which may be much higher than the average 
emissions. As discussed in a separate response to comment above, CAMx 
modeling using source apportionment provided by the commenter (Entergy) 
modeled a facility-wide impact from Entergy Independence of 1.64 dv on 
the maximum day within the subset of days that make up the 20% worst 
days. The maximum modeled impact across the full 365 days modeled could 
be much larger. Furthermore, this modeling is based on actual emissions 
and not maximum 24-hr emissions as modeled by CALPUFF. Therefore, the 
1.952 dv visibility benefit estimated by CALPUFF is not ``impossible'' 
and is in fact in line with the visibility impacts estimated using the 
CAMx model as supplied by the commenter.
    Third, the commenter is incorrect in estimating a 4.3 dv 
improvement from all BART controls and using this value to adjust 
projected visibility conditions

[[Page 66405]]

in 2018 on the 20% worst days in the above figures. The cumulative 
visibility impacts cited to by the commenter (e.g., 4.3 dv improvement 
at Caney Creek due to all BART controls) combines the maximum 
visibility improvements from each facility that would result from 
required NOX or SO2 controls without any 
consideration of the location of the source or if the impacts and 
benefits would occur on the same day. The commenter's approach 
overstates the combined impact at a given Class I area and does not 
contemplate if sources are located near each other and would likely 
impact a Class I area at the same time. Contrary to the commenter's 
description of the methodology used to estimate the total visibility 
benefits of BART controls,\344\ the commenter simply added the CALPUFF 
modeled deciview visibility benefits for each control. These benefits 
represent the maximum (98th percentile) visibility benefits at each 
source based on reductions to the maximum 24-hr emissions modeled over 
a period of three years. The maximum benefits from controlling one 
source cannot be added to the maximum benefits of controlling another 
source as these benefits are not likely to occur on the same day since 
the sources are not collocated. In addition, the maximum benefits from 
NOX controls and SO2 controls at the same 
facility cannot be added as they may not occur on the same day. 
Furthermore, these values represent the benefit on an individual day 
and not the average visibility benefit on the 20% worst days so it is 
not appropriate to adjust the visibility conditions on the 20% worst 
days by this amount as the commenter does in the above figures. In some 
situations, the days that CALPUFF model maximum or 98th percentile 
value impacts of the facility occur may not coincide with any of the 
days that make up the days in the worst 20% days at the Class I area 
and the visibility benefits modeled by CALPUFF are not directly 
comparable to the visibility benefits that would be anticipated on the 
20% worst days from those specific controls. Furthermore, as discussed 
elsewhere in this section of the final rule, because deciviews are a 
logarithmic function of extinction, they cannot be added as the 
commenter does here. The CALPUFF modeled visibility benefits represent 
the visibility benefits of controls based on a clean background 
approach, and not the amount of benefit that would occur from degraded 
conditions, which would be needed to estimate the improvement in 
overall visibility conditions in 2018. We estimated the amount of 
visibility benefit anticipated from all controls against 2018 
visibility conditions in estimating the proposed RPGs for 2018. In this 
calculation we estimated the benefit from all required controls to be 
0.21 dv at Caney Creek and 0.19 dv at Upper Buffalo.
---------------------------------------------------------------------------

    \344\ Commenter states: ``Trinity derived the 4.3 dv improvement 
from the CALPUFF modeling by determining the total extinction (in 
inverse megameters) from each proposed BART source, adding them 
together, and then calculating the deciview improvement. The 
resulting 4.3 dv improvement is over five times the total visibility 
impact attributed to all point sources in Arkansas based on CENRAP's 
CAMx modeling and 14 times the impact attributed to point sources 
based on Entergy's current CAMx modeling.''
---------------------------------------------------------------------------

    Comment: CALPUFF overstates the visibility improvement expected 
from EPA's proposed controls on Independence, EPA concluded that the 
cumulative benefit of installing all of the controls in the Proposed 
FIP--all BART controls plus controls at Independence--would result in 
visibility benefits at Caney Creek of only 0.21 dv and at Upper Buffalo 
of only 0.19 dv. Since Independence represents only approximately 36% 
of the SO2 point source emissions and 21% of the point 
source NOX emissions in Arkansas, one can ascribe only a 
minor portion of this projected insignificant deciview improvement to 
controls on Independence (approximately 0.08 dv at Caney Creek and 0.07 
dv at Upper Buffalo).\345\ Based on this, installation of controls on 
Independence will yield no discernible visibility improvements.
---------------------------------------------------------------------------

    \345\ These values are the calculated improvement based on EPA's 
``scaling methodology.'' See 80 FR at 18997.
---------------------------------------------------------------------------

    This demonstrates the illogic of relying on CALPUFF for reasonable 
progress. Independence's contribution to the deciview improvements EPA 
projects based on the CENRAP modeling would be much less than the total 
deciview improvement at Caney Creek of 0.21 dv from the installation of 
controls at all of the proposed FIP sources and 0.19 dv at Upper 
Buffalo would not be perceptible to the human eye; nowhere close to the 
1.95 dv and 1.78 dv improvement that EPA is claiming based on CALPUFF. 
Requiring imperceptible visibility improvements is simply unreasonable. 
The CAA requires only ``reasonable progress, not the most reasonable 
progress.'' \346\
---------------------------------------------------------------------------

    \346\ North Dakota v. EPA, 730 F.3d 750, 767 (8th Cir. 2013).
---------------------------------------------------------------------------

    Response: As we discuss in depth elsewhere, visibility improvements 
from controls must be evaluated on a ``clean'' background basis to 
fully assess the benefits from controls. It is not appropriate to 
consider only the amount by which a potential measure or combination of 
measures would change the projected overall deciview index value as of 
the end of the implementation period, i.e., the degree by which the 
RPGs would differ with and without the control being included in the 
LTS, as the commenter does here. We also discuss elsewhere in this 
section of the final rule that the deciview scale is a logarithmic 
function of extinction and calculations to determine benefits or amount 
of contribution to visibility impairment must be based on extinction 
and then converted into deciviews. Nevertheless, the commenter's 
estimated visibility benefits of 0.08 dv at Caney Creek and 0.07 dv at 
Upper Buffalo on average across the 20% worst days are approximately a 
reduction in extinction of 0.8 Mm-1 at Caney Creek and 0.7 
Mm-1 at Upper Buffalo, which is 0.37 dv and 0.32 dv based on 
a clean background approach for the 20% worst days. In our response to 
a separate comment above, we discuss that due to the differences in 
models, model inputs, and metrics, the estimated visibility benefits 
estimated from CAMx modeling cannot be directly compared to CALPUFF 
modeled visibility benefits. For one, CALPUFF modeling is used to 
estimate the maximum visibility benefit based on maximum emissions 
whereas the CAMx modeling estimates the average visibility benefit over 
the 20% worst days (as defined by the monitored data) using actual or 
typical emission levels. As we also discuss above in a separate 
response to comment, CAMx visibility modeling with source apportionment 
submitted by Entergy estimates a maximum visibility impact (limited to 
only the days comprising the 20% worst days) of over 1.5 dv from the 
Independence facility at both Caney Creek and Upper Buffalo. In some 
situations, the CALPUFF modeled maximum or 98th percentile impacts of 
the facility may not coincide with the days that make up the worst 20% 
monitored days at the Class I area, therefore the maximum impact based 
on CAMx modeling could be even higher.
    With regard to the quote the commenter reproduced from the Eighth 
Circuit Court's decision in North Dakota v. EPA,\347\ several 
environmental groups challenged a portion of our final action on North 
Dakota's regional haze SIP that ultimately approved North Dakota's 
reasonable progress determination for

[[Page 66406]]

NOX controls for the Coyote Station.\348\ The environmental 
groups objected to North Dakota's decision to reject a control it had 
evaluated, after having applied the four reasonable progress factors, 
and subsequently approving another NOX control as reasonable 
progress.
---------------------------------------------------------------------------

    \347\ The commenter states that requiring imperceptible 
visibility improvements is simply unreasonable and refers to the 8th 
circuit decision that the CAA requires only ``reasonable progress, 
not the most reasonable progress.'' North Dakota v. EPA, 730 F.3d 
750, 767 (8th Cir. 2013).
    \348\ See EPA's final rule at 77 FR 20894, 20945 (April 6, 
2012).
---------------------------------------------------------------------------

    We interpret the Court's statement as meaning broadly that just 
because a more stringent level of control could be technically feasible 
in a particular instance, it does not mean it necessarily must be 
required under reasonable progress. We see no conflict with this 
determination and our proposed Arkansas FIP and requiring controls that 
may not result in perceptible visibility improvements. In North 
Dakota's case, we noted technical flaws in North Dakota's analysis, and 
we noted that we could have reached a different conclusion had we 
conducted the analysis ourselves, but we ultimately determined these 
issues did not prevent us from accepting North Dakota's reasonable 
progress determination. The Court did not find that our conclusions on 
the issue were arbitrary, stating in part that, ``[e]ven if [the 
control in question] were perhaps the most reasonable technology 
available, the CAA requires only that a state establish reasonable 
progress, not the most reasonable progress. In contrast, and as 
explained in greater detail elsewhere, in our 2012 rulemaking,\349\ we 
made a finding that Arkansas did not complete a reasonable progress 
analysis and therefore did not properly demonstrate that additional 
controls were not reasonable under 40 CFR 51.308(d)(1)(i)(A). Thus we 
disapproved the RPGs Arkansas established for Caney Creek and Upper 
Buffalo. Our proposed rulemaking completed the reasonable progress 
analysis and established revised RPGs, since we have not received a 
revised SIP to correct the portions of the SIP submittal we 
disapproved. We determined that cost effective controls were in fact 
available that would have very significant visibility benefits.
---------------------------------------------------------------------------

    \349\ 64 FR at 35732.
---------------------------------------------------------------------------

    Comment: EPA's assessment demonstrates that the Independence Power 
Plant's emissions have, and will continue to have, very little effect 
on visibility in any Class I area. EPA's reasonable progress analysis 
shows that ``[o]n the 20% worst days in 2002, sulfate from Arkansas 
point sources contributed 2.20% of the total light extinction at Caney 
Creek and 1.99% at Upper Buffalo, and nitrate from Arkansas point 
sources contributed 0.27% of the total light extinction at Caney Creek 
and 0.14% at Upper Buffalo.'' 80 FR at 18989 (footnote omitted). 
According to EPA, these very small percentages reflect contributions 
from all ``Arkansas point sources,'' not from the Independence Power 
Plant alone, whose emissions of course contribute only a fraction of 
these small amounts.
    Response: We disagree with the commenter's assertion that the 
contribution to visibility impairment from Independence is 
``insignificant'' or ``minimal.'' We agree with the commenter's 
description of the 2002 CENRAP source apportionment data. The CENRAP 
modeling also projects that Arkansas point sources will be responsible 
for 3.58% of the total light extinction at Caney Creek and 3.20% at 
Upper Buffalo in 2018. As we discuss in our proposal, based on 2011 NEI 
data the Entergy Independence Plant is the second largest source of 
SO2 and NOX point source emissions in Arkansas, 
accounting for approximately 36% of the SO2 point-source 
emissions and 21% of point-source NOX emissions in the 
State.\350\ Therefore, a significant portion of the total projected 
visibility impairment on the 20% worst days, on the order of 1% or 
more, can be expected to be attributable to SO2 emissions 
from a single facility, the Independence facility, based on the CERNAP 
modeling. We discuss in a separate response to comment that results of 
our CALPUFF modeling, as well as the results of additional CAMx 
modeling submitted by Entergy, confirm and support that the visibility 
impairment due to the Independence facility is significant and that 
emission reductions will result in meaningful visibility benefits 
towards natural visibility conditions.
---------------------------------------------------------------------------

    \350\ 80 FR at 18991.
---------------------------------------------------------------------------

6. Visibility Benefit of Entergy Arkansas Proposal
    Comment: Entergy's proposed combination of controls and lower 
SO2 emission rates will ensure that the Class I areas 
achieve virtually the same reasonable progress as EPA's proposal but at 
a cost of over $2 billion less than the proposal.\351\ Based on 
Entergy's CAMx modeling and Ranked Statistical Analysis, the difference 
in the haze index between the proposed FIP controls and Entergy's 
proposal is 0.05 dv at Caney Creek and 0.07 dv at Upper Buffalo.
---------------------------------------------------------------------------

    \351\ Entergy Arkansas Inc. stated that it is proposing near-
term interim controls and the cessation of coal combustion at White 
Bluff by 2028. Entergy is proposing to meet lower SO2 
emission rates at White Bluff Units 1 and 2 and Independence Units 1 
and 2 by 2018, and is willing to install LNB/SOFA at all four units 
and meet a 30-day rolling average NOX emission rate of 
1,342.5 lb NOX/hr, within three years after the effective 
date of the final FIP as part of its multi-unit approach. Entergy's 
comments with regard to the proposed NOX rate are 
discussed elsewhere in this final rule.
---------------------------------------------------------------------------

    Response: We discuss the ``ranked statistical analysis'' submitted 
by the commenter in the response to comments elsewhere. We disagree 
with the commenter that the Entergy proposed control scenario achieves 
``virtually'' the same visibility benefits as the controls required in 
this FIP. We examined the estimated visibility benefits of the FIP and 
Entergy's proposal from the commenter's CAMx photochemical modeling. We 
note that both scenarios include benefits from all required BART 
controls at all subject-to-BART facilities with the exception of White 
Bluff. The modeled FIP scenario also includes SO2 and 
NOX controls at both Independence and White Bluff. The 
modeled Entergy proposal scenario includes the elimination of emissions 
from White Bluff, an approximate 15% reduction in SO2 
emissions from Independence and roughly similar NOX 
reductions at Independence as required in the FIP.
    Entergy's proposal achieves less visibility benefit than the FIP 
controls at Arkansas' Class I areas, most significantly at Upper 
Buffalo where the benefit from Entergy's proposal is approximately only 
63% of the benefit from the FIP (1.54 Mm-1 from the FIP 
compared to 0.97 Mm-1 from Entergy's Proposal, see the RTC 
document for additional information). As discussed above, CAMx source 
apportionment modeling submitted by Entergy shows that Entergy 
Independence has significant visibility impacts at both Arkansas Class 
I areas. At Upper Buffalo, the Independence facility contributes more 
to visibility impairment than all the subject-to-BART sources addressed 
in this action combined. Additional reductions from the elimination of 
emissions from the White Bluff facility under Entergy's proposal are 
much too small to compensate for the lack of significant SO2 
reductions at Independence. Furthermore, Entergy's proposal does not 
achieve these benefits until 2028, seven years after the full benefits 
from the FIP would be realized. We discuss other aspects of Entergy's 
proposal, including uncertainty in emissions at White Bluff after the 
cessation of coal-burning, and issues concerning the BART requirements 
for White Bluff in separate responses to comment elsewhere in this 
document.

[[Page 66407]]

    We also disagree with the commenter's use of the results of their 
ranked statistical analysis (the ``projected haze index'' shown in the 
Entergy Arkansas Inc.'s submitted comments in figures 13 and 14) as the 
starting point for calculating the overall visibility benefits from the 
FIP or the commenter's proposed alternative. As discussed elsewhere in 
this section of the final rule, the ranked statistical analysis is 
simply a projection of future visibility conditions based on past 
improvement and is not directly tied to any additional required 
emission reductions in the next few years that would result in this 
future visibility improvement from current conditions to this projected 
value in 2018.
7. Observed Visibility Improvements
    Comment: Trinity was tasked by Entergy Arkansas with conducting a 
statistical analysis of observed visibility data gathered through the 
IMPROVE program to statistically determine the future trends in the 
regional haze index values. Trinity conducted a simple Trend 
Statistical Analysis and more robust Ranked Statistical Analysis to 
determine the projected haze index in 2018.\352\
---------------------------------------------------------------------------

    \352\ Trinity's report is included as Exhibit D IMPROVE Data 
Statistical Analysis, Trinity Consultants (July 2015) to Entergy 
Arkansas, Inc.'s comments.
---------------------------------------------------------------------------

    For Caney Creek and Upper Buffalo, respectively, the observed 
values are well below the glide path with a consistent downward trend 
in the observations. This downward trend is consistent with the 
historical (2002-2011) trend in decreasing sulfur dioxide 
(SO2) emissions from tier 1 sources located in the states 
contributing significantly to the Caney Creek and Upper Buffalo Class I 
Areas.\353\ Pursuant to the NEI emissions data, the SO2 
emissions have significantly decreased since 2005 to 2011 in all source 
categories, including especially a more than 50% drop due to fuel 
combustion from electric utilities and a 67% drop in the fuel 
combustion from industrial sources. Based on the significant downward 
trend in the observed data and the actual SO2 emissions 
data, the future haze index value in 2018 is expected to be lower than 
the currently predicted glide path. The lower haze index value in 2018 
will be additionally supported by the anticipated implementation of 
regulations further curbing emissions.
---------------------------------------------------------------------------

    \353\ See Figure 2-3 of Exhibit D to Entergy Arkansas, Inc.'s 
comments.
---------------------------------------------------------------------------

    In order to statistically calculate the future deciview haze index 
values using observed data instead of relying on the CENRAP modeling, 
two statistical analyses were performed and evaluated to determine the 
most appropriate analysis for predicting the haze index values based on 
observed data: Trend Analysis, and Ranked Statistical Analysis. The 
2018 average of the 20% worst days for visibility was calculated to be 
20.07 dv for Caney Creek and 20.91 dv for Upper Buffalo. These numbers 
are far below the URP for the first planning period and demonstrate 
that no source in Arkansas, including Independence, needs to install 
controls for Arkansas to remain below the glide path.
    Response: As we discuss in section V.C of this final rule, being 
projected to be on or below the URP glidepath in 2018 (or even beyond) 
does not automatically mean that no controls or evaluation under 
reasonable progress is needed in this planning period. The commenter 
presents SO2 emissions data from 2002, 2005, 2008, and 2011 
for states identified by the commenter as impacting visibility at the 
Arkansas Class I areas. These data show significant emissions 
reductions over this time period and are consistent with observed 
visibility improvement at the Arkansas Class I areas. However, most of 
the visibility improvement currently observed in Arkansas appears to be 
due to emissions reductions that have taken place outside the state. 
Arkansas emissions do not exhibit the same downward trend as presented 
for the other states that impact visibility at the Arkansas Class I 
areas.\354\ More recent annual emissions from 2012-2014 are actually 
higher than emissions from the 2008-2011 period and there is no 
downward trend in emissions from those point sources with the largest 
visibility impacts, those from fuel combustion at electric utilities. 
To the extent that the commenters are suggesting that Arkansas should 
be relieved of its regional haze obligations because other states' 
emission reduction efforts have already resulted in significant 
visibility improvement at Arkansas' Class I areas, this is incorrect. 
Rather Arkansas, and EPA in standing in Arkansas' shoes, must consider 
the statutory factors in addressing the long term strategy and 
reasonable progress requirements.
---------------------------------------------------------------------------

    \354\ See RTC document for additional information on Arkansas 
source category SO2 emissions from 2004 to 2014.
---------------------------------------------------------------------------

    We disagree with the commenter that the CENRAP CAMx predicted 2018 
haze index is overly conservative. The comments indicate a lack of 
understanding of how reasonable progress goals are established, as well 
as the imports of the goals as opposed to the measures adopted to 
ensure reasonable progress. As we state in the Regional Haze Rule, the 
reasonable progress goal(s) set by the state, or EPA when promulgating 
a FIP, are not enforceable. The reasonable progress goals are an 
analytical tool used by EPA and the states to estimate future 
visibility conditions and track progress towards the goal of natural 
visibility conditions. Accordingly, the RPGs must represent an estimate 
of the degree of visibility improvement that will result in a future 
year from changes in emissions inventories, changes driven by the 
particular set of control measures adopted in the regional haze SIP or 
FIP to address visibility, as well as all other enforceable measures 
expected to reduce emissions. Given the forward-looking nature of 
reasonable progress goals and the range of assumptions that must be 
made as to emissions in the future, we expect there to be some 
uncertainty in the estimates of future visibility.
    The statistical analyses provided by the commenter are simply 
extrapolations of future visibility conditions based on observed 
reductions in visibility impairment in the past. Future visibility 
projections must be directly tied to projections of future emissions, 
and anticipated reductions due to federal and state requirements. 
Current 5-yr average (2010-2014) observed visibility conditions are 
21.8 dv at Caney Creek and 21.6 dv at Upper Buffalo. Any future 
improvements in overall visibility conditions at the Arkansas Class I 
areas between now and 2018 will be due to future emission reductions 
during that time period. Commenters have not provided any specific 
information suggesting anticipated enforceable emission reductions from 
those Arkansas point sources with significant visibility impacts or 
other sources that would result in the almost 2 dv visibility 
improvement by 2018 projected by the commenter at Caney Creek in their 
statistical analysis. Furthermore, as discussed above, any anticipated 
emission reductions from sources in other states do not relieve 
Arkansas of its regional haze obligations. The BART requirements under 
Sec.  51.308(e) must be met for those specific sources that meet the 
BART criteria and contribute to visibility impairment. The 
determination of whether an RPG and the emission limitations and other 
control measures upon which it is based constitute reasonable progress 
is made by conducting certain analyses and

[[Page 66408]]

meeting the requirements under Sec.  51.308(d)(1).
    The RPGs are an analytical tool the state and we use to evaluate 
whether the measures in the implementation plan are sufficient to 
achieve reasonable progress. What is enforceable under the RH rule are 
the emission limitations and other control measures that apply to 
specific sources, and upon which the RPGs are based. Since the emission 
limitations we are requiring in our FIP for specific Arkansas sources 
(which is what our revised RPGs are based upon) are not currently being 
achieved, we disagree that visibility at the Class I areas has already 
improved beyond what we would require in our FIP and that our FIP is 
therefore unjustified and unwarranted. The emission reductions required 
in this action will result in significant visibility improvements at 
the Class I areas beyond what is currently being achieved or observed. 
As discussed elsewhere throughout this final rule, the commenter's 
photochemical modeling analysis provides an additional demonstration 
that the controls required in this action result in visibility benefits 
beyond current observed visibility conditions and serve to accelerate 
progress towards natural visibility conditions.
8. Reasonable Progress Goals
    Comment: EPA's proposed RPGs are more stringent than Arkansas' 
proposed RPGs in its 2008 Regional Haze SIP, which would have ensured 
that Arkansas is on track to achieve natural visibility conditions by 
2064. Arkansas is reducing regional haze in its Class I areas at a 
higher rate than both the URP, which was approved by EPA, and Arkansas' 
initial proposed RPGs. As indicated by the URP, Arkansas is well on 
track to reaching natural visibility conditions by 2064 and more 
stringent RPGs than those in Arkansas' 2008 Regional Haze SIP are not 
necessary. EPA should withdraw the Proposed FIP and ensure that revised 
RPGs in any subsequent plan are within the scope of EPA's authority to 
address impairment of visibility.
    The differences in projected 2018 visibility conditions at Caney 
Creek and Upper Buffalo that are attributable to all of the proposed 
FIP controls--including both FIP BART and FIP reasonable progress 
requirements--will be imperceptibly small (i.e., improvements of, at 
most, 0.21 dv and 0.19 dv, respectively, at Caney Creek and Upper 
Buffalo). The minimal visibility improvements that EPA's proposed 
reasonable progress emission control requirements would produce would 
come at exorbitant costs. Additionally, even the negligible changes in 
visibility represented by EPA's proposed revised RPGs are greatly 
overstated because some controls will not be in place until after 2018.
    Commenters also state that the methodology utilized by EPA in 
estimating the RPGs is oversimplified and inaccurate. EPA chose a 
method of determining RPGs that is admittedly inferior and less 
sophisticated than the alternative approach, which EPA rejected in 
Arkansas but used in Texas: CAMx photochemical modeling. EPA admits 
that it has not performed its own modeling in a manner adequate to 
develop ``refined numerical RPGs.'' Some commenters stated that EPA 
used CALPUFF, which is not a photochemical grid model, to develop a 
``quick-and-dirty'' RPG analysis in the proposed Rule.
    Response: As we discuss in more detail elsewhere in our response to 
comments, we agree that Arkansas proposed RPGs in its 2008 regional 
haze SIP that fell below the URP. However, in our 2012 rulemaking,\355\ 
we made a finding that Arkansas did not complete a reasonable progress 
analysis and therefore did not properly demonstrate that additional 
controls were not reasonable under 40 CFR 51.308(d)(1)(i)(A). Thus we 
disapproved the RPGs Arkansas established for Caney Creek and Upper 
Buffalo. In our proposed rulemaking, we completed the reasonable 
progress analysis and established revised RPGs, since we have not 
received a revised SIP to correct the portions of the SIP submittal we 
disapproved. As discussed in our proposal and in our RTC document, we 
focused our reasonable progress analysis on the Entergy Independence 
facility because of its significant emissions of NOX and 
SO2 and its large potential to impact visibility at nearby 
Class I areas. We determined that cost-effective controls were 
available for units at this facility and that they would result in 
significant visibility benefits. We respond to specific comments 
concerning the visibility benefits from controls on the Independence 
facility in separate responses to comments. We also completed five-
factor BART analyses and determinations for subject-to-BART facilities 
where we had previously disapproved the BART determination in the 2008 
Arkansas regional haze SIP. Our proposed RPGs reflected the visibility 
benefits anticipated from the implementation of controls across the 
subject-to-BART facilities and the Independence facility required in 
this action. As we discuss in our proposal and in response to comments, 
we have determined that these controls are cost-effective and result in 
significant visibility benefits that provide for progress towards the 
goal of natural visibility conditions. As we discuss below in a 
separate response to comment, after considering comments received, we 
agree that the RPGs should reflect anticipated visibility conditions at 
the end of the implementation period in 2018 rather than the 
anticipated visibility conditions once the FIP has been fully 
implemented. We are finalizing RPGs that represent the visibility 
conditions anticipated on the 20% worst days at Caney Creek and Upper 
Buffalo by 2018.
---------------------------------------------------------------------------

    \355\ 64 FR at 35732.
---------------------------------------------------------------------------

    We disagree with the commenter that the amount of visibility 
improvement due to our proposed FIP is ``insignificant.'' We address 
comments concerning the perceptibility of visibility improvements in 
response to comments elsewhere. The required controls are estimated to 
improve overall visibility benefits compared to the CENRAP projected 
visibility conditions for 2018 by approximately 0.2 deciviews, a 
reduction in light extinction of about 2 Mm-1 at Caney Creek 
and 1.8 Mm-1 at Upper Buffalo. Once fully implemented, the 
required controls to meet the BART requirements, as well as required 
controls on the Independence facility result in an approximate 2% 
improvement in overall visibility conditions projected by CENRAP at 
both Caney Creek and Upper Buffalo on the 20% worst days. Our technical 
record demonstrates that the required controls reduce impacts from 
these sources and result in meaningful visibility benefits towards the 
goal of natural visibility conditions. The required controls reduce the 
projected visibility impairment due to all Arkansas point sources by 
50% at Caney Creek and 50% at Upper Buffalo. We note that the required 
controls actually result in larger visibility improvements than 
calculated here because the CENRAP projections already included an 
assumption of large emission reductions due to SO2 BART at 
Flint Creek, as well as NOX controls at White Bluff and 
Flint Creek.\356\
---------------------------------------------------------------------------

    \356\ 2002 CENRAP modeled SO2 emissions for Flint 
Creek were 11,165 tpy and 2018 CENRAP modeled SO2 
emissions were 2,896 tpy, an assumed 75% reduction in emissions.
---------------------------------------------------------------------------

    We disagree with the commenter that our proposed RPGs overstated 
the visibility benefit of controls or that they are inaccurate. In our 
proposal, we acknowledged that the methodology we utilized to estimate 
the revised RPGs is

[[Page 66409]]

not as refined as developing an updated model projection. However, it 
allows us to translate the emission reductions contained in the 
proposed FIP into quantitative RPGs, based on modeling previously 
performed by the CENRAP. These proposed RPGs provided an estimate of 
the visibility benefit of all the required controls compared to the 
2018 visibility conditions projected by the state and established in 
their SIP that would result without the required controls. After 
considering comments received, we agree that the RPGs should reflect 
anticipated visibility conditions at the end of the implementation 
period in 2018 rather than the anticipated visibility conditions once 
the FIP has been fully implemented, and have accordingly revised the 
2018 RPGs. RPGs, unlike the emission limits that apply to specific 
reasonable progress and BART sources, are not directly enforceable. 
Rather, the RPGs are an analytical framework considered by us in 
evaluating whether measures in the implementation plan are sufficient 
to achieve reasonable progress. Our FIP imposes emissions limitations 
that we conclude to be necessary under the CAA for the first planning 
period. Ideally, these controls would be installed and the emission 
limitations achieved, so the visibility improvements can be realized 
and built on in a subsequent comprehensive periodic SIP revision (see 
40 CFR 51.308(f)). Arkansas may choose to use these RPGs for purposes 
of its progress report (along with a consideration for what controls 
had already been implemented and what controls would be implemented in 
the near future), or may develop new RPGs for approval by us along with 
its progress report, based on new modeling or other appropriate 
techniques, in accordance with the requirements of 40 CFR 51.308(d)(1) 
in evaluating the adequacy of their SIP (or this FIP) to meet the 
established RPGs.
    We discuss our selection of the CALPUFF model for evaluating 
single-source visibility impacts in a separate response to comment 
above. In the response, we also explain the model selection for our 
Texas action and refer the reader to our detailed explanation in the 
RTC that accompanies that action. Commenters are incorrect and confuse 
the single-source visibility analysis used to evaluate the visibility 
benefit of controls on a specific source with the assessment of overall 
visibility conditions. We did not use the CALPUFF modeling to develop 
the new reasonable progress goals we establish in this rulemaking. The 
RPGs are based on adjusting the CENRAP 2018 CAMx photochemical modeling 
based on source apportionment modeling results and emission inventory 
data. As we stated in the proposed rulemaking, we did not perform 
additional photochemical modeling to directly model the new projected 
visibility goals due to the time and resource demands associated with 
photochemical modeling. The commenters are also incorrect in their 
comparison of approaches for establishing new RPGs between this action 
for Arkansas and our previous action in Texas. For both Texas and 
Arkansas, we utilized the CENRAP 2018 CAMx modeling that estimated the 
2018 RPGs and then adjusted those RPGs to account for estimated 
visibility improvement due to required controls. In neither case did we 
perform a full photochemical modeling analysis to model all the 
required controls and project the future visibility conditions. In both 
cases, the 2018 RPGs were adjusted based on a scaling of the source 
apportionment model results and emission inventory changes.
    Comment: The demonstration methodology used by EPA is unscientific. 
EPA used a ratio of emission rates from BART sources to Arkansas point 
sources to scale the modeled predicted haze index. First, there is no 
evidence to prove that the CAMx predicted modeling results are linearly 
correlated with emission rates. In fact, the CAMx modeling 
fundamentally is based on photochemical reactions. Therefore, the 
relationship between variation in the emission rates and predicted 
concentration is complicated. Second, a deciview is a logarithmic scale 
based on the concept that one deciview is the minimum change in the 
visibility perceptible to a human observer. As such, deciviews cannot 
be added or subtracted directly. Therefore, fractioning or scaling 
deciviews based on emission rates is illogical.
    Another commenter was supportive of our approach, stating that in 
Texas, the model results were used to demonstrate that the overall 
change in species concentrations was very nearly linearly proportional 
to the change in emission levels for an individual source (with very 
high linear correlation coefficients near 1.0). This strongly supports 
the use of the emission scaling approach for Arkansas. If the CAMx 
model were used to determine the impact of emission controls on a 
single source in Arkansas (such as Independence), it is therefore 
expected that the modeled reductions in sulfate and nitrate 
concentrations at each of the Class I areas will be very nearly 
proportional to the SO2 and NOX concentration 
reductions. In other words, the emission scaling approach has been 
shown to be mathematically sound and quite appropriate, especially 
considering the resources that would be required to exercise CAMx 
separately for each control measure at each evaluated source.
    Response: We disagree with the comments that the methodology used 
to estimate overall visibility benefits from all required controls 
control level emissions was unreasonable or unscientific. We agree with 
comments that the approach we followed is reasonable and based on a 
scaling of visibility extinction components due to Arkansas point 
sources in proportion to emission changes from the required controls at 
Arkansas point sources. The commenter is incorrect in suggesting that 
we developed a linear relationship between emissions and deciviews and 
then commenting that this ``fractioning or scaling of deciviews'' is 
flawed because the relationship between light extinction and deciviews 
is exponential. We properly developed a linear relationship between 
emissions and light extinction (inverse Megameters), not deciviews.
    We agree with the commenters, that in general, the relationship 
between downwind concentrations and emissions can be complicated and 
non-linear due to complex chemistry, including the fact that reductions 
in sulfur emissions can result in an increase in ammonium nitrate. For 
estimating the total visibility benefit from all controls and 
estimating a new reasonable progress goal that reflects those controls, 
we relied on the CENRAP's 2018 CAMx modeling results, including source 
apportionment results, and the projected emission inventories, and 
scaled the results as described in the TSD, similar to what was done in 
our previous action in Arizona and Texas. While we acknowledge that 
this approach is not as refined an estimate as would be attained in 
performing a new photochemical modeling run, it is based on scaling to 
adjust earlier photochemical modeling results that took into account 
the complex chemistry that impacts the overall visibility. The 
uncertainty in the visibility benefit from these controls introduced by 
the linear extrapolation does not impact the overall conclusions. 
Furthermore, in our technical analysis developed to support our action 
on Texas regional haze, we observed that for each facility and Class I 
area, the available modeled visibility impact was linear with respect 
to emissions with

[[Page 66410]]

high correlation.\357\ Following this approach we estimated that when 
fully implemented, the required controls would result in a reduction in 
light extinction of about 2 Mm-1 at Caney Creek and 1.8 
Mm-1 at Upper Buffalo on the 20% worst days. As discussed 
elsewhere, Entergy Arkansas submitted additional CAMx modeling with 
their comments. This photochemical modeling projects a 2.95 
Mm-1 reduction at Caney Creek and 1.54 Mm-1 
reduction at Upper Buffalo when compared to the Entergy's base case 
modeling for 2018 for the 20% worst days.\358\
---------------------------------------------------------------------------

    \357\ See 81 FR 296, 335 and the FIP TSD (document ID: EPA-R06-
OAR-2014-0754-0007).
    \358\ See Entergy CAMx Results 2015-1124_FINAL.xls.
---------------------------------------------------------------------------

    Comment: Even the negligible changes in visibility represented by 
EPA's proposed revised RPGs are greatly overstated because the bulk of 
the EPA-projected visibility improvements are due to proposed 
SO2 emission limits for BART and reasonable progress that 
have a five-year compliance deadline and thus will not become operative 
until at least 2020. No sound basis exists for the projections of 
visibility improvements by 2018 that EPA sets out in the proposed rule. 
Those EPA projections are inaccurate and unsupportable.
    In this regard, EPA fails to explain why (a) the Agency may 
permissibly use a concededly oversimplified and inaccurate shortcut 
methodology for calculating RPGs in its FIP, on the grounds that EPA 
otherwise would have to conduct time-consuming and complicated 
modeling, see id., but (b) Arkansas and other states apparently are 
held to a much higher standard for their RPG analyses, see id. In 
proposing and promulgating a FIP for Arkansas, EPA merely stands in the 
state's shoes. Accordingly, if EPA may lawfully comply with the CAA and 
the regional haze rules by conducting and relying on this sort of 
analysis that is ``not refined'' but (purportedly) sufficient to 
support its FIP's RPGs, then states also may do so to support their 
SIPs' RPGs. On the other hand, to the extent EPA does not believe that 
RPGs based on such an abbreviated analysis would be approvable if 
submitted by a state in a SIP, EPA cannot lawfully promulgate the RPGs 
that it proposes based on the analysis presented in its proposed rule.
    Response: We proposed RPGs for the 20% worst days for Caney Creek 
and Upper Buffalo of 22.27 dv and 22.33 dv, respectively that reflected 
the anticipated visibility conditions resulting from the combination of 
control measures from the approved portion of the 2008 Arkansas 
Regional Haze SIP and our FIP proposal. After considering these 
comments, we agree that the RPGs should reflect anticipated visibility 
conditions at the end of the implementation period in 2018 rather than 
the anticipated visibility conditions once the FIP has been fully 
implemented. This approach is consistent with the purpose of RPGs and 
the direction provided in our 2007 Reasonable Progress Guidance.
    Section 169B(e)(1) of the CAA directed the Administrator to 
promulgate regulations that ``include[e] criteria for measuring 
`reasonable progress' toward the national goal.'' Consequently, we 
promulgated 40 CFR 51.308(d)(1) as part of the Regional Haze Rule. This 
provision directs states to develop RPGs for the most and least 
impaired days to ``measure'' the progress that will be achieved by the 
control measures in the state's long-term strategy ``over the period of 
the implementation plan.'' \359\ The current implementation period ends 
in 2018. RPGs ``are not directly enforceable'' like the emission 
limitations in the long-term strategy.\360\ Rather, they fulfill two 
key purposes: (1) Allowing for comparisons between the progress that 
will be achieved by the state's long-term strategy and the URP,\361\ 
and (2) providing a benchmark for assessing the adequacy of a state's 
SIP in 5-year periodic reports.\362\ Consequently, in our 2007 
Reasonable Progress Guidance, we indicated that states could consider 
the ``time necessary for compliance'' factor by ``adjust[ing] the RPG 
to reflect the degree of improvement in visibility achievable within 
the period of the first SIP if the time needed for full implementation 
of a control measure (or measures) will extend beyond 2018.'' \363\ In 
other words, RPGs need not reflect the visibility improvement 
anticipated from all of the control measures deemed necessary to make 
reasonable progress (as a result of the four-factor analysis) and 
included in the long-term strategy.
---------------------------------------------------------------------------

    \359\ 40 CFR 51.308(d)(1).
    \360\ 40 CFR 51.308(d)(1)(iv).
    \361\ 40 CFR 51.308(d)(1)(ii).
    \362\ 40 CFR 51.308(g)-(h).
    \363\ ``Guidance for Setting Reasonable Progress Goals Under the 
Regional Haze Program,'' at 5-2.
---------------------------------------------------------------------------

    In this instance, we are taking final action on the Arkansas 
Regional Haze FIP 9 years after the state's initial SIP submission was 
due.\364\ As a result, only some of the control measures that we have 
determined are necessary to satisfy the BART and reasonable progress 
requirements will be installed by the end of 2018. Some controls will 
not be installed until 2021. Because RPGs are unenforceable analytical 
benchmarks, we think that it is appropriate to follow the 
recommendation in our 2007 Reasonable Progress Guidance and finalize 
RPGs that represent the visibility conditions anticipated on the 20% 
worst days at Caney Creek and Upper Buffalo by 2018. These RPGs are 
listed in the table below: \365\
---------------------------------------------------------------------------

    \364\ We discuss in section II.A of this final rule the history 
of the state's submittals and our actions.
    \365\ These RPGs are calculated using the same methodology 
described in our proposal and TSD. See ``CACR UPBU RPG analysis 
2018.xlsx'' for additional information on the calculation of the 
RPGs.

 Table 21--Reasonable Progress Goals for 2018 for Caney Creek and Upper
                                 Buffalo
------------------------------------------------------------------------
                                                           2018 RPG  20%
                      Class I area                          Worst days
                                                               (dv)
------------------------------------------------------------------------
Caney Creek.............................................           22.47
Upper Buffalo...........................................           22.51
------------------------------------------------------------------------

    We disagree with the commenter that the proposed RPGs overstated 
the visibility benefit of controls or that they are inaccurate. In our 
proposal, we acknowledged that the methodology we utilized to estimate 
the RPGs is not as refined as developing an updated model projection. 
However, it allows us to translate the emission reductions contained in 
the proposed FIP into quantitative RPGs, based on modeling previously 
performed by the CENRAP.\366\ The proposed RPGs provided an estimate of 
the visibility benefit of all the required controls compared to the 
2018 visibility conditions projected by the state and established in 
their SIP that would result without the required controls. Our final 
RPGs, calculated using the same methodology, reflect the anticipated 
visibility conditions at the end of the implementation period in 2018 
and the visibility benefit from those controls required to be 
implemented by the end of 2018. RPGs, unlike the emission limits that 
apply to specific reasonable progress and BART sources, are not 
directly enforceable.\367\ Rather, the RPGs are an analytical framework 
considered by us in evaluating whether measures in the implementation 
plan are sufficient to achieve reasonable progress.\368\ Our FIP 
imposes emissions limitations that we conclude to be necessary under 
the CAA for the first planning period. Ideally, these controls would be 
installed and the emission limitations achieved, so

[[Page 66411]]

the visibility improvements can be realized and built on in a 
subsequent comprehensive periodic SIP revision (see 40 CFR 51.308(f)). 
Arkansas may choose to use these RPGs for purposes of its progress 
report (along with a consideration for what controls had already been 
implemented and what controls would be implemented in the near future), 
or may develop new RPGs for approval by us along with its progress 
report, based on new modeling or other appropriate techniques, in 
accordance with the requirements of 40 CFR 51.308(d)(1) in evaluating 
the adequacy of their SIP (or this FIP) to meet the established RPGs.
---------------------------------------------------------------------------

    \366\ 80 FR 18944, 18998.
    \367\ 40 CFR 51.308(d)(1)(v).
    \368\ 64 FR at 35733 and 40 CFR 51.308(d)(1)(v).
---------------------------------------------------------------------------

    We disagree that Arkansas would be held to a higher standard or 
that the methodology utilized by EPA to adjust the RPGs would not be 
approvable if submitted by a state. The approach followed by EPA in 
this action, using scaling to adjust the modeled RPGs based on 
photochemical source apportionment model results is reasonable and 
meets the requirements of the Regional Haze Rule. In our 2012 
rulemaking,\369\ we made a finding that Arkansas did not complete a 
reasonable progress analysis and therefore did not properly demonstrate 
that additional controls were not reasonable under 40 CFR 
51.308(d)(1)(i)(A). Thus we disapproved the RPGs Arkansas established 
for Caney Creek and Upper Buffalo. In our proposed rulemaking, we 
completed the reasonable progress analysis and established revised RPGs 
using the methodology described above, since we have not received a 
revised SIP to correct the portions of the SIP submittal we 
disapproved.
---------------------------------------------------------------------------

    \369\ 77 FR 14604.
---------------------------------------------------------------------------

9. Additional Modeling Comments
    Comment: We received additional specific modeling comments 
concerning emission rates modeled to assess baseline visibility impacts 
for Independence, White Bluff and Flint Creek. We also received 
separate comments concerning our modeling analysis and assessment of 
NOX controls on Lake Catherine, White Bluff and 
Independence.
    Response: We address these comments in our RTC document.

K. Legal

    We received several comments on EPA's legal authority to promulgate 
a FIP under the Regional Haze Rule, and, more specifically, to address 
the Rule's reasonable progress requirements. Below is a summary of some 
of the more significant comments. For a more detailed explanation, 
please refer to the RTC document that is a part of the docket for this 
rulemaking.
    We received comments that EPA is prohibited from requiring controls 
for this planning period if they cannot be installed during this 
planning period. We disagree with these comments. The CAA establishes 
our authority and responsibility to promulgate a FIP that addresses the 
requirements of the regional haze program where a State's SIP 
submission fails to meet the program requirements. Although the first 
planning period, ending in 2018, includes RPGs specific to that 
planning period, there is no limitation in the CAA or the Regional Haze 
Rule that controls contained in a SIP (or a FIP) must be fully 
implemented by the end of the planning period. As both the long-term 
strategy and BART requirements may extend beyond the first planning 
period, it follows that EPA has FIP authority to fill in ``gaps'' or 
``inadequacies'' related to those components irrespective of whether 
controls can be put into place by 2018. In addition, any emission 
limitations that prove to be required by the CAA for the first planning 
period need to be achieved at their soonest opportunity, not delayed, 
deferred, or avoided for later planning periods when even further 
progress may be required in order to achieve the national visibility 
goal.
    We also received comments that we had no legal basis for requiring 
alternative proposals for SO2 and NOX control 
measures that would address the regional haze requirements for White 
Bluff Units 1 and 2 and Independence Units 1 and 2 for this planning 
period to achieve greater reasonable progress than the BART and 
reasonable progress requirements that EPA has proposed for the first 
planning period. Our response explains our analysis of Entergy's four-
unit approach and clarifies how our evaluation of that approach was 
consistent with the Regional Haze Rule's BART alternative and 
reasonable progress requirements.
    In addition, we received several comments that our proposed FIP was 
not in keeping with the legal requirements for reasonable progress and 
long term strategy as spelled out in the Regional Haze Rule and EPA 
Guidance. We disagree and explain in more detail in the RTC document 
that we disapproved the reasonable progress determination Arkansas 
submitted in 2012 because the State did not conduct the required four-
factor analysis. The CAA requires us to stand in the State's shoes and 
promulgate a FIP that addresses the requirements of the Regional Haze 
Rule that we disapproved, including reasonable progress and the long 
term strategy for Arkansas' Class I areas.
    We also received comments that our proposed FIP did not take into 
account the leading role of the state in developing a plan that 
addresses the regional haze program and thus is not in keeping with 
cooperative federalism. We disagree that EPA ignored the principles of 
cooperative federalism. Arkansas did develop a regional haze plan. We 
reviewed it and partially approved and disapproved the plan in 2012. 
The CAA creates a mandatory duty for EPA to either approve a state SIP 
revision submittal that corrects the deficiency or promulgate a FIP 
within two years of the effective date of the disapproval of a state 
plan.
    We received comments that EPA does not have authority to finalize a 
FIP after two years have elapsed from our initial disapproval of the 
Arkansas Regional Haze SIP. We describe in more detail in the RTC 
document our disagreement with this interpretation of what is required 
under the Clean Air Act. The Tenth Circuit has upheld EPA's authority 
to finalize a Regional Haze FIP after the two years have passed for EPA 
to act on Oklahoma's Regional Haze SIP.
    We also received comments that our proposed FIP was not in keeping 
with Executive Orders 12866 and 13211. Our response is that our 
proposed action is not subject to Executive Order 13211 because it is 
not a ``significant regulatory action'' under Executive Order 12866; 
therefore, the proposed FIP is not a rule of general applicability 
because its requirements apply and are tailored to only seven 
individually identified facilities. Thus, it is not a ``rule'' or 
``regulation'' within the meaning of E.O. 12866 and this action is not 
a ``regulatory action'' subject to 12866. Since E.O. 13211 applies only 
to ``significant regulatory actions'' under E.O. 12866, this action is 
not subject to review under E.O. 13211.\28\ Evaluation of the proposal 
under E.O. 13211's criteria is therefore not required.
    We respond in greater detail in the RTC document to comments that 
EPA did not adequately consider costs to ratepayers as is required 
under Arkansas law in developing air regulations. States are under an 
obligation to submit a Regional Haze SIP to EPA which complies with 
federal requirements. While states enjoy flexibility in developing a 
SIP and can meet additional state requirements as long as the federal 
requirements are satisfied, in the event that EPA must step in and 
create a Federal Implementation Plan, we must meet all federal 
requirements. We are not subject to state law requirements related to 
how the cost

[[Page 66412]]

analyses must be conducted or what specific factors need to be 
considered. We did consider costs in great detail to ensure that the 
controls required by the FIP are cost-effective, appropriate in light 
of the visibility reductions achieved, and consistent with expectations 
in other SIPs and FIPs.
    We received several general comments including a claim that 
documents that EPA relied for its rulemaking were not in the docket. As 
explained more fully in our RTC document, the documents referred to are 
briefing sheets and did not serve as the basis for EPA's decision 
making. The docket contains all of the documents that serve as our 
basis for our rulemaking for Arkansas Regional Haze.

L. Interstate Visibility Transport

    Comment: The good neighbor visibility provision in 42 U.S.C. 
7410(a)(2)(D)(i)(II) prohibits interference with ``measures'' required 
to be included in another State's implementation plan to protect 
visibility. EPA has not demonstrated that any of these sources in its 
FIP proposal are interfering with any visibility control measure in any 
other state's SIP. In its FIP proposal, EPA states that the Arkansas 
SIP did not ensure that emissions from Arkansas sources ``do not 
interfere with other states' visibility programs as required by section 
110(a)(2)(D)(i)(II) of the CAA.'' \370\ The visibility protection 
requirement of section 110(a)(2)(D)(i)(II) does not protect against 
interference with either other states ``efforts'' or other states 
``programs.'' Unlike the language in section 110(a)(2)(D)(i)(I), which 
prohibits emissions that contribute significantly to nonattainment or 
maintenance of a NAAQS in another state, the visibility protection 
requirement is narrower and only protects against interference with 
specific measures, that is, actions included in another state's plan to 
achieve a visibility goal. Reasonable progress goals, projected 
deciview improvements from regional efforts, and the like are goals or 
standards; they are not ``measures'' taken by or enforced by a state. 
There is nothing in the record demonstrating that any of the sources in 
the FIP proposal interfere with any measure included in any other 
state's SIP for the purpose of protecting or improving visibility. To 
the extent that EPA's proposed interstate visibility transport FIP is 
not based on direct interference with a control measure in another 
state's regional haze SIP (in contrast to interference with a regional 
haze related visibility goal), EPA's interpretation is contrary to the 
clear and express language of Section 110. EPA's interpretation also is 
contrary to the CAA's clear direction that each state is to determine 
its own emission limits, schedules of compliance and other measures for 
sources in that state for purposes of visibility protection under 
section 169A. EPA's interpretation would impermissibly give one state 
the power to control another state's regional haze SIP decisions, 
including its BART and reasonable progress determinations. Finally, 
even if the CAA's good neighbor visibility provision required a SIP to 
contain emission limits for sources that contribute to visibility 
impairment at a Class I area in another state, EPA has not demonstrated 
that any of the controls in its FIP proposal are ``necessary'' for that 
purpose, considering based on the uncertainty in the modeling that 
these controls will result in actual visibility improvements.
---------------------------------------------------------------------------

    \370\ 80 FR at 18998.
---------------------------------------------------------------------------

    Response: Section 110(a)(2)(D)(i)(II) does not explicitly define 
what is required in SIPs to prevent the prohibited impact on visibility 
in other states nor does it explicitly define how to determine if a 
state's emissions are interfering with another state's measures to 
protect visibility. We have interpreted this statutory requirement as 
providing that a Regional Haze SIP that requires emission reductions 
consistent with the assumptions the relevant RPO used to model the RPGs 
for Class I areas in other states satisfies a state's obligation to 
ensure that its own emissions do not interfere with another state's 
visibility measures. States may rely on a fully approved Regional Haze 
SIP to demonstrate that a SIP for 8-hour ozone or PM2.5 
contains adequate provisions to prohibit emissions that interfere with 
visibility measures in other states.\371\
---------------------------------------------------------------------------

    \371\ See ``2006 Guidance for SIP Submissions to Meet Current 
Outstanding Obligations Under Section 110(a)(2)(D)(i) for the 8-Hour 
Ozone and PM2.5 NAAQS'' at pages 9-10.
---------------------------------------------------------------------------

    Arkansas chose to address the interstate visibility transport 
requirement under section 110(a)(2)(D)(i)(II) by relying on its 2008 
Regional Haze SIP submittal to achieve the emissions reductions 
necessary to meet this requirement. However, due to our previous 
partial disapproval of this submittal,\372\ the Arkansas SIP does not 
currently include all of the emission reductions Arkansas agreed to 
achieve in its RPO process. Arkansas is a member state of CENRAP, the 
regional planning committee on regional haze. Each CENRAP state based 
its regional haze plan and RPGs on the CENRAP modeling, which was based 
in part on the emissions reductions each state intended to achieve by 
2018. Within the CENRAP process, Arkansas promised to achieve emission 
reductions corresponding to BART, and these emissions reductions were 
included in the CENRAP modeling used by the participating states to 
develop their RPGs and Regional Haze SIPs. However, EPA previously 
disapproved some of Arkansas' BART determinations; therefore, the 
State's SIP does not currently provide for all the emissions reductions 
that Arkansas itself determined to be necessary to meet the interstate 
visibility transport requirement. Because Arkansas has not provided any 
other analysis or explanation of how the Arkansas SIP fulfills the 
requirement of 110(a)(2)(D)(i)(II), it follows that the Arkansas SIP 
does not contain adequate provisions to prohibit emissions that would 
interfere with other states' visibility protection measures.
---------------------------------------------------------------------------

    \372\ 77 FR 14604.
---------------------------------------------------------------------------

    We disagree with the commenter's contention that our interpretation 
is contrary to the CAA because the Act gives clear direction that each 
state is to determine its own emission limits, schedules of compliance 
and other measures for sources in that state for purposes of visibility 
protection under section 169A. The commenter states that our 
interpretation would impermissibly give one state the power to control 
another state's regional haze SIP decisions. However, the commenter's 
interpretation is inconsistent with section 110(a)(2)(D)(i)(II)'s 
``good neighbor'' provision, which requires states to prohibit 
emissions that interfere with other states' measures to protect 
visibility. This statutory requirement anticipates that a state may be 
required to adjust its own emissions based on the impacts of those 
emissions on other states. Our Regional Haze Rule, which was 
promulgated through notice-and-comment rulemaking in 1999, also 
requires that states develop ``coordinated emission management 
strategies'' when necessary to prevent interstate visibility 
impairment.\373\ Thus, while the CAA and our regulations do not allow 
one state to ``control'' another's regional haze planning, they do 
contemplate that a state may be required to prohibit emissions that 
interfere with visibility in another state's Class I areas.
---------------------------------------------------------------------------

    \373\ 40 CFR 51.308(d)(3)(i).
---------------------------------------------------------------------------

    As stated above, Arkansas elected to address the interstate 
visibility transport requirement under section 110(a)(2)(D)(i)(II) by 
relying on the BART determinations that are part of its

[[Page 66413]]

Regional Haze SIP submittal. Arkansas could have elected to address the 
interstate visibility transport requirement under section 
110(a)(2)(D)(i)(II) by other means; we have elsewhere determined that 
states may also be able to satisfy the requirements of CAA section 
110(a)(2)(D)(i)(II) with something less than an approved Regional Haze 
SIP.\374\ In other words, an approved Regional Haze SIP is not the only 
possible means to satisfy the requirements of CAA section 
110(a)(2)(D)(i)(II) with respect to visibility; however such a SIP 
could be sufficient.\375\ The approved portion of the Arkansas Regional 
Haze SIP and our Regional Haze FIP together will ensure emissions 
reductions from Arkansas sources consistent with the assumptions used 
in the CENRAP modeling and meets Arkansas' obligations to address the 
interstate visibility transport requirement under section 
110(a)(2)(D)(i)(II).
---------------------------------------------------------------------------

    \374\ See, e.g., Colorado (76 FR 22036 (April 20, 2011)), Idaho 
(76 FR 36329 (June 22, 2011)), and New Mexico (76 FR 52388 (August, 
22, 2011)).
    \375\ We've allowed states to rely on their approved regional 
haze plan to meet the requirements of the visibility component of 
110(a)(2)(D)(i)(II) because the regional haze plan achieved at least 
as much emissions reductions as projected by the RPO modeling. See 
76 FR 34608, June 14, 2011 (California); 79 FR 60985, October 9, 
2014 (New Mexico); 76 FR 36329, June 22, 2011 (Idaho); and 76 FR 
38997, July 5, 2011 (Oregon).
---------------------------------------------------------------------------

    We address elsewhere in this document comments contending that 
there is uncertainty in the CALPUFF modeling and uncertainty that our 
proposed controls will result in actual visibility improvements.

VI. Final Action

    We are finalizing a FIP to remedy the deficiencies in the Arkansas 
Regional Haze SIP and Interstate Visibility Transport SIP to address 
the visibility transport requirement under section 110(a)(2)(D)(i)(II) 
for the 1997 8-hour ozone and PM2.5 NAAQS.

A. Regional Haze

    Our final FIP includes SO2, NOX, and PM 
emission limits for specific emission units in Arkansas to address the 
BART requirements. The affected emission units are the AECC Bailey Unit 
1; AECC McClellan Unit 1; AEP Flint Creek Unit 1; Entergy White Bluff 
Units 1, 2, and Auxiliary Boiler; Entergy Lake Catherine Unit 4; and 
Domtar Ashdown Mill Power Boilers No. 1 and 2. In addition, we are 
requiring SO2 and NOX controls under reasonable 
progress for Entergy Independence Units 1 and 2. We are also finalizing 
compliance schedules and testing, reporting and recordkeeping 
requirements for these emission units. Our final FIP requires the 
following emission limits for these emission units:

                                      Table 22--Final BART Emission Limits
----------------------------------------------------------------------------------------------------------------
                                          Final SO2 emission       Final NOX emission
                 Unit                           limit                    limit           Final PM emission limit
----------------------------------------------------------------------------------------------------------------
Bailey Unit 1........................  0.5% limit on sulfur     887 lb/hr..............  0.5% limit on sulfur
                                        content of fuel                                   content of fuel
                                        combusted.                                        combusted.
McClellan Unit 1.....................  0.5% limit on sulfur     869.1 lb/hr \a\/705.8    0.5% limit on sulfur
                                        content of fuel          lb/hr \a\.               content of fuel
                                        combusted.                                        combusted.
Flint Creek Unit 1...................  0.06 lb/MMBtu..........  0.23 lb/MMBtu..........  EPA approved the
                                                                                          state's BART
                                                                                          determination in March
                                                                                          12, 2012 final action
                                                                                          (77 FR 14604).
White Bluff Unit 1...................  0.06 lb/MMBtu..........  0.15 lb/MMBtu \b\/671    EPA approved the
                                                                 lb/hr \c\.               state's BART
                                                                                          determination in March
                                                                                          12, 2012 final action
                                                                                          (77 FR 14604).
White Bluff Unit 2...................  0.06 lb/MMBtu..........  0.15 lb/MMBtu \b\/671    EPA approved the
                                                                 lb/hr \c\.               state's BART
                                                                                          determination in March
                                                                                          12, 2012 final action
                                                                                          (77 FR 14604).
White Bluff Auxiliary Boiler.........  105.2 lb/hr............  32.2 lb/hr.............  4.5 lb/hr.
Lake Catherine Unit 4 \d\............  EPA approved the         0.22 lb/MMBtu..........  EPA approved the
                                        state's BART                                      state's BART
                                        determination in March                            determination in March
                                        12, 2012 final action                             12, 2012 final action
                                        (77 FR 14604).                                    (77 FR 14604).
Domtar Ashdown Mill Power Boiler No.   504 lb/day.............  207.4 lb/hr............  EPA approved the
 1.                                                                                       state's BART
                                                                                          determination in March
                                                                                          12, 2012 final action
                                                                                          (77 FR 14604).
Domtar Ashdown Mill Power Boiler No.   91.5 lb/hr.............  345 lb/hr..............  PM BART shall be
 2.                                                                                       satisfied by relying
                                                                                          on the applicable PM
                                                                                          standard under 40 CFR
                                                                                          part 63, subpart DDDDD
                                                                                          \e\
----------------------------------------------------------------------------------------------------------------
\a\ Emission limit of 869.1 lb/hr applies to the natural gas-firing scenario; emission limit of 705.8 lb/hr
  applies to the fuel oil-firing scenario.
\b\ Emission limit of 0.15 lb/MMBtu applies when unit is operated at 50% or greater of the unit's maximum heat
  input rating.
\c\ Emission limit of 671 lb/hr applies when the unit is operated at less than 50% of the unit's maximum heat
  input rating.
\d\ Emission limit for NOX applies to the natural gas-firing scenario. The unit shall not burn fuel oil until
  BART determinations for SO2, NOX, and PM are promulgated for the unit for the fuel oil-firing scenario through
  EPA approval of a SIP revision or a FIP.
\e\ The facility shall rely on the applicable PM standard under 40 CFR part 63, subpart DDDDD--National Emission
  Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers
  and Process Heaters, as revised, to satisfy the PM BART requirement.

   Table 23--Final Reasonable Progress Emission Limits for Sources not
                             Subject to BART
------------------------------------------------------------------------
                                  Final SO2 emission  Final NOX emission
              Unit                       limit               limit
------------------------------------------------------------------------
Independence Unit 1.............  0.06 lb/MMBtu.....  0.15 lb/MMBtu a/
                                                       671 lb/hr b

[[Page 66414]]

 
Independence Unit 2.............  0.06 lb/MMBtu.....  0.15 lb/MMBtu a/
                                                       671 lb/hr b
------------------------------------------------------------------------
a Emission limit of 0.15 lb/MMBtu applies when unit is operated at 50%
  or greater of the unit's maximum heat input rating.
b Emission limit of 671 lb/hr applies when the unit is operated at less
  than 50% of the unit's maximum heat input rating.

    Based on our technical analysis, we have calculated the following 
RPGs for the 20% worst days for Arkansas' Class I areas:

 Table 24--Reasonable Progress Goals for 2018 for Caney Creek and Upper
                                 Buffalo
------------------------------------------------------------------------
                                                           2018 RPG 20%
                      Class I area                          Worst days
                                                               (dv)
------------------------------------------------------------------------
Caney Creek.............................................           22.47
Upper Buffalo...........................................           22.51
------------------------------------------------------------------------

B. Interstate Visibility Transport

    We are finalizing our determination that the control measures in 
the approved portion of the Arkansas Regional Haze SIP and our final 
FIP are sufficient to prevent Arkansas' emissions from interfering with 
other states' required measures to protect visibility. Thus, the 
combined measures from both plans satisfy the interstate transport 
visibility requirement of CAA section 110(a)(2)(D)(i)(II) for the 1997 
8-hour ozone and the 1997 PM2.5 NAAQS.

VII. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review and Executive 
Order 13563: Improving Regulation and Regulatory Review

    This action is exempt from review by the Office of Management and 
Budget (OMB) because it imposes requirements that apply and are 
tailored to only six individual power plants (AECC Bailey; AECC 
McClellan; AEP Flint Creek; Entergy White Bluff; Entergy Lake 
Catherine; and Entergy Independence) and one paper mill in Arkansas 
(Domtar Ashdown Paper Mill). This FIP is not a rule of general 
applicability. Thus, it is not a ``rule'' or ``regulation'' within the 
meaning of E.O. 12866, and this action is not a ``regulatory action'' 
subject to 12866.

B. Paperwork Reduction Act (PRA)

    This action does not impose an information collection burden under 
the provisions of the PRA, 44 U.S.C. 3501 et seq. Under the PRA, a 
``collection of information'' is defined as a requirement for ``answers 
to * * * identical reporting or recordkeeping requirements imposed on 
ten or more persons * * *'' 44 U.S.C. 3502(3)(A). Because the FIP 
applies to only seven facilities, the Paperwork Reduction Act does not 
apply. See 5 CFR 1320.3(c).

C. Regulatory Flexibility Act (RFA)

    I certify that this action will not have a significant economic 
impact on a substantial number of small entities under the RFA. This 
action will not impose any requirements on small entities. This FIP 
will apply to seven facilities, none of which fall under the definition 
of small entities.

D. Unfunded Mandates Reform Act (UMRA)

    EPA has determined that Title II of the UMRA does not apply to this 
rule. In 2 U.S.C. 1502(1) all terms in Title II of UMRA have the 
meanings set forth in 2 U.S.C. 658, which further provides that the 
terms ``regulation'' and ``rule'' have the meanings set forth in 5 
U.S.C. 601(2). Under 5 U.S.C. 601(2), ``the term `rule' does not 
include a rule of particular applicability relating to . . . 
facilities.'' Because this rule is a rule of particular applicability 
relating to seven named facilities, EPA has determined that it is not a 
``rule'' for the purposes of Title II of the UMRA.

E. Executive Order 13132: Federalism

    This action does not have Federalism implications. It will not have 
substantial direct effects on the states, on the relationship between 
the national government and the states, or on the distribution of power 
and responsibilities among the various levels of government. The final 
rule does not impose significant economic costs on state or local 
governments. Thus, Executive Order 13132 does not apply to the final 
rule.

F. Executive Order 13175: Coordination With Indian Tribal Governments

    This action does not have tribal implications as specified in 
Executive Order 13175. This action applies to seven facilities in 
Arkansas and to Federal Class I areas in Arkansas. This action does not 
apply on any Indian reservation land, any other area where EPA or an 
Indian tribe has demonstrated that a tribe has jurisdiction, or non-
reservation areas of Indian country. Thus, Executive Order 13175 does 
not apply to this action.

G. Executive Order 13045: Protection of Children From Environmental 
Health Risks and Safety Risks

    The EPA interprets Executive Order 13045 as applying only to those 
regulatory actions that concern environmental health or safety risks 
that the EPA has reason to believe may disproportionately affect 
children, per the definition of ``covered regulatory action'' in 
section 2-202 of the Executive Order. This action is not subject to 
Executive Order 13045 because it implements specific standards 
established by Congress in statutes.

H. Executive Order 13211: Actions That Significantly Affect Energy 
Supply, Distribution or Use

    This action is not subject to Executive Order 13211 because it is 
not a significant regulatory action under Executive Order 12866.

I. National Technology Transfer and Advancement Act

    This action involves technical standards. Section 12(d) of the 
National Technology Transfer and Advancement Act of 1995 (``NTTAA''), 
Public Law 104-113, 12(d) (15 U.S.C. 272 note) directs EPA to use 
voluntary consensus standards in its regulatory activities unless to do 
so would be inconsistent with applicable law or otherwise impractical. 
Voluntary consensus standards are technical standards (e.g., materials 
specifications, test methods, sampling procedures, and business 
practices) that are developed or adopted by voluntary consensus 
standards bodies. NTTAA directs EPA to provide Congress, through OMB, 
explanations when the Agency decides not to use available and 
applicable voluntary consensus standards. This rule would require the 
seven affected facilities to meet the applicable monitoring 
requirements of 40 CFR part 75. Part 75 already incorporates a number 
of voluntary consensus standards. Consistent with the Agency's 
Performance Based Measurement System (PBMS), part 75 sets forth 
performance criteria that allow the use of alternative methods to the 
ones set

[[Page 66415]]

forth in part 75. The PBMS approach is intended to be more flexible and 
cost-effective for the regulated community; it is also intended to 
encourage innovation in analytical technology and improved data 
quality. At this time, EPA is not recommending any revisions to part 
75; however, EPA periodically revises the test procedures set forth in 
part 75. When EPA revises the test procedures set forth in part 75 in 
the future, EPA will address the use of any new voluntary consensus 
standards that are equivalent. Currently, even if a test procedure is 
not set forth in part 75, EPA is not precluding the use of any method, 
whether it constitutes a voluntary consensus standard or not, as long 
as it meets the performance criteria specified; however, any 
alternative methods must be approved through the petition process under 
40 CFR 75.66 before they are used.

J. Executive Order 12898: Federal Actions To Address Environmental 
Justice in Minority Populations and Low-Income Populations

    The EPA believes the human health or environmental risk addressed 
by this action will not have potential disproportionately high and 
adverse human health or environmental effects on minority, low-income, 
or indigenous populations because it increases the level of 
environmental protection for all affected populations without having 
any disproportionately high and adverse human health or environmental 
effects on any population, including any minority or low-income 
population. This FIP limits emissions of SO2, 
NOX, and PM from seven facilities in Arkansas.

K. Congressional Review Act

    The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the 
Small Business Regulatory Enforcement Fairness Act of 1996, generally 
provides that before a rule may take effect, the agency promulgating 
the rule must submit a rule report, which includes a copy of the rule, 
to each House of the Congress and to the Comptroller General of the 
United States. EPA will submit a report containing this action and 
other required information to the U.S. Senate, the U.S. House of 
Representatives, and the Comptroller General of the United States prior 
to publication of the rule in the Federal Register. A major rule cannot 
take effect until 60 days after it is published in the Federal 
Register. This action is not a ``major rule'' as defined by 5 U.S.C. 
804(2). This rule will be effective on October 27, 2016.

L. Judicial Review

    Under section 307(b)(1) of the Clean Air Act, petitions for 
judicial review of this action must be filed in the United States Court 
of Appeals for the appropriate circuit by November 28, 2016. Filing a 
petition for reconsideration by the Administrator of this final rule 
does not affect the finality of this action for the purposes of 
judicial review nor does it extend the time within which a petition for 
judicial review may be filed, and shall not postpone the effectiveness 
of such rule or action. This action may not be challenged later in 
proceedings to enforce its requirements. (See CAA section 307(b)(2).)

List of Subjects in 40 CFR Part 52

    Environmental protection, Air pollution control, Incorporation by 
reference, Nitrogen dioxide, Ozone, Particulate matter, Reporting and 
recordkeeping requirements, Sulfur dioxides, Visibility, Interstate 
transport of pollution, regional haze, Best available retrofit 
technology.

    Dated: August 31, 2016.
Gina McCarthy,
Administrator.
    Title 40, chapter I, of the Code of Federal Regulations is 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 adding paragraphs (c) and (d) to read 
as follows:

Sec.  52.173  Visibility protection.

* * * * *
    (c) Federal implementation plan for regional haze. Requirements for 
AECC Carl E. Bailey Unit 1; AECC John L. McClellan Unit 1; AEP Flint 
Creek Unit 1; Entergy White Bluff Units 1, 2, and Auxiliary Boiler; 
Entergy Lake Catherine Unit 4; Domtar Ashdown Paper Mill Power Boilers 
No. 1 and 2; and Entergy Independence Units 1 and 2 affecting 
visibility.
    (1) Applicability. The provisions of this section shall apply to 
each owner or operator, or successive owners or operators, of the 
sources designated as: AECC Carl E. Bailey Unit 1; AECC John L. 
McClellan Unit 1; AEP Flint Creek Unit 1; Entergy White Bluff Units 1, 
2, and Auxiliary Boiler; Entergy Lake Catherine Unit 4; Domtar Ashdown 
Paper Mill Power Boilers No. 1 and 2; and Entergy Independence Units 1 
and 2.
    (2) Definitions. All terms used in this part but not defined herein 
shall have the meaning given them in the Clean Air Act and in parts 51 
and 60 of this title. For the purposes of this section:
    24-hour period means the period of time between 12:01 a.m. and 12 
midnight.
    Air pollution control equipment includes selective catalytic 
control units, baghouses, particulate or gaseous scrubbers, and any 
other apparatus utilized to control emissions of regulated air 
contaminants which would be emitted to the atmosphere.
    Boiler-operating-day for electric generating units listed under 
paragraph (c)(1) of this section means any 24-hour period between 12 
midnight and the following midnight during which any fuel is combusted 
at any time at the steam generating unit, unless otherwise specified. 
For power boilers listed under paragraph (c)(1) of this section, we 
define boiler-operating-day as a 24-hr period between 6 a.m. and 6 a.m. 
the following day during which any fuel is fed into and/or combusted at 
any time in the power boiler.
    Daily average means the arithmetic average of the hourly values 
measured in a 24-hour period.
    Heat input means heat derived from combustion of fuel in a unit and 
does not include the heat input from preheated combustion air, 
recirculated flue gases, or exhaust gases from other sources. Heat 
input shall be calculated in accordance with 40 CFR part 75.
    Owner or Operator means any person who owns, leases, operates, 
controls, or supervises any of the units or power boilers listed under 
paragraph (c)(1) of this section.
    Regional Administrator means the Regional Administrator of EPA 
Region 6 or his/her authorized representative.
    Unit means one of the natural gas, fuel oil, or coal fired boilers 
covered under paragraph (c) of this section.
    (3) Emissions limitations for AECC Bailey Unit 1 and AECC McClellan 
Unit 1. The individual SO2, NOX, and PM emission 
limits for each unit are as listed in the following table.

[[Page 66416]]

----------------------------------------------------------------------------------------------------------------
                 Unit                     SO2 Emission limit       NOX Emission limit       PM Emission limit
----------------------------------------------------------------------------------------------------------------
AECC Bailey Unit 1...................  Use of fuel with a       887 lb/hr..............  Use of fuel with a
                                        sulfur content limit                              sulfur content limit
                                        of 0.5% by weight..                               of 0.5% by weight.
AECC McClellan Unit 1................  Use of fuel with a       869.1 lb/hr............  Use of fuel with a
                                        sulfur content limit    (Natural Gas firing)...   sulfur content limit
                                        of 0.5% by weight..     705.8 lb/hr............   of 0.5% by weight.
                                                                (Fuel Oil firing)......
----------------------------------------------------------------------------------------------------------------

    (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. The owner 
or operator of each unit must comply with the NOX emission 
limits in paragraph (c)(3) of this section by October 27, 2016.
    (5) Compliance determination and reporting and recordkeeping 
requirements for AECC Bailey Unit 1 and AECC McClellan Unit--(i) 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.
    (ii) NOX. To determine compliance with the NOX emission 
limits of paragraph (c)(3) of this section, the owner or operator shall 
determine the average concentration (arithmetic average of three 
contiguous one hour periods) of NOX as measured by the CEMS 
and converted to pounds per hour using corresponding average 
(arithmetic average of three contiguous one hour periods) stack gas 
flow rates. Records of the NOX emissions rates must be 
maintained by the owner or operator and made available upon request to 
EPA and ADEQ representatives.
    (iii) The owner or operator shall continue to maintain and operate 
a CEMS for NOX on the units listed in paragraph (c)(3) 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 limits for NOX shall be 
determined by using data from a CEMS.
    (iv) Continuous emissions monitoring shall apply during all periods 
of operation of the units listed in paragraph (c)(3) 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 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 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.
    (6) Emissions limitations for AEP Flint Creek Unit 1 and Entergy 
White Bluff Units 1 and 2. The individual SO2 and 
NOX emission limits for each unit are as listed in the 
following table, as specified in pounds per million British thermal 
units (lb/MMBtu) or pounds per hour (lb/hr). The SO2 
emission limits of 0.06 lb/MMBtu and the NOX emission limits 
of 0.23 lb/MMBtu and 0.15 lb/MMBtu are on a rolling 30 boiler-
operating-day averaging period. The NOX emission limit of 
671 lb/hr is on a rolling 3-hour average.

----------------------------------------------------------------------------------------------------------------
                                                                   SO2 Emission    NOX Emission
                              Unit                                  limit (lb/      limit (lb/     NOX Emission
                                                                      MMBtu)          MMBtu)       limit (lb/hr)
----------------------------------------------------------------------------------------------------------------
AEP Flint Creek Unit 1..........................................            0.06            0.23  ..............
Entergy White Bluff Unit 1......................................            0.06            0.15             671
Entergy White Bluff Unit 2......................................            0.06            0.15             671
----------------------------------------------------------------------------------------------------------------

    (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 and NOX emission limits 
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, and must comply with the NOX 
emission limits listed in paragraph (c) (6) of this section by April 
27, 2018.
    (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 and NOX emissions limits listed in paragraph

[[Page 66417]]

(c)(6) of this section for AEP Flint Creek Unit 1 and with the 
SO2 emissions limit 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 or pounds of 
NOX. 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 or NOX from that day and the preceding 29 
boiler-operating-days and dividing the total pounds of SO2 
or NOX 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 or NOX. If a valid SO2 or 
NOX pounds per hour or heat input is not available for any 
hour for a unit, that heat input and SO2 or NOX 
pounds per hour shall not be used in the calculation of the 30 boiler-
operating-day rolling average for SO2 or NOX. For 
each day, records of the total SO2 and NOX 
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 and 
NOX 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) For purposes of determining compliance with the 0.15 lb/MMBtu 
NOX emissions limit listed in paragraph (c)(6) of this 
section for White Bluff Units 1 and 2, the NOX emissions for 
each unit shall be determined by the following procedure:
    (A) Summing the total pounds of NOX emitted during the 
current boiler-operating-day and the preceding 29 boiler-operating-days 
while including only emissions during hours when the unit was 
dispatched at 50% or greater of the unit's maximum heat input rating;
    (B) Summing the total heat input in MMBtu to the unit during the 
current boiler-operating-day and the preceding 29 boiler-operating-days 
while including only the heat input during hours when the unit was 
dispatched at 50% or greater of the unit's maximum heat input rating; 
and
    (C) Dividing the total pounds of NOX emitted as 
calculated in step 1 by the total heat input to the unit as calculated 
in step 2. The result shall be the 30 boiler-operating-day rolling 
average in terms of lb/MMBtu emissions of NOX. If a valid 
NOX pounds per hour or heat input is not available for any 
hour for a unit, that heat input and 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 for each unit 
of the hours during which the unit was dispatched at 50% or greater of 
the unit's maximum heat input rating, as well as NOX 
emissions and hourly heat input for each of those hours 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 NOX 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.
    (iii) For purposes of determining compliance with the 671 lb/hr 
NOX emissions limit listed in paragraph (c)(6) of this 
section for White Bluff Units 1 and 2, the NOX emissions for 
each unit shall be determined by the following procedure:
    (A) Summing the total pounds of NOX emitted during the 
current hour and the preceding 2 hours during which the unit was 
dispatched at less than 50% of the unit's maximum heat input rating; 
and
    (B) Dividing the total pounds of NOX emitted as 
calculated in step 1 by 3. The result shall be the rolling 3-hour 
average in terms of lb/hr emissions of NOX. If a valid 
NOX pounds per hour is not available for any hour for a 
unit, that NOX pounds per hour shall not be used in the 
calculation of the rolling 3-hour average for NOX. For each 
day, records for each unit of the hours during which the unit was 
dispatched at less than 50% of each unit's maximum heat input rating, 
as well as NOX emissions and hourly heat input for each of 
those hours must be maintained by the owner or operator and made 
available upon request to EPA and ADEQ representatives. Records of the 
rolling 3-hour averages for NOX for each unit as described 
above must be maintained for each day by the owner or operator and made 
available upon request to EPA and ADEQ representatives.
    (iv) The owner or operator shall continue to maintain and operate a 
CEMS for SO2 and NOX 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 limits for 
SO2 and NOX shall be determined by using data 
from a CEMS.
    (v) 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 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.
    (9) Emissions limitations for Entergy White Bluff Auxiliary Boiler. 
The individual SO2, NOX, and PM emission limits 
for the unit are as listed in the following table in pounds per hour 
(lb/hr).

----------------------------------------------------------------------------------------------------------------
                                                                   SO2 Emission    NOX Emission     PM Emission
                              Unit                                 limit (lb/hr)   limit (lb/hr)   limit (lb/hr)
----------------------------------------------------------------------------------------------------------------
Entergy White Bluff Auxiliary Boiler............................           105.2            32.2             4.5
----------------------------------------------------------------------------------------------------------------

[[Page 66418]]

    (10) Compliance dates for Entergy White Bluff Auxiliary Boiler. The 
owner or operator of the unit must comply with the SO2, 
NOX, and PM emission limits listed in paragraph (c)(9) of 
this section by October 27, 2016.
    (11) Compliance determination and reporting and recordkeeping 
requirements for Entergy White Bluff Auxiliary Boiler. For purposes of 
demonstrating compliance with the emission limits listed in paragraph 
(c)(9) of this section, records of fuel oil analysis must be maintained 
by the owner or operator and made available upon request to EPA and 
ADEQ representatives.
    (12) Emissions limitations for Entergy Lake Catherine Unit 4. The 
individual NOX emission limit for the unit for natural gas 
firing is as listed in the following table in pounds per million 
British thermal units (lb/MMBtu) as averaged over a rolling 30 boiler-
operating-day period. The unit must not burn fuel oil until BART 
determinations are promulgated for the unit for SO2, 
NOX, 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.

------------------------------------------------------------------------
                                                           NOX Emission
                                                          limit--natural
                          Unit                            gas firing (lb/
                                                              MMBtu)
------------------------------------------------------------------------
Entergy Lake Catherine Unit 4...........................            0.22
------------------------------------------------------------------------

    (13) Compliance dates for Entergy Lake Catherine Unit 4. The owner 
or operator of the unit must comply with the NOX emission 
limit listed in paragraph (c)(12) of this section by October 27, 2019.
    (14) Compliance determination and reporting and recordkeeping 
requirements for Entergy Lake Catherine Unit 4. (i) NOX 
emissions for each day shall be determined by summing the hourly 
emissions measured in pounds of NOX. The 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 the unit shall 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 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 NOX. If a 
valid NOX pounds per hour or heat input is not available for 
any hour for the unit, that heat input and 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 NOX emitted that day by the 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 NOX for the 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 on the unit listed in paragraph (c)(12) of this section in 
accordance with 40 CFR part 75, Appendix E as long as the unit meets 
the definition of a peaking unit under 40 CFR part 75. The owner or 
operator shall comply with the quality assurance procedures for CEMS 
found in 40 CFR part 75.
    (iii) Continuous emissions monitoring shall apply during all 
periods of operation of the unit listed in paragraph (c)(12) of this 
section, including periods of startup, shutdown, and malfunction, 
except for CEMS breakdowns, repairs, calibration checks, and zero and 
span adjustments.
    (15) Emissions Limitations for Domtar Ashdown Paper Mill Power 
Boiler No. 1. The SO2 emission limit for the boiler is as 
listed in the following table in pounds per day (lb/day) as averaged 
over a rolling 30 boiler-operating-day period. The NOX 
emission limit for the boiler is as listed in the following table in 
pounds per hour (lb/hr).

------------------------------------------------------------------------
                                           SO2 Emission    NOX Emission
                  Unit                    limit (lb/day)   limit (lb/hr)
------------------------------------------------------------------------
Domtar Ashdown Paper Mill Power Boiler               504           207.4
 No. 1..................................
------------------------------------------------------------------------

    (16) 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)(15) of this 
section by November 28, 2016.
    (17) 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

[[Page 66419]]

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)(17)(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)(15) of this section. The compliance 
determination requirements and the reporting and recordkeeping 
requirements under paragraph (c)(17)(i) of this section would not apply 
and confirmation of the accuracy of the site-specific curve equation 
under paragraph (c)(17)(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)(15) 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)(15) 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 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)(17)(iii) 
of this section would not apply.
    (18) SO2 and NOX  Emissions Limitations for Domtar Ashdown Paper 
Mill Power Boiler No.2. The individual SO2 and 
NOX emission limits for the boiler are as listed in the 
following table in pounds per hour (lb/hr) as averaged over a rolling 
30 boiler-operating-day period.

------------------------------------------------------------------------
                                           SO2 Emission    NOX Emission
                  Unit                     Limit (lb/hr)   Limit (lb/hr)
------------------------------------------------------------------------
Domtar Ashdown Paper Mill Power Boiler              91.5             345
 No. 2..................................
------------------------------------------------------------------------

    (19) 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)(18) of this section by October 27, 2021.
    (20) 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)(18) 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)(18) 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

[[Page 66420]]

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)(18) of this section. Under these 
circumstances, the compliance determination requirements under 
paragraphs (c)(20)(i) through (iii) of this section would not apply to 
the SO2 emission limit listed in paragraph (c)(18) 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)(18) 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)(20)(i) through (iii) of 
this section would not apply to the NOX emission limit.
    (21) PM BART Requirements for Domtar Ashdown Paper Mill Power 
Boiler No.2. The owner or operator must rely on the applicable PM 
standard required under 40 CFR part 63, subpart DDDDD--National 
Emission Standards for Hazardous Air Pollutants for Major Sources: 
Industrial, Commercial, and Institutional Boilers and Process Heaters, 
as revised, to satisfy the PM BART requirement. Compliance with the 
applicable PM standard under 40 CFR part 63 subpart DDDDD, as revised, 
shall demonstrate compliance with the PM BART requirement.
    (22) 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)(21) of this section by November 28, 
2016.
    (23) Alternative PM Compliance Determination for Domtar Ashdown 
Paper Mill Power Boiler No.2. 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 PM BART requirement under paragraph (c)(21) of this section.
    (24) 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) 
or pounds per hour (lb/hr). The SO2 emission limit and the 
NOX emission limits listed in the table as lb/MMBtu are on a 
rolling 30 boiler-operating-day averaging period. The NOX 
emission limit of 671 lb/hr is on a rolling 3-hour average.

----------------------------------------------------------------------------------------------------------------
                                                                   SO2 Emission    NOX Emission
                              Unit                                  limit (lb/      limit (lb/     NOX Emission
                                                                      MMBtu)          MMBtu)       Limit (lb/hr)
----------------------------------------------------------------------------------------------------------------
Entergy Independence Unit 1.....................................            0.06            0.15             671
Entergy Independence Unit 2.....................................            0.06            0.15             671
----------------------------------------------------------------------------------------------------------------

    (25) Compliance dates for Entergy Independence Units 1 and 2. The 
owner or operator of each unit must comply with the SO2 
emission limit in paragraph (c)(24) of this section by October 27, 2021 
and with the NOX emission limits by April 27, 2018.
    (26) 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)(24) 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) For purposes of determining compliance with the 0.15 lb/MMBtu 
NOX emissions limit listed in paragraph (c)(24), the 
NOX emissions for each unit shall be determined by the 
following procedure:
    (A) Summing the total pounds of NOX emitted during the 
current boiler-operating-day and the preceding 29 boiler-operating-days 
while including only emissions during hours when the unit was 
dispatched at 50% or greater of the unit's maximum heat input rating;

[[Page 66421]]

    (B) Summing the total heat input in MMBtu to the unit during the 
current boiler-operating-day and the preceding 29 boiler operating days 
while including only the heat input during hours when the unit was 
dispatched at 50% or greater of the unit's maximum heat input rating; 
and
    (C) Dividing the total pounds of NOX emitted as 
calculated in step 1 by the total heat input to the unit as calculated 
in step 2. The result shall be the 30 boiler-operating-day rolling 
average in terms of lb/MMBtu emissions of NOX. If a valid 
NOX pounds per hour or heat input is not available for any 
hour for a unit, that heat input and 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 for each unit 
of the hours during which the unit was dispatched at 50% or greater of 
the unit's maximum heat input rating, as well as NOX 
emissions and hourly heat input for each of those hours 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 NOX 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.
    (iii) For purposes of determining compliance with the 671 lb/hr 
NOX emissions limit listed in paragraph (c)(24), the 
NOX emissions for each unit shall be determined by the 
following procedure:
    (A) Summing the total pounds of NOX emitted during the 
current hour and the preceding 2 hours during which the unit was 
dispatched at less than 50% of the unit's maximum heat input rating; 
and
    (B) Dividing the total pounds of NOX emitted as 
calculated in step 1 by 3. The result shall be the rolling 3-hour 
average in terms of lb/hr emissions of NOX. If a valid 
NOX pounds per hour is not available for any hour for a 
unit, that NOX pounds per hour shall not be used in the 
calculation of the rolling 3-hour average for NOX. For each 
day, records for each unit of the hours during which the unit was 
dispatched at less than 50% of each unit's maximum heat input rating, 
as well as NOX emissions and hourly heat input for each of 
those hours must be maintained by the owner or operator and made 
available upon request to EPA and ADEQ representatives. Records of the 
rolling 3-hour averages for NOX for each unit as described 
above must be maintained for each day by the owner or operator and made 
available upon request to EPA and ADEQ representatives.
    (iv) The owner or operator shall continue to maintain and operate a 
CEMS for SO2 and NOX on the units listed in 
paragraph (c)(24) 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 and 
NOX shall be determined by using data from a CEMS.
    (v) Continuous emissions monitoring shall apply during all periods 
of operation of the units listed in paragraph (c)(24) 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.
    (27) Reporting and recordkeeping requirements. Unless otherwise 
stated all requests, reports, submittals, notifications, and other 
communications to the Regional Administrator required under paragraph 
(c) of this section shall be submitted, unless instructed otherwise, to 
the Director, Multimedia Planning and Permitting Division, U.S. 
Environmental Protection Agency, Region 6, to the attention of Mail 
Code: 6PD, at 1445 Ross Avenue, Suite 1200, Dallas, Texas 75202-2733. 
For each unit subject to the emissions limitation under paragraph (c) 
of this section, the owner or operator shall comply with the following 
requirements, unless otherwise specified:
    (i) For each emissions limit under paragraph (c) of this section 
where compliance shall be determined by using data from a CEMS, comply 
with the notification, reporting, and recordkeeping requirements for 
CEMS compliance monitoring in 40 CFR 60.7(c) and (d).
    (ii) [Reserved]
    (28) Equipment operations. At all times, including periods of 
startup, shutdown, and malfunction, the owner or operator shall, to the 
extent practicable, maintain and operate the unit including associated 
air pollution control equipment in a manner consistent with good air 
pollution control practices for minimizing emissions. Determination of 
whether acceptable operating and maintenance procedures are being used 
will be based on information available to the Regional Administrator 
which may include, but is not limited to, monitoring results, review of 
operating and maintenance procedures, and inspection of the unit.
    (29) Enforcement. (i) Notwithstanding any other provision in this 
implementation plan, any credible evidence or information relevant as 
to whether the unit would have been in compliance with applicable 
requirements if the appropriate performance or compliance test had been 
performed, can be used to establish whether or not the owner or 
operator has violated or is in violation of any standard or applicable 
emission limit in the plan.
    (ii) Emissions in excess of the level of the applicable emission 
limit or requirement that occur due to a malfunction shall constitute a 
violation of the applicable emission limit.
    (d) Measures Addressing Partial Disapproval of Portion of 
Interstate Visibility Transport SIP for the 1997 8-hour ozone and 
PM2.5 NAAQS. The deficiencies identified in EPA's partial 
disapproval of the portion of the SIP pertaining to adequate provisions 
to prohibit emissions in Arkansas from interfering with measures 
required in another state to protect visibility, submitted on March 28, 
2008, and supplemented on September 27, 2011 are satisfied by Sec.  
52.173.
[FR Doc. 2016-22508 Filed 9-26-16; 8:45 am]
 BILLING CODE 6560-50-P