[Federal Register Volume 81, Number 187 (Tuesday, September 27, 2016)]
[Rules and Regulations]
[Pages 66332-66421]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2016-22508]
[[Page 66331]]
Vol. 81
Tuesday,
No. 187
September 27, 2016
Part II
Environmental Protection Agency
-----------------------------------------------------------------------
40 CFR Part 52
Promulgation of Air Quality Implementation Plans; State of Arkansas;
Regional Haze and Interstate Visibility Transport Federal
Implementation Plan; Final Rule
Federal Register / Vol. 81 , No. 187 / Tuesday, September 27, 2016 /
Rules and Regulations
[[Page 66332]]
-----------------------------------------------------------------------
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.
-----------------------------------------------------------------------
SUMMARY: The Environmental Protection Agency (EPA) is promulgating a
final Federal Implementation Plan (FIP) addressing the requirements of
the Regional Haze Rule and interstate visibility transport for the
portions of Arkansas' Regional Haze State Implementation Plan (SIP)
that EPA disapproved in a final rule published in the Federal Register
on March 12, 2012. In that action, we partially approved and partially
disapproved the State's plan to implement the regional haze program for
the first planning period. This final rule addresses the Regional Haze
Rule's requirements for Best Available Retrofit Technology (BART),
reasonable progress, and a long-term strategy (LTS), as well as the
requirements of the Clean Air Act (CAA or Act) regarding interference
with other states' programs for visibility protection (interstate
visibility transport) triggered by the issuance of the 1997 ozone
National Ambient Air Quality Standards (NAAQS) and the 1997 fine
particulate matter (PM2.5) NAAQS. The FIP includes sulfur
dioxide (SO2), nitrogen oxide (NOX), and
particulate matter (PM) emission limits for nine units located at six
facilities to address BART requirements (these limits also satisfy
reasonable progress requirements for these sources); and SO2
and NOX emission limits for two units located at one power
plant to address the reasonable progress requirements. We also provide
reasonable progress goals (RPGs) for Arkansas' Class I areas. We are
prepared to work with the State on a SIP revision that would replace
some or all elements of the FIP.
DATES: This final rule is effective on October 27, 2017.
ADDRESSES: The EPA has established a docket for this action under
Docket ID No. EPA-R06-OAR-2015-0189. All documents in the docket are
listed on the http://www.regulations.gov Web site. Publicly available
docket materials are available either electronically through http://www.regulations.gov or in hard copy at EPA Region 6, 1445 Ross Avenue,
Suite 700, Dallas, Texas 75202-2733.
FOR FURTHER INFORMATION CONTACT: Ms. Dayana Medina at 214-665-7241; or
[email protected].
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\
---------------------------------------------------------------------------
\1\ 76 FR 64186, October 17, 2011 (proposed action); and 77 FR
14604, March 12, 2012 (final action).
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\2\ 77 FR 14604.
---------------------------------------------------------------------------
We are also making a finding that the combination of the approved
portion of the Arkansas Regional Haze SIP and this FIP satisfy the
requirements of CAA section 110(a)(2)(D)(i)(II) with respect to
visibility (interstate visibility transport requirement) for the 1997
8-hour ozone and 1997 PM2.5 NAAQS. This provision of the CAA
requires that each state's SIP have adequate provisions to prohibit in-
state emissions from interfering with measures required to protect
visibility in any other state. To address this requirement, the SIP
must address the
[[Page 66333]]
potential for interference with visibility protection caused by the
pollutant (including precursors) to which the new or revised NAAQS
applies. In our March 12, 2012 final action on the Arkansas Regional
Haze SIP, we also partially approved and partially disapproved the SIP
submittal with respect to the interstate transport visibility
requirement under CAA section 110(a)(2)(D)(i)(II). This FIP fully
addresses the deficiencies we identified in our final action on the
Arkansas Regional Haze SIP with respect to the interstate visibility
transport requirement under CAA section 110(a)(2)(D)(i)(II) for the
1997 8-hour ozone and 1997 PM2.5 NAAQS.
In this document, we summarize our responses to comments received
during our comment period on our proposed rule and indicate where we
have made adjustments based on the comments and additional information
we received. In some cases, we have adjusted the emission limits,
compliance deadlines, and requirements for testing and demonstration of
compliance in response to information received during the comment
period. We also received several comments, from Entergy and Sierra
Club, after the close of the comment period, which included new
information on an alternative approach for White Bluff. We do not
address these late comments in our rulemaking and they are not a basis
for our decision in this action. We do note that the new information
regarding an alternative approach may have promise with respect to
addressing the BART requirements for White Bluff, and we encourage the
State to consider it as it develops a SIP revision to replace our FIP.
EPA is promulgating this partial FIP to address the deficiencies in
the Arkansas Regional Haze SIP and the SIP revision submitted by the
State to address the interstate visibility transport requirements.\3\
The State retains its authority to submit a revised state plan
consistent with CAA and Regional Haze Rule requirements. EPA stands
ready to work with the State on a SIP revision that would replace some
or all elements of the FIP.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\4\ 76 FR 64186.
\5\ 77 FR 14604.
\6\ See 76 FR 64186, 64188 (proposed action) and 77 FR 14604,
14672 (final action).
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
B. EPA's Authority To Promulgate a FIP
Under CAA section 110(c), EPA is required to promulgate a FIP at
any time within 2 years of the effective date of a finding that a state
has failed to make a required SIP submission or has made an incomplete
submission, or of the date that EPA disapproves a SIP in whole or in
part. The FIP requirement is terminated only if a state submits a SIP,
and EPA approves that SIP as meeting applicable CAA requirements before
promulgating a FIP. CAA section 302(y) defines the term ``Federal
implementation plan'' in pertinent part, as a plan (or portion thereof)
promulgated by EPA ``to fill all or a portion of a gap or otherwise
correct all or a portion of an inadequacy'' in a SIP, and which
includes enforceable emission limitations or other control measures,
means or techniques (including economic incentives, such as marketable
permits or auctions or emissions allowances).
[[Page 66334]]
As discussed above, in a final action published on March 12, 2012,
we disapproved in part the Arkansas Regional Haze SIP and the SIP
submitted by the state to address the interstate visibility transport
requirement of CAA section 110(a)(2)(D)(i)(II) for the 1997 8-hour
ozone and 1997 PM2.5 NAAQS.\12\ That final action became
effective on April 11, 2012. Therefore, EPA is required under CAA
section 110(c) to promulgate a FIP for the portions of the Arkansas
Regional Haze SIP and the SIP submittal to address the interstate
visibility transport requirement of CAA section 110(a)(2)(D)(i)(II) for
the 1997 8-hour ozone and 1997 PM2.5 NAAQS that we
disapproved on March 12, 2012.
---------------------------------------------------------------------------
\12\ 77 FR 14604.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\13\ 80 FR 18944.
\14\ 80 FR 24872.
\15\ 81 FR 19097.
---------------------------------------------------------------------------
A. Regional Haze
Our FIP proposal addressed the disapproved portions of the Arkansas
Regional Haze SIP and interstate visibility transport SIP. In our March
12, 2012 final action on the Arkansas Regional Haze SIP, we disapproved
some of the state's BART determinations and we also determined that the
SIP did not include the required analysis of the four reasonable
progress factors. Therefore, we partially disapproved the state's LTS
for Caney Creek and Upper Buffalo and also disapproved the RPGs
established by the state.
CAA section 169A(b)(2)(A) requires states to revise their SIPs to
contain such measures as may be necessary to make reasonable progress
towards the natural visibility goal, including a requirement that
certain categories of existing major stationary sources built between
1962 and 1977 procure, install, and operate the ``best available
retrofit technology,'' as determined by the state or EPA in the case of
a plan promulgated under section 110(c) of the CAA. Under the Regional
Haze Rule, states are directed to conduct BART determinations for such
``BART-eligible'' sources that may be anticipated to cause or
contribute to any visibility impairment in a Class I area. Rather than
requiring source-specific BART controls, states or EPA in a FIP also
have the flexibility to adopt an emissions trading program or other
alternative program as long as the alternative provides greater
reasonable progress towards improving visibility than BART. CAA section
169(g)(2) and the Regional Haze Rule at 40 Code of Federal Regulations
(CFR) Sec. 51.308(e)(1)(A) provide that in determining BART, the state
or EPA in a FIP shall take into consideration the following factors:
Costs of compliance, the energy and nonair quality environmental
impacts of compliance, any existing pollution control technology in use
at the source, the remaining useful life of the source, and the degree
of improvement in visibility which may reasonably be anticipated to
result from the use of such technology. We commonly refer to these as
the BART factors, or the five statutory factors. CAA section 169(g)(1)
and Sec. 51.308(d)(1) also require that in determining reasonable
progress, there shall be taken into consideration the costs of
compliance, the time necessary for compliance, the energy and nonair
quality environmental impacts of compliance, and the remaining useful
life of any existing source subject to such requirements. We commonly
refer to these as the reasonable progress factors, or the four
statutory factors. Consistent with the requirement in CAA section
169A(b) that states include in their regional haze SIP a 10--15 year
strategy for making reasonable progress, Sec. 51.308(d)(3) requires
that states include a LTS in their regional haze SIPs. The LTS is the
compilation of all control measures a state will use during the
implementation period of the specific SIP submittal to meet any
applicable RPGs. The LTS must include enforceable emissions
limitations, compliance schedules, monitoring and recordkeeping
requirements, and various supporting documentation and analyses to
ensure that the SIP or FIP will provide reasonable progress toward the
national goal of natural visibility conditions.
Our FIP proposal included proposed BART determinations for nine
units at six facilities and proposed reasonable progress determinations
for two units at one facility in Arkansas. These determinations
resulted in proposed emission limits, compliance schedules, and other
requirements for these sources. The proposed regulatory language was
included under Part 52 at the end of that document. We also addressed
the RPGs, as well as the LTS requirements. Lastly, we proposed that the
approved measures in the Arkansas Regional Haze SIP and measures in our
proposed FIP would adequately address the interstate transport of
pollutants that affect visibility requirement for the 1997 8-hour ozone
and 1997 PM2.5 NAAQS.
Georgia Pacific-Crossett Mill 6A and 9A Power Boilers: In our FIP
proposal, we proposed to find that the Georgia Pacific-Crossett Mill 6A
Boiler is a BART-eligible source, but not subject to BART. We also
proposed to find that the 9A Boiler, which the State had previously
determined was BART-eligible, is not subject to BART. Our proposed
determinations were based on the company's newly provided analysis and
documentation, including BART screening modeling conducted in 2011 by
Georgia Pacific based on revised emission limits from a permit issued
on May 23, 2012, and using 2001, 2002, and 2003 meteorology. The
modeling showed the maximum visibility impact from the boilers was
0.359 deciviews (dv) at Caney Creek, which is below the 0.5 dv
threshold the state used in the Arkansas Regional Haze SIP to identify
subject-to-BART sources. Prior to issuing our FIP proposal, we had
communicated to ADEQ our concern with relying on the company's BART
screening modeling that was based on revised emission limits from a
permit issued in 2012, without documentation that these emission limits
were representative of the baseline period emissions.\16\ To address
our concern, the company provided estimates of maximum 24-hour emission
rates for the 6A and 9A Boilers from the 2001-2003 baseline period to
demonstrate that these emission rates were lower than the revised
emission limits that it modeled in its 2011 BART screening
modeling.\17\ This indicated that the 2011 BART screening modeling that
was based on allowable emissions was conservative in terms of
representing the impact that the source had on visibility in the 2001-
2003 period, the period that matters for the subject-to-BART
determination, and we proposed to find that it is reasonable to
conclude based on the modeling analysis and documentation provided by
Georgia Pacific that the 6A and 9A Boilers had visibility impacts below
0.5
[[Page 66335]]
dv during the 2001-2003 baseline period and are therefore not subject
to BART.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
We proposed that BART for NOX is an emission limit of
207.4 lb/hr on a 30 boiler-operating-day rolling average, where boiler-
operating-day is defined as a 24-hour period between 12 midnight and
the following midnight during which any fuel is fed into and/or
combusted at any time in the Power Boiler. This emission limit is
consistent with the Power Boiler's baseline emissions and would not
necessitate additional controls. We proposed to require the source to
comply with this emission limit as of the effective date of the final
rule. To demonstrate compliance with this NOX BART emission
limit, we proposed to require the source to conduct annual stack
[[Page 66336]]
testing. We invited public comment on the appropriateness of this
method for demonstrating compliance with the proposed NOX
BART emission limit for Power Boiler No. 1.
Domtar Ashdown Mill Power Boiler No. 2: We proposed that BART for
SO2 is an emission limit of 0.11 lb/MMBtu on a 30 boiler-
operating-day rolling average, which we estimated is representative of
operating the existing venturi scrubbers at 90% control efficiency and
can be achieved through the installation of scrubber pump upgrades and
use of additional scrubbing reagent. We indicated that boiler-
operating-day is defined as a 24-hour period between 12 midnight and
the following midnight during which any fuel is fed into and/or
combusted at any time in the Power Boiler. We invited public comment
specifically on the appropriateness of our proposed SO2
emission limit. We proposed to require compliance with this BART
emission limit no later than 3 years from the effective date of the
final action, but invited public comment on the appropriateness of a
compliance date anywhere from 1-5 years. We also proposed to require
the source to demonstrate compliance with this emission limit using the
existing continuous emissions monitoring system (CEMS).
We proposed that BART for NOX is an emission limit of
345 lb/hr on a 30 boiler-operating-day rolling averaging basis,
consistent with the installation and operation of LNB. We indicated
that boiler-operating-day is defined as a 24-hour period between 12
midnight and the following midnight during which any fuel is fed into
and/or combusted at any time in the Power Boiler. We proposed to
require compliance with this emission limit no later than 3 years from
the effective date of the final rule, and invited public comment on the
appropriateness of this compliance date. We also proposed to require
the source to demonstrate compliance with this emission limit using the
existing CEMS.
Power Boiler No. 2 is subject to the Boiler Maximum Achievable
Control Technology (MACT) standards for PM required under CAA section
112, and found at 40 CFR part 63, subpart DDDDD--National Emission
Standards for Hazardous Air Pollutants for Major Sources: Industrial,
Commercial, and Institutional Boilers and Process Heaters. We proposed
to find that the current Boiler MACT PM standard satisfies the PM BART
requirement for Power Boiler No. 2. We also proposed that the same
method for demonstrating compliance with the Boiler MACT PM standard is
to be used for demonstrating compliance with the PM BART emission
limit. We proposed to require the source to comply with this emission
limit for BART purposes as of the effective date of the final rule.
Proposed Reasonable Progress Determinations: In our proposed rule,
we explained that the Central Regional Air Planning Association
(CENRAP) CAMx modeling with Particulate Source Apportionment Tool
(PSAT) showed that point sources are responsible for a majority of the
light extinction at Arkansas Class I areas, contributing approximately
60% of the total light extinction at each Class I area on the 20% worst
days in 2002. Point sources contributed 81.04 Mm-\1\ out of
133.93 Mm-\1\ of light extinction at Caney Creek and 77.80
Mm-\1\ out of 131.79 Mm-\1\ of light extinction
at Upper Buffalo on the average across the 20% worst days in 2002.
Since other source types (i.e., natural, on-road, non-road, and area)
each contributed a much smaller proportion of the total light
extinction at each Class I area, we decided to focus only on point
sources in our reasonable progress analysis for this planning period.
As a starting point in our analysis to determine whether additional
controls on Arkansas sources are necessary to make reasonable progress
in the first regional haze planning period, we examined the most recent
SO2 and NOX emissions inventories for point
sources in Arkansas. Based on the 2011 National Emissions Inventory
(NEI), the Entergy White Bluff Plant, the Entergy Independence Plant,
and the AEP Flint Creek Power Plant are the three largest point sources
of SO2 and NOX emissions in Arkansas.\20\ The
combined annual emissions from these three sources make up
approximately 84% of the statewide SO2 point-source
emissions and 55% of the statewide NOX point-source
emissions. As our proposed rule included SO2 and
NOX emission limits under BART for White Bluff Units 1 and 2
and Flint Creek Unit 1 that are anticipated to result in a substantial
reduction in SO2 and NOX emissions from these
facilities, we proposed to determine that it is appropriate to
eliminate these three units from further consideration of additional
controls under the reasonable progress requirements for the first
planning period. The Entergy Independence Plant is not subject to BART,
and its emissions were 30,398 SO2 tons per year (tpy) and
13,411 NOX tpy based on the 2011 NEI. The Entergy
Independence Plant is the second largest source of SO2 and
NOX point-source emissions in Arkansas, accounting for
approximately 36% of the SO2 point-source emissions and 21%
of the NOX point-source emissions in the State. In our
proposal, we explained that it is appropriate to focus our reasonable
progress analysis on the Entergy Independence Power Plant because it is
a significant source of SO2 and NOX, as it is the
second largest point source for both NOX and SO2
emissions in the State. We explained that our proposed SO2
and NOX controls under BART for White Bluff Units 1 and 2
and Flint Creek Unit 1 and our evaluation of controls under reasonable
progress for the Independence facility would address a sufficient
amount of SO2 and NOX point source emissions in
the State in this first planning period. The fourth largest
SO2 and NOX point sources in Arkansas are the
Future Fuel Chemical Company, with emissions of 3,421 SO2
tpy, and the Natural Gas Pipeline Company of America #308, with
emissions of 3,194 NOX tpy (2011 NEI). In comparison to the
SO2 and NOX emissions from the top three point
sources (i.e., White Bluff, Independence, and Flint Creek), emissions
from these two facilities and remaining point sources in the state are
relatively small. Therefore, we did not evaluate other Arkansas point
sources in our reasonable progress analysis. We explained that it is
therefore appropriate to defer the consideration and evaluation of any
additional sources under reasonable progress to future regional haze
planning periods.
---------------------------------------------------------------------------
\20\ See NEI 2011 v1. A spreadsheet containing the emissions
inventory is found in the docket for our proposed rulemaking.
---------------------------------------------------------------------------
We conducted source-specific reasonable progress analyses of
potential SO2 and NOX controls for Independence
Units 1 and 2 and conducted CALPUFF modeling to assess the baseline
visibility impacts from the facility and potential visibility benefits
of controls. Based on these analyses, we proposed two options in the
alternative for satisfying the reasonable progress requirements for
Independence Units 1 and 2. Under Option 1, we proposed to establish
both SO2 and NOX emission limits. We proposed to
require compliance with an SO2 emission limit of 0.06 lb/
MMBtu for Independence Units 1 and 2 based on a 30 boiler-operating-day
rolling average basis, consistent with the installation and operation
of dry FGD. We proposed to require Independence Units 1 and 2 to comply
with this emission limit no later than 5 years from the effective date
of the final rule. We proposed to require compliance with a
NOX emission limit of 0.15 lb/MMBtu on a 30 boiler-
operating-day averaging basis,
[[Page 66337]]
consistent with the installation and operation of LNB/SOFA. We proposed
to require Independence Units 1 and 2 to comply with this emission
limit no later than 3 years from the effective date of the final rule.
We proposed to require SO2 controls based on our
evaluation of the four reasonable progress factors, our CALPUFF
modeling of the anticipated benefits of controls, and the existing
CENRAP CAMx modeling. Specifically, we proposed that dry FGD was cost-
effective and would provide considerable visibility improvement on the
days where Independence has the largest impacts at nearby Class I
areas. Additionally, the CENRAP CAMx modeling showed that on most of
the 20% worst days in 2002, total extinction is dominated by sulfate at
both Caney Creek and Upper Buffalo.\21\ Therefore, we concluded that
the substantial SO2 emissions reductions that would be
achieved by our proposed SO2 controls for Independence Units
1 and 2 would accordingly reduce visibility extinction at Arkansas'
Class I areas on the 20% worst days.
---------------------------------------------------------------------------
\21\ See Arkansas Regional Haze SIP, Appendix 8.1--``Technical
Support Document for CENRAP Emissions and Air Quality Modeling to
Support Regional Haze State Implementation Plans,'' sections 3.7.1
and 3.7.2. See the docket for this rulemaking for a copy of the
Arkansas Regional Haze SIP.
---------------------------------------------------------------------------
We also proposed to require NOX controls under Option 1
based on our evaluation of the four reasonable progress factors, our
CALPUFF modeling of the anticipated benefits of controls, and the
existing CENRAP CAMx modeling. Specifically, we proposed that LNB/SOFA
was very cost-effective and would provide considerable visibility
improvement on the days where Independence has the largest impacts at
nearby Class I areas. In addition, the CENRAP CAMx modeling showed that
total extinction at Caney Creek was dominated by nitrate on 4 of the
days that comprise the 20% worst days in 2002, while a significant
portion of the total extinction at Upper Buffalo was due to nitrate on
2 of the days that comprise the 20% worst days in 2002.\22\ Therefore,
we concluded that our proposed NOX controls on Independence
Units 1 and 2 would improve visibility on some of the 20% worst days.
In the alternative, we proposed under Option 2 to require only
SO2 controls for Independence Units 1 and 2 under the CAA's
reasonable progress requirements. Our reasoning for proposing to
require only SO2 controls under Option 2 was that nitrate
from point sources is not a primary contributor to the total light
extinction at Arkansas Class I areas on most of the 20% worst days, so
NOX controls would not offer as much visibility improvement
on the most impaired days as SO2 controls. In our proposed
rule, we specifically solicited public comment on Options 1 and 2.
---------------------------------------------------------------------------
\22\ See Arkansas Regional Haze SIP, Appendix 8.1--``Technical
Support Document for CENRAP Emissions and Air Quality Modeling to
Support Regional Haze State Implementation Plans,'' section 3.7.1
and 3.7.2. See the docket for this rulemaking for a copy of the
Arkansas Regional Haze SIP.
---------------------------------------------------------------------------
In addition to Options 1 and 2, we also solicited public comment on
any alternative SO2 and NOX control measures that
would address the regional haze requirements for Entergy White Bluff
Units 1 and 2 and Entergy Independence Units 1 and 2 for this planning
period. We noted that this could include, but was not limited to, a
combination of early unit shutdowns and other emissions control
measures that would achieve greater reasonable progress than the BART
and reasonable progress requirements we proposed for these four units
in our proposed rule.
On May 1, 2015, we published a notice in the Federal Register
announcing supplemental modeling that we conducted for Independence
Units 1 and 2, and extending the comment period to allow interested
persons additional time to provide comments on the supplemental
modeling.\23\ We performed the supplemental modeling after receiving a
letter dated April 13, 2015, that revealed that we made an error in the
modeled location of the Entergy Independence facility.\24\ The
supplemental modeling included the corrected facility location. We
provided a summary of our supplemental modeling for Independence Units
1 and 2 in the docket for our proposed rulemaking.\25\ In the summary,
we provided a comparison of our previous CALPUFF modeling for
Independence Units 1 and 2 (i.e., the modeling that was presented in
our proposed rule published on April 8, 2015) and our supplemental
modeling. We noted that the modeled visibility benefits from our
proposed SO2 controls (dry FGD) for Independence were the
same or larger in the supplemental modeling. The largest difference was
an increase of 0.29 dv in the modeled visibility benefit from
SO2 controls at Upper Buffalo. The largest modeled benefit
from NOX controls was at Caney Creek and was approximately
the same in the supplemental modeling. Modeled visibility benefits from
NOX controls at the three other Class I areas were slightly
smaller in the supplemental modeling. The change in location of the
modeled facility resulted in different transport patterns from the
facility to the Class I areas, which resulted in the modeled 98th
percentile visibility impacts being more driven by sulfate impacts.
Therefore, the benefits from NOX controls on the 98th
percentile days were slightly reduced. In addition, whereas our
previous modeling of the control scenario that included both dry FGD
and LNB/SOFA controls showed visibility benefits ranging from 1.18 to
1.48 dv at each Class I area, the supplemental modeling showed larger
visibility benefits ranging from 1.40 to 1.52 dv at each Class I area.
After reviewing the supplemental modeling, we did not change our
proposed reasonable progress controls for Independence Units 1 and 2.
---------------------------------------------------------------------------
\23\ 80 FR 24872.
\24\ April 13, 2015 letter from Mr. Bill Bumpers to Mr. Guy
Donaldson, Chief, Air Planning Section, EPA Region 6, ``Entergy
Arkansas Inc. (EAI) request for extension of comment period on EPA-
R06-OAR-2015-0189-0001.'' This document is found in the docket for
this rulemaking.
\25\ See document titled ``Summary of Additional Modeling for
Entergy Independence,'' dated April 20, 2015. This document is found
in the docket for this rulemaking.
---------------------------------------------------------------------------
Proposed Reasonable Progress Goals: We proposed RPGs for Caney
Creek and Upper Buffalo that reflected the anticipated visibility
conditions resulting from the combination of control measures from the
approved portion of the 2008 Arkansas Regional Haze SIP and our FIP
proposal. As explained more fully in our proposal, we adjusted the 2018
RPGs modeled by CENRAP using a scaling methodology that adjusted
visibility extinction components in proportion to emission changes. We
recognized that this method was not refined, but explained that it
allowed us to incorporate the additional emission reductions achieved
through the FIP into the states' RPGs. Based on this methodology, we
proposed revised RPGs for the first planning period for the 20% worst
days of 22.27 dv for Caney Creek and 22.33 dv for Upper Buffalo.
Our proposed revised RPGs and our methodology for calculating the
revised RPGs were discussed in detail in our FIP proposal and in our
technical support documentation,\26\ which was made available in the
docket when the proposed rule was published on April 8, 2015. However,
a spreadsheet containing the actual calculations of our proposed
revised RPGs for the 20% worst days for the Caney Creek and Upper
Buffalo Wilderness Areas was inadvertently omitted from the docket. On
April 4, 2016, we published a notice in the Federal Register announcing
the
[[Page 66338]]
availability in the docket of the spreadsheet containing the actual
calculations of our proposed revised RPGs for the 20% worst days for
the Caney Creek and Upper Buffalo Wilderness Areas.\27\ The notice also
reopened the comment period for our FIP proposal until May 4, 2016, but
strictly limited the reopening of the comment period to our
calculations of the revised RPGs, as presented in the spreadsheet we
made available at that time in the docket.\28\
---------------------------------------------------------------------------
\26\ See ``Technical Support Document for EPA's Proposed Action
on the Arkansas Regional Haze Federal Implementation Plan'' at page
147.
\27\ 81 FR 19097.
\28\ See the document titled ``Caney Creek and Upper Buffalo
Wilderness Areas Reasonable Progress Goals (CACR UPBU RPG
analysis.xlsx),'' which is available in the docket for our
rulemaking.
---------------------------------------------------------------------------
Long-Term Strategy: We proposed to find that provisions in the
approved portion of the Arkansas Regional Haze SIP and our FIP proposal
fulfilled the requirements of 40 CFR 51.308(d)(3), which requires
emission limitations, compliance schedules, monitoring and
recordkeeping requirements, and various supporting documentation and
analyses to ensure that the SIP or FIP will provide reasonable progress
toward the national goal. Specifically, we proposed to promulgate
emission limits, compliance schedules, and other requirements for
Arkansas' BART sources and the two units at the Independence facility
to address the long-term strategy requirement.
B. Interstate Visibility Transport
Among other things, CAA section 110(a)(2)(D)(i)(II) requires that
all SIPs contain adequate provisions to prohibit emissions that will
interfere with measures required to protect visibility in other states.
We refer to this as the interstate transport visibility requirement.
Our proposed FIP included emission limits for Arkansas sources under
the BART and reasonable progress requirements that would ensure a level
of emissions reductions at least as great as what surrounding states
relied on in developing their regional haze SIPs. We proposed that the
combination of the measures in the approved portions of the Arkansas
Regional Haze SIP and our FIP proposal would satisfy the visibility
requirement of CAA section 110(a)(2)(D)(i)(II) for the 1997 8-hour
ozone and 1997 PM2.5 NAAQS.
IV. Summary of Our Final FIP
Below, we present a summary of our final Arkansas Regional Haze
FIP. In this section, we provide a summary of our final BART
determinations, reasonable progress determinations, revised RPGs, LTS
provisions, and interstate transport provisions. This final FIP
includes emission limits, compliance schedules, and requirements for
equipment maintenance, monitoring, testing, recordkeeping, and
reporting for all affected sources and units.
We note that we are finalizing our FIP with certain changes to our
proposal in response to comments we received during the public comment
period. In particular, we are finalizing a bifurcated NOX
BART emission limit for White Bluff Units 1 and 2; we are finalizing an
SO2 BART emission limit for the Domtar Ashdown Mill Power
Boiler No. 1 in the form of lb/day based on a 30 boiler-operating-day
average instead of lb/hr based on a 30 boiler-operating-day average;
and we are finalizing an SO2 BART emission limit for the
Domtar Ashdown Mill Power Boiler No. 2 in the form of lb/hr based on a
30 boiler-operating-day average instead of lb/MMBtu based on a 30
boiler-operating-day average. In light of information we received
during the public comment period, we are also adjusting the compliance
dates for some of our BART determinations. We are requiring AEP Flint
Creek Unit 1 to comply with the SO2 BART emission limit
within 18 months of the effective date of this final action, instead of
the 5-year compliance date we proposed. We are requiring AEP Flint
Creek Unit 1 and White Bluff Units 1 and 2 to comply with the
NOX BART emission limit within 18 months of the effective
date of this final action, instead of the 3-year compliance date we
proposed. We are requiring the Domtar Ashdown Mill to comply with the
SO2 and NOX BART emission limits for Power Boiler
No. 1 and the PM BART emission limit for Power Boiler No. 2 within 30
days from the effective date of this final action instead of on the
date of the final action. We are requiring the Domtar Ashdown Mill to
comply with the SO2 and NOX BART emission limits
for Power Boiler No. 2 within 5 years of the effective date of this
final action, instead of the 3-year compliance date we proposed. We are
making some adjustments to the requirements for demonstrating
compliance, testing, reporting, and recordkeeping for SO2
and NOX BART for the Domtar Ashdown Mill Power Boiler No. 1
and for SO2, NOX, and PM BART for Power Boiler
No. 2. We are also revising the definition of boiler-operating-day as
it applies to Power Boilers No. 1 and 2 under this FIP.
We are finalizing SO2 and NOX controls under
reasonable progress for Independence Units 1 and 2 (our proposed Option
1). In response to comments we received during the public comment
period, we are finalizing a bifurcated NOX emission limit
for Independence Units 1 and 2 and are requiring the source to comply
with the NOX emission limit within 18 months of the
effective date of this final action instead of the 3-year compliance
date we proposed. We are also providing revised RPGs for Arkansas'
Class I areas that reflect anticipated visibility conditions at the end
of the implementation period in 2018 rather than the anticipated
visibility conditions once the FIP has been fully implemented.
These changes to our proposal are discussed in more detail in the
subsections that follow and in our separate Response to Comment (RTC)
document, which can be found in the docket for this final rulemaking.
The final regulatory language for the FIP is under Part 52 at the end
of this notice.
The final FIP requires that subject-to-BART sources comply with the
emission limits contained in Table 1 below and that the Independence
Plant comply with the emission limits contained in Table 2 below. We
are determining that the BART emission limits for the sources listed in
Table 1 are also sufficient for reasonable progress. Throughout this
section of the final rule, we specify the averaging basis of each
emission limit and associated compliance dates.
Table 1--Final BART Emission Limits
----------------------------------------------------------------------------------------------------------------
Final SO2 emission Final NOX emission
Unit limit limit Final PM emission limit
----------------------------------------------------------------------------------------------------------------
Bailey Unit 1........................ 0.5% limit on sulfur 887 lb/hr \a\.......... 0.5% limit on sulfur
content of fuel content of fuel
combusted. combusted.
McClellan Unit 1..................... 0.5% limit on sulfur 869.1 lb/hr \b\/705.8 0.5% limit on sulfur
content of fuel lb/hr \b\. content of fuel
combusted. combusted.
[[Page 66339]]
Flint Creek Unit 1................... 0.06 lb/MMBtu.......... 0.23 lb/MMBtu.......... EPA approved the
state's BART
determination in March
12, 2012 final action
(77 FR 14604).
White Bluff Unit 1................... 0.06 lb/MMBtu.......... 0.15 lb/MMBtu \c\/671 EPA approved the
lb/hr \d\. state's BART
determination in March
12, 2012 final action
(77 FR 14604).
White Bluff Unit 2................... 0.06 lb/MMBtu.......... 0.15 lb/MMBtu \c\/671 EPA approved the
lb/hr \d\. state's BART
determination in March
12, 2012 final action
(77 FR 14604).
White Bluff Auxiliary Boiler......... 105.2 lb/hr \a\........ 32.2 lb/hr \a\......... 4.5 lb/hr \a\.
Lake Catherine Unit 4 \e\............ EPA approved the 0.22 lb/MMBtu.......... EPA approved the
state's BART state's BART
determination in March determination in March
12, 2012 final action 12, 2012 final action
(77 FR 14604). (77 FR 14604).
Domtar Ashdown Mill Power Boiler No. 504 lb/day \f\......... 207.4 lb/hr \f\........ EPA approved the
1. state's BART
determination in March
12, 2012 final action
(77 FR 14604).
Domtar Ashdown Mill Power Boiler No. 91.5 lb/hr............. 345 lb/hr.............. PM BART shall be
2. satisfied by relying
on the applicable PM
standard under 40 CFR
part 63, subpart DDDDD
\g\.
----------------------------------------------------------------------------------------------------------------
\a\ Existing emission limit; we do not anticipate that the facility will have to install any additional control
to comply with this emission limit.
\b\ Existing emission limit; we do not anticipate that the facility will have to install any additional control
to comply with this emission limit. Emission limit of 869.1 lb/hr applies to the natural gas-firing scenario;
emission limit of 705.8 lb/hr applies to the fuel oil-firing scenario.
\c\ Emission limit of 0.15 lb/MMBtu applies when unit is operated at 50% or greater of the unit's maximum heat
input rating.
\d\ Emission limit of 671 lb/hr applies when the unit is operated at less than 50% of the unit's maximum heat
input rating.
\e\ Emission limit for NOX applies to the natural gas-firing scenario. The unit shall not burn fuel oil until
BART determinations for SO2, NOX, and PM are promulgated for the unit for the fuel oil-firing scenario through
EPA approval of a SIP revision or a FIP.
\f\ Emission limit is representative of baseline emissions; we do not anticipate that the facility will have to
install any additional control to comply with this emission limit.
\g\ The facility shall rely on the applicable PM standard under 40 CFR part 63, subpart DDDDD--National Emission
Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers
and Process Heaters, as revised, to satisfy the PM BART requirement.
Table 2--Final Reasonable Progress Emission Limits for Sources not
Subject to BART
------------------------------------------------------------------------
Final SO2 emission Final NOX emission
Unit limit limit
------------------------------------------------------------------------
Independence Unit 1............. 0.06 lb/MMBtu..... 0.15 lb/MMBtu \a\/
671 lb/hr \b\.
Independence Unit 2............. 0.06 lb/MMBtu..... 0.15 lb/MMBtu \a\/
671 lb/hr \b\.
------------------------------------------------------------------------
\a\ Emission limit of 0.15 lb/MMBtu applies when unit is operated at 50%
or greater of the unit's maximum heat input rating.
\b\ Emission limit of 671 lb/hr applies when the unit is operated at
less than 50% of the unit's maximum heat input rating.
A. Regional Haze
1. Identification of BART-Eligible and Subject-to-BART Sources
We are finalizing our determination that the Georgia-Pacific
Crossett Mill 6A Boiler is a BART-eligible source, but is not subject
to BART. We are also finalizing our determination that the 9A Boiler,
which the State had previously determined is BART-eligible, is not
subject to BART. These determinations are based on the company's newly
provided analysis and documentation, as described above and in our
proposal. Therefore, the CAA and Regional Haze Rule do not require BART
determinations for the 6A and 9A Boilers.
2. BART Determinations
a. AECC Bailey Unit 1
Bailey Unit 1 burns primarily natural gas, but is also permitted to
burn fuel oil. Our proposal explains why the source needs to retain the
flexibility to use fuel oil. Taking into consideration the BART
factors, we are finalizing BART determinations and emission limits for
SO2, NOX, and PM as proposed. Our final BART
determination for SO2 and PM is the use of fuels with 0.5%
or lower sulfur content by weight. After the effective date of this
final rule, the facility shall not purchase fuel for use in Unit 1 that
does not meet this sulfur-content requirement. We are allowing the
facility 5 years to burn its existing supply of No. 6 fuel oil in
accordance with any operating restrictions enforced by ADEQ. Providing
this time period will avoid creating an incentive for the source to
burn large amounts of this fuel during a short period, which could
affect visibility on individual days more adversely. We are requiring
the facility to comply with the requirement to use only fuels with 0.5%
or lower sulfur content by weight no later than 5 years from the
effective date of this final rule. We discussed in detail in our
proposal the cost effectiveness and projected visibility improvement of
switching from the baseline fuel to fuels with a sulfur content by
weight of 0.5% or lower, and also present this information in Tables 3
and 4.\29\ We are not making changes to the analysis we presented in
our proposal of the cost and visibility improvement of this control
measure. As discussed in our proposal, the cost of switching from the
baseline fuel to fuels with a sulfur content by weight of 0.5% or lower
is within the range of what we consider to be cost effective for BART
and it is projected to result in considerable visibility improvement at
the affected Class I areas.\30\ We are finalizing this BART
determination for SO2 and PM as proposed.
---------------------------------------------------------------------------
\29\ See also 80 FR 18944, 18951, and 18955.
\30\ 80 FR 18944, 18952, 18956.
[[Page 66340]]
Table 3--AECC Bailey Unit 1--Cost Effectiveness of Switching to Fuel
With Sulfur Content of 0.5% or Lower
------------------------------------------------------------------------
No. 6 Fuel
oil--0.5%
Pollutant sulfur content
($/ton)
------------------------------------------------------------------------
SO2..................................................... 2,559
PM...................................................... 2,997
------------------------------------------------------------------------
Table 4--AECC Bailey Unit 1--Summary of the 98th Percentile Visibility
Impacts And Improvement of Switching to Fuel With Sulfur Content of 0.5%
or Lower
------------------------------------------------------------------------
Visibility
improvement from
baseline ([Delta]dv)--
Baseline reflects improvement
visibility from SO2 and PM
Class I area impact reductions
([Delta]dv)
----------------------
No. 6 Fuel oil--0.5%
sulfur content
------------------------------------------------------------------------
Caney Creek...................... 0.330 0.188
Upper Buffalo.................... 0.348 0.221
Hercules-Glades.................. 0.368 0.233
Mingo............................ 0.379 0.209
Cumulative Visibility Improvement .............. 0.851
([Delta]dv).....................
------------------------------------------------------------------------
Our final BART determination for NOX is an emission
limit of 887 lb/hr, which is the existing emission limit and does not
necessitate the installation of additional controls. The source must
comply with the NOX emission limit for BART purposes as of
the effective date of this final rule.
b. AECC McClellan Unit 1
AECC McClellan Unit 1 burns primarily natural gas, but is also
permitted to burn fuel oil. Our proposal explains why the source needs
to retain the flexibility to use fuel oil. Taking into consideration
the BART factors, we are finalizing BART determinations and emission
limits for SO2, NOX, and PM as proposed. Our
final BART determination for SO2 and PM is the use of fuels
with 0.5% or lower sulfur content by weight. After the effective date
of this final rule, the facility shall not purchase fuel for use in
Unit 1 that does not meet this sulfur content requirement. We are
allowing the facility 5 years to burn its existing supply of No. 6 fuel
oil, in accordance with any operating restrictions enforced by ADEQ. We
are requiring the facility to comply with the requirement to use only
fuels with 0.5% or lower sulfur content by weight no later than 5 years
from the effective date of this final rule. Providing this time period
will avoid creating an incentive for the source to burn large amounts
of this fuel during a short period, which could affect visibility on
individual days more adversely. We discussed in detail in our proposal
the cost effectiveness and projected visibility improvement of
switching from the baseline fuel to fuels with a sulfur content by
weight of 0.5% or lower, and also present this information in Tables 5
and 6.\31\ We are not making changes to the analysis we presented in
our proposal of the cost and visibility improvement of this control
measure. As discussed in our proposal, the cost of switching from the
baseline fuel to fuels with a sulfur content by weight of 0.5% or lower
is within the range of what we consider to be cost effective for BART
and it is projected to result in considerable visibility improvement at
the affected Class I areas.\32\ We are finalizing this BART
determination for SO2 and PM as proposed.
---------------------------------------------------------------------------
\31\ See also 80 FR 18944, 18958, 18959, and 18962.
Table 5--AECC McClellan Unit 1--Cost Effectiveness of Switching to Fuel
With Sulfur Content of 0.5% or Lower
------------------------------------------------------------------------
No. 6 Fuel
oil--0.5%
Pollutant sulfur content
($/ton)
------------------------------------------------------------------------
SO2..................................................... 3,823
PM...................................................... 4,553
------------------------------------------------------------------------
---------------------------------------------------------------------------
\32\ 80 FR 18944, 18959, 18962.
[[Page 66341]]
Table 6--AECC McClellan Unit 1--Summary of the 98th Percentile
Visibility Impacts And Improvement of Switching to Fuel With Sulfur
Content of 0.5% or Lower
------------------------------------------------------------------------
Visibility
improvement from
baseline ([Delta]dv)--
Baseline reflects improvement
visibility from SO2 and PM
Class I area impact reductions
([Delta]dv)
----------------------
No. 6 Fuel oil--0.5%
sulfur content
------------------------------------------------------------------------
Caney Creek...................... 0.622 0.3
Upper Buffalo.................... 0.266 0.12
Hercules-Glades.................. 0.231 0.116
Mingo............................ 0.228 0.092
Cumulative Visibility Improvement .............. 0.628
([Delta]dv).....................
------------------------------------------------------------------------
Our final BART determination for NOX is an emission
limit of 869.1 lb/hr for natural gas firing and 705.8 lb/hr for fuel
oil firing, which are the existing emission limits and do not
necessitate the installation of additional controls. The source must
comply with the NOX emission limits for BART purposes as of
the effective date of the final rule.
c. AEP Flint Creek Unit 1
Taking into consideration the BART factors, we are finalizing our
determination that BART for SO2 is an emission limit of 0.06
lb/MMBtu on a 30 boiler-operating-day rolling average, which is
consistent with the installation and operation of NID technology (a
type of dry scrubbing system). As discussed in detail in our RTC
document, we are not making changes to the analysis we presented in our
proposal of the cost and visibility improvement of this control
measure. We discussed in our proposal that the cost of NID on Flint
Creek Unit 1 is estimated to be $3,845/SO2 ton removed,
which is within the range of what we consider to be cost effective for
BART, and it is projected to result in considerable visibility
improvement at the affected Class I areas (see Table 7).\33\ Therefore,
we are finalizing this SO2 BART emission limit as proposed.
---------------------------------------------------------------------------
\33\ 80 FR 18944, 18966.
Table 7--AEP Flint Creek Unit 1--Summary of the 98th Percentile
Visibility Impacts And Improvement of NID Technology
------------------------------------------------------------------------
Baseline Visibility
visibility improvement
Class I area impact from baseline
([Delta]dv) ([Delta]dv)
------------------------------------------------------------------------
Caney Creek............................. 0.963 0.615
Upper Buffalo........................... 0.965 0.464
Hercules-Glades......................... 0.657 0.345
Mingo................................... 0.631 0.414
Cumulative Visibility Improvement .............. 1.838
([Delta]dv)............................
------------------------------------------------------------------------
In our proposal, we stated that we believed that the maximum
compliance time of 5 years allowed under the CAA and Regional Haze Rule
was appropriate for a new scrubber retrofit and proposed to require the
source to comply with this emission limit no later than 5 years from
the effective date of the final rule.\34\ We received comments during
the public comment period that brought to our attention that the
Arkansas Public Service Commission (PSC) has determined that dry
scrubber installation at Flint Creek is in the public interest and that
the installation of NID controls is already underway and anticipated by
the company to be completed by May 29, 2016. The Arkansas PSC requires
Flint Creek to provide quarterly reports on the progress of the
installation of these controls, which are publicly available online on
the Arkansas PSC Web site.\35\ The first quarterly report submitted by
the company to the Arkansas PSC is dated March 26, 2014, and stated
that the FGD project includes the installation of an Alstom NID system
to comply with the Mercury and Air Toxics Standards (MATS) Rule and in
anticipation of the BART requirements. The report also stated that the
company established design, procurement, and construction schedules to
bring the upgraded plant fully on line by May 29, 2016. The most recent
quarterly report available on the Arkansas PSC Web site is dated March
10, 2016, and covers the fourth quarter in 2015. This report indicated
that the company still expected that the upgraded plant would be fully
on line by May 29, 2016. We verified the status of the installation of
the controls with the company, who confirmed that installation of the
NID controls was completed in June 2016, and that the plant is now
operating with those controls.\36\ We proposed a 5-year compliance date
without knowing that installation of these controls was well underway.
After carefully considering
[[Page 66342]]
the comments we received, we have determined that a 5-year compliance
date is not appropriate because the CAA requires that sources comply
with BART as expeditiously as practicable.\37\ Therefore, we are
finalizing a shorter compliance date.\38\ The information that has been
made available to us during the comment period indicates that Flint
Creek intends to operate the NID system to comply with the alternative
SO2 emission limit under the Utility MATS rule. The
applicable MATS SO2 emission limit is 0.2 lb/MMBtu. The
SO2 emission limit we are requiring in our FIP to satisfy
the SO2 BART requirement is 0.06 lb/MMBtu. The comments and
documentation submitted to us indicate that the company intends to use
the same NID system to comply with MATS and the SO2 BART
requirement. We expect that in order to achieve an emission rate of
0.06 lb/MMBtu, additional scrubbing reagent would be needed beyond that
required to meet the 0.2 lb/MMBtu emission limit the company was
required to meet by April 2016 under MATS. We also recognize that it is
possible that the reagent handling system installed to meet the 0.2 lb/
MMBtu emission limit would need some upgrades in order to accommodate
the additional scrubbing reagent that would be needed to achieve the
more stringent 0.06 lb/MMBtu emission limit we are requiring in this
FIP. Therefore, to allow the facility sufficient time to secure the
additional scrubbing reagent that would be needed to comply with the
SO2 BART emission limit and to make any necessary upgrades
to the reagent handling system, we are finalizing an 18-month
compliance date for Flint Creek Unit 1 to comply with the
SO2 BART requirement. We believe that this will provide
sufficient time for the facility to be able to achieve the
SO2 BART requirement while still meeting the statutory
mandate that BART controls be installed and operated as expeditiously
as practicable.
---------------------------------------------------------------------------
\34\ 80 FR 18944, 18967.
\35\ See the Arkansas PSC Web site at http://www.apscservices.info/efilings/docket_search.asp. The quarterly
reports the company is required to submit to the Arkansas PSC are
available by searching for docket No. 12-008-U.
\36\ See file titled ``Record of Call--Flint Creek_August 10
2016,'' which is found in the docket for this rulemaking.
\37\ CAA section 169A(b)(2)(A).
\38\ The shorter compliance timeframe we are finalizing is a
logical outgrowth of our proposal based on the comments received,
which are discussed in more detail elsewhere in the final rule and
our RTC document. See Int'l Union, UMW, 407 F.3d at 1259; Fertilizer
Inst., 935 F.2d at 1311; Chocolate Mfrs. Ass'n, 755 F.2d 1098.
---------------------------------------------------------------------------
Taking into consideration the BART factors, we are finalizing our
determination that BART for NOX is an emission limit of 0.23
lb/MMBtu on a 30 boiler-operating-day rolling average, which is
consistent with the installation and operation of new LNB/OFA. In
response to comments we received on our initial cost analysis presented
in our proposal, we have revised our cost estimate for LNB/OFA for AEP
Flint Creek Unit 1. Based on this revision to our cost analysis, we
find that LNB/OFA is estimated to cost $1,258/NOX ton
removed, which is even more cost effective (lower $/ton) than we
estimated in our proposal. LNB/OFA is also projected to result in
considerable visibility improvement at the affected Class I areas (see
Table 8). As we discuss in our RTC document, after revising our cost
analysis of NOX controls for AEP Flint Creek, we find that
the additional cost of more stringent controls such as SNCR and SCR is
not justified by the incremental visibility benefits of the more
stringent controls. Therefore, we are finalizing the NOX
BART emission limit as proposed, consistent with installation of LNB/
OFA controls.
Table 8--AEP Flint Creek Unit 1--Summary of the 98th Percentile
Visibility Impacts And Improvement of LNB/OFA
------------------------------------------------------------------------
Baseline Visibility
visibility improvement
Class I area impact from baseline
([Delta]dv) ([Delta]dv)
------------------------------------------------------------------------
Caney Creek............................. 0.963 0.081
Upper Buffalo........................... 0.965 0.026
Hercules-Glades......................... 0.657 0.024
Mingo................................... 0.631 0.014
Cumulative Visibility Improvement .............. 0.145
([Delta]dv)............................
------------------------------------------------------------------------
We received comments from the company requesting that we extend our
proposed 3-year compliance date for the NOX BART requirement
to 5 years to allow sufficient time for planning, selection of
engineering and design professionals, vendors, contractors, permitting,
start up and commissioning, and coordinating and scheduling unit
outages. We also received comments from an environmental group stating
that we should shorten the compliance date because the typical
installation timeframe for low NOX burners is 6-8 months
from bid evaluation through startup of the technology. The
environmental group also indicated that the company may have already
started the process of installing LNB/OFA controls in anticipation of
the BART requirement. We do not have information corroborating that the
installation of these controls is already underway, but we agree with
the environmental group that LNB/OFA can be installed within a 6-8
month timeframe. The company did not provide specific information to
support its contention that a longer compliance date that extends
beyond the 6-8 month typical installation timeframe for LNB/OFA,
measured from bid evaluation, is needed for AEP Flint Creek. Although
we agree that 6-8 months is the typical installation timeframe for LNB/
OFA controls, in determining the appropriate compliance date we have
also taken into consideration that we are finalizing NOX
emission limits that are based on LNB/OFA or LNB/SOFA controls for a
total of five EGUs in this FIP and that the installation of these
controls will require outage time. These five EGUs combined accounted
for approximately 45% of the state's 2015 heat input.\39\ Because of
the heavy reliance on these EGUs for electricity generation in the
state, we recognize that it may be difficult to schedule outage time to
install LNB/OFA or LNB/SOFA on all five of these units within the
typical installation timeframe of 6-8 months and at the same time
supply adequate electricity to meet demand in the state. As we discuss
in section V.F. of this final rule, in light of these unique
circumstances, we believe that it is appropriate to finalize an 18-
month compliance date for these EGUs to comply with the NOX
emission limits required by this FIP. This compliance date provides the
affected utilities considerable time beyond typical LNB/
[[Page 66343]]
OFA installation timeframes to install these controls and comply with
their NOX emission limits.
---------------------------------------------------------------------------
\39\ These five EGUs are White Bluff Units 1 and 2, Independence
Units 1 and 2, and Flint Creek Unit 1.
---------------------------------------------------------------------------
Several commenters submitted comments stating that Arkansas is
subject to the Cross State Air Pollution Rule (CSAPR) for ozone season
NOX, so we should rely on CSAPR to satisfy the
NOX BART requirement instead of promulgating source-specific
NOX BART determinations. In the same way that a state
subject to CSAPR for ozone season NOX has the discretion to
decide whether to conduct source-specific BART determinations for
NOX or to rely on EPA's 2012 finding that CSAPR is better
than BART, EPA has the same discretion in promulgating a FIP. Our
decision to propose source-specific NOX BART determinations
for Arkansas was reasonable for multiple reasons: It is the approach
Congress chose in the statute itself; it is consistent with Arkansas'
earlier decision to conduct source-specific BART determinations in lieu
of relying on the Clean Air Interstate Rule (CAIR) to meet the BART
requirements; and at the time of our proposed action, it properly
accounted for uncertainty in the CSAPR better-than-BART regulation
created by ongoing litigation regarding the CSAPR program. Further,
subsequent to our proposal, the D.C Circuit Court issued a July 2015
decision upholding CSAPR but remanding without vacatur a number of the
Rule's state NOX and SO2 emissions budgets.
Arkansas' ozone season NOX budget is not itself affected by
the remand. However, the Court's remand of the affected states'
emissions budgets has implications for CSAPR better-than BART, since
the demonstration underlying that rulemaking relied on the emission
budgets of all states subject to CSAPR, including those that the D.C.
Circuit remanded, to establish that CSAPR provides for greater
reasonable progress than BART. As of the time EPA is taking this action
to finalize Arkansas' Regional Haze FIP, we are in the process of
acting on the Court's remand consistent with the planned response we
outlined in a June 2016 memorandum.\40\ For these reasons, which we
discuss in more detail in our RTC document, we are finalizing source-
specific NOX BART determinations for AEP Flint Creek Unit 1
and other Arkansas EGUs subject to BART. As we have noted throughout
this document, we are willing to work with ADEQ to develop a SIP
revision that could replace our FIP. Such a SIP revision will need to
meet the CAA and EPA's Regional Haze regulations. In its SIP revision,
ADEQ may elect to rely on CSAPR to satisfy the NOX BART
requirements for Arkansas' EGUs instead of doing source-specific
NOX BART determinations. Such an approach could be
appropriate if, as we expect, the uncertainty created by the D.C.
Circuit's remand of the affected states' emission budgets will shortly
be resolved.
---------------------------------------------------------------------------
\40\ https://www3.epa.gov/airtransport/CSAPR/pdfs/CSAPR_SO2_Remand_Memo.pdf.
---------------------------------------------------------------------------
d. White Bluff Units 1 and 2
Taking into consideration the BART factors, we are finalizing our
determination that BART for SO2 for White Bluff Units 1 and
2 is an emission limit of 0.06 lb/MMBtu on a 30 boiler-operating-day
rolling average, consistent with the installation and operation of dry
FGD or another control technology that achieves that level of control.
We are requiring the source to comply with this emission limit no later
than 5 years from the effective date of the final rule. In response to
comments we received on our initial cost analysis presented in our
proposal, we have revised our cost estimate for dry FGD for White Bluff
Units 1 and 2. Based on this revision to our cost analysis, we find
that dry FGD is estimated to cost $2,565/SO2 ton removed at
Unit 1 and $2,421/SO2 ton removed at Unit 2. Although these
cost estimates are slightly higher than we estimated in our proposal,
we continue to find these controls to be cost effective and would
result in considerable visibility improvement (see Table 9).\41\
Therefore, we are finalizing the SO2 BART emission limit as
proposed.
---------------------------------------------------------------------------
\41\ See also 80 FR 18944, 18972.
Table 9--Entergy White Bluff Units 1 and 2--Summary of the 98th Percentile Visibility Impacts And Improvement of
Dry FGD
----------------------------------------------------------------------------------------------------------------
White Bluff Unit 1 White Bluff Unit 2
---------------------------------------------------------------
Baseline Visibility Baseline Visibility
Class I area visibility improvement visibility improvement
impact from baseline impact from baseline
([Delta]dv) ([Delta]dv) ([Delta]dv) ([Delta]dv)
----------------------------------------------------------------------------------------------------------------
Caney Creek..................................... 1.628 0.813 1.695 0.754
Upper Buffalo................................... 1.140 0.762 1.185 0.767
Hercules-Glades................................. 1.041 0.683 1.061 0.645
Mingo........................................... 0.887 0.620 0.903 0.593
Cumulative Visibility Improvement ([Delta]dv)... .............. 2.878 .............. 2.759
----------------------------------------------------------------------------------------------------------------
Several commenters requested that we rely on CSAPR to satisfy the
NOX BART requirement for Arkansas EGUs in our final FIP. We
discuss in section V.H. of this final rule that we have concluded for a
number of reasons that it would not be appropriate to rely on CSAPR as
an alternative to NOX BART for EGUs in Arkansas at this
time. Therefore, we are finalizing source-specific NOX BART
determinations for all Arkansas EGUs, including White Bluff Units 1 and
2. We proposed that BART for NOX for Units 1 and 2 is an
emission limit of 0.15 lb/MMBtu on a 30 boiler-operating-day rolling
average, consistent with the installation and operation of LNB/SOFA. We
received comments from the company stating that White Bluff Units 1 and
2 are no longer expected to be able to consistently meet our proposed
NOX emission limit of 0.15 lb/MMBtu over a 30-boiler-
operating-day period based on LNB/SOFA controls. We have determined
that the company has provided sufficient information to substantiate
that the units are not expected to be able to meet our proposed
NOX emission limit of 0.15 lb/MMBtu when the units are
primarily operated at less than 50% of their operating capacity. In
particular, LNB/SOFA is expected to achieve optimal NOX
control when the boiler is operated from 50-100% steam flow because the
heat input across this range is sufficient to safely redirect a
substantial portion of combustion air through the overfire air
registers. This allows the combustion
[[Page 66344]]
zone airflow to be sub-stoichiometric and oxygen to be reduced to the
point where much of the elemental nitrogen in the fuel and combustion
air can pass through the boiler without converting to NOX.
When a boiler is operated below the 50-100% capacity range,
NOX concentrations on a lb/MMBtu basis can be elevated due
to the lower heat input rating, even though the pounds of
NOX emitted per hour are less due to the reduced amount of
fuel and air. In light of the information provided by the company, we
are finalizing a bifurcated NOX emission limit for each
unit, where our proposed 0.15 lb/MMBtu emission limit will address
emissions when the unit is operated at high capacities and a mass-based
emission limit will address emissions when the unit is operated at low
capacities. The bifurcated emission limits we are finalizing are a
logical outgrowth of our proposal based on the company's comments,
which are discussed in more detail elsewhere in the final rule and our
RTC document.\42\
---------------------------------------------------------------------------
\42\ A final rule is a logical outgrowth of the proposed rule
``if interested parties should have anticipated that the change was
possible, and thus reasonably should have filed their comments on
the subject during the notice-and-comment period.'' Int'l Union,UMW
v. MSHA, 407 F.3d 1250, 1259 (D.C. Cir. 2005) (internal quotations
omitted); see also, Fertilizer Inst. v. EPA, 935 F.2d 1303, 1311
(D.C. Cir. 1991). No additional notice or opportunity to comment is
necessary where, as here, the final rule is ``in character with the
original scheme,'' and does not ``substantially depart [] from the
terms or substance'' of the proposal. Chocolate Mfrs. Ass'n v.
Block, 755 F.2d 1098 (4th Cir. 1985).
---------------------------------------------------------------------------
We are requiring White Bluff Units 1 and 2 to each meet a
NOX emission limit of 0.15 lb/MMBtu on a 30 boiler-
operating-day rolling average, where the average is to be calculated by
including only the hours during which the unit was dispatched at 50% or
greater of maximum capacity. In this particular case, the 30 boiler-
operating-day rolling average is to be calculated for each unit by the
following procedure: (1) Summing the total pounds of NOX
emitted during the current boiler-operating day and the preceding 29
boiler-operating days, including only emissions during hours when the
unit was dispatched at 50% or greater of maximum capacity; (2) summing
the total heat input in MMBtu to the unit during the current boiler-
operating day and the preceding 29 boiler-operating days, including
only the heat input during hours when the unit was dispatched at 50% or
greater of maximum capacity; and (3) dividing the total pounds of
NOX emitted as calculated in step 1 by the total heat input
to the unit as calculated in step 2.
In addition to the 0.15 lb/MMBtu emission limit that is intended to
control NOX emissions when the units are operated at 50% or
greater of maximum capacity, we are establishing a limit in lb/hr that
applies when the units are operated at lower capacity. The company
suggested an emission limit of 1,342.5 lb/hr on a 30 boiler-operating-
day rolling average applicable at all times regardless of the capacity
at which the unit is operated. Based on the information available to
us, we find that an emission limit of 1,342.5 lb/hr is too high to
appropriately control NOX emissions when the units are
operated at low capacities. It appears that the company calculated the
emission limit by multiplying the 0.15 lb/MMBtu limit by the maximum
heat input rating for each unit (8,950 MMBtu/hr), which yielded 1,342.5
lb/hr. We find that an emission limit of 1,342.5 lb/hr would be
appropriate when the unit is operated at high capacities considering
that the limit was calculated based on the unit's maximum heat input
rating. However, such an emission limit would not be sufficiently
protective or appropriate when the unit is operated at lower capacities
since the mass of NOX emitted is expected to be lower
compared to operation at high capacity. To address this concern, we
calculated a new emission limit of 671 lb/hr that is based on 50% of
the unit's maximum heat input rating, and is applicable only when the
unit is being operated at less than 50% of maximum heat input rating.
We calculated this limit by multiplying 0.15 lb/MMBtu by 50% of the
maximum heat input rating for each unit (i.e., 50% of 8,950 MMBtu/hr,
or 4,475 MMBtu/hr). This emission limit is on a rolling 3-hour average,
where the average is to be calculated by including emissions only for
the hours during which the unit was dispatched at less than 50% of
maximum capacity (i.e., hours when the heat input to the unit is less
than 4,475 MMBtu). We are not establishing a lb/hr emission limit that
applies when the units are operated at 50% or greater of maximum heat
input rating because the 0.15 lb/MMBtu emission limit will address
NOX emission during those operating conditions. We discussed
in our proposal that the cost of LNB/SOFA on White Bluff Units 1 and 2
is estimated to be $350/NOX ton removed for Unit 1 and $340/
NOX ton removed for Unit 2,\43\ which we consider to be very
cost effective, and it would also result in considerable visibility
improvement at the affected Class I areas (see Table 10).\44\
Therefore, we are finalizing the NOX BART emission limits as
described above.
---------------------------------------------------------------------------
\43\ Our cost analysis and visibility modeling analysis for LNB/
SOFA for White Bluff Units 1 and 2, as presented in our proposal, is
based on an emission limit of 0.15 lb/MMBtu on a 30 boiler-
operating-day rolling average. As discussed in this final action, we
received new information from Entergy that indicates that the source
expects to be operating at less than 50% load more frequently and
therefore no longer expects to be able to meet our proposed
NOX emission limit. We are therefore finalizing the
bifurcated NOX emission limit described in this final
action. We recognize that the comments submitted by Entergy indicate
that some of the assumptions used to calculate the cost
effectiveness of NOX controls for White Bluff may not
exactly apply to future operations. However, because we found LNB/
SOFA controls to be very cost effective, we expect that even if the
change in operation of the source were known more precisely and were
taken into account in our calculation of the cost ($/ton), these
controls would continue to be cost effective. Therefore, we are not
revising our cost effectiveness calculations or visibility
improvement modeling of LNB/SOFA for White Bluff Units 1 and 2.
\44\ 80 FR at 18972.
---------------------------------------------------------------------------
As discussed in section V.F. of this final rule, in response to
comments we received, we are shortening the compliance date for the
NOX BART requirement for White Bluff Units 1 and 2 from our
proposed 3 years to 18 months.
Table 10--Entergy White Bluff Units 1 And 2--Summary of the 98th Percentile Visibility Impacts and Improvement
of LNB/SOFA
----------------------------------------------------------------------------------------------------------------
White Bluff Unit 1 White Bluff Unit 2
---------------------------------------------------------------
Baseline Visibility Baseline Visibility
Class I area visibility improvement visibility improvement
impact from baseline impact from baseline
([Delta]dv) ([Delta]dv) ([Delta]dv) ([Delta]dv)
----------------------------------------------------------------------------------------------------------------
Caney Creek..................................... 1.628 0.166 1.695 0.225
Upper Buffalo................................... 1.140 0.101 1.185 0.139
[[Page 66345]]
Hercules-Glades................................. 1.041 0.176 1.060 0.190
Mingo........................................... 0.887 0.038 0.903 0.047
Cumulative Visibility Improvement ([Delta]dv)... .............. 0.481 .............. 0.601
----------------------------------------------------------------------------------------------------------------
In our proposal, we also solicited public comment on any
alternative SO2 and NOX control measures that
could address the regional haze requirements for Entergy White Bluff
Units 1 and 2 and Entergy Independence Units 1 and 2 for this planning
period. We received comments from the company during the public comment
period that proposed one alternative strategy,\45\ but we determined
that this alternative strategy would not adequately address the BART
and reasonable progress requirements for the affected units. We discuss
this issue in more detail elsewhere in this final rule and in our RTC
document.
---------------------------------------------------------------------------
\45\ As described in section I. of this notice, Entergy also
submitted a comment after the close of the comment period,
indicating that Entergy intends that a second alternative described
in the late comment, involving only White Bluff, is a replacement
for the multi-unit alternative previously described in its timely
comments. Because the late comment is not a basis for our decision
making in this final rule, we are responding in this final rule and
in our RTC document to the alternative proposal described in the
comments that Entergy filed during the comment period.
---------------------------------------------------------------------------
e. White Bluff Auxiliary Boiler
We are finalizing our determination that the existing emission
limit of 105.2 lb/hr is BART for SO2, the existing emission
limit of 32.2 lb/hr is BART for NOX, and the existing
emission limit of 4.5 lb/hr is BART for PM for the Auxiliary Boiler. We
do not expect these emission limits to require the installation of
additional controls. We are requiring the White Bluff Auxiliary Boiler
to comply with these emission limits as of the effective date of this
final rule.
f. Entergy Lake Catherine Unit 4
Taking into consideration the BART factors, we are finalizing our
determination that BART for NOX for the natural gas-firing
scenario is an emission limit of 0.22 lb/MMBtu on a 30 boiler-
operating-day rolling average, consistent with the installation and
operation of BOOS. As discussed in more detail in our RTC document, we
are not making changes to the analysis presented in our proposal of the
cost and visibility improvement of this control measure. We discussed
in our proposal that the cost of BOOS on Lake Catherine Unit 4 is
estimated to be $138/NOX ton removed, which we consider to
be very cost effective, and it is also projected to result in
considerable visibility improvement at the affected Class I areas (see
Table 11).\46\ Therefore, we are finalizing the NOX BART
emission limit as proposed. We are requiring the source to comply with
this emission limit no later than 3 years from the effective date of
this final rule.
---------------------------------------------------------------------------
\46\ 80 FR 18944, 18978.
Table 11--Entergy Lake Catherine Unit 4--Summary of the 98th Percentile
Visibility Impacts and Improvement of BOOS
------------------------------------------------------------------------
Baseline Visibility
visibility improvement
Class I area impact from baseline
([Delta]dv) ([Delta]dv)
------------------------------------------------------------------------
Caney Creek............................. 1.371 0.596
Upper Buffalo........................... 0.532 0.248
Hercules-Glades......................... 0.387 0.175
Mingo................................... 0.429 0.196
Cumulative Visibility Improvement .............. 1.215
([Delta]dv)............................
------------------------------------------------------------------------
We are also finalizing our determination that Lake Catherine Unit 4
shall not burn any fuel oil unless or until Arkansas submits a SIP
revision that contains BART determinations for SO2,
NOX, and PM for the fuel oil-firing scenario for Unit 4 and
we approve these BART determinations into the SIP or we promulgate such
BART determinations in a FIP. We are finalizing this determination in
light of the fact that Unit 4 has not combusted any fuel oil in over 10
years and the company's commitment to not burn any fuel oil at Unit 4
until Arkansas submits the SIP revision described above.
g. Domtar Ashdown Mill Power Boiler No. 1
In response to comments received from the company, we are
finalizing an SO2 BART emission limit in the form of lb/day
instead of lb/hr for Power Boiler No. 1. Specifically, we are
finalizing an SO2 BART emission limit of 504 lb/day averaged
over a rolling 30 boiler-operating-day period instead of the proposed
emission limit of 21.0 lb/hr averaged over a rolling 30 boiler-
operating-day period. According to the company, the calculation of
hourly SO2 emissions using hourly fuel throughput
information is not a workable approach for Power Boiler No. 1, where
the practice is to use monthly fuel throughput information that is
reconciled at the end of each month to determine monthly fuel usage.
The company believes an emission limit in terms of lb/day is better
suited to the mill's methodology for determining fuel usage at Power
Boiler No. 1. We agree
[[Page 66346]]
with the company and are finalizing an SO2 BART emission
limit of 504 lb/day averaged over a rolling 30 boiler-operating-day
period. This emission limit is consistent with the Power Boiler's
baseline emissions and would not necessitate additional controls.\47\
We are also finalizing our determination that the mill must demonstrate
compliance with the SO2 BART emission limit by using a site-
specific curve equation (provided to us by the facility) to calculate
SO2 emissions from Power Boiler No. 1 when combusting bark,
and that the mill must confirm the accuracy of the site-specific curve
equation using stack testing.\48\ Further, we are finalizing our
determination that for purposes of demonstrating compliance with the
emission limit for BART for SO2 when combusting fuel oil,
the mill shall assume that the SO2 inlet is equal to the
SO2 being emitted at the stack, where SO2 inlet
is defined to be the SO2 content of the fuel delivered to
the fuel inlet of the combustion chamber.
---------------------------------------------------------------------------
\47\ The lb/day emission limit we are finalizing is a logical
outgrowth of our proposal based on the company's comments, which are
discussed in more detail elsewhere in the final rule and our RTC
document. See Int'l Union, UMW, 407 F.3d at 1259; Fertilizer Inst.,
935 F.2d at 1311; Chocolate Mfrs. Ass'n, 755 F.2d 1098.
\48\ The curve equation is Y = 0.4005 * X-0.2645, where Y =
pounds of sulfur emitted per ton dry fuel feed to the boiler and X =
pounds of sulfur input per ton of dry bark. The purpose of this
equation is to factor in the degree of SO2 scrubbing
provided by the combustion of bark.
---------------------------------------------------------------------------
We are finalizing a NOX BART emission limit of 207.4 lb/
hr for Power Boiler No. 1 as proposed. This emission limit is
consistent with the Power Boiler's baseline emissions, and we expect
that compliance with this emission limit will not necessitate the
installation of additional controls. In response to comments we
received from the company, we are revising our proposed method for
demonstrating compliance with the NOX BART emission limit.
We proposed that, to demonstrate compliance with the NOX
BART emission limit, the facility must conduct annual stack testing.
The company submitted comments stating that it generally agreed that
stack testing was an appropriate method for demonstrating compliance,
but it disagreed that our proposed frequency of an annual stack testing
was appropriate. The company noted that historical NOX stack
test data from 2001-2005 and 2010 for Power Boiler 1 showed the
NOX emissions were fairly consistent. After carefully
considering the company's comments, we agree that the results of these
previous stack tests demonstrate that an annual stack test is not
warranted. Therefore, we are finalizing a requirement that the facility
demonstrate compliance with the NOX BART emission limit for
Power Boiler No. 1 by conducting stack testing once every 5 years,
beginning no later than 1 year from the effective date of our final
action.
In response to comments we received from the company, we are
finalizing one alternative method for demonstrating compliance with the
SO2 and NOX BART emission limits for Power Boiler
No. 1. The company submitted comments stating that it may decide in the
near future to convert Power Boiler No. 1 to burn only natural gas.
After carefully considering the company's comments, we are making the
determination that if the company makes the decision to convert Power
Boiler No. 1 to burn only pipeline quality natural gas and its
preconstruction air permit is revised to reflect that Power Boiler No.
1 is permitted to burn only pipeline quality natural gas, the company
will have demonstrated that the boiler is complying with the
SO2 BART emission limit. Once the air permit is revised to
reflect that Power Boiler No. 1 is allowed to burn only pipeline
quality natural gas, the reporting and recordkeeping requirements
associated with our SO2 BART emission limit would no longer
be applicable. We find this alternative method for demonstrating
compliance with the SO2 BART emission limit to be
appropriate given that SO2 emissions due to natural gas
combustion are negligible. This alternative method for compliance
demonstration will ensure that the facility is not unnecessarily
burdened with calculating SO2 emissions and with
recordkeeping and reporting requirements when SO2 emissions
from Power Boiler No. 1 are anticipated to be negligible. We are also
making the determination that if the preconstruction air permit is
revised to reflect that Power Boiler No. 1 is permitted to burn only
pipeline quality natural gas, the facility may demonstrate compliance
with the NOX emission limit by calculating NOX
emissions using AP-42 emission factors and fuel usage records. Under
this scenario, the facility would not be required to demonstrate
compliance with the NOX BART emission limit for Power Boiler
No. 1 through stack testing. We also note that after the close of the
comment period for our proposal, we became aware that Power Boiler No.
1 has already switched to burn only natural gas and that the facility
submitted a permit renewal application to ADEQ that will reflect that
the power boiler is permitted to burn only natural gas. We believe that
the alternative methods for compliance demonstration we are finalizing
are appropriate and addresses the mill's concerns.\49\
---------------------------------------------------------------------------
\49\ The alternative methods for demonstrating compliance we are
finalizing for Power Boiler No. 1 are a logical outgrowth of our
proposal based on the company's comments, which are discussed in
more detail elsewhere in the final rule and our RTC document. See
Int'l Union,UMW, 407 F.3d at 1259; Fertilizer Inst., 935 F.2d at
1311; Chocolate Mfrs. Ass'n, 755 F.2d 1098.
---------------------------------------------------------------------------
In response to comments we received from the company, we are
revising our definition of ``boiler-operating-day'' as it applies to
Power Boilers Nos. 1 and 2 under this FIP. The company commented that
for mill operation purposes, it defines boiler-operating-day as ``a 24-
hr period between 6 a.m. and 6 a.m. the following day during which any
fuel is fed into and/or combusted at any time in the power boiler.''
After carefully considering the comment, we agree with the company that
it is reasonable and appropriate to harmonize our definition of a
boiler-operating day with that of the mill to avoid any unnecessary
modification or reprogramming of Power Boilers 1 and 2. Therefore, for
purposes of BART for Power Boilers No. 1 and 2, we are defining a
boiler-operating-day as a 24-hour period between 6 a.m. and 6 a.m. the
following day during which any fuel is fed into and/or combusted at any
time in the power boiler. The 30-day rolling average for Power Boiler
No. 1 shall be determined by adding together the pounds of
SO2 from that boiler-operating-day and the preceding 29
boiler-operating-days and dividing the total pounds of SO2
by the sum of the total number of boiler operating days (i.e., 30). The
result will be the 30 boiler-operating-day rolling average in terms of
lb/day emissions of SO2.\50\
---------------------------------------------------------------------------
\50\ The revised definition of ``boiler operating day'' as it
applies to these two units is a logical outgrowth of our proposal
based on the company's comments, which are discussed in more detail
elsewhere in the final rule and our RTC document. See Int'l
Union,UMW, 407 F.3d at 1259; Fertilizer Inst. v. EPA, 935 F.2d at
1311; and Chocolate Mfrs. Ass'n, 755 F.2d 1098.
---------------------------------------------------------------------------
In response to comments we received from the company, we are also
revising our proposed compliance dates for SO2 and
NOX BART for Power Boiler No. 1. The company submitted
comments requesting that we finalize a compliance date of 30 days after
the effective date of the final rule instead of requiring the source to
comply with BART as of the effective date of the final rule. The
company noted this would provide additional time for it to prepare
compliance records. We determined that the company's request is
reasonable and
[[Page 66347]]
would allow the mill to prepare applicable compliance records and
adjust recordkeeping systems without unduly delaying compliance with
the BART emission limits. Therefore, we are requiring Power Boiler No.
1 to comply with the SO2 and NOX BART emission
limits no later than 30 days from the effective date of this final
rule.\51\
---------------------------------------------------------------------------
\51\ The revised compliance date is a logical outgrowth of our
proposal based on the company's comments. See Int'l Union,UMW, 407
F.3d at 1259; Fertilizer Inst, 935 F.2d at 1311; and Chocolate Mfrs.
Ass'n, 755 F.2d 1098.
---------------------------------------------------------------------------
h. Domtar Ashdown Mill Power Boiler No. 2
In response to comments we received from the company, we are
finalizing an emission limit of 91.5 lb/hr based on a 30 boiler-
operating-day rolling average instead of 0.11 lb/MMBtu. As discussed in
our proposal, Domtar provided monthly average data for 2011, 2012, and
2013 on monitored SO2 emissions from Power Boiler No. 2,
mass of the fuel burned for each fuel type, and the percent sulfur
content of each fuel type burned.\52\ Based on the information provided
by Domtar, we found that the monthly average SO2 control
efficiency of the existing venturi scrubbers for the 2011-2013 period
ranged from 57% to 90%. The information provided also indicated that
the facility could add more scrubbing solution to achieve greater
SO2 removal than what is currently being achieved. We
proposed that it is feasible for the facility to use additional
scrubbing solution to consistently achieve at least a 90%
SO2 removal on a monthly average basis. To determine the
controlled emission rate that corresponds to the operation of the
existing venturi scrubbers at a 90% removal efficiency, we first
determined the SO2 emission rate that corresponds to the
operation of the scrubbers at the current average control efficiency
(i.e., baseline control efficiency) of approximately 69%. Based on the
emissions data provided by Domtar, we determined that Power Boiler No.
2's annual average SO2 emission rate for the years 2011-2013
was 280.9 lb/hr. This annual average SO2 emission rate
corresponds to the operation of the scrubbers at a 69% removal
efficiency. We also estimated that 100% uncontrolled emissions would
correspond to an emission rate of approximately 915 lb/hr. Application
of a 90% control efficiency to the uncontrolled rate results in a
controlled emission rate of 91.5 lb/hr, or 0.11 lb/MMBtu based on the
boiler's maximum heat input of 820 MMBtu.\53\ We thus proposed that
BART for SO2 for Power Boiler No. 2 is an emission limit of
0.11 lb/MMBtu on a 30 boiler-operating-day rolling average.
---------------------------------------------------------------------------
\52\ 80 FR 18944, 18984.
\53\ 80 FR at 18984.
---------------------------------------------------------------------------
During the public comment period, the company submitted comments
requesting that we finalize an SO2 BART emission limit that
is on a lb/hr basis instead of lb/MMBtu. The company correctly noted
that we used the boiler's maximum heat input rating of 820 MMBtu/hr to
determine the proposed emission limit in terms of lb/MMBtu. The company
brought to our attention that the use of the maximum heat input rating
is not representative of typical boiler operating conditions, which are
lower than the maximum heat input capability. We have determined that
finalizing an emission limit in terms of lb/hr is appropriate and will
address the company's concern.\54\ Therefore, we are finalizing an
SO2 emission limit of 91.5 lb/hr on a 30 boiler-operating-
day rolling average for Power Boiler No. 2. Because the SO2
emission limit we are finalizing is based on converting our proposed
emission limit of 0.11 lb/MMBtu to an emission limit in the form of lb/
hr, we find that our final emission limit is expected to achieve the
same level of SO2 reduction as 0.11 lb/MMBtu, which is what
we assumed in our analysis of cost and visibility improvement.
Therefore, we are not making changes to the analysis we presented in
our proposal of the cost and visibility improvement of this control
measure.\55\ The use of additional scrubbing reagent with scrubber pump
upgrades on the existing venturi scrubbers to meet an emission limit of
91.5 lb/hr is estimated to cost $1,411/SO2 ton removed, and
it is projected to result in considerable visibility improvement at the
affected Class I areas (see Table 12). Taking into consideration the
BART factors, we are finalizing this SO2 emission limit. In
response to comments we received from the company, we are also revising
our definition of ``boiler-operating-day'' as it applies to Power
Boilers No. 1 and 2 for BART purposes.
---------------------------------------------------------------------------
\54\ The lb/hr emission limits we are finalizing is a logical
outgrowth of our proposal based on the company's comments, which are
discussed in more detail elsewhere in the final rule and our RTC
document. See Int'l Union,UMW, 407 F.3d at 1259; Fertilizer Inst,
935 F.2d at 1311; and Chocolate Mfrs. Ass'n, 755 F.2d 1098.
\55\ 80 FR at 18984, 18985.
Table 12--Domtar Power Boiler No. 2--Summary of the 98th Percentile
Visibility Impacts and Improvement of Using Additional Scrubbing Reagent/
Scrubber Pump Upgrades
------------------------------------------------------------------------
Estimated
Baseline visibility
Class I area visibility improvement
impact from baseline
([Delta]dv) ([Delta]dv)
------------------------------------------------------------------------
Caney Creek............................. 0.844 0.139
Upper Buffalo........................... 0.146 0.05
Hercules-Glades......................... 0.105 0.048
Mingo................................... 0.065 0.025
Cumulative Visibility Improvement .............. 0.262
([Delta]dv)............................
------------------------------------------------------------------------
We also received comments from Domtar expressing uncertainty as to
whether our proposed SO2 emission limit for Power Boiler No.
2 can be met by upgrading the scrubber pumps and using additional
scrubbing solution to consistently achieve our proposed SO2
emission limit. However, we have determined that aside from expressing
general uncertainty, Domtar did not provide any information that
demonstrates that it is not technically feasible to meet our proposed
SO2 emission limit, which is based on a 30 boiler-operating-
day rolling average. We also received comments from Domtar disagreeing
with our use of 2011-2013 as the baseline years for calculating our
proposed SO2 emission limit for Power Boiler No. 2. Domtar
asked that we instead use 2001-2003 as the baseline period for
calculating the SO2 emission limit, which would result in an
emission limit of 155 lb/hr instead of
[[Page 66348]]
91.5 lb/hr. Domtar pointed out that in more recent years (after the
2001-2003 period), the mill voluntarily reduced its SO2
emissions and that using a more recent period to calculate the BART
emission limit results in a more stringent emission limit.
As discussed in more detail elsewhere in this final rule and in our
RTC document, we disagree that it is appropriate to use 2001-2003 as
the baseline period for purposes of calculating the SO2 BART
emission limit for Power Boiler No. 2. One of the factors we are
required to take into consideration in making a BART determination is
whether there is any existing pollution control equipment in use at the
source. Power Boiler No. 2 is currently equipped with venturi scrubbers
for control of SO2 emissions, and in our BART analysis, we
evaluated upgrades to the existing scrubbers. As we discussed in our
proposal, in determining whether upgrades to the existing scrubbers are
technically feasible and whether additional SO2 control
could be achieved, it was necessary for us to first determine the
current control efficiency of the scrubbers. For purposes of
determining the current control efficiency of the scrubbers, we believe
the most reasonable and appropriate approach is to rely on recent data
instead of older data from the 2001-2003 period. Therefore, we relied
on 2011-2013 monthly average data on monitored SO2
emissions, records of mass of fuel burned for each fuel type, and the
percent sulfur content of each fuel type burned to estimate the current
average control efficiency (i.e., baseline control efficiency) of the
scrubbers, which we found to be approximately 69%. We find that because
the baseline control efficiency of the existing scrubbers (i.e., 69%)
corresponds to emissions data from 2011-2013, it is reasonable and
appropriate to rely on emissions data from the same period to calculate
the emission limit that corresponds to increasing the control
efficiency from the baseline level of approximately 69% up to 90%.
Therefore, we are not using 2001-2003 as the baseline period for
purposes of calculating the SO2 emission limit for Power
Boiler No. 2.
We proposed to require the facility to demonstrate compliance with
the SO2 emission limit for Power Boiler No. 2 using the
existing CEMS. We are finalizing this method for demonstrating
compliance with the SO2 BART emission limit for Power Boiler
No. 2. During the public comment period for our proposal, Domtar
submitted comments stating that due to a repurposing project the mill
is currently undergoing, the mill's steam demands may change and Power
Boiler No. 2 may be converted to burn only natural gas, mothballed, or
shut down in the near future. After carefully considering the comments
submitted to us, we have determined that in light of the repurposing
project the mill is currently undergoing and the possibility of Power
Boiler No. 2 being converted to burn only natural gas, it is
appropriate to provide the facility with flexibility in how it must
demonstrate compliance with the SO2 emission limit for Power
Boiler No. 2. Therefore, we are providing one alternative method for
demonstrating compliance with the SO2 BART emission limit:
The owner or operator may demonstrate compliance with this emission
limit by switching Power Boiler No. 2 to burn only pipeline quality
natural gas provided that the preconstruction air permit is revised so
as to permit combustion of only pipeline quality natural gas at Power
Boiler No. 2. Therefore, if Power Boiler No. 2 is switched to burn only
pipeline quality natural gas and the company's air permit is revised to
reflect this, it would satisfy the requirement for demonstrating
compliance with the boiler's SO2 BART emission limit, and
the related reporting and recordkeeping requirements would not be
applicable.\56\
---------------------------------------------------------------------------
\56\ The alternative method to demonstrate compliance with the
SO2 emission limit is a logical outgrowth of our proposal
based on the company's comments, which are discussed in more detail
elsewhere in the final rule and our RTC document. See Int'l Union,
UMW, 407 F.3d at 1259; Fertilizer Inst, 935 F.2d at 1311; and
Chocolate Mfrs. Ass'n, 755 F.2d 1098.
---------------------------------------------------------------------------
Taking into consideration the BART factors, we are finalizing our
determination that BART for NOX for Power Boiler No. 2 is an
emission limit of 345 lb/hr on a 30 boiler-operating-day rolling
average basis, which is consistent with the installation and operation
of LNB. We are not making changes to the analysis we presented in our
proposal of the cost and visibility improvement of this control
measure.\57\ As discussed in our proposal, the cost of LNB on Power
Boiler No. 2 is estimated to cost $1,951/NOX ton removed,
and it is projected to result in considerable visibility improvement at
the most impacted Class I area (see Table 13). We are finalizing this
NOX emission limit as proposed.
---------------------------------------------------------------------------
\57\ 80 FR 18944, 18987.
Table 13--Domtar Power Boiler No. 2--Summary of the 98th Percentile
Visibility Impacts and Improvement of LNB
------------------------------------------------------------------------
Estimated
Baseline visibility
Class I area visibility improvement
impact from baseline
([Delta]dv) ([Delta]dv)
------------------------------------------------------------------------
Caney Creek............................. 0.844 0.181
Upper Buffalo........................... 0.146 0.014
Hercules-Glades......................... 0.105 0.011
Mingo................................... 0.065 0.005
Cumulative Visibility Improvement .............. 0.211
([Delta]dv)............................
------------------------------------------------------------------------
We proposed to require the facility to demonstrate compliance with
this NOX emission limit using the existing CEMS. We are
finalizing this method for demonstrating compliance. As discussed
above, during the public comment period for our proposal, Domtar
submitted comments stating that due to a repurposing project the mill
is currently undergoing, the mill's steam demands may change and Power
Boiler No. 2 may be converted to burn only natural gas, mothballed, or
shut down in the near future. After carefully considering the comments
submitted to us, we have determined that it is appropriate to provide
the facility with flexibility in how it must demonstrate compliance
with the NOX emission limit for Power Boiler No. 2.
Therefore, we are providing one alternative method
[[Page 66349]]
for demonstrating compliance with the NOX BART emission
limit: If Power Boiler No. 2 is switched to burn only natural gas and
the facility's preconstruction air permit is revised such that Power
Boiler No. 2 is permitted to burn only natural gas, the facility may
demonstrate compliance with the NOX emission limit by
calculating emissions using AP-42 emission factors and fuel usage
records provided that the operation of the CEMS is no longer required
by any other applicable requirements. Under these circumstances, the
facility would not be required to use the existing CEMS to demonstrate
compliance with the NOX BART emission limit.\58\
---------------------------------------------------------------------------
\58\ The alternative method to demonstrate compliance with the
NOX emission limit is a logical outgrowth of our proposal
based on the company's comments, which are discussed in more detail
elsewhere in the final rule and our RTC document. See Int'l Union,
UMW, 407 F.3d at 1259; Fertilizer Inst, 935 F.2d at 1311; and
Chocolate Mfrs. Ass'n, 755 F.2d 1098.
---------------------------------------------------------------------------
As discussed above, in response to comments we received from
Domtar, we are also revising our definition of ``boiler-operating-day''
as it applies to Power Boilers No. 1 and 2 for BART purposes. For
purposes of SO2 and NOX BART for Power Boilers
No. 1 and 2, we are defining a boiler-operating-day as a 24-hour period
between 6 a.m. and 6 a.m. the following day during which any fuel is
fed into and/or combusted at any time in the power boiler.
We proposed to require the Domtar Ashdown Mill to comply with the
SO2 and NOX BART emission limits no later than 3
years from the effective date of our final action, but invited public
comment on this issue in our proposal. We received comments from Domtar
requesting that we finalize a 5-year compliance date in light of the
repurposing project the mill is currently undergoing. The repurposing
project involves converting a non-BART paper machine at the mill into a
fluff pulp line and may significantly affect the mill's steam demands
and ultimately determine the future operating scenario for Power Boiler
No. 2. The comments submitted by Domtar indicate that after the
repurposing and reconfiguration of the mill systems is complete and
fully operational and the mill has learned how to operate and optimize
in its newly configured state, it will be able to determine steam
demands and will then decide the future operating scenario for Power
Boiler No. 2. Our understanding from the comments submitted is that
this decision is expected to be made in late 2018, but that additional
time will be needed after this to implement the future operating
scenario selected by the mill for Power Boiler No. 2, which could
include switching fuels, mothballing or retiring the boilers, or
continued operation under current operating conditions. It is not EPA's
intention to place an undue burden on the Domtar Ashdown Mill by
requiring a compliance date that may not provide sufficient time for
the mill to install controls or otherwise make the necessary operating
changes to meet the boiler's BART emission limits after it has made a
final decision on the future operating scenario for Power Boiler No. 2.
We believe that a 3-year compliance date is generally sufficient for
installation of the controls that the SO2 and NOX
BART emission limits we are requiring can be achieved with. However,
due to the special circumstances in this case, which we discuss in
section V.E of this final rule, we believe it is reasonable and
appropriate to establish a longer compliance date. Therefore, we are
requiring the mill to comply with the SO2 and NOX
BART emission limits no later than 5 years from the effective date of
this final rule. We believe that this adequately addresses the
commenter's concerns while complying with the CAA mandate that
compliance with BART requirements must be as expeditiously as
practicable, but in no event later than 5 years after promulgation of
this FIP.
We are finalizing our determination that Domtar must satisfy the PM
BART requirement by relying on the applicable Boiler MACT PM standard
as revised.\59\ We proposed that the same method for demonstrating
compliance with the Boiler MACT PM standard must be used for
demonstrating compliance with the PM BART emission limit. We proposed
to require the source to comply with this emission limit for BART
purposes as of the effective date of the final rule. During the public
comment period, we received comments from Domtar seeking clarification
regarding the requirements for compliance demonstration, reporting, and
recordkeeping for our proposed PM BART determination for Power Boiler
No. 2. Domtar requested that we ensure that the requirements for
compliance demonstration, testing, reporting, and recordkeeping under
the Boiler MACT standard for PM are consistent with those associated
with the PM BART emission limit for Power Boiler No. 2. As the Domtar
Ashdown Mill will be relying on compliance with the Boiler MACT PM
standard to satisfy the PM BART requirement for Power Boiler No. 2, we
believe that there is no need for a separate set of requirements for
compliance demonstration, testing, monitoring, recordkeeping, and
reporting to satisfy the PM BART requirement. This was our position at
proposal, but we recognize that the regulatory text in our proposal may
not have conveyed this clearly. Therefore, to provide clarification, we
are revising the regulatory requirements of our FIP found under 40 CFR
52.173(c) that apply to Power Boiler No. 2 for PM BART to state that
the mill shall rely on compliance with the Boiler MACT PM standard
under 40 CFR part 63 Subpart DDDDD to satisfy the PM BART requirement
for Power Boiler No. 2. In other words, compliance with the Boiler MACT
PM standard applicable to Power Boiler No. 2 is sufficient to
demonstrate compliance with the PM BART requirement. Additionally, we
are also clarifying that Power Boiler No. 2 must satisfy the PM BART
requirement by relying on the Boiler MACT PM standard that it is
subject to at any given time, such that if the MACT PM standard and/or
the compliance demonstration and recordkeeping requirements are revised
in the future, the boiler must rely on those revised requirements to
satisfy the PM BART requirement.
---------------------------------------------------------------------------
\59\ Boiler MACT standards are required under CAA section 112,
and are found at 40 CFR part 63, subpart DDDDD--National Emission
Standards for Hazardous Air Pollutants for Major Sources:
Industrial, Commercial, and Institutional Boilers and Process
Heaters.
---------------------------------------------------------------------------
In response to comments we received from the company, we are
revising our proposed compliance date for PM BART for Power Boiler No.
2. The company submitted comments requesting that we finalize a
compliance date of 30 days after the effective date of the final rule
instead of requiring the source to comply with BART as of the effective
date of the final rule. The company noted that this would provide
additional time for it to prepare compliance records. We determined
that the company's request is reasonable and would provide the mill
with additional time to understand the applicable BART requirements and
to prepare compliance records and adjust recordkeeping systems without
unduly delaying compliance with the BART emission limit. Therefore, we
are requiring Power Boiler No. 2 to comply with the PM BART emission
limit no later than 30 days from the effective date of this final
rule.\60\
---------------------------------------------------------------------------
\60\ The revised compliance date is a logical outgrowth of our
proposal based on the company's comments, which are discussed in
more detail elsewhere in the final rule and our RTC document.
---------------------------------------------------------------------------
[[Page 66350]]
3. Reasonable Progress Analysis
a. Four-Factor Analysis
In our proposed rule, we explained that the CENRAP CAMx modeling
with PSAT showed that sulfate from all source categories combined
contributed 87.05 inverse megameters (Mm-\1\) out of 133.93
Mm-\1\ of light extinction at Caney Creek on the average
across the 20% worst days in 2002, which is approximately 65% of the
total light extinction. At Upper Buffalo, sulfate from all source
categories combined contributed 83.18 Mm-\1\ out of 131.79
Mm-\1\ of light extinction at Upper Buffalo on the average
across the 20% worst days in 2002, which is approximately 63% of the
total light extinction. Nitrate from all source categories combined
contributed 13.78 Mm-\1\ out of 133.93 Mm-\1\ of
light extinction at Caney Creek and 13.30 Mm-\1\ out of
131.79 Mm-\1\ of light extinction at Upper Buffalo, which is
approximately 10% of the total light extinction at each Class I area on
the average across the 20% worst days in 2002. The CENRAP CAMx modeling
showed that on most of the 20% worst days in 2002, total extinction was
dominated by sulfate at both Caney Creek and Upper Buffalo.\61\
Additionally, total extinction at Caney Creek was dominated by nitrate
on 4 of the days that comprise the 20% worst days in 2002, while a
significant portion of the total extinction at Upper Buffalo on 2 of
the days that comprise the 20% worst days in 2002 was due to
nitrate.\62\ Given their contribution to visibility impairment on the
20% worst days, we consider both SO2 and NOX to
be key pollutants contributing to visibility impairment at Arkansas
Class I areas, so it is appropriate to consider both SO2 and
NOX controls in our reasonable progress analysis.
---------------------------------------------------------------------------
\61\ See Arkansas Regional Haze SIP, Appendix 8.1--``Technical
Support Document for CENRAP Emissions and Air Quality Modeling to
Support Regional Haze State Implementation Plans,'' sections 3.7.1
and 3.7.2. See the docket for this rulemaking for a copy of the
Arkansas Regional Haze SIP.
\62\ See Arkansas Regional Haze SIP, Appendix 8.1--``Technical
Support Document for CENRAP Emissions and Air Quality Modeling to
Support Regional Haze State Implementation Plans,'' section 3.7.1
and 3.7.2. See the docket for this rulemaking for a copy of the
Arkansas Regional Haze SIP.
---------------------------------------------------------------------------
In our proposal, we explained that point sources are responsible
for a majority of the total light extinction at each Class I area,
contributing approximately 60% of the total light extinction. Point
sources contributed 81.04 Mm-\1\ out of 133.93
Mm-\1\ of light extinction at Caney Creek and 77.80
Mm-\1\ out of 131.79 Mm-\1\ of light extinction
at Upper Buffalo on the average across the 20% worst days in 2002.
Because other source types (i.e., natural, on-road, non-road, and area)
each contributed a much smaller proportion of the total light
extinction at each Class I area, we decided to focus only on point
sources in our reasonable progress analysis for this planning period.
Sulfate from point sources contributed 75.1 Mm-\1\ out of
133.93 Mm-\1\ of light extinction at Caney Creek and 72.17
Mm-\1\ out of 131.79 Mm-\1\ of light extinction
at Upper Buffalo on the average across the 20% worst days in 2002,
which is approximately 56% of the total light extinction at Caney Creek
and 55% of the total light extinction at Upper Buffalo. Nitrate from
point sources contributed 4.06 Mm-\1\ out of 133.93
Mm-\1\ of light extinction at Caney Creek and 3.93
Mm-\1\ out of 131.79 Mm-\1\ of light extinction
at Upper Buffalo, which is approximately 3% of the total light
extinction at each Class I area. Sulfate from Arkansas point sources
contributed 2.20% of the total light extinction at Caney Creek and
1.99% at Upper Buffalo, and nitrate from Arkansas point sources
contributed 0.27% of the total light extinction at Caney Creek and
0.14% at Upper Buffalo. We explained in our proposal that
SO2 emissions (a sulfate precursor) are the principal driver
of regional haze on the 20% worst days in Arkansas' Class I areas, as
visibility impairment in 2002 on the 20% worst days was largely due to
sulfate from point sources. We also explained that on the 20% worst
days in 2018, sulfate from Arkansas' point sources is projected to
contribute 3.58% of the total light extinction at Caney Creek and 3.20%
at Upper Buffalo, while nitrate from Arkansas' point sources is
projected to contribute 0.29% of the total light extinction at Caney
Creek and 0.25% at Upper Buffalo. Based on the CENRAP 2018 visibility
projections, sulfate from point sources is expected to continue being
the principal driver of regional haze on the 20% worst days at
Arkansas' Class I areas.
As a starting point in our analysis to determine whether additional
controls on Arkansas sources are necessary to make reasonable progress
in the first regional haze planning period, we examined the most recent
SO2 and NOX emissions inventories for point
sources in Arkansas. In our examination of the SO2 and
NOX emissions inventories for Arkansas' point sources, we
found that the number of point sources in Arkansas that emit
SO2 and NOX emissions is relatively small.
Furthermore, a very small portion of the point sources in the state are
responsible for a large portion of the statewide SO2 and
NOX point-source emissions. Specifically, White Bluff,
Independence, and Flint Creek are the three largest emitters of
SO2 and NOX point-source emissions in the state
and are collectively responsible for approximately 84% of the
SO2 point source emissions and 55% of the NOX
point-source emissions in the state.\63\ As our proposed rule included
SO2 and NOX emission limits under BART for White
Bluff Units 1 and 2 and Flint Creek Unit 1 that are anticipated to
result in a substantial reduction in SO2 and NOX
emissions from these facilities, we proposed to determine that it is
appropriate to eliminate these two facilities from further
consideration of additional controls under the reasonable progress
requirements for the first planning period. The Entergy Independence
Plant is not subject to BART, and its emissions were 30,398
SO2 tpy and 13,411 NOX tpy based on the 2011 NEI.
The Entergy Independence Plant is the second largest source of
SO2 and NOX point-source emissions in Arkansas,
accounting for approximately 36% of the SO2 point-source
emissions and 21% of the NOX point-source emissions in the
state. In our proposal, we explained that it was appropriate to focus
our reasonable progress analysis on the Entergy Independence Power
Plant because it is a significant source of SO2 and
NOX as the second largest emitter of NOX and
SO2 point-source emissions in the State. Consequently,
addressing White Bluff and AEP Flint Creek under the BART requirements
and Independence under the reasonable progress requirements will
address a large proportion of the visibility impacts due to Arkansas
point sources at Caney Creek and Upper Buffalo.
---------------------------------------------------------------------------
\63\ 80 FR 18944, 18991.
---------------------------------------------------------------------------
We also found that the remaining point sources in the state had
much lower SO2 and NOX emissions than these
facilities. For example, the point source with the fourth highest
SO2 emissions is Future Fuel Chemical Company, which
contributes approximately 4.1% of the total SO2 point-source
emissions in the state (i.e., 3,420 SO2 tons out of
statewide SO2 point source emissions of 83,883
SO2 tons). The point source with the fourth highest
NOX emissions is the Natural Gas Pipeline Company of America
#308, which contributes approximately 5.1% of the total NOX
point source emissions in the state (i.e., 3,194 NOX tons
out of statewide NOX point source emissions of 62,984
NOX tons). Based on the much smaller magnitude of these
sources'
[[Page 66351]]
emissions, we determined that the remaining point sources in the state
are less likely to be significant contributors to regional haze (both
on an actual and percentage basis) and thus did not warrant closer
evaluation during this planning period. Because such a small number of
point sources in Arkansas are responsible for a such large portion of
the statewide SO2 and NOX point-source emissions
in the state, we concluded that photochemical modeling or other more
exhaustive analyses that we have performed in other regional haze
actions were unnecessary to identify sources in Arkansas to evaluate
under reasonable progress. In contrast, in states such as Texas where
the universe of point sources is much larger and the distribution of
SO2 and NOX emissions is very widespread, an
evaluation of the state's emissions inventory alone was not sufficient
to reveal the best potential candidates for evaluation under reasonable
progress. For this reason, we explained in our Texas Regional Haze FIP
that, due to the challenges presented by the geographic distribution
and number of sources in Texas, the CAMx photochemical model was best
suited for identifying sources to evaluate for reasonable progress
controls.\64\ We did not encounter these challenges in our Arkansas
Regional Haze FIP and therefore did not conduct photochemical modeling.
---------------------------------------------------------------------------
\64\ 81 FR 296 (January 5, 2016).
---------------------------------------------------------------------------
In our reasonable progress analysis for Independence, we considered
the four statutory factors under CAA section 169A(g)(1) and 40 CFR
51.308(d)(1)(i)(A): The costs of compliance, the time necessary for
compliance, the energy and nonair quality environmental impacts of
compliance, and the remaining useful life of any existing source
subject to such requirements. Alongside the four statutory factors, we
also considered the visibility improvement of controls. Although
visibility is not one of the four mandatory factors explicitly listed
for consideration under CAA section 169A(g)(1) or 40 CFR
51.308(d)(1)(i)(A), states or EPA have the option of considering the
projected visibility benefits of controls in determining if the
controls are necessary to make reasonable progress. In our proposal, we
explained that SO2 emissions are the principal driver of
regional haze on the 20% worst days in Arkansas' Class I areas. While
point source NOX emissions are not the principal contributor
to visibility extinction on the 20% worst days at Arkansas' Class I
areas, NOX is nevertheless a key pollutant since
NOX emissions contributed considerably to visibility
impairment on a portion of the 20% worst days in 2002 based on CENRAP's
CAMx source apportionment modeling. Further, our assessment of the
Independence facility using CALPUFF dispersion modeling, which assesses
the 98th percentile visibility impairment caused by the facility,
indicated that Independence is potentially one of the largest single
contributors to visibility impairment at Class I areas in Arkansas.\65\
Therefore, we determined that it was appropriate to evaluate the
Independence facility for both SO2 and NOX
controls under reasonable progress.
---------------------------------------------------------------------------
\65\ 80 FR 24872.
---------------------------------------------------------------------------
Based on our reasonable progress analysis under 40 CFR
51.308(d)(1), we discussed in our proposal that SO2 and
NOX controls at Independence would be cost-effective and
would result in meaningful visibility benefits at Arkansas' Class I
areas based on the maximum (98th percentile) facility impacts using
CALPUFF dispersion modeling. Although the reasonable progress
provisions of the Regional Haze Rule place emphasis on the 20% worst
days, the CAA goal of remedying visibility impairment due to
anthropogenic emissions encompasses all days. Thus, states and EPA have
the discretion to consider the visibility impacts of sources and the
visibility benefit of controls on days other than the 20% worst days in
making their decisions, such as the days on which a given facility has
its own largest impacts. Even if the days on which a given facility has
its largest impacts are not the same as the 20% of days with the worst
visibility overall, the facility's impacts will still need to be
addressed for Arkansas' Class I areas to achieve the goal of natural
visibility conditions. The Eighth Circuit previously addressed state
and EPA use of CALPUFF for reasonable progress purposes.\66\
---------------------------------------------------------------------------
\66\ North Dakota v. EPA, 730 F.3d 750, 764-66 (8th Cir. 2013)
(discussing reasonable progress determination for the Antelope
Valley station).
---------------------------------------------------------------------------
Based on our consideration of the four reasonable progress factors
and the visibility impacts from Independence and the visibility
improvement of controls, we proposed two alternative options for
reducing emissions at Independence Units 1 and 2. Under Option 1, we
proposed to require both SO2 and NOX controls.
Under Option 2, we proposed to require only SO2 controls. We
solicited public comment on our two proposed options. In addition to
Options 1 and 2, we also solicited public comment on any alternative
SO2 and NOX control measures that could address
the regional haze requirements for White Bluff Units 1 and 2 and
Independence Units 1 and 2 for this planning period.
We received many comments opposed to our proposal to establish any
controls on Independence to achieve reasonable progress. Many of these
comments stated that it was not necessary to control or even evaluate
Arkansas' sources under the CAA and Regional Haze Rule's reasonable
progress requirements because Arkansas' Class I areas are projected to
be below the uniform rate of progress (URP) in 2018 and because
Arkansas' Class I areas are on track to meet the RPGs established by
the state in the Arkansas Regional Haze SIP. As discussed in section
V.C. of this final rule and in our RTC document, we have an obligation
under the CAA and the Regional Haze Rule to conduct an analysis of the
four reasonable progress factors. This obligation applies even when a
Class I area is below the URP and even when monitoring data show that a
Class I area is meeting or is projected to meet the RPG previously
established by the state. The CAA and Regional Haze Rule are clear that
the determination of what controls are necessary to make reasonable
progress (and whose emission reductions dictate the RPGs) must be
determined based on the four-factor analysis. See CAA section
169A(b)(2) & (g)(1); 40 CFR 51.308(d)(1)(i). Neither the CAA nor the
Regional Haze Rule divest states or EPA of the authority and obligation
to conduct a four-factor analysis for sources contributing
significantly to visibility impairment based on existing or projected
future visibility conditions at affected Class I areas. We discussed
above and also in section V of this final rule that our four factor
analysis focused on the Independence Plant because it is a significant
source of visibility impairing pollutants, as it is the second largest
source of SO2 and NOX point-source emissions in
Arkansas.\67\ The largest and third largest sources of SO2
and NOX point-source emissions in Arkansas are White Bluff
and Flint Creek, for which we are requiring controls under the BART
requirements in this final rule. In comparison to the SO2
and NOX emissions from the three largest point sources
(i.e., White Bluff, Independence, and Flint Creek), emissions from the
remaining point sources in the state are relatively small and are less
likely to be significant contributors to regional haze, both on an
actual and percentage basis. Therefore,
[[Page 66352]]
our reasonable progress analysis focused on the Independence Plant. As
discussed in our proposal and throughout this final notice, based on
our analysis of the four reasonable progress factors and our
consideration of the baseline visibility impacts from Independence and
the visibility improvement of potential controls, we determined that
SO2 and NOX controls at Independence would be
cost-effective and would result in meaningful visibility benefits at
Arkansas' Class I areas, and therefore find that they are reasonable
controls and are necessary to make reasonable progress.
---------------------------------------------------------------------------
\67\ The Independence Plant accounts for approximately 36% of
the SO2 point-source emissions and 21% of the
NOX point-source emissions in Arkansas (2011 NEI).
---------------------------------------------------------------------------
Other comments we received stated that Arkansas' point sources have
a very small impact on visibility impairment at Arkansas' Class I areas
on the 20% worst days and that we should therefore not require any
controls at Independence under the reasonable progress requirements. At
a minimum, these commenters argued, the contribution to visibility
impairment at Arkansas' Class I areas on the 20% worst days from point-
source nitrate emissions was insignificant, so NOX controls
for Independence were unnecessary. After carefully considering these
comments, we continue to believe that Arkansas' point sources have a
significant contribution to visibility impairment at Arkansas Class I
areas on the 20% worst days. As we discuss in section V.J. of this
final rule, CAMx source apportionment modeling conducted by Entergy
Arkansas Inc.\68\ (Entergy) and submitted to us during the public
comment period showed that the contribution to visibility impairment
due to emissions from the Independence facility alone are projected to
be approximately 1.3% of the total visibility impairment during the 20%
worst days in 2018 at each Arkansas Class I area. Considering that the
CAMx photochemical modeling takes into account the emissions of
thousands of sources, both in Arkansas and outside of the state, we
consider this to be a significant contribution to visibility impairment
at each Class I area and a large portion (approximately one-third) of
the total contribution from all Arkansas point sources that can be
addressed through installation of controls on two units at a single
facility. The CAMx modeling also showed that at Upper Buffalo, the
Independence facility's contribution to visibility impairment is
greater than the contribution from all of the subject-to-BART sources
addressed in this final action combined. In terms of deciviews, the
average impact from Independence over the 20% worst days, based on
Entergy's CAMx modeling and adjusted to natural background conditions,
is over 0.5 dv at each of the Arkansas Class I areas. Together, the
modeling results from Entergy's CAMx modeling and the CALPUFF modeling
demonstrate that controls will provide meaningful visibility benefits
toward the goal of natural visibility conditions.
---------------------------------------------------------------------------
\68\ Entergy Arkansas Inc. is one of the owners of White Bluff
Units 1 and 2 and Independence Units 1 and 2. The company submitted
CAMx photochemical modeling as part of its comments submitted during
the public comment period. These and all other comments we received
are found in the docket associated with this rulemaking.
---------------------------------------------------------------------------
While the majority of the visibility impacts due to Independence on
the 20% worst days are due to SO2, we note that
NOX emissions from the facility also have impacts on the 20%
worst days. The CAMx source apportionment modeling submitted by Entergy
showed that NOX emissions from Independence are responsible
for 30-40% of the visibility impairment in Arkansas' Class I areas on 2
of the 20% worst days (i.e., 2 out of the 21 days that are the 20%
worst of the days with Interagency Monitoring of Protected Visual
Environments (IMPROVE) monitoring data). We expect that installation of
NOX controls on Independence will provide visibility
improvement on this portion of the 20% worst days and will also provide
meaningful visibility improvement on the 98th percentile day, as shown
by the CALPUFF dispersion modeling. After carefully considering all
comments submitted to us during the comment period, we are finalizing
both SO2 and NOX controls for Independence Units
1 and 2 to make reasonable progress at Arkansas' Class I areas (i.e.,
proposed Option 1), because both SO2 and NOX are
key pollutants contributing to visibility impairment, and because we
have determined that these controls are cost effective and will provide
for significant visibility benefits towards the goal of natural
visibility conditions at Arkansas' Class I areas.
In response to comments we received on our initial cost analysis
presented in our proposal, we have revised our cost estimate for dry
FGD for Independence Units 1 and 2. Based on this revision to our cost
analysis, we find that dry FGD is estimated to cost $2,853/
SO2 ton removed at Unit 1 and $2,634/SO2 ton
removed. Although these cost estimates are slightly higher than we
estimated in our proposal, we continue to find these controls to be
cost effective and well within the range of cost of controls found to
be reasonable by EPA and the States in other regional haze actions. Dry
FGD controls on Independence are also expected to result in
considerable visibility improvement at Arkansas' Class I areas based on
CALPUFF modeling of the maximum (98th percentile) visibility impacts
from the facility (see Table 14).\69\ As dry FGD will eliminate a
majority of the SO2 emissions from Independence,\70\ we
anticipate that on the 20% worst days these controls will also
accordingly eliminate a majority of the visibility impairment due to
SO2 emissions from Independence. Taking into consideration
the four reasonable progress factors and the visibility benefit of dry
FGD controls, we conclude that these are reasonable controls and are
therefore necessary to make reasonable progress. We are finalizing an
SO2 emission limit of 0.06 lb/MMBtu for Independence Units 1
and 2 based on a 30 boiler-operating-day rolling average basis, which
is consistent with the installation and operation of dry FGD. We are
requiring the facility to comply with this emission limit no later than
5 years from the effective date of this final rule.
---------------------------------------------------------------------------
\69\ 80 FR 24872.
\70\ As discussed in our proposal, dry FGD controls on
Independence Units 1 and 2 are expected to reduce facility-wide
SO2 emissions by 26,902 tpy from a baseline emission rate
of 29,780 tpy (i.e., Units 1 and 2 combined). See 80 FR 18944,
18993.
[[Page 66353]]
Table 14--Entergy Independence Plant--Summary of the 98th Percentile
Baseline Visibility Impacts and Improvement Due to Dry FGD
[Facility-wide]
------------------------------------------------------------------------
Facility-wide
baseline Visibility
Class I area visibility improvement
impact from baseline
([Delta]dv) ([Delta]dv)
------------------------------------------------------------------------
Caney Creek............................. 2.512 1.096
Upper Buffalo........................... 2.264 1.178
Cumulative Visibility Improvement at .............. 2.274
Arkansas' Class I areas ([Delta]dv)....
------------------------------------------------------------------------
As discussed in our proposal, LNB/SOFA controls on Independence are
estimated to cost $401/NOX ton removed at Unit 1 and $436/
NOX ton removed at Unit 2,\71\ which we consider to be very
cost effective and well within the range of cost of controls found to
be reasonable by EPA and the States in other regional haze actions.
LNB/SOFA controls on Independence are also expected to provide
considerable visibility benefits based on CALPUFF modeling of the
maximum (98th percentile) visibility impacts from the facility (see
Table 15).\72\ As LNB controls will eliminate a large portion of the
NOX emissions from Independence,\73\ we anticipate that
these controls will also accordingly eliminate a large portion of the
visibility impairment due to NOX emissions from Independence
on a portion of the 20% worst days. Taking into consideration the four
reasonable progress factors and the visibility benefit of LNB/SOFA
controls, we conclude that these are reasonable controls and are
therefore necessary to make reasonable progress. As such, we are
requiring NOX controls for Independence Units 1 and 2 under
the reasonable progress requirements.
---------------------------------------------------------------------------
\71\ Our cost analysis and visibility modeling analysis for LNB/
SOFA for Independence Units 1 and 2, as presented in our proposal,
is based on an emission limit of 0.15 lb/MMBtu on a 30 boiler-
operating-day rolling average. As discussed in this final action, we
received new information from Entergy that indicates that the source
expects to be operating at less than 50% load more frequently and
therefore no longer expects to be able to meet our proposed
NOX emission limit. We are therefore finalizing the
bifurcated NOX emission limit described in this final
action. We recognize that the comments submitted by Entergy indicate
that some of the assumptions used to calculate the cost
effectiveness of NOX controls for Independence may not
exactly apply to future operations. However, because we found LNB/
SOFA controls to be very cost effective, we expect that even if the
change in operation of the source were known more precisely and were
taken into account in our calculation of the cost ($/ton), these
controls would continue to be cost effective. Therefore, we are not
revising our cost effectiveness calculations or visibility
improvement modeling of LNB/SOFA for Independence Units 1 and 2.
\72\ 80 FR 24872.
\73\ As discussed in our proposal, LNB/SOFA controls on
Independence Units 1 and 2 are expected to reduce facility-wide
NOX emissions by 5,927 tpy from a baseline emission rate
of 12,713 tpy (i.e., Units 1 and 2 combined). See 80 FR 18944,
18996.
Table 15--Entergy Independence Plant--Summary of the 98th Percentile
Baseline Visibility Impacts and Improvement Due to LNB/SOFA
[Facility-wide]
------------------------------------------------------------------------
Facility-wide
baseline Visibility
Class I area visibility improvement
impact from baseline
([Delta]dv) ([Delta]dv)
------------------------------------------------------------------------
Caney Creek............................. 2.028 0.459
Upper Buffalo........................... 2.003 0.198
Cumulative Visibility Improvement at .............. 0.657
Arkansas' Class I areas ([Delta]dv)....
------------------------------------------------------------------------
We received comments from the company stating that Independence
Units 1 and 2 are no longer expected to be able to consistently meet
our proposed NOX emission limit of 0.15 lb/MMBtu over a 30-
boiler-operating-day period based on LNB/SOFA controls.\74\ We have
determined that the company has provided sufficient information to
substantiate that the units are not expected to be able to meet our
proposed NOX emission limit of 0.15 lb/MMBtu when the units
are primarily operated at less than 50% of their operating capacity.
Therefore, we are finalizing a ``bifurcated'' NOX emission
limit for each unit.\75\ We are requiring Independence Units 1 and 2 to
meet a NOX emission limit of 0.15 lb/MMBtu on a 30 boiler-
operating-day rolling average, where the average is to be calculated by
including only the hours during which the unit was dispatched at 50% or
greater of maximum capacity. In this particular case, the 30 boiler-
operating-day rolling average is to be calculated for each unit by the
following procedure: (1) Summing the total pounds of NOX
emitted during the current boiler operating day and the preceding 29
boiler operating days, including only emissions during hours when the
unit was dispatched at 50% or greater of maximum capacity; (2) summing
the total heat input in MMBtu to the unit during the current boiler
operating day and the preceding 29 boiler operating days, including
only the heat input during hours when the unit was dispatched at 50% or
greater of maximum capacity; and (3) dividing the total pounds of
NOX emitted as
[[Page 66354]]
calculated in step 1 by the total heat input to the unit as calculated
in step 2. In addition to this limit that is intended to control
NOX emissions when the units are operated at 50% or greater
of maximum capacity, we are also establishing a limit in lb/hr that
applies only when the units are operated at lower capacity. We are
requiring Independence Units 1 and 2 to meet an emission limit of 671
lb/hr on a rolling 3-hour average, where the average is to be
calculated by including emissions only for the hours during which the
unit was dispatched at less than 50% of the unit's maximum heat input
rating (i.e., hours when the heat input to the unit is less than 4,475
MMBtu). We calculated this emission limit by multiplying 0.15 lb/MMBtu
by 50% of the maximum heat input rating for each unit (i.e., 50% of
8,950 MMBtu/hr, or 4,475 MMBtu/hr). As discussed in section V.F. in
this final rule, in response to comments we received, we are shortening
the compliance date for the NOX emission limit for
Independence Units 1 and 2 from our proposed 3 years to 18 months.
---------------------------------------------------------------------------
\74\ Entergy submitted comments on this issue that are
applicable to both White Bluff and Independence. We discuss and
address these comments in more detail elsewhere in this final rule.
\75\ The bifurcated emission limit is a logical outgrowth of our
proposal based on the company's comments, which are discussed in
more detail elsewhere in the final rule and our RTC document. See
Int'l Union, UMW, 407 F.3d at 1259; Fertilizer Inst, 935 F.2d at
1311; and Chocolate Mfrs. Ass'n, 755 F.2d 1098.
---------------------------------------------------------------------------
We also received comments during the public comment period from
Entergy that presented an alternative multi-unit approach to address
the regional haze requirements for White Bluff Units 1 and 2 and
Independence Units 1 and 2.\76\ The company's alternative approach
consisted of the following: Requiring White Bluff Units 1 and 2 and
Independence Units 1 and 2 to comply with an SO2 emission
limit of 0.60 lb/MMBtu on a 30 boiler-operating-day rolling average
beginning in 2018; requiring White Bluff Units 1 and 2 and Independence
Units 1 and 2 to comply with a NOX emission limit of 1,342.5
lb/hr on a 30 boiler-operating-day rolling average based on the
installation of LNB/SOFA within 3 years; and ceasing coal combustion at
White Bluff Units 1 and 2 in 2027 and 2028. We note that we do not
interpret Entergy's comments as suggesting that we adopt the elements
in its alternative that are unique to White Bluff as an alternative to
our proposed BART emission limits at the facility unless we also
conclude that the remaining elements address any reasonable progress
requirements for Independence. After carefully considering the comments
we received specifically on this issue, we do not believe the
comprehensive multi-unit strategy as presented by the company has
potential to satisfy the BART requirements for White Bluff Units 1 and
2 and the reasonable progress requirements for Independence Units 1 and
2. We address this in more detail elsewhere in this final rule.
---------------------------------------------------------------------------
\76\ As described in section I. of this notice, Entergy also
submitted a comment after the close of the comment period,
indicating that Entergy intends that a second alternative described
in the late comment, involving only White Bluff, is a replacement
for the multi-unit alternative previously described in its timely
comments. Because the late comment is not a basis for our decision
making in this final rule, we are responding in this final rule and
in our RTC document to the alternative proposal described in the
comments that Entergy filed during the comment period.
---------------------------------------------------------------------------
b. RPGs for Caney Creek and Upper Buffalo
We proposed RPGs for the 20% worst days for Caney Creek and Upper
Buffalo of 22.27 dv and 22.33 dv, respectively that reflected the
anticipated visibility conditions resulting from the combination of
control measures from the approved portion of the 2008 Arkansas
Regional Haze SIP and our FIP proposal. We received comments on our
proposal indicating that our proposed RPGs for the 20% worst days for
Caney Creek and Upper Buffalo improperly incorporated visibility
improvements that would not occur until after 2018. After considering
these comments, we agree that the RPGs should reflect anticipated
visibility conditions at the end of the implementation period in 2018
rather than the anticipated visibility conditions once the FIP has been
fully implemented. This approach is consistent with the purpose of RPGs
and the direction provided in our 2007 Reasonable Progress
Guidance.\77\
---------------------------------------------------------------------------
\77\ ``Guidance for Setting Reasonable Progress Goals Under the
Regional Haze Program,'' dated June 1, 2007. We refer to this
guidance as the ``2007 Reasonable Progress Guidance'' throughout
this final notice.
---------------------------------------------------------------------------
Section 169B(e)(1) of the CAA directed the Administrator to
promulgate regulations that ``include[e] criteria for measuring
`reasonable progress' toward the national goal.'' Consequently, we
promulgated 40 CFR 51.308(d)(1) as part of the Regional Haze Rule. This
provision directs states to develop RPGs for the most and least
impaired days to ``measure'' the progress that will be achieved by the
control measures in the state's long-term strategy ``over the period of
the implementation plan.'' \78\ The current implementation period ends
in 2018. RPGs ``are not directly enforceable'' like the emission
limitations in the long-term strategy.\79\ Rather, they fulfill two key
purposes: (1) Allowing for comparisons between the progress that will
be achieved by the state's long-term strategy and the URP,\80\ and (2)
providing a benchmark for assessing the adequacy of a state's SIP in 5-
year periodic reports.\81\ Consequently, in our 2007 Reasonable
Progress Guidance, we indicated that states could consider the ``time
necessary for compliance'' factor by ``adjust[ing] the RPG to reflect
the degree of improvement in visibility achievable within the period of
the first SIP if the time needed for full implementation of a control
measure (or measures) will extend beyond 2018.'' \82\ In other words,
RPGs need not reflect the visibility improvement anticipated from all
of the control measures deemed necessary to make reasonable progress
(as a result of the four-factor analysis) and included in the long-term
strategy.
---------------------------------------------------------------------------
\78\ 40 CFR 51.308(d)(1).
\79\ 40 CFR 51.308(d)(1)(iv).
\80\ 40 CFR 51.308(d)(1)(ii).
\81\ 40 CFR 51.308(g)-(h).
\82\ ``Guidance for Setting Reasonable Progress Goals Under the
Regional Haze Program,'' at 5-2.
---------------------------------------------------------------------------
In this instance, we are taking final action on the Arkansas
Regional Haze FIP 9 years after the state's initial SIP submission was
due.\83\ As a result, only some of the control measures that we have
determined are necessary to satisfy the BART and reasonable progress
requirements will be installed by the end of 2018. Some controls will
not be installed until 2021. Because RPGs are only unenforceable
analytical benchmarks, we think that it is appropriate to follow the
recommendation in our 2007 Reasonable Progress Guidance and finalize
RPGs that represent the visibility conditions anticipated on the 20%
worst days at Caney Creek and Upper Buffalo by 2018. These RPGs are
listed in the table below: 84 85
---------------------------------------------------------------------------
\83\ We discuss in section II.A of this final rule the history
of the state's submittals and our actions.
\84\ These RPGs are calculated using the same methodology
described in our proposal and TSD. See ``CACR UPBU RPG analysis
2018.xlsx'' for additional information on the calculation of the
RPGs.
\85\ The RPGs we are finalizing in this rulemaking for Caney
Creek and Upper Buffalo are a logical outgrowth of our proposed RPGs
based on comments we received, which are discussed in more detail
elsewhere in the final rule and our RTC document. See Int'l Union,
UMW, 407 F.3d at 1259; Fertilizer Inst., 935 F.2d at 1311; and
Chocolate Mfrs. Ass'n v. Block, 755 F.2d 1098.
Table 16--Reasonable Progress Goals for 2018 for Caney Creek and Upper
Buffalo
------------------------------------------------------------------------
2018 RPG 20%
Class I area Worst days
(dv)
------------------------------------------------------------------------
Caney Creek............................................. 22.47
Upper Buffalo........................................... 22.51
------------------------------------------------------------------------
[[Page 66355]]
4. Long-Term Strategy
We are finalizing our determination that the provisions in this
final rule, in combination with provisions in the approved portion of
the Arkansas Regional Haze SIP, fulfill the Regional Haze Rule's long-
term strategy requirements. The long-term strategy must include
enforceable emissions limitations, compliance schedules, and other
measures as necessary to achieve reasonable progress at Class I areas
impacted by emissions from Arkansas. In this final rule, we are
promulgating emission limits, compliance schedules, and other
requirements for nine units subject to BART and for two reasonable
progress units.
B. Interstate Visibility Transport
We are finalizing our determination that the control measures in
the approved portion of the Arkansas Regional Haze SIP and our final
FIP are adequate to prevent Arkansas' emissions from interfering with
other states' required measures to protect visibility. Thus, the
combined measures from both plans satisfy the interstate transport
visibility requirement of CAA section 110(a)(2)(D)(i)(II) for the 1997
8-hour ozone and the 1997 PM2.5 NAAQS.
V. Summary and Analysis of Major Issues Raised by Commenters
We received comments at the public hearing held in Little Rock, as
well as comments submitted electronically on www.regulations.gov and
through the mail. The full text of comments we received from commenters
is included in the publicly posted docket associated with this action
at www.regulations.gov. Our RTC document, which is also included in the
docket associated with this action, provides detailed responses to all
significant comments received, and is a part of the administrative
record for this action. Below we provide summaries of the more
significant comments received and our responses to them. Our RTC
document is organized similarly to the structure of this section (e.g.,
Cost, Modeling, etc.). Therefore, if additional information is desired
concerning how we addressed a particular comment, the reader should
refer to the appropriate section in the RTC document.
A. General Comments
Comment: We received 238 comments in support of our rulemaking,
specifically regarding the requirements to control SO2,
NOX, and PM emissions from Arkansas' subject-to-BART
sources, and to control emissions from the Independence facility
pursuant to the Regional Haze Rule's reasonable progress requirements.
Most of these commenters also expressed support for our proposed Option
1, which consists of both SO2 and NOX controls
for Independence Units 1 and 2. These comments were from members
representing various organizations and members of the general public.
At the public hearing in Little Rock, Arkansas, 40 people expressed
general support for the plan. The speakers at the public hearings
included members of various organizations and members of the general
public. Some of these commenters also stated that we should transition
away from coal-fired power and that retrofitting these plants and
allowing them to continue operating is not a sound long-term solution,
but does signal progress in Arkansas towards cleaner energy sources.
Response: We thank the commenters for participating in the
rulemaking and acknowledge their support of this action. As discussed
in section IV. of this final rule, we are finalizing SO2,
NOX, and PM controls for six facilities under the BART
requirements and we are finalizing both SO2 and
NOX controls for Independence under the reasonable progress
requirements (proposed Option 1). Under the Regional Haze Rule, we are
authorized to require affected sources to meet emission limits for
visibility impairing pollutants (i.e., SO2, NOX,
and PM), but we are not authorized to dictate what type of technology
the source must employ to meet those emission limits and we are not
authorized to force sources to retire or to stop burning fossil fuels.
However, sources may choose to voluntarily retire or switch fuels in
order to comply with our emission limits.
Comment: We received one email from a citizen that opposed our
proposal. The commenter expressed that it is not fair that we are
requiring sources in Arkansas to spend a large amount of money in
retrofits when other countries are not held to the same standards. The
commenter questioned why other countries are given additional time to
meet requirements. The commenter also expressed concern that our
proposed controls would result in a higher electric bill that could
mean no electricity for some people.
Response: We acknowledge the commenter's concerns. Consistent with
the CAA, the regional haze program is concerned with remedying existing
and preventing future impairment of visibility caused by manmade air
pollution in mandatory Class I Federal areas (located in this country).
Our action requires particular Arkansas sources to control emissions
that impact visibility at Arkansas and Missouri Class I areas. Our
action does not in any way expect Arkansas to make up for emissions
from international sources. On the other hand, as we discussed in the
preamble to the Regional Haze Rule, ``the States should not consider
the presence of emissions from foreign sources as a reason not to
strive to ensure reasonable progress in reducing any visibility
impairment caused by sources located within their jurisdiction.'' \86\
While the goal of the regional haze program is to restore natural
visibility conditions at Class I areas by 2064, the rule requires only
that reasonable progress be made towards the goal during each planning
period. In cases where it is not reasonable to meet the rate of
progress needed to attain the goal by 2064, the Regional Haze Rule
requires a state to demonstrate that this rate of progress is not
reasonable, and that the state's selected rate of progress is
reasonable for that planning period. While there is no indication at
this time that emissions from international sources are anticipated to
prevent Arkansas from attaining the goal of natural visibility
conditions at its Class I areas, we recognize that in some cases it may
not be possible to attain the goal by 2064 because of impacts from new
or persistent international emissions sources or impacts from sources
where reasonable controls are not available. However, states are still
required to demonstrate that they are establishing a reasonable rate of
progress that includes implementation of reasonable measures within the
state to address visibility impairment in an effort to make progress
towards the natural visibility goal during each planning period. We
acknowledge the commenter's concern regarding potential increases in
electricity rates. While our consideration of cost under the Regional
Haze Rule is limited to the direct costs incurred by sources,
consistent with the CAA's and Rule's source-specific focus, we are very
sensitive to the ramifications of our actions and we seek to select the
most cost-effective options when we propose and finalize these
controls.
---------------------------------------------------------------------------
\86\ 64 FR 35714, 35755 (July 1, 1999).
---------------------------------------------------------------------------
Comment: ADEQ submitted comments stating that it concurs with our
proposed determination that the Georgia Pacific-Crossett Mill 6A and 9A
Boilers are not subject to BART.
Response: We appreciate ADEQ's support of our proposed
determination. As discussed in section IV. of this final action, we are
finalizing our determination that the Georgia Pacific-
[[Page 66356]]
Crossett Mill 6A and 9A Power Boilers are not subject to BART.
B. Entergy's Alternative Strategy for White Bluff and Independence
Comment: Entergy proposes an alternative multi-unit strategy to
address the regional haze requirements for four units that it states
EPA should adopt instead of finalizing the proposed controls for the
four units. The alternative multi-unit strategy involves meeting an
emission limit of 0.60 lb/MMBtu on a 30-day rolling average at White
Bluff Units 1 and 2 and Independence Units 1 and 2 by 2018; ceasing
coal combustion at White Bluff Units 1 and 2 by 2027 and 2028; and
installing LNB/SOFA at White Bluff Units 1 and 2 and Independence Units
1 and 2 within 3 years. Based on Entergy's modeling, the company says
it believes its alternative multi-unit proposal achieves virtually the
same visibility benefit as the FIP proposal and that the alternative
proposal would ensure that Arkansas' Class I areas remain below the URP
glidepath. Entergy argues that the difference in the haze index between
the proposed FIP controls and Entergy's alternative multi-unit strategy
is too trivial to justify a $2 billion investment at White Bluff and
Independence for the installation of dry FGD.
Response: After carefully considering the comments we received, we
have determined that we cannot approve Entergy's alternative proposal
consistent with the Clean Air Act and Regional Haze rule. This
determination is based on our conclusion that the alternative is not a
better than BART alternative, does not meet the BART requirement for
White Bluff Units 1 and 2, does not meet the reasonable progress
requirements, and does not provide for the same visibility benefits as
the FIP while delaying a majority of the visibility benefits until
several years later than the FIP. Below, we discuss our assessment of
the merits of Entergy's alternative proposal as an alternative approach
for both meeting the BART requirements of section 308(e) for White
Bluff and meeting the requirements of sections 308(d)(1) and 308(d)(3)
regarding reasonable progress.
As an initial matter, we note that Entergy does not appear to be
proposing that we apply the provisions of sections 308(e)(2) and
308(e)(3) to determine that its multi-unit strategy is an alternative
program that provides more reasonable progress than BART. To the extent
that this is Entergy's proposal, we cannot approve Entergy's multi-unit
plan as an alternative to BART because it does not meet the
requirements of section 308(e)(2)(iii) that ``all necessary emission
reductions take place during the first planning period,'' i.e., by
December 31, 2018. Moreover, Entergy does not argue that its
alternative would provide for ``greater'' reasonable progress towards
achieving natural visibility conditions, only that its proposal would
result in ``virtually the same'' visibility benefits. Thus, our
assessment discussed below considers only the requirements of section
308(e)(1), which contains the source-specific BART requirements, in
considering the provisions of Entergy's alternative proposal applicable
to White Bluff.
Entergy proposes that White Bluff Units 1 and 2 would meet an
SO2 interim emission limit of 0.6 lb/MMBtu on a rolling 30-
day average from 2018 through 2027/2028, when coal combustion at the
two units would cease.\87\ We note that the 0.6 lb/MMBtu interim
emission limit is only slightly lower than the units' current
SO2 emission rates. The maximum monthly SO2
emission rates for White Bluff Units 1 and 2 in 2009-2013 were 0.653
lb/MMBtu and 0.679 lb/MMBtu, respectively.\88\ Thus, under Entergy's
alternative proposal, White Bluff Units 1 and 2 would continue to
operate for the remainder of the first planning period and throughout
most of the second planning period at near the current emission rate,
with only a slight actual reduction in SO2 emissions.
Because section 308(e)(1) and the BART guidelines require that a
subject-to-BART source install and operate the best available emission
reduction technology based on the five statutory factors, it is
necessary to consider whether there are any additional SO2
control measures, such as dry sorbent injection (DSI), that constitute
BART during this interim period. Entergy has argued that with this
limited remaining period of coal combustion, the cost per ton of
SO2 emissions reduction for dry scrubbers would be too high
for it to be selected as BART for White Bluff. While we agree that a
shorter remaining useful life might result in a conclusion that dry
scrubbers are not cost effective, as part of the BART analysis,
technically feasible control technologies beyond the interim
SO2 emission limit the company has proposed must be
evaluated to determine if they are cost effective for use in the period
before coal combustion ceases. In particular, DSI has a relatively low
capital cost and may be cost effective even if operated for a short
period of time.\89\ Under Entergy's proposed strategy, White Bluff
Units 1 and 2 would cease coal combustion towards the end of the second
planning period. Therefore, it would be necessary to consider and
evaluate DSI as a possible interim BART control option for White Bluff
Units 1 and 2. Because Entergy has provided no analysis to demonstrate
that there is no more effective interim SO2 control that
would constitute BART, the company's proposed strategy is not adequate
to ensure that the BART requirements for White Bluff Units 1 and 2 will
be met.
---------------------------------------------------------------------------
\87\ Although not specified in Entergy's written comments, the
company met with us and confirmed that the interim emission limit
would be met by combusting lower sulfur coal. See file titled
``Record of Meeting October 27 2015,'' which is found in the docket
for this rulemaking.
\88\ 80 FR 18944, 18970; see also the spreadsheet titled ``White
Bluff R6 cost revisions2,'' which is found in the docket for this
rulemaking.''
\89\ For example, Florida evaluated a shutdown option by
December 31, 2020 for two BART units. After reviewing the Florida
Regional Haze SIP, we concluded that the State should have evaluated
DSI as a as a possible interim BART control option during the
interim before the units shut down. We ultimately approved Florida's
determination after evaluating the cost-effectiveness of DSI and
concluding that such controls were not cost-effective in light of
the remaining useful life of the units. See 78 FR 53250, 53261
(August 29, 2013).
---------------------------------------------------------------------------
Even if it were not necessary to evaluate DSI or if we found it to
not be cost effective for use at White Bluff in the interim period
before coal combustion ceases, Entergy's alternative proposal would
still not satisfy the BART requirements for White Bluff because it does
not propose SO2 and NOX emission limits after
coal combustion ceases or otherwise propose adopting a binding
requirement to burn only natural gas or completely shut down the units.
Entergy proposes to cease coal combustion at White Bluff Units 1 and 2
in 2027/2028, but its comments do not specify the operating conditions
of White Bluff Units 1 and 2 after coal combustion ceases. The type of
fuel White Bluff is permitted to burn after ceasing coal combustion
will impact the emissions reductions actually achieved under Entergy's
alternative proposal. Exhibit C to Entergy's comments indicates that
the company assumes in its visibility modeling that SO2 and
NOX emissions from White Bluff Units 1 and 2 will be zero
under the company's alternative proposal (i.e., ``Entergy's proposed
controls'' scenario).\90\ If Entergy's alternative proposal had
included accepting a binding requirement to burn only natural gas at
White Bluff Units 1 and 2 after coal combustion ceases, or a binding
requirement to completely shut down the units, then we would
[[Page 66357]]
agree that it would be appropriate to assume that SO2
emissions from White Bluff will be zero beginning in 2027/2028.
Similarly, if Entergy's alternative proposal had included accepting a
binding requirement to completely shut down White Bluff, then we would
agree that it would be appropriate to assume that NOX
emissions from White Bluff will be zero beginning in 2027/2028.
---------------------------------------------------------------------------
\90\ See ``Regional Haze Modeling Assessment Report,'' dated
August 4, 2015, submitted as Exhibit C to Entergy Arkansas Inc.'s
comments.
---------------------------------------------------------------------------
Although, as we have already established, Entergy's alternative
proposal cannot constitute a BART alternative because all necessary
emission reductions will not take place during the first implementation
period and the alternative proposal also does not satisfy the source-
specific BART requirements of section 308(e)(1) for White Bluff, in
response to Entergy's comment that its alternative proposal would
achieve almost the same level of visibility benefit as the FIP, we
compared the potential impacts of Entergy's proposal to our FIP.
Despite the ambiguity in the comments submitted by Entergy regarding
its alternative proposal, for purposes of assessing the visibility
impacts of the company's proposed approach we have assumed that post-
2028 SO2 and NOX emissions from White Bluff Units
1 and 2 will be zero under Entergy's alternative proposal. In Table 17,
we compare the total annual SO2 emissions reductions that
would result under our FIP and under Entergy's alternative proposal
when the alternative proposal is fully implemented in 2028 (i.e., when
coal combustion has ceased at White Bluff).\91\ For consistency and to
allow for direct comparison to our FIP proposal, in estimating the
SO2 emissions reductions anticipated to result from
Entergy's alternative proposal we have assumed the same SO2
baseline emissions we used for White Bluff and Independence in our
proposal.\92\ As shown in Table 17, although Entergy's alternative
proposal would, after 2027/2028, achieve slightly greater
SO2 reductions at White Bluff Units 1 and 2 than our FIP
proposal, it would achieve substantially lower SO2
reductions at Independence Units 1 and 2. Under Entergy's proposed
approach, Independence Units 1 and 2 would be subject to an
SO2 emission limit of 0.6 lb/MMBtu on a rolling 30-day
average beginning in 2018.\93\ This emission limit is only slightly
lower than the current SO2 emission rates from Independence
Units 1 and 2. The maximum monthly SO2 emission rates for
Independence Units 1 and 2 in 2009-2013 were 0.631 lb/MMBtu and 0.612
lb/MMBtu, respectively.\94\ We have no basis to assume that future
emissions would be different from current rates in the absence of new
SIP or FIP requirements, and so these current emission rates are the
appropriate baseline for comparing strategies, rather than the
currently permitted emission rates, which are higher. As such, under
Entergy's proposal these units would continue to operate with minimal
SO2 emissions reductions. Unlike Entergy's proposed approach
with respect to White Bluff, the proposed limits for Independence would
not be interim emission limits. The company's alternative proposal does
not include any further SO2 controls for Independence Units
1 and 2, such as DSI or the eventual cessation of coal combustion. In
contrast, we expect our proposed SO2 emission limit of 0.06
lb/MMBtu would significantly and permanently reduce SO2
emissions from Independence Units 1 and 2. As shown in Table 17, our
FIP proposal would achieve substantially greater SO2
emissions reductions at Independence than Entergy's alternative
proposal. We estimate that the additional SO2 emissions
reductions that our FIP proposal would achieve at Independence compared
to Entergy's alternative strategy are 11,621 SO2 tpy at Unit
1 and 12,591 SO2 tpy at Unit 2. In light of the minimal
SO2 emissions reductions that would be achieved at
Independence under the company's proposed strategy, we expect that
there would be correspondingly minimal visibility improvement with
respect to the SO2 controls it proposes for Independence.
---------------------------------------------------------------------------
\91\ The SO2 emissions reductions expected to result
from our FIP will take place several years earlier than any
significant SO2 reductions under Entergy's alternative
proposal. However, for purposes of comparing the long-term emissions
reductions under the FIP and under the Entergy alternative, we are
assessing the annual emissions reductions that will take place
beginning in 2028, when the Entergy alternative would be fully
implemented.
\92\ In our proposal, for purposes of estimating the annual
SO2 emissions reductions due to controls on White Bluff
Units 1 and 2 and Independence Units 1 and 2, we assumed an
SO2 emissions baseline that was determined by examining
annual SO2 emissions for the years 2009-2013, eliminating
the year with the highest emissions and the year with the lowest
emissions, and obtaining the average of the three remaining years.
See 80 FR 18944, 18971, and 18992.
\93\ Although not specified in Entergy's written comments, the
company met with us and confirmed that this emission limit would be
met by combusting lower sulfur coal. See file titled ``Record of
Meeting October 27 2015,'' which is found in the docket for this
rulemaking.
\94\ See the spreadsheet titled ``White Bluff R6 cost
revisions2,'' which is found in the docket for this rulemaking.
Table 17--Comparison of Annual SO2 Emissions Reductions From White Bluff Units 1 and 2 and Independence Units 1
and 2
[Post-2028]
----------------------------------------------------------------------------------------------------------------
Additional SO2
SO2 Baseline Entergy emissions
emissions FIP Proposal-- alternative reductions
Unit (tpy) annual SO2 proposal-- achieved by
reductions \1\ annual SO2 FIP proposal
reductions \2\
----------------------------------------------------------------------------------------------------------------
White Bluff Unit 1.............................. 15,816 14,363 15,816 (1,453)
White Bluff Unit 2.............................. 16,697 15,221 16,697 (1,476)
Independence Unit 1............................. 14,269 12,912 1,291 11,621
Independence Unit 2............................. 15,511 13,990 1,399 12,591
---------------------------------------------------------------
Total--All four units combined (SO2 tpy).... 62,293 56,486 35,203 21,283
----------------------------------------------------------------------------------------------------------------
\1\ These SO2 reductions will begin taking place no later than 5 years from the effective date of this final
FIP.
\2\ This takes into account the full SO2 reductions that would take place under Entergy's alternative proposal;
a small amount of SO2 reductions would begin taking place in 2018, but the majority of these SO2 reductions
would begin taking place in 2027/2028.
As shown in Table 17, considering the four units combined, we
estimate that our FIP proposal would achieve annual emissions
reductions of 21,283 SO2 tpy more than Entergy's alternative
proposal. With regard to visibility benefits, Entergy does not assert
that its alternative proposal would provide equal or greater visibility
benefits
[[Page 66358]]
relative to our proposed FIP once the alternative is fully realized in
the period after 2027/2028. Entergy states only that its alternative
proposal would provide almost the same visibility benefit as our
proposed FIP post-2027/2028. However, as illustrated in Table 17, it is
clear that annual emissions would be significantly higher under the
Entergy alternative and that the long-term visibility benefits of the
Entergy alternative proposal would be significantly smaller than those
of the proposed and final FIP. As we explained above, Entergy assumes
in its visibility improvement projections that SO2 and
NOX emissions from White Bluff Units 1 and 2 will be zero
under the company's alternative proposal. The assumption of zero
SO2 emissions from White Bluff after coal combustion ceases
would be appropriate only if Entergy's alternative proposal involves
accepting a binding requirement to burn only natural gas or permanently
shut down after coal combustion ceases. With respect to NOX
emissions from all four units of White Bluff and Independence,
Entergy's multi-unit strategy includes the same level of NOX
control as our FIP proposal prior to the cessation of coal combustion
at White Bluff in 2027/2028. Since Entergy's explanation of its
alternative proposal does not specify the operating conditions of White
Bluff Units 1 and 2 when coal combustion ceases in 2027/2028, we find
that the assumption of zero NOX emissions is also not
adequately supported. However, even if we accept Entergy's assumption
that NOX emissions from White Bluff will be zero after coal
combustion ceases and that its alternative proposal would thus achieve
greater NOX reductions compared to our FIP proposal, given
the dominance of visibility impact from sulfate compared to nitrate at
the affected Class I areas in Arkansas, the higher visibility impacts
due to sulfate under the Entergy alternative proposal would more than
outweigh any extra nitrate-related visibility benefit. Entergy's own
CAMx modeling shows that even assuming zero SO2 and
NOX emissions from White Bluff once it ceases coal
combustion, its multi-unit alternative proposal would achieve less
visibility benefit than the FIP controls at Arkansas' Class I areas,
most significantly at Upper Buffalo where the benefit from Entergy's
proposal is approximately only 66% of the benefit from the FIP (i.e.,
1.54 dv visibility benefit from the FIP compared to 0.97 dv from
Entergy's alternative proposal).\95\
---------------------------------------------------------------------------
\95\ We discuss this, as well as Entergy's ranked statistical
analysis and its photochemical modeling, in more detail elsewhere in
this final rule and in our RTC document.
---------------------------------------------------------------------------
We also note that Entergy does not appear to be requesting in the
comments submitted during the comment period that we adopt the elements
in its alternative proposal that are unique to White Bluff as an
alternative to our proposed BART emission limits at the facility unless
we also conclude that the remaining elements address any reasonable
progress requirements for Independence. In other words, Entergy's
comments provide no indication that it is willing to accept a binding
requirement to cease coal combustion at White Bluff by 2027/2028,
unless we also accept the elements of its alternative proposal that are
applicable to Independence as satisfying the reasonable progress
requirements. Even if we had interpreted Entergy's comments as
requesting that we adopt the elements in its alternative proposal that
are unique to White Bluff as an alternative to our proposed BART
emission limits at the facility without these elements being linked to
the remaining elements addressing the reasonable progress requirements
for Independence, we conclude that we would not be able to incorporate
the Entergy alternative proposal into the final FIP as a way of meeting
the BART requirement for White Bluff for the reasons already discussed
above.\96\
---------------------------------------------------------------------------
\96\ We explain in an earlier part of our response why Entergy's
alternative proposal does not satisfy the source-specific BART
requirements of section 308(e)(1) for White Bluff.
---------------------------------------------------------------------------
Similarly, we also conclude that we cannot consider Entergy's
proposal to meet the reasonable progress requirements with respect to
Independence if Independence is considered in isolation. SO2
emissions are the primary driver of regional haze in Arkansas' Class I
areas on the 20% worst days and Independence is the second largest
source of SO2 emissions in Arkansas.\97\ As explained in our
proposal, our consideration of the four reasonable progress factors and
consideration of visibility impacts and visibility improvement of
controls for Independence revealed that dry scrubbers on Independence
Units 1 and 2 are cost effective. These controls would provide
significant visibility improvement as projected by our CALPUFF modeling
focusing on the 98th percentile impacts from the source. We also
discuss in section V.J. of this final rule and in our RTC document that
the results of Entergy's CAMx photochemical modeling, which estimates
the visibility impacts from Independence during the average of the 20%
worst days, confirm and provide additional support to our determination
that Independence significantly impacts visibility at Arkansas' Class I
areas. Since Entergy's alternative proposal includes minimal
SO2 control for Independence, thus omitting controls that we
found to be cost effective and that are anticipated to result in
considerable visibility benefits at Arkansas' Class I areas, we
conclude that the elements of Entergy's alternative proposal that are
specific to Independence do not satisfy the reasonable progress
requirements.
---------------------------------------------------------------------------
\97\ CENRAP CAMx modeling shows that on most of the 20% worst
days in 2002, total extinction is dominated by sulfate at both Caney
Creek and Upper Buffalo. Therefore, SO2 emissions are
considered the primary driver of haze in Arkansas' Class I areas.
However, as discussed elsewhere in this final rule and in our RTC
document, we consider both SO2 and NOX to be
key visibility impairing pollutants in Arkansas' Class I areas. See
Arkansas Regional Haze SIP, Appendix 8.1--``Technical Support
Document for CENRAP Emissions and Air Quality Modeling to Support
Regional Haze State Implementation Plans,'' sections 3.7.1 and
3.7.2. See the docket for this rulemaking for a copy of the Arkansas
Regional Haze SIP.
---------------------------------------------------------------------------
We recognize that ceasing coal combustion at White Bluff Units 1
and 2 could result in greater nonair environmental benefits and in more
emission reductions of mercury and other hazardous air pollutants and
CO2/CO2e than our proposed FIP. However, in
assessing Entergy's alternative proposal, we do not find it necessary
to weigh the nonair quality environmental benefits with the other
statutory factors since we ultimately find that we cannot accept
Entergy's alternative proposal because it does not satisfy the
requirements of the Regional Haze Rule. As discussed earlier in our
response, we conclude that Entergy's proposal does not satisfy the
requirements to be considered a better-than-BART alternative under
sections 308(e)(2) and 308(e)(3); does not satisfy the source-specific
BART requirements under section 308(e)(1) for White Bluff; does not
satisfy the reasonable progress requirements under section 308(d)(1);
and does not provide for the same visibility benefits as the FIP, while
delaying a majority of the visibility benefits until several years
later than the FIP. For these reasons, we cannot adopt Entergy's
alternative approach in lieu of our FIP.
In response to Entergy's comment regarding the cost to install dry
FGD and as discussed in more detail in our RTC document, we have
revised our cost calculations of SO2 controls for White
Bluff Units 1 and 2 in response to the comments received on our initial
cost
[[Page 66359]]
analysis.\98\ As we discuss in more detail elsewhere in this final
rule, based on our consideration of the five BART factors, we have
determined that controls consistent with dry scrubber and LNB/SOFA
installation are BART for White Bluff Units 1 and 2. After revising our
cost estimates, we continue to believe that dry scrubber controls and
LNB/SOFA controls are cost effective at White Bluff Units 1 and 2 and
would result in significant visibility improvement at Arkansas' Class I
areas based on our CALPUFF modeling of the 98th percentile visibility
impacts from the facility.\99\
---------------------------------------------------------------------------
\98\ Based on our revised cost analysis, we have found that dry
scrubbers on White Bluff are estimated to cost $2,565/SO2
ton removed at Unit 1 and $2,421/SO2 ton removed at Unit
2.
\99\ See 80 FR at 18972, 18974. Our FIP proposal provides a
detailed discussion of the visibility improvement of these controls
based on our CALPUFF modeling.
---------------------------------------------------------------------------
As we discuss in more detail elsewhere in this final rule, based on
our consideration of the four reasonable progress factors and of the
visibility impacts and visibility improvement of controls on
Independence, we have determined that dry scrubbers and LNB/SOFA
controls on Independence Units 1 and 2 are necessary to make reasonable
progress at Arkansas' Class I areas. We have also revised our cost
calculations of SO2 controls for these units in response to
the comments received on our initial cost analysis, and we continue to
believe that both dry scrubber and LNB/SOFA controls are cost
effective.\100\ We also find that these controls on Independence would
provide significant visibility improvement as projected by our CALPUFF
modeling that focuses on the 98th percentile impacts from the
facility.\101\ Additionally, the CAMx photochemical modeling submitted
by Entergy shows that the contribution to visibility impairment due to
baseline emissions from the Independence facility alone are projected
to be approximately 1.3% of the total visibility impairment during the
average 20% worst days in 2018 at each Arkansas Class I area. We
consider this to be a significant contribution to visibility impairment
at each Class I area and a large portion (approximately one-third) of
the total contribution from all Arkansas point sources. The results of
Entergy's CAMx modeling confirm and provide additional support to our
determination that Independence significantly impacts visibility at
Arkansas' Class I areas. While the majority of the visibility impacts
due to Independence on the 20% worst days are due to SO2, we
note that NOX emissions from the facility also have impacts
on the 20% worst days. Entergy's CAMx modeling shows that nitrate from
Independence is responsible for 30-40% of the visibility impairment in
Arkansas' Class I areas on 2 of the 20% worst days.\102\ We expect that
installation of cost-effective NOX controls on Independence
would provide visibility improvement on this portion of the 20% worst
days, and as such, are requiring both SO2 and NOX
controls under the reasonable progress requirements.
---------------------------------------------------------------------------
\100\ Based on our revised cost analysis, we have found that dry
scrubbers on Independence are estimated to cost $2,853/
SO2 ton removed at Unit 1 and $2,634/SO2 ton
removed at Unit 2. After revising our cost estimates, we continue to
believe that these controls are cost effective.
\101\ 80 FR 24872.
\102\ This means 2 out of the 21 days that are the 20% worst of
the days with IMPROVE monitoring data.
---------------------------------------------------------------------------
We are requiring White Bluff Units 1 and 2 under BART and
Independence Units 1 and 2 under reasonable progress to each meet an
SO2 emission limit of 0.06 lb/MMBtu on a 30 boiler-
operating-day rolling average. We are requiring White Bluff Units 1 and
2 under BART and Independence Units 1 and 2 under reasonable progress
to each meet a NOX emission limit of 0.15 lb/MMBtu on a 30
boiler-operating-day rolling average, where the average is to be
calculated by including only the hours during which the unit is
dispatched at 50% or greater of maximum capacity. In addition, we are
requiring White Bluff Units 1 and 2 under BART and Independence Units 1
and 2 under reasonable progress to each meet a NOX emission
limit of 671 lb/hr on a rolling 3-hour average, where the average is to
be calculated by including emissions only for the hours during which
the unit was dispatched at less than 50% of the unit's maximum heat
input rating (i.e., hours when the heat input to the unit is less than
4,475 MMBtu).
We do note that if Arkansas submits a regional haze SIP revision to
replace our FIP, the state has the discretion to consider an approach
to address the BART requirements for White Bluff that involves ceasing
coal combustion at Units 1 and 2 by 2027/2028, but an approvable SIP
revision must also include consideration and evaluation of DSI as a
possible interim BART control option. With respect to Independence, a
strategy that includes controls for Independence similar to the
elements of Entergy's alternative proposal that are specific to White
Bluff (i.e., interim SO2 controls, ceasing coal combustion
in the near future, and NOX controls) would also have
potential merit with respect to addressing the reasonable progress
requirements for Independence Units 1 and 2. The state may consider
submitting a SIP revision that includes such a strategy for
Independence to replace our FIP.
With regard to the comment that Entergy's alternative multi-unit
strategy would ensure that Arkansas' Class I areas remain below the URP
glidepath, we discuss in section V.C. of this final rule and in our RTC
document that being on or below the URP glidepath does not mean that
the BART requirements for White Bluff Units 1 and 2 and the reasonable
progress requirements for Independence Units 1 and 2 are automatically
satisfied.
Comment: Several commenters noted that as part of a multi-unit plan
to improve visibility and to better manage its generation assets for
reliability and costs, Entergy proposed in comments submitted to EPA to
cease burning coal at White Bluff Units 1 and 2 by 2027 and 2028, one
unit per year, and is prepared to take an enforceable commitment to
that effect. The commenters stated that the CAA and the Regional Haze
Rule require EPA and states to consider the remaining useful life of a
source in BART determinations, which factors into the cost of
compliance in the BART analysis. The commenters argue that as a result
of Entergy's alternative proposal, EPA's proposed BART determination
for White Bluff Units 1 and 2 has been rendered inapplicable, requiring
EPA to undertake a new BART analysis to address the now reduced
remaining useful coal-fired life of the units. The commenters noted
that comments submitted by Entergy contain a revised dry FGD cost
analysis from Sargent & Lundy (S&L) that takes into account current
costs for dry FGD installation and argue that when the appropriate dry
scrubber costs from the S&L analysis are considered, operating the dry
FGD systems at White Bluff for only 6 or 7 years would result in a cost
effectiveness of over $7,500 to $8,500 per ton at the White Bluff
units, which is several times higher than EPA estimates and not cost
effective.
Response: Entergy's comments propose a multi-unit strategy as an
alternative to the proposed FIP. As discussed above, we do not
interpret Entergy's comments submitted during the comment period as
requesting that we adopt the elements in its alternative that are
unique to White Bluff as an alternative to our proposed BART emission
limits for the facility unless we also conclude that the remaining
elements address any reasonable progress requirements for
[[Page 66360]]
Independence. As we discuss in a previous response, we do not find that
the comprehensive multi-unit alternative proposal as presented by the
company satisfies the BART requirements for White Bluff Units 1 and 2
and the reasonable progress requirements for Independence Units 1 and
2. A chief element of Entergy's alternative is its proposal to cease
coal combustion at White Bluff Units 1 and 2. It is unclear whether
this would mean the shutdown or the repowering of White Bluff Units 1
and 2. Regardless of this ambiguity, a number of commenters have argued
that because of Entergy's proposal, we should use a shorter remaining
life in assessing the costs of controls at White Bluff. If we were to
assume that Entergy were proposing changes at White Bluff regardless of
our action regarding Independence, we could include in our final FIP an
enforceable requirement for the shutdown (or repowering) and take that
change into consideration as part of a BART determination. The BART
Guidelines state that where unit shutdown affects the BART
determination, the shutdown date should be assured by a federally or
state-enforceable restriction preventing further operation.\103\
Although we could include such a requirement in our FIP, the comments
we received from Entergy during the public comment period do not
indicate that it intends to cease coal combustion at White Bluff Units
1 and 2 at this time absent a broader agreement on appropriate controls
for both White Bluff and Independence. As such, we do not consider it
appropriate to include a requirement in our FIP to cease coal
combustion at White Bluff Units 1 and 2 in our rule unless we were to
also accept the Entergy proposal as meeting all requirements with
respect to Independence.\104\ Therefore, we consider it appropriate to
assume a remaining useful life of 30 years for White Bluff Units 1 and
2 when determining BART for these units. We address specific comments
regarding the White Bluff cost analysis in the section of this final
rule where we discuss cost issues.
---------------------------------------------------------------------------
\103\ See Appendix Y to 40 CFR part 51--Guidelines for BART
Determinations Under the Regional Haze Rule, section IV.D.4.k.
\104\ Additionally, as discussed above, Entergy did not submit
sufficient information to demonstrate that there are no additional
SO2 control measures, such as DSI, that constitute BART
even in light of a limited remaining useful life for White Bluff.
---------------------------------------------------------------------------
C. Reasonable Progress Goals and Reasonable Progress Analysis
Comment: Several commenters stated that EPA lacks evidence of a
sufficient need to evaluate additional controls under reasonable
progress for Arkansas point sources. These commenters argued that
before evaluating controls under reasonable progress, EPA must first
determine that further actions are necessary in Arkansas beyond BART to
ensure that visibility improvement is continuing on or below the glide
path for each affected Class I area. These commenters cited to the CAA
and EPA guidance which they believe support their position that
reductions beyond BART should not be required because the impacted
Class I areas are at or below their glide paths. The commenters also
pointed to ADEQ's ``State Implementation Plan Review for the Five-Year
Regional Haze Progress Report'' \105\ as evidence that Caney Creek and
Upper Buffalo will be below the glide path in 2018. They claimed that
EPA ignores ADEQ's Five-Year Progress SIP revision, which they argued
demonstrates that Arkansas has achieved 73% of the 2018 RPG it
established for Caney Creek (3.88 dv of improvement) and 66% of the
2018 RPG it established for Upper Buffalo (3.75 dv of improvement). The
commenters argued that as a result of emission reductions achieved
through regional and national programs, including MATS, CAIR, and
CSAPR, future Clean Air Act programs such as implementation of the 1-
hour SO2 NAAQS, the revised ozone NAAQS and the Clean Power
Plan, as well as the reductions for White Bluff and Independence that
Entergy is proposing and the BART controls that EPA has proposed for
the other sources in Arkansas, there is every reason to project
continued improvement in visibility in Caney Creek and Upper Buffalo
well beyond 2018.
---------------------------------------------------------------------------
\105\ Available at http://www.adeq.state.ar.us/air/planning/pdfs/ar_5yr_prog_rep_review-final-6-2-2015.pdf.
---------------------------------------------------------------------------
Response: EPA disagrees with the comment that we can only evaluate
controls under reasonable progress if further controls beyond BART are
needed to be on or below the URP glidepath for a Class I area.
Specifically, commenters cited section 169A(b)(2) of the Act, which
requires regional haze regulations to ``contain such emission limits,
schedules of compliance and other measures as may be necessary to make
reasonable progress toward meeting the national goal.'' These
commenters interpret the term ``reasonable progress'' to be defined as
being on or below the URP glidepath, and that as long as a Class I area
is on or below the URP glidepath, additional controls are not necessary
under the reasonable progress requirements. This interpretation is
incorrect and does not take into account other, more explicit,
statutory and regulatory language. The CAA requires reasonable progress
determinations to be based on consideration of ``the costs of
compliance, the time necessary for compliance, the energy and nonair
quality environmental impacts of compliance, and the remaining useful
life of any existing source subject to such requirements.'' CAA section
169A(g)(1). The regional haze regulations under 40 CFR
51.308(d)(1)(i)(A) also require consideration of these four statutory
factors in establishing the RPGs and a demonstration showing how these
factors were taken into account.
We commonly refer to the evaluation of these four statutory factors
as the ``four-factor analysis'' or ``reasonable progress analysis.''
The statute and regulations are both clear that the states or EPA in a
FIP have the authority and obligation to evaluate the four reasonable
progress factors and that the decision regarding the controls required
to make reasonable progress and the establishment of the RPG must be
based on these factors identified in the CAA section 169A(g)(1) and the
Regional Haze regulations under Sec. 51.308(d)(1)(i)(A). While the
regulations require that a state must also consider the URP glidepath
in establishing the RPGs, this should not be interpreted to mean that
the URP can or should be automatically adopted as the RPG without
completing the requisite analysis of the four statutory factors. It
also should not be interpreted to mean that a set of controls
sufficient to achieve the URP is automatically sufficient for an
approvable long-term strategy. Clearly, a state's obligation to set
reasonable progress goals based on CAA section 169A(g)(1) and Sec.
51.308(d)(1) applies in all cases, without regard to the Class I area's
position on the URP. Since an evaluation of the factors is required
regardless of the Class I area's position on the glidepath, this
necessarily means that the CAA and the Regional Haze regulations
envisioned that controls could be required under reasonable progress
even when a Class I area is on or below the URP glidepath. There is
nothing in the CAA or Regional Haze regulations that suggests that a
State's obligation, or EPA's in a FIP, to ensure reasonable progress
can be met by just meeting the URP.\106\
---------------------------------------------------------------------------
\106\ 77 FR 14604, 14629.
---------------------------------------------------------------------------
Some commenters also argue that the EPA's 2007 Reasonable Progress
[[Page 66361]]
Guidance suggests that controls under reasonable progress are not
necessary if a Class I area is on or below the URP glidepath. The
specific part of the Reasonable Progress Guidance that some of the
---------------------------------------------------------------------------
commenters point to states that:
Given the significant emissions reductions that we anticipate to
result from BART, the CAIR, and the implementation of other CAA
programs, including the ozone and PM2.5 NAAQS, for many
States [determining the amount of emission reductions that can be
expected from identified sources or source categories as a result of
requirements at the local, State, and federal levels during the
planning period of the SIP and the resulting improvements in
visibility at Class I areas] will be an important step in
determining your RPG, and it may be all that is necessary to achieve
reasonable progress in the first planning period for some
States.\107\
---------------------------------------------------------------------------
\107\ ``Guidance for Setting Reasonable Progress Goals Under the
Regional Haze Program,'' at 4-1.
We see nothing in the Reasonable Progress Guidance indicating that
additional controls can only be required if further action beyond BART
is needed to remain on or below the URP glidepath. Nor do we see
anything in the Reasonable Progress Guidance indicating that a state
(or EPA) is exempt from completing the four factor analysis if a Class
I area is on or below the URP glidepath. As discussed above, the CAA
and Regional Haze regulations are clear that an evaluation of the four
statutory factors is required, and this requirement applies regardless
of the Class I area's position on the glidepath. We noted in our FIP
proposal that the preamble to the Regional Haze Rule states that the
URP does not establish a ``safe harbor'' for the state in setting its
---------------------------------------------------------------------------
progress goals:
If the State determines that the amount of progress identified
through the [URP] analysis is reasonable based upon the statutory
factors, the State should identify this amount of progress as its
reasonable progress goal for the first long-term strategy, unless it
determines that additional progress beyond this amount is also
reasonable. If the State determines that additional progress is
reasonable based on the statutory factors, the State should adopt
that amount of progress as its goal for the first long-term
strategy.\108\
---------------------------------------------------------------------------
\108\ 80 FR at 18992.
Being projected to meet the URP for 2018 does not justify
dismissing the analysis required under CAA section 169A(g)(1) and Sec.
51.308(d)(1) in determining reasonable progress and establishing the
RPGs, nor does it automatically mean that no additional controls beyond
BART are required under reasonable progress. The URP is an analytical
requirement created by regulation to ensure that states consider the
possibility of setting an ambitious reasonable progress goal. Its
purpose is to complement, not usurp, the reasonable progress analysis.
Based on the analysis of the four statutory factors required under the
CAA and Regional Haze regulations, a state (or EPA in a FIP) may
determine that a greater or lesser amount of visibility improvement
than what is reflected in the URP is necessary to demonstrate
reasonable progress.\109\ Based on our analysis of the factors under
CAA section 169A(g)(1) and Sec. 51.308(d)(1), along with consideration
of the visibility improvement of controls, we determined that there are
reasonable controls available for Independence that would be cost-
effective and would result in meaningful visibility benefit at
Arkansas' Class I areas. Because we have identified that additional
progress (beyond the amount reflected in the URP) is reasonable based
on the statutory factors and our consideration of the visibility
impacts, we are required to adopt that amount of progress under the
reasonable progress requirements. It is for this reason, we are
requiring controls on Independence. It is not, as some commenters
contend, ``for the sole purpose of achieving emissions reductions.''
---------------------------------------------------------------------------
\109\ 64 FR 35714, 35732.
---------------------------------------------------------------------------
We note that our conclusion here is consistent with our final
action on the Arkansas Regional Haze SIP, where we disapproved
Arkansas' RPGs specifically because the state established its RPGs
without conducting an evaluation of the four statutory factors and did
so based on the fact that its Class I areas are below the URP
glidepath. In the preamble to our final action on the Arkansas Regional
Haze SIP, we were clear that an evaluation of the four statutory
factors is required regardless of the Class I area's position on the
URP glidepath:
[B]eing on the ``glidepath'' does not mean a state is allowed to
forego an evaluation of the four statutory factors when establishing
its RPGs. Based on an evaluation of the four statutory factors,
states may determine that RPGs that provide for a greater rate of
visibility improvement than would be achieved with the URP for the
first implementation period are reasonable.\110\
---------------------------------------------------------------------------
\110\ 77 FR at 14629.
Our final action on the Arkansas Regional Haze SIP was published in
the Federal Register on March 12, 2012, and became effective on April
11, 2012. We reiterate in this final action that the CAA and Regional
Haze regulations require an analysis of the four reasonable progress
factors regardless of a Class I area's position on the URP and that
being below the glide path does not automatically mean that no controls
are necessary under reasonable progress.
With regard to the comment contending that we are ignoring data
from ADEQ's Five-Year Progress Report SIP revision, we note that
Arkansas submitted the first 5-year report to EPA in June 2015, and
that we are not addressing that SIP revision within this action.\111\
The 5-year progress report is a separate requirement from the regional
haze SIP required for the first and subsequent planning periods, and it
has separate content and criteria for review. We are therefore not
obligated to consider or take action on the 5-year progress report at
the same time we promulgate our FIP.
---------------------------------------------------------------------------
\111\ We anticipate taking action on ADEQ's Five Year Progress
Report SIP revision in a separate, future action.
---------------------------------------------------------------------------
We acknowledge that recent IMPROVE monitoring data indicate there
has been visibility improvement in Arkansas' Class I areas. But even
assuming that the current trend in visibility improvement will
continue, as the commenter argues, this does not divest us from our
authority and obligation to conduct a reasonable progress analysis, nor
does it justify the dismissal of controls for Independence that we have
determined, pursuant to that analysis, are cost-effective and would
result in meaningful visibility benefit at Arkansas' Class I areas. The
commenters point out that even without the BART and reasonable progress
controls required by our FIP, Caney Creek has achieved 73% and Upper
Buffalo has achieved 66% of their respective 2018 RPGs established by
Arkansas based on 5-year average data from IMPROVE monitors as of 2011.
However, even if we had approved these RPGs (which we did not),
achieving or being projected to achieve the RPG does not necessarily
demonstrate that a state has satisfied its requirements under BART and
reasonable progress. The state or EPA must complete the requisite
analyses to determine appropriate controls and emission limits under
the BART and reasonable progress requirements, and must adopt and
enforce these controls and emission limits. The numeric RPGs are
calculated by taking into account the visibility improvement
anticipated from these enforceable emission limitations and other
control measures (including BART, reasonable progress, and other ``on
the books'' controls). The Regional Haze Rule provides that these
emission limitations and control measures are what is enforceable, not
the RPGs
[[Page 66362]]
themselves.\112\ Thus, the RPGs are intended to provide a degree of
transparency regarding the rate of improvement in visibility
anticipated for each Class I area over the planning period of the
SIP.\113\
---------------------------------------------------------------------------
\112\ 64 FR 35714, 35733.
\113\ The RPGs are intended to provide the state or EPA's best
estimate of the amount of visibility improvement in deciviews
anticipated for each Class I area over the planning period of the
SIP or FIP.
---------------------------------------------------------------------------
As noted above, we disapproved Arkansas' RPGs in our March 12, 2012
final action on the Arkansas Regional Haze SIP \114\ because the state
did not complete the required four-factor analysis in establishing the
RPGs. Further, the state's RPGs were based on BART determinations that
were not in accordance with the CAA and Regional Haze regulations. As
such, the State's RPGs are not a reflection of the controls necessary
to make reasonable progress, and any arguments upholding or suggesting
that the state's RPGs are appropriate or adequate are outside the scope
of this action. That Arkansas' Class I areas are on track to achieve
the disapproved RPGs by 2018 does not mean that the reasonable progress
requirements have been satisfied, nor does it justify no additional
controls under reasonable progress.
---------------------------------------------------------------------------
\114\ 77 FR 14604.
---------------------------------------------------------------------------
Comment: Some commenters argued that our FIP proposal was improper
because it adopted an individual source-based approach to setting RPGs,
and that this is inconsistent with the CAA. Another commenter claimed
that EPA failed to explain how factors required to be considered in
setting the RPGs, which are themselves not enforceable, could somehow
be used to require specific enforceable limits for a single plant.
Response: While our FIP does consider and ultimately apply controls
on an individual source basis to assure reasonable progress, this is
consistent with the CAA, our regulations, and past EPA guidance. The
four statutory factors under CAA Section 169A(g) and 40 CFR
51.308(d)(1)(i)(A) are directed to the listed possible features or
consequences of potential emission control measures for sources,
including individual stationary sources. The CAA and the Regional Haze
regulations expressly set forth that the reasonable progress analysis
must consider the ``compliance'' time and costs for ``potentially
affected sources.'' A state determines the rate of progress that is
reasonable for a Class I area after taking into account the four
statutory factors-- as applied to specific sources or groups of
sources--to determine what additional controls should be required in
its regional haze SIP. Thus, individual stationary sources may be
subject to emission limits and source specific analysis when
determining whether additional controls are necessary to make
reasonable progress.
The commenter's suggestion that because the RPGs are not themselves
enforceable we cannot require specific enforceable limits for a single
plant is not consistent with the requirement that each regional haze
SIP or FIP include enforceable emissions limitations as necessary to
ensure that the SIP or FIP will provide reasonable progress toward the
national goal of natural visibility conditions. The numeric RPGs
established by the state or EPA represent the best estimate of the
degree of visibility improvement that will result in 2018 from changes
in emissions inventories, changes driven by the particular set of
control measures the state has adopted in its regional haze SIP or EPA
in a regional haze FIP to address visibility, as well as all other
enforceable measures expected to reduce emissions over the period of
the SIP from 2002 to 2018.\115\ Thus, the RPGs are intended to provide
a degree of transparency regarding the rate of improvement in
visibility anticipated for each Class I area over the planning period
of the SIP. But the RPGs themselves are not enforceable.\116\ EPA
cannot enforce an RPG in the sense of seeking to apply penalties on a
state for failing to meet the RPG or obtaining injunctive relief to
require a state to achieve its RPG. However, the long-term strategy can
and must contain emission limits and other control measures that apply
to specific sources under the reasonable progress requirements, and
that are themselves enforceable. The fact that the RPGs are not
enforceable does not mean that we cannot conduct a source-specific
evaluation of the reasonable progress factors or require source-
specific emission limits under the reasonable progress requirements.
---------------------------------------------------------------------------
\115\ 64 FR at 35733.
\116\ See 51.308(d)(1)(v).
---------------------------------------------------------------------------
Comment: EPA treated Independence Units 1 and 2 as if they were
subject-to-BART units by ignoring whether controls at the units are
needed to improve visibility and looking only at whether controls are
cost effective. EPA's failure to assess and document the contribution
to visibility impairment at any relevant Class I area from any Arkansas
point source, including Independence, is contrary to past rulemakings
and is inconsistent with the detailed approach taken by EPA Region 6 in
its promulgation of the Texas Regional Haze FIP. The Independence plant
was apparently singled out by EPA for additional pollution controls
under reasonable progress, while other non-BART emission sources were
not. EPA does not provide any explanation for its selective treatment
in this case other than noting that the Independence is among the top
three largest point sources in the state. EPA's justification for
imposing SO2 and NOX emission limits on
Independence is not based on rational policy, legal, or environmental
grounds and, as a result, it is arbitrary and capricious. EPA's primary
justification for proposing reasonable progress limits at Independence
is that ``it would be unreasonable to ignore a source representing more
than a third of the State's SO2 emissions and a significant
portion of NOX point source emissions.'' EPA further
supports its conclusion that emission limits based on the installation
of major control technology are justified based on a finding that the
proposed controls at Independence are cost effective. However, the fact
that a source, which is not subject to BART, may have significant
SO2 or NOX emissions, or that it would be cost
effective to control such emissions, is irrelevant for reasonable
progress purposes. This is an inapplicable and inadequate justification
to identify sources for control under a reasonable progress analysis.
EPA did not appropriately analyze which sources, if any, should be
controlled for reasonable progress and did not follow the procedures it
has regularly used in other regional haze FIPs.
Response: We did not treat Independence as if it were a subject-to-
BART source, nor did we ignore whether controls at the facility are
needed to improve visibility, or only look at whether controls are cost
effective. Under the CAA and 40 CFR 51.308(d)(1), we must consider the
following four factors in our reasonable progress analysis: (1) The
costs of compliance; (2) the time necessary for compliance; (3) the
energy and nonair quality environmental impacts of compliance; and (4)
the remaining useful life of any potentially affected sources. These
are the factors we took into consideration in our proposal. As we
discuss in our proposal and elsewhere in this final rule, although
visibility is not one of the four mandatory factors explicitly listed
for consideration under CAA section 169A(g)(1) or 40 CFR
51.308(d)(1)(i)(A), states or EPA have the option of considering the
projected visibility
[[Page 66363]]
benefits of controls in determining if the controls are necessary to
make reasonable progress. We modeled both the baseline visibility
impacts from the Independence facility and the visibility benefit of
controls using CALPUFF dispersion modeling. Based on our consideration
of the four reasonable progress factors as well as the baseline
visibility impacts from Independence and the visibility improvement of
potential controls, we determined that reasonable controls for
SO2 and NOX are available for Independence Units
1 and 2 that are cost effective and would result in a large amount of
visibility improvement in Arkansas' Class I areas in terms of the 98th
percentile impacts from the source.\117\ Therefore, the claim that we
ignored whether controls at the units are needed to improve visibility
is incorrect.
---------------------------------------------------------------------------
\117\ CAMx source apportionment modeling was submitted to us by
Entergy Arkansas Inc. during the comment period. This modeling shows
that Independence has significant visibility impacts in Arkansas
Class I areas on the 20% worst days, and further supports our
decision to require controls for Independence under reasonable
progress. We discuss Entergy Arkansas Inc.'s photochemical modeling
and the visibility impacts due to SO2 and NOX
from Independence on the 20% worst days elsewhere in this final
rule.
---------------------------------------------------------------------------
We also disagree that the fact that a non-BART source has
significant SO2 or NOX emissions, or that it
would be cost-effective to control such emissions, is irrelevant in
determining what sources to take a closer look at and evaluate under
reasonable progress. As noted above, the cost of compliance is one of
the statutory factors that EPA is required to consider in a reasonable
progress analysis, meaning that the cost effectiveness of potential
controls is not irrelevant for reasonable progress purposes.
Significant SO2 or NOX emissions from a source is
generally an indication that there may be significant visibility
impacts at nearby Class I areas and that installation of more effective
controls, if any are available, may result in substantial emissions
reductions and meaningful visibility improvement. As noted above,
states and EPA have the option of considering the projected visibility
benefits of controls in determining if the controls are necessary to
make reasonable progress. Therefore, we find that consideration of a
source's emissions and whether it would be cost-effective to control
such emissions is appropriate and relevant for reasonable progress
purposes.
The commenter makes the incorrect claim that our primary
justification for imposing emission limits under reasonable progress
for Independence Units 1 and 2 is that it would be unreasonable to
ignore a source representing more than a third of the state's
SO2 emissions and a significant portion of NOX
point source emissions. While we did state in our FIP proposal that it
would be unreasonable to ignore a source representing more than a third
of the state's SO2 emissions and a significant portion of
NOX point source emissions, the commenters took this
statement out of context. The full citation from our FIP proposal
referenced by the commenters is the following:
We believe it is appropriate to evaluate Entergy Independence
even though Arkansas Class I areas and those outside of Arkansas
most significantly impacted by Arkansas sources are projected to
meet the URP for the first planning period. This is because we
believe that in determining whether reasonable progress is being
achieved, it would be unreasonable to ignore a source representing
more than a third of the State's SO2 emissions and a
significant portion of NOX point source emissions.\118\
---------------------------------------------------------------------------
\118\ 80 FR at 18992.
As evidenced by the full citation from our FIP proposal, the fact
that we considered it unreasonable to ignore a source representing more
than a third of the State's SO2 emissions and a significant
portion of NOX point source emissions was our primary
justification for looking more closely and evaluating the Independence
plant in our reasonable progress analysis. It was not, as the commenter
contends, our justification for imposing controls on Independence. As
we discuss in our FIP proposal and elsewhere in this final action, our
decision to require controls on Independence is based on our analysis
under Sec. 51.308(d)(1), as required by the CAA and Regional Haze
Rule.
We do not agree with the commenter's allegation that we did not
appropriately analyze what sources, if any, should be controlled under
reasonable progress. To the extent that the commenter contends that our
process for determining which sources should be evaluated under
reasonable progress was incorrect because we did not conduct
photochemical modeling, such argument is incorrect. To the extent that
the commenter contends that we treated the Independence facility like a
BART source because we evaluated it under the reasonable progress
requirements without conducting photochemical modeling to identify
potential sources to evaluate under reasonable progress, this is also
incorrect. We are not required to conduct photochemical modeling in a
reasonable progress analysis. Our 2007 Reasonable Progress Guidance
states that ``The RHR gives States wide latitude to determine
additional control requirements, and there are many ways to approach
identifying additional reasonable measures; however, you must at a
minimum, consider the four statutory factors.'' \119\ The states or EPA
in the context of a FIP have wide discretion in deciding what
approaches, methods, and tools to use in identifying source categories,
specific point sources, or pollutants to evaluate for additional
controls under the reasonable progress requirements, provided that a
reasonable rationale for the approach used is provided. There are a
number of different approaches states or EPA in the context of a FIP
have used in identifying sources for reasonable progress evaluation,
but they usually center around the general premise of evaluating the
biggest sources and/or the biggest impactors on visibility. While the
states or EPA have the discretion to consider visibility in a
reasonable progress analysis, photochemical modeling is not required
for purposes of conducting a reasonable progress analysis.
---------------------------------------------------------------------------
\119\ ``Guidance for Setting Reasonable Progress Goals Under the
Regional Haze Program,'' at 4-2.
---------------------------------------------------------------------------
Our FIP proposal provided a detailed explanation of how we
determined what sources to evaluate for controls under reasonable
progress, and we provided a reasonable rationale for the approach we
used. The first step in our analysis involved determining what source
categories or specific point sources it would be appropriate to look at
more closely and evaluate under the reasonable progress requirements in
Sec. 51.308(d)(1) to determine if additional controls are necessary.
We explained in our proposal that it was appropriate to focus our
analysis on point sources since the other source categories (i.e.,
natural, on-road, non-road, and area) each contribute a much smaller
proportion of the total light extinction at each Class I area in
Arkansas based on the CENRAP CAMx modeling.\120\ At Caney Creek, point
sources contribute 81.04 Mm-1 out of a total light
extinction of 133.93 Mm-1 on the average across the 20%
worst days in 2002, or approximately 60.5% of the total light
extinction. At Upper Buffalo, point sources contribute 77.80
Mm-1 out of a total light extinction of 131.79
Mm-1 on the average across the 20% worst days in 2002, or
approximately 59% of the total light extinction. In comparison, area
sources, which are the source category with the next highest
contribution to the total light extinction at each Class I area,
contribute approximately 13.3% of the total light
[[Page 66364]]
extinction at Caney Creek and 15.5% at Upper Buffalo. The remaining
source categories each contribute less than 6% of the total light
extinction at each Class I area. Therefore, we concluded that it was
appropriate to focus our analysis on point sources.
---------------------------------------------------------------------------
\120\ See 80 FR 18944, 18989.
---------------------------------------------------------------------------
The CENRAP CAMx modeling shows that on most of the 20% worst days
in 2002, total extinction was dominated by sulfate at both Caney Creek
and Upper Buffalo.\121\ Additionally, total extinction at Caney Creek
was dominated by nitrate on 4 of the days that comprise the 20% worst
days in 2002 and a significant portion of the total extinction at Upper
Buffalo on 2 of the days that comprise the 20% worst days in 2002 was
due to nitrate.\122\ The CENRAP CAMx modeling also shows that sulfate
from point sources was responsible for approximately 54.8% of the total
visibility impairment at Upper Buffalo and 56.1% at Caney Creek on the
20% worst days in 2002. Nitrate from point sources was responsible for
approximately 3% of the total visibility impairment at each Class I
area on the 20% worst days in 2002. As such, although SO2
emissions are the primary contributor to regional haze in Arkansas'
Class I areas on the 20% worst days, NOX emissions are also
a key contributor. Thus, consistent with our Guidance for Setting
Reasonable Progress Goals Under the Regional Haze Program,\123\ we
found it appropriate to evaluate both SO2 and NOX
controls under reasonable progress.
---------------------------------------------------------------------------
\121\ See Arkansas Regional Haze SIP, Appendix 8.1--``Technical
Support Document for CENRAP Emissions and Air Quality Modeling to
Support Regional Haze State Implementation Plans,'' sections 3.7.1
and 3.7.2. See the docket for this rulemaking for a copy of the
Arkansas Regional Haze SIP.
\122\ See Arkansas Regional Haze SIP, Appendix 8.1--``Technical
Support Document for CENRAP Emissions and Air Quality Modeling to
Support Regional Haze State Implementation Plans,'' section 3.7.1
and 3.7.2. See the docket for this rulemaking for a copy of the
Arkansas Regional Haze SIP.
\123\ ``Guidance for Setting Reasonable Progress Goals Under the
Regional Haze Program,'' at 2-3 and 3-1.
---------------------------------------------------------------------------
We explained in our FIP proposal that as a starting point in our
analysis to determine whether additional controls on Arkansas point
sources are reasonable in the first regional haze planning period, we
examined the most recent SO2 and NOX emissions
inventories for point sources in Arkansas (NEI 2011 v1).\124\ We
reasoned that examination of the emissions inventories is appropriate
because significant SO2 or NOX emissions from a
source are generally an indication that it may be having significant
visibility impacts at nearby Class I areas and that installation of
controls may result in substantial emissions reductions and meaningful
visibility improvement. We did not conduct photochemical modeling or
other more exhaustive analyses to identify potential candidates to
evaluate under reasonable progress, and while we recognize that this
approach is different from the approaches and methods that we have used
or approved in other regional haze actions, we find that the approach
we are taking in this action is appropriate given the specific
circumstances. In particular, our examination of the SO2 and
NOX emissions inventories for Arkansas' point sources
revealed that the number of point sources that emit SO2 and
NOX emissions is relatively small. Furthermore, a very small
portion of the point sources in the state is responsible for a large
portion of the statewide SO2 and NOX point source
emissions. Specifically, White Bluff, Independence, and Flint Creek are
collectively responsible for approximately 84% of the SO2
point source emissions and 55% of the NOX point source
emissions in the state. Consequently, addressing these sources under
the regional haze program will address a large proportion of the
visibility impacts due to Arkansas point sources. We are requiring
SO2 and NOX controls for White Bluff and Flint
Creek under the BART requirements in this final action, which will
substantially reduce emissions from these two facilities. The
Independence Plant, which is not a subject-to-BART source, contributes
approximately 36.2% of the total SO2 point source emissions
in the state (30,398 SO2 tons out of total SO2
point source emissions of 83,883 SO2 tons, based on the 2011
NEI).\125\ This source also contributes approximately 21.3% of the
total NOX point source emission in the state (13,411
NOX tons out of total NOX point source emissions
of 62,984 NOX tons). Based on this examination, we
determined that the magnitude of emissions from the Independence Plant
warranted further evaluation of the source to determine if it is a
significant contributor to regional haze in Arkansas' Class I areas and
whether controls at the facility are needed based on an analysis under
Sec. 51.308(d)(1).
---------------------------------------------------------------------------
\124\ 80 FR at 18991.
\125\ See NEI 2011 v1. A spreadsheet containing the emissions
inventory is found in the docket for our proposed rulemaking.
---------------------------------------------------------------------------
After White Bluff, Independence, and Flint Creek, the remaining
point sources in the state have much lower SO2 and
NOX emissions than these facilities. In other words, the
magnitude of SO2 and NOX emissions from point
sources in Arkansas drops off considerably after the top 3 emitters. We
stated the following in our proposal:
The fourth largest SO2 and NOX point
sources in Arkansas are the Future Fuel Chemical Company, with
emissions of 3,421 SO2 tpy, and the Natural Gas Pipeline
Company of America #308, with emissions of 3,194 NOX tpy
(2011 NEI). In comparison to the emissions of the top three sources,
emissions from these two facilities are relatively small. Therefore,
we are not proposing controls in this first planning period for
these two facilities because we believe it is appropriate to defer
the consideration of any additional sources besides Independence to
future regional haze planning periods.\126\
---------------------------------------------------------------------------
\126\ 80 FR at 18992.
Future Fuel Chemical Company, the point source with the fourth
highest SO2 emissions (after White Buff, Independence, and
Flint Creek), contributes approximately 4.1% of the total
SO2 point source emissions in the state (3,420
SO2 tons out of total SO2 point source emissions
of 83,883 SO2 tons, based on the 2011 NEI). The Natural Gas
Pipeline Company of America #308, the point source with the fourth
highest NOX emissions, contributes approximately 5.1% of the
total NOX point source emission in the state 3,194
NOX tons out of total NOX point source emissions
of 62,984 NOX tons, based on the 2011 NEI). Based on the
much smaller magnitude of these sources' emissions, we determined that
the remaining point sources in the state are less likely to be
significant contributors to regional haze, and thus did not warrant
closer evaluation under reasonable progress in this planning period. As
such, we found that it is appropriate to evaluate Independence for
controls under reasonable progress. The claim that we arbitrarily
singled out Independence and that we provided no explanation as to why
we did not evaluate other point sources under reasonable progress is
not supported by the record in this action.
Because our examination of the Arkansas emissions inventory
revealed that the number of point sources that emit SO2 and
NOX emissions is relatively small and that a very small
portion of the point sources in the state are responsible for a large
portion of the statewide SO2 and NOX point source
emissions, we concluded that photochemical modeling or other more
exhaustive analyses that we have performed in other regional haze
actions were unnecessary to identify point sources to evaluate under
reasonable progress. In contrast, in states such as Texas, where the
universe of point
[[Page 66365]]
sources is much larger and the distribution of SO2 and
NOX emissions is very widespread, an evaluation of the
state's emissions inventory alone was not sufficient to reveal the best
potential candidates for evaluation under reasonable progress. For this
reason, we explained in our Texas Regional Haze FIP that due to the
challenges presented by the geographic distribution and number of
sources in Texas, the CAMx photochemical model was best suited for
identifying sources to evaluate for reasonable progress controls.\127\
We did not encounter these challenges in the development of our
reasonable progress analysis for Arkansas and therefore did not conduct
photochemical modeling.
---------------------------------------------------------------------------
\127\ 81 FR 296.
---------------------------------------------------------------------------
We do note that while we did not conduct photochemical modeling to
identify Arkansas point sources to evaluate under reasonable progress,
Entergy conducted CAMx source-apportionment modeling and submitted it
during the comment period. Entergy's CAMx source apportionment modeling
showed that emissions from the Independence facility alone are
projected to contribute approximately 1.3% of the total visibility
impairment in 2018 on the 20% worst days at each Arkansas Class I area.
This is a large portion (approximately one-third) of the total
contribution from all Arkansas point sources, and we consider it to be
a significant contribution to visibility impairment Arkansas' Class I
areas on the 20% worst days. The CAMx modeling also showed that at
Upper Buffalo, the Independence facility's contribution to visibility
impairment is greater than the contribution from all of the subject-to-
BART sources addressed in this final action combined. In terms of
deciviews, the average impact from Independence over the 20% worst
days, based on Entergy's CAMx modeling and adjusted to natural
background conditions, is over 0.5 dv at the Arkansas Class I areas.
The results of Entergy's CAMx modeling confirm and provide additional
support to our determination that Independence significantly impacts
visibility at Arkansas' Class I areas.
Additionally, we note that because of the controls required during
this planning period, we expect that the impact from the facilities in
Arkansas that were not controlled and not specifically evaluated in the
first planning period will become larger on a percentage basis. These
sources will become the largest impacting sources and should be
considered for analysis under reasonable progress in future planning
periods. The methodology we used here thus allows a consistent
procedure to identify facilities for additional control analysis in
this and future planning periods and ensures continuing progress
towards the goal of natural visibility conditions.
To the extent the commenter contends that additional controls under
reasonable progress cannot or should not be evaluated or required
unless controls beyond BART are needed for Arkansas to be on or below
the URP glidepath or to meet the RPGs established by the state (which,
in the case of Arkansas, we disapproved in a previous final action),
this is incorrect. As we discuss elsewhere in this section of the final
rule and in our RTC document, there is nothing in the CAA or Regional
Haze regulations that suggests that a State's obligations to ensure
reasonable progress can be met simply by being on or below the URP
glidepath or meeting the state's RPGs.\128\
---------------------------------------------------------------------------
\128\ See 77 FR at 14629.
---------------------------------------------------------------------------
Comment: EPA's own analysis counsels against imposing additional
controls on the Independence Plant. EPA asserts that CENRAP modeling
shows that sulfate from all point sources is projected to contribute to
57% of the total light extinction at Caney Creek on the worst 20% days
in 2018 and 43% of the total light extinction at Upper Buffalo. Nitrate
from all point sources is projected to account for only 3% of the total
light extinction at the Class I areas. However, the CENRAP modeling
also projects that sulfate from Arkansas point sources will be
responsible for only 3.58% of the total light extinction at Caney Creek
and 3.20% at Upper Buffalo. The contribution of nitrate from Arkansas
point sources to visibility impairment is even more insignificant,
accounting for only 0.29% of the total light extinction at Caney Creek
and 0.25% at Upper Buffalo. The Independence Plant's share of emissions
to this minimal contribution from Arkansas point sources is even
smaller. Despite these very small contributions, EPA's proposal
concludes that SO2 and NOX controls at the
Independence Plant are warranted and reasonable. EPA lacks evidence of
a sufficient need to evaluate additional controls for Arkansas point
sources and lacks a sufficient basis to justify additional controls.
Response: The commenter appears to believe that the CENRAP modeling
shows that the visibility impacts on the 20% worst days from Arkansas
point sources, and from Independence in particular, are very small. We
disagree that these visibility impacts are insignificant. As we discuss
above, Entergy's CAMx source apportionment modeling showed that the
contribution to visibility impairment due to emissions from the
Independence facility alone are projected to be approximately 1.3% of
the total visibility impairment during the 20% worst days in 2018 at
each Arkansas Class I area. This is a large portion (approximately one-
third) of the total contribution from all Arkansas point sources, and
we consider this to be a significant contribution to visibility
impairment. Entergy's CAMx modeling also showed that at Upper Buffalo,
the Independence facility's contribution to visibility impairment is
greater than the contribution from all of the subject-to-BART sources
addressed in this final action combined. In terms of deciviews, the
average impact from Independence over the 20% worst days, based on
Entergy's CAMx modeling and adjusted to natural background conditions,
is over 0.5 dv at the Arkansas Class I areas. The results from
Entergy's CAMx modeling confirm and provide additional support to our
determination that the source significantly impacts visibility at
Arkansas' Class I areas and should be evaluated for controls under
reasonable progress.
As discussed in our proposal and elsewhere in this final rule, we
have found that dry scrubbers for SO2 control are cost
effective and are expected to provide significant visibility
improvements to the facility's 98th percentile visibility impacts as
shown by our CALPUFF modeling. We have also found that NOX
controls in the form of LNB/SOFA on Independence are very cost
effective and are expected to provide considerable visibility
improvements to the 98th percentile visibility impacts.
Based on Entergy's CAMx modeling, SO2 emissions are
responsible for a majority of the visibility impacts from Independence
on the 20% worst days and NOX emissions are responsible for
30-40% of the visibility impairment on 2 of the 20% worst days.\129\
The controls we are requiring will significantly reduce SO2
and NOX emissions from Independence, and accordingly, we
expect that they will also significantly reduce the significant
visibility impacts from the facility on the 20% worst days. Therefore,
we disagree that these controls are not necessary and/or that they
would not improve visibility in Arkansas Class I areas. Based on our
consideration of the four reasonable progress factors and of the
visibility improvement of controls, we are
[[Page 66366]]
requiring both SO2 and NOX controls for
Independence Units 1 and 2 under the reasonable progress requirements.
---------------------------------------------------------------------------
\129\ This means 2 out of the 21 days that are the 20% worst of
the days with IMPROVE monitoring data.
---------------------------------------------------------------------------
Comment: The RPG and URP in the Arkansas Regional Haze SIP should
be accepted as presented by the State since ADEQ's Five Year Progress
Report SIP revision demonstrates that Arkansas is on track to achieve
its RPGs and is below the URP glidepath. EPA's disapproval of the
Arkansas Regional Haze SIP submitted to EPA in 2008 was not due to lack
of reasonable progress to achieve visibility improvement or for missing
the URP. It was disapproved primarily because the underlying emissions
were based on presumptive limits and no BART evaluations had been
conducted. EPA's proposed FIP and the controls for Independence only
serve to achieve greater emissions reductions than in the Arkansas
Regional Haze SIP. Therefore, EPA should not look beyond BART eligible
units to achieve greater visibility improvements. EPA should not simply
use the regional haze program as leverage to impose emissions
reductions that have little benefit to the purpose of the rule to
improve visibility.
Response: We disagree that we should accept Arkansas' RPGs as
presented in the Arkansas Regional Haze SIP submitted to us in 2008. We
partially approved and partially disapproved the Arkansas Regional Haze
SIP in our final action published on March 12, 2012.\130\ In that final
action, we disapproved a large portion of the state's BART
determinations, as well as the state established RPGs. We disapproved
the state's RPGs because they were based on BART determinations that
were not made in accordance with the CAA and Regional Haze regulations
and also because in establishing the RPGs, the state did not conduct
the reasonable progress analysis required under the CAA and Sec.
51.308(d)(1). As discussed in a separate response, the state decided to
forego an evaluation of the four statutory factors, stating that there
was no need for such an evaluation since Arkansas' Class I areas are
below the URP glidepath. In foregoing the reasonable progress analysis,
the state did not demonstrate that the RPGs it established were a
reflection of the amount of visibility improvement necessary to make
reasonable progress. Our final action disapproving Arkansas' RPGs for
Caney Creek and Upper Buffalo became effective on April 11, 2012. Any
arguments upholding or suggesting that the state's RPGs are appropriate
or adequate are outside the scope of this action.
---------------------------------------------------------------------------
\130\ 77 FR 14604.
---------------------------------------------------------------------------
Under section 110(c) of the Act, whenever we disapprove a mandatory
SIP submission in whole or in part, we are required to promulgate a FIP
within two years unless we approve a SIP revision correcting the
deficiencies before promulgating a FIP. To date, Arkansas has not
submitted a SIP revision following our partial disapproval, and EPA is
already past-due on its action per the statutory deadlines. In
addition, EPA is under an August 31, 2016 court ordered deadline to
either finalize a FIP or approve a SIP to address the regional haze
requirements and the interstate visibility transport requirements.
Therefore, the purpose of our FIP is to correct the deficiencies in the
SIP and conduct the required analyses and establish emission limits in
accordance with the CAA and the Regional Haze Rule. One of the required
analyses we must conduct in this FIP is the consideration of the four
statutory factors to determine if additional controls are needed to
make reasonable progress. We discuss in a separate response that the
reasonable progress requirements under CAA section 169A(g)(1) and our
Regional Haze regulations at Sec. 51.308(d)(1) cannot be satisfied by
merely being below the URP glidepath and/or meeting the RPGs previously
established by the state. The states or EPA in a FIP must conduct an
analysis of the four statutory factors regardless of the Class I area's
position on the URP glidepath. Based on our consideration of the four
statutory factors and of the baseline visibility impacts from
Independence and the visibility improvement of potential controls, we
determined that reasonable controls for SO2 and
NOX are available for Independence Units 1 and 2 that are
cost effective and would result in a large amount of visibility
improvement in Arkansas' Class I areas in terms of the 98th percentile
impacts from the source. Additionally, as we discuss in section V.J of
this final rule, CAMx source apportionment modeling submitted to us by
Entergy during the comment period shows that Independence has
significant visibility impacts in Arkansas' Class I areas on the 20%
worst days, and further supports our decision to require controls for
Independence under reasonable progress. Therefore, the claim that the
SO2 and NOX controls we are requiring for
Independence Units 1 and 2 only serve to achieve greater emissions
reductions that have little benefit to the purpose of the Regional Haze
Rule to improve visibility are incorrect. Because we have identified
through our reasonable progress analysis that additional controls are
reasonable, we are requiring these controls for Independence Units 1
and 2. We address elsewhere in this final rule and in the RTC document
comments related to ADEQ's 5-year Progress Report SIP revision.
Comment: EPA's imposition of costly controls on BART-ineligible
sources like the Independence plant, based only on what it claims is
``reasonable,'' is economically wasteful and effectively re-writes the
definition of what sources are BART eligible. Under the regional haze
program, BART controls may be imposed on (1) major stationary sources
in 26 listed categories, (2) that existed on August 7, 1977, (3) but
were not in operation prior to August 7, 1962, and (4) emit air
pollutants ``which may reasonably be anticipated to cause or contribute
to any impairment of visibility'' at Class I areas. Under the proposed
rule, the first three of these statutory and regulatory criteria would
be rendered a nullity. According to EPA, it may impose BART controls on
any facility, regardless of when it was built or when it began
operating, so long as EPA determines it to be ``reasonable.'' EPA has
effectively adopted a presumption that at least some BART-ineligible
sources should be subject to BART unless those pollution controls are
cost prohibitive. Such a presumption ignores the statute and re-writes
EPA's own regulations.
Response: We are requiring controls on Independence under the
reasonable progress requirements, not under the BART requirements.
Clean Air Act section 169A required us to promulgate regulations
directing the States to revise their SIPs to include emission limits
and other measures as necessary to make ``reasonable progress.'' \131\
Congress defined reasonable progress based on the consideration of four
statutory factors: The costs of compliance, the time necessary for
compliance, the energy and nonair quality environmental impacts of
compliance, and the remaining useful life of any existing source
subject to such requirements.\132\ We commonly refer to our analysis of
these four statutory factors as a reasonable progress analysis.
Congress also directed EPA to promulgate regulations requiring BART for
a specific universe of older sources, and again provided a set of
statutory factors States must consider: The costs of compliance, the
energy and nonair
[[Page 66367]]
quality environmental impacts of compliance, any existing pollution
control technology in use at the source, the remaining useful life of
the source, and the degree of improvement in visibility which may
reasonably be anticipated to result from the use of such
technology.\133\ We note that many of the factors that must be
considered in a BART analysis must also be considered in the reasonable
progress analysis. Therefore, some commenters may mistakenly believe
that we are somehow stretching the BART analysis to impose BART
controls on Independence Units 1 and 2. This is not the case. As
discussed in our proposal and elsewhere in this final rule, in our
reasonable progress analysis, we considered the reasonable progress
statutory factors as well as the visibility improvement of potential
controls. Although visibility is not one of the four mandatory factors
explicitly listed for consideration under CAA section 169A(g)(1) or 40
CFR 51.308(d)(1)(i)(A), states and EPA have the option of considering
the projected visibility benefits of controls in determining if the
controls are necessary to make reasonable progress. We discuss this in
more detail in our proposal and in our RTC document. Based on our
analysis of the four statutory factors and consideration of the
visibility improvement of controls, we have determined that there are
SO2 and NOX controls available for Independence
Units 1 and 2 that are cost-effective and would result in considerable
visibility benefit at Arkansas' Class I areas, and are therefore
requiring these controls under reasonable progress.
---------------------------------------------------------------------------
\131\ CAA section 169A(b)(2).
\132\ CAA section 169A(g)(1).
\133\ CAA section 169A(b)(2)(A), (g)(2).
---------------------------------------------------------------------------
To the extent the commenter believes that we treated the
Independence Plant as if it were subject to BART in performing a
source-specific reasonable progress analysis, this is incorrect. As we
discuss elsewhere in this section of the final rule, individual
stationary sources may be subject to source-specific analysis when
determining whether additional controls are necessary to make
reasonable progress. To the extent the commenter believes that only
sources subject to BART can be looked to for emission reductions to
promote reasonable progress, this is incorrect. If that were the case,
then States, or EPA acting as necessary in the place of a State, would
have little to no room for additional progress and even less need for
sequential planning periods to build on past progress.
Comment: Some commenters claim that we inappropriately took a ``cut
and paste'' approach in estimating the cost of controls for
Independence in our reasonable progress analysis.
Response: We explained in our FIP proposal that White Bluff and
Independence are sister facilities with nearly identical units. We
explained that we verified that the two plants are sister facilities by
constructing a master spreadsheet that contains information concerning
ownership, location, boiler type, environmental controls, and other
pertinent information.\134\ The cost of compliance is a factor that is
required for consideration under both a BART and a reasonable progress
analysis. Due to the similarities in the facilities and the identical
requirement for consideration of the cost of controls under reasonable
progress and BART, our use of the total annualized costs of controls on
White Bluff Units 1 and 2 in our cost analysis for Independence Units 1
and 2 was a reasonable approach. We do note that we used actual
emissions data from Independence Units 1 and 2 to estimate the emission
reductions expected to take place from the controls we evaluated and to
calculate the cost effectiveness ($/ton removed) of controls for
Independence Units 1 and 2. Thus, the total annual cost of controls on
Independence was the only aspect of our reasonable progress analysis
where we relied on our cost analysis for White Bluff. Our consideration
of the remaining reasonable progress factors (time necessary for
compliance, energy and nonair quality environmental impacts of
compliance, and the remaining useful life of any potentially affected
sources), as well as the visibility impacts of Independence and
improvement due to controls on the facility, was specific to the
Independence facility.\135\ We modeled both the baseline visibility
impacts from the Independence facility and the visibility benefit of
controls using CALPUFF dispersion modeling. Based on our consideration
of the four reasonable progress factors and the modeled visibility
improvement of controls, we determined that reasonable controls for
SO2 and NOX are available for Independence Units
1 and 2 that are cost effective and would result in a large amount of
visibility improvement in Arkansas' Class I areas in terms of the 98th
percentile impacts from the source.\136\
---------------------------------------------------------------------------
\134\ 80 FR at 18992.
\135\ 80 FR at 18996.
\136\ Entergy Arkansas Inc. submitted CAMx source apportionment
modeling during the comment period. This modeling shows that
Independence has significant visibility impacts in Arkansas Class I
areas on the 20% worst days, and further supports our decision to
require controls for Independence under reasonable progress. We
discuss Entergy Arkansas Inc.'s photochemical modeling and the
visibility impacts due to SO2 and NOX from
Independence on the 20% worst days elsewhere in this final rule and
in our RTC document.
---------------------------------------------------------------------------
Comment: The CAA's regional haze program tasks states with making
reasonable progress toward the elimination of man-made visibility
impairment, for which EPA has set a goal of 2064 with required progress
milestones. Accordingly, the CAA's regional haze program contemplates
gradual visibility improvements along a ``glide path'' toward the 2064
goal. This program does not require immediate and costly reductions in
the first planning period or any subsequent planning period that go
beyond what is needed to make ``reasonable progress,'' as determined by
a state based on its assessment of the four statutory factors. Thus, it
neither requires nor authorizes the front-loading of extensive control
requirements. Delaying consideration of controls on Independence until
the next planning period is a more reasonable approach that would allow
for the consideration of updated information, such as control equipment
characteristics and costs, emissions reductions attributable to other
regulatory and market drivers, and contemporaneous monitoring and
meteorological conditions, which would allow the coordination of these
important investment and regulatory decisions with the implementation
of other pending regulations. This approach would also give states and
regulated entities the opportunity to conduct integrated compliance
planning in ways that are consistent with provision of reliable and
affordable electric power. EPA should withdraw its proposed controls
for Independence Units 1 and 2.
Response: We agree that the regional haze program contemplates
gradual visibility improvements over several planning periods. Those
gradual improvements are guided by the principle that controls found to
be reasonable in a given planning period should be required now, rather
than in some unspecified future planning period. That is the very
nature of ``reasonable progress.'' For that reason, we do not consider
the controls we proposed and those we finalize in this action as being
frontloading. As we discuss in several sections throughout this final
rule, our cost analysis indicates that the SO2 and
NOX controls we are requiring for Independence Units 1 and 2
are cost effective and well within the range of cost of controls found
to be reasonable by EPA and the
[[Page 66368]]
states in other regional haze actions for this first planning period.
Arkansas did not comply with certain aspects of the Regional Haze Rule
and thus portions of its Regional Haze SIP submitted to us in 2008 were
not approvable, including the state's reasonable progress
determinations and RPGs.\137\ We therefore have an obligation to
promulgate this FIP to address the disapproved portions of the State's
SIP submission. Pursuant to CAA section 169A(g)(1) and our Regional
Haze regulations at Sec. 51.308(d)(i)(A), we conducted an evaluation
of additional controls under a reasonable progress analysis that
considered the four statutory factors. As discussed in our proposal and
throughout this final rule, based on the demonstrations we developed
pursuant to the CAA and Sec. 51.308(d)(1) and our consideration of the
visibility impacts from Independence and the visibility improvement of
potential controls, we determined that there are reasonable and cost-
effective SO2 and NOX controls available for
Independence that would result in considerable visibility benefit at
Arkansas' Class I areas. Under the CAA and the Regional Haze
regulations, if we determine that additional controls are reasonable
based on the consideration of the four statutory factors, we must
require those controls. Therefore, we are requiring SO2 and
NOX controls for Independence Units 1 and 2 under reasonable
progress.
---------------------------------------------------------------------------
\137\ 77 FR 14604.
---------------------------------------------------------------------------
Comment: EPA applied dollar per ton cost-effectiveness estimates
and visibility improvement rates for the proposed controls on
Independence that are out of line with the standards applied in other
regional haze actions. Specifically, EPA's proposal attempts to justify
a cost-effectiveness of dry FGD at Independence Plant totaling $2,477/
SO2 ton removed for Unit 1 and $2,686/SO2 ton
removed for Unit 2. This far exceeds the cost-effectiveness standards
reviewed and approved by EPA for the Kentucky\138\ and North Carolina
Regional Haze SIPs.\139\ In its approval of the Kentucky Regional Haze
SIP, EPA approved the use of a $2,000 per ton SO2 screening
threshold. In its approval of the North Carolina Regional Haze SIP, EPA
approved the state's decision not to implement additional controls
under reasonable progress despite the finding that there are potential
controls with cost effectiveness ranging from $912 to $1,922 per ton of
SO2 removed. EPA's proposed controls for Independence are
inconsistent with these other regional haze actions.
---------------------------------------------------------------------------
\138\ 76 FR 78194, 78206 (December 16, 2011).
\139\ 77 FR 11858, 11870 (February 28, 2012).
---------------------------------------------------------------------------
Response: In response to comments we received during the comment
period, we have revised our cost analysis for SO2 controls
for Independence and estimate that these controls cost $2,853/
SO2 ton removed for Unit 1 and $2,634/SO2 ton
removed for Unit 2. Although slightly higher than the cost
effectiveness estimates we presented in our proposal, we continue to
consider these controls to be cost effective and well within the range
of cost of controls found to be reasonable by EPA and the states in
other regional haze actions. We disagree with the statement that our
proposal to require SO2 controls for Independence is
inconsistent with our approvals of the Kentucky and North Carolina
Regional Haze SIPs. Additionally, the factual contexts of both of these
actions are easily distinguished from context in which we assessed
potential reasonable progress controls for Independence.
The commenter contends that in our proposed approval of the
Kentucky Regional Haze SIP, we approved the state's use of a $2,000/
SO2 ton threshold. This is incorrect. In the preamble of our
proposed approval of the Kentucky Regional Haze SIP, we discussed that
the state identified 10 units for evaluation under reasonable progress,
and that 9 of these were EGUs subject to CAIR. The remaining facility,
Century Aluminum, is not an EGU. We further discussed that for the
limited purpose of evaluating the cost of compliance for the reasonable
progress assessment in this first regional haze SIP for the non-EGU
Century Aluminum, Kentucky concluded that it was not equitable to
require non-EGUs to bear a greater economic burden than EGUs for a
given control strategy. As a result, Kentucky decided to use CAIR as a
guide, using a cost of $2,000/ton of SO2 reduced as a
threshold for cost-effectiveness for that particular non-EGU source.
Kentucky found that the cost effectiveness of the SO2
control as suggested by the VISTAS control cost spreadsheet for
potlines 1-4 at Century Aluminum is $14,207/ton of SO2
removed. The State thus concluded that, based on the high cost on a $/
ton basis, there are no cost-effective SO2 reasonable
progress controls available for the Century Aluminum units for the
first implementation period. We proposed to approve Kentucky's
determination, but we also stated the following concerning our position
on Kentucky's use of a $2,000/SO2 ton threshold:
Although the use of a specific threshold for assessing costs
means that a state may not fully consider available emissions
reduction measures above its threshold that would result in
meaningful visibility improvement, EPA believes that the Kentucky
SIP still ensures reasonable progress. In proposing to approve
Kentucky's reasonable progress analysis, EPA is placing great weight
on the fact that there is no indication in the SIP submittal that
Kentucky, as a result of using a specific cost effectiveness
threshold, rejected potential reasonable progress measures that
would have had a meaningful impact on visibility in its Class I
area.\140\
---------------------------------------------------------------------------
\140\ 76 FR at 78206.
It is clear in our proposed approval that we were not approving or
otherwise advocating Kentucky's use of a $2,000/SO2 ton
threshold in the reasonable progress analysis. On the contrary, we
expressed concern that the use of a specific threshold for assessing
cost may result in a state not fully considering potential reasonable
control measures above that threshold that would have meaningful
visibility improvement on its Class I areas. Furthermore, our
statements in the proposal indicate that had there been evidence of
more affordable controls available above the $2,000/SO2 ton
threshold used by the state that provide meaningful visibility
improvement at the Class I areas, we might have arrived at a different
decision concerning the approvability of Kentucky's reasonable progress
analysis for SO2.
North Carolina took a similar approach to that of Kentucky in its
SO2 reasonable progress analysis by relying on a cost
threshold when deciding on measures for its non-EGUs. North Carolina
set this threshold based on the estimated cost of compliance with its
Clean Smokestacks Act, a law establishing a state-wide cap on
SO2 and NOX emissions from the State's two major
utilities. In our proposed approval of the North Carolina Regional Haze
SIP, we discussed that the state identified 11 units (non-EGU) for
evaluation. We noted that North Carolina decided that for the limited
purpose of evaluating the cost of compliance for non-EGUs in the
SO2 reasonable progress assessment for the first
implementation period, it was not equitable to require non-EGUs to bear
a greater economic burden than EGUs for a given control strategy and
therefore also used a cost-effectiveness threshold for its non-EGUs.
North Carolina's threshold was based on ``[t]he facility-by-facility
cost for EGUs under [the Clean Smokestacks Act which] ranged from 912
to 1,922 dollars per ton of SO2 removed,'' a statement which
the commenters appear to have misinterpreted to mean that North
[[Page 66369]]
Carolina rejected potential reasonable progress measures with costs
falling within this range.\141\ Rather, upon conducting cost
evaluations for the non-EGUs and determining that the costs of controls
exceeded its threshold, North Carolina concluded that there were no
cost-effective reasonable progress SO2 controls available
for the first implementation period. We proposed to approve North
Carolina's determination, but we also stated the following concerning
our position on North Carolina's use of a specific cost-effectiveness
threshold:
---------------------------------------------------------------------------
\141\ 77 FR at 11870.
Although the use of a specific threshold for assessing costs
means that a state may not fully consider available emissions
reduction measures above its threshold that would result in
meaningful visibility improvement, EPA believes that the North
Carolina SIP still ensures reasonable progress. In proposing to
approve North Carolina's reasonable progress analysis, EPA is
placing great weight on the fact that there is no indication in the
SIP submittal that North Carolina, as a result of using a specific
cost effectiveness threshold, rejected potential reasonable progress
measures that would have had a meaningful impact on visibility in
its Class I areas.\142\
---------------------------------------------------------------------------
\142\ 77 FR 11858, 11872.
As in the case of Kentucky, it is clear that in our proposed
approval of North Carolina's reasonable progress determination, we were
not approving or otherwise advocating North Carolina's use of that
specific cost-effectiveness threshold in the reasonable progress
analysis. Therefore, we disagree that our requirement of SO2
controls for Independence Units 1 and 2 under reasonable progress is
inconsistent with our actions on the Kentucky and North Carolina
Regional Haze SIPs.
Comment: EPA's decision to evaluate and propose NOX
controls at the Independence Plant stands completely opposite its
decision not to even evaluate similar controls for Texas' point sources
despite similar visibility conditions. EPA elected not to evaluate
Texas point sources for NOX controls because modeling
suggested that impacts from the sources on the 20% worst days were
``primarily due to sulfate emissions.'' \143\ In Arkansas, EPA was even
more explicit in stating that ``visibility impairment is not projected
to be significantly impacted by nitrate on the 20% worst days at Caney
Creek or Upper Buffalo.'' \144\ However, the agency nevertheless
evaluated and proposed NOX controls for the Independence
Plant Units 1 and 2. The arbitrary nature of this aspect of EPA's
proposal is further evidenced by the low projection for anticipated
visibility improvement due to the NOX controls. For
instance, EPA rejected installation of SCR controls under reasonable
progress where it was projected to result in 0.41 dv improvement at
affected Class I areas in the Arizona Regional Haze FIP proposal,
whereas it is proposing to require NOX controls on
Independence that are projected to result in visibility improvement of
0.461 dv in the Arkansas Regional Haze FIP proposal.
---------------------------------------------------------------------------
\143\ 79 FR 74818, 74873 (December 16, 2014).
\144\ 80 FR at 18966.
---------------------------------------------------------------------------
Response: This comment, and our response to it, illustrate the very
fact-specific nature of individual evaluations and decisions under the
regional haze program. It is critical to understand the full context of
each decision. In each one, the EPA applies the requirements of the
statute and regulations in a consistent manner, but the different
facts--unique to each state and facility--inevitably lead to different
outcomes. We agree that in our Texas FIP action we noted that on the
20% worst days, the impacts from the EGUs we evaluated under reasonable
progress were primarily due to sulfate emissions. We also agree that in
our Arkansas FIP proposal we acknowledged that the CENRAP modeling
demonstrates that sulfate is the primary driver of regional haze in
Arkansas' Class I areas on the 20% worst days. This does not mean that
NOX is not a key pollutant contributing to regional haze
impairment in both states. For instance, the CENRAP CAMx modeling shows
that total extinction at Caney Creek is dominated by nitrate on 4 of
the days that comprise the 20% worst days in 2002, and a significant
portion of the total extinction at Upper Buffalo on 2 of the days that
comprise the 20% worst days in 2002 is due to nitrate.\145\
---------------------------------------------------------------------------
\145\ See Arkansas Regional Haze SIP, Appendix 8.1-- ``Technical
Support Document for CENRAP Emissions and Air Quality Modeling to
Support Regional Haze State Implementation Plans,'' section 3.7.1
and 3.7.2. See the docket for this rulemaking for a copy of the
Arkansas Regional Haze SIP.
---------------------------------------------------------------------------
As a key pollutant, we considered NOX controls under
reasonable progress in both Texas and Arkansas. In our Texas FIP, we
considered NOX controls under reasonable progress for the
Works No. 4 Glass Plant but ultimately did not require those controls
based on the emission reductions already occurring at the facility, the
anticipated lifetime of the furnaces, and the fact that Furnace No. 2
had undergone rebricking within the past few years. Although we
determined it was reasonable to not require additional controls for
Works No. 4 Glass Plant at this time, we encouraged Texas to consider
additional controls when Furnace No. 2 is scheduled for its next
rebricking. We also found that in Texas all the EGUs that we evaluated
for controls under reasonable progress had existing LNB for control of
NOX emissions. This is in contrast to Independence, which is
the second largest source of NOX point source emissions in
Arkansas and is not currently equipped with any NOX
controls. As such, Independence was a more compelling candidate for
evaluation of NOX controls than were the EGUs in Texas that
we evaluated for controls under reasonable progress.
As NOX is a visibility impairing pollutant and
Independence is responsible for a very large portion of the point
source NOX emissions in the state (approximately
21.3%),\146\ we determined that it was reasonable to evaluate
NOX controls under reasonable progress in our Arkansas FIP
proposal. We conducted CALPUFF modeling and found that the Independence
Plant has significant visibility impacts in Arkansas' Class I areas due
to NOX emissions based on the 98th percentile visibility
impacts from the facility, and also found that LNB/SOFA would improve
these visibility impacts.\147\ We also found that LNB/SOFA is very cost
effective ($401/ton removed for Unit 1 and $436/ton removed for Unit
2). For these reasons, we proposed LNB/SOFA for Independence Units 1
and 2 under Option 1. In addition, we discuss in more detail elsewhere
in this final rule and in our RTC document that Entergy submitted CAMx
photochemical modeling during the public comment period showing that
nitrate from Independence is responsible for 30-40% of the visibility
impairment in Arkansas' Class I areas on 2 out of the 20% worst days in
2018. We expect that the installation of NOX controls at
Independence, which we found to be very cost effective, would provide
visibility improvement on this portion of the 20% worst days, thereby
assuring reasonable progress toward the goal of natural visibility
conditions. Based on
[[Page 66370]]
our consideration of the four statutory factors and the visibility
improvement available from controls, we have determined that there are
reasonable NOX controls available for Independence that are
cost effective and would result in considerable visibility improvement.
Therefore, we are requiring these controls.
---------------------------------------------------------------------------
\146\ See NEI 2011 v1. A spreadsheet containing the emissions
inventory is found in the docket for our proposed rulemaking.
\147\ Although the reasonable progress provisions of the
Regional Haze Rule place emphasis on the 20% worst days, the CAA
goal of remedying visibility impairment due to anthropogenic
emissions encompasses all days. Thus, states and EPA have the
discretion to consider the visibility impacts of sources and the
visibility benefit of controls on days other than the 20% worst days
in making their decisions, such as the days on which a given
facility has its own largest (98th percentile) impacts. Because
Independence has significant 98th percentile visibility impacts,
these impacts will need to be addressed to achieve the CAA goal of
remedying visibility impairment due to anthropogenic emissions.
---------------------------------------------------------------------------
We disagree that our decision to require NOX controls
for Independence is inconsistent with our Arizona FIP proposal. In that
action, we proposed that neither SCR nor SNCR was required to achieve
reasonable progress for Springerville Units 1 and 2 in this regional
haze planning period because:
[w]hile the cost per ton for SNCR may be reasonable, the
projected visibility benefits are relatively small (0.18 dv at the
most affected area). The projected visibility benefits of SCR are
larger (0.41 dv at the most affected area), but we do not consider
them sufficient to warrant the relatively high cost of controls for
purposes of RP in this planning period. However, these units should
be considered for additional NOX controls in future
planning periods.\148\
---------------------------------------------------------------------------
\148\ 79 FR 9318, 9360 (February 18, 2014).
The ``relatively high cost'' of SCR controls we refer to in that
statement is $6,829/ton NOX removed for Springerville Unit 1
and $6,085/ton NOX removed for Springerville Units 2.\149\
Thus, our decision to not propose SCR at Springerville Units 1 and 2
was not because we considered the visibility benefits to be too small,
as the commenter appears to believe. Instead, it was because we
determined that, under these circumstances, this level of visibility
improvement was not sufficient to warrant the cost per ton of emissions
reduced. In contrast, we found that the cost of LNB/SOFA at
Independence Units 1 and 2 is significantly lower ($401/ton removed for
Unit 1 and $436/ton removed for Unit 2), and we determined that 0.459
dv visibility improvement on a facility wide basis warranted the cost
of these controls. Therefore, we disagree that the NOX
controls we proposed and are finalizing in this action for Independence
Units 1 and 2 in any way contradict our proposed Arizona Regional Haze
FIP.
---------------------------------------------------------------------------
\149\ 79 FR 9318, 9359.
---------------------------------------------------------------------------
Comment: The overarching requirement of the CAA's haze provisions
is for each state's plan to include ``emission limits, schedules of
compliance and other measures as may be necessary to make reasonable
progress.'' CAA section 169A(b)(2). The statute defines reasonable
progress to account for four factors: The cost of controls, the time
needed to install controls, energy and nonair quality environmental
impacts of controls, and the remaining useful life of the source. CAA
section 169A(g)(1) and 40 CFR 51.308(d)(1)(i)(A). EPA's implementing
regulations require each state with a Class I area to set an RPG for
each area within its borders based on considering the four statutory
factors for reasonable progress. Each state must also determine the
uniform rate of progress. If a state sets a reasonable progress goal
that provides for less progress than the URP, the state must
demonstrate that achieving the URP is unreasonable and that its
alternative goal is reasonable. Moreover, each state must consult with
other states that contribute to haze in the host state's Class I areas.
Neither the statute nor the regulations exempts states from the
required reasonable progress analysis merely because a Class I area is
on the glidepath to achieving the URP. To the contrary, EPA's long-
standing interpretation of the regional haze rule is that ``the URP
does not establish a `safe harbor' for the state in setting its
progress goals.'' \150\ If it is reasonable to make more progress than
the URP, a state must do so, as EPA explained in the 1999 Regional Haze
Rule.\151\ Having disapproved Arkansas' regional haze plan, EPA has an
obligation to conduct a reasonable progress analysis for Caney Creek
and Upper Buffalo based on a consideration of the four statutory
factors for reasonable progress. 40 CFR 51.308(d)(1).
---------------------------------------------------------------------------
\150\ 79 FR 74818, 74834.
\151\ 64 FR at 35714, 35732.
---------------------------------------------------------------------------
Response: We agree with this comment with regard to our obligation
to conduct a reasonable progress analysis for sources in Arkansas
regardless of the Class I areas' position on the URP glidepath.
D. Control Levels and Emission Limits
Comment: Assuming EPA proceeds with BART for the Ashdown Mill, EPA
should revise the proposed SO2 limit for Power Boiler 2 from
0.11 lb/MMBTU to 155 lb/hr on a 30-day boiler operating day. There are
a number of concerns with EPA's proposed limit of 0.11 lb/MMBTU: It is
too stringent, it is based on the use of an inappropriate baseline
(2011-2013), and assumes the existing control equipment can
continuously operate at the upper range of its capability (90%
efficiency) over long periods of time, without supporting data or other
documentation. First, in the methodology to calculate the proposed BART
limit, EPA used data from 2011-2013 for determining the proposed BART
limit, instead of using 2001-2003 as the baseline. No justification is
given for not using 2001-2003 as the baseline, or why the particular
years EPA selected are better than the BART baseline years or legally
appropriate. Deviating from the 2001-2003 BART baseline is appropriate
if significant changes were made to the emission units or permit
conditions were imposed that prevent a unit from operating at the BART
baseline emission value. However, this is not the case for Power Boiler
2. The BART 2001-2003 baseline information is representative of Power
Boiler 2's potential operations. The fact that the Ashdown Mill
voluntarily elected to operate at a lower SO2 level
subsequent to the 2001-2003 baseline period is not relevant. Moreover,
by not utilizing the BART 2001-2003 baseline actual emissions in
establishing the proposed BART SO2 limit, EPA penalizes the
Ashdown Mill for its voluntary SO2 emission reductions
undertaken on its own initiative since the BART baseline period. Here,
the mill voluntarily reduced SO2 emissions by over 40% since
the BART baseline years prior to the proposed BART requirements. Using
the actual emission data from the BART baseline period of 2001-2003,
gives the mill credit for its early voluntary action. Second, EPA
wrongly applied the maximum rated heat input capacity of 820 MMBTU/hr
when it converted from a lb/hr limit to a lb/MMBTU limit. The use of
the maximum heat input rating is not representative of average
(typical) boiler operating conditions, which are lower than the maximum
heat input capability. The actual average heat input during the 2001-
2003 baseline period is 586 MMBTU/hr. In this situation, the use of
actual emission data and maximum rated heat input to calculate the
proposed SO2 BART limit is inappropriate and an inaccurate
methodology which creates significant concerns. EPA should instead
establish an SO2 emission limit in terms of lb/hr. Third,
based on monthly SO2 information for the 2011-2013 period,
EPA estimated that the SO2 control efficiency for the
existing scrubber on Power Boiler 2 to be approximately 69% and that
the existing scrubber may achieve on a short-term basis an
SO2 control efficiency of 90%. However, there is no
documentation showing that the scrubber can sustain this maximum
performance level on a long term basis. EPA should revise the
methodology for calculating the SO2 BART emission limit for
Power Boiler No. 2 by using 2001-2003 actual emissions as the baseline;
assuming the existing scrubbers operated at a 69% control efficiency
during the 2001-2003
[[Page 66371]]
baseline period; calculating an SO2 emission limit in lb/hr
based on 2001-2003 baseline actual emissions and a 90% control
efficiency. Based on this approach, EPA should revise the proposed
SO2 limit for Power Boiler 2 from 0.11 lb/MMBTU to 155 lb/hr
on a 30-day boiler operating day.
Response: We disagree that an emission limit of in an emission
limit of 155 lb/hr on a 30 boiler-operating-day satisfies the
SO2 BART requirement for Power Boiler No. 2. As discussed in
our proposal, we requested information from the facility to determine
if upgrades to the existing scrubbers are technically feasible and if
they would be cost effective and provide meaningful visibility benefit.
This assessment first required us to determine the current control
efficiency of the scrubbers. Because our BART analysis involved
determining the current control efficiency of the existing scrubbers,
we found that the most reasonable approach was to use data that reflect
the current control efficiency of the existing scrubbers, as opposed to
2001-2003 data. In order to conduct our BART analysis, we requested
monthly average data for 2011, 2012, and 2013 on monitored
SO2 emissions from Power Boiler No. 2, mass of the fuel
burned for each fuel type, and the percent sulfur content of each fuel
type burned.\152\ These were the three most recent full calendar years
of data available at the time we conducted our BART analysis. For these
reasons, our use of 2011-2013 as the baseline for calculating the
current control efficiency of the existing scrubbers and our proposed
SO2 BART limit for Power Boiler No. 2 was appropriate and
justified. As discussed in detail in our proposal, based on the
emissions data and fuel usage data Domtar provided to us, we estimated
that the current control efficiency of the existing scrubbers is
approximately 69% based on 2011-2013 data.\153\ The data also indicated
that the existing scrubbers could achieve up to 90% removal efficiency.
As discussed in our proposal, Domtar indicated that the scrubbers are
currently operated in a manner that allows for compliance with
permitted emission limits.\154\ In other words, the facility generally
uses only the amount of scrubbing solution needed to comply with
permitted emission limits. The information the facility provided
indicated that it would be possible to add more scrubbing solution to
achieve greater SO2 removal than required to meet the
boiler's existing SO2 permit limit; specifically, the
information indicated that additional scrubbing reagent can be added to
increase the control efficiency of the existing scrubbers to 90%.\155\
---------------------------------------------------------------------------
\152\ See 80 FR at 18984. See also August 29, 2014 letter from
Annabeth Reitter, Corporate Manager of Environmental Regulation,
Domtar, to Dayana Medina, U.S. EPA Region 6. A copy of this letter
and an Excel file attachment titled ``Domtar 2PB Monthly
SO2 Data,'' are found in the docket for our proposed
rulemaking.
\153\ See 80 FR at 18984. See also the spreadsheet titled
``Domtar 2PB Monthly SO2 Data.'' This spreadsheet was
included as an attachment to the August 29, 2014 letter from
Annabeth Reitter, Corporate Manager of Environmental Regulation,
Domtar, to Dayana Medina, U.S. EPA Region 6. See also the
spreadsheet titled ``Domtar PB No2--Cost Effectiveness
calculations.'' Copies of these documents can be found in the docket
for this proposed rulemaking.
\154\ 80 FR at 18983, 18984.
\155\ 80 FR at 18984.
---------------------------------------------------------------------------
We agree that we applied the boiler's maximum heat input rating of
820 MMBtu/hr when we calculated our proposed limit of 0.11 lb/MMBtu,
and based on information provided by the commenter, we acknowledge that
use of the maximum heat input rating is not representative of average
(typical) boiler operating conditions. To address the commenter's
concern, we are finalizing an SO2 BART limit for Power
Boiler No. 2 in terms of lb/hr. As we discussed in our proposal, based
on the emissions data we obtained from Domtar, we determined that the
No. 2 Power Boiler's annual average SO2 emission rate for
the years 2011-2013 was 280.9 lb/hr.\156\ This annual average
SO2 emission rate corresponds to the operation of the
scrubbers at a 69% removal efficiency. We also estimated that 100%
uncontrolled emissions would correspond to an emission rate of
approximately 915 lb/hr. Application of 90% control to this emission
rate results in a controlled emission rate of 91.5 lb/hr.\157\ We
recognize that the boiler's SO2 emissions are currently
lower than they were in the 2001-2003 period, and that had we used
2001-2003 data to calculate the current control efficiency and
SO2 BART emission limit, as the commenter requests, this
would have resulted in a less stringent emission limit. However, as
discussed above, the most reasonable approach is to use recent data in
our calculation of an appropriate SO2 BART emission limit.
As Domtar is requesting an emission limit in terms of lb/hr, we are
finalizing for SO2 BART for Power Boiler No. 2 an emission
limit of 91.5 lb/hr on a 30 boiler operating day. We believe this
emission limit reflects operation of the scrubbers at 90% control
efficiency and addresses the SO2 BART requirement for Power
Boiler No. 2.
---------------------------------------------------------------------------
\156\ See 80 FR at 18984. See also the spreadsheet titled
``Domtar 2PB Monthly SO2 Data.'' This spreadsheet was
included as an attachment to the August 29, 2014 letter from
Annabeth Reitter, Corporate Manager of Environmental Regulation,
Domtar, to Dayana Medina, U.S. EPA Region 6. See also the
spreadsheet titled ``No2 Boiler_Monthly Avg SO2 emission
rate and calculations.'' Copies of these documents can be found in
the docket for our rulemaking.
\157\ See 80 FR at 18984. See also the spreadsheet titled ``No2
Boiler Monthly Avg SO2 emission rate and calculations.''
A copy of this spreadsheet can be found in the docket for our
rulemaking.
---------------------------------------------------------------------------
We believe it reasonable to set the emission limit using baseline
emissions resulting from recent/current fuels. Given that we don't find
it appropriate to use emissions from the 2001-2003 period to calculate
the SO2 emission limit, the control efficiency from that
period is irrelevant. What is relevant are the current uncontrolled
SO2 emissions and the possible control efficiency of the
existing scrubbers, which is what we considered in our BART analysis.
We found in our analysis that during the 2011-2013 period, the company
was able to achieve an average monthly control efficiency of 90% and
find that this level of control is reasonable, and can be achieved by
the use of sufficient reagent to achieve the lower level. We also note
that the commenter did not provide additional information to support
the claim that the existing scrubbers cannot consistently achieve the
level of control efficiency necessary to meet an emission limit of 91.5
lb/hr.
Comment: The NOX emission limits proposed for the units
at White Bluff and Independence are based on the emission rate for LNB/
SOFA of 0.15 lb/MMBtu that Entergy proposed in the Revised White Bluff
BART Analysis. At the time Entergy submitted the Revised White Bluff
BART Analysis in October 2013, which EPA relied on in developing its
FIP proposal, all four of the coal-fired units at White Bluff and
Independence were operated as base load units and spent the
overwhelming majority of their operating time at loads of greater than
50% of unit capacity. Since submitting the Revised White Bluff BART
Analysis, Entergy transitioned to MISO in December 2013. MISO utilizes
an economic dispatch model to determine which EGUs within its service
territory are dispatched to operate and the operating load (MW) for
each unit. Beginning in December 2014, the units at both White Bluff
and Independence began to be dispatched primarily as load-following
units. Since December 2014, the White Bluff and Independence units have
been dispatched less frequently and, when dispatched, have spent
significantly more time at low operating rates of less than 50% of unit
capacity. The data for 2015 (through June 30) reflects a significant
increase in the percentage of time that each unit is dispatched at less
[[Page 66372]]
than 50% of operating capacity. Three of the four units have spent
greater than 40% of their 2015 operating hours at less than 50% of
capacity, and the two Independence units have spent nearly half of
their operating time at less than 50% of capacity. This change in
dispatch coincided with a sharp drop in natural gas prices. This drop
in gas prices to near $3 per MMBtu has been sustained since December
2014, and Entergy has no reason to expect any significant increase in
gas pricing in the near future. This change in dispatch for the units
at both White Bluff and Independence is significant with regard to
NOX emissions as the LNB/SOFA system is designed to operate
primarily in the range of 50-100% of unit load. Entergy has selected
Foster Wheeler as the LNB/SOFA vendor for White Bluff and has only been
able to obtain a guarantee of less than 0.15 lb/MMBtu for operating
loads in the range of 50-100% of unit capacity. Since the available
emission guarantee does not cover unit operation at less than 50% of
capacity, Entergy requested a memorandum from Foster Wheeler regarding
the impact of unit operation at less than 50% capacity on
NOX emission rates. Based on input from the LNB/SOFA vendor,
Entergy does not believe that the proposed emission rate of 0.15 lb/
MMBtu is consistently achievable under all operating conditions. Even
with a 30-day averaging period for the proposed limit, a unit which is
frequently dispatched at less than 50% of capacity may not be able to
achieve compliance. This was not perceived as an issue at the time that
the Revised White Bluff BART Analysis was prepared and submitted to
ADEQ by Entergy as, historically and at that time, the units were
operated almost exclusively as base-load units and spent less than 10%
of their operating time at less than 50% of unit capacity. In the
current dispatch environment, with some units spending nearly 50% of
their operating time outside of the control range for LNB/SOFA, Entergy
can no longer be confident that the units will be able to achieve
compliance with a limit of 0.15 lb/MMBtu on a 30-day rolling average
basis. The concern arises from low-load operation during which periods
of higher NOX emissions, on a lb/MMBtu basis, would not be
expected to correspond to an increase in the maximum mass emission rate
(lb/hr) from the units as any increase in the emission rate on a lb/
MMBtu basis would be expected to be more than offset by the lower unit
operating rate in MMBtu/hr to arrive at a mass emission rate (lb/hr).
To address the potential for a higher NOX emission rate
(lb/MMBtu basis) at operating rates of less than 50% of unit capacity,
Entergy proposes a rolling 30-boiler operating day average emission
rate of 1,342.5 lb NOX/hr at each coal-fired unit at White
Bluff and Independence. In the alternative, if EPA believes that a lb/
MMBtu limit is necessary for the units, Entergy proposes a bifurcated
NOX emission limit for each unit at both White Bluff and
Independence as follows: (1) For all unit operation (0-100% of
capacity) require an emission limit of 1,342.5 lb NOX/hr,
based on a rolling 30-boiler operating day average; and (2) for unit
operation at 50-100% of capacity, require an emission limit of 0.15 lb
NOX/MMBtu, based on a rolling 30-boiler operating day
average, to include only those hours for which the unit was dispatched
at 50% or greater of maximum capacity. This alternative approach would
ensure that the units are operated in compliance with the LNB/SOFA
design within the control range of 50-100% of capacity while providing
Entergy with flexibility in demonstrating compliance. The lb/hr limit,
which would apply to all operating hours, will ensure that the 30-day
average emission rates remain below those on which both EPA and Entergy
relied to project visibility improvements from the proposed
NOX emission reductions.
Response: We acknowledge the information provided by the commenter.
We understand the commenter's concerns that because of recent changes
in dispatch of the units, White Bluff Units 1 and 2 and Independence
Units 1 and 2 are no longer expected to be able to consistently meet
our proposed NOX emission limit of 0.15 lb/MMBtu over a 30-
boiler-operating-day period based on LNB/SOFA controls. We believe the
commenter has provided sufficient information to substantiate that the
units are not expected to be able to meet our proposed NOX
emission limit of 0.15 lb/MMBtu when the units are primarily operated
at less than 50% of their operating capacity. In particular, the
information provided by the commenter indicates that LNB/SOFA achieves
optimal NOX control when the boiler is operated from 50 to
100% steam flow because the heat input across this range is sufficient
to safely redirect a substantial portion of combustion air through the
overfire air registers.\158\ This allows the combustion zone airflow to
be sub-stoichiometric and oxygen to be reduced to the point where much
of the elemental nitrogen in the fuel and combustion air can pass
through the boiler without oxidizing (i.e., converting to
NOX). When a boiler is operated below the 50 to 100%
capacity range, NOX concentrations on a lb/MMBtu basis can
be elevated due to the lower heat input rating, even though the pounds
of NOX emitted (i.e., on a mass basis) is less due to the
reduced amount of fuel and air. In light of the information provided by
the commenter, we believe it is appropriate to promulgate a bifurcated
NOX emission limit for each unit, as suggested by the
commenter.
---------------------------------------------------------------------------
\158\ See comments submitted during the comment period by
Entergy Arkansas Inc., including Exhibit G to Entergy's comments.
These and all other comments and associated attachments submitted
during the public comment period are found in the docket associated
with this rulemaking.
---------------------------------------------------------------------------
Therefore, in this FIP we are requiring White Bluff Units 1 and 2
and Independence Units 1 and 2 to each meet a NOX emission
limit of 0.15 lb/MMBtu on a 30 boiler-operating-day rolling average,
where the average is to be calculated by including only the hours
during which the unit was dispatched at 50% or greater of maximum
capacity, as requested by the commenter. Specifically, the 30 boiler-
operating-day rolling average is to be calculated for each unit by the
following procedure: (1) Summing the total pounds of NOX
emitted during the current boiler-operating-day and the preceding 29
boiler-operating-days, including only emissions during hours when the
unit was dispatched at 50% or greater of maximum capacity; (2) summing
the total heat input in MMBtu to the unit during the current boiler-
operating-day and the preceding 29 boiler-operating-days, including
only the heat input during hours when the unit was dispatched at 50% or
greater of maximum capacity; and (3) dividing the total pounds of
NOX emitted as calculated in step 1 by the total heat input
to the unit as calculated in step 2. In addition to this limit that is
intended to control NOX emissions when the units are
operated at 50% or greater of maximum capacity, we are establishing a
limit in lb/hr for periods in which the units are operated at less than
50% capacity. However, the 1,342.5 lb/hr emission limit suggested by
the commenter is too high to appropriately control NOX
emissions when the units are operated at low capacities. There is no
indication in the comments submitted that the 1,342.5 lb/hr emission
limit suggested by the
[[Page 66373]]
commenter was based on a vendor guarantee. The commenter did not
explain how the 1,342.5 lb/hr limit was calculated, but it appears that
it was calculated by multiplying the 0.15 lb/MMBtu limit by the maximum
heat input rating for each unit (8,950 MMBtu/hr), which yielded 1,342.5
lb/hr. An emission limit of 1,342.5 lb/hr would be appropriate when the
unit is operated at high capacities considering that the limit was
calculated based on the unit's maximum heat input rating. However, such
an emission limit would not be sufficiently protective or appropriate
when the unit is operated at lower capacities when it is expected that
NOX emissions on a mass basis would be lower compared to
operation at high capacity. To address this concern, we have calculated
a new emission limit of 671 lb/hr that is based on 50% of the unit's
maximum heat input rating, and is applicable only when the unit is
being operated at less than 50% of the unit's maximum heat input
rating. We calculated this limit by multiplying 0.15 lb/MMBtu by 50% of
the maximum heat input rating for each unit (i.e., 50% of 8,950 MMBtu/
hr, or 4,475 MMBtu/hr). This limit is on a rolling 3-hour average,
where the average is to be calculated by including emissions only from
the hours during which the unit was operated at less than 50% of the
unit's maximum heat input rating (i.e., hours when the heat input to
the unit is less than 4,475 MMBtu). We are not establishing a lb/hr
emission limit that applies when the units are operated at 50% or
greater of the unit's maximum heat input rating because there is no
need for it since the 0.15 lb/MMBtu limit will address NOX
emission during those operating conditions.
As such, we are requiring White Bluff Units 1 and 2 and
Independence Units 1 and 2 to each meet a NOX emission limit
of 0.15 lb/MMBtu on a 30 boiler-operating-day rolling average, where
the average is to be calculated by including only the hours during
which the unit was dispatched at 50% or greater of maximum capacity, as
requested by the commenter. In addition, we are requiring White Bluff
Units 1 and 2 and Independence Units 1 and 2 to each meet a
NOX emission limit of 671 lb/hr on a rolling 3-hour average
that applies only to the hours when the unit is operated at less than
50% of the unit's maximum heat input rating. We believe that these
limits address the commenter's concern of not being able to meet the
lb/MMBtu emission limit when the unit is being operated at lower
capacities, and will also ensure that NOX emissions are
appropriately controlled when the units are operated at higher
capacities, as well as when they are operated at lower capacities.
Comment: Assuming EPA proceeds with BART for the Domtar Ashdown
Mill, the mill conceptually agrees with the proposed BART
SO2 limit for Power Boiler 1 of 21.0 lb/hr on a 30-day
averaging basis with no add-on control. However, based on the
methodology the mill uses to determine fuel usage, the emission limit
needs to be expressed in an alternative form to better match with the
compliance averaging time of 30 days. Calculation of hourly
SO2 emissions using hourly fuel usage information is not a
workable approach for Power Boiler 1, where the facility's practice is
to use monthly fuel usage information that is reconciled at the end of
each month based on fuel inventory records. Records of daily fuel usage
may be adjusted at the end of the month as part of the reconciliation
process. Therefore, Domtar requests the BART limit of 21.0 lb/hr be
expressed as 504 lb/day.
Response: After carefully considering this comment we have
determined that Domtar's request for an SO2 BART emission
limit in terms of lb/day is reasonable. An emission limit in terms of
lb/day will be better suited for the mill's methodology of using
monthly fuel throughput information. Therefore, as requested by the
facility, we are finalizing an SO2 BART emission limit of
504 lb/day for Power Boiler No. 1.
E. Domtar Ashdown Mill Repurposing Project
Comment: The Domtar Ashdown Mill is in the process of re-purposing
and is in a state of transition. Once the re-purposing and re-
configuration is complete and the mill is fully operational, the mill
will need to decide if Power Boiler 1 will continue with full or
intermittent operation, and if so what fuels will be used, or will be
retired. If the boiler is fuel switched to natural gas or the boiler
retired, the SO2 BART limit will be unnecessary along with
the associated monitoring, recordkeeping and reporting requirements for
the SO2 BART limit. The Ashdown Mill is requesting EPA
include in the FIP final rule an alternate compliance option that
removes all of SO2 BART related requirements for Power
Boiler 1 if this boiler is switched to burn only natural gas. If Power
Boiler 1 is switched to burn only natural gas, requirements for NOx
testing also need to be removed and an alternate NOX BART
compliance option needs to be developed to allow compliance to be based
on the use of AP-42 emission factors and fuel use records. If Power
Boiler 1 is retired, there is no need to retain the SO2 and
NOX BART limits and associated requirements, and an
alternate BART compliance option should address this retirement
scenario as well.
Response: We proposed an SO2 BART emission limit of 21.0
lb/hr for Power Boiler No. 1. As discussed in section IV. of this final
rule, we are finalizing an emission limit in terms of lb/day, as
requested by Domtar. We proposed to find that to demonstrate compliance
with this SO2 BART emission limit, the facility was required
to use a site-specific curve equation (provided to us by the facility)
to calculate the SO2 emissions from Power Boiler No. 1 when
combusting bark, and to confirm the curve equation using stack
testing.\159\ We also proposed to find that to calculate the
SO2 emissions from Power Boiler No. 1 when combusting fuel
oil, the facility must assume that the SO2 inlet is equal to
the SO2 being emitted at the stack.\160\ In our proposal we
invited public comment specifically on the issue of whether our
proposed method of demonstrating compliance is appropriate.
---------------------------------------------------------------------------
\159\ 80 FR 18944, 18980.
\160\ 80 FR at 18980.
---------------------------------------------------------------------------
We note that we became aware that Power Boiler No. 1 wished to burn
only natural gas after the end of the comment period for our proposal,
and that the facility has submitted a permit renewal application to
ADEQ that will reflect this enforceable change.\161\ We do not agree
that the SO2 BART emission limit becomes ``unnecessary''
when a unit is switched to burn only natural gas. The Regional Haze
regulations define BART as an emission limitation based on the degree
of reduction achievable through the application of the best system of
continuous emission reduction for each pollutant which is emitted by an
existing stationary facility.\162\ Therefore, a BART emission limit is
still applicable and is required regardless if the unit switches to
natural gas. However, the repurposing project the mill is currently
undergoing and the fact that the facility's air permit will be revised
such that Power Boiler No. 1 will be permitted to burn only natural gas
render it appropriate to provide the facility with flexibility in
demonstrating compliance with the SO2 emission limit.
Therefore, in addition to the method we proposed for demonstrating
compliance with the SO2 BART emission limit for Power Boiler
No. 1, we are also finalizing one alternative method for
[[Page 66374]]
demonstrating compliance: The owner or operator may demonstrate
compliance with the SO2 emission limit by switching Power
Boiler No. 1 to burn only pipeline quality natural gas. Therefore, if
the facility's air permit is revised to reflect that Power Boiler No. 1
is permitted to burn only pipeline quality natural gas, this would
satisfy the requirement for demonstrating compliance with the boiler's
SO2 BART emission limit, and the reporting and recordkeeping
requirements would be waived. We are revising proposed Sec. 52.173 to
reflect this.
---------------------------------------------------------------------------
\161\ See file ``Record of Meeting_March 10 2016,'' which can be
found in the docket for this rulemaking.
\162\ 40 CFR 51.301.
---------------------------------------------------------------------------
We are finalizing our determination that NOX BART for
Power Boiler No. 1 is an emission limit of 207.4 lb/hr. We proposed
that to demonstrate compliance with this NOX BART emission
limit, the facility was required to conduct annual stack testing. In
response to a separate comment provided by Domtar, in our final FIP we
are requiring stack testing every five years instead of annually to
demonstrate compliance with the NOX BART emission limit. The
repurposing project the mill is currently undergoing and the fact that
the facility's air permit will be revised such that Power Boiler No. 1
will be permitted to burn only natural gas render it appropriate to
provide the facility with flexibility in demonstrating compliance with
the NOX emission limit. Therefore, we are also providing one
alternative method for demonstrating compliance with the NOX
emission limit: If the facility's air permit is revised to reflect that
Power Boiler No. 1 is permitted to burn only pipeline quality natural
gas, the facility may demonstrate compliance with the NOX
emission limit by calculating emissions using AP-42 emission factors
and fuel usage records. Under these circumstances, the facility would
not be required to demonstrate compliance with the NOX BART
emission limit for Power Boiler No. 1 through stack testing. We are
revising proposed Sec. 52.173 to reflect this.
With regard to the request that we include a provision in our FIP
that removes all SO2 and NOX BART related
requirements for Power Boiler 1 if this boiler is permanently retired
in the future, we noted above that the Regional Haze regulations define
BART as an emission limitation based on the degree of reduction
achievable through the application of the best system of continuous
emission reduction for each pollutant which is emitted by an existing
stationary facility. The BART emission limits and applicable
requirements continue to apply regardless if a BART source is
mothballed or retired/shut down without being dismantled,
decommissioned, and having the air permit revoked. In the event that
the BART source is permanently shut down, dismantled, decommissioned,
and the permit revoked in the future, the process for removing the BART
emission limits and applicable requirements would necessarily involve a
request by the company for partial FIP withdrawal or a SIP revision
from the State in the event that we have approved a SIP revision that
replaces our FIP. We are committed to work with ADEQ and the facility
to partially withdraw our FIP with respect to the emission limits for
the BART unit or revise the SIP if at some point in the future the
company decides to permanently shut down, dismantle, and decommission
the boiler and surrender the air permit.
Further, we consider the conditions under which a unit is
permanently retired and the mechanism by which this is made enforceable
to be critical. Because the company has not decided if and when Power
Boiler No. 1 will be permanently retired or decided what the conditions
of the retirement will be, we believe that it is reasonable and
appropriate to wait until the company makes these decisions instead of
including a provision in our FIP that waives the BART recordkeeping
requirements in anticipation that the unit's permanent retirement will
take place under certain conditions and made enforceable through a
particular mechanism that may be different from what ultimately takes
place.
Comment: If Power Boiler 2 is fuel switched to natural gas or
retired as part of the Domtar Ashdown Mill's repurposing project, there
is no need to retain the SO2 and PM BART limits and the
associated monitoring, recordkeeping and reporting requirements for the
SO2 and PM BART limits. The Ashdown Mill requests that EPA
include in the FIP final rule an alternative compliance option which
removes the SO2 and PM BART limits and the associated
requirements if the boiler is fuel switched to natural gas or
permanently retired. Additionally, if Power Boiler 2 is fuel switched
to natural gas as part of the Domtar Ashdown Mill's repurposing
project, the NOX BART requirements need to be modified to
require compliance based on the use of AP-42 emission factors and fuel
use records. The requirement to operate and maintain a NOX
CEM needs to be removed. If Power Boiler 2 is retired, all the BART
requirements are unnecessary. The Ashdown Mill requests that EPA
include alternate compliance options in the FIP final rule provisions
to address these potential scenarios.
Response: We are finalizing an SO2 BART emission limit
of 91.5 lb/hr and we are finalizing our determination that compliance
with the Boiler MACT PM standard as revised satisfies the PM BART
requirement for Power Boiler No. 2. We proposed to require the facility
to demonstrate compliance with the SO2 emission limit for
Power Boiler No. 2 using the existing CEMS, and to demonstrate
compliance with the PM emission limit using the same method that is
used for demonstrating compliance with the Boiler MACT PM standard. We
are finalizing these methods for demonstrating compliance with the
SO2 and PM emission limits for Power Boiler No. 2. With
regard to the commenter's request that we include an alternate
compliance option in our FIP that removes the SO2 and PM
BART limits if the boiler is switched to natural gas, we do not have
the authority to do this. The Regional Haze regulations define BART as
an emission limitation based on the degree of reduction achievable
through the application of the best system of continuous emission
reduction for each pollutant which is emitted by an existing stationary
facility.\163\ The BART emission limits are still applicable and are
required regardless if the unit is switched to natural gas. However,
the repurposing project the mill is currently undergoing and the
possibility of Power Boiler No. 2 being converted to burn only natural
gas render it appropriate to provide the facility with flexibility in
demonstrating compliance with the SO2 and PM emission limits
for Power Boiler No. 2. Therefore, we are providing one alternative
method for demonstrating compliance with the SO2 and PM
emission limits: The owner or operator may demonstrate compliance with
these emission limits by switching Power Boiler No. 2 to burn only
natural gas. Therefore, if Power Boiler No. 2 is switched to burn only
pipeline quality natural gas, and the air permit is revised to reflect
this change, this would satisfy the requirement for demonstrating
compliance with the boiler's SO2 and PM BART emission
limits, and the related reporting and recordkeeping requirements would
be waived. Under these circumstances, the SO2 and PM BART
determinations for Power Boiler No. 2 would continue to apply but the
facility would be able to demonstrate compliance with these emission
limits by virtue of switching to natural gas and it would not be
required to use the existing CEMS to demonstrate
[[Page 66375]]
compliance with the SO2 BART emission limit. We are revising
proposed Sec. 52.173 to reflect this.
---------------------------------------------------------------------------
\163\ 40 CFR 51.301.
---------------------------------------------------------------------------
We are requiring Power Boiler No. 2 to meet an emission limit of
345 lb/hr to satisfy the NOX BART requirement. We proposed
to require the facility to demonstrate compliance with this
NOX emission limit using the existing CEMS, and we are
finalizing this method for demonstrating compliance. However, the
repurposing project the mill is currently undergoing and the
possibility of Power Boiler No. 2 being converted to burn natural gas
only render it appropriate to provide the facility with flexibility in
demonstrating compliance with the NOX emission limit.
Therefore, we are providing one alternative method for demonstrating
compliance with the NOX emission limit: If Power Boiler No.
2 is switched to burn only pipeline quality natural gas, and the air
permit is revised to reflect this, the facility may demonstrate
compliance with the NOX emission limit by calculating
emissions using AP-42 emission factors and fuel usage records. Under
these circumstances, the facility would not be required to use the
existing CEMS to demonstrate compliance with the NOX BART
emission limit. We are revising proposed Sec. 52.173 to reflect this.
We do not have the authority to include in our FIP a provision that
removes all SO2, NOX, and PM BART requirements
for Power Boiler No. 2 if it is permanently retired in the future. As
noted above, the Regional Haze regulations define BART as an emission
limitation based on the degree of reduction achievable through the
application of the best system of continuous emission reduction for
each pollutant which is emitted by an existing stationary facility. The
BART emission limits and applicable requirements continue to apply
regardless if a BART source is mothballed or retired/shut down without
being dismantled, decommissioned, and having the air permit revoked. In
the event that the BART source is permanently shut down, dismantled,
decommissioned, and the permit revoked in the future, the process for
removing the BART emission limits and applicable requirements would
necessarily involve a request for a partial FIP withdrawal or a SIP
revision in the event that we have approved a SIP revision that
replaces our FIP. We are committed to work with ADEQ and the facility
to partially withdraw our FIP with respect to the emission limits for
the BART unit or revise the SIP if at some point in the future the
company decides to permanently shut down, dismantle, and decommission
the boiler and surrender the air permit.
Further, we consider the conditions under which a unit is
permanently retired and the mechanism by which this is made enforceable
to be critical. Because the company has not decided if and when Power
Boiler No. 2 will be permanently retired or decided what the conditions
of the retirement will be, we believe that it is reasonable and
appropriate to wait until the company makes these decisions instead of
including a provision in our FIP that waives the BART recordkeeping
requirements in anticipation that the unit's permanent retirement will
take place under certain conditions and made enforceable through a
particular mechanism that may be different from what ultimately takes
place.
Comment: EPA proposes to require compliance with the SO2
BART emission limit for Power Boiler 2 within 3 years of the effective
date of the final rule. EPA also proposes compliance with the
NOX BART emission limit within 3 years of the effective date
of the final rule. With the mill transformation and re-purposing
project and all of the work associated with this huge undertaking, the
Ashdown Mill needs a 5-year compliance window from the effective date
of the final rule for the SO2 and NOX BART
requirements for Power Boiler 2 (assuming EPA decides to proceed with
BART for the mill). As announced in late 2014, the mill is converting a
paper machine to produce fluff pulp. This transformation project is
being driven by the continued decline in the demand for paper products.
Power 1 and Power Boiler 2 are part of the mill's steam generating
components, and are operated to produce steam that is needed for the
manufacturing of pulp and paper products. It is anticipated that this
mill transformation project may significantly affect mill steam demands
reducing the amount of steam needed from Power Boiler 1 and 2.
Ultimately, this transformation project may determine future use of
Power Boiler 2. Once the re-purposing and re-configuration of the mill
systems is complete and fully operational, the mill will decide whether
Power Boiler 2 will continue with full or intermittent operation, if
so, using what fuels, or will it be permanently retired. In order to
make this decision, the mill will need to go through the startup,
initial operation and a shakedown period with the new fluff pulp
process. Since this is a significant change for the mill it is
uncertain how long it will take to learn how to operate and to optimize
in this newly configured state. The mill will then need at least 2
winter cycles to understand what the maximum steam demand requirements
will be for the newly configured mill. The re-purposing project is
scheduled to be completed and the newly configured mill is anticipated
to start-up in late 2016. The mill will operate through the winter of
2016-2017 and will be learning how to operate and optimize the new
process. The winter of 2017-2018 will be the first real indicator of
what winter steam demands will be in the re-purposed state. For the
purposes of selecting an appropriate BART compliance schedule and
future mill operations, the understanding of how the Power Boilers will
operate and on what fuels is essential. The project schedule will set
these key decision points in late 2018. Once the decision on mill steam
needs and boiler utilization is made, additional time is required to
implement the boiler scenario selected by the mill. These scenarios
could range from the mothballing or retiring Power Boilers 1 or 2 to
shifting fuels. In addition, changes involving the combustion of the
NCG gases and the shared biomass feed system also need to be determined
and new systems engineered and permitted, as needed. Another factor to
be considered is determining the ability of the existing SO2
scrubber to continuously operate at 90% removal on a long-term basis.
If Power Boiler 2 continues to use solid fuels, additional time is
needed to optimize the existing scrubber to consistently perform at
this higher level of control efficiency on a long-term basis. Given the
mill's interconnected nature as well as the complex aspects of the re-
purposing project, a 5-year compliance schedule for achieving the
SO2 BART and NOX BART requirements for Power
Boiler 2 is essential.
Response: We have reconsidered the SO2 and
NOX BART compliance dates for Power Boiler No. 2 in response
to this comment. We understand the commenter's concerns with respect to
how the transformation and repurposing project the mill is currently
undertaking may significantly affect mill steam demands and may
ultimately determine future use of Power Boiler No. 2. We understand
that the mill will decide the future use of Power Boiler No. 2,
including whether it will be converted to other fuels or permanently
retired, after the repurposing and reconfiguration of the mill systems
is complete and fully operational and after the mill has learned how to
operate and to optimize in its newly configured state. Our
understanding from the comments is that Ashdown Mill expects
[[Page 66376]]
to make this decision in late 2018, but that additional time will be
needed to implement the boiler scenario selected by the mill, which
could include switching fuels, mothballing or retiring the boilers, or
continued operation and combustion of solid fuels and installation of
air pollution controls to meet the BART emission limits. It is not
EPA's intention to place an undue burden on the Domtar Ashdown Mill by
requiring a compliance date that may not provide sufficient time for
the mill to install controls or otherwise make the necessary operating
changes to meet the boiler's BART emission limits. While we believe
that a 3-year compliance date is generally sufficient for installation
of the controls on which the BART emission limits are based, due to the
special circumstances in this case we believe that it is reasonable and
appropriate to establish a longer compliance date particularly since it
could avoid unnecessary investment in a scrubber that may be no longer
needed due shutdown or fuel switch. Therefore, we are requiring that
the mill comply with the SO2 and NOX BART
emission limits no later than 5 years from the effective date of this
final rule and have amended the proposed regulatory text to reflect
this change. We believe that this adequately addresses the commenter's
concerns while in keeping with the CAA mandate that compliance with
BART requirements must be as expeditiously as practicable but in no
event later than 5 years after promulgation of this FIP.
F. Other Compliance Dates
Comment: EPA proposed compliance with the SO2 and
NOX BART limits for Power Boiler 1 and for the PM BART limit
for Power Boiler No. 2 to be on the effective date of the final rule.
Should EPA proceed with imposing these BART limits, the Ashdown Mill
requests the compliance date be changed to 30 calendar days after
effective date of the final rule. That will give the mill additional
time to prepare the compliance records if there is a short period
between when the rule is promulgated and the effective date, especially
if the effective date of the final rule falls on a weekend or a
holiday. In addition, if any confusion exists regarding exactly when
the effective date is, the cushion of 30 days helps to provide more
certainty. This extra time will be needed if EPA finalizes any changes
to definitions or other requirements that require the Ashdown to adjust
recordkeeping systems.
Response: We are finalizing a NOX BART emission limit of
207.4 lb/hr for Power Boiler No. 1, which is what we proposed. We
proposed an SO2 BART emission limit of 21.0 lb/hr for Power
Boiler No. 1, and as discussed in section IV. of this final rule, we
are finalizing an emission limit of 504 lb/day. We are finalizing our
determination that compliance with the Boiler MACT PM standard
satisfies the PM BART requirement for Power Boiler No. 2. As discussed
elsewhere in this section of the final rule, we are finalizing some
changes to the definitions and BART requirements for Power Boiler No.
1. After carefully considering this comment, we have determined that
extending the compliance dates associated with the aforementioned BART
emission limits for Power Boiler No. 1 is appropriate because it is a
reasonable request that will allow the owner or operator of the
affected facility to prepare applicable compliance records and adjust
recordkeeping systems without unduly delaying compliance with the BART
requirement. Therefore, we are revising the compliance dates we
proposed for the SO2 and NOX BART emission limits
for Power Boiler No. 1 and the PM BART requirement for Power Boiler No.
2 such that the owner or operator must comply with these emission
limits no later than 30 calendar days from the effective date of the
final rule.
Comment: EPA's proposed BART requirements will require installation
of new emission controls on utility electric generation resources at a
significant cost. The utilities will pass these costs on to Arkansas
ratepayers. The Ashdown Mill, like other energy intensive
manufacturers, will be affected by the increasing cost of electric
power needed to operate our processes. EPA should also consider other
emerging regulatory initiatives that will be driving substantial
changes to major coal burning facilities. Manufacturing facilities,
such as the Ashdown Mill, are undertaking major transformation projects
that potentially may result in a move away from coal and other emerging
regulations targeting utilities are likely to further reduce coal
burning and further remove visibility concerns. A practical alternative
to EPA's proposed compliance dates is for EPA to use its discretion
under the Regional Haze Rule and delay the Arkansas BART requirements
for all sources for five years. This will align compliance timelines so
that the full effects of all of these regulatory changes will be known.
Facilities affected by these other requirements can plan holistic
compliance strategies rather than being compelled to follow an
expensive and potentially wasteful piecemeal approach. Using the
maximum 5-year window allowed under BART will provide the Ashdown Mill
the time to determine if coal will continue as a fuel for the facility.
It will also provide the other affected sources in Arkansas with time
to address the Clean Power Plan strategies and other significant
regulatory programs that may also remove coal as a fuel. The effect of
allowing a full 5-year compliance program will thereby minimize the
potential for stranded assets and minimize the cost increases on
companies and on ratepayers. This approach is further compelled by the
fact that Arkansas is more than meeting its ``glide path'' as discussed
above.
Response: We acknowledge the commenter's concerns related to the
potential increase in utility rates for Arkansas ratepayers as well as
to potential requirements related to other CAA and EPA regulatory
actions. We agree that multiple regulatory actions are pending that
will affect the power sector and that regulatory development should be
coordinated when possible while still meeting the statutory and
regulatory requirements for compliance. We also recognize the
importance of long-term and coordinated planning on the parts of owners
of industrial sources that are subject to BART. However, we disagree
that our FIP presents a tight or unreasonable regulatory timeline. It
is an appropriate timeline for cost-effective control measures needed
to meet the regional haze requirements.
The CAA and Regional Haze Rule require the installation and
operation of BART, in particular, to be carried out expeditiously. The
CAA defines the term ``as expeditiously as practicable'' to mean ``as
expeditiously as practicable but in no event later than five years
after the date of approval of a [Regional Haze] plan revision. . . .''
\164\ Therefore, we do not have the authority to delay compliance dates
across the board for all subject-to-BART sources in Arkansas to allow
time for greater certainty regarding requirements associated with other
CAA and regulatory requirements. We also disagree that ADEQ's finding
that Arkansas Class I areas are projected to be below the URP glidepath
in 2018 is sufficient justification for delaying the compliance dates
for all subject-to-BART sources in Arkansas. We address other more
specific comments related to this issue in a separate response.
---------------------------------------------------------------------------
\164\ CAA section 169A(b)(2)(A) and (g)(4).
---------------------------------------------------------------------------
In determining what is ``as expeditiously as practicable'' for
installation and operation of a particular control technology, the
states and EPA
[[Page 66377]]
usually consider the amount of time it generally takes to install and
operate that type of technology at similar sources and the compliance
dates that have been required for the installation and operation of the
same type of control technology at similar sources in other regional
haze actions, especially if there are no source-specific considerations
or other special circumstances that would prevent the source from
installing and operating the control technology within the same amount
of time. For example, where a particular control technology can
generally be installed and operated in 3 years, and where there are no
source-specific considerations or other special circumstances that
would affect the facility's ability to install and operate the control
technology within that time frame, it would not be in accordance with
the CAA and the Regional Haze Rule to allow a 5-year compliance period
because that would not be as expeditiously as practicable.
Additionally, considering that most other states already have plans in
place that fully address the regional haze requirements, it would be
inequitable and contrary to the intent of the CAA and the Regional Haze
Rule to further delay implementation of regional haze requirements in
Arkansas by allowing a 5-year compliance date across the board for all
of Arkansas' subject-to-BART sources. Therefore, we disagree that it is
appropriate for us to allow a 5-year compliance date for all subject-
to-BART sources in Arkansas, rather than establishing deadlines
consistent with the facts and regulatory requirements in each instance.
We do note that we are revising some of the compliance dates we
proposed in response to source-specific considerations raised in other
comments. We address these comments in separate responses.
Comment: If EPA's final SO2 BART determination for Flint
Creek Unit 1 is based on installation of a NID dry scrubber, EPA should
impose a shorter compliance deadline, as required by the Act. EPA's
proposed FIP requires Flint Creek Unit 1 to comply with the
SO2 BART determination within five years from the effective
date of the final rule. Yet the statute requires a source to comply
with BART as expeditiously as possible, but no later than five years
from the effective date of EPA's action on the regional haze plan.\165\
AEP could install a NID scrubber at Flint Creek much more expeditiously
than five years from the effective date of the rule. The utility has
already obtained an Arkansas PSC order finding that NID dry scrubber
installation is in the public interest.\166\ ADEQ has already issued a
Title V air permit for scrubber construction and operation at Flint
Creek.\167\ Further, it appears that on-site construction of the NID
scrubber has begun, and that the Flint Creek owners intend to operate
it by May 29, 2016, in order to comply with EPA's MATS rule.\168\ Thus,
given that AEP is currently installing the NID scrubber with a May 2016
planned operation date, EPA's five-year SO2 BART compliance
deadline does not comply with the statutory requirement that BART
controls be installed ``as expeditiously as practicable,'' \169\ Since
AEP is installing the NID scrubber for MATS as well as BART compliance,
EPA should require SO2 BART compliance at Flint Creek by no
later than May 29, 2016.
---------------------------------------------------------------------------
\165\ 40 CFR 51.308(e)(1)(iv).
\166\ See 7/10/2013 SWEPCO News Release, SWEPCO Receives
Arkansas Commission Approval for Flint Creek Plant Project, at
https://www.swepco.com/info/news/viewRelease.aspx?releaseID=1424.
\167\ See Stamper Report at 14 (citing October 25, 2013 Permit
No. 0276-AOP-R6 at 5 (Ex. 29 to Stamper Report)).
\168\ Stamper Report at 14 (citing Flint Creek Retrofit Project,
SWEPCO News & Info Site at https://swepco.com/info/projects/FlintCreek/; March 26, 2014 Independent Monitor Report for AEP Flint
Creek Plant Unit 1, submitted to the Arkansas Public Service
Commission under Docket No. 12-008-U, at (Ex. 30 to Stamper
Report)).
\169\ CAA section 169A(b)(2)(A).
---------------------------------------------------------------------------
Response: We acknowledge the information provided by the commenter
regarding AEP Flint Creek's plans to complete installation of the NID
system in 2016 in order to comply with 40 CFR part 63, subpart UUUUU--
National Emission Standards for Hazardous Air Pollutants: Coal- and
Oil-Fired Electric Utility Steam Generating Units, otherwise known as
the Utility MATS Rule. MATS establishes emission limits for three
categories of pollutants: Mercury, acid gases (HCl and SO2),
and non-mercury hazardous air pollutant (HAP) metals. To address acid
gases, an EGU must comply with an HCl emission limit unless it is
equipped with a wet or dry FGD or DSI and an SO2 CEMS, in
which case it has the option of complying with an alternative
SO2 emission limit. The applicable alternative
SO2 emission limit is 0.2 lb/MMBtu.
The commenter has made us aware that the Arkansas PSC has
determined that dry scrubber installation at Flint Creek is in the
public interest and that the installation of those controls is already
underway and anticipated by the company to be complete by May 29, 2016.
The commenter also points to the air permit issued to Flint Creek by
ADEQ on October 25, 2013, which allows for the installation and
operation of new control equipment and associated material handling
systems to comply with the requirements of the Utility MATS Rule. These
controls include a NID system on Unit 1. The AEP-SWEPCO Web site also
indicates that the installation of these scrubber controls is driven by
MATS and future Regional Haze rules.\170\ A timeline provided on the
Web site states that construction of these controls began in October
2013 and that installation will be complete and the facility will be
operating with these controls by the end of May 2016. In addition, the
commenter has made us aware that the Arkansas PSC requires Flint Creek
to provide quarterly reports on the progress of the installation of
these controls. The first report the company submitted to the Arkansas
PSC is dated March 26, 2014, and stated that the FGD project includes
the installation of an Alstom NID system to comply with MATS and in
anticipation of the BART requirements. The report also stated that the
NID system and associated equipment are to be constructed at Flint
Creek Unit 1, and that the company established design, procurement, and
construction schedules to bring the upgraded plant fully on line by May
29, 2016. The commenter provided the report as an attachment to the
comments submitted, but this and all other quarterly reports the
company submitted to the Arkansas PSC are available online.\171\ The
most recent quarterly report available on the Arkansas PSC Web site is
dated March 10, 2016, and covers the fourth quarter in 2015. This
report indicated that the company still expected the upgraded plant to
be fully on line by May 29, 2016. We verified the status of the
installation of the controls with the company, who confirmed that
installation of the NID controls was completed in June 2016, and that
the plant is now operating with those controls.\172\
---------------------------------------------------------------------------
\170\ https://www.swepco.com/info/projects/FlintCreek/.
\171\ See the Arkansas PSC Web site at http://www.apscservices.info/efilings/docket_search.asp. The quarterly
reports the company is required to submit to the Arkansas PSC are
available by searching for docket No. 12-008-U.
\172\ See file titled ``Record of Call- Flint Creek_August 10
2016,'' which is found in the docket for this rulemaking.
---------------------------------------------------------------------------
After carefully considering the information the commenter has
brought to our attention, we no longer believe that a 5-year compliance
date is appropriate for the SO2 BART controls
[[Page 66378]]
we are requiring for Flint Creek. We agree with the commenter that BART
controls must be installed as expeditiously as practicable. CAA section
169A(b)(2)(A). Therefore, we are finalizing a shorter compliance date.
The information made available to us during the comment period, as
discussed above, indicates that Flint Creek intends to operate the NID
system to comply with the alternative SO2 emission limit
under the Utility MATS rule. The applicable SO2 emission
limit is 0.2 lb/MMBtu. The SO2 emission limit we are
requiring in our FIP to satisfy the BART requirement is 0.06 lb/MMBtu.
As indicated in the information and other documentation the commenter
provided, the company plans to use the same NID system to comply with
MATS and to comply with the facility's SO2 BART requirement.
We expect that to achieve an emission rate of 0.06 lb/MMBtu, additional
scrubbing reagent would be needed beyond that required to meet the 0.2
lb/MMBtu emission limit the company is required to meet by April 2016
under MATS. We also recognize that it is possible that the reagent
handling system installed to meet the 0.2 lb/MMBtu emission limit would
need some upgrades in order to accommodate the additional scrubbing
reagent that would be needed to achieve the more stringent 0.06 lb/
MMBtu emission limit we are requiring in this FIP. Therefore, to allow
the facility sufficient time to secure the additional scrubbing reagent
that would be needed to comply with the SO2 BART emission
limit and to make any necessary upgrades to the reagent handling
system, we are finalizing an 18-month compliance date for Flint Creek
Unit 1 to comply with the SO2 BART requirement. We believe
this is will provide sufficient time for the facility to be able to
achieve the SO2 BART requirement while still meeting the
statutory mandate that BART controls be installed as expeditiously as
practicable.
Comment: If EPA's final NOX BART determination for White
Bluff is based on installation of a SCR with LNB/SOFA, EPA should
require a NOX BART compliance date for SCR at White Bluff of
no later than within 3 years of the final rule's effective date, which
would represent the expeditious implementation required by CAA section
169A(b)(2)(A). The NOX BART compliance date for LNB/SOFA
should be 8 months from the final rule's effective date. If EPA
finalizes its proposal to require LNB/SOFA only as NOX BART
for White Bluff, EPA should require compliance within 8 months of the
final rule's effective date. Eight months is sufficient time for
installation of these controls. These same comments apply and should be
extended to EPA's reasonable progress determination for NOX
for Independence Units 1 and 2.
Response: We are requiring White Bluff Units 1 and 2 and
Independence Units 1 and 2 to each meet a NOX emission limit
of 0.15 lb/MMBtu on a 30 boiler-operating-day rolling average, where
the average is to be calculated by including only the hours during
which the unit was dispatched at 50% or greater of maximum capacity. In
addition, we are requiring each unit to meet a NOX emission
limit of 671 lb/hr on a rolling 3-hour average that is applicable only
when the unit is being operated at less than 50% of the unit's maximum
heat input rating. These emission limits are consistent with the
installation and operation of LNB/SOFA controls. In light of the
comment, we have reconsidered the compliance date for the
NOX BART requirements for White Bluff Units 1 and 2 and for
the NOX controls under reasonable progress for Independence
Units 1 and 2. Based on the supporting information provided by the
commenter, we agree with the commenter that 6-8 months is the typical
installation timeframe for LNB/OFA controls.\173\ However, in
determining the appropriate compliance date for these NOX
controls, we have also taken into consideration that we are finalizing
NOX emission limits that are based on LNB/OFA or LNB/SOFA
controls for a total of five EGUs in this FIP and that the installation
of these controls will require outage time. These five EGUs are Flint
Creek Unit 1, White Bluff Units 1 and 2, and Independence Units 1 and
2, and combined they accounted for approximately 45% of the state's
2015 heat input. Because of the heavy reliance on these EGUs for
electricity generation in the state, we recognize that it may be
difficult to schedule outage time to install LNB/OFA or LNB/SOFA on all
five of these Arkansas units within the typical installation timeframe
of 6-8 months and at the same time supply adequate electricity to meet
demand in the state. In light of these unique circumstances, we find
that it is appropriate to finalize an 18-month compliance date for
White Bluff Units 1 and 2, Independence Units 1 and 2, and Flint Creek
Unit 1 to comply with the NOX emission limits required by
this FIP. This compliance date provides the affected utilities
sufficient time beyond typical LNB/OFA installation timeframes to
install these controls and comply with their NOX emission
limits, while safeguarding the continuity of Arkansas' electricity
supply.
---------------------------------------------------------------------------
\173\ See comments and exhibits submitted by Earthjustice, the
National Parks Conservation Association, and Sierra Club, dated
August 7, 2015. These and all other comments submitted during the
public comment period are found in the docket associated with this
rulemaking.
---------------------------------------------------------------------------
We address comments contending that we should require SCR controls
on White Bluff and Independence elsewhere in this final rule and in our
RTC document.
Comment: One commenter noted that the proposed FIP would require
Flint Creek Unit 1 to comply with the NOX BART requirement
within 3 years of the effective date of the rule. The commenter argued
that if EPA's final NOX BART determination for Flint Creek
is based on installation of LNB/OFA, EPA should establish a shorter
compliance deadline since compliance with BART is required as
expeditiously as practicable.\174\ The commenter contends that AEP has
been planning for the installation of LNB/OFA and that construction has
already begun. The commenter argues that since the utility is currently
installing LNB/OFA with a May 2016 planned operation date, EPA should
require a NOX BART compliance date of no later than May 2016
in order to ensure the expeditious implementation required by law.
---------------------------------------------------------------------------
\174\ 40 CFR 51.308(e)(1)(iv).
---------------------------------------------------------------------------
AEP/SWEPCO, which is one of the owners of Flint Creek, also
commented on our proposed NOX BART compliance date for Flint
Creek Unit 1. The company stated that if EPA does not rely on CSAPR to
satisfy the NOX BART requirement for EGUs in Arkansas, it
supports EPA's determination of LNB/OFA controls as BART and the
associated limits proposed by EPA. But the company stated that the
proposed 3-year compliance timeframe is unreasonable. The company
stated that the compliance time frame must allow for planning,
selection of engineering and design professionals, vendors,
contractors, permitting, start up and commissioning, and coordinating
and scheduling unit outages. The company also argued that since EPA has
allowed installation schedules up to 5 years in other states, we should
allow such a time frame here.
Response: We are finalizing our determination that NOX
BART for AEP Flint Creek Unit 1 is an emission limit of 0.23 lb/MMBtu
on a 30 boiler-operating-day rolling average, which is consistent with
the installation and operation of LNB/OFA. The commenter has not
provided sufficient information to corroborate the claim that
installation of LNB/OFA at Flint Creek Unit 1 is
[[Page 66379]]
expected to be completed by May 2016. We acknowledge that on July 10,
2013, the Arkansas PSC filed an order agreeing that the installation of
additional environmental controls at Flint Creek Unit 1, including LNB/
OFA to meet the NOX BART requirement, is in the public
interest.\175\ In the attachments to the comment, the commenter points
to a news article that references a January 21, 2014 report submitted
by AEP/SWEPCO to the Arkansas PSC.\176\ In that January 21, 2014
report, AEP/SWEPCO announces that construction of environmental
controls at Flint Creek commenced on January 20, 2014.\177\ However,
the January 21, 2014 report does not specify if this includes
construction of LNB/OFA. While we acknowledge that there is publicly
available information indicating that the company planned to complete
installation of a NID system and activated carbon injection by May 2016
to comply with the Utility MATS rule, there is no information available
to us corroborating that the expected date of LNB/OFA installation was
also May 2016. In fact, the comments submitted by AEP/SWEPCO indicate
that the company has not begun installation of these controls.\178\
With regard to AEP/SWEPCO's request that we extend the compliance date
to 5 years, we have determined that the company has not provided any
information regarding any special circumstances specific to the
facility that sets it apart from other facilities and that would
prevent it from completing installation of controls within typical 3-
year LNB/OFA installation timeframes.
---------------------------------------------------------------------------
\175\ See Arkansas Public Service Commission, Docket No. 12-008-
U, Order No. 14, dated July 10, 2013. A copy of the order can be
found at http://www.apscservices.info/pdf/12/12-008-u_227_1.pdf.
\176\ See the document titled ``Technical Support Document to
Comments of Conservation Organizations,'' which is an attachment to
the comments submitted by Earthjustice, the National Parks
Conservation Association, and Sierra Club. These and all other
comments submitted during the public comment period are found in the
docket associated with this rulemaking.
\177\ http://www.apscservices.info/pdf/12/12-008-u_238_1.pdf.
\178\ See the comments submitted by AEP-SWEPCO, dated July 15,
2015 and August 7, 2015. These and all other comments submitted
during the public comment period are found in the docket associated
with this rulemaking.
---------------------------------------------------------------------------
Additionally, as discussed in a previous response, we agree that
LNB/OFA can typically be installed within a 6-8 month timeframe.
However, in determining the appropriate compliance date for these
NOX controls, we have also taken into consideration that we
are finalizing NOX emission limits that can be achieved by
the installation of LNB/OFA or LNB/SOFA controls for a total of 5 EGUs
in this FIP. Because of the heavy reliance on these EGUs for
electricity generation in the state and because it may be difficult to
schedule outage time to install these controls on all five of these
units within the typical installation timeframe of 6-8 months without
disrupting the supply of electricity in the state, we are finalizing an
18-month compliance date for Flint Creek Unit 1 and the other EGUs to
comply with the NOX emission limits required by this FIP.
G. Compliance Demonstration Requirements
Comment: For purposes of BART for the Domtar Ashdown Mill Power
Boiler No. 1 and Power Boiler No. 2, EPA is defining boiler operating
day as a 24-hour period between 12 midnight and the following midnight
during which any fuel is fed into and/or combusted at any time in the
power boiler, consistent with the guidelines for utility boilers.
However, the Ashdown Mill boilers are industrial boilers, not utility
boilers. The Ashdown Mill defines a mill operating day to be a 24-hour
period between 6 a.m. and 6 a.m. the following day. All of the mill's
systems for Power Boilers No. 1 and 2 are programmed around this
definition of a mill operating day and modification of these systems
would require a significant amount of effort and would require the
gathering and maintaining of multiple sets of records. Assuming EPA
proceeds with BART for the Ashdown Mill, the mill requests that for
Power Boiler No. 1 and Power Boiler No. 2 a boiler operating day be
defined as ``a 24-hr period between 6 a.m. and 6 a.m. the following day
during which any fuel is fed into and/or combusted at any time in the
power boiler.'' Harmonizing the definitions of a boiler operating day
and a mill operating day does not increase costs for the mill, reduces
confusion for the mill operators, eliminates the need for maintaining
multiple sets of records, and eliminates the need for changes to
existing monitoring systems. We believe EPA is authorized or can use
its discretion to define a boiler operating day for the Ashdown Mill to
be consistent with the mill's boiler operating day definition.
Response: After carefully considering the comment, we agree that
Domtar's request is reasonable and that it is appropriate to harmonize
the definitions of a boiler operating day and a mill operating day to
avoid any unnecessary modification or reprogramming of Power Boilers 1
and 2. To accommodate Domtar's request, for purposes of Power Boiler 1
and Power Boiler 2, in this final action we are defining a boiler
operating day as ``a 24-hr period between 6 a.m. and 6 a.m. the
following day during which any fuel is fed into and/or combusted at any
time in the power boiler.'' We are revising proposed Sec. 52.173 to
reflect this.
Comment: EPA proposed to require compliance with the BART
NOX limit for the Domtar Ashdown mill Power Boiler No. 1 be
demonstrated with an annual stack test. Domtar agrees in general that
stack testing is an appropriate method for demonstrating compliance.
However, EPA's proposal to require stack testing annually is not
appropriate. Historical NOX stack test data from 2001, 2002,
2003, 2004, 2005, and 2010 for Power Boiler 1 show NOX
emissions to be fairly consistent. Based on the numerous previous stack
tests, conducting stack tests annually is not warranted. Should EPA
proceed with BART for the Ashdown Mill, the facility is requesting that
stack testing to demonstrate compliance with the BART NOX
limit be required every 5 years instead of annually, which is
consistent with the Ashdown Mill's Title V permit requirements.
Response: After carefully considering the comment, we have
reconsidered our proposed requirement of annual stack testing. We agree
that the results of the NOX stack testing conducted by
Domtar for Power Boiler No. 1 demonstrate that NOX emissions
have historically remained well below the NOX emission limit
we are finalizing for the boiler.\179\ Therefore, we agree with the
company that it is appropriate to require stack testing every 5 years
instead of annually. In our final action we are requiring that the
facility demonstrate compliance with the NOX BART emission
limit for Power Boiler No. 1 by conducting stack testing every five
years, beginning no later than 1 year from the effective date of our
final action. As discussed in a separate response, we are also
providing one alternative method for demonstrating compliance with the
NOX BART emission limit for Power Boiler No. 1.
Specifically, if the facility's air permit is revised to reflect that
Power Boiler No. 1 is permitted to burn only natural gas, the facility
may demonstrate compliance with the NOX emission limit by
calculating emissions using AP-42 emission factors and fuel usage
records. Under these circumstances, the
[[Page 66380]]
facility would not be required to demonstrate compliance with the
NOX BART emission limit for Power Boiler No. 1 through stack
testing. We are revising proposed Sec. 52.173 to reflect this.
---------------------------------------------------------------------------
\179\ See Excel file titled ``Email from Domtar Regarding NOx
Stack Test for PB1,'' found in the docket for this final rule. The
data provided by Domtar indicate that out of the stack testing
conducted in 2001, 2002, 2003, 2004, 2005, and 2010, the highest
NOX emission rate from Power Boiler No. 1 was 171.3 lb/
hr, compared to the 207.4 lb/hr NOX emission limit we are
finalizing.
---------------------------------------------------------------------------
Comment: Assuming EPA proceeds with BART for the Domtar Ashdown
Mill, the mill agrees with the proposed BART PM limit of 0.44 lb/MMBTU
for Power Boiler No. 2 based on the MACT standard for the ``biomass
hybrid suspension grate'' sub-category contained in the 2013 Boiler
MACT final rule. The Ashdown Mill agrees with EPA's approach of relying
on the Boiler MACT standards for PM to satisfy the PM BART requirement.
However, for this streamlined BART approach, EPA must also ensure that
the monitoring, recordkeeping, reporting requirements for PM BART are
consistent with the monitoring, recordkeeping and reporting
requirements under Boiler MACT. Deviating from the MACT requirements
will result in additional administrative burden for the facility in
maintaining ``multiple sets of compliance books.'' It also will create
confusion for external stakeholders if different values and information
are being reported.
Response: We generally agree with the comment. We proposed to find
that the Domtar Ashdown Mill may rely on compliance with the Boiler
MACT PM standard to satisfy the PM BART requirement for Power Boiler
No. 2, and we did not intend for our FIP to establish requirements for
compliance demonstration, monitoring, recordkeeping, and reporting
different from those the mill is already required to comply with under
the Boiler MACT PM standard. In our proposal, our intent was to propose
requirements for compliance demonstration, monitoring, recordkeeping,
and reporting for the PM BART limit for Power Boiler No. 2 that are
consistent with those under the Boiler MACT PM standard. However, the
commenter has brought to our attention that only some of the compliance
demonstration, monitoring, recordkeeping, and reporting requirements
associated with the Boiler MACT PM standard were included under our
proposed Sec. 52.173(c)(21) and (22) and that it appeared that we were
proposing a separate and distinct set of requirements associated with
our PM BART determination for Power Boiler No.2. Therefore, to ensure
clarity and consistency, we are revising the regulatory text found
under 40 CFR 52.173(c) that applies to Power Boiler No. 2 for PM BART
to state that the mill shall rely on compliance with the Boiler MACT PM
standard under 40 CFR part 63 Subpart DDDDD as revised to satisfy the
PM BART requirement for Power Boiler No. 2. We interpret this to mean
that compliance with the applicable Boiler MACT PM standard as revised
is sufficient to demonstrate compliance with the PM BART requirement.
We are not establishing a separate set of requirements for compliance
demonstration, monitoring, recordkeeping, and reporting (i.e., in
addition to those already required under the Boiler MACT PM standard,
as revised), that Power Boiler No. 2 is required to comply with to
satisfy the PM BART requirement.
H. Reliance on CSAPR Better Than BART
Comment: Arkansas is subject to a Cross-State Air Pollution Rule
(CSAPR, also referred to as the Transport Rule) FIP for ozone-season
NOX. EPA should not require sources that are subject to the
CSAPR FIP to also install BART or additional emissions controls based
on a reasonable progress analysis. The Regional Haze Rule allows states
to implement an alternative program in lieu of BART so long as the
alternative program has been demonstrated to achieve greater reasonable
progress toward the national visibility goal than would BART.\180\ EPA
published CSAPR as a replacement to CAIR on August 8, 2011.\181\ In the
final Transport rule, EPA demonstrated that CSAPR would make greater
reasonable progress toward national visibility goals than would
BART.\182\ EPA concluded in the final Transport rule that a state in
the CSAPR region whose EGUs are subject to the requirements of the
CSAPR trading program for ozone season NOX may rely on EPA's
finding that CSAPR makes greater reasonable progress than source-
specific NOX BART. Despite EPA's demonstration that CSAPR
makes greater reasonable progress than source-specific BART, EPA makes
no mention of CSAPR emissions controls in the FIP proposal and requires
source specific NOX BART for Arkansas EGUs that are covered
by CSAPR. The approach that EPA has proposed for Arkansas is
inconsistent with that taken for other states. EPA promulgated FIPs to
replace reliance on CAIR with reliance on CSAPR for the following
states: Georgia, Indiana, Iowa, Kentucky, Michigan, Missouri, Ohio,
Pennsylvania, South Carolina, Tennessee, Virginia and West Virginia.
Similarly, Virginia is revising the Virginia Regional Haze SIP to rely
on the Virginia CSAPR FIP to meet BART and reasonable progress
requirements for SO2 and NOX. Perhaps most
noteworthy, EPA has proposed reliance on CSAPR in states that border
Arkansas. The Texas-Oklahoma Regional Haze FIP proposal does not
require BART for sources that are subject to CSAPR.\183\ In that FIP
proposal, EPA reiterates its position that ``CSAPR, like CAIR, provides
for greater reasonable progress towards the national goal than would
BART,'' \184\ and proposes replacing reliance on CAIR with reliance on
the trading programs of CSAPR as an alternative to SO2 and
NOX BART for Texas EGUs.\185\ Not only is EPA requiring
Arkansas EGUs covered by CSAPR to control emissions under BART in the
FIP proposal, but EPA has not even considered CSAPR as an option for
making reasonable progress. Even if EPA ultimately rejected CSAPR as a
means to meet the reasonable progress requirements under the Regional
Haze Rule, EPA is required to cogently explain why it has exercised its
discretion in a given manner. EPA's failure to consider CSAPR is
arbitrary and capricious in light of its treatment of other states. EPA
should withdraw the FIP proposal and remove the source-specific
NOX BART requirements for Arkansas EGUs that are covered by
CSAPR in any subsequently proposed plan.
---------------------------------------------------------------------------
\180\ 40 CFR 51.308(e); 77 FR 33642.
\181\ 76 FR 48208.
\182\ 77 FR 33642 (June 7, 2012).
\183\ Approval and Promulgation of Implementation Plans; Texas
and Oklahoma; Regional Haze State Implementation Plans; Interstate
Transport State Implementation Plan To Address Pollution Affecting
Visibility and Regional Haze; Federal Implementation Plan for
Regional Haze and Interstate Transport of Pollution Affecting
Visibility, 79 FR 74818.
\184\ 79 FR 74818, 74851.
\185\ 79 FR 74818, 74853.
---------------------------------------------------------------------------
Response: Arkansas EGUs are subject to CSAPR for ozone season
NOX, and we acknowledge that a state in the CSAPR region
whose EGUs are subject to the requirements of the CSAPR trading program
for ozone season NOX may rely on CSAPR to satisfy the
NOX BART requirement for its EGUs. However, when standing in
the shoes of a state and promulgating a FIP, EPA has the same
discretion as the state to choose to either conduct source-specific
BART determinations or to rely on EPA's 2012 finding that CSAPR is
better than BART. Our decision to make source-specific NOX
BART determinations for Arkansas is reasonable for multiple reasons: It
is the approach Congress chose in the statute itself; \186\ it is
consistent with Arkansas' earlier decision to conduct
[[Page 66381]]
source-specific NOX BART determinations in lieu of relying
on CAIR to meet the BART requirements; and at the time of our proposed
action, it properly accounted for uncertainty in the CSAPR better-than-
BART regulation created by ongoing litigation regarding the CSAPR
program. Further explanation of these reasons is given below.
---------------------------------------------------------------------------
\186\ See CAA section 169A(g)(2) in which Congress defined the
five factor analysis for determining BART but did not expressly
provide for an alternative to source by source BART.
---------------------------------------------------------------------------
The Regional Haze regulations provide generally that ``[a] State
may opt'' to rely on an emissions trading program rather than to
require source-specific BART controls.\187\ More specifically, in 2005
EPA revised the Regional Haze regulations to provide that a state
subject to CAIR ``need not require affected BART-eligible EGUs to
install, operate, and maintain BART.'' \188\ Following the D.C.
Circuit's vacatur and remand of CAIR,\189\ EPA issued CSAPR as a
replacement rule. EPA revised its regulations in 2012 to allow states
to rely on CSAPR in lieu of source-specific BART.\190\
---------------------------------------------------------------------------
\187\ 40 CFR 51.308(e)(2).
\188\ 70 FR 39104, 39156 (July 6, 2005).
\189\ North Carolina v. EPA, 531 F.3d 896 (D.C. Cir. 2008).
\190\ 77 FR 33642.
---------------------------------------------------------------------------
In its 2008 regional haze SIP submittal, Arkansas decided to not
rely on CAIR to satisfy the NOX BART requirement for its
EGUs.\191\ In our Regional Haze FIP proposal for Arkansas, we did not
rely on CSAPR (the follow up rule to CAIR) to satisfy the
NOX BART requirement for EGUs because we chose to follow the
same source-specific approach to NOX BART that Arkansas
selected in its Regional Haze SIP submittal. In addition, litigation
surrounding CSAPR was ongoing at the time that we issued our proposed
Arkansas Regional Haze FIP. CSAPR was issued in 2011, but on December
30, 2011, the D.C. Circuit stayed the rule prior to implementation. The
D.C. Circuit subsequently vacated CSAPR, an action later reversed by
the Supreme Court in 2014. The case was then remanded to the D.C.
Circuit. Then, after our April 2015 Regional Haze FIP proposal, the
D.C. Circuit issued a July 2015 decision in EME Homer City Generation
v. EPA \192\ upholding CSAPR but remanding without vacatur a number of
the Rule's state NOX and SO2 emissions budgets.
Arkansas' ozone season NOX budget is not itself affected by
the remand. However, the Court's remand of the affected states'
emissions budgets has implications for CSAPR better-than BART, since
the demonstration underlying that rulemaking relied on the emission
budgets of all states subject to CSAPR, including those that the D.C.
Circuit remanded, to establish that CSAPR provides for greater
reasonable progress than BART. As of the time EPA is taking this action
to finalize Arkansas' Regional Haze FIP, we are in the process of
acting on the Court's remand consistent with the planned response we
outlined in a June 2016 memorandum.\193\
---------------------------------------------------------------------------
\191\ As Arkansas did not rely on CAIR to satisfy requirements
in the regional haze SIP, Arkansas is not included in the EPA's
limited disapproval of regional haze SIPs that relied on CAIR to
satisfy certain regional haze requirements. See 77 FR 33642, at
33654. In that same rulemaking, the EPA promulgated FIPs to replace
reliance on CAIR with reliance on CSAPR in many of those regional
haze SIPs; however, Arkansas was likewise not included in that FIP
action.
\192\ 795 F.3d 118 (DC Cir 2015).
\193\ https://www3.epa.gov/airtransport/CSAPR/pdfs/CSAPR_SO2_Remand_Memo.pdf.
---------------------------------------------------------------------------
Our final action on the Arkansas Regional Haze FIP is consistent
with our final action on the Texas Regional Haze FIP. Although we
proposed to rely on CSAPR to address the NOX BART
requirements for EGUs in Texas, we did not finalize that portion of our
proposed Texas FIP given the uncertainty arising from the remand of the
CSAPR budgets for Texas and other states.\194\ In light of the above,
the comments that we are treating Arkansas differently than other
states where EPA relied on CSAPR to meet the BART requirements are no
longer applicable.
---------------------------------------------------------------------------
\194\ 81 FR 296, 302.
---------------------------------------------------------------------------
As we have noted throughout this document, we are willing to work
with ADEQ to develop a SIP revision that could replace our FIP. Such a
SIP revision will need to meet the CAA and EPA's Regional Haze
regulations. In its SIP revision, ADEQ may elect to rely on CSAPR to
satisfy the NOX BART requirements for Arkansas' EGUs instead
of doing source-specific NOX BART determinations. Such an
approach could be appropriate if, as we expect, the uncertainty created
by the D.C. Circuit's remand of the affected states' emission budgets
will shortly be resolved.
With regard to the comment that we should not require EGUs that are
covered under CSAPR to also install additional emissions controls under
reasonable progress analysis, we disagree. In our 2012 finding that
CSAPR is better than BART, we stated that states with EGUs covered
under CSAPR may rely on CSAPR to satisfy the BART requirement. However,
controls under reasonable progress are a separate requirement from
BART, and we disagree that states can rely on CSAPR to satisfy the
reasonable progress requirements under Sec. 51.308(d)(1). As explained
in the 2005 rulemaking addressing reliance on CAIR, our determination
that a trading program provides for greater reasonable progress than
BART is not a determination that the trading program satisfies all
reasonable progress requirements.\195\
---------------------------------------------------------------------------
\195\ 70 FR 39104, 39143; see also 77 FR 33642, 33653.
---------------------------------------------------------------------------
I. Cost
We received numerous comments related to the cost analyses we
proposed. These comments were received from both industry and
environmental groups, and covered all aspects of our cost analyses.
We received comments from industry concerning our proposed scrubber
cost analyses that objected to our use of the IPM cost algorithms that
Sargent and Lundy (S&L) developed under contract to us. As we discuss
in our TSD, we programmed the Spray Dryer Absorber (SDA--a type of dry
scrubber), and wet FGD cost algorithms, as employed in version 5.13 of
our IPM model, into spreadsheets in our analysis of various aspects of
the Entergy White Bluff and Independence scrubber cost analyses.\196\
Industry stated these cost algorithms were not accurate enough to
warrant their use in individual unit-by-unit cost analyses, do not
consider site-specific costs, and that our use of them violated our
Control Cost Manual. Environmental groups supported our use of the IPM
cost algorithms, and employed them as well in costing scrubber and SCR
control costs to support their own comments. In response, we conclude
that the IPM cost algorithms provide reliable, study-level, unit-
specific costs for regulatory cost analysis such as required for BART
and reasonable progress.\197\
---------------------------------------------------------------------------
\196\ See discussion beginning on pages 9 and 20 of our TSD
Appendix A.
\197\ We believe that the IPM cost algorithms provide study
level accuracy. See pdf page 17 of our Control Cost Manual:
``[a]``study'' level estimate [has] a nominal accuracy of 30% percent. According to Perry's Chemical Engineer's
Handbook, a study estimate is `. . . used to estimate the economic
feasibility of a project before expending significant funds for
piloting, marketing, land surveys, and acquisition . . . [However]
it can be prepared at relatively low cost with minimum data.'''
---------------------------------------------------------------------------
We received comments relating to our critique of Entergy's White
Bluff dry scrubber cost analysis. These primarily involved claims that
we (1) improperly escalated Entergy's own cost analyses, (2) improperly
excluded costs, (3) under-estimated O&M costs, (4) improperly
calculated the SO2 baseline, (5) improperly excluded
``Allowance for Funds Used During Construction''
[[Page 66382]]
(AFUDC) and owner's costs, and (6) improperly extended our White Bluff
scrubber cost analyses to the Independence facility. In response to
these comments, we have made some minor adjustments to our White Bluff
scrubber cost analyses, but those changes do not change our proposal
that scrubbers remain cost-effective for the White Bluff facility, and
by extension to the Independence facility.
We received comments from environmental groups concerning the White
Bluff, Independence, and Flint Creek facilities that (1) generally
supported our proposed control suite, (2) criticized us in some cases
for not proposing stricter control levels, (3) criticized our control
cost analyses for being too conservative in some cases and/or
containing errors, and (4) criticized us in some cases for not
requiring earlier compliance. These groups also generally opposed our
BART determination for Lake Catherine Unit 4.
Below we present a summary of our responses to the more significant
comments we received that relate to our proposed cost analyses.
Comment: S&L states we significantly under-estimated the direct
Operating and Maintenance (``O&M'') costs projected for the scrubbers
by using its Integrated Planning Model (``IPM'') Spray Dryer Absorber
(``SDA'') cost model to scale the O&M costs rather than estimating
these costs using current utility pricing information. S&L stated that
our use of the IPM cost algorithms was not in keeping with our Control
Cost Manual and because of the limited number of site-specific inputs,
the IPM cost algorithms provide order-of-magnitude control system cost
estimates, but do not provide case-by-case project-specific cost
estimates meeting the requirements of the BART Guidelines, nor do the
IPM equations incorporate the cost estimating methodology described in
the Control Cost Manual.
Response: We disagree with S&L. As we discuss in our TSD,\198\ we
needed to adjust Entergy's O&M costs for its White Bluff SDA model
because of a mismatch between Entergy's SO2 emission
baseline and the SO2 inlet it assumed in the design of its
scrubber (discussed in our response to another comment). Entergy costed
a scrubber capable of treating a SO2 level of 2.0 lbs/MMBtu,
when it historically burned coal that averaged less than 0.6 lbs/MMBtu
from 2009-2013. This had the effect of worsening the cost effectiveness
(increasing the $/ton) over what it would have been had Entergy
designed it to treat the coal it historically burned. We could not
directly adjust Entergy's O&M costs because Entergy's O&M cost
estimates were based on an S&L economic model from May 2008, which it
did not supply.\199\ These issues, which we discuss in our responses to
comments elsewhere, dictated a revision to Entergy's cost estimate. We
were left with no choice but to seek an alternative means of estimating
Entergy's O&M costs, in order to address the mismatch described above.
We utilized the IPM SDA cost model that Entergy's own contractor
designed for us.
---------------------------------------------------------------------------
\198\ See Section 3.1 in Appendix A of our TSD.
\199\ See Section 2.7 in Appendix A of our TSD.
---------------------------------------------------------------------------
We disagree that our cost estimates were not in keeping with the
Control Cost Manual. As we stated in our TSD Appendix A, we relied on
the methods and principles contained within the Control Cost Manual,
namely the use of the overnight costing method. In fact, the Control
Cost Manual does not include any method for estimating the costs
specific to any of the SO2 control equipment evaluated in
this action. We note our technique of relying on a publicly available
control cost tool is similar to the strategy the states themselves
employed in the development of their SIPs. For instance, as explained
in the Texas SIP, the ADEQ used the control strategy analysis completed
by the CENRAP, which depended on the EPA AirControlNET tool \200\ to
develop cost per ton estimates. We have used IPM cost models to
estimate BART costs in other similar rulemakings including our Arizona
Regional Haze FIPs,\201\ the Wyoming Regional Haze FIP,\202\ and to
supplement our analysis in the Oklahoma FIP.\203\ S&L used real world
cost data to construct its cost algorithms and confirm their validity.
These cost models have been updated and maintained since their
introduction in 2010 and we have been continuously using them since
that time. These control costs are based on databases of actual control
project costs and account for project specifics such as unit size, coal
type, gross heat rate, and retrofit factor. The costs further require
unit specific inputs such as reagent cost, waste disposal cost,
auxiliary power cost, labor cost, gross load, and emission information.
We believe that the IPM cost models provide reliable study-level, unit-
specific costs for regulatory cost analysis such as required for BART
and reasonable progress. We are confident enough in the basic
methodology behind the S&L cost algorithms that in our recent update of
the SCR chapter of the Control Cost Manual \204\ we presented an
example costing methodology that is based on the IPM S&L SCR
algorithms, which were developed using a similar methodology to the wet
FGD, SDA, and DSI cost algorithms discussed herein. Lastly, we note
that Entergy used a number of general approximations when estimating
the wet scrubbing costs for White Bluff, as we describe in our
TSD.\205\ We conclude that our approach is in keeping with the Control
Cost Manual and is sufficiently accurate for its intended purpose.
---------------------------------------------------------------------------
\200\ Our AirControlNET tool is out of date and no longer
supported.
\201\ 77 FR 42852 (July 20, 2012).
\202\ Memorandum from Jim Staudt to Doug Grano, EPA, Re: Review
of Estimated Compliance Costs for Wyoming Electricity Generating
Units (EGUs)--Revision of Previous Memo, February 7, 2013, EPA-R08-
OAR-2012-0026-0086_Feb 7, 2013.
\203\ 76 FR 81728 (December 28, 2011).
\204\ https://www3.epa.gov/ttn/ecas/cost_manual.html.
\205\ See discussion beginning on page 19 of Appendix A to our
TSD.
---------------------------------------------------------------------------
Comment: Entergy disagreed with our approach for escalating a 2013
scrubber cost analysis for its White Bluff facility to 2015, rather
than obtaining a revised cost estimate. Entergy claims this caused us
to underestimate our scrubber cost estimate by $36,322,881 (total for
both units). Entergy also disagreed with our application of the
Chemical Engineering Plant Cost Index (CEPCI) indices in several
instances from 2008 that de-escalated costs, resulting in lower costs
in 2013 as compared to 2008. Entergy states that our cost calculations
ignored the updated 2012 direct annual costs it provided, and instead
included the 2008 costs. In a subsequent comment, Entergy calculates an
escalation rate of 4.7%, based on a comparison of a revised 2013 quote
to a 2009 quote, and applies that escalation rate along with other
corrections to various cost line items in concluding that we
underestimated the cost of installing scrubbers at the White Bluff
facility by $42,607,547 per unit.
Response: For our proposal, we used Entergy's revised BART analysis
for the White Bluff facility, as submitted by it on October 14, 2013,
because at the time it was the latest information available to us.\206\
In our proposal, our control cost analysis used the same basic
information that Entergy previously presented to us in 2013. As we
describe in Appendix A of our TSD, Entergy stated that it received two
different SDA cost estimates for White Bluff: An early 2009 Sargent and
Lundy (S&L) estimate with a total contractor cost of $291,930,000, and
a December 2009
[[Page 66383]]
estimate from Alstom of $247,856,184. Entergy stated that unlike the
S&L quote, the Alstom estimate was not itemized and only included a
total price. Entergy used the 2009 Alstom price quote as the basis for
its BART cost analysis for White Bluff by increasing it by 10%, and
scaling the S&L itemized cost to match the 110% adjusted Alstom total
price. As we describe in our RTC, we critiqued certain aspects of
Entergy's use of this information. For example, Entergy mistakenly
included certain NOX controls in its 2013 cost analysis. It
also failed to document certain BOP costs that we had no choice but to
exclude. However, between the 2009 S&L and the 2009 Alstom quotes, and
with these corrections, we were able to construct a reasonable control
cost estimate. In so doing, we used the same 2009 Alstom total, and the
Alstom payment schedule for its quote, as the actual Alstom quote was
not supplied and no better information was presented by Entergy.
Because Entergy's 2013 cost estimate used 2009 Alstom pricing, we had
no choice but to escalate it to 2013--more recent information was not
available.
---------------------------------------------------------------------------
\206\ See section 2.1 of Appendix A to our TSD.
---------------------------------------------------------------------------
Entergy did not provide its updated 2015 cost estimate, which it
references in its comment, until after our proposal. Entergy's 2015
report uses updated 2013 pricing from Alstom as its basis. As we
discuss in our RTC, we reviewed this 2015 cost analysis and found that
it presents problems that prevent us from using it, primarily because
it is undocumented.
In this comment, Entergy attempts to use its newly submitted 2015
cost analysis to discredit the escalation technique we employed to
adjust its previous 2013 cost analysis. It does so without even
presenting the 2013 Alstom quote on which it states the 2015 cost
estimate relies. Thus, we have no basis to conclude that the costs
Entergy presents in its first table above even cover the same scope of
work. This is an important consideration and a different scope can
cause a significant difference in cost. Entergy itself noted this when
it used a revised BOP estimate to adjust its 2009 Alstom quote because
the scope had changed. Even different cost estimates received in the
same year can result in significantly different totals. For instance,
as we also note in our TSD, Entergy stated that it received two
different SDA cost estimates for White Bluff: An early 2009 S&L
estimate with a total contractor cost of $291,930,000, and a December
2009 estimate from Alstom of $247,856,184.\207\ We note that the
difference between these two quotes is $44,073,816, which is more than
Entergy calculates in its first table above is the difference between
our escalated 2013 quote ($261,581,119) and its revised 2015 cost
estimate, based on the its 2013 Alstom quote ($297,904,000).
---------------------------------------------------------------------------
\207\ See section 2.1 of Appendix A to our TSD.
---------------------------------------------------------------------------
Escalation from one year's cost basis to another \208\ is not only
allowed by the Control Cost Manual, it is a required procedure in order
to allow an apples-to-apples comparison between control cost analyses.
Our use of the Chemical Engineering Plant Cost Index (CEPCI) is a
standard method of escalating costs,\209\ and one that power companies
have also used on numerous occasions. Entergy itself has used the CEPCI
in an attempt to escalate its costs. Unfortunately, as we explain in
our TSD, Entergy did so incorrectly and we corrected that error.\210\
We certainly prefer revised vendor quotations to escalating older cost
estimates. However, when revised vendor quotes are not available as in
this case, we have no choice but to escalate older cost estimates in
order to bring the cost basis to the present.
---------------------------------------------------------------------------
\208\ Note that escalation during the construction period is
disallowed, however, because that is not a part of the overnight
method.
\209\ Vatavuk, William, M., ``Updating the CE Plant Cost
Index,'' Chemical Engineering, January 2002.
\210\ See section 2.6 of Appendix A to our TSD.
---------------------------------------------------------------------------
Entergy also apparently objects to any escalation technique that
results in a reduction in a future year's cost basis, holding it up as
evidence of our error.\211\ This is a fundamental misunderstanding of
escalation. For instance, although the Composite CE index usually
increases from year to year, it does occasionally decrease, due to
various broad economic factors, such as it did from 2008 to 2009, and
again from 2011 to 2013. This is mainly due to broad economic factors
that influence the cost of raw materials, supply and demand, vendor
profit, etc. Thus, Entergy's objection over the ``de-escalation'' of
cost from 2008 to 2013 is entirely misplaced. In other words,
escalation is escalation: Most of the time it is positive but sometimes
it is negative. We therefore do not agree with Entergy's objections to
our escalation technique. We take up the issue of Entergy's 2015 cost
estimate in our response to another comment.
---------------------------------------------------------------------------
\211\ Entergy's reference to de-escalated costs.
---------------------------------------------------------------------------
Entergy states that our cost calculations ignored the updated 2012
direct annual costs provided by Entergy, and instead included the 2008
costs. As noted in the first sentence of our response to this comment,
we were constrained to use Entergy's revised BART analysis for the
White Bluff facility, as submitted by Entergy on October 14, 2013
(hereafter referred to as the ``2013 SDA Cost Analysis''). These costs
employed a 2008 vintage total direct annual cost, as we indicate in
Appendix A of our TSD.\212\ Regarding its direct annual costs, Entergy
further states, ``The cost estimates were scaled to reflect 2012
dollars.'' \213\ We therefore agree that Entergy did provide what it
stated was 2012 vintage direct annual costs. We did not use those costs
because Entergy incorrectly escalated them from 2008, as we discuss
above. For instance, Entergy presented its 2008 direct annual cost as
$7,901,369. It then ``scaled'' them to 2012 using a 2008 CEPCI index of
530.7 and a 2012 CEPCI index of 593.6, resulting in a 2012 value of
$8,837,861. As we discuss in Appendix A of our TSD, Entergy appears to
have incorrectly used the January monthly CEPCI value for each year
instead of the annual CEPCI value. Entergy should have used a 2008
CEPCI index of 575.4 and a 2012 CEPCI index of 584.6, resulting in a
2012 escalated direct annual cost of $8,027,703 ($7,901,369 x 584.6/
575.4). As we also discuss in our TSD, because we were conducting our
analysis later, we escalated Entergy's 2008 direct annual cost to 2013,
resulting in a value of $7,790,140 ($7,901,369 x 567.3/575.4). These
facts appear to have been ignored by Entergy in its comment. We
therefore have no choice but to disagree with Entergy's comment
concerning our not using its 2012 direct annual cost.
---------------------------------------------------------------------------
\212\ See section 2.7 of Appendix A to our TSD.
\213\ Revised Bart Five Factor Analysis, White Bluff Steam
Electric Station, Redfield, Arkansas (AFIN 35-00110). Appendix A,
SDA cost analysis, June 2013, Appendix A.
---------------------------------------------------------------------------
Comment: Entergy and Nucor stated that we improperly excluded AFUDC
and owner's costs from our White Bluff control cost analysis. Entergy
also objects to our disallowance of certain BOP costs.
Response: As we have noted in a number of our FIPs, AFUDC and
Owner's Costs are not valid costs under our Control Cost Manual
methodology. We invite the commenters to examine our response to
similar comments we received in response to those actions.\214\
---------------------------------------------------------------------------
\214\ See, e.g., ``Response to Technical Comments for Sections E
through H of the Federal Register Notice for the Oklahoma Regional
Haze and Visibility Transport Federal Implementation Plan,'' Docket
No. EPA-R06-OAR-2010-0190, 12/13/2011.
---------------------------------------------------------------------------
In Appendix A to our TSD, we noted that Entergy used BOP costs from
a 2008 S&L quote to supplement its adjusted 2009 Alstom quote in its
2013 SDA cost analysis for the White Bluff BART determination. However,
due to a lack of documentation, it appeared that a number of items were
either not appropriate for a SO2 scrubber, or were
[[Page 66384]]
already covered as part of the Alstom quote. As discussed in detail in
our RTC document, we removed those items from our proposed SDA cost
analysis and invited Entergy to supply additional documentation to
verify these costs. S&L now points to an S&L Report #012831, which
contains a 2015 White Bluff SDA cost estimate, for that documentation.
First, Entergy states that its 2015 SDA cost estimate is based on a
2013 Alstom quote. As with the 2009 Alstom quote it used to support its
2013 SDA cost analysis, Entergy did not provide this Alstom quote.
Consequently, we have no way of verifying Entergy's 2015 cost
calculations or to conclude that their scopes are the same. Therefore,
we have no choice but to conclude that Entergy has not demonstrated
that our removal of costs associated with the reagent preparation
enclosure and reagent handling system and ductwork was incorrect.
Similarly, we continue to find that Entergy has not documented certain
BOP indirect costs, miscellaneous contract labor, Entergy internal
costs, and capital suspense.
We do agree that Entergy has provided documentation for other
costs, including demonstrating that recalibration of the CEMS and
painting of the chimney are justified, and we have adjusted our White
Bluff scrubber cost analysis accordingly. Other costs that were
calculated as percentages of the equipment, material, and labor costs
were similarly adjusted. We have revised our cost analysis to include
these adjustments, and have determined that dry scrubbers are estimated
to cost $2,565/SO2 ton removed at Unit 1 and $2,421/
SO2 ton removed at Unit 2.\215\ Revising these costs did not
change our final determination that dry scrubbers are cost-effective
for the White Bluff facility.
---------------------------------------------------------------------------
\215\ See the file, ``White Bluff_R6 cost revisions2-
revised.xlsx'' in our docket.
---------------------------------------------------------------------------
Comment: S&L objects to our approach of calculating an
SO2 baseline for the White Bluff and Independence
facilities, in which we eliminated the high and low annual emission
values from 2009 to 2013, and averaged the remaining values. S&L
presents four alternative approaches in which a straight five year
average from 2009 to 2013, and different three year averages from 2009
to 2013 are examined for White Bluff Units 1 and 2 and Independence
Units 1 and 2, and concludes that in all cases, at least one of the
alternative approaches would have resulted in lower baseline
SO2 emissions for one of the units.
Response: We disagree with S&L that we erred in the procedure we
used in estimating baseline emissions for our BART and reasonable
progress scrubber upgrade cost analyses. We calculated our baseline
SO2 emissions by first acquiring the 2009 to 2013 emissions
as reported to us by the facilities in question.\216\ We reasonably
eliminated the high and low values from the 2009-2013 emissions to
better address potential yearly variations in in coal sulfur data,
capacity usage, etc., and to make the baseline more representative of
plant operations and thereby provide the basis for a more accurate
estimate of the cost effectiveness of controls. The fact that S&L can
construct alternative approaches to our baseline calculation that
result in lower emissions estimates does not invalidate our BART and
reasonable progress approaches. As can be seen from an examination of
S&L's own data, regardless of whether a 3-year average or a 5-year
average of a particular set of years is employed, the resulting
emissions baselines are all similar. In fact, for three out of four
units, one of S&L's alternative approaches would have produced higher
SO2 emissions baselines, which if used would have resulted
in the cost analyses we performed being even more cost-effective. We
believe that the procedure we used is in compliance with the BART
Guidelines, which states:
---------------------------------------------------------------------------
\216\ http://ampd.epa.gov/ampd/
How do I calculate baseline emissions?
1. The baseline emissions rate should represent a realistic
depiction of anticipated annual emissions for the source. In
general, for the existing sources subject to BART, you will estimate
the anticipated annual emissions based upon actual emissions from a
baseline period.
2. When you project that future operating parameters (e.g.,
limited hours of operation or capacity utilization, type of fuel,
raw materials or product mix or type) will differ from past
practice, and if this projection has a deciding effect in the BART
determination, then you must make these parameters or assumptions
into enforceable limitations. In the absence of enforceable
limitations, you calculate baseline emissions based upon
continuation of past practice.\217\
---------------------------------------------------------------------------
\217\ 70 FR 39104, 39167.
Regarding the baseline used in our Independence reasonable progress
analysis, our 2007 Reasonable Progress Guidance notes the similarity
between some of the reasonable progress factors and the BART factors
contained in Sec. 51.308(e)(1)((ii)(A), and suggests that the BART
Guidelines be consulted regarding cost, energy and nonair quality
environmental impacts, and remaining useful life.\218\ We are therefore
relying on our BART Guidelines for assistance in interpreting those
reasonable progress factors, as applicable. One of these areas is in
the calculation of the baseline emissions in determining cost
effectiveness.
---------------------------------------------------------------------------
\218\ ``Guidance for Setting Reasonable Progress Goals Under the
Regional Haze Program,'' at 5-1.
---------------------------------------------------------------------------
The difference between our baseline calculations and any of the
alternative procedures S&L outlines is small and would not change our
conclusions for the White Bluff BART determinations and the
Independence reasonable progress determinations.
Comment: S&L objects to our extending our White Bluff scrubber cost
analysis to the Independence facility on the basis of the similarity of
the two facilities. S&L states that our use of EIA information,
satellite photographs and other points of comparison are inadequate to
account for potential site-specific differences between the two
facilities, such as operating data, O&M practices, underground utility
interferences, geotechnical differences, and seismic differences.
Response: While there are likely differences between the two
facilities that would have some minor impact on the scrubber cost
analyses, we reasonably concluded based on the information available to
us that there were enough similarities between the facilities to make
our approach appropriate. As we discuss in our TSD:
The White Bluff and Independence facilities are sister
facilities. According to EIA,\219\ the boilers were manufactured by
Combustion Engineering with in-service dates of 1980 and 1981 for
White Bluff, and 1983 and 1985 for Independence. All four units are
tangentially firing boilers having nameplate capacities of 900 MW
and similar gross ratings. As we indicate above, all four units burn
coal from the Powder River Basin of Wyoming with similar
characteristics. All four units employ cold side electrostatic
precipitators for particulate collection. Other pertinent
characteristics are similar.\220\
---------------------------------------------------------------------------
\219\ See ``EIA Consolidated Data_WB and IND_Y2012.xlsx.''
\220\ See document titled ``AR RH FIP TSD Appendix A--White
Bluff and Independence SO2 Cost Analysis,'' found in the
docket for this rulemaking.
We further presented satellite photographs to demonstrate that the
layout of these facilities are extremely similar. We consequently
expect that the differences Entergy describes in its comments result in
minor differences in the cost to install and operate scrubbers. As we
have discussed in our response to another comment, the Control Cost
Manual explains that the sole input required for making an ``order of
magnitude'' estimate is the control
[[Page 66385]]
system's capacity (often measured by the maximum volumetric flow rate
of the gas passing through the system). Such an estimate, for example,
could be obtained from the cost reported in dollars per megawatt ($/MW)
or dollars per million BTUs fired ($/MMBtu), metrics that are widely
reported in the literature. The Control Cost Manual indicates that
``the costs and estimating methodology in this Manual are directed
toward the `study' estimate with a nominal accuracy of +/-30%
percent.'' This is the long-standing rule of thumb for cost estimate
accuracy used by the EPA for regulatory cost effectiveness analyses. We
see nothing in Entergy's comments that would suggest that the
differences between these two facilities are so significant they would
impact this required level of accuracy. Indeed, Entergy does not
attempt to estimate the capital costs of these differences or otherwise
provide a cost estimate specific to the Independence facility in
support of its argument that it was inappropriate for us to extend our
White Bluff scrubber cost analysis to the Independence facility.
Comment: Entergy objects to our correction to its White Bluff
scrubber control cost analysis to adjust the cost for a scrubber
designed to treat a 2.0 lb/MMBtu coal to 0.68 lbs/MMBtu to account for
the lower sulfur coal it has historically burned. Entergy states that
we correctly assumed that the 2.0 lb/MMBtu design basis for the White
Bluff scrubber was to preserve fuel flexibility, but our conclusions
that, ``either (1) this higher cost be balanced against its greater
SO2 reduction potential, or (2) that the scrubber system's
capability and cost be adjusted down to match the facility's historical
emissions'' are without basis and inconsistent with the BART
guidelines. Entergy also concludes that its assumption that a 2.0 lb/
MMBtu scrubber inlet was in error and a 1.2 lb/MMBtu inlet assumption
is now appropriate. Entergy presents SO2 emission data in
support of its position that our 0.68 lbs/MMBtu coal assumption was
incorrect and recalculates its O&M and capital costs. Lastly, Entergy
states that in correcting its scrubber control cost analysis to account
for a 0.68 lbs/MMBtu coal, we misapplied a correction factor to our
total direct and indirect costs.
Response: As we noted in our TSD, ``either (1) this higher cost be
balanced against its greater SO2 reduction potential, or (2)
that the scrubber system's capability and cost be adjusted down to
match the facility's historical emissions.'' Entergy chose to do
neither and costed a scrubber capable of treating a coal far in excess
of what it historically burned, but continued to base the capabilities
of the scrubber on its historical SO2 baseline. Thus, either
Entergy's annualized cost (the ``$'') or its tons reduced (the
``tons'') in the $/ton cost effectiveness calculation are
misrepresented. Our approach was to recalculate Entergy's scrubber cost
to bring its scrubber design in line with the coal it has historically
burned. Entergy could have taken the alternative approach of
calculating a new baseline on the basis of its higher sulfur design
coal, but it chose not to do so. We see nothing in Entergy's comments
that would cause us to conclude our reasoning was in error. With regard
to Entergy's concerns with the 0.68 lbs/MMBtu baseline that we use, it
appears the SO2 emission data Entergy presented was hourly
data, which should not be used to design a scrubber that would have to
meet a 30-BOD average. Our analysis indicates the individual hourly
data fluctuations Entergy presents are inconsequential. Further, an
examination of the running 30-BOD average indicates that our decision
to fix the mismatch between Entergy's scrubber costs and its historical
SO2 baseline on the basis of a SO2 inlet of 0.68
lbs/MMBtu is reasonable.
In apparent agreement with our basic approach, Entergy recalculates
its variable and fixed O&M costs on the basis of 0.68 lb/MMBtu fuel
sulfur levels. We note that our own variable and fixed O&M costs are
actually greater, adding to the conservativeness of our calculation. To
illustrate the small difference in capital costs associated with the
revised design basis (1.2 lb/MMBtu versus 0.68 lb/MMBtu), Entergy then
performs a sensitivity analysis and concedes there is a ``small
difference in capital costs associated with the revised design basis
(1.2 lb/MMBtu versus 0.68 lb/MMBtu). . . .'' This conclusion is borne
out by our own figures, which indicate there is a small difference in
capital costs to even the 2.0 lbs/MMBtu case; the capital, engineering
and construction costs, which cover the fundamental design parameter of
a scrubber--gas flow rate--were only changed by less than 5%. In sum,
Entergy's assertion that our cost analysis improperly designed the
White Bluff scrubber system is without merit and would make an
insignificant difference in the final outcome.
Lastly, we agree with Entergy that we misapplied a correction
factor to our total direct and indirect costs. We incorporate that
correction in our final SDA cost analysis for the White Bluff and
Independence facilities, which we discuss in more detail in our
response to other comments. This correction has a relatively minor
impact on the overall cost analysis.
Comment: The Sierra Club supported our proposal regarding
SO2 for the White Bluff and Independence facilities, but
concluded that our proposed SO2 emission rate of 0.06 lbs/
MMBtu on a 30-BOD average should have been stricter at 0.04 lbs/MMBtu,
based on wet scrubbing. The Sierra Club also agrees with our assessment
that Entergy included undocumented costs in its White Bluff scrubber
cost estimate.
The Sierra Club's consultant performed a cost analysis of dry and
wet scrubber systems, including Alstom's NID circulating dry scrubber,
and concluded that our White Bluff scrubber cost analysis was
conservative, that scrubbers are cost effective compared to controls
required pursuant to other BART determinations, and that we should have
required compliance in 3 years instead of 5 years.
Response: We confirm that we intended to construct conservative
cost estimates. With some minor disagreements with the Sierra Club, we
generally agree that an independent cost analysis such as it presents
does support our basic position that scrubbers are cost effective at
both the White Bluff and Independence facilities. However, as we
discuss in our RTC document, we disagree that in this specific instance
wet scrubbers are more cost effective than dry scrubbers. Our scrubber
cost analyses was built off of the analyses supplied by Entergy, and we
determined that wet scrubbers were significantly less cost effective--
again, in the specific cases of the White Bluff and Independence
facilities for BART and reasonable progress respectively. We disagree
with the SO2 baseline Sierra Club uses in its cost analysis,
rendering its scrubber cost analysis and ours not directly comparable.
Consequently, we disagree that an SO2 emission rate of 0.04
lbs/MMBtu averaged over a 30-boiler-operating-day period, based on a
wet scrubber cost analysis, is appropriate for either the White Bluff
or Independence facilities. We agree that in some cases scrubbers can
be installed in less than the 5 years that we proposed. However, this
is site-specific and, in this case, we have found that installation
within 5 years is as expeditious as practicably possible.
We agree that the Alstom NID circulating dry scrubber is a
promising SO2 control option. We reviewed NID in our
preliminary work but ultimately decided not to evaluate it as a control
because we had no relevant operating data and no method to estimate
costs.
[[Page 66386]]
After addressing all comments from Entergy and the Sierra Club
concerning our White Bluff and Independence scrubber cost analyses, we
made several minor corrections.\221\ Below we summarize those
corrections:
---------------------------------------------------------------------------
\221\ Those corrections are contained in the file, ``White
Bluff_R6 cost revisions2-revised.xlsx,'' which appears in our
docket.
Table 18--Corrections to Our Cost-Effectiveness Calculations for Dry FGD
for White Bluff and Independence
------------------------------------------------------------------------
Proposed cost- Final cost-
Unit effectiveness effectiveness
($/ton) ($/ton)
------------------------------------------------------------------------
White Bluff Unit 1...................... $2,227 $2,565
White Bluff Unit 2...................... 2,101 2,421
Independence Unit 1..................... 2,477 2,853
Independence Unit 2..................... 2,286 2,634
------------------------------------------------------------------------
We find that these revised cost-effectiveness calculations do not
change our proposed findings for BART and reasonable progress for these
units.
In addition, we have examined the effect of adding back in a number
of the BOP and other costs we excluded (based on these costs being
either disallowed by the Control Cost Manual, or having lacked
documentation from Entergy). This exercise also appears in the file
``White Bluff_R6 cost revisions2-revised.xlsx.'' These costs include:
BOP Costs associated with the reagent prep enclosure and
the reagent handling system, totaling $21,229,000.
BOP Costs associated with the flue gas system ductwork,
totaling $1,754,000.
BOP indirect costs of $8,474,666 (escalated to 2013).
Miscellaneous contract labor costs of $4,448,074
(escalated to 2013).
Entergy internal costs of $19,482,518 (escalated to 2013).
Capital suspense costs of $8,101,226 (escalated to 2013).
Table 19--Alternate Cost-Effective Calculations for Dry FGD on White
Bluff and Independence
[Include disallowed costs]
------------------------------------------------------------------------
Alternate cost-
Unit effectiveness
($/ton)
------------------------------------------------------------------------
White Bluff Unit 1...................................... $3,013
White Bluff Unit 2...................................... 2,843
Independence Unit 1..................................... 3,351
Independence Unit 2..................................... 3,093
------------------------------------------------------------------------
We continue to believe that these costs are either disallowed by
the Control Cost Manual, or are properly disallowed because they lack
documentation from Entergy. We have presented this information to
indicate that these disallowed costs have a relatively minor effect on
the final cost effectiveness. Although our final decision regarding
BART and reasonable progress for the White Bluff and Independence units
does not rest upon these cost-effectiveness calculations that include
the disallowed costs, had our final decision rested on these cost-
effectiveness calculations, we would have reached the same conclusions
regarding BART and reasonable progress for these units.
Comment: The Sierra Club stated that the NOX emission
limit of 0.15 lbs/MMBtu based on LNB/SOFA we proposed for White Bluff
Units 1 and 2 does not satisfy BART. The Sierra Club asserted that
NOX BART for these units should have been based on SCR. The
Sierra Club's consultant concluded that we overestimated the costs of
SCR and underestimated the visibility benefits of SNCR and SCR. The
consultant's conclusions are based on cost-effectiveness calculations
developed by the consultant, which rely on the S&L IPM SCR Cost Module
and assume an achievable NOX emission rate of 0.04 lb/MMBtu
for LNB/SOFA plus SCR. The Sierra Club stated that LNB/SOFA can be
installed in much shorter timeframe than the 3 years we proposed. The
Sierra Club also stated that we should have evaluated SNCR and SCR for
the Independence facility.
Response: We have a number of disagreements with the Sierra Club's
consultant concerning the SCR cost analysis provided, including the
NOX baseline and the emission limit, which are outlined in
detail in our RTC document. After addressing those issues, we do not
believe that the cost effectiveness of SCR or SNCR fall within a range
that justifies the relatively small incremental visibility improvement
(over our NOX BART determination based on LNB/SOFA) that
would result from the installation of SNCR or SCR at the White Bluff
facility. As we discussed in our proposal,\222\ our modeling indicated
that the visibility improvement at several Class I areas from the
installation of LNB/SOFA at the Independence facility was of a similar
magnitude as the same controls at the White Bluff facility, and
cumulatively (i.e., at all Class I areas combined) the visibility
improvement of the controls at Independence was lower than at White
Bluff. Therefore, we reasoned that since White Bluff and Independence
are sister facilities with near identical units, the cost effectiveness
of SCR or SNCR at Independence would likely not fall within a range
that justifies the relatively small incremental visibility improvement
(over LNB/SOFA) that would result from installation of these controls.
Therefore, we did not evaluate SCR or SNCR controls for Independence.
As we discuss in a separate response, after carefully considering the
comments we have received, we are finalizing an 18-month compliance
date for the NOX emission limits we are establishing for
White Bluff Units 1 sand 2 under BART and Independence Units 1 and 2
under reasonable progress.
---------------------------------------------------------------------------
\222\ See our supplemental NOX modeling results for
the Independence facility in 80 FR 24872 vs. our NOX
modeling results for the White Bluff facility in 80 FR at 18974.
---------------------------------------------------------------------------
Comment: The Sierra Club and others stated that the costs of both a
wet and a dry scrubber are reasonable at the two Independence units.
The Sierra noted our proposed costs are reasonable in other reasonable
progress determinations that it summarizes. The Sierra Club's
consultant independently calculated the costs of scrubbers at
Independence Units 1 and 2 and concluded that those calculations
confirm that a scrubber is cost-effective. The consultant also noted
that the significant visibility improvement from a scrubber at
Independence Units 1 and 2 would equal or exceed the visibility
improvement from other reasonable
[[Page 66387]]
progress controls we have previously approved. The Sierra Club's
consultant also incorporated comments for the White Bluff facility
regarding time for installation and control level.
Response: We take no position on the separate cost analysis that
the Sierra Club's consultant has conducted for dry and wet scrubbers
and that uses to conclude that our cost analyses are reasonable. We
agree that our finding that the control costs are reasonable, given the
visibility improvements achieved, is consistent with other EPA actions.
We refer the Sierra Club's consultant to our responses to other similar
comments regarding the White Bluff facility scrubber concerning control
level and installation time.
Comment: The Sierra Club and others stated that our proposal that
SO2 BART for AEP Flint Creek is a NID dry scrubber is
appropriate, but argued that a NID dry scrubber is even more cost-
effective than what AEP and EPA have estimated. The Sierra Club's
consultant presented cost analyses for wet and NID scrubbing for Flint
Creek, based on the IPM cost algorithms we used in our recent Texas-
Oklahoma FIP. In so doing, the consultant applied the SDA cost
algorithm to NID, citing to documentation that indicates that NID may
be 1-2% lower in cost to an SDA system. The Sierra Club's consultant
argues that both wet and dry scrubbers are capable of even greater
levels of control than what we assumed.
Response: As we discuss in our TSD,\223\ we noted a number of
issues with AEP's NID and wet scrubber cost analyses that if corrected
would have resulted in more favorable (lower $/ton) cost-effectiveness
values. Nevertheless, even disregarding those errors, we concluded that
NID was cost-effective and worth the visibility benefit that will
result from its installation. We also determined that wet scrubbing
would remain less cost-effective than NID, and was not worth the small
additional visibility that would result from its installation in this
particular instance.
---------------------------------------------------------------------------
\223\ See page 65 of our TSD: ``[W]e believe that AEP's
escalation of the cost of controls to 2016 dollars has likely
resulted in the over estimation of the average cost-effectiveness
values. Therefore, we believe a wet scrubber and NID are more cost-
effective (i.e., less dollars per ton of SO2 removed)
than estimated by AEP (see table above). However, we did not adjust
the cost numbers and cost-effectiveness values because we do not
believe that doing so would change our proposed BART determination.
We believe that the average cost-effectiveness of both control
options was likely over-estimated and the costs associated with a
wet scrubber would continue to be higher than the costs associated
with NID if the estimates were adjusted, yet the installation and
operation of a wet scrubber is projected to result in minimal
incremental visibility improvement over NID.
---------------------------------------------------------------------------
We extensively analyzed the performance potential of wet scrubbers
in our recent Texas-Oklahoma FIP.\224\ We concluded that a control
level of 98%, not to go below an emission rate of 0.04 lbs/MMBtu on a
30-BOD average, was a reasonable lower level of control. We applied the
same reasoning to our Arkansas proposal. As we discuss in our response
to another comment, although we regard NID as a promising technology
that may in fact be capable of greater levels of control than what we
have assumed, there is no real long-term monitoring data to
substantiate such a conclusion. Therefore, because we have concluded
that in this instance the cost-effectiveness of wet scrubbers is not
justified by their relatively small additional visibility benefit, we
disagree that SO2 BART for Flint Creek Unit 1 should be
0.04, based on the performance of a wet scrubber.
---------------------------------------------------------------------------
\224\ See response to comment beginning on page 310 of our
Response to Comments for the Federal Register Notice for the Texas
and Oklahoma Regional Haze State Implementation Plans; Interstate
Visibility Transport State Implementation Plan to Address Pollution
Affecting Visibility and Regional Haze; and Federal Implementation
Plan for Regional Haze, Docket No. EPA-R06-OAR-2014-0754, 12/9/2015.
---------------------------------------------------------------------------
Comment: The Sierra Club and others stated that the LNB/OFA
proposal for Flint Creek does not satisfy NOX BART, which
should have been based on SCR. The Sierra Club stated that we and AEP
used very conservative assumptions that inflated the cost of the SCRs
and SNCRs as NOX BART options for Flint Creek. The Sierra
Club's consultant stated that the 20-year life assumed in AEP's SCR
cost analysis should have been 30 years, and that the assumed level of
control should have been 0.04 lbs/MMBtu. The consultant then performed
an SCR control cost analysis and concluded that the cost effectiveness
was within a range we have previously found to be acceptable in other
BART determinations. The Sierra Club's consultant also stated that AEP
overestimated the cost of SNCR because it based it on a reduction of
from 0.31 lbs/MMBtu to 0.2 lbs/MMBtu, when in fact, the first-in-line
LNB/OFA controls would have already reduced the NOX to 0.23
lbs/MMBtu, resulting in a lesser loading to the SNCR system and
reducing its operating costs.
Response: We note that we provided comments to ADEQ,\225\ which
included a recommendation that 30 years should be used as an equipment
life for SNCR. AEP did not adopt this recommendation in its September
2013 BART analysis for the Flint Creek facility. We agree with the
Sierra Club's consultant that AEP overestimated the cost of SNCR
because its calculation based it on a reduction of from 0.31 lbs/MMBtu
to 0.2 lbs/MMBtu. We have corrected this error, and the error in AEP
SWEPCO's assumed 20-year equipment life, and recalculated the SNCR cost
effectiveness for Flint Creek. We calculated that SNCR + LNB/OFA has a
revised cost-effectiveness of $1,346/ton, as opposed to cost
effectiveness of $1,258/ton for LNB/OFA alone. Also, we calculated that
the incremental cost effectiveness of SNCR + LNB/OFA over LNB/OFA alone
is $1,581/ton. We then re-applied the BART five factors, with emphasis
on cost and visibility improvement. The incremental visibility
improvement of SNCR + LNB/OFA over LNB/OFA alone is 0.033 dv at Caney
Creek and ranges from 0.005 to 0.01 dv at each of the other affected
Class I areas. As discussed in our proposal, we consider the
incremental visibility improvement of SNCR + LNB/OFA to be relatively
small at Caney Creek and to be very small in the remaining three
affected Class I areas. We conclude that despite the improvement in the
cost-effectiveness of SNCR + LNB/OFA over LNB/OFA alone, under these
circumstances the resulting relatively small incremental visibility
improvement is still not worth the additional cost of the more
stringent controls.
---------------------------------------------------------------------------
\225\ See email from Dayana Medina to Mary Pettyjohn on 8/21/13.
---------------------------------------------------------------------------
Regarding the Sierra Club's consultant's SCR control cost analysis,
we do not believe that a NOX emission limit of 0.04 lbs/
MMBtu has been maintained on a 30 boiler-operating-day average at other
similar facilities. We conclude that, as we did in our New Mexico FIP,
a 30 boiler-operating-day NOX average of 0.05 lbs/MMBtu is
an appropriate assumption for SCR installation at the Flint Creek
facility. We also note that the maximum visibility improvement due to
SCR at Flint Creek based on the modeled rate of 0.067 lb/MMBtu was
0.245 dv, which occurred at Caney Creek. If we make reasonable,
conservative adjustments to the anticipated visibility benefit, based
on a control level of 0.055 lbs/MMBtu rather than the modeled rate of
0.067 lbs/MMBtu,\226\ we estimate that the resulting visibility
improvement at Caney Creek would be no higher than
[[Page 66388]]
0.26 dv.\227\ Based on this adjustment, the incremental visibility
improvement of SCR + LNB/OFA over SNCR + LNB/OFA is 0.146 dv. Even
accepting the Sierra Club's consultant's SCR cost analysis of $3,511/
ton (which would be higher were it revised using a controlled
NOX rate of 0.05 lbs/MMBtu) and taking into consideration
the adjustments we have made to the cost analysis for SNCR + LNB/OFA,
the incremental cost effectiveness of SCR + LNB/OFA over SNCR + LNB/OFA
is $4,969/ton. In the context of this BART determination, we do not
consider the relatively small incremental visibility improvement to be
worth the incremental cost of the SCR installation.
---------------------------------------------------------------------------
\226\ Modeled emission rates were based on a maximum heat input
of 6,324 MMBtu/hr multiplied by the anticipated control rate (e.g.
0.067 lb/MMBtu) Baseline emissions determined from 2001-2003 CAMD
data were 1,945 lb/hr, approximately 0.308 lb/MMbtu.
\227\ Modeled visibility benefit at CACR over baseline from SCR
at 0.067lb/MMbtu was 0.245 dv. SCR at 0.055 lb/MMBtu would result in
an additional reduction in emissions from baseline of only 4%.
Assuming a linear relationship between emission and visibility
impacts, this would also result in an increase in visibility benefit
of only 4%.
---------------------------------------------------------------------------
Comment: The Sierra Club and others stated that the Lake Catherine
Unit 4 BART analysis failed to accurately consider compliance costs,
non-environmental impacts, and the degree of visibility improvement.
The Sierra Club further stated we underestimated the cost of BOOS and
overestimated the costs of low NOX burners, over-fired air,
SNCR, and SCR. The Sierra Club's consultant also alleges that the
documentation to support the Lake Catherine NOX BART
analysis is incomplete. Lastly, the Sierra Club stated that our cost-
effectiveness analysis should be based on a capacity calculation that
depends on time of operation, and our proposal to use a 10% capacity is
unenforceable. Had we used a higher capacity factor, the Sierra Club
reasons that the increase in NOX emissions removed by the
various pollution control equipment would have improved their cost-
effectiveness (lower $/ton), making them more attractive.
Response: The Sierra Club's consultant raises a number of issues
pertaining to missing documentation or errors in Entergy's
NOX BART analysis for Lake Catherine Unit 4, on which we
relied on in making our BART decision. We reviewed the issues raised by
the Sierra Club's consultant in detail in our RTC document and conclude
they are unfounded or lack documentation. We conducted an analysis of
Lake Catherine's data on heat input, operational time, and
NOX emissions to investigate the correlation between heat
input and operational time to NOX emissions, and further
conclude that capacity calculations for the Lake Catherine Unit 4
should be based on heat input and not operational time. Lastly, we
calculate the historical capacity for the Lake Catherine Unit 4 as
follows:
Table 20--Lake Catherine Unit 4 Historical Capacity
------------------------------------------------------------------------
Capacity
Year factor (%)
------------------------------------------------------------------------
2001.................................................... 28.2
2002.................................................... 24.2
2003.................................................... 11.3
2004.................................................... 3.7
2005.................................................... 4.7
2006.................................................... 0.6
2007.................................................... 0.8
2008.................................................... 2.3
2009.................................................... 2.8
2010.................................................... 3.5
2011.................................................... 2.9
2012.................................................... 14.3
2013.................................................... 11.1
2014.................................................... 2.0
2015.................................................... 3.9
------------------------------------------------------------------------
We agree that the Lake Catherine Unit 4 historical capacity has
sometimes exceeded the 10% capacity Entergy has assumed in its control
cost analyses. However, the average from the last ten years of data
(2006 to 2015) has been 4.4%. Typically, we place the most emphasis on
the last five years of data, and our recent practice has been to
discard the high and low values and average the remaining three
years.\228\ Applying that procedure to the Lake Catherine Unit 4
capacity factor results in a value of 6.0%. Alternatively, calculating
a straight average of the last five years results in a value of 6.8%.
Thus, we disagree that we erred in accepting Entergy's assumption of a
10% capacity factor in its control cost analysis. We note that in its
response to us, Entergy stated, ``If future capacity factors change,
ADEQ and EPA may impose further NOX emission reductions on
Unit 4, if necessary, in later planning periods to show reasonable
progress.'' We believe that is an appropriate strategy and we will re-
examine Lake Catherine's historical capacity in our review of Arkansas'
next regional haze SIP.
---------------------------------------------------------------------------
\228\ This was our approach in calculating the SO2
baselines used in our recent TX-OK FIP.
---------------------------------------------------------------------------
Comment: We received comments from Nucor, Entergy and Conway
Corporation stating that we should have used the dollar per deciview
($/dv) metric to weigh the cost versus the visibility benefit of
controls for the White Bluff and Independence facilities. The Sierra
Club supported our position that we are not required to use this
metric.
Response: The BART Guidelines require that cost effectiveness be
calculated in terms of annualized dollars per ton of pollutant removed,
or $/ton.\229\ The BART Guidelines list the $/deciview metric as an
optional cost effectiveness measure that can be employed along with the
required $/ton metric for use in a BART evaluation. The metric can be
useful in comparing control strategies or as additional information in
the BART determination process; however, due to the complexity of the
technical issues surrounding regional haze, we have never recommended
the use of this metric as a cutpoint or threshold in making BART
determinations or reasonable progress determinations. We note that to
use the $/deciview metric as the main determining factor would most
likely require the development of thresholds of acceptable costs per
deciview of improvement for BART and reasonable progress determinations
for both single and multiple Class I analyses. We have not developed
such thresholds for use in BART or reasonable progress determinations.
Generally speaking, while the $/deciview metric can be useful if
thoughtfully applied, we view the use of this metric as suggesting a
level of precision in the calculation of visibility impacts that is not
justified in many cases. While we did not use a $/deciview metric in
the BART and reasonable progress determinations we make in this FIP, we
did, however, consider the visibility benefits and costs of control
together, as noted above by weighing the costs in light of the
predicted visibility improvement. We have addressed this issue in a
number of our previous actions since we first discussed this issue in
our Oklahoma FIP,\230\ and our position with regard to the $/deciview
metric was reviewed and upheld in Oklahoma v. EPA, 723 F.3d 1201 by the
Tenth Circuit which ruled:
---------------------------------------------------------------------------
\229\ 70 FR at 39167.
\230\ Response to Technical Comments for Sections E. through H.
of the Federal Register Notice for the Oklahoma Regional Haze and
Visibility Transport Federal Implementation Plan, Docket No. EPA-
R06-OAR-2010-0190, 12/13/2011, pdf 116.
Oklahoma first suggests EPA should not have rejected the
visibility analysis it conducted in the SIP, which used the dollar-
per-deciview method. This argument is misguided. The EPA rejected
the SIP because of the flawed cost estimates. When promulgating its
own implementation plan, it did not need to use the same metric as
Oklahoma. The guidelines merely permit the BART-determining
authority to use dollar per deciview as an optional method of
evaluating cost effectiveness. See 40 CFR pt. 51 app.
Y(IV)(E)(1).\231\ And in the final rule, the EPA
[[Page 66389]]
explained why it did not use the dollar-per-deciview metric used by
Oklahoma. ``Generally speaking, while the metric can be useful if
thoughtfully applied, we view the use of the $/deciview metric as
suggesting a level of precision in the calculation of visibility
impacts that is not justified in many cases.'' 76 Fed. Reg. at
81,747. The EPA has never mandated the use of this metric, and has
not developed ``thresholds of acceptable costs per deciview
improvement.'' Id. While the federal land managers have developed
thresholds, these thresholds were apparently developed without input
from the EPA and without notice-and-comment review. EPA Br. at 54 n.
13. In light of this, we do not find it arbitrary or capricious that
the EPA chose not to use the dollar-per-deciview metric in
evaluating BART options in creating the FIP. We therefore also
conclude that any argument by the petitioners that the dollar-per-
deciview measurement proves the scrubbers are not cost effective
lacks merit. See Pet. Reply Br. at 16.
---------------------------------------------------------------------------
\231\ We note, however, that in both its final rule and in its
brief the EPA asserts that the guidelines require the use of the
dollar-per-ton metric in evaluating cost effectiveness. The
guidelines themselves are a bit unclear. In the section on cost
effectiveness, the guidelines mention only the dollar-per-ton
metric. 40 CFR pt. 51 app. Y(IV)(D)(4)(c). However, the guidelines
later state that in evaluating alternatives, ``we recommend you
develop a chart (or charts) displaying for each of the
alternatives'' that includes, among other factors, the cost of
compliance defined as ``compliance--total annualized costs ($), cost
effectiveness ($/ton), and incremental cost effectiveness ($/ton),
and/or any other cost-effectiveness measures (such as $/deciview).''
Id. app.Y(IV)(E)(1) (emphasis added).
We see no reason to deviate from our view of the $/deciview metric
here.
J. Modeling
1. Cumulative Visibility Impairment
Comment: Several commenters opposed the use of a ``cumulative
deciviews'' or ``total'' visibility improvement metric and claim the
``cumulative deciviews'' metric has no basis in the CAA and EPA's
regulations. It also allegedly mischaracterizes visibility improvements
in Class I areas. Determinations instead should be based on the
predicted visibility improvements at individual Class I areas.
Furthermore, the cumulative metric is deceptive and provides no
information that could be used to assess whether any single Class I
area would experience perceivable visibility improvements as a result
of BART or reasonable progress controls, and may mask the fact that no
individual Class I area would experience any discernible visibility
improvement from control of emissions at any particular source. The
cumulative metric represents an illusory visibility benefit; it is an
improvement that cannot be perceived and therefore provides no
indication of whether the proposed controls will contribute to the goal
of the regional haze program: To reduce human perception of visibility
impairment in Class I areas. The only purpose of the cumulative
visibility improvement indicator is to imply that facilities are having
a large impact across numerous Class I areas, but this indicator can be
deceptive if it includes imperceptible visibility improvements for some
Class I areas.
The commenters also suggest that the use of a ``total dv'' metric
is inconsistent with BART guidelines (40 CFR part 51 Appendix Y,
IV.D.5) that state it is appropriate to model impacts at the nearest
Class I area as well as other nearby Class I areas to determine where
the impacts are greatest. Modeling at other Class I areas may be
unwarranted if the highest modeled effects are observed at the nearest
Class I area. The commenters claim the analysis should be focused on
the visibility impacts at the most impacted area, not all areas. Other
commenters supported the use of the cumulative visibility metric,
stating that it is appropriate and lawful, and within the spirit of the
statutory mandate and expressly permissible within the regulation to
consider cumulative impacts.
Response: We agree with the comments supporting the consideration
of cumulative visibility impacts and benefits. We disagree with the
other commenters that cumulative improvement over multiple areas is an
inappropriate metric, or that examining a single Class I area is
sufficient. The cumulative improvement metric (i.e., the simple sum of
impacts or improvements over all the affected Class I areas) is not
intended to correspond to a single human's perception at a given time
and place. The approach is simply one way of assessing improvements at
multiple areas, for consideration along with other visibility metrics.
Another approach would be to simply list visibility improvements at the
various areas, and qualitatively weigh the number of areas and the
magnitudes of the improvements. The cumulative sum is simply an easily
understood and objective way of weighing cumulative visibility
improvement, as part of the overall control evaluation along with the
visibility improvement at each impacted Class I area. As noted by some
comments, we have calculated cumulative visibility in a number of
Regional Haze actions evaluating the benefits of controls under BART
and when visibility is considered in the reasonable progress analysis.
Furthermore, the FLMs have provided comments in support of the use of
this metric in past actions.\232\
---------------------------------------------------------------------------
\232\ For example, see 76 FR 52388, 52429 (August 22, 2011).
---------------------------------------------------------------------------
The comment opposing cumulative modeling does not provide the full
context when citing to the BART guidelines. The portion referred to by
the commenter discusses the development of a modeling protocol and
establishing the receptors to model. The full portion of the BART
Guidelines that the commenter referenced states:
The receptors that you use should be located in the nearest
Class I area with sufficient density to identify the likely
visibility effects of the source. For other Class I areas in
relatively close proximity to a BART-eligible source, you may model
a few strategic receptors to determine whether effects at those
areas may be greater than at the nearest Class I area. For example,
you might chose to locate receptors at these areas at the closest
point to the source, at the highest and lowest elevation in the
Class I area, at the IMPROVE monitor, and at the approximate
expected plume release height. If the highest modeled effects are
observed at the nearest Class I area, you may choose not to analyze
the other Class I areas any further as additional analyses might be
unwarranted.\233\
---------------------------------------------------------------------------
\233\ 40 CFR 51 Appendix Y, IV.D.5.
This section of the BART Guidelines addresses how to determine
visibility impacts as part of the BART determination. Several
paragraphs later in the BART Guidelines it states: ``You have
flexibility to assess visibility improvements due to BART controls by
one or more methods. You may consider the frequency, magnitude, and
duration components of impairment,'' emphasizing the flexibility in
method and metrics that exists in assessing the net visibility
improvement.
In fully considering the visibility benefits anticipated from the
use of an available control technology as one of the factors in
selection of BART, it is appropriate to account for visibility benefits
across all affected Class I areas and the BART guidelines provide the
flexibility to do so. One approach as noted above is to qualitatively
consider, for example, the frequency, magnitude, and duration of
impairment at each and all affected Class I areas. Where a source
significantly impacts more than one Class I areas, the cumulative
visibility metric is one way to take magnitude of the impacts of the
source into account.
With respect to our analysis of controls under reasonable progress,
we rely on our Reasonable Progress Guidance.\234\ Our Reasonable
Progress Guidance notes the similarity between some of the reasonable
progress factors and the BART factors contained in Sec.
51.308(e)(1)((ii)(A), and suggests that
[[Page 66390]]
the BART Guidelines be consulted regarding cost, energy and nonair
quality environmental impacts, and remaining useful life. We are
therefore relying on our BART Guidelines for assistance in interpreting
those reasonable progress factors, as applicable.
---------------------------------------------------------------------------
\234\ ``Guidance for Setting Reasonable Progress Goals Under the
Regional Haze Program,'' June 1, 2007.
---------------------------------------------------------------------------
Also, similar to a BART analysis, we are also considering the
projected visibility benefit in our analysis following the BART
guidelines and the use of CALPUFF.\235\ We rely on the BART Guidelines
here and in other actions evaluating reasonable progress controls
because they provide a reasonable and consistent approach regarding
visibility modeling. This includes the flexibility in metrics that
exists in assessing the net visibility improvement, and the use of
cumulative visibility, along with visibility impacts at individual
Class I areas, as one way to take magnitude of the impacts of the
source into account where a source evaluated under reasonable progress
significantly impacts more than one Class I area.
---------------------------------------------------------------------------
\235\ As we explain in our proposed action (80 FR at 18993):
``While visibility is not an explicitly listed factor to consider
when determining whether additional controls are reasonable under
the reasonable progress requirements, the purpose of the four-factor
analysis is to determine what degree of progress toward natural
visibility conditions is reasonable. Therefore, it is appropriate to
consider the projected visibility benefit of the controls when
determining if the controls are needed to make reasonable
progress''. See 79 FR at 74838, 74840, and 74874.
---------------------------------------------------------------------------
For each subject-to-BART source and the source evaluated for
reasonable progress controls, we evaluated the visibility impacts from
the source and benefits of controls at four separate Class I areas. In
addition to providing the visibility impacts and potential benefits at
each Class I area in the proposal, we also summed the impact and
improvement across the four Class I areas. The results show that some
sources significantly impact visibility at more than one Class I area,
emission reductions result in visibility benefits at all impacted class
I areas, and in some situations, the largest visibility benefits from
controls can occur at Class I areas other than the most impacted.
Therefore, consistent with the BART Guidelines, and based upon
these facts, we determined additional analyses were not only warranted
but necessary. The BART Guidelines only indicate that additional
analyses may be unwarranted at other Class I areas, and in no way
exclude such analyses, as the commenter suggests. We concluded that a
quantitative analysis of visibility impacts and benefits at only the
most impacted area would not be sufficient to fully assess the impacts
and benefits of controlling emissions from the sources evaluated for
BART and reasonable progress.
Nothing in the Regional Haze Rule suggests that a state (or EPA in
issuing a FIP) should ignore the full extent of the visibility impacts
and improvements from controls at multiple Class I areas. Given that
the national goal of the program is to improve visibility at all Class
I areas, it would be short-sighted to limit the evaluation of the
visibility benefits of a control to only the most impacted Class I
area. We believe such information is useful in quantifying the overall
benefit of controls. As discussed in our proposal, we evaluated the
statutory factor, visibility benefits anticipated due to controls, at
each Class I area in making BART determinations and considered the
visibility benefits in consideration of controls for reasonable
progress.
2. Imperceptible Visibility Improvement
Comment: EPA must withdraw the proposed FIP because the FIP would
only achieve visibility improvements below one deciview, which is not
discernible to the naked eye. Commenters state that the CAA only
provides EPA with the authority to regulate the ``impairment of
visibility.'' \236\ Visibility extends only to things that humans can
see with their naked eyes.\237\ By extension, EPA only has authority to
regulate the impairments of visibility that are perceptible to the
human eye. Under both the plain language and dictionary definitions of
``visibility,'' the statute does not provide EPA with the authority to
regulate haze below a single deciview, which would be invisible to the
naked eye. Since the Proposed FIP will only achieve visibility
improvements smaller than one deciview, the EPA lacks authority to
revise the RPGs suggested by Arkansas, and it should withdraw the
Proposed FIP.
---------------------------------------------------------------------------
\236\ CAA section 169A (``Congress hereby declares as a national
goal the prevention of any future, and the remedying of any
existing, impairment of visibility in mandatory class I Federal
areas which impairment results from manmade air pollution.)
(emphasis added).
\237\ E.g. Webster's Third New International Dictionary 2557
(1981) (``visible'' means ``capable of being seen''; ``visibility''
means ``the degree or extent to which something is visible . . .
[by] the observer's eye unaided by special optical devices'').
---------------------------------------------------------------------------
Commenters also state that the EPA may not require a source ``to
spend millions of dollars for new technology that will have no
appreciable effect on haze in any Class I area.'' Am. Corn Growers
Ass'n. v. EPA \238\ (vacating EPA's BART determinations because EPA
left open the possibility that it could require a source to install
technologies even when those technologies had no appreciable effect on
visibility). Yet the EPA requires certain stationary sources of immense
value to the State of Arkansas and its citizens to install controls
that will cost billions of dollars in order to achieve imperceptible
visibility improvements.
---------------------------------------------------------------------------
\238\ Am. Corn Growers Ass'n v. EPA, 291 F.3d 1, 7 (D.C. Cir.
2002).
---------------------------------------------------------------------------
Response: We disagree with commenters that the Regional Haze Rule
requires that controls on a source or group of sources result in
perceptible visibility improvement.\239\ We believe, for reasons we
have outlined in our proposal and elsewhere in our response to
comments, that the controls we proposed under our FIP will result in
significant improvements in visibility at a number of Class I areas. In
a situation where the installation of BART may not result in a
perceptible improvement in visibility, the visibility benefit may still
be significant, as explained by the Regional Haze Rule:
---------------------------------------------------------------------------
\239\ It is generally recognized that a change in visibility of
1.0 deciview is humanly perceptible.
Even though the visibility improvement from an individual source
may not be perceptible, it should still be considered in setting
BART because the contribution to haze may be significant relative to
other source contributions in the Class I area. Thus, we disagree
that the degree of improvement should be contingent upon
perceptibility. Failing to consider less-than-perceptible
contributions to visibility impairment would ignore the CAA's intent
to have BART requirements apply to sources that contribute to, as
well as cause, such impairment.\240\
---------------------------------------------------------------------------
\240\ 70 FR 39104, 39129.
Section 169A of the CAA requires that certain major sources that
emit any pollutant which may reasonably be anticipated to cause or
contribute to visibility impairment in Class I Areas install BART. The
following factors must be taken into account in determining BART: The
costs of compliance, the energy and nonair quality environmental
impacts of compliance, any existing pollution control technology in use
at the source, the remaining useful life of the source, and the degree
of improvement in visibility which may reasonably be anticipated to
result from the use of such technology.\241\
---------------------------------------------------------------------------
\241\ CAA section 169A(g)(2).
---------------------------------------------------------------------------
The CAA also requires that in determining reasonable progress there
shall be taken into consideration the costs of compliance, the time
necessary for compliance, the energy and nonair
[[Page 66391]]
quality environmental impacts of compliance, and the remaining useful
life of any existing source subject to such requirements. Our 2007
Reasonable Progress Guidance \242\ notes the similarity between some of
the reasonable progress factors and the BART factors contained in Sec.
51.308(e)(1)(ii)(A), and suggests that the BART Guidelines be consulted
regarding cost, energy and nonair quality environmental impacts, and
remaining useful life. We are therefore relying on our BART Guidelines
for assistance in interpreting those reasonable progress factors, as
applicable, including visibility improvement even though it may not be
perceptible from an individual source. Also, similar to a BART
analysis, we are also considering the projected visibility benefit in
our analysis of reasonable progress controls following the BART
guidelines.\243\ We rely on the BART Guidelines here and in other
actions evaluating reasonable progress controls because they provide a
reasonable and consistent approach regarding visibility modeling.
---------------------------------------------------------------------------
\242\ ``Guidance for Setting Reasonable Progress Goals Under the
Regional Haze Program,'' June 1, 2007.
\243\ As we explain in our proposed action (80 FR at 18993):
``While visibility is not an explicitly listed factor to consider
when determining whether additional controls are reasonable under
the reasonable progress requirements, the purpose of the four-factor
analysis is to determine what degree of progress toward natural
visibility conditions is reasonable. Therefore, it is appropriate to
consider the projected visibility benefit of the controls when
determining if the controls are needed to make reasonable
progress''. See also 79 FR at 74838, 74840, and 74874.
---------------------------------------------------------------------------
We accordingly disagree that selection of control measures under
BART or for reasonable progress should be contingent upon perceptible
visibility improvement. As we stated in our previous rulemaking
addressing the BART determinations in Oklahoma:
Given that sources are subject to BART based on a contribution
threshold of no greater than 0.5 deciviews, it would be inconsistent
to automatically rule out additional controls where the improvement
in visibility may be less than 1.0 deciview or even 0.5 deciviews. A
perceptible visibility improvement is not a requirement of the BART
determination because visibility improvements that are not
perceptible may still be determined to be significant.\244\
---------------------------------------------------------------------------
\244\ 76 FR 81728, 81739.
The Regional Haze Rule provides that BART-eligible sources with a
0.5 dv impact at a Class I area ``contribute'' to visibility impairment
and must be analyzed for BART controls. BART determining authorities,
however, are free to establish thresholds less than 0.5 dv.
Consequently, even though the visibility improvement from controlling
an individual source may not be perceptible, it should still be
considered because the contribution to haze may be significant when the
aggregate contribution of other sources in the Class I area is taken
into account and because the contribution to haze from the source may
be significant relative to other source contributions in the Class I
area. Thus, in our visibility improvement analysis for BART sources and
in consideration of visibility benefits from controls under our
reasonable progress analysis, we have not considered perceptibility as
a threshold criterion for considering improvements in visibility to be
meaningful.
We have considered visibility improvement in a holistic manner,
taking into account all reasonably anticipated improvements in
visibility, and the fact that, in the aggregate, improvements from
controls on multiple sources (either under BART or reasonable progress)
will contribute to visibility progress towards the goal of natural
visibility conditions. Visibility impacts below the thresholds of
perceptibility cannot be ignored because regional haze is produced by a
multitude of sources and activities which are located across a broad
geographic area. In this action, we found that the required cost-
effective controls reduce visibility impairment from those BART sources
that contribute or cause visibility impairment at nearby Class I areas
and result in meaningful visibility benefits towards the goal of
natural visibility conditions. Similarly, we also found that the
required cost-effective controls at the Entergy Independence facility
reduce visibility impairment from the source with the largest potential
visibility impacts (among all Non-BART sources) and result in
meaningful visibility benefits towards the goal of natural visibility
conditions.
The commenter mischaracterizes a statement made by the D.C. Circuit
Court of Appeals in Am. Corn Growers Ass'n. v. EPA. The statement made
by the Court is as follows: ``[U]nder EPA's take on the statute, it is
therefore entirely possible that a source may be forced to spend
millions of dollars for new technology that will have no appreciable
effect on the haze in any Class I area.'' \245\ The Court made this
statement in reviewing EPA's approach to the BART requirements in the
Regional Haze Rule promulgated in 1999 which did not require the
source-specific assessment of a BART eligible source's visibility
impacts at any step of the BART process.\246\
---------------------------------------------------------------------------
\245\ Am. Corn Growers Ass'n v. EPA, 291 F.3d 1, 7 (D.C. Cir.
2002).
\246\ Id.
---------------------------------------------------------------------------
The Court disagreed with the approach used by EPA to determine what
BART eligible sources are reasonably anticipated to cause or contribute
to regional haze and therefore subject to BART.\247\ The approach in
the Regional Haze Rule required a State to analyze ``the degree of
visibility improvement that would be achieved in each mandatory Class I
Federal area as a result of the emission reductions achievable from all
sources subject to BART located within the region that contributes to
visibility impairment in the Class I area.'' \248\ The Court held that
the Rule's treatment of ``the degree of improvement in visibility which
may reasonably be anticipated to result from the use of such
technology'' factor infringed on states' authority with respect to BART
determinations under the Act.\249\ The Court noted that the Act does
not assign a specific weight with which to consider each factor, it
solely mandates that all the factors be considered in making a BART
determination.\250\ The Court's issue was not with the weight, or lack
thereof, placed on this factor by EPA. It found issue with what it
considered to be ``dramatically'' different treatment of the visibility
factor by EPA. Id. While the court in American Corn Growers Ass'n. v.
EPA found that we had impermissibly constrained State authority, it did
so because it found that we forced States to require BART controls
without first assessing a source's particular contribution to
visibility impairment. This is not the case with our action in
Arkansas. In response to this court decision and to address these
concerns we finalized revised Regional Haze Regulations and Guidelines
for Best Available Retrofit Technology (BART) Determinations.\251\
---------------------------------------------------------------------------
\247\ Id. at 7-8.
\248\ 40 CFR 51.308(e)(1)(ii)(B).
\249\ Id.
\250\ 291 F.3d at 6.
\251\ 70 FR 39104.
---------------------------------------------------------------------------
Our analysis does not give greater weight to one factor over
another; rather, we considered all five BART factors fully, revealing
that the cost and visibility factors were the two most important
factors in our decisions. In American Corn Growers Ass'n. v. EPA, the
D.C. Circuit Court faulted how EPA assessed the statutory fifth factor
of visibility improvement in a BART determination by using a regional,
multi-source, group approach to assessing the visibility improvement
factor, while assessing the other four
[[Page 66392]]
statutory BART factors on a source-specific basis. Here, we did not
give greater weight to our consideration of visibility improvement or
consider the visibility in a different fashion from the other factors.
All BART factors were evaluated on a source-specific basis.
The Court also noted that it is the State's and not EPA's duty to
determine what BART is (provided that the State's determination
complies with the Act and EPA guidelines.\252\). When EPA promulgates a
FIP, it is acting in the place of the State, and thus has the same
authority a state has when the state promulgates a SIP. It is therefore
our duty to determine what BART is since we are proposing a FIP for
Arkansas. We must also consider the same factors that the State is
mandated to consider by the CAA. The ``degree of improvement in
visibility which may reasonably be anticipated to result from the use
of such [best available retrofit] technology'' is just one of several
factors the State, or EPA in the case of a FIP, must consider in
determining what BART is for a specific source.
---------------------------------------------------------------------------
\252\ 291 F. 3d at 8-9.
---------------------------------------------------------------------------
We also disagree with commenter's statement that we required
emissions reductions just for the sake of doing so under the guise of
imperceptible visibility improvements or solely for the sake of
reducing emissions. As discussed above, we considered all the statutory
factors, including the ``degree of improvement in visibility which may
reasonably be anticipated to result from the use of such [best
available retrofit] technology'' in our BART determinations. We do not
consider perceptibility as a threshold criterion for considering
improvements in visibility to be meaningful. Failing to consider less-
than-perceptible contributions to visibility impairment would ignore
the CAA's intent to have BART requirements apply to sources that
contribute to, as well as cause, such impairment.
Comment: One commenter stated that the visibility benefits of some
of the required controls either individually or in combination will
result in perceptible visibility benefits. They also comment that the
regional haze regulations reflect EPA's finding that the Congressional
goal of eliminating haze can be achieved only by tackling the multitude
of sources that contribute to haze in national parks and wilderness
areas. For this reason, EPA has stated that ``visibility improvement
does not need to be perceptible to be deemed significant for BART
purposes.'' \253\
---------------------------------------------------------------------------
\253\ 79 FR 5032, 5120 (January 30, 2014).
---------------------------------------------------------------------------
Response: We agree with the commenter. As we discuss in response to
comments above, the Regional Haze Rule does not require that controls
on a source or group of sources result in perceptible visibility
improvement. We also agree that in some cases required controls either
individually or in combination with other required controls will result
in perceptible visibility improvements at impacted Class I areas on
some days.
3. Model Selection
Comment: CALPUFF modeling cannot be used to justify controls at
Independence under the reasonable progress requirements. Using CALPUFF,
a single source model, for evaluating the reasonable progress benefits
of installing controls at Independence is misplaced and clearly in
error. EPA must demonstrate that additional controls are rational and
economically justifiable and that the amount of progress that would
result will be ``reasonable based upon the statutory factors.'' CALPUFF
is overly simplistic and greatly overstates the effect of single source
emissions.\254\ CALPUFF also fails to show the effects of multiple
sources, and is much less sophisticated in its treatment of the
chemical interactions of the different pollutants in the atmosphere
than CAMx. The commenters also state that the use of CALPUFF does not
reflect the interaction of pollutants in the atmosphere as accurately
as CAMx does.
---------------------------------------------------------------------------
\254\ BART Guidelines, 70 FR 39104, 39121 (``there are other
features of our recommended modeling approach that are likely to
overstate the actual visibility effects of an individual source.
Most important, the simplified chemistry in the model tends to
magnify the actual visibility effects of that source.'')
---------------------------------------------------------------------------
EPA used CALPUFF and did not perform refined, multi-state modeling
to determine the amount of visibility improvements that would be
achieved through the installation of controls because it would be
difficult, time-consuming, and expensive. Instead, the Agency took a
``thumbnail'' approach in an attempt to justify the proposed controls
based on how long it would take to achieve background levels.
EPA recognized in their action on Texas regional haze that CAMx, a
photochemical transport 3-dimensional grid model, is a more appropriate
modeling tool for reasonable progress purposes.\255\ BART analyses
assess the impact of a single facility based on the maximum or 98th
percentile impacts, regardless of whether the Class I area was actually
experiencing high visibility impairment on any given day. Since CALPUFF
does not conduct an analysis considering all the emissions from all
potential sources, some of the days with the worst model-predicted
concentrations could be days that are not significantly impaired.
Reasonable progress modeling using a photochemical model, such as CAMx,
allows EPA to evaluate impacts from a source (with all other sources
included in the modeling) on a Class I area's best and worst days.\256\
---------------------------------------------------------------------------
\255\ Proposed Texas Regional Haze FIP, 79 FR 74818, 74877,
74878.
\256\ Id. at 74878.
---------------------------------------------------------------------------
The draft EPA Modeling Guidance for Demonstrating Attainment of Air
Quality Goals for Ozone, PM2.5, and Regional Haze (Dec. 2014) (``Draft
Modeling Guidance'') discusses the use of photochemical grid models.
The Draft Modeling Guidance specifically notes that ``a modeling based
demonstration of the impacts of an emissions control scenario . . . as
part of a regional haze assessment usually necessitates the application
of a chemical transport grid model.'' \257\ Throughout the Draft
Modeling Guidance, the discussion is focused on items specific to
photochemical grid models such as CAMx, including emissions
inventories, supporting models, pre-processors, and applying a model to
changes in visibility.
---------------------------------------------------------------------------
\257\ Draft Modeling Guidance at 22. The Draft Modeling Guidance
is available at http://www.epa.gov/scram001/guidance/guide/Draft_O3-PMRH_Modeling_Guidance-2014.pdf.
---------------------------------------------------------------------------
Notably, EPA recently issued a proposal, which would remove CALPUFF
from EPA's preferred list of air dispersion models in its Guideline on
Air Quality Models \258\ (``Guideline''). Although EPA states that the
proposed changes to the Guideline would not affect its recommendation
that CALPUFF be used in the BART determination process, EPA made no
such assurances regarding the use of CALPUFF for a reasonable progress
analysis. EPA's proposal emphasizes the use of chemical transport
models for assessing visibility impacts from a single source or small
group of sources.
---------------------------------------------------------------------------
\258\ Appendix W to 40 CFR part 51.
---------------------------------------------------------------------------
EPA's Interagency Workgroup on Air Quality Modeling Phase 3 Summary
Report: Long Range Transport and Air Quality Related Values \259\ makes
clear that CALPUFF should not be used for a reasonable progress
analysis.
---------------------------------------------------------------------------
\259\ Docket ID EPA-HQ-OAR-2015-0310-0004.
---------------------------------------------------------------------------
Another commenter, EarthJustice, states that the other commenter's
assessment of the methodology used for Texas sources is incorrect. In
fact, EPA also used an emission ``scaling'' approach to determine the
effects of various control scenarios for their evaluation of Texas
sources that is
[[Page 66393]]
similar to that currently being applied for the evaluation of the
sources in Arkansas. EPA Region 6 did not run the CAMx model repeatedly
to determine the overall visibility effects of controlling individual
sources.
Response: The commenters confuse the single source analysis for
evaluating the visibility impact and benefits of controls on units at
the Independence facility and the analysis to estimate the visibility
benefits of all controls on the 20% worst days in establishing a new
reasonable progress goal for 2018. We utilized CALPUFF modeling
following the same modeling protocol relied on for the BART analyses to
assess the visibility impacts and potential benefits of controls for
the units at the Independence facility. For estimating the total
visibility benefit from all controls and estimating a new reasonable
progress goal that reflects those controls, we relied on the CENRAP's
2018 CAMx modeling results, including source apportionment results, and
the projected emission inventories, and scaled the results as described
in the TSD. While we acknowledge that this approach is not as refined
an estimate as would be attained in performing a new photochemical
modeling run, it is based on scaling of earlier photochemical modeling
results and not on CALPUFF modeling, as the commenter suggests. We
disagree with the commenter's characterization of our analysis as a
``thumbnail'' approach and noted in our proposal that similar
approaches have been used in other actions in Hawaii and Arizona. As
discussed in the proposed action, our determination that controls were
reasonable for the Independence units was based on our evaluation of
the four factors and including consideration of the visibility benefit
of controls. For consideration of the visibility benefits, we relied on
the results of our CALPUFF modeling, the CENRAP CAMx source
apportionment results, and point source emission inventory data that
initially identified the Independence facility as having the greatest
potential to impact visibility at nearby Class I areas among all
sources not already controlled under the BART requirements.
The 2005 BART Guidelines recommended the use of CALPUFF for
assessing visibility (secondary chemical impacts) but noted that
CALPUFF's chemistry was fairly simple. The visibility results from
CALPUFF could be used as one of the five factors in a BART evaluation
and the impacts should be utilized in a somewhat relative sense because
CALPUFF was not explicitly approved for full chemistry
calculations.\260\ The BART guidelines also provided the option to
potentially use photochemical grid models (such as CAMx) in the future
if modeling tools available were appropriate and EPA approved of the
technical approaches and how the model would be utilized.\261\ Appendix
W gives us discretionary authority in the selection of what models to
use for visibility assessments with modeling systems, and models such
as CALPUFF, CMAQ, REMSAD, and CAMx have all been used for that purpose.
Specifically for single-source reasonable progress assessments similar
to that done here for Independence, CALPUFF has been used for the
majority of sources, while CAMx has been used in some situations, most
notably and as noted by the commenter, in evaluating specific Texas
sources for reasonable progress. In 2006/7, EPA OAQPS and EPA Region 6
consulted with FLM representatives and approved Texas' BART screening
modeling protocol using source apportionment tools in CAMx.\262\
---------------------------------------------------------------------------
\260\ 70 FR 39104, 39123, 39124. ``We understand the concerns of
commenters that the chemistry modules of the CALPUFF model are less
advanced than some of the more recent atmospheric chemistry
simulations. To date, no other modeling applications with updated
chemistry have been approved by EPA to estimate single source
pollutant concentrations from long range transport.'' and in
discussion of using other models with more advanced chemistry it
continues, ``A discussion of the use of alternative models is given
in the Guideline on Air Quality in appendix W, section 3.2.''
\261\ 70 FR at 39123, 39124. ``The use of other models and
techniques to estimate if a source causes or contributes to
visibility impairment may be considered by the State, and the BART
guidelines preserve a State's ability to use other models. Regional
scale photochemical grid models may have merit, but such models have
been designed to assess cumulative impacts, not impacts from
individual sources. Such models are very resource intensive and time
consuming relative to CALPUFF, but States may consider their use for
SIP development in the future as they are adapted and demonstrated
to be appropriate for single source applications.''
\262\ See Appendix 9-4: CAMx Modeling Protocol, Screening
Analysis of Potentially BART-Eligible Sources in Texas of the Texas
regional haze SIP.
---------------------------------------------------------------------------
Under the BART guidelines, CALPUFF should be used as a screening
tool and appropriate consultation with the reviewing authority is
required to use CALPUFF in a BART determination as part of a SIP or
FIP. The BART Guideline cited and referred to EPA's Guideline on Air
Quality Models (Appendix W) \263\ which includes provisions to obtain
approval through consultation with the reviewing authority. Moreover,
we also note that in EPA's document entitled Guidance on the Use of
Models and Other Analyses for Demonstrating Attainment of Air Quality
Goals for Ozone, PM2.5, and Regional Haze (EPA-454/B-07-
002), that Appendix W does not identify a particular modeling system as
`preferred' for modeling conducted in support of state implementation
plans under 40 CFR 51.308(b). A model should meet several general
criteria for it to be a candidate for consideration. These general
criteria are consistent with the requirements of 40 CFR 51.112 and 40
CFR 51, Appendix W. Therefore, it is correct to interpret that no model
system is considered `preferred' under 40 CFR 51, Appendix W, Section
3.1.1 (b) for either secondary particulate matter or for visibility
assessments. Under this general framework, we followed the general
recommendation in Appendix Y to use CALPUFF as a screening technique
since the modeling system has not been specifically approved for
chemistry. The use of CALPUFF is subject to Appendix W requirements in
section 3.0(b), 4, and 6.2.1(e) which includes an approved protocol to
use the current version.
---------------------------------------------------------------------------
\263\ 40 CFR part 51 Appendix W, Guideline on Air Quality
Models, 70 FR 68218 (November 9, 2005).
---------------------------------------------------------------------------
We and some states have used CALPUFF to model visibility benefits
as part of the reasonable progress analysis, and have used largely the
same methodology as in BART modeling (i.e. use of 24 hour or hourly
maximum emissions, a ``clean'' background condition, and a maximum or
98th percentile metric).\264\ This approach provides information on the
relative visibility benefits of controls to inform the evaluation of
cost-effectiveness as part of the four factor analysis and has the
benefit that it is immediately comparable to modeling used for BART
determinations. Compared to a CAMx modeling exercise, CALPUFF modeling
of one or more sources requires much less resources and time. However,
the CALPUFF approach models the impacts from the single facility with
limited chemistry and focuses on the maximum impacts from the source
rather than the visibility impairment on the 20% worst days. We agree
with the commenter that the CAMx model may be better suited for
evaluating the average visibility impairment due to individual sources
during the 20% worst days as part of reasonable progress analysis.
Photochemical models, like the CAMx model, provide a complete
representation of emissions, chemistry, transport, and deposition,
while CALPUFF treats a single source with simplified chemistry and
parameterized physical processes. Furthermore, the
[[Page 66394]]
CAMx model can be used to evaluate a large number of individual
sources, and there are concerns in using CALPUFF for modeling impacts
at distances much greater than 300 km from the source. In our analysis
of source-specific impacts of Texas sources, we determined that CAMx
was best suited for the complex analysis that we needed to perform in
evaluating a large number of sources (38 separate facilities for our
initial analysis) at distances from impacted Class I areas much larger
than 300km, and in focusing on the 20% worst days. We discuss our
selection of CAMx modeling in our Texas analysis in depth in the RTC
document that accompanies that action.\265\ As noted by EarthJustice,
we did not perform a final CAMx model scenario to obtain the new RPGs
in our Texas action, and instead relied on a scaling analysis similar
to the methodology used in this action to adjust the CENRAP modeled RPG
values based on the source apportionment data and emissions data
available. As discussed above, RPGs were adjusted in actions in
Arizona, Hawaii, Texas/Oklahoma and in this action by estimating the
visibility improvement due to required controls based on scaling the
anticipated emission reductions and the source apportionment modeling.
In Texas/Oklahoma, source-specific source apportionment data and
emissions were utilized. In the other states, emissions and source-
apportionment data on a state and source category level were utilized.
---------------------------------------------------------------------------
\264\ For example see summary of the reasonable progress
analyses for specific sources in Arizona (79 FR 9353), North Dakota
(76 FR 58631), Montana (77 FR 24065), and Wyoming (78 FR 34785).
\265\ Texas Regional Haze FIP, EPA Response to Comments
Document, available at www.regulations.gov, Document ID: EPA-R06-
OAR-2014-0754-0087.
---------------------------------------------------------------------------
Consistent with the examples discussed above,\266\ in evaluating
the sources in Arkansas, we determined that CALPUFF was adequate since
we determined that only one source needed to be assessed for a
reasonable progress evaluation, and that source was well within the
recommended range for CALPUFF modeling of under 300km from the Class I
areas of interest. In fact, three of the four impacted Class I areas
lie within 200km of the source. We discuss comments concerning why our
reasonable progress screening analysis focused on NOX and
SO2 emissions from Arkansas point sources and our
determination that additional analysis was necessary for the
Independence facility in response to comments elsewhere in this
document. In evaluating visibility impacts and benefits for those
sources subject to BART, we relied on CALPUFF modeling prepared by the
facilities. Utilizing CALPUFF for the reasonable progress analysis on
Independence provided for a consistent approach for all facilities and
allowed for direct comparison of the visibility impacts and benefits
across all facilities impacted by the proposed rulemaking. In some
situations, the CALPUFF modeled maximum or 98th percentile impacts of
the facility may not coincide with the days that make up the worst 20%
monitored days at the Class I area. Therefore, the visibility benefits
modeled by CALPUFF are not directly comparable to the visibility
benefits that would be anticipated on the 20% worst days from those
specific controls. However, our analysis of the CENRAP 2018 CAMx
photochemical modeling showed that: On the 20% worst days, Arkansas
point sources contribute significantly to visibility impairment at
Arkansas' Class I areas (greater than 4% of total visibility impairment
at each Arkansas Class I area); review of the emission inventory
revealed that a very small number of point sources are responsible for
the majority of the point source emissions of NOX and
SO2 and therefore a very small number of point sources are
responsible for the portion of visibility impairment due to Arkansas
point sources on the 20% worst days; and the Independence facility is
one of the very largest emission sources and it is located relatively
close (under 200 km) to three Class I areas. Therefore, we identified
Independence as having the greatest potential to impact visibility on
the 20% worst days based on emissions and location and should be
evaluated for reasonable progress controls. We determined that CALPUFF
modeling was appropriate and sufficient to provide information on the
degree of visibility benefits of controls on Independence to inform the
reasonable progress assessment. Through our evaluation of the four
statutory factors, we identified cost-effective controls. We then
considered visibility benefits of the cost-effective controls. We
conducted CALPUFF modeling to determine the level of visibility impacts
and benefits anticipated by SO2 and NOX controls
at nearby impacted Class I areas, evaluating the 98th percentile
visibility impacts.\267\
---------------------------------------------------------------------------
\266\ For example see summary of the reasonable progress
analyses for specific sources in Arizona (79 FR 9321, 9353), North
Dakota (76 FR 58570, 58631 (September 21, 2011)), Montana (77 FR
23988, 24065 (April 20, 2012)), and Wyoming (78 FR 34738, 34785
(June 10, 2013)).
\267\ See Summary of Additional Modeling for Entergy
Independence and Appendix C to the TSD.
---------------------------------------------------------------------------
As we discuss elsewhere in this final rule, Entergy submitted CAMx
model results as part of their comments. The modeled contribution to
visibility impairment due to baseline emissions from the Independence
facility alone were approximately 1.3% of the total visibility
impairment at each Arkansas Class I area. In terms of deciviews, the
average impact over the 20% worst days based on Entergy's CAMx modeling
(adjusting to natural background conditions) is over 0.5 dv at the
Arkansas Class I areas and even larger at the Class I areas in
Missouri. These results estimate the visibility impacts from the source
on the 20% worst days and confirm and provide additional support to our
determination that Independence significantly impacts visibility, both
in terms of maximum visibility impairment and visibility impairment on
the 20% worst days, and that emissions controls provide for meaningful
visibility benefits towards the goal of natural visibility conditions.
In conclusion, both approaches, CALPUFF and CAMx, support the
determination that the required controls are reasonable.
The commenter cites the BART guidelines and asserts that EPA
recognizes that the CALPUFF model is overly simplistic and overstates
the effect of single-source emissions. This is not an accurate
characterization. EPA recognized the uncertainty in the CALPUFF
modeling results when EPA made the decision, in the final BART
Guidelines, to recommend that the model be used to estimate the 98th
percentile visibility impairment rather than the highest daily impact
value. We made the decision to consider the less conservative 98th
percentile primarily because the chemistry modules in the CALPUFF model
are simplified and likely to provide conservative (higher) results for
peak impacts. Since CALPUFF's simplified chemistry could lead to model
over predictions and thus be conservative, EPA decided to use the less
conservative 98th percentile.\268\ While recognizing the limitations of
the CALPUFF model in the preamble, EPA concluded that, for the specific
purposes of the Regional Haze Rule's BART provisions, CALPUFF is
sufficiently reliable to inform the decision making process.\269\ More
recent evaluations demonstrate that the CALPUFF model can both under-
predict and over-predict visibility impacts. For example, the 2012
ENVIRON report on
[[Page 66395]]
Comparison of Single-Source Air Quality Assessment Techniques for
Ozone, PM2.5, other criteria pollutants and AQRVs found that CALPUFF
predicted highest 24-hr nitrate and sulfate concentrations lower than
those predicted by the CAMx photochemical grid model in some areas
within the modeling domain.\270\ In a presentation for the 2010 annual
Community Modeling and Analysis System conference, Anderson et al.
(2010) \271\ found that the CALPUFF model frequently predicted lower
nitrate concentrations compared to the CAMx photochemical grid model
which has a much more rigorous treatment of photochemical reactions. As
we stated in promulgating the BART Guidelines, we are confident that
CALPUFF distinguishes, comparatively, the relative contributions from
sources such that the differences in source configurations, sizes,
emission rates, and visibility impacts are well-reflected in the model
results.\272\
---------------------------------------------------------------------------
\268\ ``Most important, the simplified chemistry in the model
tends to magnify the actual visibility effects of that source.
Because of these features and the uncertainties associated with the
model, we believe it is appropriate to use the 98th percentile--a
more robust approach that does not give undue weight to the extreme
tail of the distribution.''
\269\ 70 FR at 39123.
\270\ Comparison of Single[hyphen]Source Air Quality Assessment
Techniques for Ozone, PM2.5, other Criteria Pollutants
and AQRVs, ENVIRON, September 2012.
\271\ Anderson, B., K. Baker, R. Morris, C. Emery, A. Hawkins,
E. Snyder ``Proof-of-Concept Evaluation of Use of Photochemical Grid
Model Source Apportionment Techniques for Prevention of Significant
Deterioration of Air Quality Analysis Requirements'' Presentation
for Community Modeling and Analysis System (CMAS) 2010 Annual
Conference, (October 11-15, 2010) can be found at http://www.cmascenter.org/conference/2010/agenda.cfm.
\272\ 70 FR 39104, 39122.
---------------------------------------------------------------------------
With regard to comments concerning the draft EPA modeling Guidance
for Demonstrating Attainment of Air Quality Goals for Ozone, PM2.5, and
Regional Haze (Dec. 2014), the commenter confuses the single-source
analysis to evaluate visibility impacts and benefits of controls on an
individual source with the analysis of overall visibility conditions at
a Class I area due to the complete emission control strategy for all
sources developed under the reasonable progress and long-term strategy
requirements. The draft modeling guidance (as does the current guidance
\273\) discusses the projection of overall visibility conditions and
the need for photochemical grid modeling to account for all emission
sources to model current visibility conditions and project future
visibility conditions in response to the overall emission control
scenarios. The section of the modeling guidance on regional haze \274\
describes the recommended modeling analysis to assess overall future
visibility improvement relative to the uniform rate of progress or
``glidepath'' (for each Class I area) as part of a reasonable progress
analysis, and does not discuss source-specific analyses that may be
completed to inform a reasonable progress assessment.\275\ Because the
CALPUFF model only evaluates visibility impacts from a single-source or
a limited group of sources, it is not capable of projecting overall
visibility conditions due to all sources and controls. Consistent with
this draft guidance and the current guidance, CENRAP and Arkansas
utilized CAMx and CMAQ modeling to project future visibility conditions
for 2018 for establishment of the RPGs and comparison with the URP.
Similarly, we utilized the CENRAP CAMx model results and adjusted them
based on source apportionment and emissions data, to estimate the new
RPGs for the Arkansas Class I areas considering the anticipated changes
in emissions due to all required controls. We discuss the selection of
models for assessing individual visibility impacts and benefits of
controls above.
---------------------------------------------------------------------------
\273\ 2007 EPA modeling Guidance for Demonstrating Attainment of
Air Quality Goals for Ozone, PM2.5, and Regional Haze.
\274\ Draft EPA modeling Guidance for Demonstrating Attainment
of Air Quality Goals for Ozone, PM2.5, and Regional Haze
(December 2014) Section 4.8 ``What Is The Recommended Modeling
Analysis for Regional Haze?''
\275\ Draft EPA modeling Guidance for Demonstrating Attainment
of Air Quality Goals for Ozone, PM2.5, and Regional Haze (December
2014) at 173: ``The modeling can be used to determine the predicted
improvement in visibility and whether the visibility levels are on,
above, or below the glidepath. It cannot by itself determine the
reasonable progress goals or determine whether the reasonable
progress goal is met, and it does not satisfy the requirements for
the statutory four factor analysis. See the Regional Haze Rule and
related guidance documents for more information on the four factor
analysis, including control strategy analysis for single sources.''
---------------------------------------------------------------------------
The commenters cite to the proposed revisions to the Guideline on
Air Quality Models (Appendix W) \276\ and the IWAQM Phase 3 modeling
report \277\ and assert that they support the conclusion that the use
of CALPUFF for Independence was inappropriate. We disagree with the
commenter. As we discuss above, we agree with the commenter that the
CAMx model, may be better suited for a reasonable progress analysis in
certain situations. Proposed revisions to Appendix W discuss removing
the requirement to use CALPUFF for long-range transport assessments and
as a preferred model due to the need to provide flexibility in
estimating single-source secondary pollutant impacts and concerns about
management and maintenance of the CALPUFF modeling code.\278\ These
proposed changes do not affect EPA's recommendation that States use
CALPUFF to determine the applicability and level of BART in regional
haze implementation plans. The proposed changes also do not preclude
the use of CALPUFF for any other non-BART analysis, such as long-range
transport PSD increment assessment, but recognize that modern chemical
transport models have evolved sufficiently and provide a credible
platform for estimating potential visibility impacts from a single or
small group of emission sources.\279\ The proposed Appendix W rule
simply proposes to remove CALPUFF as a preferred model. If the proposed
changes are finalized, CALPUFF or any other model can still be used for
non-BART analyses with the appropriate justification as an
``alternative model''.
---------------------------------------------------------------------------
\276\ 80 FR 45340 (July 29, 2015).
\277\ Interagency Workgroup on Air Quality Modeling Phase 3
Summary Report: Long Range Transport and Air Quality Related Values.
\278\ 80 CFR 45340, 45349: ``In order to provide the user
community flexibility in estimating single-source secondary
pollutant impacts and given the availability of more appropriate
modeling techniques, such as photochemical transport models (which
address limitations of models like CALPUFF [37]), the EPA is
proposing that the Guideline no longer contain language that
requires the use of CALPUFF or another Lagrangian puff model for
long-range transport assessments. Additionally, the EPA is proposing
to remove the CALPUFF modeling system as an EPA-preferred model for
long-range transport due to concerns about the management and
maintenance of the model code given the frequent change in ownership
of the model code since promulgation in the previous version of the
Guideline. [38] The EPA recognizes that long-range transport
assessments may be necessary in certain limited situations for PSD
increment. For these situations, the EPA is proposing a screening
approach where CALPUFF along with other appropriate screening tools
and methods may be used to support long-range transport PSD
increment assessments''
\279\ 80 FR at 45349.
---------------------------------------------------------------------------
The IWAQM Phase 3 modeling report \280\ discusses in detail the
difference between the CALPUFF analysis typically followed under BART
and the use of photochemical grid models for assessing reasonable
progress and overall visibility conditions. The report does not
identify a preferred model for single-source analysis but rather
identifies the difference between the modeling approaches and cautions
that the model results are not directly comparable.\281\ The report
also states
[[Page 66396]]
that puff-models, such as CALPUFF, are not suited for reasonable
progress demonstrations assessing overall visibility conditions and
improvement because they are only able to model a single or small group
of sources. Accordingly, we utilized CAMx model results to project
overall future visibility conditions and establish the new RPGs in our
reasonable progress demonstration. We used CALPUFF visibility modeling
along with our evaluation of the costs of controls to inform our
decision on the reasonableness of controls at the Independence
facility. We also used CALPUFF visibility modeling as only one factor
to inform our decisions on BART for subject-to-BART facilities. We also
note that both the proposed revisions and the IWAQM report were
published after the proposed rule for Arkansas regional haze was
published and well before the technical analysis and modeling were
completed.
---------------------------------------------------------------------------
\280\ Interagency Workgroup on Air Quality Modeling Phase 3
Summary Report: Long Range Transport and Air Quality Related Values
(July 2015).
\281\ IWAQM Phase 3 Report (July 2015) at 9: ``In sum, the
differences in the types of models, the inputs to the models, and
how the models and model results are used means that the results
from a BART determination or similar modeling using CALPUFF cannot
be directly compared to estimated impacts of emissions controls from
a single source on a reasonable progress goal. If recommended
procedures change for either BART determination impact assessments
or reasonable progress goal impact assessments the comparability
between approaches would also change. Photochemical grid models
could be applied to estimate single source impacts and post-
processed in a manner consistent with requirements for a BART-like
assessment but Lagrangian puff models are not ideal for reasonable
progress demonstrations since they typically characterize one or a
small group of sources''
---------------------------------------------------------------------------
We address comments concerning the contribution to visibility
impairment from Arkansas point sources and the benefit of controls on
Independence on Arkansas Class I areas elsewhere. We find that the
contribution to visibility impairment from Arkansas point sources to be
significant and that controls on Independence will result in meaningful
visibility improvements towards the goal of natural visibility
conditions and addresses a significant portion of the visibility
impairment due to Arkansas sources.
Comment: Use of CALPUFF modeling does not support EPA's
determination to require controls at the three coal-fired power plants.
EPA's reliance on CALPUFF modeling results to make regulatory decisions
in this case is not justified due to CALPUFF's well-known
overestimation of visibility impacts.\282\ Under the circumstances
here, it is highly likely that CALPUFF overestimated the visibility
impacts of White Bluff, Flint Creek and Independence by at least five
(5) times. One component of this overestimation is the failure to
incorporate the puff splitting option within the CALPUFF model into the
development of visibility results. CALPUFF's overestimation of
visibility impacts by a factor of 2-10 times under similar
circumstances has been previously identified \283\ and is described
with specific reference to EPA's Proposed FIP for Arkansas in a report
by Dr. Richard T. McNider.\284\ Dr. McNider's report explains that the
CALPUFF protocols used in the Proposed FIP fail to account for several
well-known meteorological phenomena and processes, and causes it to
overestimate visibility impacts. The Hoffnagle report demonstrates that
CALPUFF modeling has not been validated by real world observations and
that the current regulatory version of CALPUFF used by EPA is
outdated.\285\ Consequently, CALPUFF is not ``sufficiently accurate to
make determinations of deciview differences of 1 deciview.'' \286\
---------------------------------------------------------------------------
\282\ Coincidentally, the EPA Administrator on July 14, 2015,
signed a proposed notice to remove CALPUFF as a model for long-range
transport in EPA's Guideline on Air Quality Models in Docket No.
EPA-HQ-OAR-2015-0310.
\283\ See Exhibit 19 to Nucor's comments, Hoffnagle, G.,
``Accuracy of Visibility Protocol Modeling in BART Evaluations''
(June 15, 2012); EPA Docket EPA-R08-OAR-2011-0851.
\284\ See, McNider, R. ``Inadequacy of CALPUFF and CALMET
Protocols for Visibility Impact Analysis in the Arkansas RHR FIP,''
July 13, 2015, attached hereto as Exhibit 20 to Nucor's comments.
\285\ Hoffnagle, Exhibit 19 at p. 4.
\286\ Hoffnagle, Exhibit 19 at p. 23.
---------------------------------------------------------------------------
It is inappropriate to utilize CALPUFF as a screening tool to
qualify a source as subject to BART and subsequently use it to
determine a facility's required implementation of a control technology
at a significant financial cost. EPA in its final regional haze rules
stated that ``because of the scale of the predicted impacts from these
sources, CALPUFF is an appropriate or a reasonable application to
determine whether such a facility can reasonably be anticipated to
cause or contribute to any impairment of visibility. In other words, to
find that a source with a predicted maximum impact greater than 2 to 3
deciviews meets the contribution threshold adopted by the States does
not require the degree of certainty in the results of the model that
might be required for other regulatory purposes.'' \287\
---------------------------------------------------------------------------
\287\ 70 FR 39104, 39123.
---------------------------------------------------------------------------
EPA's visibility analysis in the Proposed FIP systematically
overstates both the baseline visibility impacts of White Bluff, Flint
Creek and Independence, and the visibility benefits that would result
from installation of EPA's required controls.\288\ EPA's Proposed FIP
presumes greater accuracy and precision than is reasonable or that may
be expected from CALPUFF under the circumstances here. EPA has failed
to update its model or to address any of these deficiencies considering
currently available state-of-the-art modeling science. EPA's
consideration of visibility impacts is fundamentally flawed and should
be withdrawn and corrected.
---------------------------------------------------------------------------
\288\ As well as the other sources that were modeled using
CALPUFF.
---------------------------------------------------------------------------
EPA's admission that CALPUFF is a reasonable tool to evaluate a
facility's visibility impacts only if those impacts exceed 2 to 3
deciviews, combined with the inability of the model to make accurate
determinations below the 1 deciview threshold of perceptibility,
discredits the results of the visibility analyses in the Proposed FIP.
For these reasons, EPA has not adequately explained how the baseline
and subsequent controlled visibility analyses in the Proposed FIP
justify the selected control technologies.
Response: In promulgating the 2005 BART guidelines, we responded to
comments concerning the limitations and appropriateness of using
CALPUFF. There we respond:
CALPUFF is the best modeling application available for
predicting a single source's contribution to visibility impairment.
It is the only EPA-approved model for use in estimating single
source pollutant concentrations resulting from the long range
transport of primary pollutants. In addition, it can also be used
for some purposes, such as the visibility assessments addressed in
today's rule, to account for the chemical transformation of
SO2 and NOX. As explained above, simulating
the effect of precursor pollutant emissions on PM2.5
concentrations requires air quality modeling that not only addresses
transport and diffusion, but also chemical transformations. CALPUFF
incorporates algorithms for predicting both. At a minimum, CALPUFF
can be used to estimate the relative impacts of BART-eligible
sources. We are confident that CALPUFF distinguishes, comparatively,
the relative contributions from sources such that the differences in
source configurations, sizes, emission rates, and visibility impacts
are well-reflected in the model results.
The use of CALPUFF in the context of the Regional Haze rule
provides results that can be used in a relative manner and are only one
factor in the overall BART determination. We determined the visibility
results from CALPUFF could be used as one of the five factors in a BART
evaluation and the impacts should be utilized somewhat in a relative
sense because CALPUFF was not explicitly approved for full chemistry
calculations.\289\
---------------------------------------------------------------------------
\289\ 70 FR at 39123, 39124. ``We understand the concerns of
commenters that the chemistry modules of the CALPUFF model are less
advanced than some of the more recent atmospheric chemistry
simulations. To date, no other modeling applications with updated
chemistry have been approved by EPA to estimate single source
pollutant concentrations from long range transport.'' and in
discussion of using other models with more advanced chemistry it
continues, ``A discussion of the use of alternative models is given
in the Guideline on Air Quality in appendix W, section 3.2.''
---------------------------------------------------------------------------
[[Page 66397]]
EPA's modeling in this action was consistent with the BART
Guidelines and Appendix W. In recommending the use of CALPUFF for
assessing source specific visibility impacts, EPA recognized that the
model had certain limitations but concluded that ``[f]or purposes of
the regional haze rule's BART provisions . . . CALPUFF is sufficiently
reliable to inform the decision-making process.'' \290\ To the extent
that the comment takes issue with the provisions in the BART Guidelines
for use of CALPUFF, the legal deadline for challenging the use of
CALPUFF has passed.
---------------------------------------------------------------------------
\290\ 70 FR at 39123.
---------------------------------------------------------------------------
The commenters also refer to the 2005 Rule where we discuss the use
of CALPUFF as a screening tool to qualify a source as subject to BART
\291\ and claim that we state that CALPUFF is only a reasonable tool
when impacts exceed 2 to 3 deciviews. This is incorrect. The commenters
fail to note that later in that same section we also discuss the
recommended use of CALPUFF to evaluate visibility benefits of controls.
There we state:
---------------------------------------------------------------------------
\291\ 70 FR at 39123.
``. . . we also recommend that the States use CALPUFF as a screening
application in estimating the degree of visibility improvement that
may reasonably be expected from controlling a single source in order
to inform the BART determination. As we noted in 2004, this estimate
of visibility improvement does not by itself dictate the level of
control a State would impose on a source; ``the degree of
improvement in visibility which may reasonably be anticipated to
result from the use of [BART]'' is only one of five criteria that
the State must consider together in making a BART determination.''
\292\
---------------------------------------------------------------------------
\292\ 70 FR at 39123.
With respect to our analysis of controls under reasonable progress,
we rely on our Reasonable Progress Guidance.\293\ Our Reasonable
Progress Guidance notes the similarity between some of the reasonable
progress 4 statutory factors and the BART 5 statutory factors contained
in the Act and repeated in the Guidance, and suggests that the BART
Guidelines be consulted regarding cost, energy and nonair quality
environmental impacts, and remaining useful life. We are therefore
relying on our BART Guidelines for assistance in interpreting those
reasonable progress factors, as applicable.
---------------------------------------------------------------------------
\293\ ``Guidance for Setting Reasonable Progress Goals Under the
Regional Haze Program,'' June 1, 2007.
---------------------------------------------------------------------------
Also, similar to a BART analysis, we are considering the projected
visibility benefit in our reasonable progress analysis following the
BART guidelines and the use of CALPUFF.\294\ We rely on the BART
Guidelines here and in other actions evaluating reasonable progress
controls because they provide a reasonable and consistent approach
regarding visibility modeling.
---------------------------------------------------------------------------
\294\ As we explain in our proposed action (80 FR at 18993):
``While visibility is not an explicitly listed factor to consider
when determining whether additional controls are reasonable under
the reasonable progress requirements, the purpose of the four-factor
analysis is to determine what degree of progress toward natural
visibility conditions is reasonable. Therefore, it is appropriate to
consider the projected visibility benefit of the controls when
determining if the controls are needed to make reasonable
progress''. See 79 FR at 74838, 74840, and 74874.
---------------------------------------------------------------------------
We also disagree with the commenters conclusions concerning CALPUFF
model performance and assertions that model predictions are
overestimated by a factor of 5. We note that our regulations do not
allow for the calibration of model results to try to adjust for
potential biases as suggested by the commenter.\295\
---------------------------------------------------------------------------
\295\ App. W, Section 7.2.9(a) ``. . . Therefore, model
calibration is unacceptable.''
---------------------------------------------------------------------------
As discussed more fully in the RTC document, the CALPUFF model can
both under-predict and over-predict visibility impacts. While
recognizing the limitations of the CALPUFF model in the Preamble of the
Regional Haze Rule EPA concluded that, for the specific purposes of the
Regional Haze Rule's BART provisions, CALPUFF is sufficiently reliable
to inform the decision making process.\296\
---------------------------------------------------------------------------
\296\ 70 FR at 39123.
---------------------------------------------------------------------------
We disagree with the commenter's assertion that we were incorrect
in not utilizing the puff-splitting option \297\ and that this resulted
in an overestimation of model results. Tests conducted by the EPA and
the FLM's have shown that the CALPUFF puff-splitting algorithm does not
behave in the manner posited in Dr. McNider's document.\298\ As
discussed in detail in the RTC document, multiple evaluations of puff-
splitting show that visibility impacts (and thus concentrations) both
increased and decreased across various Class I areas impacted by the
source. These results are contrary to the claims of the commenter that
CALPUFF overpredicts downwind concentrations at distances beyond 100 km
and that the use of puff-splitting would result in lower
concentrations. Furthermore, commenters have not provided any
additional CALPUFF modeling to support their claims concerning model
performance using the non-default puff splitting option.
---------------------------------------------------------------------------
\297\ CALPUFF contains an optional puff splitting algorithm that
can further account for vertical wind shear effects across
individual puffs when this is of specific concern. Dispersion and
transport can act on separate puffs generated from the original
puff. This option is not part of the regulatory default set-up.
\298\ See CALPUFF_SJGS_SPLIT_summary.xls.
---------------------------------------------------------------------------
The commenter refers to the Hoffnagle report (Ex. 19 of Nucor
comments) to support claims that the CALPUFF model overpredicts
concentrations, that the model is unreliable beyond 200km, and that the
modeling is not sufficiently accurate to make determinations of
deciview differences of 1 dv. We disagree with the conclusions of the
Hoffnagle report and note significant flaws in that analysis. We also
note that all the large EGU sources modeled in this action are less
than 200 km for at least one Class I area. We specifically address
Hoffnagle's analysis of modeled to measured results in response to
comments elsewhere where we address comments concerning the ``margin of
error'' of the model and case study comparisons of CALPUFF modeled
values to measured values.
We disagree with the commenter that the model we utilized is
outdated. We used the regulatory version of the CALPUFF model.\299\ We
disagree that the newer versions of CALPUFF should be used in this
action to determine potential visibility impacts. The newer version(s)
of CALPUFF have not received the level of review required for use in
regulatory actions subject to EPA approval and consideration in a BART
decision making process. Based on our review of the available evidence
we do not consider these newer versions of CALPUFF to have been shown
to be sufficiently documented, technically valid, and reliable for use
in a BART decision making process.
---------------------------------------------------------------------------
\299\ On December 4, 2013, EPA approved an update to v5.8.4 that
contains bug fixes to the previous version. See December 3, 2013
CALPUFF Update Memo for a discussion of model changes.
---------------------------------------------------------------------------
The commenters also refer to the proposed revisions to the
Guideline on Air Quality Models (Appendix W). Proposed revisions to
Appendix W discuss removing the requirement to use CALPUFF for long-
range transport assessments and as a preferred model due to the need to
provide flexibility in estimating single-source secondary pollutant
impacts and concerns about management and maintenance of the CALPUFF
modeling code.\300\ These
[[Page 66398]]
proposed changes do not affect EPA's recommendation that States use
CALPUFF to determine the applicability and level of BART in regional
haze implementation plans. The proposed changes also do not preclude
the use of CALPUFF for any other non-BART analysis. The proposed
changes to the Appendix W rule simply propose to remove CALPUFF as a
preferred model for long-range transport assessments. If the proposed
changes are finalized, CALPUFF or any other model can still be used
with the appropriate justification as an ``alternative model'' for
long-range transport assessments.
---------------------------------------------------------------------------
\300\ 80 CFR at 45349: ``In order to provide the user community
flexibility in estimating single-source secondary pollutant impacts
and given the availability of more appropriate modeling techniques,
such as photochemical transport models (which address limitations of
models like CALPUFF [37]), the EPA is proposing that the Guideline
no longer contain language that requires the use of CALPUFF or
another Lagrangian puff model for long-range transport assessments.
Additionally, the EPA is proposing to remove the CALPUFF modeling
system as an EPA-preferred model for long-range transport due to
concerns about the management and maintenance of the model code
given the frequent change in ownership of the model code since
promulgation in the previous version of the Guideline. [38] The EPA
recognizes that long-range transport assessments may be necessary in
certain limited situations for PSD increment. For these situations,
the EPA is proposing a screening approach where CALPUFF along with
other appropriate screening tools and methods may be used to support
long-range transport PSD increment assessments.''
---------------------------------------------------------------------------
Finally, the CAMx modeling provided by Entergy Arkansas provides
additional information that directly contradicts the commenter's
assertion that CALPUFF greatly overestimates visibility impacts by at
least a factor of 5. As we discuss elsewhere in this final rule, the
CAMx visibility modeling estimates a maximum visibility impact (limited
to only the days comprising the 20% worst days and based on annual
emissions) of over 1.5 dv from the Independence facility at both Caney
Creek and Upper Buffalo. For the White Bluff facility, the CAMx maximum
visibility impact is approximately 3.5 dv at Caney Creek and 0.8 dv at
Upper Buffalo. In some situations, the CALPUFF modeled maximum or 98th
percentile impacts of the facility may not coincide with the days that
make up the worst 20% monitored days at the Class I area, therefore the
true maximum impact considering all days based on CAMx modeling could
be even higher. This compares to a CALPUFF modeled visibility 98th
percentile impact (based on maximum emissions) due to the Independence
facility of 2.5 dv at Caney Creek and 2.3 at Upper Buffalo. For White
Bluff, the CALPUFF modeled impact (98th percentile) is approximately
3.3 dv at Caney Creek and 2.3 dv at Upper Buffalo.
We address more general comments concerning the use of CALPUFF
modeling and model uncertainty in separate response to comments.
4. Margin of Error in CALPUFF Modeling
Comment: Commenters stated that BART requires that states (or EPA
in the case of a federal implementation plan) consider ``the degree of
improvement in visibility which may reasonably be anticipated to result
from the use of such technology.'' \301\ The Ninth Circuit, in National
Parks Conservation Association v. EPA, Case No. 12-73710, 2015 WL
3559149 at 8 (9th Cir. June 9, 2015), held that the estimated
visibility improvement was less than CALPUFF's margin of error, and
thus, EPA had no basis to believe that BART controls in that case could
``reasonably be anticipated'' to improve visibility. The Clean Air Act
does not require visibility improvements that cannot be reasonable
anticipated. Visibility improvements that are less than the margin of
error are not ``reasonably anticipated'' and found to be invalid by the
Ninth Circuit in National Parks Conservation Association.\302\ In the
proposal, EPA dictates the imposition of control equipment for
emissions reduction under BART in instances where CALPUFF predicted
minor visibility improvements. EPA did so without first undertaking any
site specific analytical analysis to determine if the visibility
improvements were in fact within the CALPUFF margin of error.
---------------------------------------------------------------------------
\301\ CAA section 169A(g)(2).
\302\ 80 FR at 18968.
---------------------------------------------------------------------------
The CAA does not require visibility improvements that cannot be
reasonably anticipated. Conversely, visibility improvements that are
less than the margin of error were expressly found to be invalid. Until
such time as EPA can provide assurance that the CALPUFF model is a
reliable indicator of visibility projections, many of the numerical
projections contained in the Proposed FIP are themselves, unreliable.
For this reason, the Proposed FIP is flawed and is overly expansive and
should be withdrawn.
Response: We disagree with the commenter's characterization of the
Ninth Circuit decision regarding the ``margin of error'' of the CALPUFF
model. The Ninth Circuit decision cited did not rule on any specific
issue related to CALPUFF or the ``margin of error.'' Rather, the court
ruled on a procedural error that EPA did not respond to the comment
received regarding the CALPUFF margin of error in its rulemaking as
required under the law.\303\
---------------------------------------------------------------------------
\303\ ``Concurring, Judge Berzon wrote separately to emphasize
her understanding that the lead opinion is not impugning the EPA's
use of the CALPUFF model generally, but only requiring a
sufficiently reasoned response to a particular comment regarding
CALPUFF's usefulness in these specific circumstances.'' Nat'l Parks
Conservation Ass'n vs. EPA.
---------------------------------------------------------------------------
In response to the court's finding in American Corn Growers Ass'n.
v. EPA \304\ that we failed to provide an option for BART evaluations
on an individual source-by-source basis, we had to identify the
appropriate analytical tools to estimate single-source visibility
impacts. The 2005 BART Guidelines recommended the use of CALPUFF for
assessing visibility (secondary chemical impacts) but noted that
CALPUFF's chemistry was fairly simple and the model has not been fully
tested for secondary formation and thus is not fully approved for
secondary-formed particulate. In the preamble of the final 2005 BART
guidelines we identify CALPUFF as the best available tool for analyzing
the visibility effects of individual sources, but we also recognized
that it is a model that includes certain assumptions and
uncertainties.\305\ Evaluation of CALPUFF model performance for
dispersion (no chemistry) to case studies using inert tracers has been
performed.\306\ It was concluded from these case studies the CALPUFF
dispersion model had performed in a reasonable manner, and had no
apparent bias toward over or under prediction, so long as the transport
distance was limited to less than 300km.307 308
---------------------------------------------------------------------------
\304\ Am. Corn Growers Ass'n v. EPA, 291 F.3d 1 (D.C. Cir.
2002).
\305\ 70 FR at 39121.
\306\ See ``more recent series of comparisons has been completed
for a new model, CALPUFF (Section A.3). Several of these field
studies involved three-to-four hour releases of tracer gas sampled
along arcs of receptors at distances greater than 50km downwind. In
some cases, short-term concentration sampling was available, such
that the transport of the tracer puff as it passed the arc could be
monitored. Differences on the order of 10 to 20 degrees were found
between the location of the simulated and observed center of mass of
the tracer puff. Most of the simulated centerline concentration
maxima along each arc were within a factor of two of those
observed.'' 68 FR 18440, 18458 (April 15, 2003), 2003 Revisions to
Appendix W, Guideline on Air Quality Models
\307\ Interagency Workgroup on Air Quality Modeling (IWAQM)
Phase 2 Summary Report and Recommendations for Modeling Long-Range
Transport Impacts. Publication No. EPA-454/R-98-019. Office of Air
Quality Planning & Standards, Research Triangle Park, NC. 1998.
\308\ 68 FR 18440, 18458, 2003 Revisions to Appendix W,
Guideline on Air Quality Models.
---------------------------------------------------------------------------
In promulgating the 2005 BART guidelines, we responded to comments
concerning the limitations and
[[Page 66399]]
---------------------------------------------------------------------------
appropriateness of using CALPUFF. There we respond:
CALPUFF is the best modeling application available for
predicting a single source's contribution to visibility impairment.
It is the only EPA-approved model for use in estimating single
source pollutant concentrations resulting from the long range
transport of primary pollutants. In addition, it can also be used
for some purposes, such as the visibility assessments addressed in
today's rule, to account for the chemical transformation of
SO2 and NOX. As explained above, simulating
the effect of precursor pollutant emissions on PM2.5
concentrations requires air quality modeling that not only addresses
transport and diffusion, but also chemical transformations. CALPUFF
incorporates algorithms for predicting both. At a minimum, CALPUFF
can be used to estimate the relative impacts of BART-eligible
sources. We are confident that CALPUFF distinguishes, comparatively,
the relative contributions from sources such that the differences in
source configurations, sizes, emission rates, and visibility impacts
are well-reflected in the model results.
In the 2003 revisions to the Guideline on Air Quality Models,
CALPUFF was added as an approved model for long-range transport of
primary pollutants. At that time, we considered approving CALPUFF for
assessing the impact from secondary pollutants but determined that it
was not appropriate in the context of a PSD review because the impact
results could be used as the sole determinant in denying a permit.\309\
However, the use of CALPUFF in the context of the Regional Haze rule
provides results that can be used in a relative manner and are only one
factor in the overall BART determination. We determined the visibility
results from CALPUFF could be used as one of the five factors in a BART
evaluation and the impacts should be utilized somewhat in a relative
sense because CALPUFF was not explicitly approved for full chemistry
calculations.\310\
---------------------------------------------------------------------------
\309\ 68 FR 18440.
\310\ 70 FR at 39123, 39124. ``We understand the concerns of
commenters that the chemistry modules of the CALPUFF model are less
advanced than some of the more recent atmospheric chemistry
simulations. To date, no other modeling applications with updated
chemistry have been approved by EPA to estimate single source
pollutant concentrations from long range transport,'' and in
discussion of using other models with more advanced chemistry it
continues, ``A discussion of the use of alternative models is given
in the Guideline on Air Quality in appendix W, section 3.2.''
---------------------------------------------------------------------------
We also recognized the uncertainty in the CALPUFF modeling results
when we made the decision, in the final BART Guidelines, to recommend
that the model be used to estimate the 98th percentile visibility
impairment rather than the highest daily impact value. We made the
decision to consider the less conservative 98th percentile primarily
because the chemistry modules in the CALPUFF model are simplified and
likely to provide conservative (higher) results for peak impacts. Since
CALPUFF's simplified chemistry could lead to model over predictions and
thus be conservative, EPA decided to use the less conservative 98th
percentile.\311\ Examining the distribution of CALPUFF modeled
visibility impacts, it can be seen that the few values at the extreme
of the distribution are much higher than the rest of the values.\312\
Therefore, in recognizing some of the limitations of the CALPUFF model,
we determined that use of the maximum modeled impact may be overly
conservative and recommended the use of the 98th percentile value.
---------------------------------------------------------------------------
\311\ ``Most important, the simplified chemistry in the model
tends to magnify the actual visibility effects of that source.
Because of these features and the uncertainties associated with the
model, we believe it is appropriate to use the 98th percentile--a
more robust approach that does not give undue weight to the extreme
tail of the distribution.'' 70 FR 39104, 39121.
\312\ See figures for Lake Catherine and Domtar in our response
to comments on the ``Margin of Error'' analysis in the RTC document
---------------------------------------------------------------------------
We disagree with the commenter's general statement that there is an
acknowledged over-prediction of the CALPUFF model or an acknowledged
inaccuracy at low levels, and that the actual visibility impacts from
the BART sources are lower. The CALPUFF model can both under-predict
and over-predict visibility impacts when compared to photochemical grid
model. For example, the 2012 ENVIRON report on Comparison of Single-
Source Air Quality Assessment Techniques for Ozone, PM2.5, other
criteria pollutants and AQRVs found that CALPUFF predicted highest 24-
hr nitrate and sulfate concentrations lower than those predicted by the
CAMx photochemical grid model in some areas within the modeling
domain.\313\ In a presentation for the 2010 annual Community Modeling
and Analysis System conference, Anderson et al. (2010) \314\ found that
the CALPUFF model frequently predicted lower nitrate concentrations
compared to the CAMx photochemical grid model, which has a much more
rigorous treatment of photochemical reactions. As discussed above,
model evaluations examining how the model captures the transport and
diffusion of pollutants showed that the model performed in a reasonable
manner for modelled distances less than 300 km.\315\ The selection of
the 98th percentile value rather than the maximum value was made to
address concerns that the maximum may be overly conservative.
---------------------------------------------------------------------------
\313\ Comparison of Single[hyphen]Source Air Quality Assessment
Techniques for Ozone, PM2.5, other Criteria Pollutants
and AQRVs, ENVIRON, September 2012.
\314\ Anderson, B., K. Baker, R. Morris, C. Emery, A. Hawkins,
E. Snyder ``Proof-of-Concept Evaluation of Use of Photochemical Grid
Model Source Apportionment Techniques for Prevention of Significant
Deterioration of Air Quality Analysis Requirements'' Presentation
for Community Modeling and Analysis System (CMAS) 2010 Annual
Conference, (October 11-15, 2010) can be found at http://www.cmascenter.org/conference/2010/agenda.cfm.
\315\ 68 FR at 18458, 2003 Revisions to Appendix W, Guideline on
Air Quality Models.
---------------------------------------------------------------------------
The CALPUFF modeling following the BART guidelines and using the
98th percentile value does not lend itself to model performance
evaluations of the type suggested by the commenters (see comments below
concerning the ``Margin of error'' analysis), comparing measured
visibility impairment at a specific time and place to modeled
impairment at that same time and place to derive some ``margin of
error'' in the modeled estimates. The BART modeling is a worst case
assessment, utilizing maximum emissions,\316\ assumptions of background
ammonia and ozone, and simplified chemistry, modeled over a period of
three years.\317\ The modeling also does not capture the effect of
competition with other emission sources for the available ammonia. The
goal of this modeling is to estimate the maximum anticipated impact
from the source in the vicinity of a Class I area (typically an area on
the order of several hundred square miles or more), and not to provide
an estimate of downwind concentrations or visibility conditions for a
specific place at a specific time.
---------------------------------------------------------------------------
\316\ 70 FR at 39129, ``We believe the maximum 24hour modeled
impact can be an appropriate measure in determining the degree of
visibility improvement expected from BART reductions (or for BART
applicability)''
\317\ 70 FR 39104, 39107-3918 of BART Rule. For assessing the
fifth factor, the degree of improvement in visibility from various
BART control options, the States may run CALPUFF or another
appropriate dispersion model to predict visibility impacts.
Scenarios would be run for the pre-controlled and post-controlled
emission rates for each of the BART control options under review.
The maximum 24-hour emission rates would be modeled for a period of
three or five years of meteorological data.
---------------------------------------------------------------------------
CALPUFF uses a pseudo-first-order chemical reaction mechanism to
model the conversion of SO2 to SO4 and
NOX (NO + NO2) to NO3. We find the
representation of key chemical conversions of precursors to
PM2.5 in CALPUFF are appropriate for estimating a worst-case
scenario for this particular source and region. We note that small
changes in emission levels will not significantly perturb the available
ammonia. Therefore, the relative difference between two scenarios with
similar emissions will not be overly
[[Page 66400]]
influenced by assumptions of background concentrations of ammonia.
The utility of the model used must be judged based on the available
data, the known limitations or simplifications inherent to the model,
and the purpose of the modeling or manner in which the model results
are used in informing decisions. The use of the 98th percentile value
and considering a minimum of three years of meteorological data within
CALPUFF provides a snapshot of the worst case visibility impacts,
simulating impacts (based on maximum emissions and assumed ammonia
concentrations) on a day when modeled meteorological conditions are
most conducive to formation and transport of visibility impairing
pollutants to a receptor within a Class I area. While there is some
uncertainty in the absolute visibility impacts and benefits due to the
model and some of the simplifications and assumptions used in the BART
guideline modeling approach, the relative level of impact is a reliable
assessment of the degree of visibility impacts and benefit from
controls. Any uncertainties in meteorological conditions that govern
the transport and diffusion of pollutants are less important in
comparing impacts between two control scenarios, since the same effects
will be included in both the base and the control scenario model
simulations. CALPUFF modeling will be better at predicting changes in
visibility impairment due to the application of controls than at
predicting the absolute visibility impacts. BART determinations are
only made for sources that have already been shown to reasonably be
anticipated to cause or contribute to any visibility impairment in a
Class I area. Modeling of control scenarios is used to estimate the
amount that this visibility impact can be reduced due to a reduction in
emissions. The modeling of these control scenarios is done in a manner
that holds all variables constant except for the emissions of the
pollutant of interest. A relative reduction in visibility impact due to
a change in emissions is an indication that visibility benefits are
reasonably anticipated to occur. The modeled magnitude of the
visibility improvement is not a determinative factor in the BART
determination, but only one factor and is considered on a relative
basis to the baseline impact and the benefits of other controls. The
relative visibility benefit of all controls is weighed along with the
absolute and relative costs of controls, energy and nonair
environmental impacts, any existing controls, and the remaining useful
life of the source. As stated above, we are confident that CALPUFF
distinguishes, comparatively, the relative contributions from sources
such that the differences in source configurations, sizes, emission
rates, and visibility impacts are well-reflected in the model results.
CALPUFF visibility modeling, performed using the regulatory CALPUFF
model version and following all applicable guidance and EPA/FLM
recommendations, provides a consistent tool for comparison with the 0.5
dv subject-to-BART threshold. The CALPUFF model, as recommended in the
BART guidelines, has been used for almost every single-source BART
analysis in the country and has provided a consistent basis for
assessing the degree of visibility benefit anticipated from controls as
one of the factors under consideration in a five-factor BART analysis.
Since almost all states have completed their BART analyses and have
either approved SIPs or FIPs in place, there is a large set of
available data on modeled visibility impacts and benefits, and how
those model results were utilized to screen out sources and as part of
the five-factor analysis in making BART control determinations for
comparison with.
Comment: Trinity Consultants completed a quantitative analysis to
evaluate the margin of error in the CALPUFF model for Lake Catherine
Unit 4 and Domtar Ashdown Mill.\318\ Trinity calculated the average
difference between modeled values obtained using CALPUFF (including the
CENRAP background) and IMPROVE monitored values for Caney Creek and
Upper Buffalo. Trinity compared the regional haze design value format
of average W20 days visibility for this analysis.
---------------------------------------------------------------------------
\318\ ``Evaluation of the CALPUFF Modeling System Margin of
Error Report for BART Analysis, Domtar A. W. LLC, Ashdown Mill''
Prepared by Trinity Consultants, August 2015 and ``Evaluation of the
CALPUFF Modeling System Margin of Error Report for BART Analysis,
Entergy Arkansas, Inc., Lake Catherine Plant'' Prepared by Trinity
Consultants, August 2015.
---------------------------------------------------------------------------
In its analysis, the pre-BART impact from Lake Catherine Unit 4 at
Caney Creek and Upper Buffalo is inconsequential when compared with the
IMPROVE measurements, which capture the impact of all other sources,
including Lake Catherine, on the Class I areas.
The proposed NOX BART controls for Lake Catherine Unit 4
will result in visibility improvements that are even more
inconsequential and cannot accurately be predicted by CALPUFF. Based on
Trinity's analysis, the minimum calculated margin of error for CALPUFF
for Lake Catherine Unit 4 is 0.93 dv. The CALPUFF modeling predicted
visibility improvement associated with EPA's proposed BART controls for
Lake Catherine Unit 4 at Caney Creek and Upper Buffalo falls within the
minimum calculated margin of error for CALPUFF for Lake Catherine Unit
4. Similarly, the predicted visibility improvements associated with the
imposition of the proposed BART requirements for Power Boiler 2 at the
Domtar Ashdown Mill fall within the CALPUFF model's margin of error. As
such, the visibility improvements at each of these Class I areas
associated with the proposed BART controls cannot ``reasonably be
anticipated.'' \319\ Accordingly, EPA has not adequately demonstrated
that it is appropriate to require controls on Lake Catherine Unit 4 or
Power Boiler 2 at the Domtar Ashdown Mill.
---------------------------------------------------------------------------
\319\ CAA section 169A(g)(2); see NPCA, 788 F.3d 1134, 1146-47.
---------------------------------------------------------------------------
These analyses include a discussion of work performed by TRC
Environmental Corporation, including a June 2012 paper prepared by Gale
Hoffnagle that discusses several case studies that compared CALPUFF
modeled values to measured values from the IMPROVE monitoring
network.\320\ The commenters state that PPL Montana relied on this
study in its successful challenge to the Montana FIP for its argument
that EPA failed to explain why it could reasonably anticipate a
visibility improvement when the improvement was within CALPUFF's margin
of error.\321\
---------------------------------------------------------------------------
\320\ Gale F. Hoffnagle, Accuracy of Visibility Protocol
Modeling in BART Evaluations, TRC Environmental Corporation, June
15, 2012.
\321\ National Parks Conservation Ass'n v. EPA, 788 F.3d 1134,
1146-47 (9th Cir. 2015).
---------------------------------------------------------------------------
Response: The commenters mischaracterize the Ninth Circuit decision
regarding the ``margin of error'' of the model. The commenter suggests
that the Court agreed that the anticipated visibility benefits in that
case were within the margin of error of the model. This is incorrect.
The Ninth Circuit decision cited did not rule on any specific issue
related to CALPUFF. Rather, the court ruled on a procedural error that
EPA did not respond to the comment received regarding the CALPUFF
margin of error in its rulemaking as required under the law.\322\ Here
and elsewhere in our response to comments we address a very similar
comment with respect to
[[Page 66401]]
CALPUFF modeling for Arkansas sources, as well as the commenter's
analysis claiming to estimate the ``margin of error''.
---------------------------------------------------------------------------
\322\ ``Concurring, Judge Berzon wrote separately to emphasize
her understanding that the lead opinion is not impugning the EPA's
use of the CALPUFF model generally, but only requiring a
sufficiently reasoned response to a particular comment regarding
CALPUFF's usefulness in these specific circumstances.'' Nat'l Parks
Conservation Ass'n vs. EPA.
---------------------------------------------------------------------------
The Trinity analysis \323\ purports to calculate a ``margin of
error'' of the CALPUFF modeling for Lake Catherine. In general, the
commenter's analysis adds CALPUFF model results for a specific source
or sources with CAMx model results and compares this value to
visibility conditions derived from monitored data at each Class I area.
This analysis is flawed for many reasons as discussed in detail in our
RTC document and fails to provide any assessment of the ability of the
CALPUFF model to evaluate the degree of visibility improvement that may
be expected from available control technology to inform BART and
reasonable progress evaluations. Whether or not the modeled visibility
impacts or benefits lie below this calculated ``margin of error'' is
immaterial to any assessment of whether or not the visibility
impairment or benefits from controls can reasonably be anticipated to
occur. BART determinations are only made for sources that have already
been shown to reasonably be anticipated to cause or contribute to any
visibility impairment in a Class I area. Modeling of control scenarios
is used to estimate the amount that this visibility impact can be
reduced due to a reduction in emissions. The modeling of these control
scenarios is done in a manner that holds all variables constant except
for the emissions of the pollutant of interest. A relative reduction in
visibility impact due to a change in emissions is an indication that
visibility benefits are reasonably anticipated to occur. The modeled
magnitude of the visibility improvement is not the determinative factor
in the BART determination, but only one factor and is considered on a
relative basis to the baseline impact and the benefits of other
controls. The relative visibility benefit of all controls is weighed
along with the absolute and relative costs of controls, energy and
nonair environmental impacts, any existing controls, and the remaining
useful life of the source. As discussed elsewhere in this section of
the final rule, we are confident that CALPUFF distinguishes,
comparatively, the relative contributions from sources such that the
differences in source configurations, sizes, emission rates, and
visibility impacts are well-reflected in the model results.
---------------------------------------------------------------------------
\323\ Evaluation of the CALPUFF Modeling System Margin of Error
for a BART Analysis, Entergy Services, Inc.--Lake Catherine Plant,
available as Exhibit H to comments submitted by Entergy Arkansas,
Inc.
---------------------------------------------------------------------------
We respond to specific comments concerning each separate case study
in our RTC document.
5. Reasonable Progress Analysis for Entergy Independence
Comment: Entergy contracted with Trinity to perform regional haze
modeling using CAMx and PSAT based on the modeling originally developed
for CENRAP. This modeling was performed to assess the proposed control
options for Independence units 1 and 2, as well as White Bluff units 1
and 2. In addition to the baseline scenario modeling, the FIP scenario
(proposed controls in EPA's FIP) and Entergy's proposed control
approach consisting of installed LNB/SOFA on Independence, and the
cessation of coal combustion at White Bluff were modeled.
Entergy stated that EPA's own analysis counsels against imposing
emission limits on Independence. EPA asserts that CENRAP modeling shows
that sulfate from all point sources included in the regional modeling
is projected to contribute to 57% of the total light extinction at
Caney Creek on the W20 days in 2018 and 43% of the total light
extinction at Upper Buffalo.\324\ However, EPA recognizes that the
CENRAP modeling also demonstrates that sulfate from all (elevated and
low level) Arkansas point sources is projected to be responsible for
only 3.58% of the total light extinction at Caney Creek and 3.20% at
Upper Buffalo.\325\ The contribution of Arkansas point sources' nitrate
emissions to visibility impairment at Arkansas' Class I areas is even
more insignificant. According to EPA's analysis, nitrate from all point
sources included in the regional modeling is projected to account for
only 3% of the total light extinction at the Caney Creek and Upper
Buffalo Class I areas, with nitrate from Arkansas point sources being
responsible for only 0.29% of the total light extinction at Caney Creek
and 0.25% at Upper Buffalo.\326\ The Independence units' share of
emissions to this minimal contribution from Arkansas point sources to
visibility impairment at Caney Creek and Upper Buffalo is even less.
---------------------------------------------------------------------------
\324\ 80 FR 18944, 18990.
\325\ Id.
\326\ Id.
---------------------------------------------------------------------------
Entergy's CAMx modeling confirms that Independence's contribution
to visibility impairment is insignificant in both Class I areas.
Independence is projected to contribute to only 0.119 dv of visibility
impairment at Caney Creek and Upper Buffalo on W20 days in 2018.\327\
This reflects only one half of one percent of the visibility
impairment, based on modeling, on the W20 days in either Caney Creek or
Upper Buffalo. Yet, based on such a miniscule contribution and with no
credible explanation, EPA arbitrarily concludes that SO2 and
NOX controls at Independence are warranted.
---------------------------------------------------------------------------
\327\ See Figures 9 and 10 of Entergy Arkansas Inc. Comments On
the Proposed Regional Haze and Interstate Visibility Transport
Federal Implementation Plan for Arkansas available in the docket for
this action.
---------------------------------------------------------------------------
Response: We disagree with the commenter's assertion that the
contribution to visibility impairment from Entergy Independence is
``insignificant'' or ``minimal.'' For example, as the commenter states,
the CENRAP source apportionment data show that sulfate from Arkansas
point sources are projected to be responsible for 3.58% of the total
light extinction at Caney Creek and 3.20% at Upper Buffalo in 2018. As
we discuss in our proposal, based on 2011 NEI data, the Entergy
Independence Plant is the second largest source of both SO2
and NOX point source emissions in Arkansas, accounting for
approximately 36% of the SO2 point-source emissions and 21%
of the point source NOX emissions in the State.\328\
Therefore, a significant portion of the total visibility impairment on
the 20% worst days, on the order of 1% or more, can be expected to be
attributable to SO2 emissions from a single facility, the
Independence facility. As we discuss in more detail elsewhere, given
their contribution to visibility impairment on the 20% worst days, we
consider both SO2 and NOX to be key pollutants
contributing to visibility impairment at Arkansas' Class I areas. Our
CALPUFF modeling evaluating the baseline 98th percentile impacts
confirmed that the Independence facility was estimated to impact
visibility at levels much larger than the level considered to ``cause''
visibility impairment (greater than 1 dv) at nearby Class I areas,
ranging from 2.512 dv at Caney Creek, to 1.859 dv at Mingo. CALPUFF
modeling also showed that anticipated visibility benefits from
SO2 and NOX controls at the facility exceeded 1
dv at each of the four impacted Class I areas. Although we recognize
that Independence is not a subject to BART source, for comparison
purposes we note that the threshold used for visibility impacts to
[[Page 66402]]
determine whether facilities are subject to BART is 0.5 dv.\329\
---------------------------------------------------------------------------
\328\ 80 FR at 18991.
\329\ ``As a general matter, any threshold that you use for
determining whether a source ``contributes'' to visibility
impairment should not be higher than 0.5 deciviews.'' BART
Guidelines, App. Y to 40 CFR 51.
---------------------------------------------------------------------------
We disagree with the commenter that the CAMx modeling submitted by
the commenter confirms that contributions to visibility impairment from
the Independence facility are insignificant. When properly assessed, as
detailed in the RTC document, the commenter's CAMx modeling supports
and reinforces our finding that visibility impairment from Entergy
Independence is significant and emission reductions will result in
meaningful visibility benefits towards the goal of natural visibility
conditions. Entergy's CAMx modeling shows a visibility impact of 0.12
dv at both Caney Creek and Upper Buffalo when compared to 2018
``dirty'' or ``degraded'' background conditions. The commenter then
calculates that this 0.12 dv impact is 0.5% of the total 23 dv
visibility impairment. As discussed in the RTC document, the deciview
scale is a logarithmic function of extinction, and therefore the
calculations by the commenter are incorrect because they are based on
deciview values and must be performed based on light extinction to
properly calculate the percent contribution to visibility impairment.
Spreadsheets submitted by the commenter present the light extinction
attributable to each source (in inverse megameters) based on the
results of their CAMx source apportionment modeling and calculate the
percent contribution to total visibility impairment at each Class I
area.\330\ The commenter is incorrect in its statement that the impact
from the Independence facility is one half of one percent; it is in
fact, based on their own modeling and calculation, approximately 1.3%
of the total visibility impairment at each Arkansas Class I area.
Considering that the CAMx photochemical modeling takes into account the
emissions of thousands of sources, both in Arkansas and outside of the
state, we consider this to be a significant contribution to visibility
impairment at each Class I area and a large portion (approximately one-
third) of the total contribution from all Arkansas point sources that
can be addressed through installation of controls on two units at a
single facility. The CAMx modeling also showed that at Upper Buffalo,
the Independence facility's contribution to visibility impairment is
greater than the contribution from all of the subject-to-BART sources
addressed in this final action combined.
---------------------------------------------------------------------------
\330\ See ``Entergy Scenario 01 Contribution 2015-
1124_FINAL.xlsx,'' ``Avg_Impacts'' tab, column ``AA'' for Caney
Creek and Upper Buffalo Class I areas. We summarize these results in
the RTC document.
---------------------------------------------------------------------------
Furthermore, the deciview visibility impacts for individual sources
should be assessed based on natural ``clean'' background visibility
conditions. The deciview improvement based on the 2018 background
conditions provides an estimate of the amount of benefit that can be
anticipated in 2018 and the impact a control/emission reduction may
have on the established RPG for 2018. However, this estimate based on
degraded or ``dirty'' background conditions underestimates the
visibility improvement that would be realized for the control options
under consideration. The source impacts and the potential benefits of
controls must be considered relative to a light extinction level that
represents a clean/natural background, rather than the current
visibility conditions or projected visibility conditions at the end of
the planning period.\331\ The need for consideration of visibility
impacts and benefits relative to clean/natural conditions was explained
in the preamble to the final BART Guidelines:
---------------------------------------------------------------------------
\331\ This recommended approach to the treatment of background
air quality when quantifying source impacts and potential benefits
from additional measures is different than the approach to
background air quality when projecting how all emission reductions
measures combined will determine visibility conditions at the end of
the implementation period, i.e., how background assumptions relate
to the RPGs. It is not appropriate to consider only the amount by
which a potential measure or combination of measures would change
the projected overall deciview index value as of the end of the
implementation period, i.e., the degree by which the RPGs would
differ with and without the control being included in the LTS. The
RPGs are values that will be compared in a progress report to actual
visibility conditions, and accordingly must represent the expected
actual overall visibility conditions. Estimates of source impacts
and measure benefits have a different purpose, which is to help
guide decisions on the control of individual sources.
Using existing conditions as the baseline for single source
visibility impact determinations would create the following paradox:
The dirtier the existing air, the less likely it would be that any
control is required. This is true because of the nonlinear nature of
visibility impairment. In other words, as a Class I area becomes
more polluted, any individual source's contribution to changes in
impairment becomes geometrically less. Therefore the more polluted
the Class I area would become, the less control would seem to be
needed from an individual source. . . . Such a reading would render
the visibility provisions meaningless, as EPA and the States would
be prevented from assuring ``reasonable progress'' and fulfilling
the statutorily-defined goals of the visibility program. Conversely,
measuring improvement against clean conditions would ensure
reasonable progress toward those clean conditions.\332\
---------------------------------------------------------------------------
\332\ 70 FR at 39124.
The same logic applies to the evaluation of visibility impacts and
benefits for sources examined for controls for reasonable progress.
Accordingly, the EPA has used clean background conditions in evaluating
the benefits of controls on individual reasonable progress sources and
has disapproved reasonable progress decisions by states that relied on
modeling employing dirty background conditions.\333\ This approach has
been upheld by the Eighth Circuit.\334\
---------------------------------------------------------------------------
\333\ The EPA has followed this logic in the North Dakota (77 FR
20894, April 6, 2012), Montana (77 FR 57864, September 18, 2012),
Arizona (79 FR 52420, September 3, 2014), and Texas (81 FR 296,
January 5, 2016) FIPs and partial disapprovals of North Dakota (77
FR 20894, April 6, 2012) and Texas (81 FR 296, January 5, 2016).
\334\ North Dakota v. EPA, 730 F.3d 750, 764-766 (8th Cir.
2013). ``Although the State was free to employ its own visibility
model and to consider visibility improvement in its reasonable
progress determinations, it was not free to do so in a manner that
was inconsistent with the CAA. Because the goal of Sec. 169A is to
attain natural visibility conditions in mandatory Class I Federal
areas, see CAA section 169A(a)(1), and EPA has demonstrated that the
visibility model used by the State would serve instead to maintain
current degraded conditions, we cannot say that EPA acted in a
manner that was arbitrary, capricious, or an abuse of discretion by
disapproving the State's reasonable progress determination based
upon its cumulative source visibility modeling.''
---------------------------------------------------------------------------
We note that while CALPUFF results are not directly comparable to
CAMx model results due to differences in metrics, models and model
inputs,\335\ CALPUFF visibility impacts are also calculated based on
natural or ``clean'' background conditions.
---------------------------------------------------------------------------
\335\ Some of the major differences are: (1) CALPUFF uses
maximum 24-hour emission rates, while CAMx uses annual average
emission rates; (2) CALPUFF focuses on the day with the 98th
percentile highest visibility impact from the source being
evaluated, whereas CAMx focuses on the average visibility impacts
across the 20% worst days regardless of whether the impacts from a
specific facility are large or small; and (3) CAMx models all
sources of emissions in the modeling domain, which includes all of
the continental U.S., whereas CALPUFF only models the impact of
emissions from one facility without explicit chemical interaction
with other sources' emissions.
---------------------------------------------------------------------------
We recalculated the average modeled visibility impact for the 20%
worst days based on the commenter's CAMx modeled average visibility
impact for the 20% worst days using a clean background approach (using
annual average natural conditions background).\336\ The Independence
facility (units 1 and 2 combined) has impacts greater than 0.5 dv at
both
[[Page 66403]]
Caney Creek and Upper Buffalo on average across the 20% worst days on a
``clean'' background basis based on CAMx modeling submitted by the
commenter.\337\ These CAMx model results for the average across the 20%
worst days show that the Independence facility contributes
significantly to visibility impairment on the 20% worst days and
controls will result in meaningful visibility benefit towards the goal
of natural visibility conditions. Furthermore, the maximum visibility
impact on an individual day within the subset of days that make up the
20% worst days are much larger. Facility-wide visibility impacts from
Independence exceed 1 dv at each Arkansas Class I area. We note that in
some situations, the days that CALPUFF model maximum or 98th percentile
value impacts of the facility occur may not coincide with any of the
days that make up the days in the worst 20% days at the Class I area
and the visibility impacts modeled by CALPUFF are not directly
comparable to the visibility benefits that would be anticipated on the
20% worst days. See our complete RTC document for additional
information on calculated visibility impacts from the Entergy
facilities based on the commenter's CAMx modeling results.
---------------------------------------------------------------------------
\336\ Deciview impacts are calculated using the following
equation: [Delta]dv = 10 ln((bbackground+
bsource)/bbackground), where b is extinction
(Mm-1) and [Delta]dv is the delta-deciview visibility
impact.
\337\ See ``Entergy Arkansas CAMx--EPA calcs max and clean
background.xlsx,'' available in the docket for this action.
---------------------------------------------------------------------------
Comment: The level of improvement expected from EPA's proposed
controls for Independence is virtually insignificant and does not
justify the costs of controls. The BART-type evaluation for
NOX for the Independence Power Plant Units 1 and 2 would
result in visibility improvements ranging from 0.148 to 0.459 dv with a
cumulative improvement of 0.978 dv. EPA recognized that these
improvements were relatively small and proposed an option (Option 2)
that did not include the LNB/SOFA NOX controls for Units 1
and 2. EPA, however, did not recognize that the Independence facility
is subject to CSAPR and that NOX reductions ``better than
BART'' would already be achieved by participation in that program
without specifically requiring the LNB/SOFA in the FIP.
For SO2 emissions for Independence Units 1 and 2, EPA
estimated improvements with dry FGD ranging from 1.045 to 1.178 dv with
a cumulative benefit of 4.375 dv. Three of the four class I areas would
realize visibility improvements barely discernible to the human eye
(<1.1 dv). The best improvement is for Upper Buffalo and is only 1.178
dv. It is not appropriate to use the cumulative values as a
representation of the visibility benefit of adding controls since only
the improvement at each particular Class I area could actually be
recognized. This level of visibility improvement is virtually
insignificant and does not justify the costs associated with adding a
dry FGD and, therefore, does not meet the statutory RPG requirement for
proper consideration of the cost of controls and so is not
``reasonable.''
Response: We disagree with the commenter and do not believe that
visibility improvements from NOX controls ranging from 0.128
to 0.459 dv are relatively small. Given that sources are subject to
BART based on a contribution threshold of no greater than 0.5
deciviews, it would be inconsistent to consider an improvement in
visibility of nearly 0.5 dv to be insignificant or small for reasonable
progress. In our proposed action, we noted that ``The single source
CALPUFF modeling shows that sizeable reductions to the maximum 98th
percentile visibility impact from the Independence facility may be
achieved through NOX controls.'' \338\ Furthermore, total
modeled extinction at Caney Creek is dominated by nitrate on 4 of the
days that comprise the 20% worst days in 2002, and a significant
portion of the total extinction at Upper Buffalo on 2 of the days that
comprise the 20% worst days in 2002 is due to nitrate.\339\ Both
NOX and SO2 are key pollutants that contribute to
visibility impairment at the Arkansas Class I areas. Because we have
identified these two pollutants as key, we are obligated to determine
which sources or source categories are responsible for emitting these
pollutants and evaluate them for reasonable progress. Independence is
the second largest point source of both SO2 and
NOX in the State.\340\ Therefore, we evaluated it for
reasonable progress controls for both pollutants. We recognized,
however, that at this time, even though NOX emissions are a
key pollutant, point source NOX emissions are not the main
contributors to visibility impairment on the average of the 20% worst
days at Arkansas' Class I areas in 2018, as projected by CAMx source
apportionment modeling.'' \341\ Even though we recognized that
NOX emissions are a key pollutant to reaching the regional
haze goals, and that the visibility benefits from NOX
controls were sizeable, we took comment on two options because the
visibility impairment due to Arkansas point source emissions on the
average of the 20% worst days were primarily due to sulfate emissions.
We also found that significant reductions could be achieved very cost
effectively through the implementation of low NOX burners.
In our final action, we have determined that it is appropriate to
require the NOX controls as proposed under Option 1 because
the goal of the long-term strategy and reasonable progress requirements
is to improve visibility and make progress towards natural conditions
and NOX is a key pollutant impacting visibility at the
Arkansas Class I areas. We used a shorthand term, ``driver,'' in our
proposal discussing SO2, and did not mean to imply that
NOX was not also a key pollutant. While point source
NOX emissions are not the primary contributor to impairment
on most of the 20% worst days, NOX is a key contributor to
visibility on other days of the year and on some days that make up the
20% worst days (in 2002, IMPROVE monitor data shows that two days that
make up the 20% worst days at Upper Buffalo and three days at Caney
Creek are more significantly impacted by nitrate than sulfate). So in
considering reasonable progress factors, we have determined that
because NOX and SO2 are both key visibility
impairing pollutants, for Independence there are technically feasible
and cost effective controls available for both SO2 and
NOX and those controls will provide significant visibility
improvement. Therefore, both SO2 and NOX controls
are reasonable and necessary to eventually achieve the national goal.
We have determined that it is appropriate to reduce NOX
emissions and finalize Option 1. As to the comment that we did not
recognize ``better than BART'' coverage due to CSAPR, we address this
comment elsewhere in a separate response to comment.
---------------------------------------------------------------------------
\338\ 80 FR at 18995.
\339\ See Arkansas Regional Haze SIP, Appendix 8.1-- ``Technical
Support Document for CENRAP Emissions and Air Quality Modeling to
Support Regional Haze State Implementation Plans,'' section 3.7.1
and 3.7.2. See the docket for this rulemaking for a copy of the
Arkansas Regional Haze SIP.
\340\ See 80 FR at 18991, Table 59.
\341\ 80 FR at 18995.
---------------------------------------------------------------------------
With respect to the anticipated visibility improvement due to
SO2 controls, we consider visibility benefits ranging from
1.045 to 1.178 dv at each Class I area to be significant. We note that
the Regional Haze Rule provides that sources with a 0.5 dv impact at a
Class I area ``contribute'' to visibility impairment and must be
analyzed for BART controls, and that source with a 1.0 dv impact at a
Class I area to ``cause'' visibility impairment. Given
[[Page 66404]]
that sources are subject to BART based on a contribution threshold of
no greater than 0.5 deciviews and visibility impacts greater than 1.0
deciview are considered a level to be ``causing'' visibility
impairment, it would be inconsistent to consider a potential
improvement in visibility of greater than twice the BART threshold to
be insignificant.
Furthermore, as discussed elsewhere throughout this final rule,
results of Entergy Arkansas' CAMx modeling with source apportionment
provide additional support that the Independence facility has
significant impacts on visibility at nearby Class I areas on the 20%
worst days and that controlling these units would result in significant
visibility benefits towards the goal of natural visibility conditions.
We address comments concerning the consideration of cumulative
visibility benefits and imperceptible visibility benefits elsewhere.
Comment: EPA's CALPUFF modeling indicates that the SO2
and NOX emission limits proposed for Independence will
result in a 1.952 dv improvement in Caney Creek and a 1.782 dv
improvement in Upper Buffalo. However, this range is vastly overstated.
Based on the current monitored visibility levels in Caney Creek and
Upper Buffalo, the W20 days show that the visibility impairment in 2018
will be approximately 23 to 24 dv. EPA recognizes that sulfate from all
of Arkansas' point sources are projected to be responsible for only
about 3.6% of total light extinction at Arkansas' Class I areas based
on CENRAP modeling.\342\ This means that sulfate from all Arkansas
point sources are projected to be responsible for only about 0.81-0.86
dv of impairment (23-24 dv x 3.6%). For nitrates, EPA projects that
Arkansas point source emissions will account for, at most, 0.29% of the
total light extinction at Arkansas' Class I areas. Independence's
SO2 and NOX emissions contribute only a portion
to the sulfate and nitrate percentages estimated from Arkansas point
sources. It would, therefore, be impossible for the SO2 and
NOX limits proposed for Independence to result in deciview
improvements at Caney Creek and Upper Buffalo of 1.952 dv and 1.782 dv,
respectively. This simple example demonstrates the obvious flaw in
EPA's use of CALPUFF for its reasonable progress analysis and, thus,
its justification for imposing emission limits on Independence despite
the fact that the Class I areas are below the URP.
---------------------------------------------------------------------------
\342\ 80 FR at 18990.
---------------------------------------------------------------------------
Based on CALPUFF modeling, EPA's proposed BART limits will result
in projected combined visibility benefits of approximately 4.3 dv at
Caney Creek. Based on Entergy's statistical projection of the haze
index in Caney Creek, that would result in a haze index of 15.76 dv,
which would put Caney Creek closer to natural background levels than
the glide path. The URP would not reach that haze level until
approximately 2048.\343\ Indeed, even if you ascribed the CALPUFF-
projected benefits to Caney Creek based on the recent IMPROVE levels
(approximately 22 dv between 2009 and 2012), the projected haze index
would drop to 17.7 dv, which indicates no further action should be
needed to remain below the URP until approximately 2038.
---------------------------------------------------------------------------
\343\ The projected haze index at Upper Buffalo of 18.05 dv
would keep Upper Buffalo below the glide path until approximately
2038--the end of the third planning period.
---------------------------------------------------------------------------
If EPA insists on relying on CALPUFF to evaluate the projected
visibility benefits of requiring controls on Independence, it must be
consistent and use CALPUFF to evaluate the need for such controls for
purposes of demonstrating reasonable progress. As demonstrated in
Figures 11 and 12, controls at Independence cannot be justified for
reasonable progress based on the CALPUFF results, which predict an
improvement of several deciviews solely from BART controls.
Response: As more fully explained above and in the RTC Document,
the commenter's analysis fails to account for the fact that deciviews
are a logarithmic function of extinction, that CALPUFF results are for
the maximum impact (98th percentile impact from each source) in
contrast to the CENRAP projected visibility conditions that are for the
average visibility over the 20% worst days, and also fails to
differentiate between deciview values calculated based on natural
background conditions (as the CALPUFF results are) and the deciview
values relative to a degraded or dirty background.
First, the commenter incorrectly estimates that the impact from
sulfate point source emissions in Arkansas is 0.81-0.86 dv. Because the
deciview metric is a logarithmic function of extinction, the percent
extinction cannot be directly applied to the total deciview impairment.
Recalculating the impact from sulfate point sources to correct for this
error yields approximately a 0.32 dv impact based on a ``dirty''
background 2018 projected visibility conditions and 0.92 dv based on a
natural background approach.
Second, 0.92 dv represents the estimated deciview improvement from
eliminating sulfate emissions at all point sources in Arkansas (based
on typical or average emissions) on average across the 20% worst days,
as defined by the 20% worst days of monitored visibility at Caney
Creek. This CAMx derived value is not directly comparable to the
CALPUFF modeled 1.952 dv improvement from controls on both units at
Independence, due to differences in models, model inputs and metrics.
CALPUFF modeling following the BART guidelines and recommended protocol
provides an estimate of the maximum (98th percentile) visibility
benefit based on 24-hr maximum actual emissions modeled over a period
of three years. The CAMx modeling results presented by the commenter
represent the average visibility impacts over the 20% worst days (as
defined by monitored data) based on modeling actual emissions levels.
In addition, CALPUFF uses an estimated constant background ammonia
level and does not account for the competition for ammonia due to
emissions from other sources. A maximum value of 1.952 dv for
visibility benefits of controlling Independence based on CALPUFF
modeling is not inconsistent with an estimated 0.92 dv impact from all
sulfate point source emissions averaged over the 20% worst days. In
general, the maximum value could be several times larger than the
average over the 20% worst days (representing the average visibility
over the 73 days, or 24 monitored days with the worst visibility).
Furthermore, the maximum value as modeled by CALPUFF is based on
maximum 24-hr emissions, which may be much higher than the average
emissions. As discussed in a separate response to comment above, CAMx
modeling using source apportionment provided by the commenter (Entergy)
modeled a facility-wide impact from Entergy Independence of 1.64 dv on
the maximum day within the subset of days that make up the 20% worst
days. The maximum modeled impact across the full 365 days modeled could
be much larger. Furthermore, this modeling is based on actual emissions
and not maximum 24-hr emissions as modeled by CALPUFF. Therefore, the
1.952 dv visibility benefit estimated by CALPUFF is not ``impossible''
and is in fact in line with the visibility impacts estimated using the
CAMx model as supplied by the commenter.
Third, the commenter is incorrect in estimating a 4.3 dv
improvement from all BART controls and using this value to adjust
projected visibility conditions
[[Page 66405]]
in 2018 on the 20% worst days in the above figures. The cumulative
visibility impacts cited to by the commenter (e.g., 4.3 dv improvement
at Caney Creek due to all BART controls) combines the maximum
visibility improvements from each facility that would result from
required NOX or SO2 controls without any
consideration of the location of the source or if the impacts and
benefits would occur on the same day. The commenter's approach
overstates the combined impact at a given Class I area and does not
contemplate if sources are located near each other and would likely
impact a Class I area at the same time. Contrary to the commenter's
description of the methodology used to estimate the total visibility
benefits of BART controls,\344\ the commenter simply added the CALPUFF
modeled deciview visibility benefits for each control. These benefits
represent the maximum (98th percentile) visibility benefits at each
source based on reductions to the maximum 24-hr emissions modeled over
a period of three years. The maximum benefits from controlling one
source cannot be added to the maximum benefits of controlling another
source as these benefits are not likely to occur on the same day since
the sources are not collocated. In addition, the maximum benefits from
NOX controls and SO2 controls at the same
facility cannot be added as they may not occur on the same day.
Furthermore, these values represent the benefit on an individual day
and not the average visibility benefit on the 20% worst days so it is
not appropriate to adjust the visibility conditions on the 20% worst
days by this amount as the commenter does in the above figures. In some
situations, the days that CALPUFF model maximum or 98th percentile
value impacts of the facility occur may not coincide with any of the
days that make up the days in the worst 20% days at the Class I area
and the visibility benefits modeled by CALPUFF are not directly
comparable to the visibility benefits that would be anticipated on the
20% worst days from those specific controls. Furthermore, as discussed
elsewhere in this section of the final rule, because deciviews are a
logarithmic function of extinction, they cannot be added as the
commenter does here. The CALPUFF modeled visibility benefits represent
the visibility benefits of controls based on a clean background
approach, and not the amount of benefit that would occur from degraded
conditions, which would be needed to estimate the improvement in
overall visibility conditions in 2018. We estimated the amount of
visibility benefit anticipated from all controls against 2018
visibility conditions in estimating the proposed RPGs for 2018. In this
calculation we estimated the benefit from all required controls to be
0.21 dv at Caney Creek and 0.19 dv at Upper Buffalo.
---------------------------------------------------------------------------
\344\ Commenter states: ``Trinity derived the 4.3 dv improvement
from the CALPUFF modeling by determining the total extinction (in
inverse megameters) from each proposed BART source, adding them
together, and then calculating the deciview improvement. The
resulting 4.3 dv improvement is over five times the total visibility
impact attributed to all point sources in Arkansas based on CENRAP's
CAMx modeling and 14 times the impact attributed to point sources
based on Entergy's current CAMx modeling.''
---------------------------------------------------------------------------
Comment: CALPUFF overstates the visibility improvement expected
from EPA's proposed controls on Independence, EPA concluded that the
cumulative benefit of installing all of the controls in the Proposed
FIP--all BART controls plus controls at Independence--would result in
visibility benefits at Caney Creek of only 0.21 dv and at Upper Buffalo
of only 0.19 dv. Since Independence represents only approximately 36%
of the SO2 point source emissions and 21% of the point
source NOX emissions in Arkansas, one can ascribe only a
minor portion of this projected insignificant deciview improvement to
controls on Independence (approximately 0.08 dv at Caney Creek and 0.07
dv at Upper Buffalo).\345\ Based on this, installation of controls on
Independence will yield no discernible visibility improvements.
---------------------------------------------------------------------------
\345\ These values are the calculated improvement based on EPA's
``scaling methodology.'' See 80 FR at 18997.
---------------------------------------------------------------------------
This demonstrates the illogic of relying on CALPUFF for reasonable
progress. Independence's contribution to the deciview improvements EPA
projects based on the CENRAP modeling would be much less than the total
deciview improvement at Caney Creek of 0.21 dv from the installation of
controls at all of the proposed FIP sources and 0.19 dv at Upper
Buffalo would not be perceptible to the human eye; nowhere close to the
1.95 dv and 1.78 dv improvement that EPA is claiming based on CALPUFF.
Requiring imperceptible visibility improvements is simply unreasonable.
The CAA requires only ``reasonable progress, not the most reasonable
progress.'' \346\
---------------------------------------------------------------------------
\346\ North Dakota v. EPA, 730 F.3d 750, 767 (8th Cir. 2013).
---------------------------------------------------------------------------
Response: As we discuss in depth elsewhere, visibility improvements
from controls must be evaluated on a ``clean'' background basis to
fully assess the benefits from controls. It is not appropriate to
consider only the amount by which a potential measure or combination of
measures would change the projected overall deciview index value as of
the end of the implementation period, i.e., the degree by which the
RPGs would differ with and without the control being included in the
LTS, as the commenter does here. We also discuss elsewhere in this
section of the final rule that the deciview scale is a logarithmic
function of extinction and calculations to determine benefits or amount
of contribution to visibility impairment must be based on extinction
and then converted into deciviews. Nevertheless, the commenter's
estimated visibility benefits of 0.08 dv at Caney Creek and 0.07 dv at
Upper Buffalo on average across the 20% worst days are approximately a
reduction in extinction of 0.8 Mm-1 at Caney Creek and 0.7
Mm-1 at Upper Buffalo, which is 0.37 dv and 0.32 dv based on
a clean background approach for the 20% worst days. In our response to
a separate comment above, we discuss that due to the differences in
models, model inputs, and metrics, the estimated visibility benefits
estimated from CAMx modeling cannot be directly compared to CALPUFF
modeled visibility benefits. For one, CALPUFF modeling is used to
estimate the maximum visibility benefit based on maximum emissions
whereas the CAMx modeling estimates the average visibility benefit over
the 20% worst days (as defined by the monitored data) using actual or
typical emission levels. As we also discuss above in a separate
response to comment, CAMx visibility modeling with source apportionment
submitted by Entergy estimates a maximum visibility impact (limited to
only the days comprising the 20% worst days) of over 1.5 dv from the
Independence facility at both Caney Creek and Upper Buffalo. In some
situations, the CALPUFF modeled maximum or 98th percentile impacts of
the facility may not coincide with the days that make up the worst 20%
monitored days at the Class I area, therefore the maximum impact based
on CAMx modeling could be even higher.
With regard to the quote the commenter reproduced from the Eighth
Circuit Court's decision in North Dakota v. EPA,\347\ several
environmental groups challenged a portion of our final action on North
Dakota's regional haze SIP that ultimately approved North Dakota's
reasonable progress determination for
[[Page 66406]]
NOX controls for the Coyote Station.\348\ The environmental
groups objected to North Dakota's decision to reject a control it had
evaluated, after having applied the four reasonable progress factors,
and subsequently approving another NOX control as reasonable
progress.
---------------------------------------------------------------------------
\347\ The commenter states that requiring imperceptible
visibility improvements is simply unreasonable and refers to the 8th
circuit decision that the CAA requires only ``reasonable progress,
not the most reasonable progress.'' North Dakota v. EPA, 730 F.3d
750, 767 (8th Cir. 2013).
\348\ See EPA's final rule at 77 FR 20894, 20945 (April 6,
2012).
---------------------------------------------------------------------------
We interpret the Court's statement as meaning broadly that just
because a more stringent level of control could be technically feasible
in a particular instance, it does not mean it necessarily must be
required under reasonable progress. We see no conflict with this
determination and our proposed Arkansas FIP and requiring controls that
may not result in perceptible visibility improvements. In North
Dakota's case, we noted technical flaws in North Dakota's analysis, and
we noted that we could have reached a different conclusion had we
conducted the analysis ourselves, but we ultimately determined these
issues did not prevent us from accepting North Dakota's reasonable
progress determination. The Court did not find that our conclusions on
the issue were arbitrary, stating in part that, ``[e]ven if [the
control in question] were perhaps the most reasonable technology
available, the CAA requires only that a state establish reasonable
progress, not the most reasonable progress. In contrast, and as
explained in greater detail elsewhere, in our 2012 rulemaking,\349\ we
made a finding that Arkansas did not complete a reasonable progress
analysis and therefore did not properly demonstrate that additional
controls were not reasonable under 40 CFR 51.308(d)(1)(i)(A). Thus we
disapproved the RPGs Arkansas established for Caney Creek and Upper
Buffalo. Our proposed rulemaking completed the reasonable progress
analysis and established revised RPGs, since we have not received a
revised SIP to correct the portions of the SIP submittal we
disapproved. We determined that cost effective controls were in fact
available that would have very significant visibility benefits.
---------------------------------------------------------------------------
\349\ 64 FR at 35732.
---------------------------------------------------------------------------
Comment: EPA's assessment demonstrates that the Independence Power
Plant's emissions have, and will continue to have, very little effect
on visibility in any Class I area. EPA's reasonable progress analysis
shows that ``[o]n the 20% worst days in 2002, sulfate from Arkansas
point sources contributed 2.20% of the total light extinction at Caney
Creek and 1.99% at Upper Buffalo, and nitrate from Arkansas point
sources contributed 0.27% of the total light extinction at Caney Creek
and 0.14% at Upper Buffalo.'' 80 FR at 18989 (footnote omitted).
According to EPA, these very small percentages reflect contributions
from all ``Arkansas point sources,'' not from the Independence Power
Plant alone, whose emissions of course contribute only a fraction of
these small amounts.
Response: We disagree with the commenter's assertion that the
contribution to visibility impairment from Independence is
``insignificant'' or ``minimal.'' We agree with the commenter's
description of the 2002 CENRAP source apportionment data. The CENRAP
modeling also projects that Arkansas point sources will be responsible
for 3.58% of the total light extinction at Caney Creek and 3.20% at
Upper Buffalo in 2018. As we discuss in our proposal, based on 2011 NEI
data the Entergy Independence Plant is the second largest source of
SO2 and NOX point source emissions in Arkansas,
accounting for approximately 36% of the SO2 point-source
emissions and 21% of point-source NOX emissions in the
State.\350\ Therefore, a significant portion of the total projected
visibility impairment on the 20% worst days, on the order of 1% or
more, can be expected to be attributable to SO2 emissions
from a single facility, the Independence facility, based on the CERNAP
modeling. We discuss in a separate response to comment that results of
our CALPUFF modeling, as well as the results of additional CAMx
modeling submitted by Entergy, confirm and support that the visibility
impairment due to the Independence facility is significant and that
emission reductions will result in meaningful visibility benefits
towards natural visibility conditions.
---------------------------------------------------------------------------
\350\ 80 FR at 18991.
---------------------------------------------------------------------------
6. Visibility Benefit of Entergy Arkansas Proposal
Comment: Entergy's proposed combination of controls and lower
SO2 emission rates will ensure that the Class I areas
achieve virtually the same reasonable progress as EPA's proposal but at
a cost of over $2 billion less than the proposal.\351\ Based on
Entergy's CAMx modeling and Ranked Statistical Analysis, the difference
in the haze index between the proposed FIP controls and Entergy's
proposal is 0.05 dv at Caney Creek and 0.07 dv at Upper Buffalo.
---------------------------------------------------------------------------
\351\ Entergy Arkansas Inc. stated that it is proposing near-
term interim controls and the cessation of coal combustion at White
Bluff by 2028. Entergy is proposing to meet lower SO2
emission rates at White Bluff Units 1 and 2 and Independence Units 1
and 2 by 2018, and is willing to install LNB/SOFA at all four units
and meet a 30-day rolling average NOX emission rate of
1,342.5 lb NOX/hr, within three years after the effective
date of the final FIP as part of its multi-unit approach. Entergy's
comments with regard to the proposed NOX rate are
discussed elsewhere in this final rule.
---------------------------------------------------------------------------
Response: We discuss the ``ranked statistical analysis'' submitted
by the commenter in the response to comments elsewhere. We disagree
with the commenter that the Entergy proposed control scenario achieves
``virtually'' the same visibility benefits as the controls required in
this FIP. We examined the estimated visibility benefits of the FIP and
Entergy's proposal from the commenter's CAMx photochemical modeling. We
note that both scenarios include benefits from all required BART
controls at all subject-to-BART facilities with the exception of White
Bluff. The modeled FIP scenario also includes SO2 and
NOX controls at both Independence and White Bluff. The
modeled Entergy proposal scenario includes the elimination of emissions
from White Bluff, an approximate 15% reduction in SO2
emissions from Independence and roughly similar NOX
reductions at Independence as required in the FIP.
Entergy's proposal achieves less visibility benefit than the FIP
controls at Arkansas' Class I areas, most significantly at Upper
Buffalo where the benefit from Entergy's proposal is approximately only
63% of the benefit from the FIP (1.54 Mm-1 from the FIP
compared to 0.97 Mm-1 from Entergy's Proposal, see the RTC
document for additional information). As discussed above, CAMx source
apportionment modeling submitted by Entergy shows that Entergy
Independence has significant visibility impacts at both Arkansas Class
I areas. At Upper Buffalo, the Independence facility contributes more
to visibility impairment than all the subject-to-BART sources addressed
in this action combined. Additional reductions from the elimination of
emissions from the White Bluff facility under Entergy's proposal are
much too small to compensate for the lack of significant SO2
reductions at Independence. Furthermore, Entergy's proposal does not
achieve these benefits until 2028, seven years after the full benefits
from the FIP would be realized. We discuss other aspects of Entergy's
proposal, including uncertainty in emissions at White Bluff after the
cessation of coal-burning, and issues concerning the BART requirements
for White Bluff in separate responses to comment elsewhere in this
document.
[[Page 66407]]
We also disagree with the commenter's use of the results of their
ranked statistical analysis (the ``projected haze index'' shown in the
Entergy Arkansas Inc.'s submitted comments in figures 13 and 14) as the
starting point for calculating the overall visibility benefits from the
FIP or the commenter's proposed alternative. As discussed elsewhere in
this section of the final rule, the ranked statistical analysis is
simply a projection of future visibility conditions based on past
improvement and is not directly tied to any additional required
emission reductions in the next few years that would result in this
future visibility improvement from current conditions to this projected
value in 2018.
7. Observed Visibility Improvements
Comment: Trinity was tasked by Entergy Arkansas with conducting a
statistical analysis of observed visibility data gathered through the
IMPROVE program to statistically determine the future trends in the
regional haze index values. Trinity conducted a simple Trend
Statistical Analysis and more robust Ranked Statistical Analysis to
determine the projected haze index in 2018.\352\
---------------------------------------------------------------------------
\352\ Trinity's report is included as Exhibit D IMPROVE Data
Statistical Analysis, Trinity Consultants (July 2015) to Entergy
Arkansas, Inc.'s comments.
---------------------------------------------------------------------------
For Caney Creek and Upper Buffalo, respectively, the observed
values are well below the glide path with a consistent downward trend
in the observations. This downward trend is consistent with the
historical (2002-2011) trend in decreasing sulfur dioxide
(SO2) emissions from tier 1 sources located in the states
contributing significantly to the Caney Creek and Upper Buffalo Class I
Areas.\353\ Pursuant to the NEI emissions data, the SO2
emissions have significantly decreased since 2005 to 2011 in all source
categories, including especially a more than 50% drop due to fuel
combustion from electric utilities and a 67% drop in the fuel
combustion from industrial sources. Based on the significant downward
trend in the observed data and the actual SO2 emissions
data, the future haze index value in 2018 is expected to be lower than
the currently predicted glide path. The lower haze index value in 2018
will be additionally supported by the anticipated implementation of
regulations further curbing emissions.
---------------------------------------------------------------------------
\353\ See Figure 2-3 of Exhibit D to Entergy Arkansas, Inc.'s
comments.
---------------------------------------------------------------------------
In order to statistically calculate the future deciview haze index
values using observed data instead of relying on the CENRAP modeling,
two statistical analyses were performed and evaluated to determine the
most appropriate analysis for predicting the haze index values based on
observed data: Trend Analysis, and Ranked Statistical Analysis. The
2018 average of the 20% worst days for visibility was calculated to be
20.07 dv for Caney Creek and 20.91 dv for Upper Buffalo. These numbers
are far below the URP for the first planning period and demonstrate
that no source in Arkansas, including Independence, needs to install
controls for Arkansas to remain below the glide path.
Response: As we discuss in section V.C of this final rule, being
projected to be on or below the URP glidepath in 2018 (or even beyond)
does not automatically mean that no controls or evaluation under
reasonable progress is needed in this planning period. The commenter
presents SO2 emissions data from 2002, 2005, 2008, and 2011
for states identified by the commenter as impacting visibility at the
Arkansas Class I areas. These data show significant emissions
reductions over this time period and are consistent with observed
visibility improvement at the Arkansas Class I areas. However, most of
the visibility improvement currently observed in Arkansas appears to be
due to emissions reductions that have taken place outside the state.
Arkansas emissions do not exhibit the same downward trend as presented
for the other states that impact visibility at the Arkansas Class I
areas.\354\ More recent annual emissions from 2012-2014 are actually
higher than emissions from the 2008-2011 period and there is no
downward trend in emissions from those point sources with the largest
visibility impacts, those from fuel combustion at electric utilities.
To the extent that the commenters are suggesting that Arkansas should
be relieved of its regional haze obligations because other states'
emission reduction efforts have already resulted in significant
visibility improvement at Arkansas' Class I areas, this is incorrect.
Rather Arkansas, and EPA in standing in Arkansas' shoes, must consider
the statutory factors in addressing the long term strategy and
reasonable progress requirements.
---------------------------------------------------------------------------
\354\ See RTC document for additional information on Arkansas
source category SO2 emissions from 2004 to 2014.
---------------------------------------------------------------------------
We disagree with the commenter that the CENRAP CAMx predicted 2018
haze index is overly conservative. The comments indicate a lack of
understanding of how reasonable progress goals are established, as well
as the imports of the goals as opposed to the measures adopted to
ensure reasonable progress. As we state in the Regional Haze Rule, the
reasonable progress goal(s) set by the state, or EPA when promulgating
a FIP, are not enforceable. The reasonable progress goals are an
analytical tool used by EPA and the states to estimate future
visibility conditions and track progress towards the goal of natural
visibility conditions. Accordingly, the RPGs must represent an estimate
of the degree of visibility improvement that will result in a future
year from changes in emissions inventories, changes driven by the
particular set of control measures adopted in the regional haze SIP or
FIP to address visibility, as well as all other enforceable measures
expected to reduce emissions. Given the forward-looking nature of
reasonable progress goals and the range of assumptions that must be
made as to emissions in the future, we expect there to be some
uncertainty in the estimates of future visibility.
The statistical analyses provided by the commenter are simply
extrapolations of future visibility conditions based on observed
reductions in visibility impairment in the past. Future visibility
projections must be directly tied to projections of future emissions,
and anticipated reductions due to federal and state requirements.
Current 5-yr average (2010-2014) observed visibility conditions are
21.8 dv at Caney Creek and 21.6 dv at Upper Buffalo. Any future
improvements in overall visibility conditions at the Arkansas Class I
areas between now and 2018 will be due to future emission reductions
during that time period. Commenters have not provided any specific
information suggesting anticipated enforceable emission reductions from
those Arkansas point sources with significant visibility impacts or
other sources that would result in the almost 2 dv visibility
improvement by 2018 projected by the commenter at Caney Creek in their
statistical analysis. Furthermore, as discussed above, any anticipated
emission reductions from sources in other states do not relieve
Arkansas of its regional haze obligations. The BART requirements under
Sec. 51.308(e) must be met for those specific sources that meet the
BART criteria and contribute to visibility impairment. The
determination of whether an RPG and the emission limitations and other
control measures upon which it is based constitute reasonable progress
is made by conducting certain analyses and
[[Page 66408]]
meeting the requirements under Sec. 51.308(d)(1).
The RPGs are an analytical tool the state and we use to evaluate
whether the measures in the implementation plan are sufficient to
achieve reasonable progress. What is enforceable under the RH rule are
the emission limitations and other control measures that apply to
specific sources, and upon which the RPGs are based. Since the emission
limitations we are requiring in our FIP for specific Arkansas sources
(which is what our revised RPGs are based upon) are not currently being
achieved, we disagree that visibility at the Class I areas has already
improved beyond what we would require in our FIP and that our FIP is
therefore unjustified and unwarranted. The emission reductions required
in this action will result in significant visibility improvements at
the Class I areas beyond what is currently being achieved or observed.
As discussed elsewhere throughout this final rule, the commenter's
photochemical modeling analysis provides an additional demonstration
that the controls required in this action result in visibility benefits
beyond current observed visibility conditions and serve to accelerate
progress towards natural visibility conditions.
8. Reasonable Progress Goals
Comment: EPA's proposed RPGs are more stringent than Arkansas'
proposed RPGs in its 2008 Regional Haze SIP, which would have ensured
that Arkansas is on track to achieve natural visibility conditions by
2064. Arkansas is reducing regional haze in its Class I areas at a
higher rate than both the URP, which was approved by EPA, and Arkansas'
initial proposed RPGs. As indicated by the URP, Arkansas is well on
track to reaching natural visibility conditions by 2064 and more
stringent RPGs than those in Arkansas' 2008 Regional Haze SIP are not
necessary. EPA should withdraw the Proposed FIP and ensure that revised
RPGs in any subsequent plan are within the scope of EPA's authority to
address impairment of visibility.
The differences in projected 2018 visibility conditions at Caney
Creek and Upper Buffalo that are attributable to all of the proposed
FIP controls--including both FIP BART and FIP reasonable progress
requirements--will be imperceptibly small (i.e., improvements of, at
most, 0.21 dv and 0.19 dv, respectively, at Caney Creek and Upper
Buffalo). The minimal visibility improvements that EPA's proposed
reasonable progress emission control requirements would produce would
come at exorbitant costs. Additionally, even the negligible changes in
visibility represented by EPA's proposed revised RPGs are greatly
overstated because some controls will not be in place until after 2018.
Commenters also state that the methodology utilized by EPA in
estimating the RPGs is oversimplified and inaccurate. EPA chose a
method of determining RPGs that is admittedly inferior and less
sophisticated than the alternative approach, which EPA rejected in
Arkansas but used in Texas: CAMx photochemical modeling. EPA admits
that it has not performed its own modeling in a manner adequate to
develop ``refined numerical RPGs.'' Some commenters stated that EPA
used CALPUFF, which is not a photochemical grid model, to develop a
``quick-and-dirty'' RPG analysis in the proposed Rule.
Response: As we discuss in more detail elsewhere in our response to
comments, we agree that Arkansas proposed RPGs in its 2008 regional
haze SIP that fell below the URP. However, in our 2012 rulemaking,\355\
we made a finding that Arkansas did not complete a reasonable progress
analysis and therefore did not properly demonstrate that additional
controls were not reasonable under 40 CFR 51.308(d)(1)(i)(A). Thus we
disapproved the RPGs Arkansas established for Caney Creek and Upper
Buffalo. In our proposed rulemaking, we completed the reasonable
progress analysis and established revised RPGs, since we have not
received a revised SIP to correct the portions of the SIP submittal we
disapproved. As discussed in our proposal and in our RTC document, we
focused our reasonable progress analysis on the Entergy Independence
facility because of its significant emissions of NOX and
SO2 and its large potential to impact visibility at nearby
Class I areas. We determined that cost-effective controls were
available for units at this facility and that they would result in
significant visibility benefits. We respond to specific comments
concerning the visibility benefits from controls on the Independence
facility in separate responses to comments. We also completed five-
factor BART analyses and determinations for subject-to-BART facilities
where we had previously disapproved the BART determination in the 2008
Arkansas regional haze SIP. Our proposed RPGs reflected the visibility
benefits anticipated from the implementation of controls across the
subject-to-BART facilities and the Independence facility required in
this action. As we discuss in our proposal and in response to comments,
we have determined that these controls are cost-effective and result in
significant visibility benefits that provide for progress towards the
goal of natural visibility conditions. As we discuss below in a
separate response to comment, after considering comments received, we
agree that the RPGs should reflect anticipated visibility conditions at
the end of the implementation period in 2018 rather than the
anticipated visibility conditions once the FIP has been fully
implemented. We are finalizing RPGs that represent the visibility
conditions anticipated on the 20% worst days at Caney Creek and Upper
Buffalo by 2018.
---------------------------------------------------------------------------
\355\ 64 FR at 35732.
---------------------------------------------------------------------------
We disagree with the commenter that the amount of visibility
improvement due to our proposed FIP is ``insignificant.'' We address
comments concerning the perceptibility of visibility improvements in
response to comments elsewhere. The required controls are estimated to
improve overall visibility benefits compared to the CENRAP projected
visibility conditions for 2018 by approximately 0.2 deciviews, a
reduction in light extinction of about 2 Mm-1 at Caney Creek
and 1.8 Mm-1 at Upper Buffalo. Once fully implemented, the
required controls to meet the BART requirements, as well as required
controls on the Independence facility result in an approximate 2%
improvement in overall visibility conditions projected by CENRAP at
both Caney Creek and Upper Buffalo on the 20% worst days. Our technical
record demonstrates that the required controls reduce impacts from
these sources and result in meaningful visibility benefits towards the
goal of natural visibility conditions. The required controls reduce the
projected visibility impairment due to all Arkansas point sources by
50% at Caney Creek and 50% at Upper Buffalo. We note that the required
controls actually result in larger visibility improvements than
calculated here because the CENRAP projections already included an
assumption of large emission reductions due to SO2 BART at
Flint Creek, as well as NOX controls at White Bluff and
Flint Creek.\356\
---------------------------------------------------------------------------
\356\ 2002 CENRAP modeled SO2 emissions for Flint
Creek were 11,165 tpy and 2018 CENRAP modeled SO2
emissions were 2,896 tpy, an assumed 75% reduction in emissions.
---------------------------------------------------------------------------
We disagree with the commenter that our proposed RPGs overstated
the visibility benefit of controls or that they are inaccurate. In our
proposal, we acknowledged that the methodology we utilized to estimate
the revised RPGs is
[[Page 66409]]
not as refined as developing an updated model projection. However, it
allows us to translate the emission reductions contained in the
proposed FIP into quantitative RPGs, based on modeling previously
performed by the CENRAP. These proposed RPGs provided an estimate of
the visibility benefit of all the required controls compared to the
2018 visibility conditions projected by the state and established in
their SIP that would result without the required controls. After
considering comments received, we agree that the RPGs should reflect
anticipated visibility conditions at the end of the implementation
period in 2018 rather than the anticipated visibility conditions once
the FIP has been fully implemented, and have accordingly revised the
2018 RPGs. RPGs, unlike the emission limits that apply to specific
reasonable progress and BART sources, are not directly enforceable.
Rather, the RPGs are an analytical framework considered by us in
evaluating whether measures in the implementation plan are sufficient
to achieve reasonable progress. Our FIP imposes emissions limitations
that we conclude to be necessary under the CAA for the first planning
period. Ideally, these controls would be installed and the emission
limitations achieved, so the visibility improvements can be realized
and built on in a subsequent comprehensive periodic SIP revision (see
40 CFR 51.308(f)). Arkansas may choose to use these RPGs for purposes
of its progress report (along with a consideration for what controls
had already been implemented and what controls would be implemented in
the near future), or may develop new RPGs for approval by us along with
its progress report, based on new modeling or other appropriate
techniques, in accordance with the requirements of 40 CFR 51.308(d)(1)
in evaluating the adequacy of their SIP (or this FIP) to meet the
established RPGs.
We discuss our selection of the CALPUFF model for evaluating
single-source visibility impacts in a separate response to comment
above. In the response, we also explain the model selection for our
Texas action and refer the reader to our detailed explanation in the
RTC that accompanies that action. Commenters are incorrect and confuse
the single-source visibility analysis used to evaluate the visibility
benefit of controls on a specific source with the assessment of overall
visibility conditions. We did not use the CALPUFF modeling to develop
the new reasonable progress goals we establish in this rulemaking. The
RPGs are based on adjusting the CENRAP 2018 CAMx photochemical modeling
based on source apportionment modeling results and emission inventory
data. As we stated in the proposed rulemaking, we did not perform
additional photochemical modeling to directly model the new projected
visibility goals due to the time and resource demands associated with
photochemical modeling. The commenters are also incorrect in their
comparison of approaches for establishing new RPGs between this action
for Arkansas and our previous action in Texas. For both Texas and
Arkansas, we utilized the CENRAP 2018 CAMx modeling that estimated the
2018 RPGs and then adjusted those RPGs to account for estimated
visibility improvement due to required controls. In neither case did we
perform a full photochemical modeling analysis to model all the
required controls and project the future visibility conditions. In both
cases, the 2018 RPGs were adjusted based on a scaling of the source
apportionment model results and emission inventory changes.
Comment: The demonstration methodology used by EPA is unscientific.
EPA used a ratio of emission rates from BART sources to Arkansas point
sources to scale the modeled predicted haze index. First, there is no
evidence to prove that the CAMx predicted modeling results are linearly
correlated with emission rates. In fact, the CAMx modeling
fundamentally is based on photochemical reactions. Therefore, the
relationship between variation in the emission rates and predicted
concentration is complicated. Second, a deciview is a logarithmic scale
based on the concept that one deciview is the minimum change in the
visibility perceptible to a human observer. As such, deciviews cannot
be added or subtracted directly. Therefore, fractioning or scaling
deciviews based on emission rates is illogical.
Another commenter was supportive of our approach, stating that in
Texas, the model results were used to demonstrate that the overall
change in species concentrations was very nearly linearly proportional
to the change in emission levels for an individual source (with very
high linear correlation coefficients near 1.0). This strongly supports
the use of the emission scaling approach for Arkansas. If the CAMx
model were used to determine the impact of emission controls on a
single source in Arkansas (such as Independence), it is therefore
expected that the modeled reductions in sulfate and nitrate
concentrations at each of the Class I areas will be very nearly
proportional to the SO2 and NOX concentration
reductions. In other words, the emission scaling approach has been
shown to be mathematically sound and quite appropriate, especially
considering the resources that would be required to exercise CAMx
separately for each control measure at each evaluated source.
Response: We disagree with the comments that the methodology used
to estimate overall visibility benefits from all required controls
control level emissions was unreasonable or unscientific. We agree with
comments that the approach we followed is reasonable and based on a
scaling of visibility extinction components due to Arkansas point
sources in proportion to emission changes from the required controls at
Arkansas point sources. The commenter is incorrect in suggesting that
we developed a linear relationship between emissions and deciviews and
then commenting that this ``fractioning or scaling of deciviews'' is
flawed because the relationship between light extinction and deciviews
is exponential. We properly developed a linear relationship between
emissions and light extinction (inverse Megameters), not deciviews.
We agree with the commenters, that in general, the relationship
between downwind concentrations and emissions can be complicated and
non-linear due to complex chemistry, including the fact that reductions
in sulfur emissions can result in an increase in ammonium nitrate. For
estimating the total visibility benefit from all controls and
estimating a new reasonable progress goal that reflects those controls,
we relied on the CENRAP's 2018 CAMx modeling results, including source
apportionment results, and the projected emission inventories, and
scaled the results as described in the TSD, similar to what was done in
our previous action in Arizona and Texas. While we acknowledge that
this approach is not as refined an estimate as would be attained in
performing a new photochemical modeling run, it is based on scaling to
adjust earlier photochemical modeling results that took into account
the complex chemistry that impacts the overall visibility. The
uncertainty in the visibility benefit from these controls introduced by
the linear extrapolation does not impact the overall conclusions.
Furthermore, in our technical analysis developed to support our action
on Texas regional haze, we observed that for each facility and Class I
area, the available modeled visibility impact was linear with respect
to emissions with
[[Page 66410]]
high correlation.\357\ Following this approach we estimated that when
fully implemented, the required controls would result in a reduction in
light extinction of about 2 Mm-1 at Caney Creek and 1.8
Mm-1 at Upper Buffalo on the 20% worst days. As discussed
elsewhere, Entergy Arkansas submitted additional CAMx modeling with
their comments. This photochemical modeling projects a 2.95
Mm-1 reduction at Caney Creek and 1.54 Mm-1
reduction at Upper Buffalo when compared to the Entergy's base case
modeling for 2018 for the 20% worst days.\358\
---------------------------------------------------------------------------
\357\ See 81 FR 296, 335 and the FIP TSD (document ID: EPA-R06-
OAR-2014-0754-0007).
\358\ See Entergy CAMx Results 2015-1124_FINAL.xls.
---------------------------------------------------------------------------
Comment: Even the negligible changes in visibility represented by
EPA's proposed revised RPGs are greatly overstated because the bulk of
the EPA-projected visibility improvements are due to proposed
SO2 emission limits for BART and reasonable progress that
have a five-year compliance deadline and thus will not become operative
until at least 2020. No sound basis exists for the projections of
visibility improvements by 2018 that EPA sets out in the proposed rule.
Those EPA projections are inaccurate and unsupportable.
In this regard, EPA fails to explain why (a) the Agency may
permissibly use a concededly oversimplified and inaccurate shortcut
methodology for calculating RPGs in its FIP, on the grounds that EPA
otherwise would have to conduct time-consuming and complicated
modeling, see id., but (b) Arkansas and other states apparently are
held to a much higher standard for their RPG analyses, see id. In
proposing and promulgating a FIP for Arkansas, EPA merely stands in the
state's shoes. Accordingly, if EPA may lawfully comply with the CAA and
the regional haze rules by conducting and relying on this sort of
analysis that is ``not refined'' but (purportedly) sufficient to
support its FIP's RPGs, then states also may do so to support their
SIPs' RPGs. On the other hand, to the extent EPA does not believe that
RPGs based on such an abbreviated analysis would be approvable if
submitted by a state in a SIP, EPA cannot lawfully promulgate the RPGs
that it proposes based on the analysis presented in its proposed rule.
Response: We proposed RPGs for the 20% worst days for Caney Creek
and Upper Buffalo of 22.27 dv and 22.33 dv, respectively that reflected
the anticipated visibility conditions resulting from the combination of
control measures from the approved portion of the 2008 Arkansas
Regional Haze SIP and our FIP proposal. After considering these
comments, we agree that the RPGs should reflect anticipated visibility
conditions at the end of the implementation period in 2018 rather than
the anticipated visibility conditions once the FIP has been fully
implemented. This approach is consistent with the purpose of RPGs and
the direction provided in our 2007 Reasonable Progress Guidance.
Section 169B(e)(1) of the CAA directed the Administrator to
promulgate regulations that ``include[e] criteria for measuring
`reasonable progress' toward the national goal.'' Consequently, we
promulgated 40 CFR 51.308(d)(1) as part of the Regional Haze Rule. This
provision directs states to develop RPGs for the most and least
impaired days to ``measure'' the progress that will be achieved by the
control measures in the state's long-term strategy ``over the period of
the implementation plan.'' \359\ The current implementation period ends
in 2018. RPGs ``are not directly enforceable'' like the emission
limitations in the long-term strategy.\360\ Rather, they fulfill two
key purposes: (1) Allowing for comparisons between the progress that
will be achieved by the state's long-term strategy and the URP,\361\
and (2) providing a benchmark for assessing the adequacy of a state's
SIP in 5-year periodic reports.\362\ Consequently, in our 2007
Reasonable Progress Guidance, we indicated that states could consider
the ``time necessary for compliance'' factor by ``adjust[ing] the RPG
to reflect the degree of improvement in visibility achievable within
the period of the first SIP if the time needed for full implementation
of a control measure (or measures) will extend beyond 2018.'' \363\ In
other words, RPGs need not reflect the visibility improvement
anticipated from all of the control measures deemed necessary to make
reasonable progress (as a result of the four-factor analysis) and
included in the long-term strategy.
---------------------------------------------------------------------------
\359\ 40 CFR 51.308(d)(1).
\360\ 40 CFR 51.308(d)(1)(iv).
\361\ 40 CFR 51.308(d)(1)(ii).
\362\ 40 CFR 51.308(g)-(h).
\363\ ``Guidance for Setting Reasonable Progress Goals Under the
Regional Haze Program,'' at 5-2.
---------------------------------------------------------------------------
In this instance, we are taking final action on the Arkansas
Regional Haze FIP 9 years after the state's initial SIP submission was
due.\364\ As a result, only some of the control measures that we have
determined are necessary to satisfy the BART and reasonable progress
requirements will be installed by the end of 2018. Some controls will
not be installed until 2021. Because RPGs are unenforceable analytical
benchmarks, we think that it is appropriate to follow the
recommendation in our 2007 Reasonable Progress Guidance and finalize
RPGs that represent the visibility conditions anticipated on the 20%
worst days at Caney Creek and Upper Buffalo by 2018. These RPGs are
listed in the table below: \365\
---------------------------------------------------------------------------
\364\ We discuss in section II.A of this final rule the history
of the state's submittals and our actions.
\365\ These RPGs are calculated using the same methodology
described in our proposal and TSD. See ``CACR UPBU RPG analysis
2018.xlsx'' for additional information on the calculation of the
RPGs.
Table 21--Reasonable Progress Goals for 2018 for Caney Creek and Upper
Buffalo
------------------------------------------------------------------------
2018 RPG 20%
Class I area Worst days
(dv)
------------------------------------------------------------------------
Caney Creek............................................. 22.47
Upper Buffalo........................................... 22.51
------------------------------------------------------------------------
We disagree with the commenter that the proposed RPGs overstated
the visibility benefit of controls or that they are inaccurate. In our
proposal, we acknowledged that the methodology we utilized to estimate
the RPGs is not as refined as developing an updated model projection.
However, it allows us to translate the emission reductions contained in
the proposed FIP into quantitative RPGs, based on modeling previously
performed by the CENRAP.\366\ The proposed RPGs provided an estimate of
the visibility benefit of all the required controls compared to the
2018 visibility conditions projected by the state and established in
their SIP that would result without the required controls. Our final
RPGs, calculated using the same methodology, reflect the anticipated
visibility conditions at the end of the implementation period in 2018
and the visibility benefit from those controls required to be
implemented by the end of 2018. RPGs, unlike the emission limits that
apply to specific reasonable progress and BART sources, are not
directly enforceable.\367\ Rather, the RPGs are an analytical framework
considered by us in evaluating whether measures in the implementation
plan are sufficient to achieve reasonable progress.\368\ Our FIP
imposes emissions limitations that we conclude to be necessary under
the CAA for the first planning period. Ideally, these controls would be
installed and the emission limitations achieved, so
[[Page 66411]]
the visibility improvements can be realized and built on in a
subsequent comprehensive periodic SIP revision (see 40 CFR 51.308(f)).
Arkansas may choose to use these RPGs for purposes of its progress
report (along with a consideration for what controls had already been
implemented and what controls would be implemented in the near future),
or may develop new RPGs for approval by us along with its progress
report, based on new modeling or other appropriate techniques, in
accordance with the requirements of 40 CFR 51.308(d)(1) in evaluating
the adequacy of their SIP (or this FIP) to meet the established RPGs.
---------------------------------------------------------------------------
\366\ 80 FR 18944, 18998.
\367\ 40 CFR 51.308(d)(1)(v).
\368\ 64 FR at 35733 and 40 CFR 51.308(d)(1)(v).
---------------------------------------------------------------------------
We disagree that Arkansas would be held to a higher standard or
that the methodology utilized by EPA to adjust the RPGs would not be
approvable if submitted by a state. The approach followed by EPA in
this action, using scaling to adjust the modeled RPGs based on
photochemical source apportionment model results is reasonable and
meets the requirements of the Regional Haze Rule. In our 2012
rulemaking,\369\ we made a finding that Arkansas did not complete a
reasonable progress analysis and therefore did not properly demonstrate
that additional controls were not reasonable under 40 CFR
51.308(d)(1)(i)(A). Thus we disapproved the RPGs Arkansas established
for Caney Creek and Upper Buffalo. In our proposed rulemaking, we
completed the reasonable progress analysis and established revised RPGs
using the methodology described above, since we have not received a
revised SIP to correct the portions of the SIP submittal we
disapproved.
---------------------------------------------------------------------------
\369\ 77 FR 14604.
---------------------------------------------------------------------------
9. Additional Modeling Comments
Comment: We received additional specific modeling comments
concerning emission rates modeled to assess baseline visibility impacts
for Independence, White Bluff and Flint Creek. We also received
separate comments concerning our modeling analysis and assessment of
NOX controls on Lake Catherine, White Bluff and
Independence.
Response: We address these comments in our RTC document.
K. Legal
We received several comments on EPA's legal authority to promulgate
a FIP under the Regional Haze Rule, and, more specifically, to address
the Rule's reasonable progress requirements. Below is a summary of some
of the more significant comments. For a more detailed explanation,
please refer to the RTC document that is a part of the docket for this
rulemaking.
We received comments that EPA is prohibited from requiring controls
for this planning period if they cannot be installed during this
planning period. We disagree with these comments. The CAA establishes
our authority and responsibility to promulgate a FIP that addresses the
requirements of the regional haze program where a State's SIP
submission fails to meet the program requirements. Although the first
planning period, ending in 2018, includes RPGs specific to that
planning period, there is no limitation in the CAA or the Regional Haze
Rule that controls contained in a SIP (or a FIP) must be fully
implemented by the end of the planning period. As both the long-term
strategy and BART requirements may extend beyond the first planning
period, it follows that EPA has FIP authority to fill in ``gaps'' or
``inadequacies'' related to those components irrespective of whether
controls can be put into place by 2018. In addition, any emission
limitations that prove to be required by the CAA for the first planning
period need to be achieved at their soonest opportunity, not delayed,
deferred, or avoided for later planning periods when even further
progress may be required in order to achieve the national visibility
goal.
We also received comments that we had no legal basis for requiring
alternative proposals for SO2 and NOX control
measures that would address the regional haze requirements for White
Bluff Units 1 and 2 and Independence Units 1 and 2 for this planning
period to achieve greater reasonable progress than the BART and
reasonable progress requirements that EPA has proposed for the first
planning period. Our response explains our analysis of Entergy's four-
unit approach and clarifies how our evaluation of that approach was
consistent with the Regional Haze Rule's BART alternative and
reasonable progress requirements.
In addition, we received several comments that our proposed FIP was
not in keeping with the legal requirements for reasonable progress and
long term strategy as spelled out in the Regional Haze Rule and EPA
Guidance. We disagree and explain in more detail in the RTC document
that we disapproved the reasonable progress determination Arkansas
submitted in 2012 because the State did not conduct the required four-
factor analysis. The CAA requires us to stand in the State's shoes and
promulgate a FIP that addresses the requirements of the Regional Haze
Rule that we disapproved, including reasonable progress and the long
term strategy for Arkansas' Class I areas.
We also received comments that our proposed FIP did not take into
account the leading role of the state in developing a plan that
addresses the regional haze program and thus is not in keeping with
cooperative federalism. We disagree that EPA ignored the principles of
cooperative federalism. Arkansas did develop a regional haze plan. We
reviewed it and partially approved and disapproved the plan in 2012.
The CAA creates a mandatory duty for EPA to either approve a state SIP
revision submittal that corrects the deficiency or promulgate a FIP
within two years of the effective date of the disapproval of a state
plan.
We received comments that EPA does not have authority to finalize a
FIP after two years have elapsed from our initial disapproval of the
Arkansas Regional Haze SIP. We describe in more detail in the RTC
document our disagreement with this interpretation of what is required
under the Clean Air Act. The Tenth Circuit has upheld EPA's authority
to finalize a Regional Haze FIP after the two years have passed for EPA
to act on Oklahoma's Regional Haze SIP.
We also received comments that our proposed FIP was not in keeping
with Executive Orders 12866 and 13211. Our response is that our
proposed action is not subject to Executive Order 13211 because it is
not a ``significant regulatory action'' under Executive Order 12866;
therefore, the proposed FIP is not a rule of general applicability
because its requirements apply and are tailored to only seven
individually identified facilities. Thus, it is not a ``rule'' or
``regulation'' within the meaning of E.O. 12866 and this action is not
a ``regulatory action'' subject to 12866. Since E.O. 13211 applies only
to ``significant regulatory actions'' under E.O. 12866, this action is
not subject to review under E.O. 13211.\28\ Evaluation of the proposal
under E.O. 13211's criteria is therefore not required.
We respond in greater detail in the RTC document to comments that
EPA did not adequately consider costs to ratepayers as is required
under Arkansas law in developing air regulations. States are under an
obligation to submit a Regional Haze SIP to EPA which complies with
federal requirements. While states enjoy flexibility in developing a
SIP and can meet additional state requirements as long as the federal
requirements are satisfied, in the event that EPA must step in and
create a Federal Implementation Plan, we must meet all federal
requirements. We are not subject to state law requirements related to
how the cost
[[Page 66412]]
analyses must be conducted or what specific factors need to be
considered. We did consider costs in great detail to ensure that the
controls required by the FIP are cost-effective, appropriate in light
of the visibility reductions achieved, and consistent with expectations
in other SIPs and FIPs.
We received several general comments including a claim that
documents that EPA relied for its rulemaking were not in the docket. As
explained more fully in our RTC document, the documents referred to are
briefing sheets and did not serve as the basis for EPA's decision
making. The docket contains all of the documents that serve as our
basis for our rulemaking for Arkansas Regional Haze.
L. Interstate Visibility Transport
Comment: The good neighbor visibility provision in 42 U.S.C.
7410(a)(2)(D)(i)(II) prohibits interference with ``measures'' required
to be included in another State's implementation plan to protect
visibility. EPA has not demonstrated that any of these sources in its
FIP proposal are interfering with any visibility control measure in any
other state's SIP. In its FIP proposal, EPA states that the Arkansas
SIP did not ensure that emissions from Arkansas sources ``do not
interfere with other states' visibility programs as required by section
110(a)(2)(D)(i)(II) of the CAA.'' \370\ The visibility protection
requirement of section 110(a)(2)(D)(i)(II) does not protect against
interference with either other states ``efforts'' or other states
``programs.'' Unlike the language in section 110(a)(2)(D)(i)(I), which
prohibits emissions that contribute significantly to nonattainment or
maintenance of a NAAQS in another state, the visibility protection
requirement is narrower and only protects against interference with
specific measures, that is, actions included in another state's plan to
achieve a visibility goal. Reasonable progress goals, projected
deciview improvements from regional efforts, and the like are goals or
standards; they are not ``measures'' taken by or enforced by a state.
There is nothing in the record demonstrating that any of the sources in
the FIP proposal interfere with any measure included in any other
state's SIP for the purpose of protecting or improving visibility. To
the extent that EPA's proposed interstate visibility transport FIP is
not based on direct interference with a control measure in another
state's regional haze SIP (in contrast to interference with a regional
haze related visibility goal), EPA's interpretation is contrary to the
clear and express language of Section 110. EPA's interpretation also is
contrary to the CAA's clear direction that each state is to determine
its own emission limits, schedules of compliance and other measures for
sources in that state for purposes of visibility protection under
section 169A. EPA's interpretation would impermissibly give one state
the power to control another state's regional haze SIP decisions,
including its BART and reasonable progress determinations. Finally,
even if the CAA's good neighbor visibility provision required a SIP to
contain emission limits for sources that contribute to visibility
impairment at a Class I area in another state, EPA has not demonstrated
that any of the controls in its FIP proposal are ``necessary'' for that
purpose, considering based on the uncertainty in the modeling that
these controls will result in actual visibility improvements.
---------------------------------------------------------------------------
\370\ 80 FR at 18998.
---------------------------------------------------------------------------
Response: Section 110(a)(2)(D)(i)(II) does not explicitly define
what is required in SIPs to prevent the prohibited impact on visibility
in other states nor does it explicitly define how to determine if a
state's emissions are interfering with another state's measures to
protect visibility. We have interpreted this statutory requirement as
providing that a Regional Haze SIP that requires emission reductions
consistent with the assumptions the relevant RPO used to model the RPGs
for Class I areas in other states satisfies a state's obligation to
ensure that its own emissions do not interfere with another state's
visibility measures. States may rely on a fully approved Regional Haze
SIP to demonstrate that a SIP for 8-hour ozone or PM2.5
contains adequate provisions to prohibit emissions that interfere with
visibility measures in other states.\371\
---------------------------------------------------------------------------
\371\ See ``2006 Guidance for SIP Submissions to Meet Current
Outstanding Obligations Under Section 110(a)(2)(D)(i) for the 8-Hour
Ozone and PM2.5 NAAQS'' at pages 9-10.
---------------------------------------------------------------------------
Arkansas chose to address the interstate visibility transport
requirement under section 110(a)(2)(D)(i)(II) by relying on its 2008
Regional Haze SIP submittal to achieve the emissions reductions
necessary to meet this requirement. However, due to our previous
partial disapproval of this submittal,\372\ the Arkansas SIP does not
currently include all of the emission reductions Arkansas agreed to
achieve in its RPO process. Arkansas is a member state of CENRAP, the
regional planning committee on regional haze. Each CENRAP state based
its regional haze plan and RPGs on the CENRAP modeling, which was based
in part on the emissions reductions each state intended to achieve by
2018. Within the CENRAP process, Arkansas promised to achieve emission
reductions corresponding to BART, and these emissions reductions were
included in the CENRAP modeling used by the participating states to
develop their RPGs and Regional Haze SIPs. However, EPA previously
disapproved some of Arkansas' BART determinations; therefore, the
State's SIP does not currently provide for all the emissions reductions
that Arkansas itself determined to be necessary to meet the interstate
visibility transport requirement. Because Arkansas has not provided any
other analysis or explanation of how the Arkansas SIP fulfills the
requirement of 110(a)(2)(D)(i)(II), it follows that the Arkansas SIP
does not contain adequate provisions to prohibit emissions that would
interfere with other states' visibility protection measures.
---------------------------------------------------------------------------
\372\ 77 FR 14604.
---------------------------------------------------------------------------
We disagree with the commenter's contention that our interpretation
is contrary to the CAA because the Act gives clear direction that each
state is to determine its own emission limits, schedules of compliance
and other measures for sources in that state for purposes of visibility
protection under section 169A. The commenter states that our
interpretation would impermissibly give one state the power to control
another state's regional haze SIP decisions. However, the commenter's
interpretation is inconsistent with section 110(a)(2)(D)(i)(II)'s
``good neighbor'' provision, which requires states to prohibit
emissions that interfere with other states' measures to protect
visibility. This statutory requirement anticipates that a state may be
required to adjust its own emissions based on the impacts of those
emissions on other states. Our Regional Haze Rule, which was
promulgated through notice-and-comment rulemaking in 1999, also
requires that states develop ``coordinated emission management
strategies'' when necessary to prevent interstate visibility
impairment.\373\ Thus, while the CAA and our regulations do not allow
one state to ``control'' another's regional haze planning, they do
contemplate that a state may be required to prohibit emissions that
interfere with visibility in another state's Class I areas.
---------------------------------------------------------------------------
\373\ 40 CFR 51.308(d)(3)(i).
---------------------------------------------------------------------------
As stated above, Arkansas elected to address the interstate
visibility transport requirement under section 110(a)(2)(D)(i)(II) by
relying on the BART determinations that are part of its
[[Page 66413]]
Regional Haze SIP submittal. Arkansas could have elected to address the
interstate visibility transport requirement under section
110(a)(2)(D)(i)(II) by other means; we have elsewhere determined that
states may also be able to satisfy the requirements of CAA section
110(a)(2)(D)(i)(II) with something less than an approved Regional Haze
SIP.\374\ In other words, an approved Regional Haze SIP is not the only
possible means to satisfy the requirements of CAA section
110(a)(2)(D)(i)(II) with respect to visibility; however such a SIP
could be sufficient.\375\ The approved portion of the Arkansas Regional
Haze SIP and our Regional Haze FIP together will ensure emissions
reductions from Arkansas sources consistent with the assumptions used
in the CENRAP modeling and meets Arkansas' obligations to address the
interstate visibility transport requirement under section
110(a)(2)(D)(i)(II).
---------------------------------------------------------------------------
\374\ See, e.g., Colorado (76 FR 22036 (April 20, 2011)), Idaho
(76 FR 36329 (June 22, 2011)), and New Mexico (76 FR 52388 (August,
22, 2011)).
\375\ We've allowed states to rely on their approved regional
haze plan to meet the requirements of the visibility component of
110(a)(2)(D)(i)(II) because the regional haze plan achieved at least
as much emissions reductions as projected by the RPO modeling. See
76 FR 34608, June 14, 2011 (California); 79 FR 60985, October 9,
2014 (New Mexico); 76 FR 36329, June 22, 2011 (Idaho); and 76 FR
38997, July 5, 2011 (Oregon).
---------------------------------------------------------------------------
We address elsewhere in this document comments contending that
there is uncertainty in the CALPUFF modeling and uncertainty that our
proposed controls will result in actual visibility improvements.
VI. Final Action
We are finalizing a FIP to remedy the deficiencies in the Arkansas
Regional Haze SIP and Interstate Visibility Transport SIP to address
the visibility transport requirement under section 110(a)(2)(D)(i)(II)
for the 1997 8-hour ozone and PM2.5 NAAQS.
A. Regional Haze
Our final FIP includes SO2, NOX, and PM
emission limits for specific emission units in Arkansas to address the
BART requirements. The affected emission units are the AECC Bailey Unit
1; AECC McClellan Unit 1; AEP Flint Creek Unit 1; Entergy White Bluff
Units 1, 2, and Auxiliary Boiler; Entergy Lake Catherine Unit 4; and
Domtar Ashdown Mill Power Boilers No. 1 and 2. In addition, we are
requiring SO2 and NOX controls under reasonable
progress for Entergy Independence Units 1 and 2. We are also finalizing
compliance schedules and testing, reporting and recordkeeping
requirements for these emission units. Our final FIP requires the
following emission limits for these emission units:
Table 22--Final BART Emission Limits
----------------------------------------------------------------------------------------------------------------
Final SO2 emission Final NOX emission
Unit limit limit Final PM emission limit
----------------------------------------------------------------------------------------------------------------
Bailey Unit 1........................ 0.5% limit on sulfur 887 lb/hr.............. 0.5% limit on sulfur
content of fuel content of fuel
combusted. combusted.
McClellan Unit 1..................... 0.5% limit on sulfur 869.1 lb/hr \a\/705.8 0.5% limit on sulfur
content of fuel lb/hr \a\. content of fuel
combusted. combusted.
Flint Creek Unit 1................... 0.06 lb/MMBtu.......... 0.23 lb/MMBtu.......... EPA approved the
state's BART
determination in March
12, 2012 final action
(77 FR 14604).
White Bluff Unit 1................... 0.06 lb/MMBtu.......... 0.15 lb/MMBtu \b\/671 EPA approved the
lb/hr \c\. state's BART
determination in March
12, 2012 final action
(77 FR 14604).
White Bluff Unit 2................... 0.06 lb/MMBtu.......... 0.15 lb/MMBtu \b\/671 EPA approved the
lb/hr \c\. state's BART
determination in March
12, 2012 final action
(77 FR 14604).
White Bluff Auxiliary Boiler......... 105.2 lb/hr............ 32.2 lb/hr............. 4.5 lb/hr.
Lake Catherine Unit 4 \d\............ EPA approved the 0.22 lb/MMBtu.......... EPA approved the
state's BART state's BART
determination in March determination in March
12, 2012 final action 12, 2012 final action
(77 FR 14604). (77 FR 14604).
Domtar Ashdown Mill Power Boiler No. 504 lb/day............. 207.4 lb/hr............ EPA approved the
1. state's BART
determination in March
12, 2012 final action
(77 FR 14604).
Domtar Ashdown Mill Power Boiler No. 91.5 lb/hr............. 345 lb/hr.............. PM BART shall be
2. satisfied by relying
on the applicable PM
standard under 40 CFR
part 63, subpart DDDDD
\e\
----------------------------------------------------------------------------------------------------------------
\a\ Emission limit of 869.1 lb/hr applies to the natural gas-firing scenario; emission limit of 705.8 lb/hr
applies to the fuel oil-firing scenario.
\b\ Emission limit of 0.15 lb/MMBtu applies when unit is operated at 50% or greater of the unit's maximum heat
input rating.
\c\ Emission limit of 671 lb/hr applies when the unit is operated at less than 50% of the unit's maximum heat
input rating.
\d\ Emission limit for NOX applies to the natural gas-firing scenario. The unit shall not burn fuel oil until
BART determinations for SO2, NOX, and PM are promulgated for the unit for the fuel oil-firing scenario through
EPA approval of a SIP revision or a FIP.
\e\ The facility shall rely on the applicable PM standard under 40 CFR part 63, subpart DDDDD--National Emission
Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers
and Process Heaters, as revised, to satisfy the PM BART requirement.
Table 23--Final Reasonable Progress Emission Limits for Sources not
Subject to BART
------------------------------------------------------------------------
Final SO2 emission Final NOX emission
Unit limit limit
------------------------------------------------------------------------
Independence Unit 1............. 0.06 lb/MMBtu..... 0.15 lb/MMBtu a/
671 lb/hr b
[[Page 66414]]
Independence Unit 2............. 0.06 lb/MMBtu..... 0.15 lb/MMBtu a/
671 lb/hr b
------------------------------------------------------------------------
a Emission limit of 0.15 lb/MMBtu applies when unit is operated at 50%
or greater of the unit's maximum heat input rating.
b Emission limit of 671 lb/hr applies when the unit is operated at less
than 50% of the unit's maximum heat input rating.
Based on our technical analysis, we have calculated the following
RPGs for the 20% worst days for Arkansas' Class I areas:
Table 24--Reasonable Progress Goals for 2018 for Caney Creek and Upper
Buffalo
------------------------------------------------------------------------
2018 RPG 20%
Class I area Worst days
(dv)
------------------------------------------------------------------------
Caney Creek............................................. 22.47
Upper Buffalo........................................... 22.51
------------------------------------------------------------------------
B. Interstate Visibility Transport
We are finalizing our determination that the control measures in
the approved portion of the Arkansas Regional Haze SIP and our final
FIP are sufficient to prevent Arkansas' emissions from interfering with
other states' required measures to protect visibility. Thus, the
combined measures from both plans satisfy the interstate transport
visibility requirement of CAA section 110(a)(2)(D)(i)(II) for the 1997
8-hour ozone and the 1997 PM2.5 NAAQS.
VII. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and Executive
Order 13563: Improving Regulation and Regulatory Review
This action is exempt from review by the Office of Management and
Budget (OMB) because it imposes requirements that apply and are
tailored to only six individual power plants (AECC Bailey; AECC
McClellan; AEP Flint Creek; Entergy White Bluff; Entergy Lake
Catherine; and Entergy Independence) and one paper mill in Arkansas
(Domtar Ashdown Paper Mill). This FIP is not a rule of general
applicability. Thus, it is not a ``rule'' or ``regulation'' within the
meaning of E.O. 12866, and this action is not a ``regulatory action''
subject to 12866.
B. Paperwork Reduction Act (PRA)
This action does not impose an information collection burden under
the provisions of the PRA, 44 U.S.C. 3501 et seq. Under the PRA, a
``collection of information'' is defined as a requirement for ``answers
to * * * identical reporting or recordkeeping requirements imposed on
ten or more persons * * *'' 44 U.S.C. 3502(3)(A). Because the FIP
applies to only seven facilities, the Paperwork Reduction Act does not
apply. See 5 CFR 1320.3(c).
C. Regulatory Flexibility Act (RFA)
I certify that this action will not have a significant economic
impact on a substantial number of small entities under the RFA. This
action will not impose any requirements on small entities. This FIP
will apply to seven facilities, none of which fall under the definition
of small entities.
D. Unfunded Mandates Reform Act (UMRA)
EPA has determined that Title II of the UMRA does not apply to this
rule. In 2 U.S.C. 1502(1) all terms in Title II of UMRA have the
meanings set forth in 2 U.S.C. 658, which further provides that the
terms ``regulation'' and ``rule'' have the meanings set forth in 5
U.S.C. 601(2). Under 5 U.S.C. 601(2), ``the term `rule' does not
include a rule of particular applicability relating to . . .
facilities.'' Because this rule is a rule of particular applicability
relating to seven named facilities, EPA has determined that it is not a
``rule'' for the purposes of Title II of the UMRA.
E. Executive Order 13132: Federalism
This action does not have Federalism implications. It will not have
substantial direct effects on the states, on the relationship between
the national government and the states, or on the distribution of power
and responsibilities among the various levels of government. The final
rule does not impose significant economic costs on state or local
governments. Thus, Executive Order 13132 does not apply to the final
rule.
F. Executive Order 13175: Coordination With Indian Tribal Governments
This action does not have tribal implications as specified in
Executive Order 13175. This action applies to seven facilities in
Arkansas and to Federal Class I areas in Arkansas. This action does not
apply on any Indian reservation land, any other area where EPA or an
Indian tribe has demonstrated that a tribe has jurisdiction, or non-
reservation areas of Indian country. Thus, Executive Order 13175 does
not apply to this action.
G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
The EPA interprets Executive Order 13045 as applying only to those
regulatory actions that concern environmental health or safety risks
that the EPA has reason to believe may disproportionately affect
children, per the definition of ``covered regulatory action'' in
section 2-202 of the Executive Order. This action is not subject to
Executive Order 13045 because it implements specific standards
established by Congress in statutes.
H. Executive Order 13211: Actions That Significantly Affect Energy
Supply, Distribution or Use
This action is not subject to Executive Order 13211 because it is
not a significant regulatory action under Executive Order 12866.
I. National Technology Transfer and Advancement Act
This action involves technical standards. Section 12(d) of the
National Technology Transfer and Advancement Act of 1995 (``NTTAA''),
Public Law 104-113, 12(d) (15 U.S.C. 272 note) directs EPA to use
voluntary consensus standards in its regulatory activities unless to do
so would be inconsistent with applicable law or otherwise impractical.
Voluntary consensus standards are technical standards (e.g., materials
specifications, test methods, sampling procedures, and business
practices) that are developed or adopted by voluntary consensus
standards bodies. NTTAA directs EPA to provide Congress, through OMB,
explanations when the Agency decides not to use available and
applicable voluntary consensus standards. This rule would require the
seven affected facilities to meet the applicable monitoring
requirements of 40 CFR part 75. Part 75 already incorporates a number
of voluntary consensus standards. Consistent with the Agency's
Performance Based Measurement System (PBMS), part 75 sets forth
performance criteria that allow the use of alternative methods to the
ones set
[[Page 66415]]
forth in part 75. The PBMS approach is intended to be more flexible and
cost-effective for the regulated community; it is also intended to
encourage innovation in analytical technology and improved data
quality. At this time, EPA is not recommending any revisions to part
75; however, EPA periodically revises the test procedures set forth in
part 75. When EPA revises the test procedures set forth in part 75 in
the future, EPA will address the use of any new voluntary consensus
standards that are equivalent. Currently, even if a test procedure is
not set forth in part 75, EPA is not precluding the use of any method,
whether it constitutes a voluntary consensus standard or not, as long
as it meets the performance criteria specified; however, any
alternative methods must be approved through the petition process under
40 CFR 75.66 before they are used.
J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations
The EPA believes the human health or environmental risk addressed
by this action will not have potential disproportionately high and
adverse human health or environmental effects on minority, low-income,
or indigenous populations because it increases the level of
environmental protection for all affected populations without having
any disproportionately high and adverse human health or environmental
effects on any population, including any minority or low-income
population. This FIP limits emissions of SO2,
NOX, and PM from seven facilities in Arkansas.
K. Congressional Review Act
The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the
Small Business Regulatory Enforcement Fairness Act of 1996, generally
provides that before a rule may take effect, the agency promulgating
the rule must submit a rule report, which includes a copy of the rule,
to each House of the Congress and to the Comptroller General of the
United States. EPA will submit a report containing this action and
other required information to the U.S. Senate, the U.S. House of
Representatives, and the Comptroller General of the United States prior
to publication of the rule in the Federal Register. A major rule cannot
take effect until 60 days after it is published in the Federal
Register. This action is not a ``major rule'' as defined by 5 U.S.C.
804(2). This rule will be effective on October 27, 2016.
L. Judicial Review
Under section 307(b)(1) of the Clean Air Act, petitions for
judicial review of this action must be filed in the United States Court
of Appeals for the appropriate circuit by November 28, 2016. Filing a
petition for reconsideration by the Administrator of this final rule
does not affect the finality of this action for the purposes of
judicial review nor does it extend the time within which a petition for
judicial review may be filed, and shall not postpone the effectiveness
of such rule or action. This action may not be challenged later in
proceedings to enforce its requirements. (See CAA section 307(b)(2).)
List of Subjects in 40 CFR Part 52
Environmental protection, Air pollution control, Incorporation by
reference, Nitrogen dioxide, Ozone, Particulate matter, Reporting and
recordkeeping requirements, Sulfur dioxides, Visibility, Interstate
transport of pollution, regional haze, Best available retrofit
technology.
Dated: August 31, 2016.
Gina McCarthy,
Administrator.
Title 40, chapter I, of the Code of Federal Regulations is amended
as follows:
PART 52--APPROVAL AND PROMULGATION OF IMPLEMENTATION PLANS
0
1. The authority citation for part 52 continues to read as follows:
Authority: 42 U.S.C. 7401 et seq.
Subpart E--Arkansas
0
2. Section 52.173 is amended by adding paragraphs (c) and (d) to read
as follows:
Sec. 52.173 Visibility protection.
* * * * *
(c) Federal implementation plan for regional haze. Requirements for
AECC Carl E. Bailey Unit 1; AECC John L. McClellan Unit 1; AEP Flint
Creek Unit 1; Entergy White Bluff Units 1, 2, and Auxiliary Boiler;
Entergy Lake Catherine Unit 4; Domtar Ashdown Paper Mill Power Boilers
No. 1 and 2; and Entergy Independence Units 1 and 2 affecting
visibility.
(1) Applicability. The provisions of this section shall apply to
each owner or operator, or successive owners or operators, of the
sources designated as: AECC Carl E. Bailey Unit 1; AECC John L.
McClellan Unit 1; AEP Flint Creek Unit 1; Entergy White Bluff Units 1,
2, and Auxiliary Boiler; Entergy Lake Catherine Unit 4; Domtar Ashdown
Paper Mill Power Boilers No. 1 and 2; and Entergy Independence Units 1
and 2.
(2) Definitions. All terms used in this part but not defined herein
shall have the meaning given them in the Clean Air Act and in parts 51
and 60 of this title. For the purposes of this section:
24-hour period means the period of time between 12:01 a.m. and 12
midnight.
Air pollution control equipment includes selective catalytic
control units, baghouses, particulate or gaseous scrubbers, and any
other apparatus utilized to control emissions of regulated air
contaminants which would be emitted to the atmosphere.
Boiler-operating-day for electric generating units listed under
paragraph (c)(1) of this section means any 24-hour period between 12
midnight and the following midnight during which any fuel is combusted
at any time at the steam generating unit, unless otherwise specified.
For power boilers listed under paragraph (c)(1) of this section, we
define boiler-operating-day as a 24-hr period between 6 a.m. and 6 a.m.
the following day during which any fuel is fed into and/or combusted at
any time in the power boiler.
Daily average means the arithmetic average of the hourly values
measured in a 24-hour period.
Heat input means heat derived from combustion of fuel in a unit and
does not include the heat input from preheated combustion air,
recirculated flue gases, or exhaust gases from other sources. Heat
input shall be calculated in accordance with 40 CFR part 75.
Owner or Operator means any person who owns, leases, operates,
controls, or supervises any of the units or power boilers listed under
paragraph (c)(1) of this section.
Regional Administrator means the Regional Administrator of EPA
Region 6 or his/her authorized representative.
Unit means one of the natural gas, fuel oil, or coal fired boilers
covered under paragraph (c) of this section.
(3) Emissions limitations for AECC Bailey Unit 1 and AECC McClellan
Unit 1. The individual SO2, NOX, and PM emission
limits for each unit are as listed in the following table.
[[Page 66416]]
----------------------------------------------------------------------------------------------------------------
Unit SO2 Emission limit NOX Emission limit PM Emission limit
----------------------------------------------------------------------------------------------------------------
AECC Bailey Unit 1................... Use of fuel with a 887 lb/hr.............. Use of fuel with a
sulfur content limit sulfur content limit
of 0.5% by weight.. of 0.5% by weight.
AECC McClellan Unit 1................ Use of fuel with a 869.1 lb/hr............ Use of fuel with a
sulfur content limit (Natural Gas firing)... sulfur content limit
of 0.5% by weight.. 705.8 lb/hr............ of 0.5% by weight.
(Fuel Oil firing)......
----------------------------------------------------------------------------------------------------------------
(4) Compliance dates for AECC Bailey Unit 1 and AECC McClellan
Unit. The owner or operator of each unit must comply with the
SO2 and PM requirements listed in paragraph (c)(3) of this
section by October 27, 2021. As of October 27, 2016, the owner or
operator of each unit shall not purchase fuel for combustion at the
unit that does not meet the sulfur content limit in paragraph (c)(3) of
this section. The owner or operator of each unit must comply with the
requirement in paragraph (c)(3) of this section to burn only fuel with
a sulfur content limit of 0.5% by weight by October 27, 2021. The owner
or operator of each unit must comply with the NOX emission
limits in paragraph (c)(3) of this section by October 27, 2016.
(5) Compliance determination and reporting and recordkeeping
requirements for AECC Bailey Unit 1 and AECC McClellan Unit--(i) SO2
and PM. To determine compliance with the SO2 and PM
requirements listed in paragraph (c)(3) of this section, the owner or
operator shall sample and analyze each shipment of fuel to determine
the sulfur content by weight, except for natural gas shipments. A
``shipment'' is considered delivery of the entire amount of each order
of fuel purchased. Fuel sampling and analysis may be performed by the
owner or operator of an affected unit, an outside laboratory, or a fuel
supplier. All records pertaining to the sampling of each shipment of
fuel as described above, including the results of the sulfur content
analysis, must be maintained by the owner or operator and made
available upon request to EPA and ADEQ representatives.
(ii) NOX. To determine compliance with the NOX emission
limits of paragraph (c)(3) of this section, the owner or operator shall
determine the average concentration (arithmetic average of three
contiguous one hour periods) of NOX as measured by the CEMS
and converted to pounds per hour using corresponding average
(arithmetic average of three contiguous one hour periods) stack gas
flow rates. Records of the NOX emissions rates must be
maintained by the owner or operator and made available upon request to
EPA and ADEQ representatives.
(iii) The owner or operator shall continue to maintain and operate
a CEMS for NOX on the units listed in paragraph (c)(3) of
this section in accordance with 40 CFR 60.8 and 60.13(e), (f), and (h),
and appendix B of part 60. The owner or operator shall comply with the
quality assurance procedures for CEMS found in 40 CFR part 75.
Compliance with the emission limits for NOX shall be
determined by using data from a CEMS.
(iv) Continuous emissions monitoring shall apply during all periods
of operation of the units listed in paragraph (c)(3) of this section,
including periods of startup, shutdown, and malfunction, except for
CEMS breakdowns, repairs, calibration checks, and zero and span
adjustments. Continuous monitoring systems for measuring NOX
and diluent gas shall complete a minimum of one cycle of operation
(sampling, analyzing, and data recording) for each successive 15-minute
period. Hourly averages shall be computed using at least one data point
in each fifteen minute quadrant of an hour. Notwithstanding this
requirement, an hourly average may be computed from at least two data
points separated by a minimum of 15 minutes (where the unit operates
for more than one quadrant in an hour) if data are unavailable as a
result of performance of calibration, quality assurance, preventive
maintenance activities, or backups of data from data acquisition and
handling system, and recertification events. When valid NOX
pounds per hour emission data are not obtained because of continuous
monitoring system breakdowns, repairs, calibration checks, or zero and
span adjustments, emission data must be obtained by using other
monitoring systems approved by the EPA to provide emission data for a
minimum of 18 hours in each 24-hour period and at least 22 out of 30
successive boiler operating days.
(6) Emissions limitations for AEP Flint Creek Unit 1 and Entergy
White Bluff Units 1 and 2. The individual SO2 and
NOX emission limits for each unit are as listed in the
following table, as specified in pounds per million British thermal
units (lb/MMBtu) or pounds per hour (lb/hr). The SO2
emission limits of 0.06 lb/MMBtu and the NOX emission limits
of 0.23 lb/MMBtu and 0.15 lb/MMBtu are on a rolling 30 boiler-
operating-day averaging period. The NOX emission limit of
671 lb/hr is on a rolling 3-hour average.
----------------------------------------------------------------------------------------------------------------
SO2 Emission NOX Emission
Unit limit (lb/ limit (lb/ NOX Emission
MMBtu) MMBtu) limit (lb/hr)
----------------------------------------------------------------------------------------------------------------
AEP Flint Creek Unit 1.......................................... 0.06 0.23 ..............
Entergy White Bluff Unit 1...................................... 0.06 0.15 671
Entergy White Bluff Unit 2...................................... 0.06 0.15 671
----------------------------------------------------------------------------------------------------------------
(7) Compliance dates for AEP Flint Creek Unit 1 and Entergy White
Bluff Units 1 and 2. The owner or operator of AEP Flint Creek Unit 1
must comply with the SO2 and NOX emission limits
listed in paragraph (c)(6) of this section by April 27, 2018. The owner
or operator of White Bluff Units 1 and 2 must comply with the
SO2 emission limit listed in paragraph (c)(6) of this
section by October 27, 2021, and must comply with the NOX
emission limits listed in paragraph (c) (6) of this section by April
27, 2018.
(8) Compliance determination and reporting and recordkeeping
requirements for AEP Flint Creek Unit 1 and Entergy White Bluff Units 1
and 2. (i) For purposes of determining compliance with the
SO2 and NOX emissions limits listed in paragraph
[[Page 66417]]
(c)(6) of this section for AEP Flint Creek Unit 1 and with the
SO2 emissions limit listed in paragraph (c)(6) of this
section for White Bluff Units 1 and 2, the emissions for each boiler-
operating-day for each unit shall be determined by summing the hourly
emissions measured in pounds of SO2 or pounds of
NOX. For each unit, heat input for each boiler-operating-day
shall be determined by adding together all hourly heat inputs, in
millions of BTU. Each boiler-operating-day of the 30-day rolling
average for a unit shall be determined by adding together the pounds of
SO2 or NOX from that day and the preceding 29
boiler-operating-days and dividing the total pounds of SO2
or NOX by the sum of the heat input during the same 30
boiler-operating-day period. The result shall be the 30 boiler-
operating-day rolling average in terms of lb/MMBtu emissions of
SO2 or NOX. If a valid SO2 or
NOX pounds per hour or heat input is not available for any
hour for a unit, that heat input and SO2 or NOX
pounds per hour shall not be used in the calculation of the 30 boiler-
operating-day rolling average for SO2 or NOX. For
each day, records of the total SO2 and NOX
emitted that day by each emission unit and the sum of the hourly heat
inputs for that day must be maintained by the owner or operator and
made available upon request to EPA and ADEQ representatives. Records of
the 30 boiler-operating-day rolling average for SO2 and
NOX for each unit as described above must be maintained by
the owner or operator for each boiler-operating-day and made available
upon request to EPA and ADEQ representatives.
(ii) For purposes of determining compliance with the 0.15 lb/MMBtu
NOX emissions limit listed in paragraph (c)(6) of this
section for White Bluff Units 1 and 2, the NOX emissions for
each unit shall be determined by the following procedure:
(A) Summing the total pounds of NOX emitted during the
current boiler-operating-day and the preceding 29 boiler-operating-days
while including only emissions during hours when the unit was
dispatched at 50% or greater of the unit's maximum heat input rating;
(B) Summing the total heat input in MMBtu to the unit during the
current boiler-operating-day and the preceding 29 boiler-operating-days
while including only the heat input during hours when the unit was
dispatched at 50% or greater of the unit's maximum heat input rating;
and
(C) Dividing the total pounds of NOX emitted as
calculated in step 1 by the total heat input to the unit as calculated
in step 2. The result shall be the 30 boiler-operating-day rolling
average in terms of lb/MMBtu emissions of NOX. If a valid
NOX pounds per hour or heat input is not available for any
hour for a unit, that heat input and NOX pounds per hour
shall not be used in the calculation of the 30 boiler-operating-day
rolling average for NOX. For each day, records for each unit
of the hours during which the unit was dispatched at 50% or greater of
the unit's maximum heat input rating, as well as NOX
emissions and hourly heat input for each of those hours must be
maintained by the owner or operator and made available upon request to
EPA and ADEQ representatives. Records of the 30 boiler-operating-day
rolling average for NOX for each unit as described above
must be maintained by the owner or operator for each boiler-operating-
day and made available upon request to EPA and ADEQ representatives.
(iii) For purposes of determining compliance with the 671 lb/hr
NOX emissions limit listed in paragraph (c)(6) of this
section for White Bluff Units 1 and 2, the NOX emissions for
each unit shall be determined by the following procedure:
(A) Summing the total pounds of NOX emitted during the
current hour and the preceding 2 hours during which the unit was
dispatched at less than 50% of the unit's maximum heat input rating;
and
(B) Dividing the total pounds of NOX emitted as
calculated in step 1 by 3. The result shall be the rolling 3-hour
average in terms of lb/hr emissions of NOX. If a valid
NOX pounds per hour is not available for any hour for a
unit, that NOX pounds per hour shall not be used in the
calculation of the rolling 3-hour average for NOX. For each
day, records for each unit of the hours during which the unit was
dispatched at less than 50% of each unit's maximum heat input rating,
as well as NOX emissions and hourly heat input for each of
those hours must be maintained by the owner or operator and made
available upon request to EPA and ADEQ representatives. Records of the
rolling 3-hour averages for NOX for each unit as described
above must be maintained for each day by the owner or operator and made
available upon request to EPA and ADEQ representatives.
(iv) The owner or operator shall continue to maintain and operate a
CEMS for SO2 and NOX on the units listed in
paragraph (c)(6) of this section in accordance with 40 CFR 60.8 and
60.13(e), (f), and (h), and appendix B of part 60. The owner or
operator shall comply with the quality assurance procedures for CEMS
found in 40 CFR part 75. Compliance with the emission limits for
SO2 and NOX shall be determined by using data
from a CEMS.
(v) Continuous emissions monitoring shall apply during all periods
of operation of the units listed in paragraph (c)(6) of this section,
including periods of startup, shutdown, and malfunction, except for
CEMS breakdowns, repairs, calibration checks, and zero and span
adjustments. Continuous monitoring systems for measuring SO2
and NOX and diluent gas shall complete a minimum of one
cycle of operation (sampling, analyzing, and data recording) for each
successive 15-minute period. Hourly averages shall be computed using at
least one data point in each fifteen minute quadrant of an hour.
Notwithstanding this requirement, an hourly average may be computed
from at least two data points separated by a minimum of 15 minutes
(where the unit operates for more than one quadrant in an hour) if data
are unavailable as a result of performance of calibration, quality
assurance, preventive maintenance activities, or backups of data from
data acquisition and handling system, and recertification events. When
valid SO2 or NOX pounds per hour emission data
are not obtained because of continuous monitoring system breakdowns,
repairs, calibration checks, or zero and span adjustments, emission
data must be obtained by using other monitoring systems approved by the
EPA to provide emission data for a minimum of 18 hours in each 24 hour
period and at least 22 out of 30 successive boiler operating days.
(9) Emissions limitations for Entergy White Bluff Auxiliary Boiler.
The individual SO2, NOX, and PM emission limits
for the unit are as listed in the following table in pounds per hour
(lb/hr).
----------------------------------------------------------------------------------------------------------------
SO2 Emission NOX Emission PM Emission
Unit limit (lb/hr) limit (lb/hr) limit (lb/hr)
----------------------------------------------------------------------------------------------------------------
Entergy White Bluff Auxiliary Boiler............................ 105.2 32.2 4.5
----------------------------------------------------------------------------------------------------------------
[[Page 66418]]
(10) Compliance dates for Entergy White Bluff Auxiliary Boiler. The
owner or operator of the unit must comply with the SO2,
NOX, and PM emission limits listed in paragraph (c)(9) of
this section by October 27, 2016.
(11) Compliance determination and reporting and recordkeeping
requirements for Entergy White Bluff Auxiliary Boiler. For purposes of
demonstrating compliance with the emission limits listed in paragraph
(c)(9) of this section, records of fuel oil analysis must be maintained
by the owner or operator and made available upon request to EPA and
ADEQ representatives.
(12) Emissions limitations for Entergy Lake Catherine Unit 4. The
individual NOX emission limit for the unit for natural gas
firing is as listed in the following table in pounds per million
British thermal units (lb/MMBtu) as averaged over a rolling 30 boiler-
operating-day period. The unit must not burn fuel oil until BART
determinations are promulgated for the unit for SO2,
NOX, and PM for the fuel oil firing scenario through a FIP
and/or through EPA action upon and approval of revised BART
determinations submitted by the State as a SIP revision.
------------------------------------------------------------------------
NOX Emission
limit--natural
Unit gas firing (lb/
MMBtu)
------------------------------------------------------------------------
Entergy Lake Catherine Unit 4........................... 0.22
------------------------------------------------------------------------
(13) Compliance dates for Entergy Lake Catherine Unit 4. The owner
or operator of the unit must comply with the NOX emission
limit listed in paragraph (c)(12) of this section by October 27, 2019.
(14) Compliance determination and reporting and recordkeeping
requirements for Entergy Lake Catherine Unit 4. (i) NOX
emissions for each day shall be determined by summing the hourly
emissions measured in pounds of NOX. The heat input for each
boiler-operating-day shall be determined by adding together all hourly
heat inputs, in millions of BTU. Each boiler-operating-day of the
thirty-day rolling average for the unit shall be determined by adding
together the pounds of NOX from that day and the preceding
29 boiler-operating-days and dividing the total pounds of
NOX by the sum of the heat input during the same 30 boiler-
operating-day period. The result shall be the 30 boiler-operating-day
rolling average in terms of lb/MMBtu emissions of NOX. If a
valid NOX pounds per hour or heat input is not available for
any hour for the unit, that heat input and NOX pounds per
hour shall not be used in the calculation of the 30 boiler-operating-
day rolling average for NOX. For each day, records of the
total NOX emitted that day by the unit and the sum of the
hourly heat inputs for that day must be maintained by the owner or
operator and made available upon request to EPA and ADEQ
representatives. Records of the 30 boiler-operating-day rolling average
for NOX for the unit as described above must be maintained
by the owner or operator for each boiler-operating-day and made
available upon request to EPA and ADEQ representatives.
(ii) The owner or operator shall continue to maintain and operate a
CEMS on the unit listed in paragraph (c)(12) of this section in
accordance with 40 CFR part 75, Appendix E as long as the unit meets
the definition of a peaking unit under 40 CFR part 75. The owner or
operator shall comply with the quality assurance procedures for CEMS
found in 40 CFR part 75.
(iii) Continuous emissions monitoring shall apply during all
periods of operation of the unit listed in paragraph (c)(12) of this
section, including periods of startup, shutdown, and malfunction,
except for CEMS breakdowns, repairs, calibration checks, and zero and
span adjustments.
(15) Emissions Limitations for Domtar Ashdown Paper Mill Power
Boiler No. 1. The SO2 emission limit for the boiler is as
listed in the following table in pounds per day (lb/day) as averaged
over a rolling 30 boiler-operating-day period. The NOX
emission limit for the boiler is as listed in the following table in
pounds per hour (lb/hr).
------------------------------------------------------------------------
SO2 Emission NOX Emission
Unit limit (lb/day) limit (lb/hr)
------------------------------------------------------------------------
Domtar Ashdown Paper Mill Power Boiler 504 207.4
No. 1..................................
------------------------------------------------------------------------
(16) Compliance dates for Domtar Ashdown Mill Power Boiler No. 1.
The owner or operator of the boiler must comply with the SO2
and NOX emission limits listed in paragraph (c)(15) of this
section by November 28, 2016.
(17) Compliance determination and reporting and recordkeeping
requirements for Domtar Ashdown Paper Mill Power Boiler No. 1. (i)(A)
SO2 emissions resulting from combustion of fuel oil shall be
determined by assuming that the SO2 content of the fuel
delivered to the fuel inlet of the combustion chamber is equal to the
SO2 being emitted at the stack. The owner or operator must
maintain records of the sulfur content by weight of each fuel oil
shipment, where a ``shipment'' is considered delivery of the entire
amount of each order of fuel purchased. Fuel sampling and analysis may
be performed by the owner or operator, an outside laboratory, or a fuel
supplier. All records pertaining to the sampling of each shipment of
fuel oil, including the results of the sulfur content analysis, must be
maintained by the owner or operator and made available upon request to
EPA and ADEQ representatives. SO2 emissions resulting from
combustion of bark shall be determined by using the following site-
specific curve equation, which accounts for the SO2
scrubbing capabilities of bark combustion:
Y= 0.4005 * X-0.2645
Where:
Y= pounds of sulfur emitted per ton of dry fuel feed to the boiler
X= pounds of sulfur input per ton of dry bark
(B) The owner or operator must confirm the site-specific curve
equation through stack testing. By October 27, 2017, the owner or
operator must provide a report to EPA showing confirmation of the site
specific-curve equation accuracy. Records of the quantity of fuel input
to the boiler for each fuel type for each day must be compiled no later
than 15 days after the end of the month and must be maintained by the
owner or operator and made available upon request to EPA and ADEQ
representatives. Each boiler-operating-day of the 30-day rolling
average for the boiler must be determined by adding together the pounds
of SO2 from that boiler-operating-day and the preceding 29
boiler-operating-days and dividing the total pounds of SO2
by the sum of the
[[Page 66419]]
total number of boiler operating days (i.e., 30). The result shall be
the 30 boiler-operating-day rolling average in terms of lb/day
emissions of SO2. Records of the total SO2
emitted for each day must be compiled no later than 15 days after the
end of the month and must be maintained by the owner or operator and
made available upon request to EPA and ADEQ representatives. Records of
the 30 boiler-operating-day rolling averages for SO2 as
described in this paragraph (c)(17)(i) must be maintained by the owner
or operator for each boiler-operating-day and made available upon
request to EPA and ADEQ representatives.
(ii) If the air permit is revised such that Power Boiler No. 1 is
permitted to burn only pipeline quality natural gas, this is sufficient
to demonstrate that the boiler is complying with the SO2
emission limit under paragraph (c)(15) of this section. The compliance
determination requirements and the reporting and recordkeeping
requirements under paragraph (c)(17)(i) of this section would not apply
and confirmation of the accuracy of the site-specific curve equation
under paragraph (c)(17)(i)(B) of this section through stack testing
would not be required so long as Power Boiler No. 1 is only permitted
to burn pipeline quality natural gas.
(iii) To demonstrate compliance with the NOX emission
limit under paragraph (c)(15) of this section, the owner or operator
shall conduct stack testing using EPA Reference Method 7E once every 5
years, beginning 1 year from the effective date of our final rule.
Records and reports pertaining to the stack testing must be maintained
by the owner or operator and made available upon request to EPA and
ADEQ representatives.
(iv) If the air permit is revised such that Power Boiler No. 1 is
permitted to burn only pipeline quality natural gas, the owner or
operator may demonstrate compliance with the NOX emission
limit under paragraph (c)(15) of this section by calculating
NOX emissions using fuel usage records and the applicable
NOX emission factor under AP-42, Compilation of Air
Pollutant Emission Factors, section 1.4, Table 1.4-1. Records of the
quantity of natural gas input to the boiler for each day must be
compiled no later than 15 days after the end of the month and must be
maintained by the owner or operator and made available upon request to
EPA and ADEQ representatives. Records of the calculation of
NOX emissions for each day must be compiled no later than 15
days after the end of the month and must be maintained by the owner or
operator and made available upon request to EPA and ADEQ
representatives. Each boiler-operating-day of the 30-day rolling
average for the boiler must be determined by adding together the pounds
of NOX from that day and the preceding 29 boiler-operating-
days and dividing the total pounds of NOX by the sum of the
total number of hours during the same 30 boiler-operating-day period.
The result shall be the 30 boiler-operating-day rolling average in
terms of lb/hr emissions of NOX. Records of the 30 boiler-
operating-day rolling average for NOX must be maintained by
the owner or operator for each boiler-operating-day and made available
upon request to EPA and ADEQ representatives. Under these
circumstances, the compliance determination requirements and the
reporting and recordkeeping requirements under paragraph (c)(17)(iii)
of this section would not apply.
(18) SO2 and NOX Emissions Limitations for Domtar Ashdown Paper
Mill Power Boiler No.2. The individual SO2 and
NOX emission limits for the boiler are as listed in the
following table in pounds per hour (lb/hr) as averaged over a rolling
30 boiler-operating-day period.
------------------------------------------------------------------------
SO2 Emission NOX Emission
Unit Limit (lb/hr) Limit (lb/hr)
------------------------------------------------------------------------
Domtar Ashdown Paper Mill Power Boiler 91.5 345
No. 2..................................
------------------------------------------------------------------------
(19) SO2 and NOX Compliance dates for Domtar Ashdown Mill Power
Boiler No. 2. The owner or operator of the boiler must comply with the
SO2 and NOX emission limits listed in paragraph
(c)(18) of this section by October 27, 2021.
(20) SO2 and NOX Compliance determination and reporting and
recordkeeping requirements for Domtar Ashdown Mill Power Boiler No. 2.
(i) NOX and SO2 emissions for each day shall be
determined by summing the hourly emissions measured in pounds of
NOX or pounds of SO2. Each boiler-operating-day
of the 30-day rolling average for the boiler shall be determined by
adding together the pounds of NOX or SO2 from
that day and the preceding 29 boiler-operating-days and dividing the
total pounds of NOX or SO2 by the sum of the
total number of hours during the same 30 boiler-operating-day period.
The result shall be the 30 boiler-operating-day rolling average in
terms of lb/hr emissions of NOX or SO2. If a
valid NOX pounds per hour or SO2 pounds per hour
is not available for any hour for the boiler, that NOX
pounds per hour shall not be used in the calculation of the 30 boiler-
operating-day rolling average for NOX. For each day, records
of the total SO2 and NOX emitted for that day by
the boiler must be maintained by the owner or operator and made
available upon request to EPA and ADEQ representatives. Records of the
30 boiler-operating-day rolling average for SO2 and
NOX for the boiler as described above must be maintained by
the owner or operator for each boiler-operating-day and made available
upon request to EPA and ADEQ representatives.
(ii) The owner or operator shall continue to maintain and operate a
CEMS for SO2 and NOX on the boiler listed in
paragraph (c)(18) of this section in accordance with 40 CFR 60.8 and
60.13(e), (f), and (h), and appendix B of part 60. The owner or
operator shall comply with the quality assurance procedures for CEMS
found in 40 CFR part 60. Compliance with the emission limits for
SO2 and NOX shall be determined by using data
from a CEMS.
(iii) Continuous emissions monitoring shall apply during all
periods of operation of the boiler listed in paragraph (c)(18) of this
section, including periods of startup, shutdown, and malfunction,
except for CEMS breakdowns, repairs, calibration checks, and zero and
span adjustments. Continuous monitoring systems for measuring
SO2 and NOX and diluent gas shall complete a
minimum of one cycle of operation (sampling, analyzing, and data
recording) for each successive 15-minute period. Hourly averages shall
be computed using at least one data point in each fifteen minute
quadrant of an hour. Notwithstanding this requirement, an hourly
average may be computed from at least two data points separated by a
minimum of 15 minutes (where the unit operates for more than one
quadrant in an hour) if data are unavailable as a result of performance
of calibration, quality assurance, preventive maintenance activities,
or
[[Page 66420]]
backups of data from data acquisition and handling system, and
recertification events. When valid SO2 or NOX
pounds per hour emission data are not obtained because of continuous
monitoring system breakdowns, repairs, calibration checks, or zero and
span adjustments, emission data must be obtained by using other
monitoring systems approved by the EPA to provide emission data for a
minimum of 18 hours in each 24 hour period and at least 22 out of 30
successive boiler operating days.
(iv) If the air permit is revised such that Power Boiler No. 2 is
permitted to burn only pipeline quality natural gas, this is sufficient
to demonstrate that the boiler is complying with the SO2
emission limit under paragraph (c)(18) of this section. Under these
circumstances, the compliance determination requirements under
paragraphs (c)(20)(i) through (iii) of this section would not apply to
the SO2 emission limit listed in paragraph (c)(18) of this
section.
(v) If the air permit is revised such that Power Boiler No. 2 is
permitted to burn only pipeline quality natural gas and the operation
of the CEMS is not required under other applicable requirements, the
owner or operator may demonstrate compliance with the NOX
emission limit under paragraph (c)(18) of this section by calculating
NOX emissions using fuel usage records and the applicable
NOX emission factor under AP-42, Compilation of Air
Pollutant Emission Factors, section 1.4, Table 1.4-1. Records of the
quantity of natural gas input to the boiler for each day must be
compiled no later than 15 days after the end of the month and must be
maintained by the owner or operator and made available upon request to
EPA and ADEQ representatives. Records of the calculation of
NOX emissions for each day must be compiled no later than 15
days after the end of the month and must be maintained and made
available upon request to EPA and ADEQ representatives. Each boiler-
operating-day of the 30-day rolling average for the boiler must be
determined by adding together the pounds of NOX from that
day and the preceding 29 boiler-operating-days and dividing the total
pounds of NOX by the sum of the total number of hours during
the same 30 boiler-operating-day period. The result shall be the 30
boiler-operating-day rolling average in terms of lb/hr emissions of
NOX. Records of the 30 boiler-operating-day rolling average
for NOX must be maintained by the owner or operator for each
boiler-operating-day and made available upon request to EPA and ADEQ
representatives. Under these circumstances, the compliance
determination requirements under paragraphs (c)(20)(i) through (iii) of
this section would not apply to the NOX emission limit.
(21) PM BART Requirements for Domtar Ashdown Paper Mill Power
Boiler No.2. The owner or operator must rely on the applicable PM
standard required under 40 CFR part 63, subpart DDDDD--National
Emission Standards for Hazardous Air Pollutants for Major Sources:
Industrial, Commercial, and Institutional Boilers and Process Heaters,
as revised, to satisfy the PM BART requirement. Compliance with the
applicable PM standard under 40 CFR part 63 subpart DDDDD, as revised,
shall demonstrate compliance with the PM BART requirement.
(22) PM compliance dates for Domtar Ashdown Mill Power Boiler No.
2. The owner or operator of the boiler must comply with the PM BART
requirement listed in paragraph (c)(21) of this section by November 28,
2016.
(23) Alternative PM Compliance Determination for Domtar Ashdown
Paper Mill Power Boiler No.2. If the air permit is revised such that
Power Boiler No. 2 is permitted to burn only pipeline quality natural
gas, this is sufficient to demonstrate that the boiler is complying
with the PM BART requirement under paragraph (c)(21) of this section.
(24) Emissions limitations for Entergy Independence Units 1 and 2.
The individual emission limits for each unit are as listed in the
following table in pounds per million British thermal units (lb/MMBtu)
or pounds per hour (lb/hr). The SO2 emission limit and the
NOX emission limits listed in the table as lb/MMBtu are on a
rolling 30 boiler-operating-day averaging period. The NOX
emission limit of 671 lb/hr is on a rolling 3-hour average.
----------------------------------------------------------------------------------------------------------------
SO2 Emission NOX Emission
Unit limit (lb/ limit (lb/ NOX Emission
MMBtu) MMBtu) Limit (lb/hr)
----------------------------------------------------------------------------------------------------------------
Entergy Independence Unit 1..................................... 0.06 0.15 671
Entergy Independence Unit 2..................................... 0.06 0.15 671
----------------------------------------------------------------------------------------------------------------
(25) Compliance dates for Entergy Independence Units 1 and 2. The
owner or operator of each unit must comply with the SO2
emission limit in paragraph (c)(24) of this section by October 27, 2021
and with the NOX emission limits by April 27, 2018.
(26) Compliance determination and reporting and recordkeeping
requirements for Entergy Independence Units 1 and 2. (i) For purposes
of determining compliance with the SO2 emissions limit
listed in paragraph (c)(24) of this section for each unit, the
SO2 emissions for each boiler-operating-day shall be
determined by summing the hourly emissions measured in pounds of
SO2. For each unit, heat input for each boiler-operating-day
shall be determined by adding together all hourly heat inputs, in
millions of BTU. Each boiler-operating-day of the thirty-day rolling
average for a unit shall be determined by adding together the pounds of
SO2 from that day and the preceding 29 boiler-operating-days
and dividing the total pounds of SO2 by the sum of the heat
input during the same 30 boiler-operating-day period. The result shall
be the 30 boiler-operating-day rolling average in terms of lb/MMBtu
emissions of SO2. If a valid SO2 pounds per hour
or heat input is not available for any hour for a unit, that heat input
and SO2 pounds per hour shall not be used in the calculation
of the applicable 30 boiler-operating-days rolling average. For each
day, records of the total SO2 emitted that day by each
emission unit and the sum of the hourly heat inputs for that day must
be maintained by the owner or operator and made available upon request
to EPA and ADEQ representatives. . Records of the 30 boiler-operating-
day rolling average for each unit as described above must be maintained
by the owner or operator for each boiler-operating-day and made
available upon request to EPA and ADEQ representatives.
(ii) For purposes of determining compliance with the 0.15 lb/MMBtu
NOX emissions limit listed in paragraph (c)(24), the
NOX emissions for each unit shall be determined by the
following procedure:
(A) Summing the total pounds of NOX emitted during the
current boiler-operating-day and the preceding 29 boiler-operating-days
while including only emissions during hours when the unit was
dispatched at 50% or greater of the unit's maximum heat input rating;
[[Page 66421]]
(B) Summing the total heat input in MMBtu to the unit during the
current boiler-operating-day and the preceding 29 boiler operating days
while including only the heat input during hours when the unit was
dispatched at 50% or greater of the unit's maximum heat input rating;
and
(C) Dividing the total pounds of NOX emitted as
calculated in step 1 by the total heat input to the unit as calculated
in step 2. The result shall be the 30 boiler-operating-day rolling
average in terms of lb/MMBtu emissions of NOX. If a valid
NOX pounds per hour or heat input is not available for any
hour for a unit, that heat input and NOX pounds per hour
shall not be used in the calculation of the 30 boiler-operating-day
rolling average for NOX. For each day, records for each unit
of the hours during which the unit was dispatched at 50% or greater of
the unit's maximum heat input rating, as well as NOX
emissions and hourly heat input for each of those hours must be
maintained by the owner or operator and made available upon request to
EPA and ADEQ representatives. Records of the 30 boiler-operating-day
rolling average for NOX for each unit as described above
must be maintained by the owner or operator for each boiler-operating-
day and made available upon request to EPA and ADEQ representatives.
(iii) For purposes of determining compliance with the 671 lb/hr
NOX emissions limit listed in paragraph (c)(24), the
NOX emissions for each unit shall be determined by the
following procedure:
(A) Summing the total pounds of NOX emitted during the
current hour and the preceding 2 hours during which the unit was
dispatched at less than 50% of the unit's maximum heat input rating;
and
(B) Dividing the total pounds of NOX emitted as
calculated in step 1 by 3. The result shall be the rolling 3-hour
average in terms of lb/hr emissions of NOX. If a valid
NOX pounds per hour is not available for any hour for a
unit, that NOX pounds per hour shall not be used in the
calculation of the rolling 3-hour average for NOX. For each
day, records for each unit of the hours during which the unit was
dispatched at less than 50% of each unit's maximum heat input rating,
as well as NOX emissions and hourly heat input for each of
those hours must be maintained by the owner or operator and made
available upon request to EPA and ADEQ representatives. Records of the
rolling 3-hour averages for NOX for each unit as described
above must be maintained for each day by the owner or operator and made
available upon request to EPA and ADEQ representatives.
(iv) The owner or operator shall continue to maintain and operate a
CEMS for SO2 and NOX on the units listed in
paragraph (c)(24) in accordance with 40 CFR 60.8 and 60.13(e), (f), and
(h), and appendix B of part 60. The owner or operator shall comply with
the quality assurance procedures for CEMS found in 40 CFR part 75.
Compliance with the emission limits for SO2 and
NOX shall be determined by using data from a CEMS.
(v) Continuous emissions monitoring shall apply during all periods
of operation of the units listed in paragraph (c)(24) of this section,
including periods of startup, shutdown, and malfunction, except for
CEMS breakdowns, repairs, calibration checks, and zero and span
adjustments. Continuous monitoring systems for measuring SO2
and NOX and diluent gas shall complete a minimum of one
cycle of operation (sampling, analyzing, and data recording) for each
successive 15-minute period. Hourly averages shall be computed using at
least one data point in each fifteen minute quadrant of an hour.
Notwithstanding this requirement, an hourly average may be computed
from at least two data points separated by a minimum of 15 minutes
(where the unit operates for more than one quadrant in an hour) if data
are unavailable as a result of performance of calibration, quality
assurance, preventive maintenance activities, or backups of data from
data acquisition and handling system, and recertification events. When
valid SO2 or NOX pounds per hour emission data
are not obtained because of continuous monitoring system breakdowns,
repairs, calibration checks, or zero and span adjustments, emission
data must be obtained by using other monitoring systems approved by the
EPA to provide emission data for a minimum of 18 hours in each 24 hour
period and at least 22 out of 30 successive boiler operating days.
(27) Reporting and recordkeeping requirements. Unless otherwise
stated all requests, reports, submittals, notifications, and other
communications to the Regional Administrator required under paragraph
(c) of this section shall be submitted, unless instructed otherwise, to
the Director, Multimedia Planning and Permitting Division, U.S.
Environmental Protection Agency, Region 6, to the attention of Mail
Code: 6PD, at 1445 Ross Avenue, Suite 1200, Dallas, Texas 75202-2733.
For each unit subject to the emissions limitation under paragraph (c)
of this section, the owner or operator shall comply with the following
requirements, unless otherwise specified:
(i) For each emissions limit under paragraph (c) of this section
where compliance shall be determined by using data from a CEMS, comply
with the notification, reporting, and recordkeeping requirements for
CEMS compliance monitoring in 40 CFR 60.7(c) and (d).
(ii) [Reserved]
(28) Equipment operations. At all times, including periods of
startup, shutdown, and malfunction, the owner or operator shall, to the
extent practicable, maintain and operate the unit including associated
air pollution control equipment in a manner consistent with good air
pollution control practices for minimizing emissions. Determination of
whether acceptable operating and maintenance procedures are being used
will be based on information available to the Regional Administrator
which may include, but is not limited to, monitoring results, review of
operating and maintenance procedures, and inspection of the unit.
(29) Enforcement. (i) Notwithstanding any other provision in this
implementation plan, any credible evidence or information relevant as
to whether the unit would have been in compliance with applicable
requirements if the appropriate performance or compliance test had been
performed, can be used to establish whether or not the owner or
operator has violated or is in violation of any standard or applicable
emission limit in the plan.
(ii) Emissions in excess of the level of the applicable emission
limit or requirement that occur due to a malfunction shall constitute a
violation of the applicable emission limit.
(d) Measures Addressing Partial Disapproval of Portion of
Interstate Visibility Transport SIP for the 1997 8-hour ozone and
PM2.5 NAAQS. The deficiencies identified in EPA's partial
disapproval of the portion of the SIP pertaining to adequate provisions
to prohibit emissions in Arkansas from interfering with measures
required in another state to protect visibility, submitted on March 28,
2008, and supplemented on September 27, 2011 are satisfied by Sec.
52.173.
[FR Doc. 2016-22508 Filed 9-26-16; 8:45 am]
BILLING CODE 6560-50-P