[Federal Register Volume 81, Number 187 (Tuesday, September 27, 2016)]
[Rules and Regulations]
[Pages 66331-66421]
[FR Doc No: 2016-22508]

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

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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<PHONE_NUMBER>; or
<EMAIL_ADDRESS>
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

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).

    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

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

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,

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

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.

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.

  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.

     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

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/

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

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

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

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

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

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