Approval and Promulgation of Implementation Plans; Arkansas; Approval of Regional Haze State Implementation Plan Revision and Partial Withdrawal of Federal Implementation Plan, 62204-62240 [2018-26073]
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ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 52
[EPA–R06–OAR–2015–0189; FRL–9986–67–
Region 6]
Approval and Promulgation of
Implementation Plans; Arkansas;
Approval of Regional Haze State
Implementation Plan Revision and
Partial Withdrawal of Federal
Implementation Plan
Environmental Protection
Agency (EPA).
ACTION: Proposed rule.
AGENCY:
Pursuant to the Federal Clean
Air Act (CAA or the Act), the
Environmental Protection Agency (EPA)
is proposing to approve a portion of the
revision to the Arkansas State
Implementation Plan (SIP) that
addresses certain requirements of the
CAA and the EPA’s regional haze rules
for the protection of visibility in
mandatory Class I Federal areas (Class I
areas) for the first implementation
period. The EPA is proposing to
approve the portions of the SIP revision
addressing the best available retrofit
technology (BART) requirements for
sulfur dioxide (SO2), particulate matter
(PM) and nitrogen oxide (NOX) for seven
electric generating units (EGUs) in
Arkansas. The EPA is also proposing to
approve the determination that no
additional controls at any Arkansas
sources are necessary under reasonable
progress; calculation of the revised
reasonable progress goals (RPGs) for
Arkansas’ Class I areas; certain
components of the long-term strategy for
making reasonable progress; the
clarification that both the 6A and 9A
Boilers at the Georgia-Pacific Crossett
Mill are BART-eligible; and the
additional information and technical
analysis in support of the determination
that the Georgia-Pacific Crossett Mill 6A
and 9A Boilers are not subject to BART.
In conjunction with our proposed
approval of portions of the SIP revision,
we are proposing to withdraw the
corresponding federal implementation
plan (FIP) provisions established in a
prior action to address regional haze
requirements for Arkansas.
DATES: Written comments must be
received on or before December 31,
2018.
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SUMMARY:
Submit your comments,
identified by Docket No. EPA–R06–
OAR–2015–0189, at https://
www.regulations.gov or via email to
R6AIR_ARHaze@epa.gov. Follow the
online instructions for submitting
ADDRESSES:
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comments. Once submitted, comments
cannot be edited or removed from
Regulations.gov. The EPA may publish
any comment received to its public
docket. Do not submit electronically any
information you consider to be
Confidential Business Information (CBI)
or other information whose disclosure is
restricted by statute. Multimedia
submissions (audio, video, etc.) must be
accompanied by a written comment.
The written comment is considered the
official comment and should include
discussion of all points you wish to
make. The EPA will generally not
consider comments or comment
contents located outside of the primary
submission (i.e. on the web, cloud, or
other file sharing system). For
additional submission methods, please
contact Dayana Medina,
medina.dayana@epa.gov. For the full
EPA public comment policy,
information about CBI or multimedia
submissions, and general guidance on
making effective comments, please visit
https://www2.epa.gov/dockets/
commenting-epa-dockets.
Docket: The index to the docket for
this action is available electronically at
www.regulations.gov and in hard copy
at the EPA Region 6, 1445 Ross Avenue,
Suite 700, Dallas, Texas. While all
documents in the docket are listed in
the index, some information may be
publicly available only at the hard copy
location (e.g., copyrighted material), and
some may not be publicly available at
either location (e.g., CBI).
FOR FURTHER INFORMATION CONTACT:
Dayana Medina, 214–665–7241,
medina.dayana@epa.gov. To inspect the
hard copy materials, please schedule an
appointment with Dayana Medina or
Mr. Bill Deese at 214–665–7253.
SUPPLEMENTARY INFORMATION:
Throughout this document wherever
‘‘we,’’ ‘‘us,’’ or ‘‘our’’ is used, we mean
the EPA.
Table of Contents
I. Background
A. The Regional Haze Program
B. Our Previous Actions on Arkansas
Regional Haze
II. Our Evaluation of Arkansas’ SO2 and PM
Regional Haze SIP Revision
A. Identification of BART-Eligible and
Subject-to-BART Sources
B. Arkansas’ Five-Factor Analyses for SO2
and PM BART
1. AECC Bailey Unit 1
a. SO2 BART Analysis and Determination
b. PM BART Analysis and Determination
2. AECC McClellan Unit 1
a. SO2 BART Analysis and Determination
b. PM BART Analysis and Determination
3. SWEPCO Flint Creek Plant Boiler No. 1
a. SO2 BART Analysis and Determination
4. Entergy Lake Catherine Unit 4
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5. Entergy White Bluff Units 1 and 2 and
the White Bluff Auxiliary Boiler
a. White Bluff Units 1 and 2 SO2 BART
Analysis and Determinations
b. White Bluff Auxiliary Boiler BART
Determinations
C. Reasonable Progress Analysis for SO2
1. Arkansas’ Discussion of Key Pollutants
and Source Category Contributions
a. Region-Wide PSAT Data for Caney Creek
and Upper Buffalo
b. Arkansas PSAT Data for Caney Creek
and Upper Buffalo
c. Arkansas’ Conclusions Regarding Key
Pollutants and Source Category
Contributions
2. Arkansas’ Analysis of Reasonable
Progress Factors Broadly Applicable to
Arkansas Sources
3. Identification of Potential Sources for
Evaluation of SO2 Controls Under
Reasonable Progress
4. Arkansas’ Reasonable Progress Analysis
for Independence Units 1 and 2
a. Arkansas’ Evaluation of the Reasonable
Progress Factors for SO2 for Entergy
Independence Units 1 and 2
b. Arkansas’ Determination Regarding
Reasonable Progress Requirements for
Independence
5. Arkansas’ Determination Regarding
Additional Controls Necessary Under
Reasonable Progress and Revised RPGs
6. EPA’s Evaluation and Conclusions on
Arkansas’ Reasonable Progress Analysis
and Revised RPGs
D. Long-Term Strategy
E. Required Consultation
F. Interstate Visibility Transport Under
Section 110(a)(2)(D)(i)(II)
G. Clean Air Act Section 110(l)
III. Proposed Action
A. Arkansas’ Regional Haze SIP Revision
B. Partial FIP Withdrawal
C. Clean Air Act Section 110(l)
IV. Incorporation by Reference
V. Statutory and Executive Order Reviews
I. Background
A. The Regional Haze Program
Regional haze is visibility impairment
that is produced by a multitude of
sources and activities that are located
across a broad geographic area and emit
fine particulates (PM2.5) (e.g., sulfates,
nitrates, organic carbon (OC), elemental
carbon (EC), and soil dust), and their
precursors (e.g., SO2, NOX, and in some
cases, ammonia (NH3) and volatile
organic compounds (VOCs)). Fine
particle precursors react in the
atmosphere to form PM2.5, which
impairs visibility by scattering and
absorbing light. This light scattering
reduces the clarity, color and visible
distance that one can see. Particulate
matter can also cause serious health
effects in humans (including premature
death, heart attacks, irregular heartbeat,
aggravated asthma, decreased lung
function and increased respiratory
symptoms) and contribute to
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environmental effects such as acid
deposition and eutrophication.
Data from the existing visibility
monitoring network, the ‘‘Interagency
Monitoring of Protected Visual
Environments’’ (IMPROVE) monitoring
network, show that at the time the
Regional Haze Rule was finalized in
1999, visibility impairment caused by
air pollution occurred virtually all the
time at most national parks and
wilderness areas. The average visual
range 1 in many Class I areas in the
western U.S. was 62–93 miles, but in
some Class I areas, these visual ranges
may have been impacted by natural
wildfire and dust episodes in addition
to anthropogenic impacts. In most of the
eastern Class I areas of the U.S., the
average visual range was less than 19
miles.2 CAA programs have reduced
emissions of some haze-causing
pollution, lessening some visibility
impairment and resulting in partially
improved average visual ranges.3
In section 169A of the 1977
Amendments to the CAA, Congress
created a program for protecting
visibility in the nation’s national parks
and wilderness areas. This section of the
CAA establishes as a national goal the
prevention of any future, and the
remedying of any existing, man-made
impairment of visibility in 156 national
parks and wilderness areas designated
as mandatory Class I Federal areas.4
Congress added section 169B to the
1 Visual range is the greatest distance, in
kilometers or miles, at which a dark object can be
discerned against the sky by a typical observer.
Visual range is inversely proportional to light
extinction (bext) by particles and gases and is
calculated as: Visual Range = 3.91/bext (Bennett,
M.G., The physical conditions controlling visibility
through the atmosphere; Quarterly Journal of the
Royal Meteorological Society, 1930, 56, 1–29). Light
extinction has units of inverse distance (i.e., Mm¥1
or inverse Megameters [mega = 106]).
2 64 FR 35715 (July 1, 1999).
3 An interactive ‘‘story map’’ depicting efforts and
recent progress by EPA and states to improve
visibility at national parks and wilderness areas
may be visited at: https://arcg.is/29tAbS3.
4 Areas designated as mandatory Class I Federal
areas consist of National Parks exceeding 6,000
acres, wilderness areas and national memorial parks
exceeding 5,000 acres, and all international parks
that were in existence on August 7, 1977. 42 U.S.C.
7472(a). In accordance with section 169A of the
CAA, EPA, in consultation with the Department of
Interior, promulgated a list of 156 areas where
visibility is identified as an important value. 44 FR
69122 (November 30, 1979). The extent of a
mandatory Class I area includes subsequent changes
in boundaries, such as park expansions. 42 U.S.C.
7472(a). Although states and tribes may designate
as Class I additional areas which they consider to
have visibility as an important value, the
requirements of the visibility program set forth in
section 169A of the CAA apply only to ‘‘mandatory
Class I Federal areas.’’ Each mandatory Class I
Federal area is the responsibility of a ‘‘Federal Land
Manager.’’ 42 U.S.C. 7602(i). When we use the term
‘‘Class I area’’ in this action, we mean a ‘‘mandatory
Class I Federal area.’’
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CAA in 1990 to address regional haze
issues, and the EPA promulgated
regulations addressing regional haze in
1999. The Regional Haze Rule 5 revised
the existing visibility regulations to add
provisions addressing regional haze
impairment and established a
comprehensive visibility protection
program for Class I areas. The
requirements for regional haze, found at
40 CFR 51.308 and 51.309, are included
in our visibility protection regulations at
40 CFR 51.300–309. The requirement to
submit a regional haze SIP revision at
periodic intervals applies to all 50
states, the District of Columbia, and the
Virgin Islands. States were required to
submit the first implementation plan
addressing regional haze visibility
impairment no later than December 17,
2007.6
Section 169A of the CAA directs
states to evaluate the use of retrofit
controls at certain larger, often undercontrolled, older stationary sources in
order to address visibility impacts from
these sources. Specifically, section
169A(b)(2)(A) of the CAA requires states
to revise their SIPs to contain such
measures as may be necessary to make
reasonable progress toward the natural
visibility goal, including a requirement
that certain categories of existing major
stationary sources 7 built between 1962
and 1977 procure, install, and operate
BART controls. Larger ‘‘fossil-fuel fired
steam electric plants’’ are one of these
source categories. Under the Regional
Haze Rule, states are directed to conduct
BART determinations for ‘‘BARTeligible’’ sources that may be
anticipated to cause or contribute to any
visibility impairment in a Class I area.
Sources that are reasonably anticipated
to cause or contribute to any visibility
impairment in a Class I area are
determined to be subject-to-BART. For
each source subject to BART, 40 CFR
51.308(e)(1)(ii)(A) requires that states (or
EPA, in the case of a FIP) identify the
level of control representing BART after
considering the factors set out in CAA
section 169A(g). The evaluation of
BART for EGUs that are located at fossilfuel fired power plants having a
generating capacity in excess of 750
megawatts (MW) must follow the
5 Here and elsewhere in this document, the term
‘‘Regional Haze Rule,’’ refers to the 1999 final rule
(64 FR 35714), as amended in 2005 (70 FR 39156,
July 6, 2005), 2006 (71 FR 60631, October 13, 2006),
2012 (77 FR 33656, June 7, 2012), and 2017 (82 FR
3078, January 10, 2017).
6 See 40 CFR 51.308(b). EPA’s regional haze
regulations require subsequent updates to the
regional haze SIPs. 40 CFR 51.308(f)–(i). The next
update is due by July 31, 2021.
7 See 42 U.S.C. 7491(g)(7) (listing the set of
‘‘major stationary sources’’ potentially subject-toBART).
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‘‘Guidelines for BART Determinations
Under the Regional Haze Rule’’ at
appendix Y to 40 CFR part 51
(hereinafter referred to as the ‘‘BART
Guidelines’’). Rather than requiring
source-specific BART controls, states
also have the flexibility to adopt an
emissions trading program or other
alternative program as long as the
alternative provides for greater
reasonable progress towards improving
visibility than BART.
The vehicle for ensuring continuing
progress towards achieving the natural
visibility goal is the submission of a
series of regional haze SIPs that contain
long-term strategies to make reasonable
progress towards natural visibility
conditions. As part of this process,
States also establish RPGs for every
Class I area to provide assessments of
the improvements in visibility
anticipated to result from the long-term
strategies. States have significant
flexibility in establishing long-term
strategies and RPGs,8 but must
determine whether additional control
measures beyond BART and other ‘‘on
the books’’ controls are needed for
reasonable progress based on
consideration of the following factors
set out in section 169A of the CAA: (1)
The costs of compliance; (2) the time
necessary for compliance; (3) the energy
and non-air quality environmental
impacts of compliance; and (4) the
remaining useful life of any potentially
affected sources. States must
demonstrate in their SIPs how these
factors are considered when selecting
measures for their long-term strategies
and calculating the associated RPGs for
each applicable Class I area. We
commonly refer to this as the
‘‘reasonable progress analysis’’ or ‘‘four
factor analysis.’’
B. Our Previous Actions on Arkansas
Regional Haze
Arkansas submitted a SIP revision on
September 9, 2008, to address the
requirements of the first regional haze
implementation period. On August 3,
2010, Arkansas submitted a SIP revision
with mostly non-substantive revisions
to Arkansas Pollution Control and
Ecology Commission (APCEC)
Regulation 19, Chapter 15.9 On
8 Guidance for Setting Reasonable Progress Goals
under the Regional Haze Program, June 1, 2007,
memorandum from William L. Wehrum, Acting
Assistant Administrator for Air and Radiation, to
EPA Regional Administrators, EPA Regions 1–10
(pp. 4–2, 5–1).
9 The September 9, 2008, SIP submittal included
APCEC Regulation 19, Chapter 15, which is the
state regulation that identified the BART-eligible
and subject-to-BART sources in Arkansas and
established BART emission limits for subject-to-
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September 27, 2011, the State submitted
supplemental information to address the
regional haze requirements. We are
hereafter referring to these regional haze
submittals collectively as the ‘‘2008
Arkansas Regional Haze SIP.’’ On March
12, 2012, we partially approved and
partially disapproved the 2008 Arkansas
Regional Haze SIP.10 On September 27,
2016, we promulgated a FIP (the
Arkansas Regional Haze FIP) addressing
the disapproved portions of the 2008
Arkansas Regional Haze SIP.11 Among
other things, the FIP established SO2,
NOX, and PM emission limits under the
BART requirements for nine units at six
facilities: AECC Bailey Plant Unit 1;
AECC McClellan Plant Unit 1; SWEPCO
Flint Creek Plant Boiler No. 1; Entergy
Lake Catherine Plant Unit 4; Entergy
White Bluff Plant Units 1 and 2; Entergy
White Bluff Auxiliary Boiler; and the
Domtar Ashdown Mill Power Boilers
No. 1 and 2. The FIP also established
SO2 and NOX emission limits under the
reasonable progress requirements for
Entergy Independence Units 1 and 2.
Following the issuance of the
Arkansas Regional Haze FIP, the State of
Arkansas and several industry parties
filed petitions for reconsideration and
an administrative stay of the final rule.12
On April 14, 2017, we announced our
decision to convene a proceeding to
reconsider several elements of the FIP,
as follows: Appropriate compliance
dates for the NOX emission limits for
Flint Creek Boiler No. 1, White Bluff
Units 1 and 2, and Independence Units
1 and 2; the low-load NOX emission
limits applicable to White Bluff Units 1
and 2 and Independence Units 1 and 2
during periods of operation at less than
50 percent of the unit’s maximum heat
input rating; the SO2 emission limits for
White Bluff Units 1 and 2; and the
compliance dates for the SO2 emission
limits for Independence Units 1 and 2.13
EPA also published a notice in the
Federal Register on April 25, 2017,
BART sources. The August 3, 2010, SIP revision did
not revise Arkansas’ list of BART-eligible and
subject-to-BART sources or revise any of the BART
requirements for affected sources. Instead, it
included mostly non-substantive revisions to the
state regulation.
10 77 FR 14604.
11 81 FR 66332; see also 81 FR 68319 (October 4,
2016) (correction).
12 See the docket associated with this proposed
rulemaking for a copy of the petitions for
reconsideration and administrative stay submitted
by the State of Arkansas; Entergy Arkansas Inc.,
Entergy Mississippi Inc., and Entergy Power LLC
(collectively ‘‘Entergy’’); AECC; and the Energy and
Environmental Alliance of Arkansas (EEAA).
13 Letter from E. Scott Pruitt, Administrator, EPA,
to Nicholas Jacob Bronni and Jamie Leigh Ewing,
Arkansas Attorney General’s Office (April 14, 2017).
A copy of this letter is included in the docket,
https://www.regulations.gov/document?D=EPAR06-OAR-2015-0189-0240.
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administratively staying the
effectiveness of the NOX compliance
dates in the FIP for the Flint Creek,
White Bluff, and Independence units, as
well as the compliance dates for the SO2
emission limits for the White Bluff and
Independence units for a period of 90
days.14 On July 13, 2017, the EPA
published a proposed rule to extend the
NOX compliance dates for Flint Creek
Boiler No. 1, White Bluff Units 1 and 2,
and Independence Units 1 and 2, by 21
months to January 27, 2020.15 However,
EPA did not take final action on the July
13, 2017, proposed rule because on July
12, 2017, Arkansas submitted a
proposed SIP revision with a request for
parallel processing, addressing the NOX
BART requirements for Bailey Unit 1,
McClellan Unit 1, Flint Creek Boiler No.
1, Lake Catherine Unit 4, White Bluff
Units 1 and 2, White Bluff Auxiliary
Boiler, as well as the reasonable
progress requirements with respect to
NOX (Arkansas Regional Haze NOX SIP
revision or Arkansas NOX SIP revision).
In a proposed rule published in the
Federal Register on September 11, 2017,
we proposed to approve the Arkansas
Regional Haze NOX SIP revision and to
withdraw the corresponding parts of the
Arkansas Regional Haze FIP.16 On
October 31, 2017, we received ADEQ’s
final Regional Haze NOX SIP revision
addressing NOX BART for EGUs and the
reasonable progress requirements with
respect to NOX for the first
implementation period. On February 12,
2018, we took final action to approve
the Arkansas Regional Haze NOX SIP
revision and to withdraw the
corresponding parts of the FIP.17
II. Our Evaluation of Arkansas’ SO2
and PM Regional Haze SIP Revision
On August 8, 2018, Arkansas
submitted a SIP revision (Arkansas
Regional Haze SO2 and PM SIP revision)
addressing all remaining disapproved
parts of the 2008 Regional Haze SIP,
with the exception of the BART and
associated long-term strategy
requirements for the Domtar Ashdown
Mill Power Boilers No. 1 and 2. The SIP
revision also includes a discussion on
Arkansas’ interstate visibility transport
requirements. We are proposing action
on a portion of the August 8, 2018,
Arkansas Regional Haze SO2 and PM
SIP revision in this Federal Register
notice, and we are also proposing to
withdraw the parts of the FIP
corresponding to our proposed
14 82
FR 18994.
FR 32284.
16 82 FR 42627.
17 83 FR 5927 and 83 FR 5915 (February 12,
2018).
15 82
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approvals. Since we are proposing to
withdraw certain portions of the FIP, we
are also proposing to redesignate the FIP
by revising the numbering of certain
paragraphs under section 40 CFR
52.173. Our proposed redesignation of
the numbering of these paragraphs is
non-substantive and does not mean we
are reopening these parts for public
comment in this proposed rulemaking.
We intend to propose action on the
portion of this SIP revision discussing
the interstate visibility transport
requirements for pollutants that affect
visibility in Class I areas in nearby states
in a future proposed rulemaking.
The Arkansas Regional Haze SO2 and
PM SIP revision submitted to us on
August 8, 2018, addresses the majority
of the remaining parts of the 2008
Regional Haze SIP that EPA
disapproved on March 12, 2012.18
Specifically, the August 8, 2018, SIP
revision revises ADEQ’s identification
of BART-eligible sources by now
identifying the 6A Boiler at the GeorgiaPacific Crossett Mill as BART-eligible;
provides additional information and
technical analysis in support of the
determination that the Georgia-Pacific
Crossett Mill 6A and 9A Boilers are not
subject to BART; 19 prohibits the
burning of fuel oil at Lake Catherine
Unit 4 until SO2 and PM BART
determinations for the fuel oil firing
scenario are approved into the SIP by
EPA; and addresses the following BART
requirements: SO2 and PM BART for
Bailey Unit 1 and McClellan Unit 1; SO2
BART for Flint Creek Boiler No. 1; SO2
BART for White Bluff Units 1 and 2; and
SO2, NOX, and PM BART for the White
Bluff Auxiliary Boiler. The SIP revision
also addresses the reasonable progress
requirements, arriving at the conclusion
that no additional controls at
Independence Units 1 and 2 or any
other Arkansas sources are necessary
under reasonable progress,20 and
establishes revised RPGs for Arkansas’
two Class I areas, the Caney Creek
Wilderness Area and the Upper Buffalo
Wilderness Area. Finally, the SIP
18 77
FR 14604.
eligible sources that are reasonably
anticipated to cause or contribute to any visibility
impairment in a Class I area are determined to be
subject-to-BART. In the 2008 Arkansas Regional
Haze SIP, ADEQ used a contribution threshold of
0.5 dv for determining whether a source
‘‘contributes’’ to visibility impairment and is thus
subject to BART.
20 In a SIP revision submitted on October 31,
2017, Arkansas provided a reasonable progress
analysis and reasonable progress determination
with respect to NOX, and we took final action to
approve the analysis and determination in a final
action published on February 12, 2018 (see 83 FR
5927). Thus, the August 8, 2018 SIP revision
addresses reasonable progress requirements with
respect to SO2 and PM emissions.
19 BART
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revision revises the State’s long-term
strategy by including in the long-term
strategy an SO2 emission limit of 0.60
lb/MMBtu for Independence Units 1
and 2 based on the use of low sulfur
coal, as well as each of the BART
measures listed above. The August 8,
2018, SIP revision does not address
BART for the Domtar Ashdown Mill
Power Boilers No. 1 and 2 and relies on
the Domtar BART emission limits from
our FIP and the 2012 partially approved
SIP for the associated long-term strategy
requirements.
The August 8, 2018, SIP revision is
the subject of this proposed action, in
conjunction with our proposed
withdrawal of the parts of the Arkansas
Regional Haze FIP corresponding to our
proposed approval. We are proposing to
approve ADEQ’s revised identification
of the 6A Boiler at the Georgia-Pacific
Crossett Mill as BART-eligible; the
additional information and technical
analysis presented in the SIP revision in
support of the determination that the
Georgia-Pacific Crossett Mill 6A and 9A
Boilers are not subject to BART; and the
state’s BART decisions for the seven
subject-to-BART units listed above. We
are proposing to withdraw our prior
approval of Arkansas’ reliance on
participation in the Cross-State Air
Pollution Rule (CSAPR) for ozone
season NOX to satisfy the NOX BART
requirement for the White Bluff
Auxiliary Boiler. The Arkansas Regional
Haze NOX SIP revision erroneously
stated that the Auxiliary Boiler
participates in CSAPR for ozone season
NOX and that the state was electing to
rely on participation in that trading
program to satisfy the Auxiliary Boiler’s
NOX BART requirements, and we
erroneously approved this
determination in a final action
published in the Federal Register on
February 12, 2018.21 We are proposing
to withdraw our approval of that
determination for the Auxiliary Boiler
and to replace it with our proposed
approval of a source specific NOX BART
emission limit contained in the
Arkansas Regional Haze SIP Revision
before us.
We are also proposing to approve
Arkansas’ reasonable progress
determinations for Independence Units
1 and 2 and all other sources in
Arkansas, and to approve the revised
RPGs contained in the August 8, 2018,
SIP revision. We are further proposing
to find that, based on the state’s
currently approved SIP and the analyses
and determinations we are proposing to
approve in this action, the state’s
reasonable progress obligations for the
21 83
FR 5927.
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first implementation period have been
satisfied. At this time, the majority of
the BART requirements for the Domtar
Ashdown Mill are satisfied by a FIP.22
The SIP revision explains that, based
upon the BART determinations and
analysis in that FIP, nothing further is
currently needed for reasonable progress
at the Domtar Ashdown Mill. EPA
agrees. If the State chooses to submit a
further SIP revision to address BART
requirements for Domtar Power Boilers
No. 1 and No. 2 that are currently
satisfied by the FIP, we will evaluate
that SIP submittal, including as well as
any conclusions ADEQ draws about the
adequacy of such SIP-based measures
for reasonable progress. We will also, at
that time, evaluate any changes in the
measures for the Domtar Ashdown Mill
relative to those currently in the FIP to
determine whether the calculation of
the reasonable progress goals for the
first implementation period continue to
be sufficient.
Finally, we are proposing to approve
the components of the long-term
strategy addressed by the August 8,
2018, SIP revision and to find that
Arkansas’ long-term strategy for
reasonable progress with respect to all
sources other than Domtar is approved.
The long-term strategy is the
compilation of all control measures a
state will use during the
implementation period of the specific
SIP submittal to make reasonable
progress towards the goal of natural
visibility conditions, including emission
limitations corresponding to BART
determinations. If the proposed
approvals of the BART measures and
the emission limitations for the
Independence facility addressed in this
action are finalized, those measures will
also be integrated into the State’s longterm strategy. Because the August 8,
2018, SIP revision does not address the
BART requirements for Domtar, that
component of the long-term strategy
will remain satisfied by the FIP unless
and until EPA has received and
approved a SIP revision containing the
required analyses and determinations
for this facility.
We are also proposing to withdraw
the majority of the Arkansas Regional
Haze FIP we promulgated on September
27, 2016. Upon finalization of this
proposed rulemaking, the majority of
remaining FIP provisions would be
replaced by the corresponding revisions
to the SIP that we are proposing to
approve in this proposed rulemaking.
22 We note that the PM determination for Domtar
Ashdown Mill Power Boiler No. 1 in the 2008 SIP
was approved in our 2012 rulemaking. (77 FR
14604, March 12, 2012).
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62207
Specifically, we are proposing to
withdraw the following components of
the FIP: The SO2 and PM BART
emission limits for Bailey Unit 1; the
SO2 and PM BART emission limits for
McClellan Unit 1; the SO2 BART
emission limit for Flint Creek Boiler No.
1; the SO2 BART emission limit for
White Bluff Units 1 and 2; the SO2 and
PM BART emission limits for the White
Bluff Auxiliary Boiler; the prohibition
on burning fuel oil at Lake Catherine
Unit 4; and the SO2 emission limits for
Independence Units 1 and 2 under the
reasonable progress provisions. Since
we are proposing to withdraw certain
portions of the FIP, we are also
proposing to redesignate the FIP by
revising the numbering of certain
paragraphs under section 40 CFR
52.173. Our proposed redesignation of
the numbering of these paragraphs is
non-substantive and does not mean we
are reopening these parts for public
comment in this proposed rulemaking.
The SIP revision also includes a
discussion on interstate visibility
transport. Specifically, the SIP revision
discusses the impacts of Arkansas
sources on Missouri’s Class I areas, as
well as the most recent IMPROVE
monitoring data for Missouri’s Class I
areas. The SIP revision concludes that
Missouri is on track to achieve its
visibility goals, that the visibility
progress observed indicates that sources
in Arkansas are not interfering with the
achievement of Missouri’s RPGs for the
Hercules-Glades Wilderness Area and
Mingo Wilderness Area, and that no
additional controls on sources within
Arkansas are necessary to ensure that
other states’ visibility goals for their
Class I areas are met. We are deferring
proposing action on the interstate
visibility transport portion of the SIP
revision until a future proposed
rulemaking.
A. Identification of BART-Eligible and
Subject-to-BART Sources
States are required to identify all the
BART-eligible sources within their
boundaries by utilizing the three
eligibility criteria in the BART
Guidelines 23 and the Regional Haze
Rule 24: (1) One or more emission units
at the facility fit within one of the 26
categories listed in the BART
Guidelines; (2) the emission unit(s)
began operation on or after August 6,
1962, and the unit was in existence on
August 6, 1977; and (3) the potential
emissions of any visibility impairing
pollutant from subject units are 250 tons
or more per year. Sources that meet
23 70
24 40
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these three criteria are considered
BART-eligible. Once a list of the BARTeligible sources within a state has been
compiled, states must determine
whether to make BART determinations
for all of them or whether some may not
reasonably be anticipated to cause or
contribute to any visibility impairment
in a Class I area and may thus not be
subject to further BART analysis or
requirements. The BART Guidelines
present several options that rely on
modeling and/or emissions analyses to
determine if a source may reasonably be
anticipated to cause or contribute to
visibility impairment in a Class I area.
A source that may not be reasonably
anticipated to cause or contribute to any
visibility impairment in any Class I area
is not ‘‘subject to BART,’’ and for such
sources, a state need not make a BART
determination.
In our March 12, 2012, final action on
the 2008 Arkansas Regional Haze SIP,
we approved Arkansas’ identification of
BART-eligible sources with the
exception of the Georgia-Pacific Crossett
Mill 6A Boiler.25 We also approved
Arkansas’ determination of which
sources are subject to BART, with the
exception of its determination that the
Georgia-Pacific Crossett Mill 6A and 9A
Boilers are not subject to BART. In that
final action, we determined that the
2008 Arkansas Regional Haze SIP did
not include sufficient documentation to
demonstrate that the 6A Boiler is not
BART-eligible and did not contain
sufficient documentation to demonstrate
that the 6A and 9A Boilers are not
subject to BART. In the Arkansas
Regional Haze FIP, we made the
determination that the 6A Boiler is
BART-eligible. We also noted that we
continued to agree with the state’s
previous determination from the 2008
Arkansas Regional Haze SIP that the 9A
Boiler is BART-eligible. Based on
additional information and a technical
analysis provided to the EPA by
Georgia-Pacific, EPA determined that
the 6A and 9A Boilers are not subject to
BART. In the August 8, 2018, Arkansas
Regional Haze SO2 and PM SIP revision,
Arkansas has made determinations
consistent with our findings in the FIP.
Specifically, Arkansas made a revision
to its identification of BART-eligible
sources,26 now identifying the 6A Boiler
at the Georgia-Pacific Crossett Mill as
BART-eligible. In the 2008 Arkansas
Regional Haze SIP, the state had already
identified the 9A Boiler at the GeorgiaPacific Crossett Mill as BART-eligible;
in the August 8, 2018, SIP revision, the
25 80
FR 18947.
26 See Arkansas Regional Haze SO and PM SIP
2
revision, Table 1, page 8 and 9.
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state made no changes to the
identification of the 9A Boiler as BARTeligible. In addition, Arkansas included
in the SIP revision a copy of the
technical analysis and other information
that was provided by Georgia-Pacific to
EPA, which we previously included in
the record for the Arkansas Regional
Haze FIP in support of our
determination that the 6A and 9A
Boilers are not subject to BART.27 As
Arkansas explains in the SIP revision,
Georgia-Pacific provided information
regarding revisions to emission limits
included in the facility’s permit and
additional dispersion modeling
conducted in 2011 using those revised
limits. The results of this 2011 BART
screening modeling demonstrated that
the maximum impact of the GeorgiaPacific Crossett Mill boilers on any
Class I area was less than the 0.5 dv
threshold used by ADEQ to determine
whether a BART-eligible source should
be considered subject to BART. Because
the 2011 BART screening modeling was
based on permit limits from a permit
revision issued in 2012 rather than on
maximum 24-hour emission rates from
the 2001–2003 baseline period, GeorgiaPacific also provided further
information regarding fuel usage during
the 2001–2003 baseline and performed
calculations using AP–42, Compilation
of Air Pollutant Emission Factors, to
estimate the 24-hour emission rates for
SO2, NOX, and PM10 for the 6A and 9A
Boilers for each day during the baseline
years. Georgia Pacific then identified the
maximum 24-hour emission rates for
each pollutant for the two boilers during
the 2001–2003 baseline period. A
comparison of the estimated maximum
24-hour emission rates with the
emission rates modeled in GeorgiaPacific’s 2011 BART screening modeling
demonstrates that the maximum 24hour emission rates from the 2001–2003
baseline were lower than the rates
modeled in the 2011 BART screening
modeling and lower than the boilers’
permit limits. Based upon the additional
information provided by GeorgiaPacific, ADEQ concluded that the 6A
and 9A Boilers are not subject to
BART.28 Thus, ADEQ revised its
identification of BART-eligible sources
by identifying the Georgia-Pacific Mill
27 See the documentation provided by Georgia
Pacific to EPA that was previously included in the
record for the Arkansas Regional Haze FIP. This
documentation is included in the docket at the
following location: https://www.regulations.gov/
searchResults?rpp=50&so=ASC&sb=docId&
po=0&dktid=EPA-R06-OAR-2015-0189.
28 ADEQ provides documentation in support of
the determination that the Georgia-Pacific Crossett
Mill 6A and 9A Boilers are not subject to BART in
Appendix A to the Arkansas Regional Haze SO2 and
PM SIP revision.
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6A Boiler as BART-eligible. Since ADEQ
previously determined in the 2008
Regional Haze SIP that the 9A Boiler is
BART-eligible, it made no change to that
previous determination. ADEQ did not
make changes to its list of subject-toBART sources, but did include in the
SIP revision the additional information
and technical analysis from GeorgiaPacific to support and document the
determination that the 6A and 9A
boilers are not subject to BART.
We are proposing to find that the
analysis and documentation provided
by Georgia-Pacific and included in the
Arkansas Regional Haze SO2 and PM
SIP revision appropriately and
sufficiently demonstrate that the 6A and
9A Boilers are not subject to BART. We
are proposing to approve ADEQ’s
revised determination that the 6A Boiler
is BART-eligible and concur that the 6A
and 9A Boilers are not subject to BART.
B. Arkansas’ Five-Factor Analyses for
SO2 and PM BART
In determining BART, the state must
consider the five statutory factors in
section 169A of the CAA: (1) The costs
of compliance; (2) the energy and nonair
quality environmental impacts of
compliance; (3) any existing pollution
control technology in use at the source;
(4) the remaining useful life of the
source; and (5) the degree of
improvement in visibility which may
reasonably be anticipated to result from
the use of such technology.29 All units
that are subject to BART must undergo
a BART analysis. The BART Guidelines
break the analysis down into five
steps:30
STEP 1—Identify All Available
Retrofit Control Technologies,
STEP 2—Eliminate Technically
Infeasible Options,
STEP 3—Evaluate Control
Effectiveness of Remaining Control
Technologies,
STEP 4—Evaluate Impacts and
Document the Results, and
STEP 5—Evaluate Visibility Impacts.
As mentioned previously, EPA
partially approved and partially
disapproved the 2008 Arkansas
Regional Haze SIP revision in a final
action published on March 12, 2012.31
Following our 2012 partial disapproval
of the 2008 Arkansas Regional Haze SIP,
ADEQ began the process of generating
additional technical information and
analyses from the companies whose
BART determinations we disapproved.
These analyses and technical
29 See
also 40 CFR 51.308(e)(1)(ii)(A).
FR 39103, 39164 (July 6, 2005) [40 CFR 51,
App. Y].
31 77 FR 14604.
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information were provided to EPA and
were the basis for our evaluation of
BART for subject-to-BART facilities in
the FIP. In turn, ADEQ relied on those
same analyses and technical
information in the state’s evaluation of
BART for subject-to-BART sources in
the Arkansas Regional Haze SO2 and PM
SIP revision, with the exception of
White Bluff Units 1 and 2, for which
updated technical information has been
provided by Entergy and is included in
the SIP revision. In evaluating the
Arkansas Regional Haze SO2 and PM
SIP revision, we reviewed each BART
analysis for SO2 and PM for each
subject-to-BART source and other
relevant information provided in the SIP
revision.
As noted above, we approved certain
parts of the 2008 Arkansas Regional
Haze SIP in 2012.32 The parts that we
approved in 2012 included PM BART
for Flint Creek Boiler No. 1; PM BART
for White Bluff Units 1 and 2; SO2 and
PM BART for the natural gas firing
scenario for Lake Catherine Unit 4; and
PM BART for Domtar Power Boiler No.
1. We also published a final action on
February 12, 2018, in which we
approved a SIP revision submitted by
ADEQ on October 31, 2017, to address
the regional haze requirements for NOX
for EGUs in Arkansas (‘‘Arkansas
Regional Haze NOX SIP Revision’’).33
That final action included approval of
Arkansas’ NOX BART determinations
for Bailey Unit 1; McClellan Unit 1;
Flint Creek Boiler No. 1; Lake Catherine
Unit 4 (for both the natural gas firing
and fuel oil firing scenarios); White
Bluff Units 1 and 2; and the White Bluff
Auxiliary Boiler; and removed the
corresponding portions of the Arkansas
Regional Haze FIP. Thus, the only BART
requirements currently addressed under
the Arkansas Regional Haze FIP are the
SO2 and PM BART requirements for
Bailey Unit 1; the SO2 and PM BART
requirements for McClellan Unit 1; the
SO2 BART requirements for Flint Creek
Boiler No. 1; the prohibition on burning
fuel oil at Lake Catherine Unit 4 until
SO2 and PM BART determinations for
the fuel oil firing scenario are approved
into the SIP by EPA; the SO2 BART
requirements for White Bluff Units 1
and 2; the SO2 and PM BART
requirements for the White Bluff
Auxiliary Boiler; the SO2 and NOX
BART requirements for the Domtar
Ashdown Mill Power Boiler No. 1; and
the SO2, NOX, and PM BART
requirements for the Domtar Ashdown
Mill Power Boiler No. 2. The Arkansas
Regional Haze SO2 and PM SIP revision
32 77
33 83
FR 14604.
FR 5927.
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addresses all these BART requirements
currently covered under the FIP, with
the exception of the requirements for
the Domtar Ashdown Mill Power
Boilers No. 1 and 2. As noted above, in
the Arkansas Regional Haze NOX SIP
revision, ADEQ erroneously stated that
the Auxiliary Boiler participated in
CSAPR for ozone season NOX and the
state decided to rely on participation in
that trading program to satisfy the
Auxiliary Boiler’s NOX BART
requirement. In a final action published
in the Federal Register on February 12,
2018, we took final action to approve
this SIP revision, including reliance on
CSAPR for ozone season NOX to satisfy
the Auxiliary Boiler’s NOX BART
requirement.34 Since the White Bluff
Auxiliary Boiler does not participate in
CSAPR for ozone season NOX, we are
proposing to withdraw our prior
approval of the NOX BART
determination for the Auxiliary Boiler
and to replace it with our proposed
approval of a source specific NOX BART
emission limit contained in the August
8, 2018, Arkansas Regional Haze SIP
revision. We discuss this in greater
detail in section II.B.5.b. of this
proposed action.
1. AECC Bailey Unit 1
The AECC Bailey Unit 1 has a wallfired boiler, a gross output of 122 MW,
and a maximum heat input rate of 1,350
million British thermal units per hour
(MMBtu/hr). The unit is currently
permitted to burn pipeline quality
natural gas and fuel oil. The fuel oil
burned is currently subject to a sulfur
content limit of 2.3% by weight. AECC
produced BART analyses dated March
2014 for Bailey Unit 1, which were
evaluated by EPA and largely formed
the basis for EPA’s SO2 and PM BART
evaluations in the FIP.35 The same
BART analyses 36 have now been
adopted and incorporated by ADEQ into
the Arkansas Regional Haze SO2 and PM
BART SIP revision to address the SO2
and PM BART requirements for Bailey
Unit 1.
a. SO2 BART Analysis and
Determination
In assessing SO2 BART, ADEQ
explained that AECC considered the five
BART factors. In assessing feasible
control technologies and their
34 83
FR 5927.
FR 18950.
36 ‘‘BART Five Factor Analysis, Arkansas Electric
Cooperative Corporation Bailey and McClellan
Generating Stations,’’ dated March 2014, Version 4,
prepared by Trinity Consultants Inc. in conjunction
with Arkansas Electric Cooperative Corporation,’’
which can be found in Appendix B to the Arkansas
Regional Haze SO2 and PM BART SIP Revision.
62209
effectiveness, AECC considered flue gas
desulfurization (FGD) systems and fuel
switching during fuel oil burning. Due
to the intrinsically low sulfur content of
natural gas, no control technologies
were evaluated for natural gas burning
scenarios. As such, the BART analysis
focused on fuel oil firing as the base
case. For fuel oil firing, fuel switching
was determined to be the only
technically feasible control option, and
thus AECC did not further consider FGD
for SO2 BART. The baseline fuel AECC
assumed in the BART analysis is No. 6
fuel oil with 1.81% sulfur content by
weight, which is based on the average
sulfur content of the fuel oil from the
most recent shipment received by the
facility in December 2006. ADEQ
explained that AECC evaluated
switching to the following fuel types:
1% sulfur No. 6 fuel oil, corresponding
to an estimated 45% control efficiency;
0.5% sulfur No. 6 fuel oil,
corresponding to 72% control
efficiency; and 0.05% sulfur diesel,
corresponding to 97% control
efficiency.37
In considering the costs of compliance
for fuel switching, AECC concluded that
the fuel switching options evaluated
would not require capital investments
in equipment, but instead the annual
costs would be based upon operation
and maintenance costs associated with
the different fuel types. AECC estimated
that the cost-effectiveness of switching
Bailey Unit 1 to No. 6 fuel oil with 1%
and 0.5% sulfur content by weight is
$1,198/ton and $2,559/ton, respectively.
Switching to diesel, which has 0.05%
sulfur content, is estimated to cost
$5,382/ton. ADEQ stated that the cost in
dollars per ton for diesel is out of the
range of what is typically considered
cost-effective, while the cost of both 1%
and 0.5% sulfur No. 6 fuel oil is
estimated to be within the range of what
is typically considered cost-effective.
ADEQ stated that AECC’s evaluation
did not identify any energy or non-air
quality environmental impacts
associated with switching to 1% sulfur
No. 6 fuel oil, 0.5% sulfur No. 6 fuel oil,
or diesel. In assessing the remaining
useful life of Bailey Unit 1, AECC
concluded that this factor does not
impact the annualized costs of the
evaluated control options since fuel
switching is not expected to require any
significant capital costs in this case.
35 80
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37 We also note that AECC evaluated switching to
natural gas as an available SO2 control option in its
SO2 BART analysis, but the evaluation of this
control option was not discussed by ADEQ in the
SIP revision. We discuss this issue in greater detail
below when we present our evaluation of the state’s
BART determination.
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In assessing visibility impacts, the
state’s submittal included CALPUFF
modeling evaluating the visibility
benefits of switching from the baseline
fuel oil (assuming 100% use of fuel oil)
to the various fuel switching options.
We summarize the results of that
modeling in Table 1.
TABLE 1—ANTICIPATED VISIBILITY BENEFIT DUE TO FUEL SWITCHING AT AECC BAILEY UNIT 1
[CALPUFF, 98th percentile]
Class I area
Caney Creek ....................................................................................
Upper Buffalo ...................................................................................
Hercules-Glades ..............................................................................
Mingo ...............................................................................................
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Visibility benefit of controls over baseline
(dv)
Baseline
visibility
impact
(dv)
No. 6 fuel oil—
1% sulfur
0.330
0.348
0.368
0.379
Switching to 1% sulfur No. 6 fuel oil
is anticipated to achieve visibility
benefits of approximately 0.137 dv at
Caney Creek, 0.154 dv at Upper Buffalo,
0.162 dv at Hercules-Glades, and 0.173
dv at Mingo over baseline visibility
conditions. Switching to 0.5% sulfur
No. 6 fuel oil is anticipated to achieve
visibility benefits of approximately
0.188 dv at Caney Creek, 0.221 dv at
Upper Buffalo, 0.233 dv at HerculesGlades, and 0.209 dv at Mingo over the
baseline. The visibility benefits of
switching to diesel are anticipated to be
even greater, with benefits of
approximately 0.246 dv at Caney Creek,
0.279 dv at Upper Buffalo, 0.299 dv at
Hercules-Glades, and 0.284 dv at Mingo
over the baseline.
Taking into consideration the costeffectiveness and the anticipated
visibility improvement of the fuel
switching options, ADEQ concurred
with AECC’s recommendation that SO2
BART for AECC Bailey Unit 1 be
determined to be the use of fuel with a
sulfur content by weight of 0.5% or less.
We note that switching to diesel
would result in additional reductions in
SO2 emissions, but the additional costs
per ton for doing so would be high in
comparison to the additional visibility
benefits. We also note that AECC
evaluated switching to natural gas as an
available SO2 control option in its SO2
BART analysis,38 but the evaluation of
this control option in the SO2 BART
analysis was not discussed by ADEQ in
the SIP revision. In its analysis, AECC
explained that switching to natural gas
may have an adverse energy impact
during periods of natural gas
curtailment and that the ability to burn
both fuel oil and natural gas was
important for the facility to maintain
electrical reliability.39 Therefore, AECC
did not recommend switching to natural
gas and instead recommended switching
to fuels with 0.5% sulfur content to be
SO2 BART for Bailey Unit 1.40 In the
Arkansas Regional Haze FIP, we agreed
with AECC’s recommendation, and
explained that the BART Guidelines
provide that it is not our intent to direct
subject-to-BART sources to switch fuel
forms, such as from coal or fuel oil to
natural gas (40 CFR part 51, Appendix
Y, section IV.D.1).41 We noted that since
natural gas has a sulfur content by
weight that is well below 0.5%, the
facility may elect to use this type of fuel
to comply with BART, but we did not
require a switch to natural gas for SO2
BART in the FIP.42 Therefore, we do not
find that ADEQ’s lack of consideration
of switching to natural gas as an SO2
control option in the SO2 BART analysis
for Bailey Unit 1 changes the result of
the BART analysis in this instance. We
are proposing to approve the state’s
determination that SO2 BART for AECC
Bailey Unit 1 is the use of fuel with a
sulfur content by weight of 0.5% or less.
We are also proposing to approve the
state’s determination that Bailey Unit 1
must comply with this BART
requirement no later than October 27,
2021, and that as of the effective date of
the Administrative Order, which is
August 7, 2018, the source shall not
purchase fuel that does not meet the
sulfur limit requirement for combustion
at Bailey Unit 1. These BART
requirements have now been made
38 See ‘‘BART Five Factor Analysis, Arkansas
Electric Cooperative Corporation Bailey and
McClellan Generating Stations, dated March 2014,
Version 4, prepared by Trinity Consultants Inc. in
conjunction with Arkansas Electric Cooperative
Corporation,’’ pages 5–1 to 5–14. This BART
analysis has been adopted and incorporated by
ADEQ into the SIP revision (see Appendix B to the
Arkansas Regional Haze SO2 and PM BART SIP
revision).
39 See ‘‘BART Five Factor Analysis, Arkansas
Electric Cooperative Corporation Bailey and
McClellan Generating Stations, dated March 2014,
Version 4, prepared by Trinity Consultants Inc. in
conjunction with Arkansas Electric Cooperative
Corporation,’’ pages 5–2, 5–10, and 5–14.
40 Id.
41 80 FR 18952 and 81 FR at 66339.
42 Id.
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No. 6 fuel oil—
0.5% sulfur
0.137
0.154
0.162
0.173
0.188
0.221
0.233
0.209
Diesel—
0.05% sulfur
0.246
0.279
0.299
0.284
enforceable by the state through an
Administrative Order that has been
adopted and incorporated in the SIP
revision. The Administrative Order for
AECC Bailey Unit 1 includes not only
the requirement to limit the sulfur
content of the fuel burned, but also
requirements for the source to sample
and analyze each shipment of fuel to
determine the sulfur content by weight
and maintain records pertaining to the
sampling of each fuel shipment to assess
compliance with the BART
requirements.43 We are proposing to
approve the state’s Administrative
Order, including the compliance
determination requirements contained
in the Administrative Order, into the
SIP. The state’s SO2 BART emission
limit and compliance date for Bailey
Unit 1 are consistent with the BART
decision EPA previously made in the
FIP we promulgated on September 27,
2016.44 We are concurrently proposing
to withdraw the FIP’s SO2 BART
requirements for Bailey Unit 1, as they
would be replaced by our approval of
the state’s SO2 BART decision.
b. PM BART Analysis and
Determination
PM emissions are inherently low
when burning natural gas, but are higher
when burning fuel oil. Bailey Unit 1
does not currently have pollution
control equipment for PM emissions. In
assessing PM BART for Bailey Unit 1,
ADEQ explained that AECC considered
the five BART factors. In assessing
feasible control technologies and their
43 The Administrative Order can be found in the
Arkansas Regional Haze SO2 and PM BART SIP
Revision.
44 The Arkansas Regional Haze FIP requires
Bailey Unit 1 to only use fuel with a sulfur content
limit of 0.5% by weight, with a compliance date of
October 27, 2021. Additionally, the FIP prohibits
the owner or operator of the unit from purchasing
fuel for combustion at the unit that does not meet
the sulfur content limit; the compliance date for
this requirement is October 27, 2016. See 81 FR
66335, 66415–16.
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effectiveness, AECC considered the
following control technologies for PM
BART: Dry electrostatic precipitator
(ESP), wet ESP, fabric filter, wet
scrubber, cyclone (i.e., mechanical
collector), and fuel switching. AECC’s
evaluation noted that the particulate
matter from oil-fired boilers tends to be
sticky and small, affecting the collection
efficiency of dry ESPs and fabric filters.
Dry ESPs operate by placing a charge on
the particles through a series of
electrodes, and then capturing the
charged particles on collection plates,
while fabric filters work by filtering the
PM in the flue gas through filter bags.
The collected particles are periodically
removed from the filter bag through a
pulse jet or reverse flow mechanism.
Because of the sticky nature of particles
from oil-fired boilers, AECC considered
dry ESPs and fabric filters to be
technically infeasible for use at Bailey
Unit 1. AECC found wet ESPs, wet
scrubbers, cyclones, and fuel switching
to be technically feasible PM control
options.
Residual fuel, such as the baseline No.
6 fuel oil burned at Bailey Unit 1, has
inherent ash that contributes to
emissions of filterable PM. Reductions
in filterable PM emissions are directly
related to the sulfur content of the
fuel.45 Therefore, switching to No. 6 fuel
oil with a lower sulfur content is
expected to result in lower filterable PM
emissions. Also, ash content is much
lower in a distillate fuel such as diesel
and essentially zero in natural gas. The
fuel switching options considered by
AECC in the PM BART analysis are No.
6 fuel oil with 1% sulfur content by
weight, No. 6 fuel oil with 0.5% sulfur
content by weight, natural gas, and
diesel. AECC estimated that switching
to a lower sulfur fuel has a PM control
efficiency ranging from approximately
44%–99%, depending on the fuel type.
The estimated PM control efficiency of
each control option is summarized in
Table 2.
TABLE 2—PM CONTROL EFFICIENCY OF BART CONTROL OPTIONS FOR AECC BAILEY UNIT 1
Fuel switching
Wet
scrubber
PM control option
PM Control Efficiency ..........................................................
(%) ........................................................................................
In considering the costs of the PM
control options, AECC noted that addon controls such as a wet scrubber,
cyclone, and wet ESP involve capital
costs for new equipment, which AECC
annualized over a 15-year period in the
analysis. Based on this analysis, AECC
determined that the estimated costeffectiveness of the add-on control
options are as follows: $3,558,286/ton
for a wet scrubber; $54,570/ton for a
cyclone; and $981,583/ton for a wet
ESP. AECC determined that the
estimated cost-effectiveness of the fuel
switching options are as follows:
$27,528/ton for No. 6 fuel oil with 1%
sulfur content; $22,386/ton for No. 6
fuel oil with 0.5% sulfur content;
55.0
Cyclone
Wet ESP
85.0
90.0
$25,004/ton for diesel; and $2,327/ton
for natural gas. AECC noted that it does
not consider any of the PM control
options to be cost-effective.
ADEQ explained that AECC’s PM
BART evaluation did not discuss any
energy or non-air quality environmental
impacts associated with fuel switching.
AECC did identify certain energy and
non-air quality environmental impacts
associated with wet ESPs and wet
scrubbers. These impacts, which are
factored in the cost of compliance,
include increased energy usage for
operation of the control equipment, the
generation of wastewater streams that
must be treated on-site or sent to a waste
water treatment plant, and the
No. 6 fuel
oil—1% S
No. 6 fuel
oil—0.5%
S
65.7
89.3
Natural
gas
99.0
Diesel
99.5
generation of a filter cake that would
likely require land-filling. In assessing
the remaining useful life of Bailey Unit
1, AECC concluded that this factor does
not impact the annualized costs of the
evaluated control options since the
remaining useful life of Bailey Unit 1 is
at least as long as the capital cost
recovery period of 15 years.
In assessing visibility impacts, the
state’s submittal included CALPUFF
modeling evaluating the visibility
benefits of switching from the baseline
fuel oil (assuming 100% use of fuel oil)
to the various fuel switching options.
We summarize the results of that
modeling in Table 3.
TABLE 3—ANTICIPATED VISIBILITY BENEFIT OF PM CONTROLS AT AECC BAILEY UNIT 1
[CALPUFF, 98th percentile]
Baseline
visibility
impact
(dv)
amozie on DSK3GDR082PROD with PROPOSALS5
Class I area
Caney Creek ....................................................
Upper Buffalo ...................................................
Hercules-Glades ..............................................
Mingo ...............................................................
Visibility benefit of controls over baseline
(dv) 46
Wet
scrubber
0.330
0.347
0.367
0.378
0.002
0.002
0.007
0.004
Cyclone
0.002
0.002
0.006
0.004
Wet ESP
No. 6 fuel
oil—1%
sulfur
No. 6 fuel
oil—0.5%
sulfur
0.003
0.004
0.011
0.007
0.137
0.154
0.162
0.173
0.188
0.221
0.233
0.209
Diesel—
0.05%
sulfur
0.246
0.279
0.299
0.284
Natural
gas
0.247
0.276
0.295
0.277
The anticipated visibility benefits of
add-on controls (i.e., wet scrubber,
cyclone, and wet ESP) are anticipated to
be very small, ranging from 0.002 to
0.011 dv at each affected Class I area. As
discussed above, fuel switching to lower
45 See ‘‘AP–42, Compilation of Air Pollutant
Emission Factors,’’ section 1.3.3.1, and Table 1.3–
1, available at https://www.epa.gov/ttnchie1/ap42/.
46 The modeled visibility improvement of the fuel
switching options reflects both SO2 and PM
emissions reductions since reductions in filterable
PM are directly related to the sulfur content of the
fuel.
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amozie on DSK3GDR082PROD with PROPOSALS5
sulfur fuels is expected to result in both
lower filterable PM emissions and lower
SO2 emissions. Switching to 1% sulfur
No. 6 fuel oil is anticipated to achieve
visibility benefits of approximately
0.137 dv at Caney Creek, 0.154 dv at
Upper Buffalo, 0.162 dv at HerculesGlades, and 0.173 dv at Mingo over
baseline visibility conditions. Switching
to 0.5% sulfur No. 6 fuel oil is
anticipated to achieve visibility benefits
of approximately 0.188 dv at Caney
Creek, 0.221 dv at Upper Buffalo, 0.233
dv at Hercules-Glades, and 0.209 dv at
Mingo over the baseline. The visibility
benefits of switching to diesel are
anticipated to be even greater, with
benefits of approximately 0.246 dv at
Caney Creek, 0.279 dv at Upper Buffalo,
0.299 dv at Hercules-Glades, and 0.284
dv at Mingo over the baseline. The
visibility benefits of switching to natural
gas are anticipated to be only slightly
more than switching to diesel. The
modeled visibility improvement of
switching to lower sulfur fuels reflects
benefits of both SO2 and PM emissions
reductions since reductions in filterable
PM are directly related to the sulfur
content of the fuel. We do note that the
majority of the baseline visibility impact
at each Class I area when burning the
baseline fuel oil is due to SO2 emissions
that form sulfate PM, while direct PM10
emissions contribute only a small
portion of the baseline visibility impacts
at each Class I area.47 Accordingly, the
majority of the visibility improvement
associated with switching to lower
sulfur fuels, as shown in Table 3, can
reasonably be expected to be the result
of a reduction in SO2 emissions rather
than PM emissions.
Taking into consideration the costeffectiveness and the anticipated
visibility improvement of the PM
control options considered, ADEQ
concluded that add-on controls are not
cost-effective, with AECC estimating the
cost of these controls to be
approximately $55,000/ton and greater.
ADEQ concluded that the cost of
switching to lower sulfur fuels is also
not a cost-effective method for reducing
PM emissions. However, ADEQ noted
that the SO2 BART determination for
Bailey Unit 1, which is the use of fuel
that has 0.5% or less sulfur content by
weight, would also result in PM
47 See Table 4–3 BASELINE VISIBILITY
IMPAIRMENT ATTRIBUTABLE TO BAILEY, UNIT
1 (2001–2003)—FUEL OIL, ‘‘BART Five Factor
Analysis, Arkansas Electric Cooperative
Corporation Bailey and McClellan Generating
Stations,’’ dated March 2014, Version 4, prepared
by Trinity Consultants Inc. in conjunction with
Arkansas Electric Cooperative Corporation,’’ which
can be found in Appendix B to the Arkansas
Regional Haze SO2 and PM BART SIP Revision.
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emissions reductions. ADEQ therefore
arrived at the determination that PM
BART for Bailey Unit 1 is no additional
control beyond switching to fuel with
0.5% or less sulfur content, consistent
with the SO2 BART decision for the
unit.
We do not agree with the use of a 15year capital cost recovery period for
calculating the average costeffectiveness of a wet ESP, wet scrubber,
and cyclone. Per the EPA Control Cost
Manual, facilities are to rely on a 30year capital cost recovery period for
calculating the average costeffectiveness of a wet ESP, wet scrubber,
or cyclone barring a technical rationale
to deviate from the 30-year capital cost
recovery period. AECC Bailey
Generating Station did not provide a
technical rationale to deviate from the
assumed 30-year capital cost recovery
period. In addition, we are not aware of
any enforceable shutdown date for the
AECC Bailey Generating Station, nor did
AECC’s evaluation or ADEQ’s SIP
revision indicate any future planned
shutdown or provide any reason for
adopting a 15-year equipment life for
the controls under consideration.
Therefore, we believe that assuming a
30-year equipment life rather than a 15year equipment life would be more
appropriate for these control
technologies.48 Extending the
amortization period from 15 to 30 years
has the effect of decreasing the total
annual cost of each control option,
thereby improving the average costeffectiveness value of controls (i.e.,
lower dollars per ton removed). As
discussed above, the cost of add-on PM
control equipment at Bailey Unit 1,
assuming a 15-year remaining useful
life, ranges from $54,570/ton of PM
removed for a cyclone to $3,558,286/ton
of PM removed for a wet scrubber. Even
though adjusting the costs of the add-on
controls based on a 30-year remaining
useful life as opposed to a 15-year
remaining useful life would decrease
the $/ton costs, we anticipate that the
costs in $/ton would still be
considerable and well outside of the
range that has generally been considered
to be cost-effective for BART. Therefore,
we believe that add-on PM controls
would still not be justified in light of the
considerable costs and the minimal
visibility benefits, which would range
from 0.002 to 0.011 at each Class I area
(see Table 3 above). Therefore, we are
proposing to agree with ADEQ’s
48 The Arkansas Regional Haze FIP assumed a 30year equipment life in the PM BART analysis for
AECC Bailey Unit 1. See 80 FR 18955.
PO 00000
Frm 00010
Fmt 4701
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determination that PM add-on controls
are not PM BART for Bailey Unit 1.
We also disagree with the total annual
cost and cost-effectiveness values for
fuel switching presented in AECC’s PM
BART analysis 49 and in the SIP
revision. In AECC’s SO2 BART cost
analysis for the same unit, the company
considered the same fuel switching
options, yet the total annual cost
numbers presented in the PM cost
analysis are significantly greater than
those presented in the SO2 cost
analysis.50 This appears to be because in
the SO2 cost analysis, AECC calculated
the differential cost of fuel switching
(i.e., the difference in cost between the
baseline fuel and the fuel switching
options), whereas the absolute cost of
the fuel switching options was
calculated in the PM cost analysis. We
believe that AECC and ADEQ should
have considered the differential cost of
fuel switching as opposed to the
absolute cost of fuel for each of the fuel
switching options in the PM BART
analysis, as was done in the SO2 BART
analysis. Thus, we believe that the
correct cost effectiveness values that
ADEQ should have considered in the
PM BART analysis are those presented
in Table 5–9 of AECC’s SO2 BART
analysis,51 which shows that the costs of
switching to fuel oil with a sulfur
content of 1% or 0.5% are within the
range that have generally been
considered to be cost-effective for
BART. Although switching to diesel
would result in additional reductions in
PM emissions, we believe that the
additional cost per ton for switching to
diesel would be high in comparison to
the additional visibility benefits.52 We
49 See ‘‘BART Five Factor Analysis, Arkansas
Electric Cooperative Corporation Bailey and
McClellan Generating Stations,’’ dated March 2014,
Version 4, prepared by Trinity Consultants Inc. in
conjunction with Arkansas Electric Cooperative
Corporation,’’ Table 7–4, page 7–6. This BART
analysis can be found in Appendix B to the
Arkansas Regional Haze SO2 and PM BART SIP
Revision.
50 See ‘‘BART Five Factor Analysis, Arkansas
Electric Cooperative Corporation Bailey and
McClellan Generating Stations,’’ dated March 2014,
Version 4, prepared by Trinity Consultants Inc. in
conjunction with Arkansas Electric Cooperative
Corporation,’’ Table 5–9, page 5–9.
51 See ‘‘BART Five Factor Analysis, Arkansas
Electric Cooperative Corporation Bailey and
McClellan Generating Stations,’’ dated March 2014,
Version 4, prepared by Trinity Consultants Inc. in
conjunction with Arkansas Electric Cooperative
Corporation,’’ Table 5–9, column titled ‘‘PM10 Cost
Effectiveness,’’ page 5–9.
52 Based on Table 5–13 from AECC’s SO BART
2
analysis, switching to diesel would result in an
additional visibility benefit of 0.111 dv compared
to switching to 1% No. 6 fuel oil, and in an
additional visibility benefit of only 0.075 dv
compared to switching to 0.5% No. 6 fuel oil at
Mingo, which is the Class I area with the greatest
visibility impacts from Bailey Unit 1. Based on
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believe that switching to fuel with 0.5%
or less sulfur content is within the range
that has generally been considered to be
cost-effective for BART and since the
source will have to comply with that
same requirement for SO2 BART, we
consider it appropriate to require it
under PM BART as well. Therefore, we
are proposing to approve ADEQ’s
determination that PM BART for AECC
Bailey Unit 1 is no additional control
beyond switching to fuel with 0.5% or
less sulfur content by October 27, 2021.
Additionally, the owner or operator of
the unit shall not purchase fuel for
combustion at the unit that does not
meet this sulfur content limit as of the
effective date of the Administrative
Order, which is August 7, 2018. This
BART determination has now been
made enforceable by the state through
an Administrative Order that has been
adopted and incorporated in the SIP
revision. We are proposing to approve
into the SIP the state’s Administrative
Order with respect to the PM BART
requirements for AECC Bailey Unit 1.53
The state’s PM BART decision for
Bailey Unit 1 is consistent with the
BART decision EPA previously made in
the FIP we promulgated on September
27, 2016.54 We are concurrently
proposing to withdraw the FIP’s PM
BART requirements for Bailey Unit 1, as
they would be replaced by our approval
of the state’s PM BART decision.
2. AECC McClellan Unit 1
The AECC McClellan Unit 1 has a
wall-fired boiler, a gross output of 122
MW and a maximum heat input rate of
1,436 MMBtu/hr. The unit is currently
permitted to burn pipeline quality
natural gas and fuel oil. The fuel oil
burned is currently subject to a sulfur
content limit of 2.8% by weight. AECC
produced BART analyses dated March
2014 for McClellan Unit 1, which were
evaluated by EPA and largely formed
the basis for EPA’s SO2 and PM BART
evaluations in the FIP.55 The same
BART analyses 56 have now been
adopted and incorporated by ADEQ into
the Arkansas Regional Haze SO2 and PM
BART SIP revision to address the SO2
and PM BART requirements for
McClellan Unit 1.
a. SO2 BART Analysis and
Determination
In assessing SO2 BART, ADEQ
explained that AECC considered the five
BART factors. In assessing feasible
control technologies and their
effectiveness, AECC considered FGD
systems and fuel switching during fuel
oil burning. Due to the intrinsically low
sulfur content of natural gas, no control
technologies were evaluated for natural
gas burning scenarios. As such, the
BART analysis focused on fuel oil firing
as the base case. For fuel oil firing, fuel
switching was determined to be the only
technically feasible control option, and
thus AECC did not further consider FGD
for SO2 BART. The baseline fuel AECC
assumed in the BART analysis is No. 6
fuel oil with 1.38% sulfur content by
weight, which is based on the average
sulfur content of the fuel oil from the
most recent shipment received by the
facility in April 2009. ADEQ explained
that AECC evaluated switching to the
following fuel types: 1% Sulfur No. 6
fuel oil, corresponding to an estimated
28% control efficiency; 0.5% sulfur No.
6 fuel oil, corresponding to 64% control
efficiency; and 0.05% sulfur diesel,
corresponding to 96% control
efficiency.57
In considering the costs of compliance
for fuel switching, AECC concluded that
the fuel switching options evaluated
would not require capital investments
in equipment, but instead the annual
costs would be based upon operation
and maintenance costs associated with
the different fuel types. AECC estimated
that the cost-effectiveness of switching
McClellan Unit 1 to No. 6 fuel oil with
1% and 0.5% sulfur content by weight
is $2,613/ton and $3,823/ton,
respectively. Switching to diesel, which
has 0.05% sulfur content, is estimated
to cost $7,145/ton. ADEQ stated that the
cost in dollars per ton for diesel is out
of the range of what is typically
considered cost-effective, while the cost
of both 1% and 0.5% sulfur No. 6 fuel
oil is estimated to be within the range
of what is typically considered costeffective.
ADEQ stated that AECC’s evaluation
did not identify any energy or non-air
quality environmental impacts
associated with switching to 1% sulfur
No. 6 fuel oil, 0.5% sulfur No. 6 fuel oil,
or diesel. In assessing the remaining
useful life of McClellan Unit 1, AECC
concluded that this factor does not
impact the annualized costs of the
evaluated control options since fuel
switching is not expected to require any
significant capital costs in this case.
In assessing visibility impacts, the
state’s submittal included CALPUFF
modeling evaluating the visibility
benefits of switching from the baseline
fuel (assuming 100% use of fuel oil) to
the various fuel switching options. We
summarize the results of that modeling
in Table 4.
TABLE 4—ANTICIPATED VISIBILITY BENEFIT DUE TO FUEL SWITCHING AT AECC MCCLELLAN UNIT 1
[CALPUFF, 98th percentile]
Baseline
visibility
impact
(dv)
Class I area
amozie on DSK3GDR082PROD with PROPOSALS5
Caney Creek ....................................................................................................
Upper Buffalo ...................................................................................................
Hercules-Glades ..............................................................................................
Table 5–9 from AECC’s SO2 BART analysis, the
corrected cost of switching to 1% and 0.5% No. 6
fuel oil is estimated to be $1,165/ton of PM
removed and $2,998/ton of PM removed
(respectively), while the corrected cost of diesel is
estimated to be $7,608/ton of PM removed. We do
not consider the additional cost of switching to
diesel at Bailey Unit 1 to be warranted by the
additional level of anticipated visibility benefit.
53 The Administrative Order can be found in the
Arkansas Regional Haze SO2 and PM BART SIP
Revision.
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No. 6 fuel
oil—1%
sulfur
0.622
0.266
0.231
54 The Arkansas Regional Haze FIP required
Bailey Unit 1 to only use fuel with a sulfur content
limit of 0.5% by weight, with a compliance date of
October 27, 2021. Additionally, the FIP prohibited
the owner or operator of the unit from purchasing
fuel for combustion at the unit that does not meet
the sulfur content limit; the compliance date for
this requirement was October 27, 2016. See 81 FR
66335 and 66415–16.
55 80 FR 18957.
56 ‘‘BART Five Factor Analysis, Arkansas Electric
Cooperative Corporation Bailey and McClellan
PO 00000
Visibility benefit of controls
over baseline
(dv)
0.085
0.035
0.029
No. 6 fuel
oil—0.5%
sulfur
0.300
0.120
0.116
Diesel—0.05%
sulfur
0.448
0.193
0.169
Generating Stations,’’ dated March 2014, Version 4,
prepared by Trinity Consultants Inc. in conjunction
with Arkansas Electric Cooperative Corporation,’’
which can be found in Appendix B to the Arkansas
Regional Haze SO2 and PM BART SIP Revision.
57 We also note that AECC evaluated switching to
natural gas as an available SO2 control option in its
SO2 BART analysis, but the evaluation of this
control option was not discussed by ADEQ in the
SIP revision. We discuss this issue in greater detail
below when we present our evaluation of the state’s
BART determination.
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TABLE 4—ANTICIPATED VISIBILITY BENEFIT DUE TO FUEL SWITCHING AT AECC MCCLELLAN UNIT 1—Continued
[CALPUFF, 98th percentile]
Baseline
visibility
impact
(dv)
Class I area
Mingo ...............................................................................................................
amozie on DSK3GDR082PROD with PROPOSALS5
Switching to 1% sulfur No. 6 fuel oil
is anticipated to achieve visibility
benefits of approximately 0.085 dv at
Caney Creek, 0.035 dv at Upper Buffalo,
0.029 dv at Hercules-Glades, and 0.035
dv at Mingo over baseline visibility
conditions. Switching to 0.5% sulfur
No. 6 fuel oil is anticipated to achieve
visibility benefits of approximately
0.300 dv at Caney Creek, 0.120 dv at
Upper Buffalo, 0.116 dv at HerculesGlades, and 0.092 dv at Mingo over the
baseline. The visibility benefits of
switching to diesel are anticipated to be
even greater, with benefits of
approximately 0.448 dv at Caney Creek,
0.193 dv at Upper Buffalo, 0.169 dv at
Hercules-Glades, and 0.148 dv at Mingo
over the baseline.
Taking into consideration the costeffectiveness and the anticipated
visibility improvement of the fuel
switching options, ADEQ concurred
with AECC’s recommendation that SO2
BART for AECC McClellan Unit 1 be
determined to be the use of fuel with a
sulfur content by weight of 0.5% or less.
We note that switching to diesel
would result in additional reductions in
SO2 emissions, but the additional costs
per ton for doing so would be high in
comparison to the additional visibility
benefits. We also note that AECC
evaluated switching to natural gas as an
available SO2 control option in its SO2
BART analysis,58 but the evaluation of
this control option in the SO2 BART
analysis was not discussed by ADEQ in
the SIP revision. In its analysis, AECC
explained that switching to natural gas
may have an adverse energy impact
during periods of natural gas
curtailment and that the ability to burn
both fuel oil and natural gas was
important for the facility to maintain
58 See ‘‘BART Five Factor Analysis, Arkansas
Electric Cooperative Corporation Bailey and
McClellan Generating Stations, dated March 2014,
Version 4, prepared by Trinity Consultants Inc. in
conjunction with Arkansas Electric Cooperative
Corporation,’’ pages 5–1 to 5–14. This BART
analysis has been adopted and incorporated by
ADEQ into the SIP revision (see Appendix B to the
Arkansas Regional Haze SO2 and PM BART SIP
revision).
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59 See ‘‘BART Five Factor Analysis, Arkansas
Electric Cooperative Corporation Bailey and
McClellan Generating Stations, dated March 2014,
Version 4, prepared by Trinity Consultants Inc. in
conjunction with Arkansas Electric Cooperative
Corporation,’’ pages 5–2, 5–10, and 5–14.
60 Id.
61 See 80 FR at 18959 and 81 FR at 66340.
62 Id.
Frm 00012
Fmt 4701
Sfmt 4702
No. 6 fuel
oil—1%
sulfur
0.228
electrical reliability.59 Therefore, AECC
did not recommend switching to natural
gas and instead recommended switching
to fuels with 0.5% sulfur content to be
SO2 BART for McClellan Unit 1.60 In the
Arkansas Regional Haze FIP, we agreed
with AECC’s recommendation, and
explained that the BART Guidelines
provide that it is not our intent to direct
subject-to-BART sources to switch fuel
forms, such as from coal or fuel oil to
natural gas (40 CFR part 51, Appendix
Y, section IV.D.1).61 We noted that since
natural gas has a sulfur content by
weight that is well below 0.5%, the
facility may elect to use this type of fuel
to comply with BART, but we did not
require a switch to natural gas for SO2
BART in the FIP.62 Therefore, we do not
find that ADEQ’s lack of consideration
of switching to natural gas as an SO2
control option in the SO2 BART analysis
for McClellan Unit 1 changes the result
of the BART analysis in this instance.
We are proposing to approve the state’s
determination that SO2 BART for
McClellan Unit 1 is the use of fuel with
a sulfur content by weight of 0.5% or
less. We are also proposing to approve
the state’s determination that McClellan
Unit 1 must comply with this BART
requirement no later than October 27,
2021, and that as of the effective date of
the Administrative Order, which is
August 7, 2018, the source shall not
purchase fuel that does not meet the
sulfur limit requirement for combustion
at McClellan Unit 1. These BART
requirements have now been made
enforceable by the state through an
Administrative Order that has been
adopted and incorporated in the SIP
revision. The Administrative Order for
AECC McClellan Unit 1 includes not
only the requirement to limit the sulfur
content of the fuel burned, but also
requirements for the source to sample
PO 00000
Visibility benefit of controls
over baseline
(dv)
0.035
No. 6 fuel
oil—0.5%
sulfur
0.092
Diesel—0.05%
sulfur
0.148
and analyze each shipment of fuel to
determine the sulfur content by weight
and maintain records pertaining to the
sampling of each fuel shipment to assess
compliance with the BART
requirements.63 We are proposing to
approve the state’s Administrative
Order, including the compliance
determination requirements contained
in the Administrative Order, into the
SIP. The state’s SO2 BART emission
limit and compliance date for McClellan
Unit 1 are consistent with the BART
decision EPA previously made in the
FIP we promulgated on September 27,
2016.64 We are concurrently proposing
to withdraw the FIP’s SO2 BART
requirements for McClellan Unit 1, as
they would be replaced by our approval
of the state’s SO2 BART decision.
b. PM BART Analysis and
Determination
PM emissions are inherently low
when burning natural gas, but are higher
when burning fuel oil. McClellan Unit
1 does not currently have pollution
control equipment for PM emissions. In
assessing PM BART for McClellan Unit
1, ADEQ explained that AECC
considered the five BART factors. In
assessing feasible control technologies
and their effectiveness, AECC
considered the following control
technologies for PM BART: Dry ESP,
wet ESP, fabric filter, wet scrubber,
cyclone, and fuel switching. AECC’s
evaluation noted that the particulate
matter from oil-fired boilers tends to be
sticky and small, affecting the collection
efficiency of dry ESPs and fabric filters.
Dry ESPs operate by placing a charge on
the particles through a series of
electrodes, and then capturing the
charged particles on collection plates,
63 The Administrative Order can be found in the
Arkansas Regional Haze SO2 and PM BART SIP
Revision.
64 The Arkansas Regional Haze FIP requires
McClellan Unit 1 to only use fuel with a sulfur
content limit of 0.5% by weight, with a compliance
date of October 27, 2021. Additionally, the FIP
prohibits the owner or operator of the unit from
purchasing fuel for combustion at the unit that does
not meet the sulfur content limit; the compliance
date for this requirement is October 27, 2016. See
81 FR 66335 and 66415–16.
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while fabric filters work by filtering the
PM in the flue gas through filter bags.
The collected particles are periodically
removed from the filter bag through a
pulse jet or reverse flow mechanism.
Because of the sticky nature of particles
from oil-fired boilers, AECC considered
dry ESPs and fabric filters to be
technically infeasible for use at
McClellan Unit 1. AECC found wet
ESPs, wet scrubbers, cyclones, and fuel
switching to be technically feasible PM
control options.
Residual fuel, such as the baseline No.
6 fuel oil burned at McClellan Unit 1,
has inherent ash that contributes to
emissions of filterable PM. Reductions
in filterable PM emissions are directly
related to the sulfur content of the fuel.
Therefore, switching to No. 6 fuel oil
with a lower sulfur content is expected
to result in lower filterable PM
emissions. Also, ash content is much
lower in a distillate fuel such as diesel
and essentially zero in natural gas. The
fuel switching options considered by
AECC in the BART analysis are No. 6
fuel oil with 1% sulfur content by
weight, No. 6 fuel oil with 0.5% sulfur
content by weight, natural gas, and
diesel. AECC estimated that switching
to a lower sulfur fuel has a PM control
efficiency ranging from approximately
44%–99%, depending on the fuel type.
The estimated PM control efficiency of
each control option is summarized in
Table 5.
TABLE 5—PM CONTROL EFFICIENCY OF BART CONTROL OPTIONS FOR AECC MCCLELLAN UNIT 1
Fuel switching
PM control option
Wet
scrubber
Cyclone
55.0
85.0
PM Control Efficiency (%) ....................................................
In considering the costs of the PM
control options, AECC noted that addon controls such as the wet scrubber,
cyclone, and wet ESP involve capital
costs for new equipment, which AECC
annualized over a 15-year period in the
analysis. Based on this analysis, AECC
determined that the estimated costeffectiveness of the add-on control
options are as follows: $695,549/ton for
a wet scrubber; $14,882/ton for a
cyclone; and $266,237/ton for a wet
ESP. AECC determined that the
estimated cost-effectiveness of the fuel
switching options are as follows:
$53,044/ton for No. 6 fuel oil with 1%
sulfur content; $31,338/ton for No. 6
fuel oil with 0.5% sulfur content;
Wet ESP
90.0
$32,952/ton for diesel; and $571/ton for
natural gas. AECC noted that it does not
consider any of the PM control options
to be cost-effective.
ADEQ explained that AECC’s PM
BART evaluation did not discuss any
energy or non-air quality environmental
impacts associated with fuel switching.
AECC did identify certain energy and
non-air quality environmental impacts
associated with wet ESPs and wet
scrubbers. These impacts, which are
factored in the cost of compliance,
include increased energy usage for
operation of the control equipment, the
generation of wastewater streams that
must be treated on-site or sent to a waste
water treatment plant, and the
No. 6 fuel
oil—1% S
No. 6 fuel
oil—0.5%
S
Natural
gas
Diesel
43.6
82.4
99.0
99.2
generation of a filter cake that would
likely require land-filling. In assessing
the remaining useful life of McClellan
Unit 1, AECC concluded that this factor
does not impact the annualized costs of
the evaluated control options since the
remaining useful life of McClellan Unit
1 is at least as long as the capital cost
recovery period of 15 years.
In assessing visibility impacts, the
state’s submittal included CALPUFF
modeling evaluating the visibility
benefits of switching from the baseline
fuel oil (assuming 100% use of fuel oil)
to the various fuel switching options.
We summarize the results of that
modeling in Table 6.
TABLE 6—ANTICIPATED VISIBILITY BENEFIT OF PM CONTROLS AT AECC MCCLELLAN UNIT 1
[CALPUFF, 98th percentile]
Baseline
visibility
impact
(dv)
Class I area
amozie on DSK3GDR082PROD with PROPOSALS5
Caney Creek ....................................................
Upper Buffalo ...................................................
Hercules-Glades ..............................................
Mingo ...............................................................
The anticipated visibility benefits of
add-on controls (i.e., wet scrubber,
cyclone, and wet ESP) are very small,
ranging from 0.001 to 0.004 dv at each
affected Class I area. As discussed
above, fuel switching to lower sulfur
fuels is expected to result in both lower
filterable PM emissions and lower SO2
emissions. Switching to 1% sulfur No.
6 fuel oil is anticipated to achieve
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Visibility benefit of controls over baseline
(dv) 65
Wet
scrubber
0.621
0.266
0.230
0.227
0.002
0.002
0.002
0.003
Cyclone
0.002
0.001
0.001
0.002
Wet ESP
No. 6 fuel
oil—1%
sulfur
No. 6 fuel
oil—0.5%
sulfur
0.004
0.003
0.003
0.004
0.085
0.035
0.029
0.035
0.300
0.120
0.116
0.092
visibility benefits of approximately
0.085 dv at Caney Creek, 0.035 dv at
Upper Buffalo, 0.029 dv at HerculesGlades, and 0.035 dv at Mingo over
baseline visibility conditions. Switching
to 0.5% sulfur No. 6 fuel oil is
anticipated to achieve visibility benefits
of approximately 0.3 dv at Caney Creek,
0.12 dv at Upper Buffalo, 0.116 dv at
Hercules-Glades, and 0.092 dv at Mingo
PO 00000
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Diesel—
0.05%
sulfur
0.448
0.193
0.169
0.148
Natural
gas
0.497
0.214
0.191
0.17
over the baseline. The visibility benefits
of switching to diesel are anticipated to
be even greater, with benefits of
approximately 0.448 dv at Caney Creek,
0.193 dv at Upper Buffalo, 0.169 dv at
65 The modeled visibility improvement of the fuel
switching options reflects both SO2 and PM
emissions reductions since reductions in filterable
PM are directly related to the sulfur content of the
fuel.
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amozie on DSK3GDR082PROD with PROPOSALS5
Hercules-Glades, and 0.148 dv at Mingo
over the baseline. The visibility benefits
of switching to natural gas are
anticipated to be only slightly more than
switching to diesel. The modeled
visibility improvement of switching to
lower sulfur fuels reflects benefits of
both SO2 and PM emissions reductions
since reductions in filterable PM are
directly related to the sulfur content of
the fuel. We do note that the majority
of the baseline visibility impact at each
Class I area when burning the baseline
fuel oil is due to SO2 emissions that
form sulfate PM, while direct PM10
emissions contribute only a small
portion of the baseline visibility impacts
at each Class I area.66 Accordingly, the
majority of the visibility improvement
associated with switching to lower
sulfur fuels, as shown in Table 6, can
reasonably be expected to be the result
of a reduction in SO2 emissions rather
than PM emissions.
Taking into consideration the costeffectiveness and the anticipated
visibility improvement of the PM
control options considered, ADEQ
concluded that add-on controls are not
cost-effective, with AECC estimating the
cost of these controls to be
approximately $15,000/ton and greater.
ADEQ concluded that the cost of
switching to lower sulfur fuels is also
not a cost-effective method for reducing
PM emissions. However, ADEQ noted
that the SO2 BART determination for
McClellan Unit 1, which is the use of
fuel that has 0.5% or less sulfur content
by weight, would also result in PM
emissions reductions. ADEQ therefore
arrived at the determination that PM
BART for McClellan Unit 1 is no
additional control beyond switching to
fuel with 0.5% or less sulfur content,
consistent with the SO2 BART decision
for the unit.
We do not agree with the use of a 15year capital cost recovery period for
calculating the average costeffectiveness of a wet ESP, wet scrubber,
and cyclone. Per the EPA Control Cost
Manual, facilities are to rely on a 30year capital cost recovery period for
calculating the average costeffectiveness of a wet ESP, wet scrubber,
or cyclone barring a technical rationale
to deviate from the 30-year capital cost
recovery period. AECC Bailey
Generating Station did not provide a
66 See Table 4–5 BASELINE VISIBILITY
IMPAIRMENT ATTRIBUTABLE TO McCLELLAN,
UNIT 1 (2001–2003)—FUEL OIL, ‘‘BART Five
Factor Analysis, Arkansas Electric Cooperative
Corporation Bailey and McClellan Generating
Stations,’’ dated March 2014, Version 4, prepared
by Trinity Consultants Inc. in conjunction with
Arkansas Electric Cooperative Corporation,’’ which
can be found in Appendix B to the Arkansas
Regional Haze SO2 and PM BART SIP Revision.
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technical rationale to deviate from the
assumed 30-year capital cost recovery
period. In addition, we are not aware of
any enforceable shutdown date for the
AECC McClellan Generating Station, nor
did AECC’s evaluation or ADEQ’s SIP
revision indicate any future planned
shutdown or provide any reason for
adopting a 15-year equipment life for
the controls under consideration.
Therefore, we believe that assuming a
30-year equipment life rather than a 15year equipment life would be more
appropriate for these control
technologies.67 Extending the
amortization period from 15 to 30 years
has the effect of decreasing the total
annual cost of each control option,
thereby improving the average costeffectiveness value of controls (i.e.,
lower dollars per ton removed). As
discussed above, the cost of add-on PM
control equipment at McClellan Unit 1,
assuming a 15-year remaining useful
life, ranges from $14,882/ton of PM
removed for a cyclone to $695,549/ton
of PM removed for a wet scrubber. Even
though adjusting the costs of the add-on
controls based on a 30-year remaining
useful life as opposed to a 15-year
remaining useful life would decrease
the $/ton costs, we anticipate that the
costs in $/ton would still be
considerable and well outside of the
range that has generally been considered
to be cost-effective for BART. Therefore,
we believe that add-on PM controls
would still not be justified in light of the
considerable costs and the minimal
visibility benefits, which would range
from 0.001 to 0.004 at each Class I area
(see Table 6 above). Therefore, we are
proposing to agree with ADEQ’s
determination that PM add-on controls
are not PM BART for McClellan Unit 1.
We also disagree with the total annual
cost and cost-effectiveness values for
fuel switching presented in AECC’s PM
BART analysis 68 and in the SIP
revision. In AECC’s SO2 BART cost
analysis for the same unit, the company
considered the same fuel switching
options, yet the total annual cost
numbers presented in the PM cost
analysis are significantly greater than
those presented in the SO2 cost
67 The Arkansas Regional Haze FIP assumed a 30year equipment life in the PM BART analysis for
AECC McClellan Unit 1. See 80 FR 18962.
68 See ‘‘BART Five Factor Analysis, Arkansas
Electric Cooperative Corporation Bailey and
McClellan Generating Stations,’’ dated March 2014,
Version 4, prepared by Trinity Consultants Inc. in
conjunction with Arkansas Electric Cooperative
Corporation,’’ Table 7–5, page 7–6. This BART
analysis can be found in Appendix B to the
Arkansas Regional Haze SO2 and PM BART SIP
Revision.
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Frm 00014
Fmt 4701
Sfmt 4702
analysis.69 This appears to be because in
the SO2 cost analysis, AECC calculated
the differential cost of fuel switching
(i.e., the difference in cost between the
baseline fuel and the fuel switching
options), whereas the absolute cost of
the fuel switching options was
calculated in the PM cost analysis. We
believe that AECC and ADEQ should
have considered the differential cost of
fuel switching as opposed to the
absolute cost of fuel for each of the fuel
switching options in the PM BART
analysis, as was done in the SO2 BART
analysis. Thus, we believe that the
correct cost effectiveness values that
ADEQ should have considered in the
PM BART analysis are those presented
in Table 5–10 of AECC’s SO2 BART
analysis,70 which shows that the costs of
switching to fuel oil with a sulfur
content of 1% or 0.5% are within the
range that have generally been
considered to be cost effective for
BART. Although switching to diesel
would result in additional reductions in
PM emissions, we believe that the
additional cost per ton for switching to
diesel would be high in comparison to
the additional visibility benefits.71 We
believe that switching to fuel with 0.5%
or less sulfur content is within the range
that has generally been considered to be
cost-effective for BART and since the
source will have to comply with that
same requirement for SO2 BART, we
consider it appropriate to require it
under PM BART as well. Therefore, we
are proposing to approve ADEQ’s
determination that PM BART for AECC
McClellan Unit 1 is no additional
control beyond switching to fuel with
0.5% or less sulfur content by October
27, 2021. Additionally, the owner or
69 See ‘‘BART Five Factor Analysis, Arkansas
Electric Cooperative Corporation Bailey and
McClellan Generating Stations,’’ dated March 2014,
Version 4, prepared by Trinity Consultants Inc. in
conjunction with Arkansas Electric Cooperative
Corporation,’’ Table 5–10, page 5–9.
70 See ‘‘BART Five Factor Analysis, Arkansas
Electric Cooperative Corporation Bailey and
McClellan Generating Stations,’’ dated March 2014,
Version 4, prepared by Trinity Consultants Inc. in
conjunction with Arkansas Electric Cooperative
Corporation,’’ Table 5–10, column titled ‘‘PM10 Cost
Effectiveness,’’ page 5–9.
71 Based on Table 5–14 from AECC’s SO BART
2
analysis, switching to diesel would result in an
additional visibility benefit of 0.363 dv compared
to switching to 1% No. 6 fuel oil and in an
additional visibility benefit of only 0.148 dv
compared to switching to 0.5% No. 6 fuel oil at
Caney Creek, which is the Class I area with the
greatest visibility impacts from McClellan Unit 1.
Based on Table 5–10 from AECC’s SO2 BART
analysis, the corrected costs of switching to 1% and
0.5% No. 6 fuel oil is estimated to be $2,457/ton
of PM removed and $4,553/ton of PM removed
(respectively), while the corrected cost of switching
to diesel is estimated to be $10,698/ton of PM
removed. We do not consider the additional cost of
switching to diesel at McClellan Unit 1 to be
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operator of the unit shall not purchase
fuel for combustion at the unit that does
not meet this sulfur content limit as of
the effective date of the Administrative
Order, which is August 7, 2018. This
BART determination has now been
made enforceable by the state through
an Administrative Order that has been
adopted and incorporated in the SIP
revision. We are proposing to approve
into the SIP the state’s Administrative
Order with respect to the PM BART
requirements for AECC McClellan Unit
1.72
The state’s PM BART decision for
McClellan Unit 1 is consistent with the
BART decision EPA previously made in
the FIP we promulgated on September
27, 2016.73 We are concurrently
proposing to withdraw the FIP’s PM
BART requirements for McClellan Unit
1, as they would be replaced by our
approval of the state’s PM BART
decision.
3. SWEPCO Flint Creek Plant Boiler No.
1
amozie on DSK3GDR082PROD with PROPOSALS5
SWEPCO Flint Creek Plant Boiler No.
1 has a 558 MW dry bottom wall-fired
boiler that commenced operation in
1978, has a maximum heat input of
6,324 MMBtu/hr, and burns low sulfur
western coal as a primary fuel, but is
also permitted to combust fuel oil and
tire-derived fuels. Fuel oil firing is only
allowed during unit startup and
shutdown, during startup and shutdown
of pulverizer mills, for flame
stabilization when coal is frozen, for No.
2 fuel oil tank maintenance, to prevent
boiler tube failure in extreme cold
weather when the unit is offline for
maintenance, and during malfunction.
SWEPCO produced a BART analysis
dated September 2013 for Flint Creek
Plant Boiler No. 1, which was evaluated
by EPA and largely formed the basis for
EPA’s SO2 BART evaluation in the
warranted by the additional level of anticipated
visibility benefit.
72 The Administrative Order can be found in the
Arkansas Regional Haze SO2 and PM BART SIP
Revision.
73 The Arkansas Regional Haze FIP required
McClellan Unit 1 to only use fuel with a sulfur
content limit of 0.5% by weight, with a compliance
date of October 27, 2021. Additionally, the FIP
prohibited the owner or operator of the unit from
purchasing fuel for combustion at the unit that does
not meet the sulfur content limit; the compliance
date for this requirement was October 27, 2016. See
81 FR 66335 and 66415–16.
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FIP.74 This BART analysis 75 has now
been adopted and incorporated by
ADEQ into the Arkansas Regional Haze
SO2 and PM BART SIP revision to
address the SO2 BART requirements for
Flint Creek Boiler No. 1.76
a. SO2 BART Analysis and
Determination
At the time that SWEPCO performed
the BART analysis, no SO2 controls
were in place at Flint Creek Plant Boiler
No. 1. The cost analysis and visibility
improvement data that are part of
SWEPCO’s BART analysis are based on
the 2001–2003 baseline, not on
emissions reflecting current SO2
controls in place. Since the time the
BART analysis was developed,
SWEPCO has installed a Novel
Integrated Deacidification (NID) system
and Activated Carbon Injection (ACI)
system at Flint Creek Boiler No. 1 in
anticipation of regional haze
requirements as well as other CAA
requirements. The installation of these
controls was completed in May 2016.
In assessing SO2 BART, SWEPCO
considered the five BART factors. The
available SO2 retrofit control technology
options considered were dry sorbent
injection (DSI), dry FGD, and wet
FGD.77 DSI was estimated to have a
control efficiency of 40–60%. Dry FGD
was estimated to have a control
efficiency of 60–95%. NID, which is a
form of dry FGD, was predicted to have
a control efficiency of 92%, achieving
74 80
FR 18964.
Five Factor Analysis Flint Creek Power
Plant Gentry, Arkansas (AFIN 04–00107),’’ dated
September 2013, Version 4, prepared by Trinity
Consultants Inc. in conjunction with American
Electric Power Service Corporation for the
Southwestern Electric Power Company Flint Creek
Power Plant,’’ which can be found in Appendix E
to the Arkansas Regional Haze SO2 and PM BART
SIP Revision.
76 In a final action published on March 12, 2012,
EPA approved Arkansas’ PM BART determination
for Flint Creek Plant Boiler No. 1. In the Arkansas
Regional Haze SO2 and PM BART SIP revision, the
state is not revising that BART determination or the
underlying analysis.
77 SWEPCO’s September 2013 SO BART analysis
2
did not identify or discuss any existing SO2 control
equipment in use at the source because at the time
the BART analysis was developed, there were no
existing SO2 controls in place. Since the Arkansas
Regional Haze SO2 and PM SIP revision was
submitted at a time when the NID system is the
pollution control equipment in use at the source,
we give ADEQ credit for considering the existing
pollution controls factor in the SIP revision because
the existing SO2 control equipment is among the
‘‘new’’ controls addressed in the older SWEPCO
SO2 BART analysis.
75 ‘‘BART
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62217
an SO2 emission rate of 0.06 lb/MMBtu.
Wet FGD was estimated to have a
control efficiency of 80–95%, achieving
an SO2 emission rate of 0.04 lb/MMBtu.
All control options considered were
deemed to be technically feasible.
In considering the costs of
compliance, SWEPCO estimated the
capital and operating costs of a NID
system and wet FGD based on EPA’s
Control Cost Manual and supplemented,
where available, with vendor and sitespecific information obtained by
SWEPCO. These values were then used
by SWEPCO to estimate the costeffectiveness of controls. SWEPCO
estimated the cost of the SO2 control
options to be $3,845/ton for a NID
system and $4,919/ton for wet FGD.
Since control options with higher
control efficiencies were within a range
considered cost-effective (with one
ultimately selected as BART),
SWEPCO’s BART analysis did not
evaluate the cost of DSI or further
consider that control option in the
analysis. Thus, the remainder of
SWEPCO’s analysis focused on a NID
system (dry FGD) and wet FGD.
SWEPCO determined that although
wet FGD is expected to achieve a
slightly higher level of SO2 control
compared to NID technology, it would
also have greater potential negative
energy and nonair quality
environmental impacts. For example,
wet FGD is expected to generate large
volumes of wastewater and solid waste/
sludge that must be treated.
Additionally, wet FGD systems have
increased power requirements and
increased reagent usage over dry FGD,
as well as the potential for increased
particulate and sulfuric acid mist
releases. The costs associated with
increased power requirements and
greater reagent usage have already been
factored into the cost analysis for wet
FGD. In assessing the remaining useful
life of Flint Creek Boiler No. 1, SWEPCO
concluded that this factor does not
impact the annualized capital costs of
the evaluated control options because
the useful life of the unit is anticipated
to be at least as long as the capital cost
recovery period (30 years).
In assessing visibility impacts, the
state’s submittal included CALPUFF
modeling evaluating the visibility
benefits of dry FGD and wet FGD. We
summarize the results of that modeling
in Table 7.
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TABLE 7—ANTICIPATED VISIBILITY BENEFIT DUE TO SO2 CONTROLS AT FLINT CREEK BOILER NO. 1
[CALPUFF, 98th percentile]
Baseline
visibility
impact
(dv)
Class I area
Caney Creek ................................................................................................................................
Upper Buffalo ...............................................................................................................................
Hercules-Glades ..........................................................................................................................
Mingo ...........................................................................................................................................
amozie on DSK3GDR082PROD with PROPOSALS5
The installation and operation of SO2
controls is anticipated to result in
considerable visibility improvement
from the baseline at the four impacted
Class I areas. NID technology is
anticipated to result in visibility
improvement ranging from 0.345 to
0.615 dv at each affected Class I area.
Although wet FGD is also anticipated to
result in considerable visibility
improvement, the visibility benefit of
wet FGD over NID technology at each
individual Class I area is anticipated to
be only slight, ranging from 0.007 to
0.014 dv at each Class I area.
As discussed above, SWEPCO
determined that NID technology would
result in considerable visibility
improvement and is estimated to cost
$3,845/ton. On the other hand, a wet
scrubber is estimated to cost $4,919/ton,
and would only achieve slightly more
visibility benefit than NID technology
(see Table 7).78 Therefore, SWEPCO
recommended that SO2 BART for Flint
Creek Boiler No. 1 be an emission limit
of 0.06 lb/MMBtu on a 30-day rolling
average over each boiler operating day,
based on the installation of NID
technology. ADEQ concurred with this
BART recommendation. We are
proposing to agree that an SO2 emission
limit of 0.06 lb/MMBtu based on NID
technology would result in significant
visibility benefits from the baseline and
is generally cost-effective. We do not
believe the additional cost of a wet
scrubber would be justified in light of
the small amount of additional visibility
benefit anticipated over NID technology.
Therefore, we are proposing to approve
the state’ determination that SO2 BART
for Flint Creek Boiler No. 1 is an
78 Although not discussed by ADEQ in the SIP
revision, SWEPCO’s BART analysis also presents
the incremental cost effectiveness of wet scrubbers
over NID technology. As shown in Tables 5–3 and
5–7 of SWEPCO’s September 2013 SO2 BART
analysis for Flint Creek, the incremental cost
effectiveness of wet scrubbers over NID technology
for Boiler No. 1 is estimated to be $35,198/ton
removed, yet the incremental visibility benefit is
projected to be only 0.014 dv at Caney Creek and
0.013 dv at Upper Buffalo and even less at Hercules
Glades and Mingo.
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21:33 Nov 29, 2018
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emission limit of 0.06 lb/MMBtu based
on NID technology.
Taking into consideration that the
control equipment has already been
installed and is operating at the facility,
we are also proposing to approve the
state’s determination that the source
must comply with the SO2 BART
requirements as of the effective date of
the Administrative Order, which is
August 7, 2018. These BART
requirements have now been made
enforceable by the state through an
Administrative Order that has been
adopted and incorporated in the SIP
revision. The Administrative Order for
Flint Creek Boiler No. 1 includes not
only the SO2 emission limit, but also a
requirement for the source to determine
compliance with the SO2 emission limit
by using a continuous emission
monitoring system.79 We are proposing
to approve into the SIP the state’s
Administrative Order with respect to
the SO2 BART requirements, including
the compliance determination
requirements contained in the
Administrative Order. The state’s SO2
BART decision for Flint Creek Boiler
No. 1 is consistent with the BART
decision EPA previously made in the
FIP we promulgated on September 27,
2016.80 We are concurrently proposing
to withdraw the FIP’s SO2 BART
requirements for Flint Creek Boiler No.
1, as they would be replaced by our
approval of the state’s SO2 BART
decision.
4. Entergy Lake Catherine Unit 4
Entergy Lake Catherine Unit 4 has a
558 MW tangentially-fired boiler with a
maximum heat input of 5,850 MMBtu/
hr. Lake Catherine Unit 4 is currently
permitted to burn only pipeline quality
natural gas, but until recently was also
permitted to burn No. 6 fuel oil as a
secondary fuel. Entergy produced a
BART analysis dated May 2014 for Lake
Catherine Unit 4, which was evaluated
79 The Administrative Order can be found in the
Arkansas Regional Haze SO2 and PM BART SIP
Revision.
80 81 FR 66335 and 66416–17.
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0.963
0.965
0.657
0.631
Visibility benefit of controls
over baseline
(dv)
NID System
0.615
0.464
0.345
0.414
Wet FGD
0.629
0.477
0.352
0.423
by EPA and largely formed the basis for
EPA’s BART evaluation in the FIP.81
The same BART analysis 82 has now
been adopted and incorporated by
ADEQ into the Arkansas Regional Haze
SO2 and PM BART SIP revision to
address BART requirements for Lake
Catherine Unit 4 under the fuel oil firing
scenario.83
In the May 2014 BART analysis
submitted by ADEQ as part of the SIP
revision, Entergy explained that no fuel
oil has been burned at Unit 4 since prior
to the 2001–2003 baseline period and
that the company does not project that
it will burn fuel oil at the unit in the
foreseeable future. Therefore, the May
2014 BART analysis does not consider
emissions from fuel oil firing and does
not include a BART five factor analysis
or BART determinations for the fuel oil
firing scenario. Entergy stated in the
BART analysis that if conditions change
such that it becomes economic to burn
fuel oil in the future, it will submit a
BART five factor analysis for the fuel oil
firing scenario to the state for use in the
development of a SIP revision, and that
Entergy commits to not burn fuel oil at
Lake Catherine Unit 4 until final EPA
approval of BART for the fuel oil firing
scenario. Furthermore, Unit 4 is not
currently permitted to burn fuel oil.84
Entergy’s commitment has now been
made enforceable by the state through
an Administrative Order that has been
adopted and incorporated in the SIP
revision. We are proposing to find that
81 80
FR 18975.
BART Five Factor Analysis Lake
Catherine Steam Electric Station Malvern, Arkansas
(AFIN 30–00011),’’ dated May 2014, prepared by
Trinity Consultants Inc. in conjunction with
Entergy Services Inc.,’’ which can be found in
Appendix C to the Arkansas Regional Haze SO2 and
PM BART SIP Revision.
83 In a final action published on March 12, 2012,
EPA approved Arkansas’ SO2 and PM BART
determinations under the natural gas firing scenario
for Lake Catherine Unit 4. In the Arkansas Regional
Haze SO2 and PM BART SIP revision, the state is
not revising those BART determinations or any of
the underlying analyses.
84 See ADEQ Air Permit No. 1717–AOP–R7,
issued on October 26, 2016. A copy of the air permit
can be found in the docket for this proposed
rulemaking.
82 ‘‘Revised
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this approach is appropriate and we are
proposing to approve the state’s
Administrative Order for Lake Catherine
Unit 4 into the SIP. The Administrative
Order would allow the unit to burn
natural gas only, per Entergy’s
commitment to not burn fuel oil at Unit
4 until ADEQ submits a SIP revision
that includes BART analyses for the fuel
oil firing scenario for Unit 4 and EPA
takes final action to approve the BART
determinations. The state’s action with
respect to addressing BART for the fuel
oil firing scenario for Lake Catherine
Unit 4 is consistent with the action EPA
previously took in the FIP we
promulgated on September 27, 2016.85
We are concurrently proposing to
withdraw the FIP provision concerning
BART for the fuel oil firing scenario for
Lake Catherine Unit 4, as it would be
replaced by our approval of the state’s
BART action.
5. Entergy White Bluff Units 1 and 2 and
the White Bluff Auxiliary Boiler
Entergy White Bluff Units 1 and 2
each have tangentially-fired 850 MW
boilers with a maximum heat input
capacity of 8,950 MMBtu/hr. White
Bluff also has a 183 MMBtu/hr
Auxiliary Boiler that is permitted to
burn only No. 2 fuel oil or biodiesel.
Entergy produced a BART analysis for
White Bluff dated October 2013, which
was evaluated by EPA and largely
formed the basis for EPA’s SO2 BART
evaluation in the FIP.86 Entergy also
submitted revised analyses dated
August 2015 and August 2016 for EPA
to consider before the FIP was finalized.
Entergy provided ADEQ with
supplemental information on April 5,
2017, providing cost-effectiveness data
for dry FGD for Units 1 and 2 with
various remaining useful life
assumptions. Additionally, at ADEQ’s
request, Entergy produced an updated
BART analysis dated August 18, 2017,
that evaluated several control options
and provided updated remaining useful
life information for White Bluff Units 1
and 2. These BART analyses and other
documentation provided by Entergy
have been adopted and incorporated by
ADEQ into the Arkansas Regional Haze
SO2 and PM BART SIP revision 87 to
85 81
FR 66335 and 66418.
FR 18969. See also ‘‘Revised BART Five
Factor Analysis White Bluff Steam Electric Station
Redfield, Arkansas (AFIN 35–00110),’’ dated
October 2013, prepared by Trinity Consultants Inc.
in conjunction with Entergy Services Inc.’’ This
BART analysis can be found in Appendix D to the
Arkansas Regional Haze SO2 and PM BART SIP
Revision.
87 These BART analyses and other information
provided by Entergy can be found in Appendix D
to the Arkansas Regional Haze SO2 and PM BART
SIP Revision.
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address the SO2 BART requirements for
White Bluff Units 1 and 2, as well as the
SO2, NOX, and PM BART requirements
for the Auxiliary Boiler.88
a. White Bluff Unit 1 and Unit 2 SO2
BART Analysis and Determinations
In assessing SO2 BART, Entergy
considered the five BART factors. There
is currently no SO2 control equipment
in use at Units 1 and 2. The current
permitted SO2 emissions rate for Units
1 and 2 is a 3-hour average emission rate
of 1.2 lb/MMBtu, based on the new
source performance standard for fossilfuel fired steam generators in effect at
the time they were constructed. The
available SO2 control technology
options considered in Entergy’s August
2017 BART analysis are switching to
low sulfur coal, DSI, spray dryer
absorber (SDA), circulating dry scrubber
(CDS), and wet FGD.
Entergy estimated that by switching to
low sulfur coal, Units 1 and 2 can
achieve an emission rate of 0.6 lb/
MMBtu,89 which would result in
approximately an 8.75% reduction in
SO2 emissions from baseline levels. For
DSI, Entergy considered two particulate
collection methods. The first collection
method, ‘‘DSI,’’ would utilize the
existing ESP, and is expected to achieve
a control efficiency of 50%. Entergy
expects that DSI would achieve an SO2
emission rate of 0.35 lb/MMBtu. The
second collection method, ‘‘enhanced
DSI,’’ would require the installation of
a fabric filter or baghouse. The use of a
fabric filter or baghouse in enhanced
DSI increases the residence time and
improves the collection efficiency to
allow more sorbent to be injected,
thereby resulting in greater emissions
reductions. Entergy expects that
enhanced DSI would achieve 80%
control efficiency, and an SO2 emission
rate of 0.15 lb/MMBtu. In the August
2017 BART analysis, Entergy claimed
that DSI has not yet been demonstrated
on units comparable to those at White
Bluff. Entergy explained that the largest
88 In a final action published on March 12, 2012,
EPA approved Arkansas’ PM BART determinations
for White Bluff Units 1 and 2. In the Arkansas
Regional Haze SO2 and PM BART SIP revision, the
state is not revising those PM BART determinations
or any of the underlying analyses.
89 The White Bluff SO BART analysis provided
2
to ADEQ by Entergy and incorporated by ADEQ as
part of the SIP revision considered an SO2 emission
limit of 0.6 lb/MMBtu for the switching to low
sulfur coal control option. However, in response to
comments the state received during the public
comment period that noted that it is typical to
round to the nearest significant digit when
demonstrating compliance, which could result in
less emissions reductions than assumed in the
BART analysis, ADEQ ultimately finalized an
emission limit of 0.60 lb/MMBtu in the final SIP
revision.
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known installed and operational DSI
system has a design feed rate of 12 tons/
hour of sorbent, while most installed
DSI systems typically inject
approximately 5–6 tons/hour of sorbent
into the exhaust gas stream. Entergy
pointed out that the predicted injection
rate of enhanced DSI at White Bluff is
approximately 15 tons/hour of sorbent.
Entergy noted that the greater the
injection rates, it is anticipated that
more issues associated with supply and
delivery logistics are likely to arise.
Entergy stated that before DSI
technology is selected as BART for
White Bluff, a demonstration test would
need to be performed to confirm its
feasibility, achievable performance, and
balance of plant impacts (brown plume
formation, ash handling modifications,
landfill/leachate considerations, and
impact to mercury control).
The dry FGD control option
considered by Entergy is SDA, which
utilizes a fine mist of lime slurry
sprayed into an absorption tower to
absorb SO2 with the resulting calcium
sulfite and calcium sulfate then
collected with a fabric filter. SDA
systems can typically achieve SO2
control efficiencies ranging from 60–
95%. Entergy expects that an SDA
system would achieve an emission rate
of 0.06 lb/MMBtu at Units 1 and 2.
Although wet FGD was identified as a
technically feasible control option, it is
not expected to achieve significant
visibility benefit beyond dry/semi-dry
FGD despite having a greater estimated
cost, based on the October 2013 BART
analysis that EPA relied on to develop
the Arkansas Regional Haze FIP.90 In
fact, dry/semi-dry FGD was expected to
achieve slightly greater visibility benefit
than wet FGD at Hercules-Glades and
Mingo based on the October 2013 BART
analysis.91 Therefore, Entergy did not
further consider wet FGD in its August
18, 2017, BART analysis, on which the
Arkansas Regional Haze SO2 and PM
BART SIP revision is largely based.
In considering the costs of
compliance, Entergy’s coal suppliers
provided the company with an
estimated incremental cost of $0.50 per
ton for delivering coal guaranteed to
have a sulfur content consistent with
achieving an SO2 emission limit of 0.6
lb/MMBtu. ADEQ noted in the SIP
revision that the annualized cost of
switching to low sulfur coal is not
dependent on the remaining useful life
of White Bluff Units 1 and 2, since no
capital investments in equipment would
be necessary. For the remaining control
options, Entergy obtained capital costs
90 80
91 80
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and annual operating and maintenance
costs from its consultant and used this
to estimate the cost effectiveness of
controls. The annualized cost of DSI,
enhanced DSI, and dry/semi-dry FGD is
dependent on the remaining useful life
of the White Bluff units since those
control options require capital
investments in new equipment or
retrofit of existing equipment. These
capital investments were amortized over
the remaining useful life of the White
Bluff units to determine the annualized
costs and compared to annual emission
reductions to determine costeffectiveness. In the August 18, 2017,
BART analysis, Entergy stated that it
anticipates cessation of coal combustion
at White Bluff by the end of 2028 and
that it will voluntarily take an
enforceable restriction on Units 1 and 2
to that effect. ADEQ noted that the
BART Guidelines provide that the
remaining useful life calculation should
begin on the date that controls will be
put in place (i.e., compliance date) and
end on the date the facility permanently
stops operations.92 The Regional Haze
Rule also states that the compliance date
for BART controls must be as
expeditiously as practicable, but in no
event later than 5 years after approval of
the SIP.93 Considering that the FIP
currently requires SO2 emission limits
for White Bluff Units 1 and 2 that are
based on dry scrubber installation and
which have a compliance date of
October 27, 2021, ADEQ acknowledged
that the record suggests that a
compliance date for scrubbers that is ‘‘as
expeditiously as practicable’’ would be
October 27, 2021. Therefore, ADEQ
assumed a remaining useful life of 7
years to estimate the cost-effectiveness
of SDA for White Bluff Units 1 and 2.
Entergy also assumed that DSI and
enhanced DSI could be installed and
operational 2 years earlier than FGD,
and therefore assumed in the BART
analysis that DSI and enhanced DSI
could be operational at White Bluff
Units 1 and 2 by the end of 2019 and
that the capital recovery period for those
controls is therefore 9 years.
Entergy also explained that for DSI,
enhanced DSI, and SDA, it developed
two sets of cost estimates. The first is
the actual cost Entergy anticipates
incurring for each control option, and
the second reflects the exclusion of
certain cost items that are disallowed
costs under the methodology in the
EPA’s Air Pollution Control Cost
Manual (EPA Control Cost Manual).94
These ‘‘disallowed’’ line items include
Allowance for Funds Used During
Construction (AFUDC). Entergy stated
in its BART analysis that it disagrees
with EPA that AFUDC and certain other
cost items are not allowed to be
considered in estimating the cost
effectiveness of controls for BART
purposes under the EPA Control Cost
Manual, but nonetheless provided a set
of cost estimates reflecting the exclusion
of the disallowed line items as well as
a set of cost estimates that included
these line items. ADEQ explained in the
SIP revision that its evaluation of
controls is based on Entergy’s set of cost
numbers that excludes the disallowed
line items and follows the EPA Control
Cost Manual. Therefore, we present here
only the set of cost numbers that follows
the methodology allowed under the
Control Cost Manual.95
Entergy determined that switching to
low sulfur coal would entail an
increased annual cost of operation based
on purchase contract terms for the
specific sulfur content of the coal. Based
on estimates provided by the coal
supplier of the cost premium for low
sulfur coal and the estimated reduction
in emissions, Entergy anticipated that
the cost to guarantee that the units
achieve an SO2 emission limit of 0.6 lb/
MMBtu translates to a cost-effectiveness
for SO2 control of approximately
$1,150/ton at Unit 1 and $1,148/ton at
Unit 2. Entergy estimated the costeffectiveness of DSI to be $6,269/ton at
Unit 1 and $6,211/ton at Unit 2 and the
cost-effectiveness of enhanced DSI to be
$6,427/ton at Unit 1 and $6,384/ton at
Unit 2. Entergy also estimated the cost
of SDA to be $5,420/ton at Unit 1 and
$5,387/ton at Unit 2. In the BART
analysis, ADEQ also took into
consideration the cost of controls in
terms of dollars per dv improvement ($/
dv) for each SO2 control option
considered for White Bluff. A summary
of the cost of controls in terms of $/dv
is provided in Table 8. A summary of
Entergy’s assessment of the visibility
benefits of the control options in terms
of dv is presented in Tables 9 and 10.
ADEQ stated that the average costeffectiveness values for DSI, enhanced
DSI, and SDA at White Bluff all exceed
what is typically considered to be costeffective for BART, taking into account
a capital cost recovery period of 7 years
for SDA and 9 years for DSI and
enhanced DSI. ADEQ noted that costeffectiveness values of BART
determinations made in previous
regional haze actions have typically
been below $5,000/ton, and that the
costs of DSI and SDA exceed this value.
Additionally, ADEQ noted that the cost
in terms of $/dv for DSI, enhanced DSI,
and SDA are approximately an order of
magnitude greater than for switching to
low sulfur coal.
TABLE 8—COST OF SO2 CONTROLS ($/DV) FOR WHITE BLUFF UNITS 1 AND 2
Class I area
SO2 control option
Caney Creek
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Low Sulfur Coal ...............................................................................................
DSI ...................................................................................................................
Enhanced DSI ..................................................................................................
SDA ..................................................................................................................
92 70
FR 39104.
CFR 51.308(e)(iv).
94 At the time the BART Guidelines were
finalized, the current version of the Control Cost
Manual was the EPA Air Pollution Control Cost
Manual, Sixth Edition, EPA/452/B–02–001, January
2002. https://www.epa.gov/economic-and-costanalysis-air-pollution-regulations/cost-reports-andguidance-air-pollution. The EPA is engaged in a
long-term process to update portions of the Control
93 40
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$14,500,519
133,341,667
158,855,956
131,447,683
Cost Manual. A project plan describing the scope
and schedule for this update effort is available at
https://www3.epa.gov/ttn/ecas/docs/cost_manual_
timeline_2016-08-04.pdf. As draft or final updated
chapters are available, states should follow the
recommendations in those rather than in the 6th
Edition. Final revised chapters are posted at https://
www.epa.gov/economic-and-cost-analysis-airpollution-regulations/cost-reports-and-guidanceair-pollution. Draft revised chapters are announced
in the Federal Register when available for public
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Upper Buffalo
$11,932,988
105,417,939
139,165,572
121,373,255
Hercules
Glades
$10,666,332
120,512,761
168,897,541
153,165,608
Mingo
$13,554,882
116,126,126
173,433,064
153,852,117
comment and can be obtained from EPA Docket No.
EPA–HQ–OAR–2015–0341 at
www.regulationgs.gov.
95 Please see the TSD associated with this
proposed rulemaking and the Arkansas Regional
Haze SO2 and PM SIP revision for Entergy’s set of
cost numbers that included line items that are not
allowed to be considered in estimating the cost
effectiveness of controls for BART purposes under
the EPA Control Cost Manual.
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In the BART analysis, Entergy noted
that there were adverse energy and
nonair quality environmental impacts
associated with DSI, enhanced DSI, and
SDA. These impacts were factored into
the costs of compliance. With regard to
consideration of the remaining useful
life factor, Entergy stated in the August
2017 BART analysis that it anticipates
cessation of coal combustion at White
Bluff by the end of 2028 and that it will
voluntarily take an enforceable
restriction on Units 1 and 2 to that
effect. Entergy’s voluntary decision to
cease coal combustion by the end of
2028 is enforceable by the state through
an Administrative Order that has been
adopted and incorporated in the SIP
revision. Therefore, for White Bluff
Units 1 and 2, ADEQ assumed a
remaining useful life of 7 years to
estimate the cost-effectiveness of SDA
62221
and a remaining useful life of 9 years to
estimate the cost-effectiveness of DSI.
In assessing visibility impacts, the
state’s submittal included the CALPUFF
modeling that was included in Entergy’s
August 18, 2017, BART analysis,
evaluating the visibility benefits of
switching to low sulfur coal, DSI,
enhanced DSI, and SDA. We summarize
the results of that modeling in Tables 9
and 10.96
TABLE 9—ANTICIPATED VISIBILITY BENEFIT DUE TO SO2 CONTROLS AT WHITE BLUFF UNIT 1
[CALPUFF, 98th percentile] *
Visibility benefit of controls over baseline
(dv)
Baseline
visibility
impact
(dv)
Class I area
Caney Creek ........................................................................
Upper Buffalo .......................................................................
Hercules-Glades ..................................................................
Mingo ...................................................................................
Low sulfur
coal
1.505
1.051
0.925
0.802
DSI
0.129
0.143
0.167
0.115
Enhanced DSI
0.308
0.375
0.341
0.333
0.492
0.555
0.467
0.436
SDA
0.603
0.642
0.525
0.504
* This table shows the modeled visibility benefits of SO2 controls for White Bluff Unit 1, as presented in Table 4–6 of Entergy’s August 18,
2017, SO2 BART analysis for White Bluff, which can be found in Appendix D of the Arkansas Regional Haze SO2 and PM SIP revision. Although
the combined visibility benefits on a facility-wide basis were not modeled, we expect that such combined visibility benefits would be greater than
the unit specific values shown in this table.
TABLE 10—ANTICIPATED VISIBILITY BENEFIT DUE TO SO2 CONTROLS AT WHITE BLUFF UNIT 2
[CALPUFF, 98th percentile] *
Visibility benefit of controls over baseline
(dv)
Baseline
visibility
impact
(dv)
Class I area
Caney Creek ........................................................................
Upper Buffalo .......................................................................
Hercules-Glades ..................................................................
Mingo ...................................................................................
Low sulfur
coal
1.533
1.059
0.912
0.819
DSI
0.097
0.127
0.137
0.122
Enhanced DSI
0.274
0.359
0.303
0.333
0.460
0.531
0.429
0.435
SDA
0.574
0.632
0.486
0.501
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* This table shows the modeled visibility benefits of SO2 controls for White Bluff Unit 2, as presented in Table 4–7 of Entergy’s August 18,
2017, SO2 BART analysis for White Bluff, which can be found in Appendix D of the Arkansas Regional Haze SO2 and PM SIP revision. Although
the combined visibility benefits on a facility-wide basis were not modeled, we expect that such combined visibility benefits would be greater than
the unit specific values shown in this table.
The SO2 control options considered
are anticipated to result in considerable
visibility improvement from the
baseline at the four impacted Class I
areas. For White Bluff Unit 1, switching
to low sulfur coal is anticipated by the
state submittal to result in visibility
improvement ranging from 0.115 to
0.167 dv at each affected Class I area.
DSI is anticipated to result in visibility
improvement ranging from 0.308 to
0.375 dv at each affected Class I area,
while enhanced DSI is anticipated to
result in visibility improvement ranging
from 0.436 to 0.555 dv. SDA is
anticipated to result in the greatest
visibility improvement, ranging from
0.504 to 0.642 dv.
For White Bluff Unit 2, switching to
low sulfur coal is anticipated by the
state submittal to result in visibility
improvement ranging from 0.097 to
0.137 dv at each affected Class I area.
DSI is anticipated to result in visibility
improvement ranging from 0.274 to
0.359 dv at each affected Class I area,
while enhanced DSI is anticipated to
result in visibility improvement ranging
from 0.429 to 0.531 dv. SDA is
anticipated to result in the greatest
visibility improvement, ranging from
0.486 to 0.632 dv.
96 As explained by ADEQ in the SIP revision,
Entergy’s modeling of the visibility improvement
from evaluated SO2 controls in the August 18, 2017,
SO2 BART analysis for White Bluff is based on an
updated baseline of 2009–2013 emissions, rather
than the 2001–2003 emissions baseline EPA used in
the Arkansas Regional Haze FIP to estimate the
visibility improvement anticipated from SDA and
wet FGD. Entergy’s change in baseline emissions
impacts the modeled visibility benefit anticipated
from SDA, resulting in a modeled visibility benefit
that is 15% to 26% lower at each unit in Entergy’s
updated analysis compared to the FIP. In the FIP,
EPA did not evaluate the visibility improvement
anticipated from DSI, enhanced DSI, and switching
to low sulfur coal, but ADEQ stated it expects that
the relative difference in $/dv among the control
options evaluated by Entergy would be similar
across both baseline periods. Further, ADEQ
believes that the differences in projected visibility
benefits resulting from different baseline emissions
in the FIP, compared to the updated Entergy BART
analysis, would not result in a change to ADEQ’s
ultimate SO2 BART decision for White Bluff Units
1 and 2.
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Taking into consideration the
remaining useful life of White Bluff
Units 1 and 2 and the resulting costeffectiveness as well as the anticipated
visibility improvement of the SO2
control options, ADEQ concurred with
Entergy’s recommendation that SO2
BART for White Bluff Units 1 and 2 is
an emission limit of 0.60 lb/MMBtu
based on the use of low sulfur coal.97
All other SO2 control options for White
Bluff have an average cost-effectiveness
value greater than $5,000/ton, which
ADEQ stated exceeds what has typically
been considered to be cost-effective for
BART. Additionally, ADEQ noted that
the cost-effectiveness in terms of $/dv
for DSI, enhanced DSI, and SDA are
approximately an order of magnitude
greater than for LSC. Considering the
costs and the visibility benefits of the
control options, ADEQ determined that
SO2 BART for White Bluff is an
emission limit of 0.60 lb/MMBtu based
on the use of low sulfur coal.98
In support of its assertion that a 3-year
compliance deadline is needed to meet
this emission limit, Entergy submitted a
letter to ADEQ dated April 3, 2018,
explaining that it is the company’s
practice to project how much coal will
be needed in future years and to
contract for a portion of its coal supply
up to 3 years in advance.99 Entergy
stated that it keeps a reserve supply of
coal at White Bluff to ensure that the
units can continue to operate in the
event of a fuel supply disruption.
Entergy finds that a 3-year compliance
date is necessary for the 0.60 lb/MMBtu
emission limit because the sulfur
content limits of Entergy’s existing coal
contracts for the next 3 years exceed this
emission rate. Entergy is currently
under contract for coal with a sulfur
content of 1.2 lb/MMBtu or less. Entergy
noted that even though the coal
delivered to White Bluff has lately been
of lower sulfur content than required by
97 Entergy evaluated an SO emission rate of 0.6
2
lb/MMBtu based on the use of low sulfur coal in
the SO2 BART analysis for White Bluff. However,
ADEQ ultimately selected 0.60 lb/MMBtu as the
BART emission limit in response to comments it
received during the state public comment period
raising concerns that finalizing an emission limit of
0.6 lb/MMBtu could result in smaller SO2
reductions than assumed because it is typical to
round to the nearest significant digit when
demonstrating compliance.
98 The White Bluff SO BART analysis submitted
2
by Entergy and ADEQ’s SIP revision both
considered an SO2 emission limit of 0.6 lb/MMBtu
for the switching to low sulfur coal control option.
However, in response to comments the state
received during the public comment period that
noted that it is typical to round to the nearest
significant digit when demonstrating compliance,
which could result in less emissions reductions
than assumed in the analysis, ADEQ ultimately
finalized an emission limit of 0.60 lb/MMBtu in the
final SIP revision.
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the contract, its experience is that the
sulfur content can vary widely. Entergy
also stated that as of the letter dated
April 3, 2018, it had already contracted
for a portion of its coal supply needs for
the next 3 years (through the end of the
year 2020). Those contracts are for coal
with a sulfur content limit ranging from
0.7 to 0.9 lb/MMBtu. Additionally,
Entergy stated it cannot accurately
calculate expected SO2 emissions from
blending of coals from its stockpile and
new deliveries of coal because the sulfur
content of the stockpile coal is not
tracked. Entergy explained that this
means that it cannot ensure that White
Bluff will receive coal with a low
enough sulfur content to ensure
compliance with the 0.60 lb/MMBtu
emission limit until the company has
had sufficient time to negotiate new
contracts and the existing coal supply
has been depleted and replaced with
coal that has a lower sulfur content.
ADEQ agreed that a 3-year compliance
date for the 0.60 lb/MMBtu emission
limit based on the use of low sulfur coal
is reasonable given the site-specific
circumstances for White Bluff as
discussed in Entergy’s letter dated April
3, 2018.
With regard to the cost analysis for
SO2 controls for White Bluff, we agree
that AFUDC and certain other cost items
are not allowed to be considered in
estimating the cost effectiveness of
controls for BART purposes under the
EPA Control Cost Manual, and we also
acknowledge and agree with ADEQ’s
decision to base its evaluation of
controls on Entergy’s set of cost
numbers that does not include the
disallowed line items. Nevertheless,
there is one aspect of Entergy’s cost
analysis that we do not agree with.
Entergy’s cost analysis is based on an
SDA system assuming a coal sulfur
content of 1.2 lb/MMBtu, which Entergy
stated is based on its current coal
contract sulfur limit. However, the
White Bluff units have historically
burned coal with a lower sulfur content.
In its BART analysis, Entergy stated that
the current average sulfur content of
coal received at the White Bluff station
is 0.57 lb SO2/MMBtu but that the
facility could receive coal with sulfur
content up to 1.2 lb SO2/MMBtu. Given
that, Entergy’s analysis is based on a
scrubber designed to handle that sulfur
load. In the Arkansas Regional Haze FIP,
we noted that Entergy’s SO2 cost
analysis for White Bluff, which was
provided to us by Entergy for EPA’s
evaluation and consideration in the
99 The letter from Entergy, dated April 3, 2018, is
found in Appendix D the Arkansas Regional Haze
SO2 and PM BART SIP Revision.
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development of the FIP, took the
approach of costing a scrubber system
designed to burn coal with a sulfur
content much higher than what has
been historically burned,100 an
approach similar to what Entergy has
done in the August 2017 BART analysis.
In the FIP, we stated that we disagreed
with Entergy’s approach for costing of
the scrubber system, and our FIP cost
analysis was instead based on a dry
scrubber system assuming a sulfur
content of 0.68 lb/MMBtu, the
maximum monthly emission rate from
2009–2013. Relying on our FIP’s cost
analysis for dry scrubbers for White
Bluff, which was based on a scrubber
system designed to burn coal having a
sulfur content consistent with what the
units have historically burned, and
adjusting for a 7-year as opposed to a
30-year capital cost recovery period to
reflect that the units will cease coal
combustion by the end of 2028,101 we
estimate that the cost of dry scrubbers
at White Bluff Units 1 and 2 is $4,376/
ton for Unit 1 and $4,129/ton for Unit
2.102 As noted in the SIP revision,
Entergy’s August 18, 2017, SO2 BART
analysis for White Bluff shows that the
estimated visibility benefit of dry
scrubbers for Unit 1 is 0.603 dv at Caney
Creek and 0.642 dv at Upper Buffalo,
and for Unit 2 is 0.574 dv at Caney
Creek and 0.632 dv at Upper Buffalo.103
Although our cost estimates for dry
scrubbers are more cost-effective than
estimated by Entergy, we still consider
these cost numbers to be on the higher
end of what has been found to be cost
effective in other regional haze actions
when also taking into account the level
of visibility benefit of the controls. We
are proposing to agree with ADEQ’s
conclusion that dry scrubbers are not
BART for White Bluff Units 1 and 2.
We are also proposing to agree with
ADEQ that the cost of compliance, in
dollars per ton, for DSI and enhanced
DSI is not cost effective when the
100 81 FR 66385; See also ‘‘Response to Comments
for the Federal Register Notice for the State of
Arkansas; Regional Haze and Interstate Visibility
Transport Federal Implementation Plan,’’ pages
261–263, and 345–349. The FIP Response to
Comments document is found in the docket at
https://www.regulations.gov/document?D=EPAR06-OAR-2015-0189-0187.
101 We are proposing to agree that it is appropriate
to assume a capital cost recovery period of 7 years
for scrubber controls in the BART analysis since
Entergy’s voluntarily proposed date for cessation of
coal combustion at White Bluff Units 1 and 2 by
the end of 2028 has been made enforceable through
an Administrative Order. The Administrative Order
can be found in the Arkansas Regional Haze SO2
and PM BART SIP Revision.
102 See Excel spreadsheet titled ‘‘EPA Revised
cost calcs_WB_Corrected CRF 7 years.xlsx,’’ which
is found in the docket for this proposed rulemaking.
103 See Tables 4–6 and 4–7 of Entergy’s August
18, 2017, White Bluff SO2 BART analysis.
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remaining useful life of White Bluff
Units 1 and 2 is taken into account. We
are proposing to agree that switching to
low sulfur coal would result in visibility
benefits from the baseline and would be
very cost-effective. Therefore, we are
proposing to approve the state’s
determination that given Entergy’s
enforceable commitment to cease coal
combustion at White Bluff Units 1 and
2 by the end of 2028, SO2 BART for
Units 1 and 2 is an SO2 emission limit
of 0.60 lb/MMBtu based on switching to
low sulfur coal. The Administrative
Order for the White Bluff units also
includes a requirement for the source to
determine compliance with the SO2
emission limits for Units 1 and 2 by
using a continuous emission monitoring
system. These BART requirements are
enforceable by the state through an
Administrative Order that has been
adopted and incorporated in the SIP
revision. We are proposing to approve
in the SIP the state’s Administrative
Order, including the 3-year compliance
date to meet the 0.60 lb/MMBtu
emission limit and the requirement for
Entergy to move forward with its
proposed plan to cease coal combustion
at White Bluff Units 1 and 2 no later
than December 31, 2028.104 We are
proposing to find that Entergy’s
explanation that it cannot ensure that
White Bluff will receive coal with a low
enough sulfur content to ensure
compliance with the 0.60 lb/MMBtu
emission limit until the company has
had sufficient time to negotiate new
contracts and the existing coal supply,
including the coal for which Entergy is
already under contract through the year
2020, has been depleted and replaced
with coal that has a lower sulfur
content, is reasonable. Therefore, we are
proposing to find that a 3-year
compliance date for the 0.60 lb/MMBtu
SO2 BART emission limit is appropriate
and reasonable. We are concurrently
proposing to withdraw the FIP’s SO2
BART requirements for White Bluff
Units 1 and 2, as they would be
replaced by our approval of the state’s
SO2 BART decision.
b. White Bluff Auxiliary Boiler BART
Determinations
In determining BART for the White
Bluff Auxiliary Boiler, ADEQ relied on
Entergy’s October 2013 BART analysis
for White Bluff.105 In the BART
analysis, Entergy explained that air
dispersion modeling demonstrates that
the maximum visibility impact
predicted from the Auxiliary Boiler is
0.036 dv, which it characterized as a
very low level of visibility impact. The
modeling results also show that looking
at the 98th percentile visibility impacts,
the greatest impact from the Auxiliary
Boiler is 0.01 dv at Caney Creek.106
Entergy reasoned that since the existing
visibility impairment due to the
Auxiliary Boiler is extremely low, any
improvement due to controls are
expected to be negligible. ADEQ further
expanded on this finding by explaining
that the Arkansas Regional Haze FIP
found that due to the small level of
baseline visibility impairment caused by
the Auxiliary Boiler, the existing SO2,
NOX, and PM emission limitations in
the Entergy White Bluff permit were
determined to satisfy BART for the
Auxiliary Boiler. ADEQ stated that it
agrees that SO2, NOX, and PM BART for
the Auxiliary Boiler are the existing
emission limits in the facility’s air
permit. We are proposing to find that
the state’s SO2, NOX, and PM BART
decisions for the Auxiliary Boiler are
appropriate. The BART Rule provides:
‘‘Consistent with the CAA and the
implementing regulations, States can
adopt a more streamlined approach to
making BART determinations where
appropriate. Although BART
determinations are based on the totality
of circumstances in a given situation,
such as the distance of the source from
a Class I area, the type and amount of
pollutant at issue, and the availability
and cost of controls, it is clear that in
some situations, one or more factors will
clearly suggest an outcome. Thus, for
example, a State need not undertake an
exhaustive analysis of a source’s impact
on visibility resulting from relatively
minor emissions of a pollutant where it
is clear that controls would be costly
and any improvements in visibility
resulting from reductions in emissions
of that pollutant would be
negligible.’’ 107
Given the very small baseline
visibility impacts from the Auxiliary
Boiler, we believe it is appropriate to
take a streamlined approach for
determining BART in this case. Because
of the very low baseline visibility
impacts from the Auxiliary Boiler at
each modeled Class I area, we believe
104 The Administrative Order can be found in the
Arkansas Regional Haze SO2 and PM BART SIP
Revision.
105 ‘‘Revised BART Five Factor Analysis White
Bluff Steam Electric Station Redfield, Arkansas
(AFIN 35–00110), dated October 2013, prepared by
Trinity Consultants Inc. in conjunction with
Entergy Services Inc.’’ This BART analysis can be
found in Appendix D to the Arkansas Regional
Haze SO2 and PM BART SIP Revision.
106 ‘‘Revised BART Five Factor Analysis White
Bluff Steam Electric Station Redfield, Arkansas
(AFIN 35–00110), dated October 2013, prepared by
Trinity Consultants Inc. in conjunction with
Entergy Services Inc.,’’ see Table 4–4.
107 70 FR 39116.
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that the visibility improvement that
could be achieved through the
installation and operation of controls
would be negligible, such that the cost
of those controls could not be justified.
Therefore, we are proposing to approve
the state’s determination that the
existing SO2, NOX, and PM emission
limitations in the Entergy White Bluff
permit are BART for the Auxiliary
Boiler. Specifically, these emission
limits are 105.2 lb/hr SO2, 32.2 lb/hr
NOX, and 4.5 lb/hr PM. These BART
requirements are enforceable by the
state through an Administrative Order
that has been adopted and incorporated
in the SIP revision. We are proposing to
approve into the SIP the state’s
Administrative Order, including the
requirement that the White Bluff
Auxiliary Boiler comply with BART as
of the effective date of the
Administrative Order, which is August
7, 2018.108 We are concurrently
proposing to withdraw the FIP’s SO2
and PM BART requirements for the
Auxiliary Boiler, as they would be
replaced by our approval of the state’s
BART decisions.
We also note that in the Arkansas
Regional Haze NOX SIP revision, ADEQ
erroneously identified the Auxiliary
Boiler as participating in CSAPR for
ozone season NOX, and the state elected
to rely on participation in that trading
program to satisfy the Auxiliary Boiler’s
NOX BART requirements. In a final
action published in the Federal Register
on February 12, 2018, we took final
action to approve this SIP revision,
including reliance on CSAPR for ozone
season NOX to satisfy the Auxiliary
Boiler’s NOX BART requirements.109
Our approval of this determination for
the Auxiliary Boiler was made in error.
Therefore, we are proposing to
withdraw our prior approval of the
state’s reliance on CSAPR for ozone
season NOX to satisfy the NOX BART
requirement for the Auxiliary Boiler that
was included in the Arkansas Regional
Haze NOX SIP revision submitted to us
on October 31, 2017. We are proposing
to replace our approval of that BART
finding for the Auxiliary Boiler with
approval of the source specific 32.2 lb/
hr NOX BART emission limit contained
in the August 8, 2018, Arkansas
Regional Haze SIP revision.
C. Reasonable Progress Analysis for SO2
In determining whether additional
controls are necessary under the
reasonable progress requirements and
108 The Administrative Order can be found in the
Arkansas Regional Haze SO2 and PM BART SIP
Revision.
109 83 FR 5927.
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thus in establishing RPGs, a state must
consider the four statutory factors in
section 169A(g)(1) of the CAA: (1) The
costs of compliance, (2) the time
necessary for compliance, (3) the energy
and nonair quality environmental
impacts of compliance, and (4) the
remaining useful life of any existing
source subject to such requirements.
The Regional Haze Rule also states that
in establishing the RPGs, the state must
consider the uniform rate of
improvement in visibility for the period
covered by the implementation plan.110
The uniform rate of visibility
improvement, or uniform rate of
progress (URP), needed to reach natural
conditions by 2064 for each Class I area
can be determined by comparing
baseline conditions with natural
conditions. The Regional Haze Rule
provides for the use of an analytical
framework that compares the rate of
progress that will be achieved by a SIP
(as represented by the reasonable
progress goals for the end of the
implementation period) to the rate of
progress that if continued would result
in natural conditions in 2064 (i.e., the
URP). When a Class I area’s visibility
conditions for the most impaired days
are better (i.e., less impaired) than the
URP, the visibility conditions at the
Class I areas are said to be ‘‘below the
URP line’’ or ‘‘below the glidepath.’’
Consistent with section 169A(b) of the
CAA, 40 CFR 51.308(d)(3) requires that
states include in their SIP a long-term
strategy for making reasonable progress
for each Class I area within their state.
This long-term strategy is the
compilation of all control measures a
state will use during the
implementation period of the specific
SIP submittal to achieve reasonable
progress, and thus to meet any
applicable RPGs for a particular Class I
area. The long-term strategy includes
control measures determined necessary
pursuant to both the BART and
reasonable progress analyses.
In the Arkansas Regional Haze SO2
and PM SIP revision,111 ADEQ noted
that EPA’s ‘‘Guidance for Setting
Reasonable Progress Goals under the
Regional Haze Program’’ 112 (EPA’s RPG
110 40
CFR 51.308(d)(1)(i)(B).
a SIP revision submitted on October 31,
2017, Arkansas provided a reasonable progress
analysis and reasonable progress determination
with respect to NOX, and we took final action to
approve the analysis and determination in a final
action published on February 12, 2018 (see 83 FR
5927). Thus, the Arkansas Regional Haze SO2 and
PM SIP revision addresses the reasonable progress
requirements with respect to SO2 and PM
emissions.
112 Guidance for Setting Reasonable Progress
Goals under the Regional Haze Program, June 1,
2007, memorandum from William L. Wehrum,
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Guidance), provides that states have
flexibility in how to take into
consideration the four statutory factors.
The SIP revision states that, considering
this guidance, ADEQ believes that the
four reasonable progress factors can be
appropriately applied broadly to a group
of sources state-wide rather than in a
source-specific manner. However,
ADEQ stated that since EPA evaluated
the four factors for controls at the
Independence facility in the Arkansas
Regional Haze FIP as part of a sourcespecific analysis, it determined that
application of the four factors to that
particular source is also ‘‘relevant’’ in its
reasonable progress analysis as a way of
addressing EPA’s previous analysis as
reflected in the FIP. Therefore, in
addition to considering a broader
analysis using the four factors, ADEQ
also conducted a more specific analysis
for the Independence facility. The
former analysis in the SIP is ‘‘broad’’ in
the sense that it does not quantify costs
or visibility benefits for any particular
source or source category and discusses
visibility benefits and costs in only
qualitative terms. In the explanation of
its approach, the SIP states that both
analyses were completed and the results
taken into consideration before the state
determined whether any controls are
necessary under reasonable progress.
Before presenting its broad analysis,
the SIP identified the key pollutants and
source categories that contribute to
visibility impairment in Arkansas Class
I areas. After presenting its broad
analysis, the SIP presents an evaluation
of which sources should be the focus of
a narrow four-factor analysis and
selected Independence as the only such
source. The identification of the key
pollutants and source categories that
contribute to visibility impairment in
Arkansas Class I areas, the broad
reasonable progress analysis performed
by ADEQ, the identification of
Independence as the only source for
which a narrow analysis would be
performed, and ADEQ’s determination
regarding additional measures for
Independence that are necessary for
reasonable progress are discussed in the
subsections that follow. We provide our
assessment of each component of the
reasonable progress section of the SIP
revision before summarizing and
assessing the next component.
Acting Assistant Administrator for Air and
Radiation, to EPA Regional Administrators, EPA
Regions 1–10 (p. 5–1).
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1. Arkansas’ Discussion of Key
Pollutants and Source Category
Contributions
As part of its reasonable progress
analysis, ADEQ provided a discussion
of the results of air quality modeling
performed by the Central Regional Air
Planning Association (CENRAP) in
support of SIP development in the
central states region for 2002 and
projected 2018 emissions.113 The
CENRAP modeling included Particulate
Source Apportionment Technology Tool
(PSAT) with Comprehensive Air Quality
model with extensions (CAMx) version
4.4, which was used to provide source
apportionment by geographic regions
and major source categories for
pollutants that contribute to visibility
impairment at each of the Class I areas
in the central states region.114 The SIP
revision provided a discussion of PSAT
data for sources region-wide (i.e.,
sources both in and outside Arkansas,
including sources in the continental
U.S. and international sources) as well
as a discussion of PSAT data for
Arkansas sources. Below, we provide a
summary of each set of PSAT data.
a. Region-Wide PSAT Data for Caney
Creek and Upper Buffalo
Based on the region-wide PSAT data,
which looked at sources both in and
outside Arkansas, it was found that
point sources are the primary
contributor to light extinction at
Arkansas’ Class I areas on the 20%
worst days in 2002. Region-wide point
sources were found to contribute 81.04
inverse Megameters (Mm¥1) at Caney
Creek and 77.8 Mm¥1 at Upper Buffalo
on the 20% worst days in 2002, which
makes up approximately 60% of the
total light extinction at each Class I area.
The region-wide PSAT data showed that
area stationary anthropogenic sources
are the next largest source category
contributor to light extinction at
Arkansas Class I areas, contributing
17.81 Mm¥1 at Caney Creek and 20.46
Mm¥1 at Upper Buffalo, which makes
up approximately 13% and 16% of the
total light extinction at each Class I area,
respectively. The remaining source
categories (i.e., natural, on-road, and
non-road sources) were found to each
contribute between 2 and 6% of the
113 The central states region includes Texas,
Oklahoma, Louisiana, Arkansas, Kansas, Missouri,
Nebraska, Iowa, Minnesota, and the tribal
governments within these states.
114 See the TSD for CENRAP Emissions and Air
Quality Modeling to Support Regional Haze State
Implementation, which is found in Appendix 8.1 of
the 2008 Arkansas Regional Haze SIP. The 2008
Arkansas Regional Haze SIP can be found in the
docket associated with this proposed rulemaking.
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total light extinction at Arkansas Class
I areas.
Based on the region-wide PSAT data,
Arkansas also found that sulfate (SO4)
contributed 87.05 Mm¥1 at Caney Creek
and 83.18 Mm¥1 at Upper Buffalo on
the 20% worst days in 2002, which is
approximately 65% and 63% of the total
modeled light extinction at each Class I
area, respectively. Most of the light
extinction due to SO4 was attributed to
point sources. Out of the light extinction
due to SO4, the point source category
was responsible for approximately 86 to
87% of that light extinction. Point
sources of SO4 contributed 75.1 Mm¥1
at Caney Creek and 72.17 Mm¥1 at
Upper Buffalo, or approximately 55 to
56% of the total light extinction at
Arkansas Class I areas on the 20% worst
days in 2002. In contrast, the other
pollutant species were responsible for a
much smaller proportion of the total
light extinction at Arkansas’ Class I
areas. For example, nitrate (NO3)
contributed approximately 10%,
primary organic aerosols (POA)
contributed approximately 8%,
elemental carbon (EC) contributed
approximately 4%, crustal material
(CM) contributed approximately 3 to
5%, and soil contributed approximately
1% of the total modeled light extinction
at each Arkansas Class I area on the
20% worst days in 2002.
The region-wide PSAT data also
showed that point sources are projected
to remain the primary contributor to
light extinction at Arkansas Class I
areas, contributing 45.27 Mm¥1 at
Caney Creek and 43.02 Mm¥1 at Upper
Buffalo on the 20% worst days in 2018.
This constitutes approximately 53% of
the total light extinction at Caney Creek
and 50% of the total light extinction at
Upper Buffalo. Area sources are
projected to continue to be the second
largest contributor to light extinction,
being responsible for 20% of the total
light extinction at Caney Creek and 23%
of the total light extinction at Upper
Buffalo. The remaining source
categories (i.e., natural, on-road, and
non-road sources) are projected to
continue to contribute 5% of the total
light extinction at Arkansas Class I areas
on the 20% worst days in 2018. Based
on the region-wide PSAT data, light
extinction due to SO4 is projected to
decrease by 44% at Caney Creek and
45% at Upper Buffalo between 2002 and
2018.115 However, SO4 is projected to
115 The CENRAP’s 2018 modeling projections
made the following regional haze control
assumptions for Arkansas’ point sources: (1)
Installation of scrubber controls at Flint Creek
Boiler No. 1 to meet the presumptive SO2 BART
limit of 0.15 lb/MMBtu; (2) installation of low NOX
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continue to be the primary driver of
total light extinction at Arkansas Class
I areas, with point sources continuing to
be the primary source of light extinction
due to SO4. Point sources of SO4 are
projected to contribute 39.83 Mm¥1 at
Caney Creek and 37.09 Mm¥1 at Upper
Buffalo, which is between 43 and 46%
of the total light extinction on the 20%
worst days in 2018.
b. Arkansas PSAT Data for Caney Creek
and Upper Buffalo
When looking at the PSAT data for
sources within Arkansas only, the state
found that the relative contribution of
sources within Arkansas to total light
extinction on the 20% worst days at
Arkansas Class I areas is small. Species
attributed to Arkansas sources
contributed approximately 10% of the
total light extinction on the 20% worst
days in 2002 and were projected to
contribute between 13 and 14% of the
total light extinction on the 20% worst
days in 2018. Additionally, the state
found that when only the visibility
impact of sources within Arkansas were
considered, area sources actually had a
larger impact on light extinction than
point sources. Based on the Arkansas
source PSAT data, area sources within
Arkansas contributed 5.03 Mm¥1 at
Caney Creek on the 20% worst days in
2002, which is approximately 37% of
the light extinction attributed to
Arkansas sources at Caney Creek and
accounts for 4% of the total light
extinction at the Class I area. Based on
the Arkansas source PSAT data, area
sources within Arkansas contributed
6.72 Mm¥1 at Upper Buffalo on the 20%
worst days in 2002, which is
approximately 50% of the light
extinction attributed to Arkansas
sources at Upper Buffalo and accounts
for 5% of the total light extinction at the
Class I area. In contrast, Arkansas point
sources contributed 3.85 Mm-1 at Caney
Creek on the 20% worst days in 2002,
which is approximately 28% of the light
extinction attributed to Arkansas
sources at Caney Creek and accounts for
3% of the total light extinction at the
Class I area. Arkansas point sources also
contributed 3.25 Mm¥1 at Upper
Creek Boiler No. 1 and White Bluff Units 1 and 2;
and (3) the shutdown of AECC Bailey Unit 1 and
Entergy Lake Catherine Unit 4 by 2018. The SIP
revision we are proposing to take action on requires
a more stringent SO2 emission limit for Flint Creek
Boiler No. 1; requires an interim SO2 emission limit
of 0.60 lb/MMBtu and cessation of coal combustion
by the end of 2028 at White Bluff Units 1 and 2;
requires an SO2 emission limit of 0.60 lb/MMBtu
for Independence Units 1 and 2; does not require
the installation of low NOX burners for any of
Arkansas’ EGUs; and does not require shutdown of
AECC Bailey Unit 1 or Entergy Lake Catherine Unit
4.
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Buffalo on the 20% worst days in 2002,
which is approximately 24% of the light
extinction attributed to Arkansas
sources and accounts for 2% of the total
light extinction at the Class I area. The
other sources in Arkansas contributed
between 7 and 14% each to light
extinction attributed to Arkansas
sources, accounting for approximately
1% each to the total light extinction at
each Arkansas Class I area on the 20%
worst days in 2002.
Based on the Arkansas source PSAT
data, it was also found that SO4 from
Arkansas sources (all source categories)
contributed 4.14 Mm¥1 at Caney Creek
and 3.97 Mm-1 at Upper Buffalo, which
is approximately 3% of the total
visibility extinction at each of the Class
I areas on the 20% worst days in 2002.
Out of the light extinction attributed to
SO4 from Arkansas sources, the point
source category contributed
approximately 67% of that light
extinction at Caney Creek and Upper
Buffalo. At Caney Creek, the largest
contributing pollutant species next to
SO4 was POA, which contributed
approximately 3.54 Mm¥1. At Upper
Buffalo, the largest contributing
pollutant species next to SO4 was CM,
which contributed approximately 3.53
Mm¥1. NO3 from Arkansas sources was
found to contribute 2.11 Mm¥1 at Caney
Creek and 1.07 Mm¥1 at Upper Buffalo,
which is approximately 2% and 1% of
the of the total light extinction at Caney
Creek and Upper Buffalo, respectively.
On-road sources accounted for
approximately 50% of the light
extinction attributed to Arkansas
sources of NO3 at Arkansas Class I areas.
The Arkansas source PSAT data also
showed that when only sources located
in Arkansas are considered, area sources
are projected to remain the primary
contributor to light extinction at
Arkansas Class I areas on the 20% worst
days in 2018. Arkansas area sources are
projected to contribute 4.85 Mm¥1 at
Caney Creek and 6.52 Mm¥1 at Upper
Buffalo on the 20% worst days in 2018,
which is approximately 43% of light
extinction attributed to Arkansas
sources at Caney Creek and 54% of the
light extinction attributed to Arkansas
sources at Upper Buffalo. In contrast,
Arkansas point sources are projected to
contribute 4.05 Mm¥1 at Caney Creek
and 3.63 Mm¥1 at Upper Buffalo on the
20% worst days in 2018. Arkansas also
notes that overall, light extinction
attributed to Arkansas sources of SO4 is
projected to decrease at Arkansas Class
I areas on the 20% worst days in 2018,
but light extinction attributed to point
sources of SO4 located in Arkansas is
projected to increase by 4% at Caney
Creek and 5% at Upper Buffalo.
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Nevertheless, Arkansas noted that the
contribution to total light extinction of
SO4 from Arkansas point sources is
projected to be approximately 3% of the
total light extinction at each Arkansas
Class I area on the 20% worst days in
2018, which is a value the state
considers to be relatively small.
c. Arkansas’ Conclusions Regarding Key
Pollutants and Source Category
Contributions
Based on an assessment of both the
region-wide PSAT data and the
Arkansas source PSAT data, Arkansas
identified SO4 as the key pollutant
species contributing to light extinction
at Caney Creek and Upper Buffalo.
When looking at the region-wide PSAT
data, SO4 is the pollutant species
responsible for the vast majority of the
visibility impairment at Arkansas Class
I areas on the 20% worst days. When
looking at the Arkansas source PSAT
data, SO4 is still the pollutant species
with the largest contribution to visibility
impairment at Arkansas Class I areas on
the 20% worst days, but its relative
contribution to light extinction is not as
heavily weighted as it is in the regionwide PSAT data. The primary driver of
SO4 formation at Arkansas Class I areas
is emissions of SO2 from point sources,
both when looking at visibility impacts
from sources region-wide and also when
looking at visibility impacts only from
sources in Arkansas.
Arkansas also noted that only a small
proportion of total light extinction is
due to NO3 from Arkansas sources, and
that this proportion has been driven by
on-road sources. For example, NO3 from
Arkansas point sources contributed less
than 0.5% of the total light extinction
on the 20% worst days at Caney Creek
and Upper Buffalo. Based on this
observation, Arkansas decided not to
evaluate sources of NO3 under the four
reasonable progress factors in the
October 2017 Arkansas Regional Haze
NOX SIP Revision. When focusing only
on sources in Arkansas, a comparison of
the various source categories reveals
that area sources do contribute a larger
proportion of total light extinction than
the other source categories. The majority
of the light extinction from Arkansas
area sources is due to CM and POA, but
Arkansas noted that these pollutant
species originate from many individual
small sources and that the costeffectiveness of these controls is
therefore difficult to quantify and
Arkansas therefore decided not to
evaluate area sources under the four
reasonable progress factors.
Since Arkansas determined that SO4
is the key pollutant species contributing
to light extinction at Caney Creek and
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Upper Buffalo on the 20% worst days
and that the majority of light extinction
due to SO4 is attributed to point sources,
it evaluated point sources emitting at
least 250 tons per year (tpy) of SO2 to
determine whether their emissions and
proximity to Arkansas Class I areas
warrant further analysis under the four
reasonable progress factors.
We agree with Arkansas that the
PSAT results for Arkansas sources show
that the relative contribution to light
extinction of SO4 on the 20% worst days
at Arkansas Class I areas is not as great
compared to the regional contribution
results. However, SO4 is still the species
with the largest contribution to light
extinction at Caney Creek and Upper
Buffalo on the 20% worst days in both
the regional data and the Arkansas
source PSAT data. We agree with
Arkansas’ identification of SO4 as the
key species contributing to light
extinction at Caney Creek and Upper
Buffalo on the 20% worst days. Newer
IMPROVE monitoring data that has
become available after the CENRAP
modeling was performed does not
appear to contradict this conclusion.116
We are also proposing to agree that the
primary driver of SO4 formation at
Arkansas Class I areas is SO2 emissions
from point sources, both when looking
at visibility impacts from sources
region-wide and also when looking at
visibility impacts only from sources in
Arkansas. Arkansas’ conclusions are
consistent with our finding in the
Arkansas Regional Haze FIP that the
CENRAP’s CAMx modeling shows that
SO4 from point sources is the driver of
regional haze at Caney Creek and Upper
Buffalo on the 20% worst days in both
2002 and 2018.117 We also agree with
Arkansas’ assertion that when only
sources located in Arkansas are
considered, light extinction due to area
sources (all pollutant species
considered) is greater compared to the
light extinction due to point sources at
both Caney Creek and Upper Buffalo on
the 20% worst days in 2002. And we
agree with Arkansas that the cost of
controlling many individual small area
sources may be difficult to quantify, and
we are therefore proposing to find that
it is acceptable for Arkansas to choose
not to further evaluate area sources for
controls under reasonable progress in
this implementation period. This is
consistent with EPA’s decision not to
conduct a four-factor analysis of area
sources under reasonable progress for
116 IMPROVE monitoring data for Caney Creek
and Upper Buffalo, as well as other Class I areas can
be found at https://views.cira.colostate.edu/fed/
QueryWizard/Default.aspx.
117 80 FR 18996.
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this implementation period in the
Arkansas Regional Haze FIP.118
Therefore, we are proposing to find that
it is appropriate for Arkansas to focus its
evaluation on point sources emitting at
least 250 SO2 tpy to determine whether
their emissions and proximity to
Arkansas Class I areas warrant further
analysis under the four reasonable
progress factors.
2. Arkansas’ Analysis of Reasonable
Progress Factors Broadly Applicable to
Arkansas Sources
In addition to the four reasonable
progress factors under CAA section
169A(g)(1), ADEQ determined that
visibility is also a relevant factor for
consideration in its reasonable progress
analysis. ADEQ’s broad evaluation of
the four reasonable progress factors plus
visibility is summarized below.
Visibility: ADEQ explained that, since
restoring natural visibility conditions in
Class I areas is the central goal of the
regional haze program, it considers
visibility to be the necessary context
within which to view whether
additional controls are reasonable in the
first planning period. ADEQ noted that
visibility has improved dramatically in
Arkansas’ Class I areas since 2004, with
visibility improving at a rate more rapid
than needed to meet the 2018 point on
the URP and Arkansas’ Class I areas
being on track to achieve natural
visibility conditions in Arkansas Class I
areas by 2064. ADEQ also noted that the
observed improvement in visibility
conditions has taken place even before
implementation of most of the controls
included in the Arkansas Regional Haze
SO2 and PM SIP revision. ADEQ stated
that the observed visibility
improvement at Arkansas Class I areas
is the result of reductions from state and
federal programs, including New Source
Performance Standards for a variety of
source types; vehicle emissions
standards; changes in NAAQS;
innovations in emissions control
technologies; retirement or
reconstruction of older facilities; and
market-driven changes in electricity
generation. ADEQ stated it anticipates
118 In the FIP we explained that the CENRAP
CAMx modeling with PSAT showed that point
sources are responsible for a majority of the light
extinction at Arkansas Class I areas on the 20%
worst days in 2002 (this is taking into account all
pollutant species and sources both in and outside
Arkansas). We reasoned that since other source
types (i.e., natural, on-road, non-road, and area)
each contributed a much smaller proportion of the
total light extinction at each Class I area, it was
appropriate to focus only on point sources in our
reasonable progress analysis for this
implementation period. See 80 FR 18944 and 81 FR
66332 at 66336. See also the ‘‘Arkansas Regional
Haze FIP Response to Comments (RTC) Document,’’
pages 71–99.
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that the implementation of the BART
controls required under the SIP revision
will further keep Arkansas Class I areas
on track to achieve natural visibility
conditions on or before 2064.
ADEQ also stated that the visibility
trajectory in Arkansas’ Class I areas is a
relevant factor for consideration in its
reasonable progress analysis. According
to ADEQ, if Arkansas Class I areas were
making less progress than necessary to
achieve the URP during the first
planning period, then more costly
controls could be warranted if found
reasonable after consideration of the
four statutory factors and other factors
the state considers relevant. ADEQ
stated that ADEQ therefore deems it
reasonable to consider that Arkansas
Class I areas are already below the 2018
point on the URP, in addition to
considering the statutory reasonable
progress factors, in evaluating whether
additional controls are necessary under
reasonable progress for the first
implementation period.
Costs of Compliance: ADEQ pointed
out that EPA’s RPG Guidance provides
that the cost of compliance factor ‘‘can
be interpreted to encompass . . . the
implication of compliance costs to the
health and vitality of industries within
a state.’’ 119 Considering the visibility
trends at Arkansas’ Class I areas, ADEQ
determined that this interpretation is
appropriate to apply in this case. ADEQ
believes that the cost of additional
controls under reasonable progress
would create a negative impact on the
health and vitality of industries within
the state, and that such adverse impacts
would be especially great if additional
SO2 controls were imposed on the
electricity sector. This is because under
Arkansas law, energy companies are
permitted to recover costs related to the
installation of emissions controls at
EGUs required under a SIP from
electricity ratepayers subject to approval
by the Arkansas Public Service
Commission. These costs, in turn,
would be allowed to be passed on to
Arkansas ratepayers, including a variety
of industries, in the form of increased
electric rates. ADEQ believes that
energy-intensive industries would be
disproportionately impacted by these
costs.
Time Necessary for Compliance:
ADEQ noted that the time necessary for
compliance varies depending on the
control technology under consideration.
ADEQ stated that the time necessary for
compliance for SO2 control technologies
considered for BART in the SIP revision
was typically 3–5 years, unless progress
had already been made toward
implementing those control
technologies.
Energy and Non-air Quality Impacts
of Compliance: ADEQ stated that the
installation of additional controls, such
as dry and wet scrubbers, under
reasonable progress for Arkansas EGUs
may have negative impacts, including
temporary outages necessary to install
the controls. Arkansas expects that this
would temporarily disrupt the supply of
electricity to the grid. Additionally,
ADEQ noted that certain control
technologies can result in reduced
generating capacity for EGUs, which is
referred to as parasitic load.
Furthermore, ADEQ noted that market
trends for coal and natural gas have
already resulted in the decreased
dispatch of coal-fired facilities, which
has in turn resulted in a decrease in
overall emissions of key pollutants that
impact visibility at Arkansas Class I
areas. ADEQ cited to data from the
Energy Information Administration
62227
showing that the trend of decreased net
electricity generation from coal and
increased net electricity generation from
natural gas and renewable energy is
expected to continue for the remainder
of the 2008–2018 implementation
period, and well beyond.
Remaining Useful Life of Potentially
Affected Sources: ADEQ pointed out
that the EPA RPG Guidance provides
that this factor is generally best treated
as one element of the overall cost
analysis. ADEQ noted that if the
remaining useful life for a given facility
is less than the typical amortization
period for new control equipment, the
annualized cost increases and the
controls become less cost effective.
Additionally, ADEQ pointed out that
the cost of controls may result in a
company making an economic decision
to discontinue operations, thus
truncating the remaining useful life of a
source.
3. Identification of Potential Sources for
Evaluation of SO2 Controls Under
Reasonable Progress
In identifying which sources to
evaluate for SO2 controls in its
reasonable progress analysis, Arkansas
compiled a list of all point sources that
emitted at least 250 SO2 tpy as reported
to the EPA emissions Inventory System
(EIS) in any given year between 2002
and 2015. For sources that participate in
EPA’s Acid Rain Program, Arkansas
obtained SO2 emissions data for 2015
using the Air Markets Program Data
tool. Arkansas then narrowed down the
list to only those sources that emitted at
least 250 tpy averaged over the most
recent 3-year period for which data is
available. Arkansas identified 11
sources that met this criterion (see Table
11).
TABLE 11—POINT SOURCES IN ARKANSAS WITH SO2 EMISSIONS GREATER THAN 250 TPY
Most recent
3-year period
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Facility
Entergy White Bluff * ................................................................................................................................................
Entergy Independence .............................................................................................................................................
SWEPCO Flint Creek Power Plant * .......................................................................................................................
Plum Point Energy Station Unit 1 ............................................................................................................................
FutureFuel Chemical Company ...............................................................................................................................
Domtar A.W. LLC, Ashdown Mill * ...........................................................................................................................
Evergreen Packaging—Pine Bluff ...........................................................................................................................
Albemarle Corporation—South Plant ......................................................................................................................
SWEPCO John W. Turk Jr. Power Plant ................................................................................................................
Ash Grove Cement Company/Foreman Cement Plant ...........................................................................................
Nucor—Yamato Steel Company .............................................................................................................................
2014–2016
2014–2016
2014–2016
2014–2016
2013–2015
2013–2015
2013–2015
2013–2015
2014–2016
2013–2015
2013–2015
Average SO2
emissions
(tpy)
24,346
22,531
5,350
2,759
2,837
1,553
986
1,382
908
369
301
*These facilities are subject to BART requirements, and the state therefore did not further consider these sources for additional controls under
reasonable progress.
119 Guidance for Setting Reasonable Progress
Goals under the Regional Haze Program, June 1,
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Acting Assistant Administrator for Air and
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Radiation, to EPA Regional Administrators, EPA
Regions 1–10 (p. 5–1).
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Arkansas explained that, since White
Bluff, Flint Creek, and Domtar are
subject to BART and the BART analyses
conducted to determine BART control
requirements are based on an
assessment of many of the same factors
that must be evaluated in determining
whether additional controls are needed
under the reasonable progress
provisions and thus in establishing the
RPGs, no additional controls under
reasonable progress are necessary for
these sources in the first
implementation period. For the
remaining sources on the list, Arkansas
calculated the total average actual
emission rate (Q) in SO2 tpy over the
most recent 3-year period and
determined the distance (D) in
kilometers of each source to its closest
Class I area (see Table 12). Arkansas
used a ‘‘Q divided by D’’ (Q/D) value of
10 as a threshold for identifying sources
to further evaluate for reasonable
progress controls. Arkansas explained
that it selected this value as a threshold
based on guidance contained in the
BART Guidelines and also noted that
this is consistent with the approach
used in other regional haze actions.
TABLE 12—Q/D VALUES FOR LARGE SO2 POINT SOURCES IN ARKANSAS
Q/D value
Facility
Upper buffalo
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Entergy Independence .............................................................................................................................................
Plum Point Energy Station Unit 1 ............................................................................................................................
FutureFuel Chemical Company ...............................................................................................................................
Evergreen Packaging—Pine Bluff ...........................................................................................................................
Albemarle Corporation—South Plant ......................................................................................................................
SWEPCO John W. Turk Jr. Power Plant ................................................................................................................
Ash Grove Cement Company/Foreman Cement Plant ...........................................................................................
Nucor—Yamato Steel Company .............................................................................................................................
As shown in Table 12, Arkansas
found that only three sources had a
maximum Q/D value greater than or
equal to 10: Entergy Independence,
FutureFuel Chemical Company, and
John W. Turk Jr. Power Plant. Arkansas
noted that Entergy Independence is the
second largest point source of SO2
emissions in Arkansas, with average
2014–2016 emissions of 22,531 SO2 tpy.
In comparison, the FutureFuel Chemical
Company and the John W. Turk Jr.
Power Plant had much lower SO2
emissions. FutureFuel Chemical
Company had average 2013–2015 SO2
emissions of 2,837 tpy, while the John
W. Turk Jr. Power Plant had average
2014–2016 SO2 emissions of 908 tpy.
Arkansas noted that SO2 emissions from
the FutureFuel Chemical Company and
the John W. Turk Jr. Power Plant are
approximately an order of magnitude
lower than emissions from Entergy
Independence. In addition, Arkansas
noted that the FutureFuel Chemical
Company was previously identified as a
BART eligible source, but was
determined to be not subject to BART in
the 2008 Arkansas Regional Haze SIP
based on CALPUFF modeling performed
in the development of that SIP.
Therefore, ADEQ did not find it
necessary to further evaluate controls
under reasonable progress for this
facility for this implementation period.
The John W. Turk Jr. Power Plant,
which began operation in 2012, has
implemented best available control
technology, which Arkansas noted is
more stringent than BART. Therefore,
ADEQ stated that it does not anticipate
that more stringent controls would be
available and/or reasonable for this
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facility in the first implementation
period. Arkansas ultimately determined
that since the Independence facility is a
source not subject to BART and because
it was required by the Arkansas
Regional Haze FIP to install controls
under reasonable progress, this
particular source warrants further
consideration and evaluation under the
four reasonable progress factors.
We are proposing to find that
Arkansas’ overall method of identifying
sources for potential further evaluation
under the four reasonable progress
factors is appropriate. We find that
Arkansas’ approach of narrowing down
the list of sources to further evaluate
under reasonable progress to only those
sources that emitted at least 250 SO2 tpy
averaged over the most recent 3-year
period for which data is available is
reasonable. We agree with Arkansas that
since White Bluff and Flint Creek are
subject to BART and are addressed
under this SIP revision, the BART
analyses conducted to determine BART
control requirements for these sources
and the determinations adopted and
incorporated by the state in this SIP
revision are adequate to eliminate these
sources from further consideration of
additional controls under the reasonable
progress requirements for the first
implementation period. The EPA RPG
Guidance explains that the BART
analysis is based, in part, on an
assessment of many of the same factors
that must be addressed in establishing
the RPGs, and therefore it is reasonable
to conclude that any control
requirements imposed in the BART
determination also satisfy the RPGrelated requirements for source review
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Caney creek
126
9
17
4
5
4
1
1
81
7
10
5
9
11
5
1
in the first implementation period.120
The guidance provides that it is
reasonable to conclude that any control
requirements imposed in the BART
determination also satisfy the RPGrelated requirements for source review
in the first RPG planning period.121 The
same rationale applies for the Domtar
Ashdown Mill, although the August 8,
2018 SIP revision does not address the
BART requirements for Domtar, which
will remain satisfied by the FIP and the
2008 Arkansas Regional Haze SIP. Based
on the consideration of the BART
factors and resulting determinations in
that FIP and the 2008 Arkansas Regional
Haze SIP, it is reasonable for ADEQ to
conclude that nothing further is needed
to address emissions from Domtar under
the requirement for reasonable progress
analysis at this time. If ADEQ chooses
to submit a SIP revision to address
BART requirements for Domtar Power
Boilers No. 1 and No. 2, we will
evaluate that SIP submittal, including
whether it also sufficiently addresses
the reasonable progress requirements for
Domtar for the first implementation
period.
We are proposing to find that
Arkansas’ use of a Q/D value of 10 as
a threshold for identifying sources to
further evaluate for reasonable progress
controls is reasonable and appropriate.
We agree with Arkansas, that the
FutureFuel Chemical Company was
120 Guidance for Setting Reasonable Progress
Goals Under the Regional Haze Program, June 1,
2007, memorandum from William L. Wehrum,
Acting Assistant Administrator for Air and
Radiation, to EPA Regional Administrators, EPA
Regions 1–10 (pp. 4–2, 4–3, and 5–1).
121 Id.
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found by the state to be not subject to
BART in the 2008 Arkansas Regional
Haze SIP, which is a determination that
was approved by EPA in our March
2012 final action on the SIP.122 The
FutureFuel Chemical Company and the
John W. Turk Jr. Power Plant are the
fifth and ninth largest SO2 point sources
in Arkansas, based on average annual
emissions from the most recent 3-year
period.123 In comparison to the SO2
emissions from the 3 largest SO2 point
sources in Arkansas, emissions from
these two facilities are relatively
small.124 Taking into consideration the
significantly lower 3-year average SO2
emissions from the FutureFuel
Chemical Company and the John W.
Turk Jr. Power Plant in comparison to
the Independence Power Plant and
considering that the John W. Turk Jr.
Power Plant operates best available
control technology, we are proposing to
find that it is reasonable and
appropriate for Arkansas to not further
evaluate these sources for controls
under reasonable progress for this
planning period. We also consider it
appropriate and reasonable for Arkansas
to decide to conduct an analysis of the
reasonable progress factors for the
Independence facility. In particular, we
consider it appropriate to evaluate the
Independence facility because it is the
second highest point source of SO2
emissions in Arkansas, accounting for
approximately 36% of the SO2 point
source emissions in Arkansas; its Q/D
values as determined by ADEQ are high
(see Table 12), especially when
122 The 2008 Arkansas Regional Haze SIP showed
that FutureFuel Chemical Company had a
maximum visibility impact (i.e., 1st high value) of
0.711 dv at Hercules Glades. EPA found that closer
inspection of the visibility modeling results
revealed that only this single day out of the 3 years
modeled exceeded the 0.5 dv threshold used by
ADEQ to determine if a source is subject to BART.
Since only one day modeled above the threshold,
EPA found in its final action on the 2008 Arkansas
Regional Haze SIP that it is unlikely that a refined
modeling approach using updated meteorological
data, which would allow the use of the 98th
percentile visibility impact instead of the max
visibility impact, would show impacts above the 0.5
dv threshold. Therefore, EPA concluded in our
March 2012 final action on the 2008 Arkansas
Regional Haze SIP that it was not necessary to
further evaluate controls under reasonable progress
for the FutureFuel Chemical Company in the first
implementation period.
123 See the Arkansas Regional Haze SO and PM
2
SIP Revision, Table 11.
124 The three largest SO point sources in
2
Arkansas, based on average annual emissions from
the most recent 3-year period, are the Entergy White
Bluff Plant, Entergy Independence Plant, and
SWEPCO Flint Creek Plant (see Table 11 of the
Arkansas Regional Haze SO2 and PM SIP Revision).
The Entergy White Bluff Plant and the SWEPCO
Flint Creek Plant are subject to BART and controls
for these facilities are already addressed in the SIP
revision based on ADEQ’s consideration of the 5
BART factors.
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compared to other Arkansas point
sources; and it is a source not subject to
BART. Therefore, we are proposing to
agree with Arkansas’ decision to
evaluate the four reasonable progress
factors for the Independence facility.
4. Arkansas’ Reasonable Progress
Analysis for Independence Units 1 and
2
As noted above, ADEQ determined
that application of the four factors to
that specific source is also ‘‘relevant’’ in
its reasonable progress analysis as a way
of addressing EPA’s previous analysis.
a. Arkansas’ Evaluation of the
Reasonable Progress Factors for SO2 for
Entergy Independence Units 1 and 2
Section 169(A)(g)(1) of the CAA
requires states to evaluate the costs of
compliance, the time necessary for
compliance, the energy and non-air
quality environmental impacts of
compliance, and the remaining useful
life of any potentially affected sources,
when determining reasonable progress.
In its evaluation of the four reasonable
progress factors for the Independence
facility, Arkansas relied on information
provided by Entergy for the
Independence facility in the evaluation
of low sulfur coal and dry scrubbers.
Arkansas also relied on data developed
by EPA in support of the Arkansas
Regional Haze FIP in the evaluation of
wet scrubbers and dry scrubbers. The
Entergy Independence Power Plant is a
coal-fired electric generating station
with two identical 900 MW boilers. The
boilers burn Wyoming Powder River
Basin sub-bituminous coal as their
primary fuel and No. 2 fuel oil or biodiesel as start-up fuel. The layout and
boiler units at this facility are similar to
those at Entergy White Bluff, but since
the units at Independence were
installed in 1983 (9 years after the
installation of the White Bluff units),
Independence Units 1 and 2 are not
BART eligible.
There is currently no SO2 control
equipment in use at Units 1 and 2.
Arkansas noted that the Independence
units are subject to a prevention of
significant deterioration (PSD) emission
limit of 0.93 lb/MMBtu. Arkansas also
noted that market trends for coal and
natural gas have resulted in decreased
dispatch of the Independence units,
which has resulted in reduced
emissions from the facility. The
available SO2 control technology
options considered in Arkansas’
analysis are as follows: Switching to
coal with a lower sulfur content, dry
FGD, and wet FGD, all of which
Arkansas identified as being technically
feasible. Switching to coal with a sulfur
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62229
content of 0.6 lb/MMBtu (referred to
herein as low sulfur coal) is expected to
result in a 4 to 6% reduction in SO2
emissions from 2009–2013 levels. Dry
FGD systems typically have SO2 control
efficiencies ranging from 60 to 95%
control, while wet FGD is typically
capable of achieving 80 to 95% control
of SO2 emissions.
Degree of Improvement in Visibility:
Although the degree of visibility
improvement is not one of the four
statutory factors that must be evaluated
in a reasonable progress analysis, as
noted above, Arkansas chose to consider
visibility improvement since the
ultimate goal of any controls under
reasonable progress is to achieve
visibility improvements. For switching
to low sulfur coal, Entergy submitted
CALPUFF modeling that estimated the
visibility benefit of switching to low
sulfur coal for Independence Units 1
and 2. This modeling showed that
switching to low sulfur coal is
anticipated to result in visibility
improvements of 0.112 dv at Caney
Creek and 0.236 dv at Upper Buffalo.
For dry scrubbers, Arkansas relied on
the visibility improvement estimates
from the modeling conducted by EPA
for the Arkansas Regional Haze FIP.
Arkansas noted that the installation of
dry FGD at Independence Units 1 and
2 is anticipated to result in visibility
improvements of 1.096 dv at Caney
Creek and 1.178 dv at Upper Buffalo.125
As discussed above, Arkansas also
estimated that the cost in terms of
dollars per deciview of dry FGD at
Independence Units 1 and 2 ranges from
$63,580,175/dv to $71,672,197/dv at
each of the four affected Class I areas
(see Table 13).
Remaining Useful Life: Since there are
no state- or federally-enforceable
limitations on continued operations at
the Independence facility, Arkansas’
cost analysis for SO2 controls assumed
a 30-year amortization period for dry
125 We note that in the SIP revision, ADEQ relied
on EPA’s visibility modeling from the FIP for dry
scrubbers at the Independence facility. In that
visibility modeling, EPA modeled two baseline
scenarios: (1) The BASE case emission rates for
NOX and SO2 were from the maximum actual 24hour emissions during the 2001–2003 period; and
(2) the BASE 2 case emission rates for SO2 were
based on the maximum actual 24-hour emissions
during the 2001–2003 period and the NOX
emissions were based on the maximum 24-hour
emissions during the 2011–2013 period. Entergy’s
CALPUFF modeling for low sulfur coal at the
Independence facility was based on a 2011–2013
baseline period for modeled emission rates. While
Entergy’s baseline for low sulfur coal differed from
the two baselines modeled by EPA for dry
scrubbers, ADEQ stated they do not expect that the
difference would substantially impact the
comparison of the visibility benefits among controls
evaluated.
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FGD and wet FGD.126 However,
Arkansas acknowledged Entergy’s
intention, as stated in comments to
Arkansas regarding the draft SIP, to
cease coal combustion at Independence
Units 1 and 2 by the end of 2030. In
addition, Arkansas noted that market
pressures may also impact continued
operations at the Independence facility,
including changes in dispatch and
economic decisions concerning the
continued viability of the units.
Therefore, Arkansas recognized that the
amortization period of controls may end
up being less than the 30 years assumed
in Arkansas’ cost analysis, potentially
resulting in the controls being less cost
effective than estimated in the analysis.
Costs of Compliance: In considering
the costs of compliance, Arkansas noted
that switching to low sulfur coal has no
associated capital costs, but there would
be a cost associated with guaranteeing
that the sulfur content remains below
0.6 lb/MBtu. Arkansas stated it
calculated cost estimates for switching
to low sulfur coal using information
provided by Entergy regarding cost
premiums for low sulfur coal, U.S.
Energy Information Administration fuel
consumption data, and EPA Air Markets
Program Data. Arkansas estimated that
the annualized operation and
maintenance costs of switching to low
sulfur coal is $1.6 million for Unit 1 and
$1.7 million for Unit 2.127 Arkansas
estimated that the cost effectiveness of
switching to low sulfur coal is
approximately $2,437/ton for Unit 1 and
$2,345/ton for Unit 2.
In contrast to switching to low sulfur
coal, the installation of dry FGD and wet
FGD is expected to require a large
capital investment. Entergy provided
Arkansas with Independence-specific
cost estimates for dry scrubbers for use
in Arkansas’ cost analysis. Entergy
estimated total capital costs of dry
scrubbers at Independence to be
$491,893,500 per unit based on ‘‘actual
costs’’ and $355,391,500 per unit based
on costs allowed under EPA’s Control
Cost Manual. Entergy annualized the
capital cost for both sets of numbers
assuming a 9-year amortization period,
based on Entergy’s plans to cease coal
combustion at Independence by the end
of 2030. Additionally, Entergy based its
calculations of SO2 emissions
reductions based on a 2009–2013
baseline. In the SIP revision, ADEQ
based its evaluation of the cost of dry
scrubbers on the set of capital costs that
reflect the costs allowed under EPA’s
Control Cost Manual, and also assumed
a 30-year amortization period in its
calculation of the cost-effectiveness of
dry scrubbers. Based on these
assumptions, Arkansas estimated that
the cost-effectiveness of dry scrubbers is
$2,970/ton for Unit 1 and $2,742/ton for
Unit 2.
Since Entergy did not provide
Independence-specific cost estimates for
wet scrubbers for Arkansas to base its
cost analysis on, Arkansas relied on the
cost estimates for Independence
developed by EPA in the Arkansas
Regional Haze FIP.128 Based on a 30year amortization period, our FIP
estimated wet FGD to cost $3,706/ton at
Unit 1 and $3,416/ton at Unit 2.
Arkansas noted that in the Arkansas
Regional Haze FIP, EPA eliminated wet
scrubbers due to the high incremental
cost-effectiveness but small incremental
visibility benefit of wet scrubbers
compared to dry scrubbers. Therefore,
consistent with EPA’s action in the FIP,
ADEQ found that wet FGD did not
warrant further consideration in its
analysis.
In addition to considering costeffectiveness calculations in the cost
analysis, Arkansas found that other costrelated factors were of relevance in its
evaluation of the reasonable progress
factors for the Independence facility.
This includes total capital costs, cost to
Arkansas communities, and the cost in
terms of dollar per dv improvement in
visibility anticipated from the control
options evaluated ($/dv). Arkansas
considered the capital costs of dry
scrubbers and wet scrubbers to be high,
even though the costs in terms of $/ton
of SO2 emissions reduced for both dry
and wet scrubbers (assuming a 30-year
remaining useful life) are within a range
that has been found to be cost effective
in other regional haze actions. In
addition, acknowledging Entergy’s
anticipated cessation of coal combustion
at the Independence facility, although it
is not state- or federally-enforceable,
Arkansas noted that assuming a 9-year
remaining useful life would likely result
in scrubber controls no longer being
cost-effective. In light of this, Arkansas
considered it important to take into
account the capital cost of controls
along with the cost-effectiveness in
terms of dollars per ton of emissions
reduced. Arkansas also noted that these
costs would be passed on to Arkansas
ratepayers. Finally, Arkansas also took
into account that the $/dv improvement
in visibility for dry scrubbers is a little
over 2 times higher than for low sulfur
coal at Caney Creek and between 5 and
6 times higher at Upper Buffalo and the
2 Missouri Class I areas (see Table 13).
Arkansas noted that consideration of the
cost in terms of $/dv improvement
demonstrates a greater disparity in costs
among the control options compared to
consideration of the cost in terms of $/
ton reduced. Arkansas concluded that
all the control options considered
would result in millions of dollars spent
to achieve what it considers to be little
visibility benefit.
TABLE 13—COST OF SO2 CONTROLS ($/dv) FOR INDEPENDENCE UNITS 1 AND 2
Class I Area
SO2 control option
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Low Sulfur Coal ...............................................................................................
Dry FGD ...........................................................................................................
$29,469,780
68,337,085
Upper Buffalo
$10,929,190
63,580,175
Hercules
Glades
$13,985,658
70,925,611
Mingo
$12,179,393
71,672,197
Time Necessary for Compliance:
Arkansas explained that the typical time
necessary for compliance for dry FGD
and wet FGD is 5 years. Considering the
time left on existing coal supply
contracts between Entergy and its coal
126 As explained above, Entergy annualized the
capital cost of controls on the Independence facility
assuming a 9-year amortization period, based on
Entergy’s plans for ceasing coal combustion at
Independence by the end of 2030. However, given
that Entergy’s plans to cease coal combustion by the
end of 2030 are not state or federally-enforceable,
ADEQ re-calculated the cost-effectiveness of
controls by annualizing the capital cost of controls
assuming a 30-year amortization period.
127 ADEQ calculated annualized operation and
maintenance costs of switching to low sulfur coal
by multiplying average annual fuel consumption in
tons for the years 2009–2013 by the $0.50/ton cost
premium Entergy was quoted by its coal supplier,
per Entergy’s August 18, 2017, SO2 BART analysis
for White Bluff. ADEQ obtained annual fuel
consumption data for the years 2009–2013 from
U.S. Energy Information Administration Form EIA–
923.
128 See 80 FR 18992–18993. See also the Arkansas
Regional Haze SO2 and PM SIP Revision, Appendix
F.
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supplier, the time required to burn
through current fuel stocks, and the
time needed to build a stockpile of low
sulfur coal to assure against potential
fuel supply disruptions, Entergy
informed Arkansas that the time
necessary to comply with an SO2
emission limit based on low sulfur coal
is estimated to be 3 years.
Energy and Non-air Quality
Environmental Impacts of Compliance:
Arkansas noted that dry FGD utilizes
lime slurry to remove SO2 from flue gas
and that in the process, particulate
matter is generated that must be
controlled through the use of a baghouse
or ESP. Once collected, the waste
material is disposed of through
landfilling. Arkansas noted that the
costs associated with control of
particulate matter and additional power
requirements were factored into the cost
estimates used in its analysis. Arkansas
determined that Entergy has not
indicated unusual circumstances that
would create greater problems than
experienced in other cases where dry
FGD has been utilized to meet regional
haze requirements. Arkansas also noted
that switching to low sulfur coal is not
anticipated to result in any adverse
energy or non-air environmental
impacts.
b. Arkansas’ Determination Regarding
Reasonable Progress Requirements for
Independence
Based on its evaluation of the
reasonable progress factors for the
Independence facility, ADEQ arrived at
the conclusion that no additional
controls are necessary for reasonable
progress during the first implementation
period. According to ADEQ, the controls
it evaluated would cost millions of
dollars annually, which would be
passed on to Arkansas ratepayers, for
what ADEQ considers to be little
visibility benefit when Arkansas’ Class
I areas are already making more progress
than the URP.
Although ADEQ concluded that none
of the controls evaluated for the
Independence facility are necessary for
achieving reasonable progress in the
first planning period, ADEQ
acknowledged Entergy’s intention to
switch to low sulfur coal at
Independence Units 1 and 2 within the
next 3 years. ADEQ noted that this
measure would strengthen the SIP and
result in some visibility benefit at
Arkansas’ Class I areas, while having no
associated capital costs. According to
ADEQ, the lack of any capital costs will
provide Entergy with flexibility
regarding the company’s planned
cessation of coal combustion at the
Independence facility by the end of
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2030. Therefore, Entergy’s commitment
to switch to low sulfur coal at
Independence Units 1 and 2 has now
been made enforceable by ADEQ as part
of the long-term strategy for this
implementation period, through an
Administrative Order that has been
adopted and incorporated in the SIP
revision. The Administrative Order
requires Independence Units 1 and 2 to
meet an SO2 emission limit of 0.60 lb/
MMBtu no later than 3 years from the
effective date of the Administrative
Order, which is August 7, 2018.129
5. Arkansas’ Determination Regarding
Additional Controls Necessary Under
Reasonable Progress and Revised RPGs
After consideration of the statutory
reasonable progress factors, along with
an evaluation of the monitored
trajectory of visibility impairment
during the first implementation period,
particulate source apportionment data,
and SO2 emissions relative to proximity
to Arkansas Class I areas, Arkansas
determined that no additional controls
beyond BART and other Clean Air Act
programs are necessary under the
reasonable progress provisions for the
first implementation period. Based on
its analysis of the reasonable progress
factors in the context of both the
analysis of a group of sources as well as
the source-specific analysis that applied
the reasonable progress factors
specifically to the Independence
facility, Arkansas determined that all
the evaluated controls would result in
the expenditure of millions of dollars
annually for what the state considers to
be little visibility benefit. In addition,
the costs of any control requirements
would be passed on to Arkansas citizens
and businesses through electricity rate
increases. Arkansas deems that these
costs are not warranted under
reasonable progress given that Arkansas
Class I areas are well below their
respective 2018 URPs. Arkansas
believes that its reasonable progress
determination is consistent with EPA’s
decision to establish a 64-year lifespan
for the regional haze program, which is
broken down into several 10-year
implementation periods. Arkansas
stated that the way the regional haze
program was set up allows for a fresh
look at the changing landscape of
sources that impact visibility and
potential controls every 10 years.
Arkansas noted that the EPA Reasonable
Progress Guidance provides that it is
reasonable for states to defer reductions
to later planning periods in order to
129 The Administrative Order can be found in the
Arkansas Regional Haze SO2 and PM BART SIP
Revision.
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maintain a consistent glidepath toward
the long-term goal of natural visibility
conditions. Therefore, Arkansas
determined that no SO2 or PM controls
beyond BART are necessary for
reasonable progress during the first
implementation period.
To reflect the control measures
required in the Arkansas Regional Haze
SO2 and PM SIP revision and the
Arkansas Regional Haze NOX SIP
revision, which was approved by EPA
in a prior action,130 Arkansas revised
the RPGs for the 20% worst days for
Caney Creek and Upper Buffalo that it
had previously established in the 2008
Arkansas Regional Haze SIP. Arkansas
did not revise its RPGs for the 20% best
days included in the 2008 Arkansas
Regional Haze SIP. In order to provide
RPGs for the 20% worst days that
account for emissions reductions from
its SIP revisions, Arkansas utilized a
method that is based on a scaling of
modeled light extinction components in
proportion to emissions changes
anticipated from SIP controls for which
compliance is required on or before
December 31, 2018. Arkansas noted that
this is the same method utilized by EPA
to revise the RPGs in the Arkansas
Regional Haze FIP. Arkansas scaled
CENRAP’s CAMx 2018 projection of
light extinction components for SO4 and
NO3 in proportion to the SIP revisions’
emission reductions for SO2 and NOX
from the CENRAP modeled 2018
emissions. Arkansas decided to use the
most recent 3 years of data (2014–2016)
as opposed to EPA’s method in the
Arkansas FIP, which involved using the
5 most recent years of data (2009–2013)
with the exclusion of the minimum and
maximum values. Arkansas explained
that this was done to ensure that recent
changes in dispatch at Arkansas EGUs
were captured. Arkansas’ revised RPGs
for Caney Creek and Upper Buffalo are
presented in Table 14.
TABLE 14—ARKANSAS’ REVISED 2018
RPGS FOR CANEY CREEK AND
UPPER BUFFALO
Class I area
Caney Creek .........................
Upper Buffalo ........................
2018 RPG
20% worst
days
(dv)
22.47
22.51
6. EPA’s Evaluation and Conclusions on
Arkansas’ Reasonable Progress Analysis
and Revised RPGs
As noted above, as part of its
reasonable progress analysis, Arkansas
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conducted both a broad source analysis
and a source-specific analysis that
evaluated the four statutory factors for
the Independence facility. The former
analysis was ‘‘broad’’ in the sense that
it did not quantify costs or visibility
benefits for any particular source or
source category, and discussed
anticipated visibility benefits and costs
in only general terms. We agree that an
approach that involves a broad analysis
of groups of sources or source categories
may be appropriate in certain cases, as
provided by EPA’s RPG Guidance.
However, we believe that the broad
analysis of a group of sources provided
by ADEQ does not clearly identify what
sources or controls were evaluated in
the state’s weighing of the costs and
other statutory factors. While
informative, we find that the state’s
broad analysis of a group of sources was
not a determinative component of the
state’s reasonable progress analysis
given that the state’s determination was
also informed by an evaluation of large
point sources individually to identify
sources for potential further evaluation
under the four reasonable progress
factors and by a more narrow and
focused analysis conducted for those
sources identified, specifically the
Independence facility, which included
consideration of various control options
and weighing of costs and the other
statutory factors.
We are proposing to find that the
reasonable progress requirements under
section 51.308(d)(1) have been fully
addressed for the first regional haze
planning period. Specifically, we are
proposing to find that the following
components of Arkansas’ analysis
satisfy the reasonable progress
requirements: Arkansas’ discussion of
the key pollutants and source categories
that contribute to visibility impairment
in Arkansas Class I areas based on the
CENRAP’s source apportionment
modeling; the identification of a group
of large SO2 point sources for potential
consideration of controls under
reasonable progress and the eventual
narrowing down of the list to the
Independence facility; 131 and the
evaluation of the four reasonable
progress factors for SO2 controls on the
Independence facility.
We are proposing to agree with
Arkansas’ cost analysis for dry scrubbers
and switching to low sulfur coal for
131 As explained elsewhere in this notice, ADEQ
relied on the fact that a FIP is in place to satisfy
the BART requirements for the Domtar Ashdown
Mill to find that nothing further is needed to
address the reasonable progress requirements with
regard to this source for the first implementation
period. EPA is proposing to agree that it is
appropriate to rely on the FIP in this manner.
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Independence Units 1 and 2, and with
the state’s decision to assume a 30-year
capital cost recovery period in the cost
analysis. It is appropriate to assume a
30-year capital cost recovery period in
the cost analysis since Entergy’s plans to
cease coal combustion at the
Independence facility are not state or
federally-enforceable. We also agree
with Arkansas’ estimates of the cost of
dry scrubbers, and note that the state’s
estimates of the cost effectiveness of dry
scrubbers for Units 1 and 2 are very
similar to the cost effectiveness
estimates we developed in the Arkansas
Regional Haze FIP.132
Since the White Bluff and
Independence facilities are sister
facilities with nearly identical units and
comparable levels of annual SO2
emissions, and since both DSI and
enhanced DSI were evaluated in the
BART analysis for White Bluff Units 1
and 2, we believe it would be
appropriate to consider these controls in
the four-factor analysis for the
Independence facility as well. However,
neither the SIP revision nor Entergy’s
four factor analysis for controls on the
Independence facility considered DSI or
enhanced DSI as control options.
Therefore, relying on Entergy’s
estimates of the capital costs and annual
operation and maintenance costs for DSI
and enhanced DSI for White Bluff Units
1 and 2 from Entergy’s August 18, 2017,
White Bluff BART analysis,133 and
assuming a 30-year equipment life, we
estimate the cost-effectiveness of DSI at
the Independence facility to be
approximately $4,963/SO2 ton removed
for Unit 1 and $4,593/SO2 ton removed
for Unit 2.134 We estimate the costeffectiveness of enhanced DSI to be
approximately $4,951/SO2 ton removed
for Unit 1 and $4,581/SO2 ton removed
for Unit 2.135 Based on our cost
estimates for DSI, we find that DSI is
less cost-effective than dry scrubbers or
wet scrubbers for Independence Units 1
and 2.136 Although the anticipated
132 Compare Arkansas’ estimates of the cost
effectiveness of dry scrubbers for the Independence
facility ($2,970/ton for Unit 1 and $2,742/ton for
Unit 2) with EPA’s estimates of the cost
effectiveness of dry scrubbers for the facility
($2,853/ton for Unit 1 and $2,634/ton for Unit 2).
See 81 FR 66352.
133 We are relying on Entergy’s ‘‘adjusted costs,’’
which reflect Entergy’s exclusion of line items not
allowed under EPA’s Control Cost Manual. See
‘‘Entergy Updated BART Five-Factor Analysis for
Units 1 and 2,’’ dated August 18, 2017, Table 4–4.
This analysis is found under Appendix D of the
Arkansas Regional Haze SO2 and PM SIP revision.
134 See the file titled ‘‘EPA Cost Calcs_DSI and
enhanced DSI_Independence.xlsx,’’ which can be
found in the docket for this proposed rulemaking.
135 Id.
136 This is based on a comparison of our cost
estimates for DSI with Entergy’s cost estimates for
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visibility benefits of DSI at the
Independence facility were not
modeled, we expect that these would be
less than that for dry scrubbers or wet
scrubbers, since DSI and enhanced DSI
typically have a lower SO2 removal
efficiency than scrubber controls.
Further, we expect that the installation
and operation of DSI or enhanced DSI
would likely present the same potential
issues discussed by Entergy in its SO2
BART analysis for White Bluff.
Specifically, Entergy stated that before
DSI technology could be selected as
BART for White Bluff, a demonstration
test would need to be performed to
confirm its feasibility, achievable
performance, and balance of plant
impacts (brown plume formation, ash
handling modifications, landfill/
leachate considerations, and impact to
mercury control). In addition, Entergy
claimed that DSI has not yet been
demonstrated on units comparable to
those at White Bluff. Because of the
similarities between the White Bluff and
Independence facilities, we expect that
these same potential issues related to
the installation and operation of DSI or
enhanced DSI would also apply to the
Independence facility. In light of all
this, we expect that even if ADEQ had
considered DSI and enhanced DSI in its
reasonable progress analysis for the
Independence facility, it likely would
not have changed the state’s final
determination on reasonable progress.
Therefore, under these particular
circumstances, we do not consider the
omission of consideration of DSI and
enhanced DSI as control options for SO2
at the Independence facility an
impediment to approving the reasonable
progress analysis.
In its reasonable progress analysis for
the Independence facility, the statutory
factor that appears to have been the
most significant in Arkansas’ reasonable
progress determination is the cost of
compliance, as well as visibility, which
the state deemed to be a relevant factor
for consideration in its analysis.
Arkansas discussed its concerns
regarding the significant capital cost of
scrubber controls, noted that the
evaluation of the $/dv metric
demonstrated a greater difference in cost
between dry FGD and low sulfur coal
compared to the $/ton metric, and
ultimately concluded that all the
controls it evaluated would cost
millions of dollars for what it considers
to be little visibility benefit. We believe
dry scrubbers and the FIP’s cost estimates for wet
scrubbers for Independence Units 1 and 2. Entergy’s
cost estimates for dry scrubbers and the FIP’s cost
estimates for wet scrubbers for Independence Units
1 and 2 are discussed earlier in this notice under
Section II.C.4.a.
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that Arkansas’ weighing of the four
statutory factors and other factors it
deemed relevant in its reasonable
progress analysis for the Independence
facility was reasonable. Considering the
state’s concerns about the high capital
costs and high $/dv of the evaluated
controls and given that the state is
requiring Independence Units 1 and 2 to
switch to low sulfur coal within 3 years
under the long-term strategy, which is
expected to reduce SO2 emissions and
result in visibility improvements at
Arkansas’ Class I areas, it is not
unreasonable for Arkansas to conclude
that SO2 controls under the reasonable
progress requirements are not necessary
for the Independence facility in the first
implementation period. We are
proposing to fully approve Arkansas’
focused reasonable progress analysis,
which applied the four statutory factors
directly to the Independence facility,
and its determination that no additional
controls under the reasonable progress
requirements are necessary to achieve
reasonable progress for the first
implementation period. Our proposed
approval is based on the following: (1)
The state’s discussion of the key
pollutants and source categories that
contribute to visibility impairment in
Arkansas’ Class I areas per the
CENRAP’s source apportionment
modeling; (2) the state’s identification of
a group of large SO2 point sources in
Arkansas for potential evaluation of
controls under reasonable progress; (3)
the state’s rationale for narrowing down
its list of potential sources to evaluate
under the reasonable progress
requirements; 137 and (4) the state’s
evaluation and reasonable weighing of
the four statutory factors along with
consideration of the visibility benefits of
controls for the Independence facility.
We are also proposing to find that the
method used by Arkansas to estimate
revised 2018 RPGs for the 20% worst
days for Caney Creek and Upper Buffalo
is appropriate. We agree with Arkansas
that this is the same method utilized by
us to revise the RPGs in the Arkansas
Regional Haze FIP. We are also
proposing to find that Arkansas’ use of
the most recent 3 years of data (2014–
137 As explained above, part of ADEQ’s basis for
determining the sources for which to conduct a
narrow reasonable progress analysis was that
certain sources were subject to BART analyses and
determinations in the first implementation period.
For the Domtar facility in particular, the state relied
on the fact that a FIP is in place to address the
BART requirements. We propose to agree that this
is an appropriate basis on which find that nothing
further is needed for reasonable progress at this
source. If, in the future, Arkansas submits a further
SIP revision addressing the Domtar Ashdown Mill,
EPA will evaluate whether the analysis and
determinations therein satisfy the reasonable
progress requirements as well as BART.
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2016) as opposed to use of the 5 most
recent years of data (2009–2013) with
the exclusion of the minimum and
maximum values, as we used in the
Arkansas FIP, is appropriate because it
reflects updated data and we also agree
with Arkansas that it will ensure that
recent changes in dispatch at Arkansas
EGUs are captured. Therefore, we are
proposing to agree with Arkansas’
revised 2018 RPGs of 22.47 dv for Caney
Creek and 22.51 dv for Upper Buffalo.
As discussed elsewhere in this
proposed rulemaking, BART controls for
Domtar Power Boilers No. 1 and 2 are
not addressed in the Arkansas Regional
Haze SO2 and PM SIP Revision, and we
are not proposing to withdraw the FIP’s
BART emission limits for the facility at
this time. If and when ADEQ submits a
SIP revision to address BART
requirements for Domtar Power Boilers
No. 1 and No. 2, we will evaluate any
conclusions ADEQ has drawn in that
submission with respect to the need to
conduct a reasonable progress analysis
for Domtar. As long as the BART
requirements for Domtar continue to be
addressed by the measures in the FIP,
however, we propose to agree with
ADEQ’s conclusion that nothing further
is needed to satisfy the reasonable
progress requirements for the first
implementation period. With respect to
the RPGs for Arkansas’ Class I areas, if
and when ADEQ submits a SIP revision
addressing Domtar, we will assess that
future SIP revision to determine if
changes are needed based on any
differences between the SIP-based
measures and the measures currently
contained in the FIP.
D. Long-Term Strategy
Section 169A(b) of the CAA and 40
CFR 51.308(d)(3) require that states
include in their SIPs a 10 to 15-year
strategy, referred to as the long-term
strategy, for making reasonable progress
for each Class I area within their state.
This long-term strategy 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 for a particular Class I area. The
long-term strategy must include
‘‘enforceable emissions limitations,
compliance schedules, and other
measures as necessary to achieve the
reasonable progress goals’’ for all Class
I areas within, or affected by emissions
from, the state.138
Section 51.308(d)(3)(v) requires that a
state consider certain elements in
developing its long-term strategy for
each Class I area. These considerations
138 40
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are the following: (1) Emission
reductions due to ongoing air pollution
control programs, including measures to
address reasonably attributable visibility
impairment (RAVI); (2) measures to
mitigate the impacts of construction
activities; (3) emissions limitations and
schedules for compliance to achieve the
reasonable progress goal; (4) source
retirement and replacement schedules;
(5) smoke management techniques for
agricultural and forestry management
purposes including plans as currently
exist within the state for these purposes;
(6) enforceability of emissions
limitations and control measures; and
(7) the anticipated net effect on
visibility due to projected changes in
point, area, and mobile source
emissions over the period addressed by
the long-term strategy. Since states are
required to consider emissions
limitations and schedules of compliance
to achieve the RPGs for each Class I
area, the BART emission limits that are
in a state’s regional haze SIP are
elements of the state’s long-term strategy
for each Class I area. In our March 12,
2012, final action on the 2008 Arkansas
Regional Haze SIP, since we
disapproved a portion of Arkansas’
BART determinations for Arkansas’ two
Class I areas, we also disapproved the
corresponding emissions limitations
and schedules of compliance elements
of the state’s long-term strategy, while
approving remaining elements under
section 51.308(d)(3)(v).
As discussed above, the state is
making enforceable Entergy’s
commitment to switch Independence
Units 1 and 2 to low sulfur coal and
comply with an SO2 emission limit of
0.60 lb/MMBtu within 3 years as part of
the long-term strategy. We are proposing
to approve Arkansas’ decision to make
enforceable the 0.60 lb/MMBtu SO2
emission limit for Independence Units 1
and 2 as part of the long-term strategy
and we are also proposing to approve
the other components of the long-term
strategy addressed by the August 8,
2018 SIP revision. We are proposing to
find that Arkansas’ long-term strategy is
approved with respect to sources other
than the Domtar Ashdown Mill. Because
we disapproved the majority of ADEQ’s
2008 BART determinations for the
Domtar facility and promulgated a FIP
to satisfy these requirements, the
corresponding components of the longterm strategy for Domtar are also
currently satisfied by the FIP. No further
action by ADEQ is required at this time;
the Domtar-related components will
remain covered by the FIP and the
approved portion of the 2008 Arkansas
Regional Haze SIP unless and until EPA
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has received and approved a SIP
revision containing the required
analyses and determinations for this
facility.
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E. Required Consultation
The Regional Haze Rule requires
states to provide the designated Federal
Land Managers (FLMs) with an
opportunity for consultation at least 60
days prior to holding any public hearing
on a SIP revision for regional haze for
the first implementation period.
Arkansas sent letters to the FLMs on
October 27, 2017, providing notification
of the proposed SIP revision and
providing electronic access to the draft
SIP revision and related documents.139
ADEQ also engaged in telephone
communications with the FLMs and
considered and addressed comments
submitted by the FLMs on the proposed
SIP revision.140
The Regional Haze Rule at section
51.308(d)(3)(i) also provides that if a
state has emissions that are reasonably
anticipated to contribute to visibility
impairment in a Class I area located in
another state, the state must consult
with the other state(s) in order to
develop coordinated emission
management strategies. Since Missouri
has two Class I areas impacted by
Arkansas sources, Arkansas sent a letter
to the Missouri Department of Natural
Resources (MDNR) on October 27, 2017,
providing notification of the proposed
SIP revision and providing electronic
access to the draft SIP revision and
related documents.141 Missouri did not
provide comments to Arkansas on the
proposed SIP revision.
We are proposing to find that
Arkansas provided an opportunity for
consultation to the FLMs and to
Missouri on the proposed SIP revision,
as required under section 51.308(i)(2)
and 51.308(d)(3)(i). We are also
proposing to find that Arkansas has
appropriately considered and provided
written responses to comments from the
FLMs in the final SIP submission.
Therefore, we are proposing to find that
Arkansas has satisfied the consultation
requirements under sections 51.308(i)(2)
and 51.308(d)(3)(i).
F. Interstate Visibility Transport Under
Section 110(a)(2)(D)(i)(II)
The SIP revision also includes a
discussion on interstate visibility
139 See Arkansas Regional Haze SO and PM SIP
2
revision, Tab E.
140 ADEQ included copies of correspondence
with the FLM’s, included comments received from
the FLMs in Tab E of the Arkansas Regional Haze
SO2 and PM SIP revision.
141 See Arkansas Regional Haze SO and PM SIP
2
revision, Tab E.
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transport. Specifically, the SIP revision
discusses the impacts of Arkansas
sources on Missouri’s Class I areas, as
well as the most recent IMPROVE
monitoring data for Missouri’s Class I
areas. The SIP revision concludes that
Missouri is on track to achieve its
visibility goals, that the visibility
progress observed indicates that sources
in Arkansas are not interfering with the
achievement of Missouri’s RPGs for
Hercules Glades and Mingo, and that no
additional controls on sources within
Arkansas are necessary to ensure that
other states’ visibility goals for their
Class I areas are met. We are deferring
proposing action on the interstate
visibility transport portion of the SIP
revision until a future proposed
rulemaking.
G. Clean Air Act Section 110(l)
Section 110(l) of the CAA states that
‘‘[t]he Administrator shall not approve a
revision of a plan if the revision would
interfere with any applicable
requirement concerning attainment and
reasonable further progress or any other
applicable requirement of this chapter.’’
We believe an approval of the Arkansas
Regional Haze SO2 and PM SIP revision
and concurrent withdrawal of the
corresponding parts of the FIP, as
proposed, will meet the Clean Air Act’s
110(1) provisions concerning attainment
and maintenance. No areas in Arkansas
are currently designated nonattainment
for any NAAQS pollutants. As all areas
in Arkansas are attaining the NAAQS
with current emissions levels, further
reductions from current emission levels
because of compliance with the
emission limits contained in this SIP
revision will not interfere with
attainment or maintenance. The SIP will
result in emission reductions beyond
the status quo.
Additionally, we do not believe an
approval of the Arkansas Regional Haze
SO2 and PM SIP revision and
concurrent withdrawal of the
corresponding parts of the FIP would
interfere with the CAA requirements for
BART or reasonable progress because
our proposed approval of the SIP
revision is supported by our evaluation
of the state’s conclusions and our
rationale explaining why we are
proposing to find that the BART and
reasonable progress requirements under
the CAA are met, as discussed under
sections II.B and II.C of this notice. With
respect to BART requirements, the SIP
would replace federal determinations
regarding SO2 and PM control
requirements for EGUs in Arkansas with
the state’s own determinations. We do
note that the majority of the state’s SO2
and PM BART determinations in the SIP
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revision are essentially identical to the
BART determinations contained in the
Arkansas Regional Haze FIP. The only
exception to this is White Bluff Units 1
and 2, for which the FIP requires an SO2
emission limit of 0.06 lb/MMBtu with a
5-year compliance date, based on the
installation of dry scrubbers. The
Arkansas Regional Haze SO2 and PM
SIP revision does not require the SO2
emission limit of 0.06 lb/MMBtu, but it
does require that Entergy move forward
with its announced plans to cease coal
combustion at White Bluff Units 1 and
2 by the end of 2028 and to meet an
interim SO2 emission limit of 0.60 lb/
MMBtu prior to ceasing coal
combustion. Once the units cease coal
combustion, SO2 emissions from White
Bluff Units 1 and 2 are expected to
significantly decrease. Therefore, we
expect that the BART controls contained
in the SIP revision are comparable to the
BART controls required under the FIP
in the long term. More importantly, our
proposed approval of the SIP revision
does not violate CAA section 110(l) with
respect to BART requirements because
the state’s BART decisions in the SIP
revision, which we are proposing to
approve, are adequately supported by
BART five factor analyses that have
been adopted and incorporated into the
SIP revision.
With respect to reasonable progress,
we are proposing to approve Arkansas’
determination that no additional
controls under the reasonable progress
requirements are necessary to achieve
reasonable progress for the first
implementation period. In contrast to
the Arkansas Regional Haze FIP, the
Arkansas Regional Haze SO2 and PM
SIP revision does not require an SO2
emission limit of 0.06 lb/MMBtu with a
5-year compliance date for
Independence Units 1 and 2 based on
the installation of dry scrubber controls
under the reasonable progress
requirements. Nevertheless, as
discussed in Section II.C of this notice,
we are proposing to find that the
reasonable progress requirements under
section 51.308(d)(1) have been fully
addressed for the first implementation
period, based on Arkansas’ discussion
of the key pollutants and source
categories that contribute to visibility
impairment in Arkansas’ Class I areas
per the CENRAP’s source
apportionment modeling; its
identification of a group of large SO2
point sources in Arkansas for potential
evaluation of controls under reasonable
progress; the state’s rationale for
narrowing down its list of potential
sources to evaluate under the reasonable
progress requirements; and its analysis
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with reasonable weighing of the four
statutory factors along with
consideration of the visibility benefits of
controls for the Independence facility.
Therefore, even though the SIP revision
would allow for an increase in SO2
emissions from the Independence
facility compared to the FIP, our
proposed approval of the SIP revision
and concurrent withdrawal of the
corresponding parts of the FIP does not
violate CAA section 110(l) with respect
to reasonable progress because we are
proposing to find that Arkansas has
provided a reasoned basis to support its
determination that the scrubber controls
are not needed for reasonable progress.
III. Proposed Action
A. Arkansas Regional Haze SIP Revision
The EPA is proposing to approve the
following revisions to the Arkansas
Regional Haze SIP submitted to EPA on
August 8, 2018: The SO2 and PM BART
requirements for the AECC Bailey Plant
Unit 1; the SO2 and PM BART
requirements for the AECC McClellan
Plant Unit 1; the SO2 BART
requirements for Flint Creek Plant
Boiler No. 1; the SO2 BART
requirements for the White Bluff Plant
Units 1 and 2; the SO2, NOX, and PM
BART requirements for the White Bluff
Auxiliary Boiler; and the prohibition on
burning of fuel oil at Lake Catherine
Unit 4 until SO2 and PM BART
determinations for the fuel oil firing
scenario are approved into the SIP by
EPA. These BART requirements have
now been made enforceable by the state
through Administrative Orders that
have been adopted and incorporated in
the SIP revision. We are proposing to
approve these Administrative Orders as
source-specific BART revisions to the
SIP. The BART requirements and
associated Administrative Orders are
listed under Table 15 below. We are
proposing to withdraw our February 12,
2018,142 approval of Arkansas’ reliance
on participation in the CSAPR ozone
season NOX trading program to satisfy
the NOX BART requirement for the
White Bluff Auxiliary Boiler given that
Arkansas erroneously identified the
Auxiliary Boiler as participating in
CSAPR for ozone season NOX. We are
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proposing to replace our prior approval
of Arkansas’ determination for the
White Bluff Auxiliary Boiler with our
proposed approval of the source specific
NOX BART emission limit contained in
the August 8, 2018, SIP revision. We are
proposing to approve ADEQ’s revised
identification of the 6A Boiler at the
Georgia-Pacific Crossett Mill as BARTeligible and the additional information
and technical analysis presented in the
SIP revision in support of the
determination that the Georgia-Pacific
Crossett Mill 6A and 9A Boilers are not
subject to BART.
We are also proposing to find that the
reasonable progress requirements under
section 51.308(d)(1) have been fully
addressed for the first implementation
period. Specifically, we are proposing to
approve the state’s focused reasonable
progress analysis and the reasonable
progress determination that no
additional SO2 controls at Independence
Units 1 and 2 or any other Arkansas
sources are necessary under reasonable
progress for the first implementation
period. We are also proposing to agree
with the state’s revised RPGs for
Arkansas’ Class I areas. We are basing
our proposed approval of the reasonable
progress provisions and revised RPGs
on the state’s discussion of the key
pollutants and source categories that
contribute to visibility impairment in
Arkansas’ Class I areas per the
CENRAP’s source apportionment
modeling; the state’s identification of a
group of large SO2 point sources in
Arkansas for potential evaluation of
controls under reasonable progress; the
state’s rationale for narrowing down its
list of potential sources to evaluate
under the reasonable progress
requirements; and the state’s evaluation
and reasonable weighing of the four
statutory factors along with
consideration of the visibility benefits of
controls for the Independence facility.
The August 8, 2018, SIP revision does
not address BART and associated longterm strategy requirements for the
Domtar Ashdown Mill Power Boilers
No. 1 and 2, and we are not proposing
to withdraw the FIP’s BART emission
limits for the facility at this time. If and
when ADEQ submits a SIP revision to
address BART requirements for Domtar
Power Boilers No. 1 and No. 2, we will
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62235
evaluate any conclusions ADEQ has
drawn in that submission with respect
to the need to conduct a reasonable
progress analysis for Domtar. As long as
the BART requirements for Domtar
continue to be addressed by the
measures in the FIP, however, we
propose to agree with ADEQ’s
conclusion that nothing further is
needed to satisfy the reasonable
progress requirements for the first
implementation period. With respect to
the RPGs for Arkansas’ Class I areas, if
and when ADEQ submits a SIP revision
addressing Domtar, we will assess that
future SIP revision to determine if
changes are needed based on any
differences between the SIP-based
measures and the measures currently
contained in the FIP.
We are proposing to approve the
components of the long-term strategy
under section 51.308(d)(3) addressed by
the August 8, 2018, SIP revision,
including the BART measures contained
in the SIP revision and the SO2 emission
limit of 0.60 lb/MMBtu for
Independence Units 1 and 2 based on
the use of low sulfur coal. These
requirements for Independence Units 1
and 2 have now been made enforceable
by the state through an Administrative
Order that has been adopted and
incorporated in the SIP revision. We are
proposing to approve this
Administrative Order as a sourcespecific revision to the SIP. The SO2
emission limit and associated
Administrative Order for the
Independence facility are listed under
Table 16 below. We are proposing to
find that Arkansas’ long-term strategy is
approved with respect to sources other
than the Domtar Ashdown Mill. We are
also proposing to find that Arkansas has
provided an opportunity for
consultation to the FLMs and to
Missouri on the proposed SIP revision,
as required under section 51.308(i)(2)
and 51.308(d)(3)(i). The BART emission
limits we are proposing to approve are
presented in Table 15; the SO2 emission
limits under the long-term strategy and
associated Administrative Order we are
proposing to approve for the
Independence facility are presented in
Table 16; and Arkansas’ revised 2018
RPGs are presented in Table 17.
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TABLE 15—SIP REVISION BART EMISSION LIMITS AND ADMINISTRATIVE ORDERS PROPOSED FOR APPROVAL
Subject-to-BART source
SIP revision SO2 BART
emission limits
SIP revision PM BART
emission limits
SIP revision NOX BART
emission limits
AECC Bailey Unit 1 ...........
0.5% limit on sulfur content of fuel combusted*.
0.5% limit on sulfur content of fuel combusted*.
0.06 lb/MMBtu* .................
0.5% limit on sulfur content of fuel combusted*.
0.5% limit on sulfur content of fuel combusted*.
Already SIP-approved .......
Already SIP-approved .......
Unit is allowed to burn
only natural gas*.
Unit is allowed to burn
only natural gas*.
Already SIP-approved .......
0.60 lb/MMBtu ...................
(Interim emission limit with
a 3-year compliance
date and cessation of
coal combustion by end
of 2028).
0.60 lb/MMBtu ...................
(Interim emission limit with
a 3-year compliance
date and cessation of
coal combustion by end
of 2028).
105.2 lb/hr* ........................
Already SIP-approved .......
Already SIP-approved .......
Administrative Order LIS
No. 18–073.
Already SIP-approved .......
Already SIP-approved .......
Administrative Order LIS
No. 18–073.
4.5 lb/hr* ............................
32.2 lb/hr* ..........................
Administrative Order LIS
No. 18–073.
AECC McClellan Unit 1 .....
AEP Flint Creek Boiler No.
1.
Entergy Lake Catherine
Unit 4 (fuel oil firing scenario).
Entergy White Bluff Unit 1
Entergy White Bluff Unit 2
Entergy White Bluff Auxiliary Boiler.
Already SIP-approved .......
Already SIP-approved .......
Administrative order
Administrative Order
No. 18–071.
Administrative Order
No. 18–071.
Administrative Order
No. 18–072.
Administrative Order
No. 18–073.
LIS
LIS
LIS
LIS
* This BART emission limit required by the SIP revision is the same as what was required under the Arkansas Regional Haze FIP.
TABLE 16—SIP REVISION EMISSION LIMITS UNDER REASONABLE PROGRESS AND ADMINISTRATIVE ORDERS PROPOSED
FOR APPROVAL
SIP revision SO2
emission limits
Source
Entergy Independence Unit 1 ..................................................
Entergy Independence Unit 2 ..................................................
0.60 lb/MMBtu
0.60 lb/MMBtu
Administrative order
Administrative Order LIS No. 18–073.
Administrative Order LIS No. 18–073.
withdraw certain portions of the FIP, we
are also proposing to redesignate the FIP
by revising the numbering of certain
paragraphs under section 40 CFR
2018 RPG
20% worst days 52.173. Our proposed redesignation of
(dv)
the numbering of these paragraphs is
22.47 non-substantive and does not mean we
22.51 are reopening these parts for public
comment in this proposed rulemaking.
TABLE 17—ARKANSAS’ REVISED 2018
RPGS
Class I area
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Caney Creek .....................
Upper Buffalo ....................
B. Partial FIP Withdrawal
We are proposing to withdraw those
portions of the Arkansas Regional Haze
FIP at 40 CFR 52.173 that impose SO2
and PM BART requirements on Bailey
Unit 1; SO2 and PM BART requirements
on McClellan Unit 1; SO2 BART
requirements on Flint Creek Boiler No.
1; the provisions concerning BART for
the fuel oil firing scenario for Lake
Catherine Unit 4; SO2 BART
requirements for White Bluff Units 1
and 2; SO2 and PM BART requirements
for the White Bluff Auxiliary Boiler; and
the SO2 emission limits under
reasonable progress for Independence
Units 1 and 2. We are proposing that
these portions of the FIP will be
replaced by the portion of the Arkansas
Regional Haze SO2 and PM SIP revision
that we are proposing to approve in this
action. Since we are proposing to
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C. Clean Air Act Section 110(l)
We are proposing to find that an
approval of a portion of the Arkansas
Regional Haze SO2 and PM SIP revision
and concurrent withdrawal of the
corresponding parts of the FIP, as
proposed, will meet the Clean Air Act’s
110(1) provisions.
IV. Incorporation by Reference
In this action, we are proposing to
include in a final rule regulatory text
that includes incorporation by
reference. In accordance with the
requirements of 1 CFR 51.5, we are
proposing to incorporate by reference
revisions to the Arkansas source specific
requirements as described in the
Proposed Action section above. We have
made, and will continue to make, these
documents generally available
electronically through
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www.regulations.gov and in hard copy
at the EPA Region 6 office (please
contact Dayana Medina, 214–665–7241,
medina.dayana@epa.gov for more
information).
V. Statutory and Executive Order
Reviews
Under the CAA, the Administrator is
required to approve a SIP submission
that complies with the provisions of the
Act and applicable Federal regulations.
42 U.S.C. 7410(k); 40 CFR 52.02(a).
Thus, in reviewing SIP submissions, the
EPA’s role is to approve state choices,
provided that they meet the criteria of
the CAA. Accordingly, this action
merely proposes to approve state law as
meeting Federal requirements and does
not impose additional requirements
beyond those imposed by state law. For
that reason, this action:
• Is not a ‘‘significant regulatory
action’’ subject to review by the Office
of Management and Budget under
Executive Orders 12866 (58 FR 51735,
October 4, 1993) and 13563 (76 FR 3821,
January 21, 2011);
• Is not an Executive Order 13771 (82
FR 9339, February 2, 2017) regulatory
action because SIP approvals are
exempted under Executive Order 12866;
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• Does not impose an information
collection burden under the provisions
of the Paperwork Reduction Act (44
U.S.C. 3501 et seq.);
• Is certified as not having a
significant economic impact on a
substantial number of small entities
under the Regulatory Flexibility Act (5
U.S.C. 601 et seq.);
• Does not contain any unfunded
mandate or significantly or uniquely
affect small governments, as described
in the Unfunded Mandates Reform Act
of 1995 (Pub. L. 104–4);
• Does not have Federalism
implications as specified in Executive
Order 13132 (64 FR 43255, August 10,
1999);
• Is not an economically significant
regulatory action based on health or
safety risks subject to Executive Order
13045 (62 FR 19885, April 23, 1997);
• Is not a significant regulatory action
subject to Executive Order 13211 (66 FR
28355, May 22, 2001);
• Is not subject to requirements of
section 12(d) of the National
Technology Transfer and Advancement
Act of 1995 (15 U.S.C. 272 note) because
this action does not involve technical
standards; and
• Does not provide EPA with the
discretionary authority to address, as
appropriate, disproportionate human
health or environmental effects, using
practicable and legally permissible
methods, under Executive Order 12898
(59 FR 7629, February 16, 1994).
In addition, the SIP is not approved
to apply on any Indian reservation land
or in any other area where EPA or an
Indian tribe has demonstrated that a
tribe has jurisdiction. In those areas of
Indian country, the proposed rule does
not have tribal implications and will not
impose substantial direct costs on tribal
governments or preempt tribal law as
specified by Executive Order 13175 (65
FR 67249, November 9, 2000).
List of Subjects in 40 CFR Part 52
Environmental protection, Air
pollution control, Best available retrofit
technology, Incorporation by reference,
Intergovernmental relations, Ozone,
Particulate matter, regional haze,
Reporting and recordkeeping
requirements, Sulfur dioxide, Visibility.
Dated: November 21, 2018.
David Gray,
Acting Regional Administrator, Region 6.
Title 40, chapter I, of the Code of
Federal Regulations is proposed to be
amended as follows:
Subpart E—Arkansas
2. In § 52.170:
a. In paragraph (d), the table titled
‘‘EPA-Approved Arkansas SourceSpecific Requirements’’ is amended by
revising the heading ‘‘Permit No.’’ to
‘‘Permit or Order No.’’ and adding the
entries ‘‘Arkansas Electric Cooperative
Corporation Carl E. Bailey Plant’’,
‘‘Arkansas Electric Cooperative
Corporation John L. McClellan’’,
‘‘Entergy Arkansas, Inc. Lake Catherine
Plant’’, ‘‘Entergy Arkansas, Inc. White
Bluff Plant’’, and ‘‘Entergy Arkansas,
Inc. Independence Plant’’.
■ b. In paragraph (e), the third table
titled ‘‘EPA-Approved Non-Regulatory
Provisions and Quasi-Regulatory
Measures in the Arkansas SIP’’ is
amended by adding the entry ‘‘Arkansas
Regional Haze SO2 and PM SIP
Revision’’ at the end of the third table.
The revision and additions read as
follows:
■
■
Identification of plan.
*
1. The authority citation for part 52
continues to read as follows:
■
Authority: 42 U.S.C. 7401 et seq.
§ 52.170
PART 52—APPROVAL AND
PROMULGATION OF
IMPLEMENTATION PLANS
62237
*
*
(d) * * *
(e) * * *
*
*
*
*
*
*
*
EPA-APPROVED ARKANSAS SOURCE-SPECIFIC REQUIREMENTS
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Name of source
Permit or order no.
State
approval/
effective
date
Arkansas Electric Cooperative
Corporation Carl E. Bailey
Plant.
Administrative Order LIS No.
18–071.
8/7/2018
Arkansas Electric Cooperative
Corporation John L. McClellan.
Administrative Order LIS No.
18–072.
8/7/2018
Entergy Arkansas, Inc. Lake
Catherine Plant.
Administrative Order LIS No.
18–073.
8/7/2018
Entergy Arkansas, Inc. White
Bluff Plant.
Administrative Order LIS No.
18–073.
8/7/2018
Entergy Arkansas, Inc. Independence Plant.
Administrative Order LIS No.
18–073.
8/7/2018
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EPA approval date
[Date of publication of the
final rule in the Federal
Register] [Federal Register citation of the final
rule].
[Date of publication of the
final rule in the Federal
Register] [Federal Register citation of the final
rule].
[Date of publication of the
final rule in the Federal
Register] [Federal Register citation of the final
rule].
[Date of publication of the
final rule in the Federal
Register] [Federal Register citation of the final
rule].
[Date of publication of the
final rule in the Federal
Register] [Federal Register citation of the final
rule].
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Unit 1.
Unit 1.
Unit 4.
Units 1, 2, and the Auxiliary
Boiler.
Units 1 and 2.
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EPA-APPROVED NON-REGULATORY PROVISIONS AND QUASI-REGULATORY MEASURES IN THE ARKANSAS SIP
Name of SIP provision
Applicable geographic
or nonattainment area
*
Arkansas Regional
Haze SO2 and PM
SIP Revision.
*
Statewide ...................
3. Section 52.173 is amended by:
a. Revising the introductory text of
paragraph (c) and paragraph (c)(1);
■ b. In paragraph (c)(2) revising the
definition ‘‘Boiler-operating-day’’;
■ c. Removing paragraphs (c)(3) through
(12), and (22) through (24);
■ d. Redesignating paragraphs (c)(13)
through (21) as paragraphs (c)(3)
through (11);
■ e. Redesignating paragraphs (c)(25)
through (27) as paragraphs (c)(12)
through (14);
■ f. Revising newly redesignated
paragraphs (c)(4), (c)(5),(c)(7), (c)(8),
(c)(10), (c)(11), and (c)(12);
■ g. Adding paragraphs (g) and (h).
The revisions and additions read as
follows:
■
■
§ 52.173
Visibility protection.
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*
*
*
*
*
(c) Federal implementation plan for
regional haze. Requirements for Domtar
Ashdown Paper Mill Power Boilers No.
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
Domtar Ashdown Paper Mill Power
Boilers No. 1 and 2.
(2) * * *
Boiler-operating-day means 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.
*
*
*
*
*
(4) 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)(3) of this
section by November 28, 2016.
(5) 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
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State submittal/
effective date
EPA approval date
*
*
*
August 8, 2018 .......... [Date of publication of
the final rule in the
Federal Register]
[Federal Register
citation of the final
rule].
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 sitespecific 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 boileroperating-day of the 30-day rolling
average for the boiler must be
determined by adding together the
pounds of SO2 from that boileroperating-day and the preceding 29
boiler-operating-days and dividing the
total pounds of SO2 by the sum of the
total number of boiler operating days
(i.e., 30). The result shall be the 30
boiler-operating-day rolling average in
terms of lb/day emissions of SO2.
Records of the total SO2 emitted for each
day must be compiled no later than 15
days after the end of the month and
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Explanation
*
*
Regional Haze SIP submittal addressing
SO2 and PM BART requirements for Arkansas EGUs, NOX BART requirement for
the White Bluff Auxiliary Boiler, and reasonable progress requirements for SO2 for
the first implementation period.
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)(5)(i) must be maintained by the
owner or operator for each boileroperating-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)(3) of
this section. The compliance
determination requirements and the
reporting and recordkeeping
requirements under paragraph (c)(5)(i)
of this section would not apply and
confirmation of the accuracy of the sitespecific curve equation under paragraph
(c)(5)(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)(3) of this section, the owner or
operator shall conduct stack testing
using EPA Reference Method 7E, found
at 40 CFR part 60, Appendix A, once
every 5 years, beginning 1 year from the
effective date of our final rule, which
corresponds to October 27, 2017.
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)(3) 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
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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-operatingday 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 boileroperating-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)(5)(iii)
of this section would not apply.
*
*
*
*
*
(7) 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)(6) of this section by October 27,
2021.
(8) 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 boileroperating-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-operatingdays 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
VerDate Sep<11>2014
21:33 Nov 29, 2018
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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
in this paragraph (c)(8)(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) The owner or operator shall
continue to maintain and operate a
CEMS for SO2 and NOX on the boiler
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
40 CFR 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)(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 15minute period. Hourly averages shall be
computed using at least one data point
in each fifteen-minute quadrant of an
hour. Notwithstanding this requirement,
an hourly average may be computed
from at least two data points separated
by a minimum of 15 minutes (where the
unit operates for more than one
quadrant in an hour) if data are
unavailable as a result of performance of
calibration, quality assurance,
preventive maintenance activities, or
backups of data from data acquisition
and handling system, and recertification
events. When valid SO2 or NOX pounds
per hour emission data are not obtained
because of continuous monitoring
system breakdowns, repairs, calibration
checks, or zero and span adjustments,
emission data must be obtained by using
other monitoring systems approved by
the EPA to provide emission data for a
minimum of 18 hours in each 24-hour
period and at least 22 out of 30
successive boiler operating days.
(iv) If the air permit is revised such
that Power Boiler No. 2 is permitted to
burn only pipeline quality natural gas,
this is sufficient to demonstrate that the
boiler is complying with the SO2
emission limit under paragraph (c)(6) of
this section. Under these circumstances,
PO 00000
Frm 00037
Fmt 4701
Sfmt 4702
62239
the compliance determination
requirements under paragraphs (c)(8)(i)
through (iii) of this section would not
apply to the SO2 emission limit listed in
paragraph (c)(6) 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)(6) 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-operatingday 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 boileroperating-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)(8)(i) through (iii) of this
section would not apply to the NOX
emission limit.
*
*
*
*
*
(10) 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)(9) of this section
by November 28, 2016.
(11) 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
E:\FR\FM\30NOP5.SGM
30NOP5
62240
Federal Register / Vol. 83, No. 231 / Friday, November 30, 2018 / Proposed Rules
amozie on DSK3GDR082PROD with PROPOSALS5
with the PM BART requirement under
paragraph (c)(9) of this section.
(12) 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
Division, U.S. Environmental Protection
Agency, Region 6, to the attention of
Mail Code: 6MM, at 1445 Ross Avenue,
Suite 1200, Dallas, Texas 75202–2733.
For each unit subject to the emissions
VerDate Sep<11>2014
21:33 Nov 29, 2018
Jkt 247001
limitation under paragraph (c) of this
section, the owner or operator shall
comply with the following
requirements, unless otherwise
specified:
*
*
*
*
*
(g) Measures addressing best available
retrofit technology (BART) for electric
generating unit (EGU) emissions of
sulfur dioxide (SO2) and particulate
matter. The BART requirements for SO2
and PM emissions from EGUs in
Arkansas and NOX emissions from the
White Bluff Auxiliary Boiler are
satisfied by the Arkansas Regional Haze
PO 00000
Frm 00038
Fmt 4701
Sfmt 9990
SO2 and PM SIP Revision approved
[Date 30 days after date of publication
of the final rule in the Federal Register].
(h) Other measures addressing
reasonable progress. The reasonable
progress requirements for SO2 and PM
emissions are satisfied by the Arkansas
Regional Haze SO2 and PM SIP Revision
approved [Date 30 days after date of
publication of the final rule in the
Federal Register], the Arkansas
Regional Haze FIP, and the 2008
Arkansas Regional Haze SIP.
[FR Doc. 2018–26073 Filed 11–29–18; 8:45 am]
BILLING CODE 6560–50–P
E:\FR\FM\30NOP5.SGM
30NOP5
]]>Agencies
[Federal Register Volume 83, Number 231 (Friday, November 30, 2018)]
[Proposed Rules]
[Pages 62204-62240]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2018-26073]
[[Page 62203]]
Vol. 83
Friday,
No. 231
November 30, 2018
Part V
Environmental Protection Agency
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40 CFR Part 52
Approval and Promulgation of Implementation Plans; Arkansas; Approval
of Regional Haze State Implementation Plan Revision and Partial
Withdrawal of Federal Implementation Plan; Proposed Rule
Federal Register / Vol. 83 , No. 231 / Friday, November 30, 2018 /
Proposed Rules
[[Page 62204]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 52
[EPA-R06-OAR-2015-0189; FRL-9986-67-Region 6]
Approval and Promulgation of Implementation Plans; Arkansas;
Approval of Regional Haze State Implementation Plan Revision and
Partial Withdrawal of Federal Implementation Plan
AGENCY: Environmental Protection Agency (EPA).
ACTION: Proposed rule.
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SUMMARY: Pursuant to the Federal Clean Air Act (CAA or the Act), the
Environmental Protection Agency (EPA) is proposing to approve a portion
of the revision to the Arkansas State Implementation Plan (SIP) that
addresses certain requirements of the CAA and the EPA's regional haze
rules for the protection of visibility in mandatory Class I Federal
areas (Class I areas) for the first implementation period. The EPA is
proposing to approve the portions of the SIP revision addressing the
best available retrofit technology (BART) requirements for sulfur
dioxide (SO2), particulate matter (PM) and nitrogen oxide
(NOX) for seven electric generating units (EGUs) in
Arkansas. The EPA is also proposing to approve the determination that
no additional controls at any Arkansas sources are necessary under
reasonable progress; calculation of the revised reasonable progress
goals (RPGs) for Arkansas' Class I areas; certain components of the
long-term strategy for making reasonable progress; the clarification
that both the 6A and 9A Boilers at the Georgia-Pacific Crossett Mill
are BART-eligible; and the additional information and technical
analysis in support of the determination that the Georgia-Pacific
Crossett Mill 6A and 9A Boilers are not subject to BART. In conjunction
with our proposed approval of portions of the SIP revision, we are
proposing to withdraw the corresponding federal implementation plan
(FIP) provisions established in a prior action to address regional haze
requirements for Arkansas.
DATES: Written comments must be received on or before December 31,
2018.
ADDRESSES: Submit your comments, identified by Docket No. EPA-R06-OAR-
2015-0189, at https://www.regulations.gov or via email to
[email protected]. Follow the online instructions for submitting
comments. Once submitted, comments cannot be edited or removed from
Regulations.gov. The EPA may publish any comment received to its public
docket. Do not submit electronically any information you consider to be
Confidential Business Information (CBI) or other information whose
disclosure is restricted by statute. Multimedia submissions (audio,
video, etc.) must be accompanied by a written comment. The written
comment is considered the official comment and should include
discussion of all points you wish to make. The EPA will generally not
consider comments or comment contents located outside of the primary
submission (i.e. on the web, cloud, or other file sharing system). For
additional submission methods, please contact Dayana Medina,
[email protected]. For the full EPA public comment policy,
information about CBI or multimedia submissions, and general guidance
on making effective comments, please visit https://www2.epa.gov/dockets/commenting-epa-dockets.
Docket: The index to the docket for this action is available
electronically at www.regulations.gov and in hard copy at the EPA
Region 6, 1445 Ross Avenue, Suite 700, Dallas, Texas. While all
documents in the docket are listed in the index, some information may
be publicly available only at the hard copy location (e.g., copyrighted
material), and some may not be publicly available at either location
(e.g., CBI).
FOR FURTHER INFORMATION CONTACT: Dayana Medina, 214-665-7241,
[email protected]. To inspect the hard copy materials, please
schedule an appointment with Dayana Medina or Mr. Bill Deese at 214-
665-7253.
SUPPLEMENTARY INFORMATION: Throughout this document wherever ``we,''
``us,'' or ``our'' is used, we mean the EPA.
Table of Contents
I. Background
A. The Regional Haze Program
B. Our Previous Actions on Arkansas Regional Haze
II. Our Evaluation of Arkansas' SO2 and PM Regional Haze
SIP Revision
A. Identification of BART-Eligible and Subject-to-BART Sources
B. Arkansas' Five-Factor Analyses for SO2 and PM BART
1. AECC Bailey Unit 1
a. SO2 BART Analysis and Determination
b. PM BART Analysis and Determination
2. AECC McClellan Unit 1
a. SO2 BART Analysis and Determination
b. PM BART Analysis and Determination
3. SWEPCO Flint Creek Plant Boiler No. 1
a. SO2 BART Analysis and Determination
4. Entergy Lake Catherine Unit 4
5. Entergy White Bluff Units 1 and 2 and the White Bluff
Auxiliary Boiler
a. White Bluff Units 1 and 2 SO2 BART Analysis and
Determinations
b. White Bluff Auxiliary Boiler BART Determinations
C. Reasonable Progress Analysis for SO2
1. Arkansas' Discussion of Key Pollutants and Source Category
Contributions
a. Region-Wide PSAT Data for Caney Creek and Upper Buffalo
b. Arkansas PSAT Data for Caney Creek and Upper Buffalo
c. Arkansas' Conclusions Regarding Key Pollutants and Source
Category Contributions
2. Arkansas' Analysis of Reasonable Progress Factors Broadly
Applicable to Arkansas Sources
3. Identification of Potential Sources for Evaluation of
SO2 Controls Under Reasonable Progress
4. Arkansas' Reasonable Progress Analysis for Independence Units
1 and 2
a. Arkansas' Evaluation of the Reasonable Progress Factors for
SO2 for Entergy Independence Units 1 and 2
b. Arkansas' Determination Regarding Reasonable Progress
Requirements for Independence
5. Arkansas' Determination Regarding Additional Controls
Necessary Under Reasonable Progress and Revised RPGs
6. EPA's Evaluation and Conclusions on Arkansas' Reasonable
Progress Analysis and Revised RPGs
D. Long-Term Strategy
E. Required Consultation
F. Interstate Visibility Transport Under Section
110(a)(2)(D)(i)(II)
G. Clean Air Act Section 110(l)
III. Proposed Action
A. Arkansas' Regional Haze SIP Revision
B. Partial FIP Withdrawal
C. Clean Air Act Section 110(l)
IV. Incorporation by Reference
V. Statutory and Executive Order Reviews
I. Background
A. The Regional Haze Program
Regional haze is visibility impairment that is produced by a
multitude of sources and activities that are located across a broad
geographic area and emit fine particulates (PM2.5) (e.g.,
sulfates, nitrates, organic carbon (OC), elemental carbon (EC), and
soil dust), and their precursors (e.g., SO2, NOX,
and in some cases, ammonia (NH3) and volatile organic
compounds (VOCs)). Fine particle precursors react in the atmosphere to
form PM2.5, which impairs visibility by scattering and
absorbing light. This light scattering reduces the clarity, color and
visible distance that one can see. Particulate matter can also cause
serious health effects in humans (including premature death, heart
attacks, irregular heartbeat, aggravated asthma, decreased lung
function and increased respiratory symptoms) and contribute to
[[Page 62205]]
environmental effects such as acid deposition and eutrophication.
Data from the existing visibility monitoring network, the
``Interagency Monitoring of Protected Visual Environments'' (IMPROVE)
monitoring network, show that at the time the Regional Haze Rule was
finalized in 1999, visibility impairment caused by air pollution
occurred virtually all the time at most national parks and wilderness
areas. The average visual range \1\ in many Class I areas in the
western U.S. was 62-93 miles, but in some Class I areas, these visual
ranges may have been impacted by natural wildfire and dust episodes in
addition to anthropogenic impacts. In most of the eastern Class I areas
of the U.S., the average visual range was less than 19 miles.\2\ CAA
programs have reduced emissions of some haze-causing pollution,
lessening some visibility impairment and resulting in partially
improved average visual ranges.\3\
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\1\ Visual range is the greatest distance, in kilometers or
miles, at which a dark object can be discerned against the sky by a
typical observer. Visual range is inversely proportional to light
extinction (bext) by particles and gases and is calculated as:
Visual Range = 3.91/bext (Bennett, M.G., The physical conditions
controlling visibility through the atmosphere; Quarterly Journal of
the Royal Meteorological Society, 1930, 56, 1-29). Light extinction
has units of inverse distance (i.e., Mm-1 or inverse
Megameters [mega = 106]).
\2\ 64 FR 35715 (July 1, 1999).
\3\ An interactive ``story map'' depicting efforts and recent
progress by EPA and states to improve visibility at national parks
and wilderness areas may be visited at: https://arcg.is/29tAbS3.
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In section 169A of the 1977 Amendments to the CAA, Congress created
a program for protecting visibility in the nation's national parks and
wilderness areas. This section of the CAA establishes as a national
goal the prevention of any future, and the remedying of any existing,
man-made impairment of visibility in 156 national parks and wilderness
areas designated as mandatory Class I Federal areas.\4\ Congress added
section 169B to the CAA in 1990 to address regional haze issues, and
the EPA promulgated regulations addressing regional haze in 1999. The
Regional Haze Rule \5\ revised the existing visibility regulations to
add provisions addressing regional haze impairment and established a
comprehensive visibility protection program for Class I areas. The
requirements for regional haze, found at 40 CFR 51.308 and 51.309, are
included in our visibility protection regulations at 40 CFR 51.300-309.
The requirement to submit a regional haze SIP revision at periodic
intervals applies to all 50 states, the District of Columbia, and the
Virgin Islands. States were required to submit the first implementation
plan addressing regional haze visibility impairment no later than
December 17, 2007.\6\
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\4\ Areas designated as mandatory Class I Federal areas consist
of National Parks exceeding 6,000 acres, wilderness areas and
national memorial parks exceeding 5,000 acres, and all international
parks that were in existence on August 7, 1977. 42 U.S.C. 7472(a).
In accordance with section 169A of the CAA, EPA, in consultation
with the Department of Interior, promulgated a list of 156 areas
where visibility is identified as an important value. 44 FR 69122
(November 30, 1979). The extent of a mandatory Class I area includes
subsequent changes in boundaries, such as park expansions. 42 U.S.C.
7472(a). Although states and tribes may designate as Class I
additional areas which they consider to have visibility as an
important value, the requirements of the visibility program set
forth in section 169A of the CAA apply only to ``mandatory Class I
Federal areas.'' Each mandatory Class I Federal area is the
responsibility of a ``Federal Land Manager.'' 42 U.S.C. 7602(i).
When we use the term ``Class I area'' in this action, we mean a
``mandatory Class I Federal area.''
\5\ Here and elsewhere in this document, the term ``Regional
Haze Rule,'' refers to the 1999 final rule (64 FR 35714), as amended
in 2005 (70 FR 39156, July 6, 2005), 2006 (71 FR 60631, October 13,
2006), 2012 (77 FR 33656, June 7, 2012), and 2017 (82 FR 3078,
January 10, 2017).
\6\ See 40 CFR 51.308(b). EPA's regional haze regulations
require subsequent updates to the regional haze SIPs. 40 CFR
51.308(f)-(i). The next update is due by July 31, 2021.
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Section 169A of the CAA directs states to evaluate the use of
retrofit controls at certain larger, often under-controlled, older
stationary sources in order to address visibility impacts from these
sources. Specifically, section 169A(b)(2)(A) of the CAA requires states
to revise their SIPs to contain such measures as may be necessary to
make reasonable progress toward the natural visibility goal, including
a requirement that certain categories of existing major stationary
sources \7\ built between 1962 and 1977 procure, install, and operate
BART controls. Larger ``fossil-fuel fired steam electric plants'' are
one of these source categories. Under the Regional Haze Rule, states
are directed to conduct BART determinations for ``BART-eligible''
sources that may be anticipated to cause or contribute to any
visibility impairment in a Class I area. Sources that are reasonably
anticipated to cause or contribute to any visibility impairment in a
Class I area are determined to be subject-to-BART. For each source
subject to BART, 40 CFR 51.308(e)(1)(ii)(A) requires that states (or
EPA, in the case of a FIP) identify the level of control representing
BART after considering the factors set out in CAA section 169A(g). The
evaluation of BART for EGUs that are located at fossil-fuel fired power
plants having a generating capacity in excess of 750 megawatts (MW)
must follow the ``Guidelines for BART Determinations Under the Regional
Haze Rule'' at appendix Y to 40 CFR part 51 (hereinafter referred to as
the ``BART Guidelines''). Rather than requiring source-specific BART
controls, states also have the flexibility to adopt an emissions
trading program or other alternative program as long as the alternative
provides for greater reasonable progress towards improving visibility
than BART.
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\7\ See 42 U.S.C. 7491(g)(7) (listing the set of ``major
stationary sources'' potentially subject-to-BART).
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The vehicle for ensuring continuing progress towards achieving the
natural visibility goal is the submission of a series of regional haze
SIPs that contain long-term strategies to make reasonable progress
towards natural visibility conditions. As part of this process, States
also establish RPGs for every Class I area to provide assessments of
the improvements in visibility anticipated to result from the long-term
strategies. States have significant flexibility in establishing long-
term strategies and RPGs,\8\ but must determine whether additional
control measures beyond BART and other ``on the books'' controls are
needed for reasonable progress based on consideration of the following
factors set out in section 169A of the CAA: (1) The costs of
compliance; (2) the time necessary for compliance; (3) the energy and
non-air quality environmental impacts of compliance; and (4) the
remaining useful life of any potentially affected sources. States must
demonstrate in their SIPs how these factors are considered when
selecting measures for their long-term strategies and calculating the
associated RPGs for each applicable Class I area. We commonly refer to
this as the ``reasonable progress analysis'' or ``four factor
analysis.''
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\8\ Guidance for Setting Reasonable Progress Goals under the
Regional Haze Program, June 1, 2007, memorandum from William L.
Wehrum, Acting Assistant Administrator for Air and Radiation, to EPA
Regional Administrators, EPA Regions 1-10 (pp. 4-2, 5-1).
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B. Our Previous Actions on Arkansas Regional Haze
Arkansas submitted a SIP revision on September 9, 2008, to address
the requirements of the first regional haze implementation period. On
August 3, 2010, Arkansas submitted a SIP revision with mostly non-
substantive revisions to Arkansas Pollution Control and Ecology
Commission (APCEC) Regulation 19, Chapter 15.\9\ On
[[Page 62206]]
September 27, 2011, the State submitted supplemental information to
address the regional haze requirements. We are hereafter referring to
these regional haze submittals collectively as the ``2008 Arkansas
Regional Haze SIP.'' On March 12, 2012, we partially approved and
partially disapproved the 2008 Arkansas Regional Haze SIP.\10\ On
September 27, 2016, we promulgated a FIP (the Arkansas Regional Haze
FIP) addressing the disapproved portions of the 2008 Arkansas Regional
Haze SIP.\11\ Among other things, the FIP established SO2,
NOX, and PM emission limits under the BART requirements for
nine units at six facilities: AECC Bailey Plant Unit 1; AECC McClellan
Plant Unit 1; SWEPCO Flint Creek Plant Boiler No. 1; Entergy Lake
Catherine Plant Unit 4; Entergy White Bluff Plant Units 1 and 2;
Entergy White Bluff Auxiliary Boiler; and the Domtar Ashdown Mill Power
Boilers No. 1 and 2. The FIP also established SO2 and
NOX emission limits under the reasonable progress
requirements for Entergy Independence Units 1 and 2.
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\9\ The September 9, 2008, SIP submittal included APCEC
Regulation 19, Chapter 15, which is the state regulation that
identified the BART-eligible and subject-to-BART sources in Arkansas
and established BART emission limits for subject-to-BART sources.
The August 3, 2010, SIP revision did not revise Arkansas' list of
BART-eligible and subject-to-BART sources or revise any of the BART
requirements for affected sources. Instead, it included mostly non-
substantive revisions to the state regulation.
\10\ 77 FR 14604.
\11\ 81 FR 66332; see also 81 FR 68319 (October 4, 2016)
(correction).
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Following the issuance of the Arkansas Regional Haze FIP, the State
of Arkansas and several industry parties filed petitions for
reconsideration and an administrative stay of the final rule.\12\ On
April 14, 2017, we announced our decision to convene a proceeding to
reconsider several elements of the FIP, as follows: Appropriate
compliance dates for the NOX emission limits for Flint Creek
Boiler No. 1, White Bluff Units 1 and 2, and Independence Units 1 and
2; the low-load NOX emission limits applicable to White
Bluff Units 1 and 2 and Independence Units 1 and 2 during periods of
operation at less than 50 percent of the unit's maximum heat input
rating; the SO2 emission limits for White Bluff Units 1 and
2; and the compliance dates for the SO2 emission limits for
Independence Units 1 and 2.\13\
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\12\ See the docket associated with this proposed rulemaking for
a copy of the petitions for reconsideration and administrative stay
submitted by the State of Arkansas; Entergy Arkansas Inc., Entergy
Mississippi Inc., and Entergy Power LLC (collectively ``Entergy'');
AECC; and the Energy and Environmental Alliance of Arkansas (EEAA).
\13\ Letter from E. Scott Pruitt, Administrator, EPA, to
Nicholas Jacob Bronni and Jamie Leigh Ewing, Arkansas Attorney
General's Office (April 14, 2017). A copy of this letter is included
in the docket, https://www.regulations.gov/document?D=EPA-R06-OAR-2015-0189-0240.
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EPA also published a notice in the Federal Register on April 25,
2017, administratively staying the effectiveness of the NOX
compliance dates in the FIP for the Flint Creek, White Bluff, and
Independence units, as well as the compliance dates for the
SO2 emission limits for the White Bluff and Independence
units for a period of 90 days.\14\ On July 13, 2017, the EPA published
a proposed rule to extend the NOX compliance dates for Flint
Creek Boiler No. 1, White Bluff Units 1 and 2, and Independence Units 1
and 2, by 21 months to January 27, 2020.\15\ However, EPA did not take
final action on the July 13, 2017, proposed rule because on July 12,
2017, Arkansas submitted a proposed SIP revision with a request for
parallel processing, addressing the NOX BART requirements
for Bailey Unit 1, McClellan Unit 1, Flint Creek Boiler No. 1, Lake
Catherine Unit 4, White Bluff Units 1 and 2, White Bluff Auxiliary
Boiler, as well as the reasonable progress requirements with respect to
NOX (Arkansas Regional Haze NOX SIP revision or
Arkansas NOX SIP revision). In a proposed rule published in
the Federal Register on September 11, 2017, we proposed to approve the
Arkansas Regional Haze NOX SIP revision and to withdraw the
corresponding parts of the Arkansas Regional Haze FIP.\16\ On October
31, 2017, we received ADEQ's final Regional Haze NOX SIP
revision addressing NOX BART for EGUs and the reasonable
progress requirements with respect to NOX for the first
implementation period. On February 12, 2018, we took final action to
approve the Arkansas Regional Haze NOX SIP revision and to
withdraw the corresponding parts of the FIP.\17\
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\14\ 82 FR 18994.
\15\ 82 FR 32284.
\16\ 82 FR 42627.
\17\ 83 FR 5927 and 83 FR 5915 (February 12, 2018).
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II. Our Evaluation of Arkansas' SO2 and PM Regional Haze SIP Revision
On August 8, 2018, Arkansas submitted a SIP revision (Arkansas
Regional Haze SO2 and PM SIP revision) addressing all
remaining disapproved parts of the 2008 Regional Haze SIP, with the
exception of the BART and associated long-term strategy requirements
for the Domtar Ashdown Mill Power Boilers No. 1 and 2. The SIP revision
also includes a discussion on Arkansas' interstate visibility transport
requirements. We are proposing action on a portion of the August 8,
2018, Arkansas Regional Haze SO2 and PM SIP revision in this
Federal Register notice, and we are also proposing to withdraw the
parts of the FIP corresponding to our proposed approvals. Since we are
proposing to withdraw certain portions of the FIP, we are also
proposing to redesignate the FIP by revising the numbering of certain
paragraphs under section 40 CFR 52.173. Our proposed redesignation of
the numbering of these paragraphs is non-substantive and does not mean
we are reopening these parts for public comment in this proposed
rulemaking. We intend to propose action on the portion of this SIP
revision discussing the interstate visibility transport requirements
for pollutants that affect visibility in Class I areas in nearby states
in a future proposed rulemaking.
The Arkansas Regional Haze SO2 and PM SIP revision
submitted to us on August 8, 2018, addresses the majority of the
remaining parts of the 2008 Regional Haze SIP that EPA disapproved on
March 12, 2012.\18\ Specifically, the August 8, 2018, SIP revision
revises ADEQ's identification of BART-eligible sources by now
identifying the 6A Boiler at the Georgia-Pacific Crossett Mill as BART-
eligible; provides additional information and technical analysis in
support of the determination that the Georgia-Pacific Crossett Mill 6A
and 9A Boilers are not subject to BART; \19\ prohibits the burning of
fuel oil at Lake Catherine Unit 4 until SO2 and PM BART
determinations for the fuel oil firing scenario are approved into the
SIP by EPA; and addresses the following BART requirements:
SO2 and PM BART for Bailey Unit 1 and McClellan Unit 1;
SO2 BART for Flint Creek Boiler No. 1; SO2 BART
for White Bluff Units 1 and 2; and SO2, NOX, and
PM BART for the White Bluff Auxiliary Boiler. The SIP revision also
addresses the reasonable progress requirements, arriving at the
conclusion that no additional controls at Independence Units 1 and 2 or
any other Arkansas sources are necessary under reasonable progress,\20\
and establishes revised RPGs for Arkansas' two Class I areas, the Caney
Creek Wilderness Area and the Upper Buffalo Wilderness Area. Finally,
the SIP
[[Page 62207]]
revision revises the State's long-term strategy by including in the
long-term strategy an SO2 emission limit of 0.60 lb/MMBtu
for Independence Units 1 and 2 based on the use of low sulfur coal, as
well as each of the BART measures listed above. The August 8, 2018, SIP
revision does not address BART for the Domtar Ashdown Mill Power
Boilers No. 1 and 2 and relies on the Domtar BART emission limits from
our FIP and the 2012 partially approved SIP for the associated long-
term strategy requirements.
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\18\ 77 FR 14604.
\19\ BART eligible sources that are reasonably anticipated to
cause or contribute to any visibility impairment in a Class I area
are determined to be subject-to-BART. In the 2008 Arkansas Regional
Haze SIP, ADEQ used a contribution threshold of 0.5 dv for
determining whether a source ``contributes'' to visibility
impairment and is thus subject to BART.
\20\ In a SIP revision submitted on October 31, 2017, Arkansas
provided a reasonable progress analysis and reasonable progress
determination with respect to NOX, and we took final
action to approve the analysis and determination in a final action
published on February 12, 2018 (see 83 FR 5927). Thus, the August 8,
2018 SIP revision addresses reasonable progress requirements with
respect to SO2 and PM emissions.
---------------------------------------------------------------------------
The August 8, 2018, SIP revision is the subject of this proposed
action, in conjunction with our proposed withdrawal of the parts of the
Arkansas Regional Haze FIP corresponding to our proposed approval. We
are proposing to approve ADEQ's revised identification of the 6A Boiler
at the Georgia-Pacific Crossett Mill as BART-eligible; the additional
information and technical analysis presented in the SIP revision in
support of the determination that the Georgia-Pacific Crossett Mill 6A
and 9A Boilers are not subject to BART; and the state's BART decisions
for the seven subject-to-BART units listed above. We are proposing to
withdraw our prior approval of Arkansas' reliance on participation in
the Cross-State Air Pollution Rule (CSAPR) for ozone season
NOX to satisfy the NOX BART requirement for the
White Bluff Auxiliary Boiler. The Arkansas Regional Haze NOX
SIP revision erroneously stated that the Auxiliary Boiler participates
in CSAPR for ozone season NOX and that the state was
electing to rely on participation in that trading program to satisfy
the Auxiliary Boiler's NOX BART requirements, and we
erroneously approved this determination in a final action published in
the Federal Register on February 12, 2018.\21\ We are proposing to
withdraw our approval of that determination for the Auxiliary Boiler
and to replace it with our proposed approval of a source specific
NOX BART emission limit contained in the Arkansas Regional
Haze SIP Revision before us.
---------------------------------------------------------------------------
\21\ 83 FR 5927.
---------------------------------------------------------------------------
We are also proposing to approve Arkansas' reasonable progress
determinations for Independence Units 1 and 2 and all other sources in
Arkansas, and to approve the revised RPGs contained in the August 8,
2018, SIP revision. We are further proposing to find that, based on the
state's currently approved SIP and the analyses and determinations we
are proposing to approve in this action, the state's reasonable
progress obligations for the first implementation period have been
satisfied. At this time, the majority of the BART requirements for the
Domtar Ashdown Mill are satisfied by a FIP.\22\ The SIP revision
explains that, based upon the BART determinations and analysis in that
FIP, nothing further is currently needed for reasonable progress at the
Domtar Ashdown Mill. EPA agrees. If the State chooses to submit a
further SIP revision to address BART requirements for Domtar Power
Boilers No. 1 and No. 2 that are currently satisfied by the FIP, we
will evaluate that SIP submittal, including as well as any conclusions
ADEQ draws about the adequacy of such SIP-based measures for reasonable
progress. We will also, at that time, evaluate any changes in the
measures for the Domtar Ashdown Mill relative to those currently in the
FIP to determine whether the calculation of the reasonable progress
goals for the first implementation period continue to be sufficient.
---------------------------------------------------------------------------
\22\ We note that the PM determination for Domtar Ashdown Mill
Power Boiler No. 1 in the 2008 SIP was approved in our 2012
rulemaking. (77 FR 14604, March 12, 2012).
---------------------------------------------------------------------------
Finally, we are proposing to approve the components of the long-
term strategy addressed by the August 8, 2018, SIP revision and to find
that Arkansas' long-term strategy for reasonable progress with respect
to all sources other than Domtar is approved. The long-term strategy is
the compilation of all control measures a state will use during the
implementation period of the specific SIP submittal to make reasonable
progress towards the goal of natural visibility conditions, including
emission limitations corresponding to BART determinations. If the
proposed approvals of the BART measures and the emission limitations
for the Independence facility addressed in this action are finalized,
those measures will also be integrated into the State's long-term
strategy. Because the August 8, 2018, SIP revision does not address the
BART requirements for Domtar, that component of the long-term strategy
will remain satisfied by the FIP unless and until EPA has received and
approved a SIP revision containing the required analyses and
determinations for this facility.
We are also proposing to withdraw the majority of the Arkansas
Regional Haze FIP we promulgated on September 27, 2016. Upon
finalization of this proposed rulemaking, the majority of remaining FIP
provisions would be replaced by the corresponding revisions to the SIP
that we are proposing to approve in this proposed rulemaking.
Specifically, we are proposing to withdraw the following components of
the FIP: The SO2 and PM BART emission limits for Bailey Unit
1; the SO2 and PM BART emission limits for McClellan Unit 1;
the SO2 BART emission limit for Flint Creek Boiler No. 1;
the SO2 BART emission limit for White Bluff Units 1 and 2;
the SO2 and PM BART emission limits for the White Bluff
Auxiliary Boiler; the prohibition on burning fuel oil at Lake Catherine
Unit 4; and the SO2 emission limits for Independence Units 1
and 2 under the reasonable progress provisions. Since we are proposing
to withdraw certain portions of the FIP, we are also proposing to
redesignate the FIP by revising the numbering of certain paragraphs
under section 40 CFR 52.173. Our proposed redesignation of the
numbering of these paragraphs is non-substantive and does not mean we
are reopening these parts for public comment in this proposed
rulemaking.
The SIP revision also includes a discussion on interstate
visibility transport. Specifically, the SIP revision discusses the
impacts of Arkansas sources on Missouri's Class I areas, as well as the
most recent IMPROVE monitoring data for Missouri's Class I areas. The
SIP revision concludes that Missouri is on track to achieve its
visibility goals, that the visibility progress observed indicates that
sources in Arkansas are not interfering with the achievement of
Missouri's RPGs for the Hercules-Glades Wilderness Area and Mingo
Wilderness Area, and that no additional controls on sources within
Arkansas are necessary to ensure that other states' visibility goals
for their Class I areas are met. We are deferring proposing action on
the interstate visibility transport portion of the SIP revision until a
future proposed rulemaking.
A. Identification of BART-Eligible and Subject-to-BART Sources
States are required to identify all the BART-eligible sources
within their boundaries by utilizing the three eligibility criteria in
the BART Guidelines \23\ and the Regional Haze Rule \24\: (1) One or
more emission units at the facility fit within one of the 26 categories
listed in the BART Guidelines; (2) the emission unit(s) began operation
on or after August 6, 1962, and the unit was in existence on August 6,
1977; and (3) the potential emissions of any visibility impairing
pollutant from subject units are 250 tons or more per year. Sources
that meet
[[Page 62208]]
these three criteria are considered BART-eligible. Once a list of the
BART-eligible sources within a state has been compiled, states must
determine whether to make BART determinations for all of them or
whether some may not reasonably be anticipated to cause or contribute
to any visibility impairment in a Class I area and may thus not be
subject to further BART analysis or requirements. The BART Guidelines
present several options that rely on modeling and/or emissions analyses
to determine if a source may reasonably be anticipated to cause or
contribute to visibility impairment in a Class I area. A source that
may not be reasonably anticipated to cause or contribute to any
visibility impairment in any Class I area is not ``subject to BART,''
and for such sources, a state need not make a BART determination.
---------------------------------------------------------------------------
\23\ 70 FR 39158.
\24\ 40 CFR 51.301.
---------------------------------------------------------------------------
In our March 12, 2012, final action on the 2008 Arkansas Regional
Haze SIP, we approved Arkansas' identification of BART-eligible sources
with the exception of the Georgia-Pacific Crossett Mill 6A Boiler.\25\
We also approved Arkansas' determination of which sources are subject
to BART, with the exception of its determination that the Georgia-
Pacific Crossett Mill 6A and 9A Boilers are not subject to BART. In
that final action, we determined that the 2008 Arkansas Regional Haze
SIP did not include sufficient documentation to demonstrate that the 6A
Boiler is not BART-eligible and did not contain sufficient
documentation to demonstrate that the 6A and 9A Boilers are not subject
to BART. In the Arkansas Regional Haze FIP, we made the determination
that the 6A Boiler is BART-eligible. We also noted that we continued to
agree with the state's previous determination from the 2008 Arkansas
Regional Haze SIP that the 9A Boiler is BART-eligible. Based on
additional information and a technical analysis provided to the EPA by
Georgia-Pacific, EPA determined that the 6A and 9A Boilers are not
subject to BART. In the August 8, 2018, Arkansas Regional Haze
SO2 and PM SIP revision, Arkansas has made determinations
consistent with our findings in the FIP. Specifically, Arkansas made a
revision to its identification of BART-eligible sources,\26\ now
identifying the 6A Boiler at the Georgia-Pacific Crossett Mill as BART-
eligible. In the 2008 Arkansas Regional Haze SIP, the state had already
identified the 9A Boiler at the Georgia-Pacific Crossett Mill as BART-
eligible; in the August 8, 2018, SIP revision, the state made no
changes to the identification of the 9A Boiler as BART-eligible. In
addition, Arkansas included in the SIP revision a copy of the technical
analysis and other information that was provided by Georgia-Pacific to
EPA, which we previously included in the record for the Arkansas
Regional Haze FIP in support of our determination that the 6A and 9A
Boilers are not subject to BART.\27\ As Arkansas explains in the SIP
revision, Georgia-Pacific provided information regarding revisions to
emission limits included in the facility's permit and additional
dispersion modeling conducted in 2011 using those revised limits. The
results of this 2011 BART screening modeling demonstrated that the
maximum impact of the Georgia-Pacific Crossett Mill boilers on any
Class I area was less than the 0.5 dv threshold used by ADEQ to
determine whether a BART-eligible source should be considered subject
to BART. Because the 2011 BART screening modeling was based on permit
limits from a permit revision issued in 2012 rather than on maximum 24-
hour emission rates from the 2001-2003 baseline period, Georgia-Pacific
also provided further information regarding fuel usage during the 2001-
2003 baseline and performed calculations using AP-42, Compilation of
Air Pollutant Emission Factors, to estimate the 24-hour emission rates
for SO2, NOX, and PM10 for the 6A and
9A Boilers for each day during the baseline years. Georgia Pacific then
identified the maximum 24-hour emission rates for each pollutant for
the two boilers during the 2001-2003 baseline period. A comparison of
the estimated maximum 24-hour emission rates with the emission rates
modeled in Georgia-Pacific's 2011 BART screening modeling demonstrates
that the maximum 24-hour emission rates from the 2001-2003 baseline
were lower than the rates modeled in the 2011 BART screening modeling
and lower than the boilers' permit limits. Based upon the additional
information provided by Georgia-Pacific, ADEQ concluded that the 6A and
9A Boilers are not subject to BART.\28\ Thus, ADEQ revised its
identification of BART-eligible sources by identifying the Georgia-
Pacific Mill 6A Boiler as BART-eligible. Since ADEQ previously
determined in the 2008 Regional Haze SIP that the 9A Boiler is BART-
eligible, it made no change to that previous determination. ADEQ did
not make changes to its list of subject-to-BART sources, but did
include in the SIP revision the additional information and technical
analysis from Georgia-Pacific to support and document the determination
that the 6A and 9A boilers are not subject to BART.
---------------------------------------------------------------------------
\25\ 80 FR 18947.
\26\ See Arkansas Regional Haze SO2 and PM SIP
revision, Table 1, page 8 and 9.
\27\ See the documentation provided by Georgia Pacific to EPA
that was previously included in the record for the Arkansas Regional
Haze FIP. This documentation is included in the docket at the
following location: https://www.regulations.gov/searchResults?rpp=50&so=ASC&sb=docId&po=0&dktid=EPA-R06-OAR-2015-0189.
\28\ ADEQ provides documentation in support of the determination
that the Georgia-Pacific Crossett Mill 6A and 9A Boilers are not
subject to BART in Appendix A to the Arkansas Regional Haze
SO2 and PM SIP revision.
---------------------------------------------------------------------------
We are proposing to find that the analysis and documentation
provided by Georgia-Pacific and included in the Arkansas Regional Haze
SO2 and PM SIP revision appropriately and sufficiently
demonstrate that the 6A and 9A Boilers are not subject to BART. We are
proposing to approve ADEQ's revised determination that the 6A Boiler is
BART-eligible and concur that the 6A and 9A Boilers are not subject to
BART.
B. Arkansas' Five-Factor Analyses for SO2 and PM BART
In determining BART, the state must consider the five statutory
factors in section 169A of the CAA: (1) The costs of compliance; (2)
the energy and nonair quality environmental impacts of compliance; (3)
any existing pollution control technology in use at the source; (4) the
remaining useful life of the source; and (5) the degree of improvement
in visibility which may reasonably be anticipated to result from the
use of such technology.\29\ All units that are subject to BART must
undergo a BART analysis. The BART Guidelines break the analysis down
into five steps:\30\
---------------------------------------------------------------------------
\29\ See also 40 CFR 51.308(e)(1)(ii)(A).
\30\ 70 FR 39103, 39164 (July 6, 2005) [40 CFR 51, App. Y].
---------------------------------------------------------------------------
STEP 1--Identify All Available Retrofit Control Technologies,
STEP 2--Eliminate Technically Infeasible Options,
STEP 3--Evaluate Control Effectiveness of Remaining Control
Technologies,
STEP 4--Evaluate Impacts and Document the Results, and
STEP 5--Evaluate Visibility Impacts.
As mentioned previously, EPA partially approved and partially
disapproved the 2008 Arkansas Regional Haze SIP revision in a final
action published on March 12, 2012.\31\ Following our 2012 partial
disapproval of the 2008 Arkansas Regional Haze SIP, ADEQ began the
process of generating additional technical information and analyses
from the companies whose BART determinations we disapproved. These
analyses and technical
[[Page 62209]]
information were provided to EPA and were the basis for our evaluation
of BART for subject-to-BART facilities in the FIP. In turn, ADEQ relied
on those same analyses and technical information in the state's
evaluation of BART for subject-to-BART sources in the Arkansas Regional
Haze SO2 and PM SIP revision, with the exception of White
Bluff Units 1 and 2, for which updated technical information has been
provided by Entergy and is included in the SIP revision. In evaluating
the Arkansas Regional Haze SO2 and PM SIP revision, we
reviewed each BART analysis for SO2 and PM for each subject-
to-BART source and other relevant information provided in the SIP
revision.
---------------------------------------------------------------------------
\31\ 77 FR 14604.
---------------------------------------------------------------------------
As noted above, we approved certain parts of the 2008 Arkansas
Regional Haze SIP in 2012.\32\ The parts that we approved in 2012
included PM BART for Flint Creek Boiler No. 1; PM BART for White Bluff
Units 1 and 2; SO2 and PM BART for the natural gas firing
scenario for Lake Catherine Unit 4; and PM BART for Domtar Power Boiler
No. 1. We also published a final action on February 12, 2018, in which
we approved a SIP revision submitted by ADEQ on October 31, 2017, to
address the regional haze requirements for NOX for EGUs in
Arkansas (``Arkansas Regional Haze NOX SIP Revision'').\33\
That final action included approval of Arkansas' NOX BART
determinations for Bailey Unit 1; McClellan Unit 1; Flint Creek Boiler
No. 1; Lake Catherine Unit 4 (for both the natural gas firing and fuel
oil firing scenarios); White Bluff Units 1 and 2; and the White Bluff
Auxiliary Boiler; and removed the corresponding portions of the
Arkansas Regional Haze FIP. Thus, the only BART requirements currently
addressed under the Arkansas Regional Haze FIP are the SO2
and PM BART requirements for Bailey Unit 1; the SO2 and PM
BART requirements for McClellan Unit 1; the SO2 BART
requirements for Flint Creek Boiler No. 1; the prohibition on burning
fuel oil at Lake Catherine Unit 4 until SO2 and PM BART
determinations for the fuel oil firing scenario are approved into the
SIP by EPA; the SO2 BART requirements for White Bluff Units
1 and 2; the SO2 and PM BART requirements for the White
Bluff Auxiliary Boiler; the SO2 and NOX BART
requirements for the Domtar Ashdown Mill Power Boiler No. 1; and the
SO2, NOX, and PM BART requirements for the Domtar
Ashdown Mill Power Boiler No. 2. The Arkansas Regional Haze
SO2 and PM SIP revision addresses all these BART
requirements currently covered under the FIP, with the exception of the
requirements for the Domtar Ashdown Mill Power Boilers No. 1 and 2. As
noted above, in the Arkansas Regional Haze NOX SIP revision,
ADEQ erroneously stated that the Auxiliary Boiler participated in CSAPR
for ozone season NOX and the state decided to rely on
participation in that trading program to satisfy the Auxiliary Boiler's
NOX BART requirement. In a final action published in the
Federal Register on February 12, 2018, we took final action to approve
this SIP revision, including reliance on CSAPR for ozone season
NOX to satisfy the Auxiliary Boiler's NOX BART
requirement.\34\ Since the White Bluff Auxiliary Boiler does not
participate in CSAPR for ozone season NOX, we are proposing
to withdraw our prior approval of the NOX BART determination
for the Auxiliary Boiler and to replace it with our proposed approval
of a source specific NOX BART emission limit contained in
the August 8, 2018, Arkansas Regional Haze SIP revision. We discuss
this in greater detail in section II.B.5.b. of this proposed action.
---------------------------------------------------------------------------
\32\ 77 FR 14604.
\33\ 83 FR 5927.
\34\ 83 FR 5927.
---------------------------------------------------------------------------
1. AECC Bailey Unit 1
The AECC Bailey Unit 1 has a wall-fired boiler, a gross output of
122 MW, and a maximum heat input rate of 1,350 million British thermal
units per hour (MMBtu/hr). The unit is currently permitted to burn
pipeline quality natural gas and fuel oil. The fuel oil burned is
currently subject to a sulfur content limit of 2.3% by weight. AECC
produced BART analyses dated March 2014 for Bailey Unit 1, which were
evaluated by EPA and largely formed the basis for EPA's SO2
and PM BART evaluations in the FIP.\35\ The same BART analyses \36\
have now been adopted and incorporated by ADEQ into the Arkansas
Regional Haze SO2 and PM BART SIP revision to address the
SO2 and PM BART requirements for Bailey Unit 1.
---------------------------------------------------------------------------
\35\ 80 FR 18950.
\36\ ``BART Five Factor Analysis, Arkansas Electric Cooperative
Corporation Bailey and McClellan Generating Stations,'' dated March
2014, Version 4, prepared by Trinity Consultants Inc. in conjunction
with Arkansas Electric Cooperative Corporation,'' which can be found
in Appendix B to the Arkansas Regional Haze SO2 and PM
BART SIP Revision.
---------------------------------------------------------------------------
a. SO2 BART Analysis and Determination
In assessing SO2 BART, ADEQ explained that AECC
considered the five BART factors. In assessing feasible control
technologies and their effectiveness, AECC considered flue gas
desulfurization (FGD) systems and fuel switching during fuel oil
burning. Due to the intrinsically low sulfur content of natural gas, no
control technologies were evaluated for natural gas burning scenarios.
As such, the BART analysis focused on fuel oil firing as the base case.
For fuel oil firing, fuel switching was determined to be the only
technically feasible control option, and thus AECC did not further
consider FGD for SO2 BART. The baseline fuel AECC assumed in
the BART analysis is No. 6 fuel oil with 1.81% sulfur content by
weight, which is based on the average sulfur content of the fuel oil
from the most recent shipment received by the facility in December
2006. ADEQ explained that AECC evaluated switching to the following
fuel types: 1% sulfur No. 6 fuel oil, corresponding to an estimated 45%
control efficiency; 0.5% sulfur No. 6 fuel oil, corresponding to 72%
control efficiency; and 0.05% sulfur diesel, corresponding to 97%
control efficiency.\37\
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\37\ We also note that AECC evaluated switching to natural gas
as an available SO2 control option in its SO2
BART analysis, but the evaluation of this control option was not
discussed by ADEQ in the SIP revision. We discuss this issue in
greater detail below when we present our evaluation of the state's
BART determination.
---------------------------------------------------------------------------
In considering the costs of compliance for fuel switching, AECC
concluded that the fuel switching options evaluated would not require
capital investments in equipment, but instead the annual costs would be
based upon operation and maintenance costs associated with the
different fuel types. AECC estimated that the cost-effectiveness of
switching Bailey Unit 1 to No. 6 fuel oil with 1% and 0.5% sulfur
content by weight is $1,198/ton and $2,559/ton, respectively. Switching
to diesel, which has 0.05% sulfur content, is estimated to cost $5,382/
ton. ADEQ stated that the cost in dollars per ton for diesel is out of
the range of what is typically considered cost-effective, while the
cost of both 1% and 0.5% sulfur No. 6 fuel oil is estimated to be
within the range of what is typically considered cost-effective.
ADEQ stated that AECC's evaluation did not identify any energy or
non-air quality environmental impacts associated with switching to 1%
sulfur No. 6 fuel oil, 0.5% sulfur No. 6 fuel oil, or diesel. In
assessing the remaining useful life of Bailey Unit 1, AECC concluded
that this factor does not impact the annualized costs of the evaluated
control options since fuel switching is not expected to require any
significant capital costs in this case.
[[Page 62210]]
In assessing visibility impacts, the state's submittal included
CALPUFF modeling evaluating the visibility benefits of switching from
the baseline fuel oil (assuming 100% use of fuel oil) to the various
fuel switching options. We summarize the results of that modeling in
Table 1.
Table 1--Anticipated Visibility Benefit Due to Fuel Switching at AECC Bailey Unit 1
[CALPUFF, 98th percentile]
----------------------------------------------------------------------------------------------------------------
Visibility benefit of controls over baseline (dv)
Baseline -----------------------------------------------------
Class I area visibility No. 6 fuel oil-- No. 6 fuel oil-- Diesel-- 0.05%
impact (dv) 1% sulfur 0.5% sulfur sulfur
----------------------------------------------------------------------------------------------------------------
Caney Creek............................. 0.330 0.137 0.188 0.246
Upper Buffalo........................... 0.348 0.154 0.221 0.279
Hercules-Glades......................... 0.368 0.162 0.233 0.299
Mingo................................... 0.379 0.173 0.209 0.284
----------------------------------------------------------------------------------------------------------------
Switching to 1% sulfur No. 6 fuel oil is anticipated to achieve
visibility benefits of approximately 0.137 dv at Caney Creek, 0.154 dv
at Upper Buffalo, 0.162 dv at Hercules-Glades, and 0.173 dv at Mingo
over baseline visibility conditions. Switching to 0.5% sulfur No. 6
fuel oil is anticipated to achieve visibility benefits of approximately
0.188 dv at Caney Creek, 0.221 dv at Upper Buffalo, 0.233 dv at
Hercules-Glades, and 0.209 dv at Mingo over the baseline. The
visibility benefits of switching to diesel are anticipated to be even
greater, with benefits of approximately 0.246 dv at Caney Creek, 0.279
dv at Upper Buffalo, 0.299 dv at Hercules-Glades, and 0.284 dv at Mingo
over the baseline.
Taking into consideration the cost-effectiveness and the
anticipated visibility improvement of the fuel switching options, ADEQ
concurred with AECC's recommendation that SO2 BART for AECC
Bailey Unit 1 be determined to be the use of fuel with a sulfur content
by weight of 0.5% or less.
We note that switching to diesel would result in additional
reductions in SO2 emissions, but the additional costs per
ton for doing so would be high in comparison to the additional
visibility benefits. We also note that AECC evaluated switching to
natural gas as an available SO2 control option in its
SO2 BART analysis,\38\ but the evaluation of this control
option in the SO2 BART analysis was not discussed by ADEQ in
the SIP revision. In its analysis, AECC explained that switching to
natural gas may have an adverse energy impact during periods of natural
gas curtailment and that the ability to burn both fuel oil and natural
gas was important for the facility to maintain electrical
reliability.\39\ Therefore, AECC did not recommend switching to natural
gas and instead recommended switching to fuels with 0.5% sulfur content
to be SO2 BART for Bailey Unit 1.\40\ In the Arkansas
Regional Haze FIP, we agreed with AECC's recommendation, and explained
that the BART Guidelines provide that it is not our intent to direct
subject-to-BART sources to switch fuel forms, such as from coal or fuel
oil to natural gas (40 CFR part 51, Appendix Y, section IV.D.1).\41\ We
noted that since natural gas has a sulfur content by weight that is
well below 0.5%, the facility may elect to use this type of fuel to
comply with BART, but we did not require a switch to natural gas for
SO2 BART in the FIP.\42\ Therefore, we do not find that
ADEQ's lack of consideration of switching to natural gas as an
SO2 control option in the SO2 BART analysis for
Bailey Unit 1 changes the result of the BART analysis in this instance.
We are proposing to approve the state's determination that
SO2 BART for AECC Bailey Unit 1 is the use of fuel with a
sulfur content by weight of 0.5% or less. We are also proposing to
approve the state's determination that Bailey Unit 1 must comply with
this BART requirement no later than October 27, 2021, and that as of
the effective date of the Administrative Order, which is August 7,
2018, the source shall not purchase fuel that does not meet the sulfur
limit requirement for combustion at Bailey Unit 1. These BART
requirements have now been made enforceable by the state through an
Administrative Order that has been adopted and incorporated in the SIP
revision. The Administrative Order for AECC Bailey Unit 1 includes not
only the requirement to limit the sulfur content of the fuel burned,
but also requirements for the source to sample and analyze each
shipment of fuel to determine the sulfur content by weight and maintain
records pertaining to the sampling of each fuel shipment to assess
compliance with the BART requirements.\43\ We are proposing to approve
the state's Administrative Order, including the compliance
determination requirements contained in the Administrative Order, into
the SIP. The state's SO2 BART emission limit and compliance
date for Bailey Unit 1 are consistent with the BART decision EPA
previously made in the FIP we promulgated on September 27, 2016.\44\ We
are concurrently proposing to withdraw the FIP's SO2 BART
requirements for Bailey Unit 1, as they would be replaced by our
approval of the state's SO2 BART decision.
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\38\ See ``BART Five Factor Analysis, Arkansas Electric
Cooperative Corporation Bailey and McClellan Generating Stations,
dated March 2014, Version 4, prepared by Trinity Consultants Inc. in
conjunction with Arkansas Electric Cooperative Corporation,'' pages
5-1 to 5-14. This BART analysis has been adopted and incorporated by
ADEQ into the SIP revision (see Appendix B to the Arkansas Regional
Haze SO2 and PM BART SIP revision).
\39\ See ``BART Five Factor Analysis, Arkansas Electric
Cooperative Corporation Bailey and McClellan Generating Stations,
dated March 2014, Version 4, prepared by Trinity Consultants Inc. in
conjunction with Arkansas Electric Cooperative Corporation,'' pages
5-2, 5-10, and 5-14.
\40\ Id.
\41\ 80 FR 18952 and 81 FR at 66339.
\42\ Id.
\43\ The Administrative Order can be found in the Arkansas
Regional Haze SO2 and PM BART SIP Revision.
\44\ The Arkansas Regional Haze FIP requires Bailey Unit 1 to
only use fuel with a sulfur content limit of 0.5% by weight, with a
compliance date of October 27, 2021. Additionally, the FIP prohibits
the owner or operator of the unit from purchasing fuel for
combustion at the unit that does not meet the sulfur content limit;
the compliance date for this requirement is October 27, 2016. See 81
FR 66335, 66415-16.
---------------------------------------------------------------------------
b. PM BART Analysis and Determination
PM emissions are inherently low when burning natural gas, but are
higher when burning fuel oil. Bailey Unit 1 does not currently have
pollution control equipment for PM emissions. In assessing PM BART for
Bailey Unit 1, ADEQ explained that AECC considered the five BART
factors. In assessing feasible control technologies and their
[[Page 62211]]
effectiveness, AECC considered the following control technologies for
PM BART: Dry electrostatic precipitator (ESP), wet ESP, fabric filter,
wet scrubber, cyclone (i.e., mechanical collector), and fuel switching.
AECC's evaluation noted that the particulate matter from oil-fired
boilers tends to be sticky and small, affecting the collection
efficiency of dry ESPs and fabric filters. Dry ESPs operate by placing
a charge on the particles through a series of electrodes, and then
capturing the charged particles on collection plates, while fabric
filters work by filtering the PM in the flue gas through filter bags.
The collected particles are periodically removed from the filter bag
through a pulse jet or reverse flow mechanism. Because of the sticky
nature of particles from oil-fired boilers, AECC considered dry ESPs
and fabric filters to be technically infeasible for use at Bailey Unit
1. AECC found wet ESPs, wet scrubbers, cyclones, and fuel switching to
be technically feasible PM control options.
Residual fuel, such as the baseline No. 6 fuel oil burned at Bailey
Unit 1, has inherent ash that contributes to emissions of filterable
PM. Reductions in filterable PM emissions are directly related to the
sulfur content of the fuel.\45\ Therefore, switching to No. 6 fuel oil
with a lower sulfur content is expected to result in lower filterable
PM emissions. Also, ash content is much lower in a distillate fuel such
as diesel and essentially zero in natural gas. The fuel switching
options considered by AECC in the PM BART analysis are No. 6 fuel oil
with 1% sulfur content by weight, No. 6 fuel oil with 0.5% sulfur
content by weight, natural gas, and diesel. AECC estimated that
switching to a lower sulfur fuel has a PM control efficiency ranging
from approximately 44%-99%, depending on the fuel type. The estimated
PM control efficiency of each control option is summarized in Table 2.
---------------------------------------------------------------------------
\45\ See ``AP-42, Compilation of Air Pollutant Emission
Factors,'' section 1.3.3.1, and Table 1.3-1, available at https://www.epa.gov/ttnchie1/ap42/.
Table 2--PM Control Efficiency of BART Control Options for AECC Bailey Unit 1
----------------------------------------------------------------------------------------------------------------
Fuel switching
-------------------------------------------
Wet No. 6
PM control option scrubber Cyclone Wet ESP No. 6 fuel oil-- Natural
fuel oil-- 0.5% S gas Diesel
1% S
----------------------------------------------------------------------------------------------------------------
PM Control Efficiency.............. 55.0 85.0 90.0 65.7 89.3 99.0 99.5
(%)................................
----------------------------------------------------------------------------------------------------------------
In considering the costs of the PM control options, AECC noted that
add-on controls such as a wet scrubber, cyclone, and wet ESP involve
capital costs for new equipment, which AECC annualized over a 15-year
period in the analysis. Based on this analysis, AECC determined that
the estimated cost-effectiveness of the add-on control options are as
follows: $3,558,286/ton for a wet scrubber; $54,570/ton for a cyclone;
and $981,583/ton for a wet ESP. AECC determined that the estimated
cost-effectiveness of the fuel switching options are as follows:
$27,528/ton for No. 6 fuel oil with 1% sulfur content; $22,386/ton for
No. 6 fuel oil with 0.5% sulfur content; $25,004/ton for diesel; and
$2,327/ton for natural gas. AECC noted that it does not consider any of
the PM control options to be cost-effective.
ADEQ explained that AECC's PM BART evaluation did not discuss any
energy or non-air quality environmental impacts associated with fuel
switching. AECC did identify certain energy and non-air quality
environmental impacts associated with wet ESPs and wet scrubbers. These
impacts, which are factored in the cost of compliance, include
increased energy usage for operation of the control equipment, the
generation of wastewater streams that must be treated on-site or sent
to a waste water treatment plant, and the generation of a filter cake
that would likely require land-filling. In assessing the remaining
useful life of Bailey Unit 1, AECC concluded that this factor does not
impact the annualized costs of the evaluated control options since the
remaining useful life of Bailey Unit 1 is at least as long as the
capital cost recovery period of 15 years.
In assessing visibility impacts, the state's submittal included
CALPUFF modeling evaluating the visibility benefits of switching from
the baseline fuel oil (assuming 100% use of fuel oil) to the various
fuel switching options. We summarize the results of that modeling in
Table 3.
---------------------------------------------------------------------------
\46\ The modeled visibility improvement of the fuel switching
options reflects both SO2 and PM emissions reductions
since reductions in filterable PM are directly related to the sulfur
content of the fuel.
Table 3--Anticipated Visibility Benefit of PM Controls at AECC Bailey Unit 1
[CALPUFF, 98th percentile]
--------------------------------------------------------------------------------------------------------------------------------------------------------
Visibility benefit of controls over baseline (dv) \46\
Baseline ----------------------------------------------------------------------------
visibility No. 6 No. 6
Class I area impact Wet fuel oil-- fuel oil-- Diesel-- Natural
(dv) scrubber Cyclone Wet ESP 1% sulfur 0.5% 0.05% gas
sulfur sulfur
--------------------------------------------------------------------------------------------------------------------------------------------------------
Caney Creek.................................................... 0.330 0.002 0.002 0.003 0.137 0.188 0.246 0.247
Upper Buffalo.................................................. 0.347 0.002 0.002 0.004 0.154 0.221 0.279 0.276
Hercules-Glades................................................ 0.367 0.007 0.006 0.011 0.162 0.233 0.299 0.295
Mingo.......................................................... 0.378 0.004 0.004 0.007 0.173 0.209 0.284 0.277
--------------------------------------------------------------------------------------------------------------------------------------------------------
The anticipated visibility benefits of add-on controls (i.e., wet
scrubber, cyclone, and wet ESP) are anticipated to be very small,
ranging from 0.002 to 0.011 dv at each affected Class I area. As
discussed above, fuel switching to lower
[[Page 62212]]
sulfur fuels is expected to result in both lower filterable PM
emissions and lower SO2 emissions. Switching to 1% sulfur
No. 6 fuel oil is anticipated to achieve visibility benefits of
approximately 0.137 dv at Caney Creek, 0.154 dv at Upper Buffalo, 0.162
dv at Hercules-Glades, and 0.173 dv at Mingo over baseline visibility
conditions. Switching to 0.5% sulfur No. 6 fuel oil is anticipated to
achieve visibility benefits of approximately 0.188 dv at Caney Creek,
0.221 dv at Upper Buffalo, 0.233 dv at Hercules-Glades, and 0.209 dv at
Mingo over the baseline. The visibility benefits of switching to diesel
are anticipated to be even greater, with benefits of approximately
0.246 dv at Caney Creek, 0.279 dv at Upper Buffalo, 0.299 dv at
Hercules-Glades, and 0.284 dv at Mingo over the baseline. The
visibility benefits of switching to natural gas are anticipated to be
only slightly more than switching to diesel. The modeled visibility
improvement of switching to lower sulfur fuels reflects benefits of
both SO2 and PM emissions reductions since reductions in
filterable PM are directly related to the sulfur content of the fuel.
We do note that the majority of the baseline visibility impact at each
Class I area when burning the baseline fuel oil is due to
SO2 emissions that form sulfate PM, while direct
PM10 emissions contribute only a small portion of the
baseline visibility impacts at each Class I area.\47\ Accordingly, the
majority of the visibility improvement associated with switching to
lower sulfur fuels, as shown in Table 3, can reasonably be expected to
be the result of a reduction in SO2 emissions rather than PM
emissions.
---------------------------------------------------------------------------
\47\ See Table 4-3 BASELINE VISIBILITY IMPAIRMENT ATTRIBUTABLE
TO BAILEY, UNIT 1 (2001-2003)--FUEL OIL, ``BART Five Factor
Analysis, Arkansas Electric Cooperative Corporation Bailey and
McClellan Generating Stations,'' dated March 2014, Version 4,
prepared by Trinity Consultants Inc. in conjunction with Arkansas
Electric Cooperative Corporation,'' which can be found in Appendix B
to the Arkansas Regional Haze SO2 and PM BART SIP
Revision.
---------------------------------------------------------------------------
Taking into consideration the cost-effectiveness and the
anticipated visibility improvement of the PM control options
considered, ADEQ concluded that add-on controls are not cost-effective,
with AECC estimating the cost of these controls to be approximately
$55,000/ton and greater. ADEQ concluded that the cost of switching to
lower sulfur fuels is also not a cost-effective method for reducing PM
emissions. However, ADEQ noted that the SO2 BART
determination for Bailey Unit 1, which is the use of fuel that has 0.5%
or less sulfur content by weight, would also result in PM emissions
reductions. ADEQ therefore arrived at the determination that PM BART
for Bailey Unit 1 is no additional control beyond switching to fuel
with 0.5% or less sulfur content, consistent with the SO2
BART decision for the unit.
We do not agree with the use of a 15-year capital cost recovery
period for calculating the average cost-effectiveness of a wet ESP, wet
scrubber, and cyclone. Per the EPA Control Cost Manual, facilities are
to rely on a 30-year capital cost recovery period for calculating the
average cost-effectiveness of a wet ESP, wet scrubber, or cyclone
barring a technical rationale to deviate from the 30-year capital cost
recovery period. AECC Bailey Generating Station did not provide a
technical rationale to deviate from the assumed 30-year capital cost
recovery period. In addition, we are not aware of any enforceable
shutdown date for the AECC Bailey Generating Station, nor did AECC's
evaluation or ADEQ's SIP revision indicate any future planned shutdown
or provide any reason for adopting a 15-year equipment life for the
controls under consideration. Therefore, we believe that assuming a 30-
year equipment life rather than a 15-year equipment life would be more
appropriate for these control technologies.\48\ Extending the
amortization period from 15 to 30 years has the effect of decreasing
the total annual cost of each control option, thereby improving the
average cost-effectiveness value of controls (i.e., lower dollars per
ton removed). As discussed above, the cost of add-on PM control
equipment at Bailey Unit 1, assuming a 15-year remaining useful life,
ranges from $54,570/ton of PM removed for a cyclone to $3,558,286/ton
of PM removed for a wet scrubber. Even though adjusting the costs of
the add-on controls based on a 30-year remaining useful life as opposed
to a 15-year remaining useful life would decrease the $/ton costs, we
anticipate that the costs in $/ton would still be considerable and well
outside of the range that has generally been considered to be cost-
effective for BART. Therefore, we believe that add-on PM controls would
still not be justified in light of the considerable costs and the
minimal visibility benefits, which would range from 0.002 to 0.011 at
each Class I area (see Table 3 above). Therefore, we are proposing to
agree with ADEQ's determination that PM add-on controls are not PM BART
for Bailey Unit 1.
---------------------------------------------------------------------------
\48\ The Arkansas Regional Haze FIP assumed a 30-year equipment
life in the PM BART analysis for AECC Bailey Unit 1. See 80 FR
18955.
---------------------------------------------------------------------------
We also disagree with the total annual cost and cost-effectiveness
values for fuel switching presented in AECC's PM BART analysis \49\ and
in the SIP revision. In AECC's SO2 BART cost analysis for
the same unit, the company considered the same fuel switching options,
yet the total annual cost numbers presented in the PM cost analysis are
significantly greater than those presented in the SO2 cost
analysis.\50\ This appears to be because in the SO2 cost
analysis, AECC calculated the differential cost of fuel switching
(i.e., the difference in cost between the baseline fuel and the fuel
switching options), whereas the absolute cost of the fuel switching
options was calculated in the PM cost analysis. We believe that AECC
and ADEQ should have considered the differential cost of fuel switching
as opposed to the absolute cost of fuel for each of the fuel switching
options in the PM BART analysis, as was done in the SO2 BART
analysis. Thus, we believe that the correct cost effectiveness values
that ADEQ should have considered in the PM BART analysis are those
presented in Table 5-9 of AECC's SO2 BART analysis,\51\
which shows that the costs of switching to fuel oil with a sulfur
content of 1% or 0.5% are within the range that have generally been
considered to be cost-effective for BART. Although switching to diesel
would result in additional reductions in PM emissions, we believe that
the additional cost per ton for switching to diesel would be high in
comparison to the additional visibility benefits.\52\ We
[[Page 62213]]
believe that switching to fuel with 0.5% or less sulfur content is
within the range that has generally been considered to be cost-
effective for BART and since the source will have to comply with that
same requirement for SO2 BART, we consider it appropriate to
require it under PM BART as well. Therefore, we are proposing to
approve ADEQ's determination that PM BART for AECC Bailey Unit 1 is no
additional control beyond switching to fuel with 0.5% or less sulfur
content by October 27, 2021. Additionally, the owner or operator of the
unit shall not purchase fuel for combustion at the unit that does not
meet this sulfur content limit as of the effective date of the
Administrative Order, which is August 7, 2018. This BART determination
has now been made enforceable by the state through an Administrative
Order that has been adopted and incorporated in the SIP revision. We
are proposing to approve into the SIP the state's Administrative Order
with respect to the PM BART requirements for AECC Bailey Unit 1.\53\
---------------------------------------------------------------------------
\49\ See ``BART Five Factor Analysis, Arkansas Electric
Cooperative Corporation Bailey and McClellan Generating Stations,''
dated March 2014, Version 4, prepared by Trinity Consultants Inc. in
conjunction with Arkansas Electric Cooperative Corporation,'' Table
7-4, page 7-6. This BART analysis can be found in Appendix B to the
Arkansas Regional Haze SO2 and PM BART SIP Revision.
\50\ See ``BART Five Factor Analysis, Arkansas Electric
Cooperative Corporation Bailey and McClellan Generating Stations,''
dated March 2014, Version 4, prepared by Trinity Consultants Inc. in
conjunction with Arkansas Electric Cooperative Corporation,'' Table
5-9, page 5-9.
\51\ See ``BART Five Factor Analysis, Arkansas Electric
Cooperative Corporation Bailey and McClellan Generating Stations,''
dated March 2014, Version 4, prepared by Trinity Consultants Inc. in
conjunction with Arkansas Electric Cooperative Corporation,'' Table
5-9, column titled ``PM10 Cost Effectiveness,'' page 5-9.
\52\ Based on Table 5-13 from AECC's SO2 BART
analysis, switching to diesel would result in an additional
visibility benefit of 0.111 dv compared to switching to 1% No. 6
fuel oil, and in an additional visibility benefit of only 0.075 dv
compared to switching to 0.5% No. 6 fuel oil at Mingo, which is the
Class I area with the greatest visibility impacts from Bailey Unit
1. Based on Table 5-9 from AECC's SO2 BART analysis, the
corrected cost of switching to 1% and 0.5% No. 6 fuel oil is
estimated to be $1,165/ton of PM removed and $2,998/ton of PM
removed (respectively), while the corrected cost of diesel is
estimated to be $7,608/ton of PM removed. We do not consider the
additional cost of switching to diesel at Bailey Unit 1 to be
warranted by the additional level of anticipated visibility benefit.
\53\ The Administrative Order can be found in the Arkansas
Regional Haze SO2 and PM BART SIP Revision.
---------------------------------------------------------------------------
The state's PM BART decision for Bailey Unit 1 is consistent with
the BART decision EPA previously made in the FIP we promulgated on
September 27, 2016.\54\ We are concurrently proposing to withdraw the
FIP's PM BART requirements for Bailey Unit 1, as they would be replaced
by our approval of the state's PM BART decision.
---------------------------------------------------------------------------
\54\ The Arkansas Regional Haze FIP required Bailey Unit 1 to
only use fuel with a sulfur content limit of 0.5% by weight, with a
compliance date of October 27, 2021. Additionally, the FIP
prohibited the owner or operator of the unit from purchasing fuel
for combustion at the unit that does not meet the sulfur content
limit; the compliance date for this requirement was October 27,
2016. See 81 FR 66335 and 66415-16.
---------------------------------------------------------------------------
2. AECC McClellan Unit 1
The AECC McClellan Unit 1 has a wall-fired boiler, a gross output
of 122 MW and a maximum heat input rate of 1,436 MMBtu/hr. The unit is
currently permitted to burn pipeline quality natural gas and fuel oil.
The fuel oil burned is currently subject to a sulfur content limit of
2.8% by weight. AECC produced BART analyses dated March 2014 for
McClellan Unit 1, which were evaluated by EPA and largely formed the
basis for EPA's SO2 and PM BART evaluations in the FIP.\55\
The same BART analyses \56\ have now been adopted and incorporated by
ADEQ into the Arkansas Regional Haze SO2 and PM BART SIP
revision to address the SO2 and PM BART requirements for
McClellan Unit 1.
---------------------------------------------------------------------------
\55\ 80 FR 18957.
\56\ ``BART Five Factor Analysis, Arkansas Electric Cooperative
Corporation Bailey and McClellan Generating Stations,'' dated March
2014, Version 4, prepared by Trinity Consultants Inc. in conjunction
with Arkansas Electric Cooperative Corporation,'' which can be found
in Appendix B to the Arkansas Regional Haze SO2 and PM
BART SIP Revision.
---------------------------------------------------------------------------
a. SO2 BART Analysis and Determination
In assessing SO2 BART, ADEQ explained that AECC
considered the five BART factors. In assessing feasible control
technologies and their effectiveness, AECC considered FGD systems and
fuel switching during fuel oil burning. Due to the intrinsically low
sulfur content of natural gas, no control technologies were evaluated
for natural gas burning scenarios. As such, the BART analysis focused
on fuel oil firing as the base case. For fuel oil firing, fuel
switching was determined to be the only technically feasible control
option, and thus AECC did not further consider FGD for SO2
BART. The baseline fuel AECC assumed in the BART analysis is No. 6 fuel
oil with 1.38% sulfur content by weight, which is based on the average
sulfur content of the fuel oil from the most recent shipment received
by the facility in April 2009. ADEQ explained that AECC evaluated
switching to the following fuel types: 1% Sulfur No. 6 fuel oil,
corresponding to an estimated 28% control efficiency; 0.5% sulfur No. 6
fuel oil, corresponding to 64% control efficiency; and 0.05% sulfur
diesel, corresponding to 96% control efficiency.\57\
---------------------------------------------------------------------------
\57\ We also note that AECC evaluated switching to natural gas
as an available SO2 control option in its SO2
BART analysis, but the evaluation of this control option was not
discussed by ADEQ in the SIP revision. We discuss this issue in
greater detail below when we present our evaluation of the state's
BART determination.
---------------------------------------------------------------------------
In considering the costs of compliance for fuel switching, AECC
concluded that the fuel switching options evaluated would not require
capital investments in equipment, but instead the annual costs would be
based upon operation and maintenance costs associated with the
different fuel types. AECC estimated that the cost-effectiveness of
switching McClellan Unit 1 to No. 6 fuel oil with 1% and 0.5% sulfur
content by weight is $2,613/ton and $3,823/ton, respectively. Switching
to diesel, which has 0.05% sulfur content, is estimated to cost $7,145/
ton. ADEQ stated that the cost in dollars per ton for diesel is out of
the range of what is typically considered cost-effective, while the
cost of both 1% and 0.5% sulfur No. 6 fuel oil is estimated to be
within the range of what is typically considered cost-effective.
ADEQ stated that AECC's evaluation did not identify any energy or
non-air quality environmental impacts associated with switching to 1%
sulfur No. 6 fuel oil, 0.5% sulfur No. 6 fuel oil, or diesel. In
assessing the remaining useful life of McClellan Unit 1, AECC concluded
that this factor does not impact the annualized costs of the evaluated
control options since fuel switching is not expected to require any
significant capital costs in this case.
In assessing visibility impacts, the state's submittal included
CALPUFF modeling evaluating the visibility benefits of switching from
the baseline fuel (assuming 100% use of fuel oil) to the various fuel
switching options. We summarize the results of that modeling in Table
4.
Table 4--Anticipated Visibility Benefit Due to Fuel Switching at AECC McClellan Unit 1
[CALPUFF, 98th percentile]
----------------------------------------------------------------------------------------------------------------
Visibility benefit of controls over baseline
(dv)
Baseline -----------------------------------------------
Class I area visibility No. 6 fuel
impact (dv) No. 6 fuel oil--0.5% Diesel--0.05%
oil--1% sulfur sulfur sulfur
----------------------------------------------------------------------------------------------------------------
Caney Creek..................................... 0.622 0.085 0.300 0.448
Upper Buffalo................................... 0.266 0.035 0.120 0.193
Hercules-Glades................................. 0.231 0.029 0.116 0.169
[[Page 62214]]
Mingo........................................... 0.228 0.035 0.092 0.148
----------------------------------------------------------------------------------------------------------------
Switching to 1% sulfur No. 6 fuel oil is anticipated to achieve
visibility benefits of approximately 0.085 dv at Caney Creek, 0.035 dv
at Upper Buffalo, 0.029 dv at Hercules-Glades, and 0.035 dv at Mingo
over baseline visibility conditions. Switching to 0.5% sulfur No. 6
fuel oil is anticipated to achieve visibility benefits of approximately
0.300 dv at Caney Creek, 0.120 dv at Upper Buffalo, 0.116 dv at
Hercules-Glades, and 0.092 dv at Mingo over the baseline. The
visibility benefits of switching to diesel are anticipated to be even
greater, with benefits of approximately 0.448 dv at Caney Creek, 0.193
dv at Upper Buffalo, 0.169 dv at Hercules-Glades, and 0.148 dv at Mingo
over the baseline.
Taking into consideration the cost-effectiveness and the
anticipated visibility improvement of the fuel switching options, ADEQ
concurred with AECC's recommendation that SO2 BART for AECC
McClellan Unit 1 be determined to be the use of fuel with a sulfur
content by weight of 0.5% or less.
We note that switching to diesel would result in additional
reductions in SO2 emissions, but the additional costs per
ton for doing so would be high in comparison to the additional
visibility benefits. We also note that AECC evaluated switching to
natural gas as an available SO2 control option in its
SO2 BART analysis,\58\ but the evaluation of this control
option in the SO2 BART analysis was not discussed by ADEQ in
the SIP revision. In its analysis, AECC explained that switching to
natural gas may have an adverse energy impact during periods of natural
gas curtailment and that the ability to burn both fuel oil and natural
gas was important for the facility to maintain electrical
reliability.\59\ Therefore, AECC did not recommend switching to natural
gas and instead recommended switching to fuels with 0.5% sulfur content
to be SO2 BART for McClellan Unit 1.\60\ In the Arkansas
Regional Haze FIP, we agreed with AECC's recommendation, and explained
that the BART Guidelines provide that it is not our intent to direct
subject-to-BART sources to switch fuel forms, such as from coal or fuel
oil to natural gas (40 CFR part 51, Appendix Y, section IV.D.1).\61\ We
noted that since natural gas has a sulfur content by weight that is
well below 0.5%, the facility may elect to use this type of fuel to
comply with BART, but we did not require a switch to natural gas for
SO2 BART in the FIP.\62\ Therefore, we do not find that
ADEQ's lack of consideration of switching to natural gas as an
SO2 control option in the SO2 BART analysis for
McClellan Unit 1 changes the result of the BART analysis in this
instance. We are proposing to approve the state's determination that
SO2 BART for McClellan Unit 1 is the use of fuel with a
sulfur content by weight of 0.5% or less. We are also proposing to
approve the state's determination that McClellan Unit 1 must comply
with this BART requirement no later than October 27, 2021, and that as
of the effective date of the Administrative Order, which is August 7,
2018, the source shall not purchase fuel that does not meet the sulfur
limit requirement for combustion at McClellan Unit 1. These BART
requirements have now been made enforceable by the state through an
Administrative Order that has been adopted and incorporated in the SIP
revision. The Administrative Order for AECC McClellan Unit 1 includes
not only the requirement to limit the sulfur content of the fuel
burned, but also requirements for the source to sample and analyze each
shipment of fuel to determine the sulfur content by weight and maintain
records pertaining to the sampling of each fuel shipment to assess
compliance with the BART requirements.\63\ We are proposing to approve
the state's Administrative Order, including the compliance
determination requirements contained in the Administrative Order, into
the SIP. The state's SO2 BART emission limit and compliance
date for McClellan Unit 1 are consistent with the BART decision EPA
previously made in the FIP we promulgated on September 27, 2016.\64\ We
are concurrently proposing to withdraw the FIP's SO2 BART
requirements for McClellan Unit 1, as they would be replaced by our
approval of the state's SO2 BART decision.
---------------------------------------------------------------------------
\58\ See ``BART Five Factor Analysis, Arkansas Electric
Cooperative Corporation Bailey and McClellan Generating Stations,
dated March 2014, Version 4, prepared by Trinity Consultants Inc. in
conjunction with Arkansas Electric Cooperative Corporation,'' pages
5-1 to 5-14. This BART analysis has been adopted and incorporated by
ADEQ into the SIP revision (see Appendix B to the Arkansas Regional
Haze SO2 and PM BART SIP revision).
\59\ See ``BART Five Factor Analysis, Arkansas Electric
Cooperative Corporation Bailey and McClellan Generating Stations,
dated March 2014, Version 4, prepared by Trinity Consultants Inc. in
conjunction with Arkansas Electric Cooperative Corporation,'' pages
5-2, 5-10, and 5-14.
\60\ Id.
\61\ See 80 FR at 18959 and 81 FR at 66340.
\62\ Id.
\63\ The Administrative Order can be found in the Arkansas
Regional Haze SO2 and PM BART SIP Revision.
\64\ The Arkansas Regional Haze FIP requires McClellan Unit 1 to
only use fuel with a sulfur content limit of 0.5% by weight, with a
compliance date of October 27, 2021. Additionally, the FIP prohibits
the owner or operator of the unit from purchasing fuel for
combustion at the unit that does not meet the sulfur content limit;
the compliance date for this requirement is October 27, 2016. See 81
FR 66335 and 66415-16.
---------------------------------------------------------------------------
b. PM BART Analysis and Determination
PM emissions are inherently low when burning natural gas, but are
higher when burning fuel oil. McClellan Unit 1 does not currently have
pollution control equipment for PM emissions. In assessing PM BART for
McClellan Unit 1, ADEQ explained that AECC considered the five BART
factors. In assessing feasible control technologies and their
effectiveness, AECC considered the following control technologies for
PM BART: Dry ESP, wet ESP, fabric filter, wet scrubber, cyclone, and
fuel switching. AECC's evaluation noted that the particulate matter
from oil-fired boilers tends to be sticky and small, affecting the
collection efficiency of dry ESPs and fabric filters. Dry ESPs operate
by placing a charge on the particles through a series of electrodes,
and then capturing the charged particles on collection plates,
[[Page 62215]]
while fabric filters work by filtering the PM in the flue gas through
filter bags. The collected particles are periodically removed from the
filter bag through a pulse jet or reverse flow mechanism. Because of
the sticky nature of particles from oil-fired boilers, AECC considered
dry ESPs and fabric filters to be technically infeasible for use at
McClellan Unit 1. AECC found wet ESPs, wet scrubbers, cyclones, and
fuel switching to be technically feasible PM control options.
Residual fuel, such as the baseline No. 6 fuel oil burned at
McClellan Unit 1, has inherent ash that contributes to emissions of
filterable PM. Reductions in filterable PM emissions are directly
related to the sulfur content of the fuel. Therefore, switching to No.
6 fuel oil with a lower sulfur content is expected to result in lower
filterable PM emissions. Also, ash content is much lower in a
distillate fuel such as diesel and essentially zero in natural gas. The
fuel switching options considered by AECC in the BART analysis are No.
6 fuel oil with 1% sulfur content by weight, No. 6 fuel oil with 0.5%
sulfur content by weight, natural gas, and diesel. AECC estimated that
switching to a lower sulfur fuel has a PM control efficiency ranging
from approximately 44%-99%, depending on the fuel type. The estimated
PM control efficiency of each control option is summarized in Table 5.
Table 5--PM Control Efficiency of BART Control Options for AECC McClellan Unit 1
----------------------------------------------------------------------------------------------------------------
Fuel switching
-----------------------------------------------
PM control option Wet Cyclone Wet ESP No. 6 fuel
scrubber No. 6 fuel oil--0.5% Natural Diesel
oil--1% S S gas
----------------------------------------------------------------------------------------------------------------
PM Control Efficiency (%)... 55.0 85.0 90.0 43.6 82.4 99.0 99.2
----------------------------------------------------------------------------------------------------------------
In considering the costs of the PM control options, AECC noted that
add-on controls such as the wet scrubber, cyclone, and wet ESP involve
capital costs for new equipment, which AECC annualized over a 15-year
period in the analysis. Based on this analysis, AECC determined that
the estimated cost-effectiveness of the add-on control options are as
follows: $695,549/ton for a wet scrubber; $14,882/ton for a cyclone;
and $266,237/ton for a wet ESP. AECC determined that the estimated
cost-effectiveness of the fuel switching options are as follows:
$53,044/ton for No. 6 fuel oil with 1% sulfur content; $31,338/ton for
No. 6 fuel oil with 0.5% sulfur content; $32,952/ton for diesel; and
$571/ton for natural gas. AECC noted that it does not consider any of
the PM control options to be cost-effective.
ADEQ explained that AECC's PM BART evaluation did not discuss any
energy or non-air quality environmental impacts associated with fuel
switching. AECC did identify certain energy and non-air quality
environmental impacts associated with wet ESPs and wet scrubbers. These
impacts, which are factored in the cost of compliance, include
increased energy usage for operation of the control equipment, the
generation of wastewater streams that must be treated on-site or sent
to a waste water treatment plant, and the generation of a filter cake
that would likely require land-filling. In assessing the remaining
useful life of McClellan Unit 1, AECC concluded that this factor does
not impact the annualized costs of the evaluated control options since
the remaining useful life of McClellan Unit 1 is at least as long as
the capital cost recovery period of 15 years.
In assessing visibility impacts, the state's submittal included
CALPUFF modeling evaluating the visibility benefits of switching from
the baseline fuel oil (assuming 100% use of fuel oil) to the various
fuel switching options. We summarize the results of that modeling in
Table 6.
Table 6--Anticipated Visibility Benefit of PM Controls at AECC McClellan Unit 1
[CALPUFF, 98th percentile]
--------------------------------------------------------------------------------------------------------------------------------------------------------
Visibility benefit of controls over baseline (dv) \65\
Baseline --------------------------------------------------------------------------------
visibility No. 6 No. 6
Class I area impact Wet fuel oil-- fuel oil-- Diesel--0.05% Natural
(dv) scrubber Cyclone Wet ESP 1% sulfur 0.5% sulfur gas
sulfur
--------------------------------------------------------------------------------------------------------------------------------------------------------
Caney Creek................................................ 0.621 0.002 0.002 0.004 0.085 0.300 0.448 0.497
Upper Buffalo.............................................. 0.266 0.002 0.001 0.003 0.035 0.120 0.193 0.214
Hercules-Glades............................................ 0.230 0.002 0.001 0.003 0.029 0.116 0.169 0.191
Mingo...................................................... 0.227 0.003 0.002 0.004 0.035 0.092 0.148 0.17
--------------------------------------------------------------------------------------------------------------------------------------------------------
The anticipated visibility benefits of add-on controls (i.e., wet
scrubber, cyclone, and wet ESP) are very small, ranging from 0.001 to
0.004 dv at each affected Class I area. As discussed above, fuel
switching to lower sulfur fuels is expected to result in both lower
filterable PM emissions and lower SO2 emissions. Switching
to 1% sulfur No. 6 fuel oil is anticipated to achieve visibility
benefits of approximately 0.085 dv at Caney Creek, 0.035 dv at Upper
Buffalo, 0.029 dv at Hercules-Glades, and 0.035 dv at Mingo over
baseline visibility conditions. Switching to 0.5% sulfur No. 6 fuel oil
is anticipated to achieve visibility benefits of approximately 0.3 dv
at Caney Creek, 0.12 dv at Upper Buffalo, 0.116 dv at Hercules-Glades,
and 0.092 dv at Mingo over the baseline. The visibility benefits of
switching to diesel are anticipated to be even greater, with benefits
of approximately 0.448 dv at Caney Creek, 0.193 dv at Upper Buffalo,
0.169 dv at
[[Page 62216]]
Hercules-Glades, and 0.148 dv at Mingo over the baseline. The
visibility benefits of switching to natural gas are anticipated to be
only slightly more than switching to diesel. The modeled visibility
improvement of switching to lower sulfur fuels reflects benefits of
both SO2 and PM emissions reductions since reductions in
filterable PM are directly related to the sulfur content of the fuel.
We do note that the majority of the baseline visibility impact at each
Class I area when burning the baseline fuel oil is due to
SO2 emissions that form sulfate PM, while direct
PM10 emissions contribute only a small portion of the
baseline visibility impacts at each Class I area.\66\ Accordingly, the
majority of the visibility improvement associated with switching to
lower sulfur fuels, as shown in Table 6, can reasonably be expected to
be the result of a reduction in SO2 emissions rather than PM
emissions.
---------------------------------------------------------------------------
\65\ The modeled visibility improvement of the fuel switching
options reflects both SO2 and PM emissions reductions
since reductions in filterable PM are directly related to the sulfur
content of the fuel.
\66\ See Table 4-5 BASELINE VISIBILITY IMPAIRMENT ATTRIBUTABLE
TO McCLELLAN, UNIT 1 (2001-2003)--FUEL OIL, ``BART Five Factor
Analysis, Arkansas Electric Cooperative Corporation Bailey and
McClellan Generating Stations,'' dated March 2014, Version 4,
prepared by Trinity Consultants Inc. in conjunction with Arkansas
Electric Cooperative Corporation,'' which can be found in Appendix B
to the Arkansas Regional Haze SO2 and PM BART SIP
Revision.
---------------------------------------------------------------------------
Taking into consideration the cost-effectiveness and the
anticipated visibility improvement of the PM control options
considered, ADEQ concluded that add-on controls are not cost-effective,
with AECC estimating the cost of these controls to be approximately
$15,000/ton and greater. ADEQ concluded that the cost of switching to
lower sulfur fuels is also not a cost-effective method for reducing PM
emissions. However, ADEQ noted that the SO2 BART
determination for McClellan Unit 1, which is the use of fuel that has
0.5% or less sulfur content by weight, would also result in PM
emissions reductions. ADEQ therefore arrived at the determination that
PM BART for McClellan Unit 1 is no additional control beyond switching
to fuel with 0.5% or less sulfur content, consistent with the
SO2 BART decision for the unit.
We do not agree with the use of a 15-year capital cost recovery
period for calculating the average cost-effectiveness of a wet ESP, wet
scrubber, and cyclone. Per the EPA Control Cost Manual, facilities are
to rely on a 30-year capital cost recovery period for calculating the
average cost-effectiveness of a wet ESP, wet scrubber, or cyclone
barring a technical rationale to deviate from the 30-year capital cost
recovery period. AECC Bailey Generating Station did not provide a
technical rationale to deviate from the assumed 30-year capital cost
recovery period. In addition, we are not aware of any enforceable
shutdown date for the AECC McClellan Generating Station, nor did AECC's
evaluation or ADEQ's SIP revision indicate any future planned shutdown
or provide any reason for adopting a 15-year equipment life for the
controls under consideration. Therefore, we believe that assuming a 30-
year equipment life rather than a 15-year equipment life would be more
appropriate for these control technologies.\67\ Extending the
amortization period from 15 to 30 years has the effect of decreasing
the total annual cost of each control option, thereby improving the
average cost-effectiveness value of controls (i.e., lower dollars per
ton removed). As discussed above, the cost of add-on PM control
equipment at McClellan Unit 1, assuming a 15-year remaining useful
life, ranges from $14,882/ton of PM removed for a cyclone to $695,549/
ton of PM removed for a wet scrubber. Even though adjusting the costs
of the add-on controls based on a 30-year remaining useful life as
opposed to a 15-year remaining useful life would decrease the $/ton
costs, we anticipate that the costs in $/ton would still be
considerable and well outside of the range that has generally been
considered to be cost-effective for BART. Therefore, we believe that
add-on PM controls would still not be justified in light of the
considerable costs and the minimal visibility benefits, which would
range from 0.001 to 0.004 at each Class I area (see Table 6 above).
Therefore, we are proposing to agree with ADEQ's determination that PM
add-on controls are not PM BART for McClellan Unit 1.
---------------------------------------------------------------------------
\67\ The Arkansas Regional Haze FIP assumed a 30-year equipment
life in the PM BART analysis for AECC McClellan Unit 1. See 80 FR
18962.
---------------------------------------------------------------------------
We also disagree with the total annual cost and cost-effectiveness
values for fuel switching presented in AECC's PM BART analysis \68\ and
in the SIP revision. In AECC's SO2 BART cost analysis for
the same unit, the company considered the same fuel switching options,
yet the total annual cost numbers presented in the PM cost analysis are
significantly greater than those presented in the SO2 cost
analysis.\69\ This appears to be because in the SO2 cost
analysis, AECC calculated the differential cost of fuel switching
(i.e., the difference in cost between the baseline fuel and the fuel
switching options), whereas the absolute cost of the fuel switching
options was calculated in the PM cost analysis. We believe that AECC
and ADEQ should have considered the differential cost of fuel switching
as opposed to the absolute cost of fuel for each of the fuel switching
options in the PM BART analysis, as was done in the SO2 BART
analysis. Thus, we believe that the correct cost effectiveness values
that ADEQ should have considered in the PM BART analysis are those
presented in Table 5-10 of AECC's SO2 BART analysis,\70\
which shows that the costs of switching to fuel oil with a sulfur
content of 1% or 0.5% are within the range that have generally been
considered to be cost effective for BART. Although switching to diesel
would result in additional reductions in PM emissions, we believe that
the additional cost per ton for switching to diesel would be high in
comparison to the additional visibility benefits.\71\ We believe that
switching to fuel with 0.5% or less sulfur content is within the range
that has generally been considered to be cost-effective for BART and
since the source will have to comply with that same requirement for
SO2 BART, we consider it appropriate to require it under PM
BART as well. Therefore, we are proposing to approve ADEQ's
determination that PM BART for AECC McClellan Unit 1 is no additional
control beyond switching to fuel with 0.5% or less sulfur content by
October 27, 2021. Additionally, the owner or
[[Page 62217]]
operator of the unit shall not purchase fuel for combustion at the unit
that does not meet this sulfur content limit as of the effective date
of the Administrative Order, which is August 7, 2018. This BART
determination has now been made enforceable by the state through an
Administrative Order that has been adopted and incorporated in the SIP
revision. We are proposing to approve into the SIP the state's
Administrative Order with respect to the PM BART requirements for AECC
McClellan Unit 1.\72\
---------------------------------------------------------------------------
\68\ See ``BART Five Factor Analysis, Arkansas Electric
Cooperative Corporation Bailey and McClellan Generating Stations,''
dated March 2014, Version 4, prepared by Trinity Consultants Inc. in
conjunction with Arkansas Electric Cooperative Corporation,'' Table
7-5, page 7-6. This BART analysis can be found in Appendix B to the
Arkansas Regional Haze SO2 and PM BART SIP Revision.
\69\ See ``BART Five Factor Analysis, Arkansas Electric
Cooperative Corporation Bailey and McClellan Generating Stations,''
dated March 2014, Version 4, prepared by Trinity Consultants Inc. in
conjunction with Arkansas Electric Cooperative Corporation,'' Table
5-10, page 5-9.
\70\ See ``BART Five Factor Analysis, Arkansas Electric
Cooperative Corporation Bailey and McClellan Generating Stations,''
dated March 2014, Version 4, prepared by Trinity Consultants Inc. in
conjunction with Arkansas Electric Cooperative Corporation,'' Table
5-10, column titled ``PM10 Cost Effectiveness,'' page 5-
9.
\71\ Based on Table 5-14 from AECC's SO2 BART
analysis, switching to diesel would result in an additional
visibility benefit of 0.363 dv compared to switching to 1% No. 6
fuel oil and in an additional visibility benefit of only 0.148 dv
compared to switching to 0.5% No. 6 fuel oil at Caney Creek, which
is the Class I area with the greatest visibility impacts from
McClellan Unit 1. Based on Table 5-10 from AECC's SO2
BART analysis, the corrected costs of switching to 1% and 0.5% No. 6
fuel oil is estimated to be $2,457/ton of PM removed and $4,553/ton
of PM removed (respectively), while the corrected cost of switching
to diesel is estimated to be $10,698/ton of PM removed. We do not
consider the additional cost of switching to diesel at McClellan
Unit 1 to be warranted by the additional level of anticipated
visibility benefit.
\72\ The Administrative Order can be found in the Arkansas
Regional Haze SO2 and PM BART SIP Revision.
---------------------------------------------------------------------------
The state's PM BART decision for McClellan Unit 1 is consistent
with the BART decision EPA previously made in the FIP we promulgated on
September 27, 2016.\73\ We are concurrently proposing to withdraw the
FIP's PM BART requirements for McClellan Unit 1, as they would be
replaced by our approval of the state's PM BART decision.
---------------------------------------------------------------------------
\73\ The Arkansas Regional Haze FIP required McClellan Unit 1 to
only use fuel with a sulfur content limit of 0.5% by weight, with a
compliance date of October 27, 2021. Additionally, the FIP
prohibited the owner or operator of the unit from purchasing fuel
for combustion at the unit that does not meet the sulfur content
limit; the compliance date for this requirement was October 27,
2016. See 81 FR 66335 and 66415-16.
---------------------------------------------------------------------------
3. SWEPCO Flint Creek Plant Boiler No. 1
SWEPCO Flint Creek Plant Boiler No. 1 has a 558 MW dry bottom wall-
fired boiler that commenced operation in 1978, has a maximum heat input
of 6,324 MMBtu/hr, and burns low sulfur western coal as a primary fuel,
but is also permitted to combust fuel oil and tire-derived fuels. Fuel
oil firing is only allowed during unit startup and shutdown, during
startup and shutdown of pulverizer mills, for flame stabilization when
coal is frozen, for No. 2 fuel oil tank maintenance, to prevent boiler
tube failure in extreme cold weather when the unit is offline for
maintenance, and during malfunction.
SWEPCO produced a BART analysis dated September 2013 for Flint
Creek Plant Boiler No. 1, which was evaluated by EPA and largely formed
the basis for EPA's SO2 BART evaluation in the FIP.\74\ This
BART analysis \75\ has now been adopted and incorporated by ADEQ into
the Arkansas Regional Haze SO2 and PM BART SIP revision to
address the SO2 BART requirements for Flint Creek Boiler No.
1.\76\
---------------------------------------------------------------------------
\74\ 80 FR 18964.
\75\ ``BART Five Factor Analysis Flint Creek Power Plant Gentry,
Arkansas (AFIN 04-00107),'' dated September 2013, Version 4,
prepared by Trinity Consultants Inc. in conjunction with American
Electric Power Service Corporation for the Southwestern Electric
Power Company Flint Creek Power Plant,'' which can be found in
Appendix E to the Arkansas Regional Haze SO2 and PM BART
SIP Revision.
\76\ In a final action published on March 12, 2012, EPA approved
Arkansas' PM BART determination for Flint Creek Plant Boiler No. 1.
In the Arkansas Regional Haze SO2 and PM BART SIP
revision, the state is not revising that BART determination or the
underlying analysis.
---------------------------------------------------------------------------
a. SO2 BART Analysis and Determination
At the time that SWEPCO performed the BART analysis, no
SO2 controls were in place at Flint Creek Plant Boiler No.
1. The cost analysis and visibility improvement data that are part of
SWEPCO's BART analysis are based on the 2001-2003 baseline, not on
emissions reflecting current SO2 controls in place. Since
the time the BART analysis was developed, SWEPCO has installed a Novel
Integrated Deacidification (NID) system and Activated Carbon Injection
(ACI) system at Flint Creek Boiler No. 1 in anticipation of regional
haze requirements as well as other CAA requirements. The installation
of these controls was completed in May 2016.
In assessing SO2 BART, SWEPCO considered the five BART
factors. The available SO2 retrofit control technology
options considered were dry sorbent injection (DSI), dry FGD, and wet
FGD.\77\ DSI was estimated to have a control efficiency of 40-60%. Dry
FGD was estimated to have a control efficiency of 60-95%. NID, which is
a form of dry FGD, was predicted to have a control efficiency of 92%,
achieving an SO2 emission rate of 0.06 lb/MMBtu. Wet FGD was
estimated to have a control efficiency of 80-95%, achieving an
SO2 emission rate of 0.04 lb/MMBtu. All control options
considered were deemed to be technically feasible.
---------------------------------------------------------------------------
\77\ SWEPCO's September 2013 SO2 BART analysis did
not identify or discuss any existing SO2 control
equipment in use at the source because at the time the BART analysis
was developed, there were no existing SO2 controls in
place. Since the Arkansas Regional Haze SO2 and PM SIP
revision was submitted at a time when the NID system is the
pollution control equipment in use at the source, we give ADEQ
credit for considering the existing pollution controls factor in the
SIP revision because the existing SO2 control equipment
is among the ``new'' controls addressed in the older SWEPCO
SO2 BART analysis.
---------------------------------------------------------------------------
In considering the costs of compliance, SWEPCO estimated the
capital and operating costs of a NID system and wet FGD based on EPA's
Control Cost Manual and supplemented, where available, with vendor and
site-specific information obtained by SWEPCO. These values were then
used by SWEPCO to estimate the cost-effectiveness of controls. SWEPCO
estimated the cost of the SO2 control options to be $3,845/
ton for a NID system and $4,919/ton for wet FGD. Since control options
with higher control efficiencies were within a range considered cost-
effective (with one ultimately selected as BART), SWEPCO's BART
analysis did not evaluate the cost of DSI or further consider that
control option in the analysis. Thus, the remainder of SWEPCO's
analysis focused on a NID system (dry FGD) and wet FGD.
SWEPCO determined that although wet FGD is expected to achieve a
slightly higher level of SO2 control compared to NID
technology, it would also have greater potential negative energy and
nonair quality environmental impacts. For example, wet FGD is expected
to generate large volumes of wastewater and solid waste/sludge that
must be treated. Additionally, wet FGD systems have increased power
requirements and increased reagent usage over dry FGD, as well as the
potential for increased particulate and sulfuric acid mist releases.
The costs associated with increased power requirements and greater
reagent usage have already been factored into the cost analysis for wet
FGD. In assessing the remaining useful life of Flint Creek Boiler No.
1, SWEPCO concluded that this factor does not impact the annualized
capital costs of the evaluated control options because the useful life
of the unit is anticipated to be at least as long as the capital cost
recovery period (30 years).
In assessing visibility impacts, the state's submittal included
CALPUFF modeling evaluating the visibility benefits of dry FGD and wet
FGD. We summarize the results of that modeling in Table 7.
[[Page 62218]]
Table 7--Anticipated Visibility Benefit Due to SO2 Controls at Flint Creek Boiler No. 1
[CALPUFF, 98th percentile]
----------------------------------------------------------------------------------------------------------------
Visibility benefit of controls
Baseline over baseline (dv)
Class I area visibility -------------------------------
impact (dv) NID System Wet FGD
----------------------------------------------------------------------------------------------------------------
Caney Creek..................................................... 0.963 0.615 0.629
Upper Buffalo................................................... 0.965 0.464 0.477
Hercules-Glades................................................. 0.657 0.345 0.352
Mingo........................................................... 0.631 0.414 0.423
----------------------------------------------------------------------------------------------------------------
The installation and operation of SO2 controls is
anticipated to result in considerable visibility improvement from the
baseline at the four impacted Class I areas. NID technology is
anticipated to result in visibility improvement ranging from 0.345 to
0.615 dv at each affected Class I area. Although wet FGD is also
anticipated to result in considerable visibility improvement, the
visibility benefit of wet FGD over NID technology at each individual
Class I area is anticipated to be only slight, ranging from 0.007 to
0.014 dv at each Class I area.
As discussed above, SWEPCO determined that NID technology would
result in considerable visibility improvement and is estimated to cost
$3,845/ton. On the other hand, a wet scrubber is estimated to cost
$4,919/ton, and would only achieve slightly more visibility benefit
than NID technology (see Table 7).\78\ Therefore, SWEPCO recommended
that SO2 BART for Flint Creek Boiler No. 1 be an emission
limit of 0.06 lb/MMBtu on a 30-day rolling average over each boiler
operating day, based on the installation of NID technology. ADEQ
concurred with this BART recommendation. We are proposing to agree that
an SO2 emission limit of 0.06 lb/MMBtu based on NID
technology would result in significant visibility benefits from the
baseline and is generally cost-effective. We do not believe the
additional cost of a wet scrubber would be justified in light of the
small amount of additional visibility benefit anticipated over NID
technology. Therefore, we are proposing to approve the state'
determination that SO2 BART for Flint Creek Boiler No. 1 is
an emission limit of 0.06 lb/MMBtu based on NID technology.
---------------------------------------------------------------------------
\78\ Although not discussed by ADEQ in the SIP revision,
SWEPCO's BART analysis also presents the incremental cost
effectiveness of wet scrubbers over NID technology. As shown in
Tables 5-3 and 5-7 of SWEPCO's September 2013 SO2 BART
analysis for Flint Creek, the incremental cost effectiveness of wet
scrubbers over NID technology for Boiler No. 1 is estimated to be
$35,198/ton removed, yet the incremental visibility benefit is
projected to be only 0.014 dv at Caney Creek and 0.013 dv at Upper
Buffalo and even less at Hercules Glades and Mingo.
---------------------------------------------------------------------------
Taking into consideration that the control equipment has already
been installed and is operating at the facility, we are also proposing
to approve the state's determination that the source must comply with
the SO2 BART requirements as of the effective date of the
Administrative Order, which is August 7, 2018. These BART requirements
have now been made enforceable by the state through an Administrative
Order that has been adopted and incorporated in the SIP revision. The
Administrative Order for Flint Creek Boiler No. 1 includes not only the
SO2 emission limit, but also a requirement for the source to
determine compliance with the SO2 emission limit by using a
continuous emission monitoring system.\79\ We are proposing to approve
into the SIP the state's Administrative Order with respect to the
SO2 BART requirements, including the compliance
determination requirements contained in the Administrative Order. The
state's SO2 BART decision for Flint Creek Boiler No. 1 is
consistent with the BART decision EPA previously made in the FIP we
promulgated on September 27, 2016.\80\ We are concurrently proposing to
withdraw the FIP's SO2 BART requirements for Flint Creek
Boiler No. 1, as they would be replaced by our approval of the state's
SO2 BART decision.
---------------------------------------------------------------------------
\79\ The Administrative Order can be found in the Arkansas
Regional Haze SO2 and PM BART SIP Revision.
\80\ 81 FR 66335 and 66416-17.
---------------------------------------------------------------------------
4. Entergy Lake Catherine Unit 4
Entergy Lake Catherine Unit 4 has a 558 MW tangentially-fired
boiler with a maximum heat input of 5,850 MMBtu/hr. Lake Catherine Unit
4 is currently permitted to burn only pipeline quality natural gas, but
until recently was also permitted to burn No. 6 fuel oil as a secondary
fuel. Entergy produced a BART analysis dated May 2014 for Lake
Catherine Unit 4, which was evaluated by EPA and largely formed the
basis for EPA's BART evaluation in the FIP.\81\ The same BART analysis
\82\ has now been adopted and incorporated by ADEQ into the Arkansas
Regional Haze SO2 and PM BART SIP revision to address BART
requirements for Lake Catherine Unit 4 under the fuel oil firing
scenario.\83\
---------------------------------------------------------------------------
\81\ 80 FR 18975.
\82\ ``Revised BART Five Factor Analysis Lake Catherine Steam
Electric Station Malvern, Arkansas (AFIN 30-00011),'' dated May
2014, prepared by Trinity Consultants Inc. in conjunction with
Entergy Services Inc.,'' which can be found in Appendix C to the
Arkansas Regional Haze SO2 and PM BART SIP Revision.
\83\ In a final action published on March 12, 2012, EPA approved
Arkansas' SO2 and PM BART determinations under the
natural gas firing scenario for Lake Catherine Unit 4. In the
Arkansas Regional Haze SO2 and PM BART SIP revision, the
state is not revising those BART determinations or any of the
underlying analyses.
---------------------------------------------------------------------------
In the May 2014 BART analysis submitted by ADEQ as part of the SIP
revision, Entergy explained that no fuel oil has been burned at Unit 4
since prior to the 2001-2003 baseline period and that the company does
not project that it will burn fuel oil at the unit in the foreseeable
future. Therefore, the May 2014 BART analysis does not consider
emissions from fuel oil firing and does not include a BART five factor
analysis or BART determinations for the fuel oil firing scenario.
Entergy stated in the BART analysis that if conditions change such that
it becomes economic to burn fuel oil in the future, it will submit a
BART five factor analysis for the fuel oil firing scenario to the state
for use in the development of a SIP revision, and that Entergy commits
to not burn fuel oil at Lake Catherine Unit 4 until final EPA approval
of BART for the fuel oil firing scenario. Furthermore, Unit 4 is not
currently permitted to burn fuel oil.\84\ Entergy's commitment has now
been made enforceable by the state through an Administrative Order that
has been adopted and incorporated in the SIP revision. We are proposing
to find that
[[Page 62219]]
this approach is appropriate and we are proposing to approve the
state's Administrative Order for Lake Catherine Unit 4 into the SIP.
The Administrative Order would allow the unit to burn natural gas only,
per Entergy's commitment to not burn fuel oil at Unit 4 until ADEQ
submits a SIP revision that includes BART analyses for the fuel oil
firing scenario for Unit 4 and EPA takes final action to approve the
BART determinations. The state's action with respect to addressing BART
for the fuel oil firing scenario for Lake Catherine Unit 4 is
consistent with the action EPA previously took in the FIP we
promulgated on September 27, 2016.\85\ We are concurrently proposing to
withdraw the FIP provision concerning BART for the fuel oil firing
scenario for Lake Catherine Unit 4, as it would be replaced by our
approval of the state's BART action.
---------------------------------------------------------------------------
\84\ See ADEQ Air Permit No. 1717-AOP-R7, issued on October 26,
2016. A copy of the air permit can be found in the docket for this
proposed rulemaking.
\85\ 81 FR 66335 and 66418.
---------------------------------------------------------------------------
5. Entergy White Bluff Units 1 and 2 and the White Bluff Auxiliary
Boiler
Entergy White Bluff Units 1 and 2 each have tangentially-fired 850
MW boilers with a maximum heat input capacity of 8,950 MMBtu/hr. White
Bluff also has a 183 MMBtu/hr Auxiliary Boiler that is permitted to
burn only No. 2 fuel oil or biodiesel. Entergy produced a BART analysis
for White Bluff dated October 2013, which was evaluated by EPA and
largely formed the basis for EPA's SO2 BART evaluation in
the FIP.\86\ Entergy also submitted revised analyses dated August 2015
and August 2016 for EPA to consider before the FIP was finalized.
Entergy provided ADEQ with supplemental information on April 5, 2017,
providing cost-effectiveness data for dry FGD for Units 1 and 2 with
various remaining useful life assumptions. Additionally, at ADEQ's
request, Entergy produced an updated BART analysis dated August 18,
2017, that evaluated several control options and provided updated
remaining useful life information for White Bluff Units 1 and 2. These
BART analyses and other documentation provided by Entergy have been
adopted and incorporated by ADEQ into the Arkansas Regional Haze
SO2 and PM BART SIP revision \87\ to address the
SO2 BART requirements for White Bluff Units 1 and 2, as well
as the SO2, NOX, and PM BART requirements for the
Auxiliary Boiler.\88\
---------------------------------------------------------------------------
\86\ 80 FR 18969. See also ``Revised BART Five Factor Analysis
White Bluff Steam Electric Station Redfield, Arkansas (AFIN 35-
00110),'' dated October 2013, prepared by Trinity Consultants Inc.
in conjunction with Entergy Services Inc.'' This BART analysis can
be found in Appendix D to the Arkansas Regional Haze SO2
and PM BART SIP Revision.
\87\ These BART analyses and other information provided by
Entergy can be found in Appendix D to the Arkansas Regional Haze
SO2 and PM BART SIP Revision.
\88\ In a final action published on March 12, 2012, EPA approved
Arkansas' PM BART determinations for White Bluff Units 1 and 2. In
the Arkansas Regional Haze SO2 and PM BART SIP revision,
the state is not revising those PM BART determinations or any of the
underlying analyses.
---------------------------------------------------------------------------
a. White Bluff Unit 1 and Unit 2 SO2 BART Analysis and
Determinations
In assessing SO2 BART, Entergy considered the five BART
factors. There is currently no SO2 control equipment in use
at Units 1 and 2. The current permitted SO2 emissions rate
for Units 1 and 2 is a 3-hour average emission rate of 1.2 lb/MMBtu,
based on the new source performance standard for fossil-fuel fired
steam generators in effect at the time they were constructed. The
available SO2 control technology options considered in
Entergy's August 2017 BART analysis are switching to low sulfur coal,
DSI, spray dryer absorber (SDA), circulating dry scrubber (CDS), and
wet FGD.
Entergy estimated that by switching to low sulfur coal, Units 1 and
2 can achieve an emission rate of 0.6 lb/MMBtu,\89\ which would result
in approximately an 8.75% reduction in SO2 emissions from
baseline levels. For DSI, Entergy considered two particulate collection
methods. The first collection method, ``DSI,'' would utilize the
existing ESP, and is expected to achieve a control efficiency of 50%.
Entergy expects that DSI would achieve an SO2 emission rate
of 0.35 lb/MMBtu. The second collection method, ``enhanced DSI,'' would
require the installation of a fabric filter or baghouse. The use of a
fabric filter or baghouse in enhanced DSI increases the residence time
and improves the collection efficiency to allow more sorbent to be
injected, thereby resulting in greater emissions reductions. Entergy
expects that enhanced DSI would achieve 80% control efficiency, and an
SO2 emission rate of 0.15 lb/MMBtu. In the August 2017 BART
analysis, Entergy claimed that DSI has not yet been demonstrated on
units comparable to those at White Bluff. Entergy explained that the
largest known installed and operational DSI system has a design feed
rate of 12 tons/hour of sorbent, while most installed DSI systems
typically inject approximately 5-6 tons/hour of sorbent into the
exhaust gas stream. Entergy pointed out that the predicted injection
rate of enhanced DSI at White Bluff is approximately 15 tons/hour of
sorbent. Entergy noted that the greater the injection rates, it is
anticipated that more issues associated with supply and delivery
logistics are likely to arise. Entergy stated that before DSI
technology is selected as BART for White Bluff, a demonstration test
would need to be performed to confirm its feasibility, achievable
performance, and balance of plant impacts (brown plume formation, ash
handling modifications, landfill/leachate considerations, and impact to
mercury control).
---------------------------------------------------------------------------
\89\ The White Bluff SO2 BART analysis provided to
ADEQ by Entergy and incorporated by ADEQ as part of the SIP revision
considered an SO2 emission limit of 0.6 lb/MMBtu for the
switching to low sulfur coal control option. However, in response to
comments the state received during the public comment period that
noted that it is typical to round to the nearest significant digit
when demonstrating compliance, which could result in less emissions
reductions than assumed in the BART analysis, ADEQ ultimately
finalized an emission limit of 0.60 lb/MMBtu in the final SIP
revision.
---------------------------------------------------------------------------
The dry FGD control option considered by Entergy is SDA, which
utilizes a fine mist of lime slurry sprayed into an absorption tower to
absorb SO2 with the resulting calcium sulfite and calcium
sulfate then collected with a fabric filter. SDA systems can typically
achieve SO2 control efficiencies ranging from 60-95%.
Entergy expects that an SDA system would achieve an emission rate of
0.06 lb/MMBtu at Units 1 and 2. Although wet FGD was identified as a
technically feasible control option, it is not expected to achieve
significant visibility benefit beyond dry/semi-dry FGD despite having a
greater estimated cost, based on the October 2013 BART analysis that
EPA relied on to develop the Arkansas Regional Haze FIP.\90\ In fact,
dry/semi-dry FGD was expected to achieve slightly greater visibility
benefit than wet FGD at Hercules-Glades and Mingo based on the October
2013 BART analysis.\91\ Therefore, Entergy did not further consider wet
FGD in its August 18, 2017, BART analysis, on which the Arkansas
Regional Haze SO2 and PM BART SIP revision is largely based.
---------------------------------------------------------------------------
\90\ 80 FR 18972.
\91\ 80 FR 18972.
---------------------------------------------------------------------------
In considering the costs of compliance, Entergy's coal suppliers
provided the company with an estimated incremental cost of $0.50 per
ton for delivering coal guaranteed to have a sulfur content consistent
with achieving an SO2 emission limit of 0.6 lb/MMBtu. ADEQ
noted in the SIP revision that the annualized cost of switching to low
sulfur coal is not dependent on the remaining useful life of White
Bluff Units 1 and 2, since no capital investments in equipment would be
necessary. For the remaining control options, Entergy obtained capital
costs
[[Page 62220]]
and annual operating and maintenance costs from its consultant and used
this to estimate the cost effectiveness of controls. The annualized
cost of DSI, enhanced DSI, and dry/semi-dry FGD is dependent on the
remaining useful life of the White Bluff units since those control
options require capital investments in new equipment or retrofit of
existing equipment. These capital investments were amortized over the
remaining useful life of the White Bluff units to determine the
annualized costs and compared to annual emission reductions to
determine cost-effectiveness. In the August 18, 2017, BART analysis,
Entergy stated that it anticipates cessation of coal combustion at
White Bluff by the end of 2028 and that it will voluntarily take an
enforceable restriction on Units 1 and 2 to that effect. ADEQ noted
that the BART Guidelines provide that the remaining useful life
calculation should begin on the date that controls will be put in place
(i.e., compliance date) and end on the date the facility permanently
stops operations.\92\ The Regional Haze Rule also states that the
compliance date for BART controls must be as expeditiously as
practicable, but in no event later than 5 years after approval of the
SIP.\93\ Considering that the FIP currently requires SO2
emission limits for White Bluff Units 1 and 2 that are based on dry
scrubber installation and which have a compliance date of October 27,
2021, ADEQ acknowledged that the record suggests that a compliance date
for scrubbers that is ``as expeditiously as practicable'' would be
October 27, 2021. Therefore, ADEQ assumed a remaining useful life of 7
years to estimate the cost-effectiveness of SDA for White Bluff Units 1
and 2. Entergy also assumed that DSI and enhanced DSI could be
installed and operational 2 years earlier than FGD, and therefore
assumed in the BART analysis that DSI and enhanced DSI could be
operational at White Bluff Units 1 and 2 by the end of 2019 and that
the capital recovery period for those controls is therefore 9 years.
---------------------------------------------------------------------------
\92\ 70 FR 39104.
\93\ 40 CFR 51.308(e)(iv).
---------------------------------------------------------------------------
Entergy also explained that for DSI, enhanced DSI, and SDA, it
developed two sets of cost estimates. The first is the actual cost
Entergy anticipates incurring for each control option, and the second
reflects the exclusion of certain cost items that are disallowed costs
under the methodology in the EPA's Air Pollution Control Cost Manual
(EPA Control Cost Manual).\94\ These ``disallowed'' line items include
Allowance for Funds Used During Construction (AFUDC). Entergy stated in
its BART analysis that it disagrees with EPA that AFUDC and certain
other cost items are not allowed to be considered in estimating the
cost effectiveness of controls for BART purposes under the EPA Control
Cost Manual, but nonetheless provided a set of cost estimates
reflecting the exclusion of the disallowed line items as well as a set
of cost estimates that included these line items. ADEQ explained in the
SIP revision that its evaluation of controls is based on Entergy's set
of cost numbers that excludes the disallowed line items and follows the
EPA Control Cost Manual. Therefore, we present here only the set of
cost numbers that follows the methodology allowed under the Control
Cost Manual.\95\
---------------------------------------------------------------------------
\94\ At the time the BART Guidelines were finalized, the current
version of the Control Cost Manual was the EPA Air Pollution Control
Cost Manual, Sixth Edition, EPA/452/B-02-001, January 2002. https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-reports-and-guidance-air-pollution. The EPA is engaged in a
long-term process to update portions of the Control Cost Manual. A
project plan describing the scope and schedule for this update
effort is available at https://www3.epa.gov/ttn/ecas/docs/cost_manual_timeline_2016-08-04.pdf. As draft or final updated
chapters are available, states should follow the recommendations in
those rather than in the 6th Edition. Final revised chapters are
posted at https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-reports-and-guidance-air-pollution. Draft
revised chapters are announced in the Federal Register when
available for public comment and can be obtained from EPA Docket No.
EPA-HQ-OAR-2015-0341 at www.regulationgs.gov.
\95\ Please see the TSD associated with this proposed rulemaking
and the Arkansas Regional Haze SO2 and PM SIP revision
for Entergy's set of cost numbers that included line items that are
not allowed to be considered in estimating the cost effectiveness of
controls for BART purposes under the EPA Control Cost Manual.
---------------------------------------------------------------------------
Entergy determined that switching to low sulfur coal would entail
an increased annual cost of operation based on purchase contract terms
for the specific sulfur content of the coal. Based on estimates
provided by the coal supplier of the cost premium for low sulfur coal
and the estimated reduction in emissions, Entergy anticipated that the
cost to guarantee that the units achieve an SO2 emission
limit of 0.6 lb/MMBtu translates to a cost-effectiveness for
SO2 control of approximately $1,150/ton at Unit 1 and
$1,148/ton at Unit 2. Entergy estimated the cost-effectiveness of DSI
to be $6,269/ton at Unit 1 and $6,211/ton at Unit 2 and the cost-
effectiveness of enhanced DSI to be $6,427/ton at Unit 1 and $6,384/ton
at Unit 2. Entergy also estimated the cost of SDA to be $5,420/ton at
Unit 1 and $5,387/ton at Unit 2. In the BART analysis, ADEQ also took
into consideration the cost of controls in terms of dollars per dv
improvement ($/dv) for each SO2 control option considered
for White Bluff. A summary of the cost of controls in terms of $/dv is
provided in Table 8. A summary of Entergy's assessment of the
visibility benefits of the control options in terms of dv is presented
in Tables 9 and 10. ADEQ stated that the average cost-effectiveness
values for DSI, enhanced DSI, and SDA at White Bluff all exceed what is
typically considered to be cost-effective for BART, taking into account
a capital cost recovery period of 7 years for SDA and 9 years for DSI
and enhanced DSI. ADEQ noted that cost-effectiveness values of BART
determinations made in previous regional haze actions have typically
been below $5,000/ton, and that the costs of DSI and SDA exceed this
value. Additionally, ADEQ noted that the cost in terms of $/dv for DSI,
enhanced DSI, and SDA are approximately an order of magnitude greater
than for switching to low sulfur coal.
Table 8--Cost of SO2 Controls ($/dv) for White Bluff Units 1 and 2
----------------------------------------------------------------------------------------------------------------
Class I area
---------------------------------------------------------------
SO2 control option Hercules
Caney Creek Upper Buffalo Glades Mingo
----------------------------------------------------------------------------------------------------------------
Low Sulfur Coal................................. $14,500,519 $11,932,988 $10,666,332 $13,554,882
DSI............................................. 133,341,667 105,417,939 120,512,761 116,126,126
Enhanced DSI.................................... 158,855,956 139,165,572 168,897,541 173,433,064
SDA............................................. 131,447,683 121,373,255 153,165,608 153,852,117
----------------------------------------------------------------------------------------------------------------
[[Page 62221]]
In the BART analysis, Entergy noted that there were adverse energy
and nonair quality environmental impacts associated with DSI, enhanced
DSI, and SDA. These impacts were factored into the costs of compliance.
With regard to consideration of the remaining useful life factor,
Entergy stated in the August 2017 BART analysis that it anticipates
cessation of coal combustion at White Bluff by the end of 2028 and that
it will voluntarily take an enforceable restriction on Units 1 and 2 to
that effect. Entergy's voluntary decision to cease coal combustion by
the end of 2028 is enforceable by the state through an Administrative
Order that has been adopted and incorporated in the SIP revision.
Therefore, for White Bluff Units 1 and 2, ADEQ assumed a remaining
useful life of 7 years to estimate the cost-effectiveness of SDA and a
remaining useful life of 9 years to estimate the cost-effectiveness of
DSI.
In assessing visibility impacts, the state's submittal included the
CALPUFF modeling that was included in Entergy's August 18, 2017, BART
analysis, evaluating the visibility benefits of switching to low sulfur
coal, DSI, enhanced DSI, and SDA. We summarize the results of that
modeling in Tables 9 and 10.\96\
---------------------------------------------------------------------------
\96\ As explained by ADEQ in the SIP revision, Entergy's
modeling of the visibility improvement from evaluated SO2
controls in the August 18, 2017, SO2 BART analysis for
White Bluff is based on an updated baseline of 2009-2013 emissions,
rather than the 2001-2003 emissions baseline EPA used in the
Arkansas Regional Haze FIP to estimate the visibility improvement
anticipated from SDA and wet FGD. Entergy's change in baseline
emissions impacts the modeled visibility benefit anticipated from
SDA, resulting in a modeled visibility benefit that is 15% to 26%
lower at each unit in Entergy's updated analysis compared to the
FIP. In the FIP, EPA did not evaluate the visibility improvement
anticipated from DSI, enhanced DSI, and switching to low sulfur
coal, but ADEQ stated it expects that the relative difference in $/
dv among the control options evaluated by Entergy would be similar
across both baseline periods. Further, ADEQ believes that the
differences in projected visibility benefits resulting from
different baseline emissions in the FIP, compared to the updated
Entergy BART analysis, would not result in a change to ADEQ's
ultimate SO2 BART decision for White Bluff Units 1 and 2.
Table 9--Anticipated Visibility Benefit Due to SO2 Controls at White Bluff Unit 1
[CALPUFF, 98th percentile] *
----------------------------------------------------------------------------------------------------------------
Visibility benefit of controls over baseline (dv)
Baseline ---------------------------------------------------------------
Class I area visibility Low sulfur
impact (dv) coal DSI Enhanced DSI SDA
----------------------------------------------------------------------------------------------------------------
Caney Creek..................... 1.505 0.129 0.308 0.492 0.603
Upper Buffalo................... 1.051 0.143 0.375 0.555 0.642
Hercules-Glades................. 0.925 0.167 0.341 0.467 0.525
Mingo........................... 0.802 0.115 0.333 0.436 0.504
----------------------------------------------------------------------------------------------------------------
* This table shows the modeled visibility benefits of SO2 controls for White Bluff Unit 1, as presented in Table
4-6 of Entergy's August 18, 2017, SO2 BART analysis for White Bluff, which can be found in Appendix D of the
Arkansas Regional Haze SO2 and PM SIP revision. Although the combined visibility benefits on a facility-wide
basis were not modeled, we expect that such combined visibility benefits would be greater than the unit
specific values shown in this table.
Table 10--Anticipated Visibility Benefit Due to SO2 Controls at White Bluff Unit 2
[CALPUFF, 98th percentile] *
----------------------------------------------------------------------------------------------------------------
Visibility benefit of controls over baseline (dv)
Baseline ---------------------------------------------------------------
Class I area visibility Low sulfur
impact (dv) coal DSI Enhanced DSI SDA
----------------------------------------------------------------------------------------------------------------
Caney Creek..................... 1.533 0.097 0.274 0.460 0.574
Upper Buffalo................... 1.059 0.127 0.359 0.531 0.632
Hercules-Glades................. 0.912 0.137 0.303 0.429 0.486
Mingo........................... 0.819 0.122 0.333 0.435 0.501
----------------------------------------------------------------------------------------------------------------
* This table shows the modeled visibility benefits of SO2 controls for White Bluff Unit 2, as presented in Table
4-7 of Entergy's August 18, 2017, SO2 BART analysis for White Bluff, which can be found in Appendix D of the
Arkansas Regional Haze SO2 and PM SIP revision. Although the combined visibility benefits on a facility-wide
basis were not modeled, we expect that such combined visibility benefits would be greater than the unit
specific values shown in this table.
The SO2 control options considered are anticipated to
result in considerable visibility improvement from the baseline at the
four impacted Class I areas. For White Bluff Unit 1, switching to low
sulfur coal is anticipated by the state submittal to result in
visibility improvement ranging from 0.115 to 0.167 dv at each affected
Class I area. DSI is anticipated to result in visibility improvement
ranging from 0.308 to 0.375 dv at each affected Class I area, while
enhanced DSI is anticipated to result in visibility improvement ranging
from 0.436 to 0.555 dv. SDA is anticipated to result in the greatest
visibility improvement, ranging from 0.504 to 0.642 dv.
For White Bluff Unit 2, switching to low sulfur coal is anticipated
by the state submittal to result in visibility improvement ranging from
0.097 to 0.137 dv at each affected Class I area. DSI is anticipated to
result in visibility improvement ranging from 0.274 to 0.359 dv at each
affected Class I area, while enhanced DSI is anticipated to result in
visibility improvement ranging from 0.429 to 0.531 dv. SDA is
anticipated to result in the greatest visibility improvement, ranging
from 0.486 to 0.632 dv.
[[Page 62222]]
Taking into consideration the remaining useful life of White Bluff
Units 1 and 2 and the resulting cost-effectiveness as well as the
anticipated visibility improvement of the SO2 control
options, ADEQ concurred with Entergy's recommendation that
SO2 BART for White Bluff Units 1 and 2 is an emission limit
of 0.60 lb/MMBtu based on the use of low sulfur coal.\97\ All other
SO2 control options for White Bluff have an average cost-
effectiveness value greater than $5,000/ton, which ADEQ stated exceeds
what has typically been considered to be cost-effective for BART.
Additionally, ADEQ noted that the cost-effectiveness in terms of $/dv
for DSI, enhanced DSI, and SDA are approximately an order of magnitude
greater than for LSC. Considering the costs and the visibility benefits
of the control options, ADEQ determined that SO2 BART for
White Bluff is an emission limit of 0.60 lb/MMBtu based on the use of
low sulfur coal.\98\
---------------------------------------------------------------------------
\97\ Entergy evaluated an SO2 emission rate of 0.6
lb/MMBtu based on the use of low sulfur coal in the SO2
BART analysis for White Bluff. However, ADEQ ultimately selected
0.60 lb/MMBtu as the BART emission limit in response to comments it
received during the state public comment period raising concerns
that finalizing an emission limit of 0.6 lb/MMBtu could result in
smaller SO2 reductions than assumed because it is typical
to round to the nearest significant digit when demonstrating
compliance.
\98\ The White Bluff SO2 BART analysis submitted by
Entergy and ADEQ's SIP revision both considered an SO2
emission limit of 0.6 lb/MMBtu for the switching to low sulfur coal
control option. However, in response to comments the state received
during the public comment period that noted that it is typical to
round to the nearest significant digit when demonstrating
compliance, which could result in less emissions reductions than
assumed in the analysis, ADEQ ultimately finalized an emission limit
of 0.60 lb/MMBtu in the final SIP revision.
---------------------------------------------------------------------------
In support of its assertion that a 3-year compliance deadline is
needed to meet this emission limit, Entergy submitted a letter to ADEQ
dated April 3, 2018, explaining that it is the company's practice to
project how much coal will be needed in future years and to contract
for a portion of its coal supply up to 3 years in advance.\99\ Entergy
stated that it keeps a reserve supply of coal at White Bluff to ensure
that the units can continue to operate in the event of a fuel supply
disruption. Entergy finds that a 3-year compliance date is necessary
for the 0.60 lb/MMBtu emission limit because the sulfur content limits
of Entergy's existing coal contracts for the next 3 years exceed this
emission rate. Entergy is currently under contract for coal with a
sulfur content of 1.2 lb/MMBtu or less. Entergy noted that even though
the coal delivered to White Bluff has lately been of lower sulfur
content than required by the contract, its experience is that the
sulfur content can vary widely. Entergy also stated that as of the
letter dated April 3, 2018, it had already contracted for a portion of
its coal supply needs for the next 3 years (through the end of the year
2020). Those contracts are for coal with a sulfur content limit ranging
from 0.7 to 0.9 lb/MMBtu. Additionally, Entergy stated it cannot
accurately calculate expected SO2 emissions from blending of
coals from its stockpile and new deliveries of coal because the sulfur
content of the stockpile coal is not tracked. Entergy explained that
this means that it cannot ensure that White Bluff will receive coal
with a low enough sulfur content to ensure compliance with the 0.60 lb/
MMBtu emission limit until the company has had sufficient time to
negotiate new contracts and the existing coal supply has been depleted
and replaced with coal that has a lower sulfur content. ADEQ agreed
that a 3-year compliance date for the 0.60 lb/MMBtu emission limit
based on the use of low sulfur coal is reasonable given the site-
specific circumstances for White Bluff as discussed in Entergy's letter
dated April 3, 2018.
---------------------------------------------------------------------------
\99\ The letter from Entergy, dated April 3, 2018, is found in
Appendix D the Arkansas Regional Haze SO2 and PM BART SIP
Revision.
---------------------------------------------------------------------------
With regard to the cost analysis for SO2 controls for
White Bluff, we agree that AFUDC and certain other cost items are not
allowed to be considered in estimating the cost effectiveness of
controls for BART purposes under the EPA Control Cost Manual, and we
also acknowledge and agree with ADEQ's decision to base its evaluation
of controls on Entergy's set of cost numbers that does not include the
disallowed line items. Nevertheless, there is one aspect of Entergy's
cost analysis that we do not agree with. Entergy's cost analysis is
based on an SDA system assuming a coal sulfur content of 1.2 lb/MMBtu,
which Entergy stated is based on its current coal contract sulfur
limit. However, the White Bluff units have historically burned coal
with a lower sulfur content. In its BART analysis, Entergy stated that
the current average sulfur content of coal received at the White Bluff
station is 0.57 lb SO2/MMBtu but that the facility could
receive coal with sulfur content up to 1.2 lb SO2/MMBtu.
Given that, Entergy's analysis is based on a scrubber designed to
handle that sulfur load. In the Arkansas Regional Haze FIP, we noted
that Entergy's SO2 cost analysis for White Bluff, which was
provided to us by Entergy for EPA's evaluation and consideration in the
development of the FIP, took the approach of costing a scrubber system
designed to burn coal with a sulfur content much higher than what has
been historically burned,\100\ an approach similar to what Entergy has
done in the August 2017 BART analysis. In the FIP, we stated that we
disagreed with Entergy's approach for costing of the scrubber system,
and our FIP cost analysis was instead based on a dry scrubber system
assuming a sulfur content of 0.68 lb/MMBtu, the maximum monthly
emission rate from 2009-2013. Relying on our FIP's cost analysis for
dry scrubbers for White Bluff, which was based on a scrubber system
designed to burn coal having a sulfur content consistent with what the
units have historically burned, and adjusting for a 7-year as opposed
to a 30-year capital cost recovery period to reflect that the units
will cease coal combustion by the end of 2028,\101\ we estimate that
the cost of dry scrubbers at White Bluff Units 1 and 2 is $4,376/ton
for Unit 1 and $4,129/ton for Unit 2.\102\ As noted in the SIP
revision, Entergy's August 18, 2017, SO2 BART analysis for
White Bluff shows that the estimated visibility benefit of dry
scrubbers for Unit 1 is 0.603 dv at Caney Creek and 0.642 dv at Upper
Buffalo, and for Unit 2 is 0.574 dv at Caney Creek and 0.632 dv at
Upper Buffalo.\103\ Although our cost estimates for dry scrubbers are
more cost-effective than estimated by Entergy, we still consider these
cost numbers to be on the higher end of what has been found to be cost
effective in other regional haze actions when also taking into account
the level of visibility benefit of the controls. We are proposing to
agree with ADEQ's conclusion that dry scrubbers are not BART for White
Bluff Units 1 and 2.
---------------------------------------------------------------------------
\100\ 81 FR 66385; See also ``Response to Comments for the
Federal Register Notice for the State of Arkansas; Regional Haze and
Interstate Visibility Transport Federal Implementation Plan,'' pages
261-263, and 345-349. The FIP Response to Comments document is found
in the docket at https://www.regulations.gov/document?D=EPA-R06-OAR-2015-0189-0187.
\101\ We are proposing to agree that it is appropriate to assume
a capital cost recovery period of 7 years for scrubber controls in
the BART analysis since Entergy's voluntarily proposed date for
cessation of coal combustion at White Bluff Units 1 and 2 by the end
of 2028 has been made enforceable through an Administrative Order.
The Administrative Order can be found in the Arkansas Regional Haze
SO2 and PM BART SIP Revision.
\102\ See Excel spreadsheet titled ``EPA Revised cost
calcs_WB_Corrected CRF 7 years.xlsx,'' which is found in the docket
for this proposed rulemaking.
\103\ See Tables 4-6 and 4-7 of Entergy's August 18, 2017, White
Bluff SO2 BART analysis.
---------------------------------------------------------------------------
We are also proposing to agree with ADEQ that the cost of
compliance, in dollars per ton, for DSI and enhanced DSI is not cost
effective when the
[[Page 62223]]
remaining useful life of White Bluff Units 1 and 2 is taken into
account. We are proposing to agree that switching to low sulfur coal
would result in visibility benefits from the baseline and would be very
cost-effective. Therefore, we are proposing to approve the state's
determination that given Entergy's enforceable commitment to cease coal
combustion at White Bluff Units 1 and 2 by the end of 2028,
SO2 BART for Units 1 and 2 is an SO2 emission
limit of 0.60 lb/MMBtu based on switching to low sulfur coal. The
Administrative Order for the White Bluff units also includes a
requirement for the source to determine compliance with the
SO2 emission limits for Units 1 and 2 by using a continuous
emission monitoring system. These BART requirements are enforceable by
the state through an Administrative Order that has been adopted and
incorporated in the SIP revision. We are proposing to approve in the
SIP the state's Administrative Order, including the 3-year compliance
date to meet the 0.60 lb/MMBtu emission limit and the requirement for
Entergy to move forward with its proposed plan to cease coal combustion
at White Bluff Units 1 and 2 no later than December 31, 2028.\104\ We
are proposing to find that Entergy's explanation that it cannot ensure
that White Bluff will receive coal with a low enough sulfur content to
ensure compliance with the 0.60 lb/MMBtu emission limit until the
company has had sufficient time to negotiate new contracts and the
existing coal supply, including the coal for which Entergy is already
under contract through the year 2020, has been depleted and replaced
with coal that has a lower sulfur content, is reasonable. Therefore, we
are proposing to find that a 3-year compliance date for the 0.60 lb/
MMBtu SO2 BART emission limit is appropriate and reasonable.
We are concurrently proposing to withdraw the FIP's SO2 BART
requirements for White Bluff Units 1 and 2, as they would be replaced
by our approval of the state's SO2 BART decision.
---------------------------------------------------------------------------
\104\ The Administrative Order can be found in the Arkansas
Regional Haze SO2 and PM BART SIP Revision.
---------------------------------------------------------------------------
b. White Bluff Auxiliary Boiler BART Determinations
In determining BART for the White Bluff Auxiliary Boiler, ADEQ
relied on Entergy's October 2013 BART analysis for White Bluff.\105\ In
the BART analysis, Entergy explained that air dispersion modeling
demonstrates that the maximum visibility impact predicted from the
Auxiliary Boiler is 0.036 dv, which it characterized as a very low
level of visibility impact. The modeling results also show that looking
at the 98th percentile visibility impacts, the greatest impact from the
Auxiliary Boiler is 0.01 dv at Caney Creek.\106\ Entergy reasoned that
since the existing visibility impairment due to the Auxiliary Boiler is
extremely low, any improvement due to controls are expected to be
negligible. ADEQ further expanded on this finding by explaining that
the Arkansas Regional Haze FIP found that due to the small level of
baseline visibility impairment caused by the Auxiliary Boiler, the
existing SO2, NOX, and PM emission limitations in
the Entergy White Bluff permit were determined to satisfy BART for the
Auxiliary Boiler. ADEQ stated that it agrees that SO2,
NOX, and PM BART for the Auxiliary Boiler are the existing
emission limits in the facility's air permit. We are proposing to find
that the state's SO2, NOX, and PM BART decisions
for the Auxiliary Boiler are appropriate. The BART Rule provides:
---------------------------------------------------------------------------
\105\ ``Revised BART Five Factor Analysis White Bluff Steam
Electric Station Redfield, Arkansas (AFIN 35-00110), dated October
2013, prepared by Trinity Consultants Inc. in conjunction with
Entergy Services Inc.'' This BART analysis can be found in Appendix
D to the Arkansas Regional Haze SO2 and PM BART SIP
Revision.
\106\ ``Revised BART Five Factor Analysis White Bluff Steam
Electric Station Redfield, Arkansas (AFIN 35-00110), dated October
2013, prepared by Trinity Consultants Inc. in conjunction with
Entergy Services Inc.,'' see Table 4-4.
---------------------------------------------------------------------------
``Consistent with the CAA and the implementing regulations, States
can adopt a more streamlined approach to making BART determinations
where appropriate. Although BART determinations are based on the
totality of circumstances in a given situation, such as the distance of
the source from a Class I area, the type and amount of pollutant at
issue, and the availability and cost of controls, it is clear that in
some situations, one or more factors will clearly suggest an outcome.
Thus, for example, a State need not undertake an exhaustive analysis of
a source's impact on visibility resulting from relatively minor
emissions of a pollutant where it is clear that controls would be
costly and any improvements in visibility resulting from reductions in
emissions of that pollutant would be negligible.'' \107\
---------------------------------------------------------------------------
\107\ 70 FR 39116.
---------------------------------------------------------------------------
Given the very small baseline visibility impacts from the Auxiliary
Boiler, we believe it is appropriate to take a streamlined approach for
determining BART in this case. Because of the very low baseline
visibility impacts from the Auxiliary Boiler at each modeled Class I
area, we believe that the visibility improvement that could be achieved
through the installation and operation of controls would be negligible,
such that the cost of those controls could not be justified. Therefore,
we are proposing to approve the state's determination that the existing
SO2, NOX, and PM emission limitations in the
Entergy White Bluff permit are BART for the Auxiliary Boiler.
Specifically, these emission limits are 105.2 lb/hr SO2,
32.2 lb/hr NOX, and 4.5 lb/hr PM. These BART requirements
are enforceable by the state through an Administrative Order that has
been adopted and incorporated in the SIP revision. We are proposing to
approve into the SIP the state's Administrative Order, including the
requirement that the White Bluff Auxiliary Boiler comply with BART as
of the effective date of the Administrative Order, which is August 7,
2018.\108\ We are concurrently proposing to withdraw the FIP's
SO2 and PM BART requirements for the Auxiliary Boiler, as
they would be replaced by our approval of the state's BART decisions.
---------------------------------------------------------------------------
\108\ The Administrative Order can be found in the Arkansas
Regional Haze SO2 and PM BART SIP Revision.
---------------------------------------------------------------------------
We also note that in the Arkansas Regional Haze NOX SIP
revision, ADEQ erroneously identified the Auxiliary Boiler as
participating in CSAPR for ozone season NOX, and the state
elected to rely on participation in that trading program to satisfy the
Auxiliary Boiler's NOX BART requirements. In a final action
published in the Federal Register on February 12, 2018, we took final
action to approve this SIP revision, including reliance on CSAPR for
ozone season NOX to satisfy the Auxiliary Boiler's
NOX BART requirements.\109\ Our approval of this
determination for the Auxiliary Boiler was made in error. Therefore, we
are proposing to withdraw our prior approval of the state's reliance on
CSAPR for ozone season NOX to satisfy the NOX
BART requirement for the Auxiliary Boiler that was included in the
Arkansas Regional Haze NOX SIP revision submitted to us on
October 31, 2017. We are proposing to replace our approval of that BART
finding for the Auxiliary Boiler with approval of the source specific
32.2 lb/hr NOX BART emission limit contained in the August
8, 2018, Arkansas Regional Haze SIP revision.
---------------------------------------------------------------------------
\109\ 83 FR 5927.
---------------------------------------------------------------------------
C. Reasonable Progress Analysis for SO2
In determining whether additional controls are necessary under the
reasonable progress requirements and
[[Page 62224]]
thus in establishing RPGs, a state must consider the four statutory
factors in section 169A(g)(1) of the CAA: (1) The costs of compliance,
(2) the time necessary for compliance, (3) the energy and nonair
quality environmental impacts of compliance, and (4) the remaining
useful life of any existing source subject to such requirements. The
Regional Haze Rule also states that in establishing the RPGs, the state
must consider the uniform rate of improvement in visibility for the
period covered by the implementation plan.\110\ The uniform rate of
visibility improvement, or uniform rate of progress (URP), needed to
reach natural conditions by 2064 for each Class I area can be
determined by comparing baseline conditions with natural conditions.
The Regional Haze Rule provides for the use of an analytical framework
that compares the rate of progress that will be achieved by a SIP (as
represented by the reasonable progress goals for the end of the
implementation period) to the rate of progress that if continued would
result in natural conditions in 2064 (i.e., the URP). When a Class I
area's visibility conditions for the most impaired days are better
(i.e., less impaired) than the URP, the visibility conditions at the
Class I areas are said to be ``below the URP line'' or ``below the
glidepath.''
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\110\ 40 CFR 51.308(d)(1)(i)(B).
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Consistent with section 169A(b) of the CAA, 40 CFR 51.308(d)(3)
requires that states include in their SIP a long-term strategy for
making reasonable progress for each Class I area within their state.
This long-term strategy is the compilation of all control measures a
state will use during the implementation period of the specific SIP
submittal to achieve reasonable progress, and thus to meet any
applicable RPGs for a particular Class I area. The long-term strategy
includes control measures determined necessary pursuant to both the
BART and reasonable progress analyses.
In the Arkansas Regional Haze SO2 and PM SIP
revision,\111\ ADEQ noted that EPA's ``Guidance for Setting Reasonable
Progress Goals under the Regional Haze Program'' \112\ (EPA's RPG
Guidance), provides that states have flexibility in how to take into
consideration the four statutory factors. The SIP revision states that,
considering this guidance, ADEQ believes that the four reasonable
progress factors can be appropriately applied broadly to a group of
sources state-wide rather than in a source-specific manner. However,
ADEQ stated that since EPA evaluated the four factors for controls at
the Independence facility in the Arkansas Regional Haze FIP as part of
a source-specific analysis, it determined that application of the four
factors to that particular source is also ``relevant'' in its
reasonable progress analysis as a way of addressing EPA's previous
analysis as reflected in the FIP. Therefore, in addition to considering
a broader analysis using the four factors, ADEQ also conducted a more
specific analysis for the Independence facility. The former analysis in
the SIP is ``broad'' in the sense that it does not quantify costs or
visibility benefits for any particular source or source category and
discusses visibility benefits and costs in only qualitative terms. In
the explanation of its approach, the SIP states that both analyses were
completed and the results taken into consideration before the state
determined whether any controls are necessary under reasonable
progress.
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\111\ In a SIP revision submitted on October 31, 2017, Arkansas
provided a reasonable progress analysis and reasonable progress
determination with respect to NOX, and we took final
action to approve the analysis and determination in a final action
published on February 12, 2018 (see 83 FR 5927). Thus, the Arkansas
Regional Haze SO2 and PM SIP revision addresses the
reasonable progress requirements with respect to SO2 and
PM emissions.
\112\ Guidance for Setting Reasonable Progress Goals under the
Regional Haze Program, June 1, 2007, memorandum from William L.
Wehrum, Acting Assistant Administrator for Air and Radiation, to EPA
Regional Administrators, EPA Regions 1-10 (p. 5-1).
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Before presenting its broad analysis, the SIP identified the key
pollutants and source categories that contribute to visibility
impairment in Arkansas Class I areas. After presenting its broad
analysis, the SIP presents an evaluation of which sources should be the
focus of a narrow four-factor analysis and selected Independence as the
only such source. The identification of the key pollutants and source
categories that contribute to visibility impairment in Arkansas Class I
areas, the broad reasonable progress analysis performed by ADEQ, the
identification of Independence as the only source for which a narrow
analysis would be performed, and ADEQ's determination regarding
additional measures for Independence that are necessary for reasonable
progress are discussed in the subsections that follow. We provide our
assessment of each component of the reasonable progress section of the
SIP revision before summarizing and assessing the next component.
1. Arkansas' Discussion of Key Pollutants and Source Category
Contributions
As part of its reasonable progress analysis, ADEQ provided a
discussion of the results of air quality modeling performed by the
Central Regional Air Planning Association (CENRAP) in support of SIP
development in the central states region for 2002 and projected 2018
emissions.\113\ The CENRAP modeling included Particulate Source
Apportionment Technology Tool (PSAT) with Comprehensive Air Quality
model with extensions (CAMx) version 4.4, which was used to provide
source apportionment by geographic regions and major source categories
for pollutants that contribute to visibility impairment at each of the
Class I areas in the central states region.\114\ The SIP revision
provided a discussion of PSAT data for sources region-wide (i.e.,
sources both in and outside Arkansas, including sources in the
continental U.S. and international sources) as well as a discussion of
PSAT data for Arkansas sources. Below, we provide a summary of each set
of PSAT data.
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\113\ The central states region includes Texas, Oklahoma,
Louisiana, Arkansas, Kansas, Missouri, Nebraska, Iowa, Minnesota,
and the tribal governments within these states.
\114\ See the TSD for CENRAP Emissions and Air Quality Modeling
to Support Regional Haze State Implementation, which is found in
Appendix 8.1 of the 2008 Arkansas Regional Haze SIP. The 2008
Arkansas Regional Haze SIP can be found in the docket associated
with this proposed rulemaking.
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a. Region-Wide PSAT Data for Caney Creek and Upper Buffalo
Based on the region-wide PSAT data, which looked at sources both in
and outside Arkansas, it was found that point sources are the primary
contributor to light extinction at Arkansas' Class I areas on the 20%
worst days in 2002. Region-wide point sources were found to contribute
81.04 inverse Megameters (Mm-1) at Caney Creek and 77.8
Mm-1 at Upper Buffalo on the 20% worst days in 2002, which
makes up approximately 60% of the total light extinction at each Class
I area. The region-wide PSAT data showed that area stationary
anthropogenic sources are the next largest source category contributor
to light extinction at Arkansas Class I areas, contributing 17.81
Mm-1 at Caney Creek and 20.46 Mm-1 at Upper
Buffalo, which makes up approximately 13% and 16% of the total light
extinction at each Class I area, respectively. The remaining source
categories (i.e., natural, on-road, and non-road sources) were found to
each contribute between 2 and 6% of the
[[Page 62225]]
total light extinction at Arkansas Class I areas.
Based on the region-wide PSAT data, Arkansas also found that
sulfate (SO4) contributed 87.05 Mm-1 at Caney
Creek and 83.18 Mm-1 at Upper Buffalo on the 20% worst days
in 2002, which is approximately 65% and 63% of the total modeled light
extinction at each Class I area, respectively. Most of the light
extinction due to SO4 was attributed to point sources. Out
of the light extinction due to SO4, the point source
category was responsible for approximately 86 to 87% of that light
extinction. Point sources of SO4 contributed 75.1
Mm-1 at Caney Creek and 72.17 Mm-1 at Upper
Buffalo, or approximately 55 to 56% of the total light extinction at
Arkansas Class I areas on the 20% worst days in 2002. In contrast, the
other pollutant species were responsible for a much smaller proportion
of the total light extinction at Arkansas' Class I areas. For example,
nitrate (NO3) contributed approximately 10%, primary organic
aerosols (POA) contributed approximately 8%, elemental carbon (EC)
contributed approximately 4%, crustal material (CM) contributed
approximately 3 to 5%, and soil contributed approximately 1% of the
total modeled light extinction at each Arkansas Class I area on the 20%
worst days in 2002.
The region-wide PSAT data also showed that point sources are
projected to remain the primary contributor to light extinction at
Arkansas Class I areas, contributing 45.27 Mm-1 at Caney
Creek and 43.02 Mm-1 at Upper Buffalo on the 20% worst days
in 2018. This constitutes approximately 53% of the total light
extinction at Caney Creek and 50% of the total light extinction at
Upper Buffalo. Area sources are projected to continue to be the second
largest contributor to light extinction, being responsible for 20% of
the total light extinction at Caney Creek and 23% of the total light
extinction at Upper Buffalo. The remaining source categories (i.e.,
natural, on-road, and non-road sources) are projected to continue to
contribute 5% of the total light extinction at Arkansas Class I areas
on the 20% worst days in 2018. Based on the region-wide PSAT data,
light extinction due to SO4 is projected to decrease by 44%
at Caney Creek and 45% at Upper Buffalo between 2002 and 2018.\115\
However, SO4 is projected to continue to be the primary
driver of total light extinction at Arkansas Class I areas, with point
sources continuing to be the primary source of light extinction due to
SO4. Point sources of SO4 are projected to
contribute 39.83 Mm-1 at Caney Creek and 37.09
Mm-1 at Upper Buffalo, which is between 43 and 46% of the
total light extinction on the 20% worst days in 2018.
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\115\ The CENRAP's 2018 modeling projections made the following
regional haze control assumptions for Arkansas' point sources: (1)
Installation of scrubber controls at Flint Creek Boiler No. 1 to
meet the presumptive SO2 BART limit of 0.15 lb/MMBtu; (2)
installation of low NOX burners to satisfy NOX
BART requirements at Flint Creek Boiler No. 1 and White Bluff Units
1 and 2; and (3) the shutdown of AECC Bailey Unit 1 and Entergy Lake
Catherine Unit 4 by 2018. The SIP revision we are proposing to take
action on requires a more stringent SO2 emission limit
for Flint Creek Boiler No. 1; requires an interim SO2
emission limit of 0.60 lb/MMBtu and cessation of coal combustion by
the end of 2028 at White Bluff Units 1 and 2; requires an
SO2 emission limit of 0.60 lb/MMBtu for Independence
Units 1 and 2; does not require the installation of low
NOX burners for any of Arkansas' EGUs; and does not
require shutdown of AECC Bailey Unit 1 or Entergy Lake Catherine
Unit 4.
---------------------------------------------------------------------------
b. Arkansas PSAT Data for Caney Creek and Upper Buffalo
When looking at the PSAT data for sources within Arkansas only, the
state found that the relative contribution of sources within Arkansas
to total light extinction on the 20% worst days at Arkansas Class I
areas is small. Species attributed to Arkansas sources contributed
approximately 10% of the total light extinction on the 20% worst days
in 2002 and were projected to contribute between 13 and 14% of the
total light extinction on the 20% worst days in 2018. Additionally, the
state found that when only the visibility impact of sources within
Arkansas were considered, area sources actually had a larger impact on
light extinction than point sources. Based on the Arkansas source PSAT
data, area sources within Arkansas contributed 5.03 Mm-1 at
Caney Creek on the 20% worst days in 2002, which is approximately 37%
of the light extinction attributed to Arkansas sources at Caney Creek
and accounts for 4% of the total light extinction at the Class I area.
Based on the Arkansas source PSAT data, area sources within Arkansas
contributed 6.72 Mm-1 at Upper Buffalo on the 20% worst days
in 2002, which is approximately 50% of the light extinction attributed
to Arkansas sources at Upper Buffalo and accounts for 5% of the total
light extinction at the Class I area. In contrast, Arkansas point
sources contributed 3.85 Mm-1 at Caney Creek on the 20% worst days in
2002, which is approximately 28% of the light extinction attributed to
Arkansas sources at Caney Creek and accounts for 3% of the total light
extinction at the Class I area. Arkansas point sources also contributed
3.25 Mm-1 at Upper Buffalo on the 20% worst days in 2002,
which is approximately 24% of the light extinction attributed to
Arkansas sources and accounts for 2% of the total light extinction at
the Class I area. The other sources in Arkansas contributed between 7
and 14% each to light extinction attributed to Arkansas sources,
accounting for approximately 1% each to the total light extinction at
each Arkansas Class I area on the 20% worst days in 2002.
Based on the Arkansas source PSAT data, it was also found that
SO4 from Arkansas sources (all source categories)
contributed 4.14 Mm-1 at Caney Creek and 3.97 Mm-1 at Upper
Buffalo, which is approximately 3% of the total visibility extinction
at each of the Class I areas on the 20% worst days in 2002. Out of the
light extinction attributed to SO4 from Arkansas sources,
the point source category contributed approximately 67% of that light
extinction at Caney Creek and Upper Buffalo. At Caney Creek, the
largest contributing pollutant species next to SO4 was POA,
which contributed approximately 3.54 Mm-1. At Upper Buffalo,
the largest contributing pollutant species next to SO4 was
CM, which contributed approximately 3.53 Mm-1.
NO3 from Arkansas sources was found to contribute 2.11
Mm-1 at Caney Creek and 1.07 Mm-1 at Upper
Buffalo, which is approximately 2% and 1% of the of the total light
extinction at Caney Creek and Upper Buffalo, respectively. On-road
sources accounted for approximately 50% of the light extinction
attributed to Arkansas sources of NO3 at Arkansas Class I
areas.
The Arkansas source PSAT data also showed that when only sources
located in Arkansas are considered, area sources are projected to
remain the primary contributor to light extinction at Arkansas Class I
areas on the 20% worst days in 2018. Arkansas area sources are
projected to contribute 4.85 Mm-1 at Caney Creek and 6.52
Mm-1 at Upper Buffalo on the 20% worst days in 2018, which
is approximately 43% of light extinction attributed to Arkansas sources
at Caney Creek and 54% of the light extinction attributed to Arkansas
sources at Upper Buffalo. In contrast, Arkansas point sources are
projected to contribute 4.05 Mm-1 at Caney Creek and 3.63
Mm-1 at Upper Buffalo on the 20% worst days in 2018.
Arkansas also notes that overall, light extinction attributed to
Arkansas sources of SO4 is projected to decrease at Arkansas
Class I areas on the 20% worst days in 2018, but light extinction
attributed to point sources of SO4 located in Arkansas is
projected to increase by 4% at Caney Creek and 5% at Upper Buffalo.
[[Page 62226]]
Nevertheless, Arkansas noted that the contribution to total light
extinction of SO4 from Arkansas point sources is projected
to be approximately 3% of the total light extinction at each Arkansas
Class I area on the 20% worst days in 2018, which is a value the state
considers to be relatively small.
c. Arkansas' Conclusions Regarding Key Pollutants and Source Category
Contributions
Based on an assessment of both the region-wide PSAT data and the
Arkansas source PSAT data, Arkansas identified SO4 as the
key pollutant species contributing to light extinction at Caney Creek
and Upper Buffalo. When looking at the region-wide PSAT data,
SO4 is the pollutant species responsible for the vast
majority of the visibility impairment at Arkansas Class I areas on the
20% worst days. When looking at the Arkansas source PSAT data,
SO4 is still the pollutant species with the largest
contribution to visibility impairment at Arkansas Class I areas on the
20% worst days, but its relative contribution to light extinction is
not as heavily weighted as it is in the region-wide PSAT data. The
primary driver of SO4 formation at Arkansas Class I areas is
emissions of SO2 from point sources, both when looking at
visibility impacts from sources region-wide and also when looking at
visibility impacts only from sources in Arkansas.
Arkansas also noted that only a small proportion of total light
extinction is due to NO3 from Arkansas sources, and that
this proportion has been driven by on-road sources. For example,
NO3 from Arkansas point sources contributed less than 0.5%
of the total light extinction on the 20% worst days at Caney Creek and
Upper Buffalo. Based on this observation, Arkansas decided not to
evaluate sources of NO3 under the four reasonable progress
factors in the October 2017 Arkansas Regional Haze NOX SIP
Revision. When focusing only on sources in Arkansas, a comparison of
the various source categories reveals that area sources do contribute a
larger proportion of total light extinction than the other source
categories. The majority of the light extinction from Arkansas area
sources is due to CM and POA, but Arkansas noted that these pollutant
species originate from many individual small sources and that the cost-
effectiveness of these controls is therefore difficult to quantify and
Arkansas therefore decided not to evaluate area sources under the four
reasonable progress factors.
Since Arkansas determined that SO4 is the key pollutant
species contributing to light extinction at Caney Creek and Upper
Buffalo on the 20% worst days and that the majority of light extinction
due to SO4 is attributed to point sources, it evaluated
point sources emitting at least 250 tons per year (tpy) of
SO2 to determine whether their emissions and proximity to
Arkansas Class I areas warrant further analysis under the four
reasonable progress factors.
We agree with Arkansas that the PSAT results for Arkansas sources
show that the relative contribution to light extinction of
SO4 on the 20% worst days at Arkansas Class I areas is not
as great compared to the regional contribution results. However,
SO4 is still the species with the largest contribution to
light extinction at Caney Creek and Upper Buffalo on the 20% worst days
in both the regional data and the Arkansas source PSAT data. We agree
with Arkansas' identification of SO4 as the key species
contributing to light extinction at Caney Creek and Upper Buffalo on
the 20% worst days. Newer IMPROVE monitoring data that has become
available after the CENRAP modeling was performed does not appear to
contradict this conclusion.\116\ We are also proposing to agree that
the primary driver of SO4 formation at Arkansas Class I
areas is SO2 emissions from point sources, both when looking
at visibility impacts from sources region-wide and also when looking at
visibility impacts only from sources in Arkansas. Arkansas' conclusions
are consistent with our finding in the Arkansas Regional Haze FIP that
the CENRAP's CAMx modeling shows that SO4 from point sources
is the driver of regional haze at Caney Creek and Upper Buffalo on the
20% worst days in both 2002 and 2018.\117\ We also agree with Arkansas'
assertion that when only sources located in Arkansas are considered,
light extinction due to area sources (all pollutant species considered)
is greater compared to the light extinction due to point sources at
both Caney Creek and Upper Buffalo on the 20% worst days in 2002. And
we agree with Arkansas that the cost of controlling many individual
small area sources may be difficult to quantify, and we are therefore
proposing to find that it is acceptable for Arkansas to choose not to
further evaluate area sources for controls under reasonable progress in
this implementation period. This is consistent with EPA's decision not
to conduct a four-factor analysis of area sources under reasonable
progress for this implementation period in the Arkansas Regional Haze
FIP.\118\ Therefore, we are proposing to find that it is appropriate
for Arkansas to focus its evaluation on point sources emitting at least
250 SO2 tpy to determine whether their emissions and
proximity to Arkansas Class I areas warrant further analysis under the
four reasonable progress factors.
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\116\ IMPROVE monitoring data for Caney Creek and Upper Buffalo,
as well as other Class I areas can be found at https://views.cira.colostate.edu/fed/QueryWizard/Default.aspx.
\117\ 80 FR 18996.
\118\ In the FIP we explained that the CENRAP CAMx modeling with
PSAT showed that point sources are responsible for a majority of the
light extinction at Arkansas Class I areas on the 20% worst days in
2002 (this is taking into account all pollutant species and sources
both in and outside Arkansas). We reasoned that since other source
types (i.e., natural, on-road, non-road, and area) each contributed
a much smaller proportion of the total light extinction at each
Class I area, it was appropriate to focus only on point sources in
our reasonable progress analysis for this implementation period. See
80 FR 18944 and 81 FR 66332 at 66336. See also the ``Arkansas
Regional Haze FIP Response to Comments (RTC) Document,'' pages 71-
99.
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2. Arkansas' Analysis of Reasonable Progress Factors Broadly Applicable
to Arkansas Sources
In addition to the four reasonable progress factors under CAA
section 169A(g)(1), ADEQ determined that visibility is also a relevant
factor for consideration in its reasonable progress analysis. ADEQ's
broad evaluation of the four reasonable progress factors plus
visibility is summarized below.
Visibility: ADEQ explained that, since restoring natural visibility
conditions in Class I areas is the central goal of the regional haze
program, it considers visibility to be the necessary context within
which to view whether additional controls are reasonable in the first
planning period. ADEQ noted that visibility has improved dramatically
in Arkansas' Class I areas since 2004, with visibility improving at a
rate more rapid than needed to meet the 2018 point on the URP and
Arkansas' Class I areas being on track to achieve natural visibility
conditions in Arkansas Class I areas by 2064. ADEQ also noted that the
observed improvement in visibility conditions has taken place even
before implementation of most of the controls included in the Arkansas
Regional Haze SO2 and PM SIP revision. ADEQ stated that the
observed visibility improvement at Arkansas Class I areas is the result
of reductions from state and federal programs, including New Source
Performance Standards for a variety of source types; vehicle emissions
standards; changes in NAAQS; innovations in emissions control
technologies; retirement or reconstruction of older facilities; and
market-driven changes in electricity generation. ADEQ stated it
anticipates
[[Page 62227]]
that the implementation of the BART controls required under the SIP
revision will further keep Arkansas Class I areas on track to achieve
natural visibility conditions on or before 2064.
ADEQ also stated that the visibility trajectory in Arkansas' Class
I areas is a relevant factor for consideration in its reasonable
progress analysis. According to ADEQ, if Arkansas Class I areas were
making less progress than necessary to achieve the URP during the first
planning period, then more costly controls could be warranted if found
reasonable after consideration of the four statutory factors and other
factors the state considers relevant. ADEQ stated that ADEQ therefore
deems it reasonable to consider that Arkansas Class I areas are already
below the 2018 point on the URP, in addition to considering the
statutory reasonable progress factors, in evaluating whether additional
controls are necessary under reasonable progress for the first
implementation period.
Costs of Compliance: ADEQ pointed out that EPA's RPG Guidance
provides that the cost of compliance factor ``can be interpreted to
encompass . . . the implication of compliance costs to the health and
vitality of industries within a state.'' \119\ Considering the
visibility trends at Arkansas' Class I areas, ADEQ determined that this
interpretation is appropriate to apply in this case. ADEQ believes that
the cost of additional controls under reasonable progress would create
a negative impact on the health and vitality of industries within the
state, and that such adverse impacts would be especially great if
additional SO2 controls were imposed on the electricity
sector. This is because under Arkansas law, energy companies are
permitted to recover costs related to the installation of emissions
controls at EGUs required under a SIP from electricity ratepayers
subject to approval by the Arkansas Public Service Commission. These
costs, in turn, would be allowed to be passed on to Arkansas
ratepayers, including a variety of industries, in the form of increased
electric rates. ADEQ believes that energy-intensive industries would be
disproportionately impacted by these costs.
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\119\ Guidance for Setting Reasonable Progress Goals under the
Regional Haze Program, June 1, 2007, memorandum from William L.
Wehrum, Acting Assistant Administrator for Air and Radiation, to EPA
Regional Administrators, EPA Regions 1-10 (p. 5-1).
---------------------------------------------------------------------------
Time Necessary for Compliance: ADEQ noted that the time necessary
for compliance varies depending on the control technology under
consideration. ADEQ stated that the time necessary for compliance for
SO2 control technologies considered for BART in the SIP
revision was typically 3-5 years, unless progress had already been made
toward implementing those control technologies.
Energy and Non-air Quality Impacts of Compliance: ADEQ stated that
the installation of additional controls, such as dry and wet scrubbers,
under reasonable progress for Arkansas EGUs may have negative impacts,
including temporary outages necessary to install the controls. Arkansas
expects that this would temporarily disrupt the supply of electricity
to the grid. Additionally, ADEQ noted that certain control technologies
can result in reduced generating capacity for EGUs, which is referred
to as parasitic load.
Furthermore, ADEQ noted that market trends for coal and natural gas
have already resulted in the decreased dispatch of coal-fired
facilities, which has in turn resulted in a decrease in overall
emissions of key pollutants that impact visibility at Arkansas Class I
areas. ADEQ cited to data from the Energy Information Administration
showing that the trend of decreased net electricity generation from
coal and increased net electricity generation from natural gas and
renewable energy is expected to continue for the remainder of the 2008-
2018 implementation period, and well beyond.
Remaining Useful Life of Potentially Affected Sources: ADEQ pointed
out that the EPA RPG Guidance provides that this factor is generally
best treated as one element of the overall cost analysis. ADEQ noted
that if the remaining useful life for a given facility is less than the
typical amortization period for new control equipment, the annualized
cost increases and the controls become less cost effective.
Additionally, ADEQ pointed out that the cost of controls may result in
a company making an economic decision to discontinue operations, thus
truncating the remaining useful life of a source.
3. Identification of Potential Sources for Evaluation of SO2
Controls Under Reasonable Progress
In identifying which sources to evaluate for SO2
controls in its reasonable progress analysis, Arkansas compiled a list
of all point sources that emitted at least 250 SO2 tpy as
reported to the EPA emissions Inventory System (EIS) in any given year
between 2002 and 2015. For sources that participate in EPA's Acid Rain
Program, Arkansas obtained SO2 emissions data for 2015 using
the Air Markets Program Data tool. Arkansas then narrowed down the list
to only those sources that emitted at least 250 tpy averaged over the
most recent 3-year period for which data is available. Arkansas
identified 11 sources that met this criterion (see Table 11).
Table 11--Point Sources in Arkansas With SO2 Emissions Greater Than 250
tpy
------------------------------------------------------------------------
Average SO2
Most recent 3- emissions
Facility year period (tpy)
------------------------------------------------------------------------
Entergy White Bluff *................... 2014-2016 24,346
Entergy Independence.................... 2014-2016 22,531
SWEPCO Flint Creek Power Plant *........ 2014-2016 5,350
Plum Point Energy Station Unit 1........ 2014-2016 2,759
FutureFuel Chemical Company............. 2013-2015 2,837
Domtar A.W. LLC, Ashdown Mill *......... 2013-2015 1,553
Evergreen Packaging--Pine Bluff......... 2013-2015 986
Albemarle Corporation--South Plant...... 2013-2015 1,382
SWEPCO John W. Turk Jr. Power Plant..... 2014-2016 908
Ash Grove Cement Company/Foreman Cement 2013-2015 369
Plant..................................
Nucor--Yamato Steel Company............. 2013-2015 301
------------------------------------------------------------------------
*These facilities are subject to BART requirements, and the state
therefore did not further consider these sources for additional
controls under reasonable progress.
[[Page 62228]]
Arkansas explained that, since White Bluff, Flint Creek, and Domtar
are subject to BART and the BART analyses conducted to determine BART
control requirements are based on an assessment of many of the same
factors that must be evaluated in determining whether additional
controls are needed under the reasonable progress provisions and thus
in establishing the RPGs, no additional controls under reasonable
progress are necessary for these sources in the first implementation
period. For the remaining sources on the list, Arkansas calculated the
total average actual emission rate (Q) in SO2 tpy over the
most recent 3-year period and determined the distance (D) in kilometers
of each source to its closest Class I area (see Table 12). Arkansas
used a ``Q divided by D'' (Q/D) value of 10 as a threshold for
identifying sources to further evaluate for reasonable progress
controls. Arkansas explained that it selected this value as a threshold
based on guidance contained in the BART Guidelines and also noted that
this is consistent with the approach used in other regional haze
actions.
Table 12--Q/D Values for Large SO2 Point Sources in Arkansas
------------------------------------------------------------------------
Q/D value
Facility -------------------------------
Upper buffalo Caney creek
------------------------------------------------------------------------
Entergy Independence.................... 126 81
Plum Point Energy Station Unit 1........ 9 7
FutureFuel Chemical Company............. 17 10
Evergreen Packaging--Pine Bluff......... 4 5
Albemarle Corporation--South Plant...... 5 9
SWEPCO John W. Turk Jr. Power Plant..... 4 11
Ash Grove Cement Company/Foreman Cement 1 5
Plant..................................
Nucor--Yamato Steel Company............. 1 1
------------------------------------------------------------------------
As shown in Table 12, Arkansas found that only three sources had a
maximum Q/D value greater than or equal to 10: Entergy Independence,
FutureFuel Chemical Company, and John W. Turk Jr. Power Plant. Arkansas
noted that Entergy Independence is the second largest point source of
SO2 emissions in Arkansas, with average 2014-2016 emissions
of 22,531 SO2 tpy. In comparison, the FutureFuel Chemical
Company and the John W. Turk Jr. Power Plant had much lower
SO2 emissions. FutureFuel Chemical Company had average 2013-
2015 SO2 emissions of 2,837 tpy, while the John W. Turk Jr.
Power Plant had average 2014-2016 SO2 emissions of 908 tpy.
Arkansas noted that SO2 emissions from the FutureFuel
Chemical Company and the John W. Turk Jr. Power Plant are approximately
an order of magnitude lower than emissions from Entergy Independence.
In addition, Arkansas noted that the FutureFuel Chemical Company was
previously identified as a BART eligible source, but was determined to
be not subject to BART in the 2008 Arkansas Regional Haze SIP based on
CALPUFF modeling performed in the development of that SIP. Therefore,
ADEQ did not find it necessary to further evaluate controls under
reasonable progress for this facility for this implementation period.
The John W. Turk Jr. Power Plant, which began operation in 2012, has
implemented best available control technology, which Arkansas noted is
more stringent than BART. Therefore, ADEQ stated that it does not
anticipate that more stringent controls would be available and/or
reasonable for this facility in the first implementation period.
Arkansas ultimately determined that since the Independence facility is
a source not subject to BART and because it was required by the
Arkansas Regional Haze FIP to install controls under reasonable
progress, this particular source warrants further consideration and
evaluation under the four reasonable progress factors.
We are proposing to find that Arkansas' overall method of
identifying sources for potential further evaluation under the four
reasonable progress factors is appropriate. We find that Arkansas'
approach of narrowing down the list of sources to further evaluate
under reasonable progress to only those sources that emitted at least
250 SO2 tpy averaged over the most recent 3-year period for
which data is available is reasonable. We agree with Arkansas that
since White Bluff and Flint Creek are subject to BART and are addressed
under this SIP revision, the BART analyses conducted to determine BART
control requirements for these sources and the determinations adopted
and incorporated by the state in this SIP revision are adequate to
eliminate these sources from further consideration of additional
controls under the reasonable progress requirements for the first
implementation period. The EPA RPG Guidance explains that the BART
analysis is based, in part, on an assessment of many of the same
factors that must be addressed in establishing the RPGs, and therefore
it is reasonable to conclude that any control requirements imposed in
the BART determination also satisfy the RPG-related requirements for
source review in the first implementation period.\120\ The guidance
provides that it is reasonable to conclude that any control
requirements imposed in the BART determination also satisfy the RPG-
related requirements for source review in the first RPG planning
period.\121\ The same rationale applies for the Domtar Ashdown Mill,
although the August 8, 2018 SIP revision does not address the BART
requirements for Domtar, which will remain satisfied by the FIP and the
2008 Arkansas Regional Haze SIP. Based on the consideration of the BART
factors and resulting determinations in that FIP and the 2008 Arkansas
Regional Haze SIP, it is reasonable for ADEQ to conclude that nothing
further is needed to address emissions from Domtar under the
requirement for reasonable progress analysis at this time. If ADEQ
chooses to submit a SIP revision to address BART requirements for
Domtar Power Boilers No. 1 and No. 2, we will evaluate that SIP
submittal, including whether it also sufficiently addresses the
reasonable progress requirements for Domtar for the first
implementation period.
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\120\ Guidance for Setting Reasonable Progress Goals Under the
Regional Haze Program, June 1, 2007, memorandum from William L.
Wehrum, Acting Assistant Administrator for Air and Radiation, to EPA
Regional Administrators, EPA Regions 1-10 (pp. 4-2, 4-3, and 5-1).
\121\ Id.
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We are proposing to find that Arkansas' use of a Q/D value of 10 as
a threshold for identifying sources to further evaluate for reasonable
progress controls is reasonable and appropriate. We agree with
Arkansas, that the FutureFuel Chemical Company was
[[Page 62229]]
found by the state to be not subject to BART in the 2008 Arkansas
Regional Haze SIP, which is a determination that was approved by EPA in
our March 2012 final action on the SIP.\122\ The FutureFuel Chemical
Company and the John W. Turk Jr. Power Plant are the fifth and ninth
largest SO2 point sources in Arkansas, based on average
annual emissions from the most recent 3-year period.\123\ In comparison
to the SO2 emissions from the 3 largest SO2 point
sources in Arkansas, emissions from these two facilities are relatively
small.\124\ Taking into consideration the significantly lower 3-year
average SO2 emissions from the FutureFuel Chemical Company
and the John W. Turk Jr. Power Plant in comparison to the Independence
Power Plant and considering that the John W. Turk Jr. Power Plant
operates best available control technology, we are proposing to find
that it is reasonable and appropriate for Arkansas to not further
evaluate these sources for controls under reasonable progress for this
planning period. We also consider it appropriate and reasonable for
Arkansas to decide to conduct an analysis of the reasonable progress
factors for the Independence facility. In particular, we consider it
appropriate to evaluate the Independence facility because it is the
second highest point source of SO2 emissions in Arkansas,
accounting for approximately 36% of the SO2 point source
emissions in Arkansas; its Q/D values as determined by ADEQ are high
(see Table 12), especially when compared to other Arkansas point
sources; and it is a source not subject to BART. Therefore, we are
proposing to agree with Arkansas' decision to evaluate the four
reasonable progress factors for the Independence facility.
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\122\ The 2008 Arkansas Regional Haze SIP showed that FutureFuel
Chemical Company had a maximum visibility impact (i.e., 1st high
value) of 0.711 dv at Hercules Glades. EPA found that closer
inspection of the visibility modeling results revealed that only
this single day out of the 3 years modeled exceeded the 0.5 dv
threshold used by ADEQ to determine if a source is subject to BART.
Since only one day modeled above the threshold, EPA found in its
final action on the 2008 Arkansas Regional Haze SIP that it is
unlikely that a refined modeling approach using updated
meteorological data, which would allow the use of the 98th
percentile visibility impact instead of the max visibility impact,
would show impacts above the 0.5 dv threshold. Therefore, EPA
concluded in our March 2012 final action on the 2008 Arkansas
Regional Haze SIP that it was not necessary to further evaluate
controls under reasonable progress for the FutureFuel Chemical
Company in the first implementation period.
\123\ See the Arkansas Regional Haze SO2 and PM SIP
Revision, Table 11.
\124\ The three largest SO2 point sources in
Arkansas, based on average annual emissions from the most recent 3-
year period, are the Entergy White Bluff Plant, Entergy Independence
Plant, and SWEPCO Flint Creek Plant (see Table 11 of the Arkansas
Regional Haze SO2 and PM SIP Revision). The Entergy White
Bluff Plant and the SWEPCO Flint Creek Plant are subject to BART and
controls for these facilities are already addressed in the SIP
revision based on ADEQ's consideration of the 5 BART factors.
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4. Arkansas' Reasonable Progress Analysis for Independence Units 1 and
2
As noted above, ADEQ determined that application of the four
factors to that specific source is also ``relevant'' in its reasonable
progress analysis as a way of addressing EPA's previous analysis.
a. Arkansas' Evaluation of the Reasonable Progress Factors for
SO2 for Entergy Independence Units 1 and 2
Section 169(A)(g)(1) of the CAA requires states to evaluate the
costs of compliance, the time necessary for compliance, the energy and
non-air quality environmental impacts of compliance, and the remaining
useful life of any potentially affected sources, when determining
reasonable progress. In its evaluation of the four reasonable progress
factors for the Independence facility, Arkansas relied on information
provided by Entergy for the Independence facility in the evaluation of
low sulfur coal and dry scrubbers. Arkansas also relied on data
developed by EPA in support of the Arkansas Regional Haze FIP in the
evaluation of wet scrubbers and dry scrubbers. The Entergy Independence
Power Plant is a coal-fired electric generating station with two
identical 900 MW boilers. The boilers burn Wyoming Powder River Basin
sub-bituminous coal as their primary fuel and No. 2 fuel oil or bio-
diesel as start-up fuel. The layout and boiler units at this facility
are similar to those at Entergy White Bluff, but since the units at
Independence were installed in 1983 (9 years after the installation of
the White Bluff units), Independence Units 1 and 2 are not BART
eligible.
There is currently no SO2 control equipment in use at
Units 1 and 2. Arkansas noted that the Independence units are subject
to a prevention of significant deterioration (PSD) emission limit of
0.93 lb/MMBtu. Arkansas also noted that market trends for coal and
natural gas have resulted in decreased dispatch of the Independence
units, which has resulted in reduced emissions from the facility. The
available SO2 control technology options considered in
Arkansas' analysis are as follows: Switching to coal with a lower
sulfur content, dry FGD, and wet FGD, all of which Arkansas identified
as being technically feasible. Switching to coal with a sulfur content
of 0.6 lb/MMBtu (referred to herein as low sulfur coal) is expected to
result in a 4 to 6% reduction in SO2 emissions from 2009-
2013 levels. Dry FGD systems typically have SO2 control
efficiencies ranging from 60 to 95% control, while wet FGD is typically
capable of achieving 80 to 95% control of SO2 emissions.
Degree of Improvement in Visibility: Although the degree of
visibility improvement is not one of the four statutory factors that
must be evaluated in a reasonable progress analysis, as noted above,
Arkansas chose to consider visibility improvement since the ultimate
goal of any controls under reasonable progress is to achieve visibility
improvements. For switching to low sulfur coal, Entergy submitted
CALPUFF modeling that estimated the visibility benefit of switching to
low sulfur coal for Independence Units 1 and 2. This modeling showed
that switching to low sulfur coal is anticipated to result in
visibility improvements of 0.112 dv at Caney Creek and 0.236 dv at
Upper Buffalo. For dry scrubbers, Arkansas relied on the visibility
improvement estimates from the modeling conducted by EPA for the
Arkansas Regional Haze FIP. Arkansas noted that the installation of dry
FGD at Independence Units 1 and 2 is anticipated to result in
visibility improvements of 1.096 dv at Caney Creek and 1.178 dv at
Upper Buffalo.\125\ As discussed above, Arkansas also estimated that
the cost in terms of dollars per deciview of dry FGD at Independence
Units 1 and 2 ranges from $63,580,175/dv to $71,672,197/dv at each of
the four affected Class I areas (see Table 13).
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\125\ We note that in the SIP revision, ADEQ relied on EPA's
visibility modeling from the FIP for dry scrubbers at the
Independence facility. In that visibility modeling, EPA modeled two
baseline scenarios: (1) The BASE case emission rates for
NOX and SO2 were from the maximum actual 24-
hour emissions during the 2001-2003 period; and (2) the BASE 2 case
emission rates for SO2 were based on the maximum actual
24-hour emissions during the 2001-2003 period and the NOX
emissions were based on the maximum 24-hour emissions during the
2011-2013 period. Entergy's CALPUFF modeling for low sulfur coal at
the Independence facility was based on a 2011-2013 baseline period
for modeled emission rates. While Entergy's baseline for low sulfur
coal differed from the two baselines modeled by EPA for dry
scrubbers, ADEQ stated they do not expect that the difference would
substantially impact the comparison of the visibility benefits among
controls evaluated.
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Remaining Useful Life: Since there are no state- or federally-
enforceable limitations on continued operations at the Independence
facility, Arkansas' cost analysis for SO2 controls assumed a
30-year amortization period for dry
[[Page 62230]]
FGD and wet FGD.\126\ However, Arkansas acknowledged Entergy's
intention, as stated in comments to Arkansas regarding the draft SIP,
to cease coal combustion at Independence Units 1 and 2 by the end of
2030. In addition, Arkansas noted that market pressures may also impact
continued operations at the Independence facility, including changes in
dispatch and economic decisions concerning the continued viability of
the units. Therefore, Arkansas recognized that the amortization period
of controls may end up being less than the 30 years assumed in
Arkansas' cost analysis, potentially resulting in the controls being
less cost effective than estimated in the analysis.
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\126\ As explained above, Entergy annualized the capital cost of
controls on the Independence facility assuming a 9-year amortization
period, based on Entergy's plans for ceasing coal combustion at
Independence by the end of 2030. However, given that Entergy's plans
to cease coal combustion by the end of 2030 are not state or
federally-enforceable, ADEQ re-calculated the cost-effectiveness of
controls by annualizing the capital cost of controls assuming a 30-
year amortization period.
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Costs of Compliance: In considering the costs of compliance,
Arkansas noted that switching to low sulfur coal has no associated
capital costs, but there would be a cost associated with guaranteeing
that the sulfur content remains below 0.6 lb/MBtu. Arkansas stated it
calculated cost estimates for switching to low sulfur coal using
information provided by Entergy regarding cost premiums for low sulfur
coal, U.S. Energy Information Administration fuel consumption data, and
EPA Air Markets Program Data. Arkansas estimated that the annualized
operation and maintenance costs of switching to low sulfur coal is $1.6
million for Unit 1 and $1.7 million for Unit 2.\127\ Arkansas estimated
that the cost effectiveness of switching to low sulfur coal is
approximately $2,437/ton for Unit 1 and $2,345/ton for Unit 2.
---------------------------------------------------------------------------
\127\ ADEQ calculated annualized operation and maintenance costs
of switching to low sulfur coal by multiplying average annual fuel
consumption in tons for the years 2009-2013 by the $0.50/ton cost
premium Entergy was quoted by its coal supplier, per Entergy's
August 18, 2017, SO2 BART analysis for White Bluff. ADEQ
obtained annual fuel consumption data for the years 2009-2013 from
U.S. Energy Information Administration Form EIA-923.
---------------------------------------------------------------------------
In contrast to switching to low sulfur coal, the installation of
dry FGD and wet FGD is expected to require a large capital investment.
Entergy provided Arkansas with Independence-specific cost estimates for
dry scrubbers for use in Arkansas' cost analysis. Entergy estimated
total capital costs of dry scrubbers at Independence to be $491,893,500
per unit based on ``actual costs'' and $355,391,500 per unit based on
costs allowed under EPA's Control Cost Manual. Entergy annualized the
capital cost for both sets of numbers assuming a 9-year amortization
period, based on Entergy's plans to cease coal combustion at
Independence by the end of 2030. Additionally, Entergy based its
calculations of SO2 emissions reductions based on a 2009-
2013 baseline. In the SIP revision, ADEQ based its evaluation of the
cost of dry scrubbers on the set of capital costs that reflect the
costs allowed under EPA's Control Cost Manual, and also assumed a 30-
year amortization period in its calculation of the cost-effectiveness
of dry scrubbers. Based on these assumptions, Arkansas estimated that
the cost-effectiveness of dry scrubbers is $2,970/ton for Unit 1 and
$2,742/ton for Unit 2.
Since Entergy did not provide Independence-specific cost estimates
for wet scrubbers for Arkansas to base its cost analysis on, Arkansas
relied on the cost estimates for Independence developed by EPA in the
Arkansas Regional Haze FIP.\128\ Based on a 30-year amortization
period, our FIP estimated wet FGD to cost $3,706/ton at Unit 1 and
$3,416/ton at Unit 2. Arkansas noted that in the Arkansas Regional Haze
FIP, EPA eliminated wet scrubbers due to the high incremental cost-
effectiveness but small incremental visibility benefit of wet scrubbers
compared to dry scrubbers. Therefore, consistent with EPA's action in
the FIP, ADEQ found that wet FGD did not warrant further consideration
in its analysis.
---------------------------------------------------------------------------
\128\ See 80 FR 18992-18993. See also the Arkansas Regional Haze
SO2 and PM SIP Revision, Appendix F.
---------------------------------------------------------------------------
In addition to considering cost-effectiveness calculations in the
cost analysis, Arkansas found that other cost-related factors were of
relevance in its evaluation of the reasonable progress factors for the
Independence facility. This includes total capital costs, cost to
Arkansas communities, and the cost in terms of dollar per dv
improvement in visibility anticipated from the control options
evaluated ($/dv). Arkansas considered the capital costs of dry
scrubbers and wet scrubbers to be high, even though the costs in terms
of $/ton of SO2 emissions reduced for both dry and wet
scrubbers (assuming a 30-year remaining useful life) are within a range
that has been found to be cost effective in other regional haze
actions. In addition, acknowledging Entergy's anticipated cessation of
coal combustion at the Independence facility, although it is not state-
or federally-enforceable, Arkansas noted that assuming a 9-year
remaining useful life would likely result in scrubber controls no
longer being cost-effective. In light of this, Arkansas considered it
important to take into account the capital cost of controls along with
the cost-effectiveness in terms of dollars per ton of emissions
reduced. Arkansas also noted that these costs would be passed on to
Arkansas ratepayers. Finally, Arkansas also took into account that the
$/dv improvement in visibility for dry scrubbers is a little over 2
times higher than for low sulfur coal at Caney Creek and between 5 and
6 times higher at Upper Buffalo and the 2 Missouri Class I areas (see
Table 13). Arkansas noted that consideration of the cost in terms of $/
dv improvement demonstrates a greater disparity in costs among the
control options compared to consideration of the cost in terms of $/ton
reduced. Arkansas concluded that all the control options considered
would result in millions of dollars spent to achieve what it considers
to be little visibility benefit.
Table 13--Cost of SO2 Controls ($/dv) for Independence Units 1 and 2
----------------------------------------------------------------------------------------------------------------
Class I Area
---------------------------------------------------------------
SO2 control option Hercules
Caney Creek Upper Buffalo Glades Mingo
----------------------------------------------------------------------------------------------------------------
Low Sulfur Coal................................. $29,469,780 $10,929,190 $13,985,658 $12,179,393
Dry FGD......................................... 68,337,085 63,580,175 70,925,611 71,672,197
----------------------------------------------------------------------------------------------------------------
Time Necessary for Compliance: Arkansas explained that the typical
time necessary for compliance for dry FGD and wet FGD is 5 years.
Considering the time left on existing coal supply contracts between
Entergy and its coal
[[Page 62231]]
supplier, the time required to burn through current fuel stocks, and
the time needed to build a stockpile of low sulfur coal to assure
against potential fuel supply disruptions, Entergy informed Arkansas
that the time necessary to comply with an SO2 emission limit
based on low sulfur coal is estimated to be 3 years.
Energy and Non-air Quality Environmental Impacts of Compliance:
Arkansas noted that dry FGD utilizes lime slurry to remove
SO2 from flue gas and that in the process, particulate
matter is generated that must be controlled through the use of a
baghouse or ESP. Once collected, the waste material is disposed of
through landfilling. Arkansas noted that the costs associated with
control of particulate matter and additional power requirements were
factored into the cost estimates used in its analysis. Arkansas
determined that Entergy has not indicated unusual circumstances that
would create greater problems than experienced in other cases where dry
FGD has been utilized to meet regional haze requirements. Arkansas also
noted that switching to low sulfur coal is not anticipated to result in
any adverse energy or non-air environmental impacts.
b. Arkansas' Determination Regarding Reasonable Progress Requirements
for Independence
Based on its evaluation of the reasonable progress factors for the
Independence facility, ADEQ arrived at the conclusion that no
additional controls are necessary for reasonable progress during the
first implementation period. According to ADEQ, the controls it
evaluated would cost millions of dollars annually, which would be
passed on to Arkansas ratepayers, for what ADEQ considers to be little
visibility benefit when Arkansas' Class I areas are already making more
progress than the URP.
Although ADEQ concluded that none of the controls evaluated for the
Independence facility are necessary for achieving reasonable progress
in the first planning period, ADEQ acknowledged Entergy's intention to
switch to low sulfur coal at Independence Units 1 and 2 within the next
3 years. ADEQ noted that this measure would strengthen the SIP and
result in some visibility benefit at Arkansas' Class I areas, while
having no associated capital costs. According to ADEQ, the lack of any
capital costs will provide Entergy with flexibility regarding the
company's planned cessation of coal combustion at the Independence
facility by the end of 2030. Therefore, Entergy's commitment to switch
to low sulfur coal at Independence Units 1 and 2 has now been made
enforceable by ADEQ as part of the long-term strategy for this
implementation period, through an Administrative Order that has been
adopted and incorporated in the SIP revision. The Administrative Order
requires Independence Units 1 and 2 to meet an SO2 emission
limit of 0.60 lb/MMBtu no later than 3 years from the effective date of
the Administrative Order, which is August 7, 2018.\129\
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\129\ The Administrative Order can be found in the Arkansas
Regional Haze SO2 and PM BART SIP Revision.
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5. Arkansas' Determination Regarding Additional Controls Necessary
Under Reasonable Progress and Revised RPGs
After consideration of the statutory reasonable progress factors,
along with an evaluation of the monitored trajectory of visibility
impairment during the first implementation period, particulate source
apportionment data, and SO2 emissions relative to proximity
to Arkansas Class I areas, Arkansas determined that no additional
controls beyond BART and other Clean Air Act programs are necessary
under the reasonable progress provisions for the first implementation
period. Based on its analysis of the reasonable progress factors in the
context of both the analysis of a group of sources as well as the
source-specific analysis that applied the reasonable progress factors
specifically to the Independence facility, Arkansas determined that all
the evaluated controls would result in the expenditure of millions of
dollars annually for what the state considers to be little visibility
benefit. In addition, the costs of any control requirements would be
passed on to Arkansas citizens and businesses through electricity rate
increases. Arkansas deems that these costs are not warranted under
reasonable progress given that Arkansas Class I areas are well below
their respective 2018 URPs. Arkansas believes that its reasonable
progress determination is consistent with EPA's decision to establish a
64-year lifespan for the regional haze program, which is broken down
into several 10-year implementation periods. Arkansas stated that the
way the regional haze program was set up allows for a fresh look at the
changing landscape of sources that impact visibility and potential
controls every 10 years. Arkansas noted that the EPA Reasonable
Progress Guidance provides that it is reasonable for states to defer
reductions to later planning periods in order to maintain a consistent
glidepath toward the long-term goal of natural visibility conditions.
Therefore, Arkansas determined that no SO2 or PM controls
beyond BART are necessary for reasonable progress during the first
implementation period.
To reflect the control measures required in the Arkansas Regional
Haze SO2 and PM SIP revision and the Arkansas Regional Haze
NOX SIP revision, which was approved by EPA in a prior
action,\130\ Arkansas revised the RPGs for the 20% worst days for Caney
Creek and Upper Buffalo that it had previously established in the 2008
Arkansas Regional Haze SIP. Arkansas did not revise its RPGs for the
20% best days included in the 2008 Arkansas Regional Haze SIP. In order
to provide RPGs for the 20% worst days that account for emissions
reductions from its SIP revisions, Arkansas utilized a method that is
based on a scaling of modeled light extinction components in proportion
to emissions changes anticipated from SIP controls for which compliance
is required on or before December 31, 2018. Arkansas noted that this is
the same method utilized by EPA to revise the RPGs in the Arkansas
Regional Haze FIP. Arkansas scaled CENRAP's CAMx 2018 projection of
light extinction components for SO4 and NO3 in
proportion to the SIP revisions' emission reductions for SO2
and NOX from the CENRAP modeled 2018 emissions. Arkansas
decided to use the most recent 3 years of data (2014-2016) as opposed
to EPA's method in the Arkansas FIP, which involved using the 5 most
recent years of data (2009-2013) with the exclusion of the minimum and
maximum values. Arkansas explained that this was done to ensure that
recent changes in dispatch at Arkansas EGUs were captured. Arkansas'
revised RPGs for Caney Creek and Upper Buffalo are presented in Table
14.
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\130\ 83 FR 5927.
Table 14--Arkansas' Revised 2018 RPGs for Caney Creek and Upper Buffalo
------------------------------------------------------------------------
2018 RPG 20%
Class I area worst days
(dv)
------------------------------------------------------------------------
Caney Creek............................................. 22.47
Upper Buffalo........................................... 22.51
------------------------------------------------------------------------
6. EPA's Evaluation and Conclusions on Arkansas' Reasonable Progress
Analysis and Revised RPGs
As noted above, as part of its reasonable progress analysis,
Arkansas
[[Page 62232]]
conducted both a broad source analysis and a source-specific analysis
that evaluated the four statutory factors for the Independence
facility. The former analysis was ``broad'' in the sense that it did
not quantify costs or visibility benefits for any particular source or
source category, and discussed anticipated visibility benefits and
costs in only general terms. We agree that an approach that involves a
broad analysis of groups of sources or source categories may be
appropriate in certain cases, as provided by EPA's RPG Guidance.
However, we believe that the broad analysis of a group of sources
provided by ADEQ does not clearly identify what sources or controls
were evaluated in the state's weighing of the costs and other statutory
factors. While informative, we find that the state's broad analysis of
a group of sources was not a determinative component of the state's
reasonable progress analysis given that the state's determination was
also informed by an evaluation of large point sources individually to
identify sources for potential further evaluation under the four
reasonable progress factors and by a more narrow and focused analysis
conducted for those sources identified, specifically the Independence
facility, which included consideration of various control options and
weighing of costs and the other statutory factors.
We are proposing to find that the reasonable progress requirements
under section 51.308(d)(1) have been fully addressed for the first
regional haze planning period. Specifically, we are proposing to find
that the following components of Arkansas' analysis satisfy the
reasonable progress requirements: Arkansas' discussion of the key
pollutants and source categories that contribute to visibility
impairment in Arkansas Class I areas based on the CENRAP's source
apportionment modeling; the identification of a group of large
SO2 point sources for potential consideration of controls
under reasonable progress and the eventual narrowing down of the list
to the Independence facility; \131\ and the evaluation of the four
reasonable progress factors for SO2 controls on the
Independence facility.
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\131\ As explained elsewhere in this notice, ADEQ relied on the
fact that a FIP is in place to satisfy the BART requirements for the
Domtar Ashdown Mill to find that nothing further is needed to
address the reasonable progress requirements with regard to this
source for the first implementation period. EPA is proposing to
agree that it is appropriate to rely on the FIP in this manner.
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We are proposing to agree with Arkansas' cost analysis for dry
scrubbers and switching to low sulfur coal for Independence Units 1 and
2, and with the state's decision to assume a 30-year capital cost
recovery period in the cost analysis. It is appropriate to assume a 30-
year capital cost recovery period in the cost analysis since Entergy's
plans to cease coal combustion at the Independence facility are not
state or federally-enforceable. We also agree with Arkansas' estimates
of the cost of dry scrubbers, and note that the state's estimates of
the cost effectiveness of dry scrubbers for Units 1 and 2 are very
similar to the cost effectiveness estimates we developed in the
Arkansas Regional Haze FIP.\132\
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\132\ Compare Arkansas' estimates of the cost effectiveness of
dry scrubbers for the Independence facility ($2,970/ton for Unit 1
and $2,742/ton for Unit 2) with EPA's estimates of the cost
effectiveness of dry scrubbers for the facility ($2,853/ton for Unit
1 and $2,634/ton for Unit 2). See 81 FR 66352.
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Since the White Bluff and Independence facilities are sister
facilities with nearly identical units and comparable levels of annual
SO2 emissions, and since both DSI and enhanced DSI were
evaluated in the BART analysis for White Bluff Units 1 and 2, we
believe it would be appropriate to consider these controls in the four-
factor analysis for the Independence facility as well. However, neither
the SIP revision nor Entergy's four factor analysis for controls on the
Independence facility considered DSI or enhanced DSI as control
options. Therefore, relying on Entergy's estimates of the capital costs
and annual operation and maintenance costs for DSI and enhanced DSI for
White Bluff Units 1 and 2 from Entergy's August 18, 2017, White Bluff
BART analysis,\133\ and assuming a 30-year equipment life, we estimate
the cost-effectiveness of DSI at the Independence facility to be
approximately $4,963/SO2 ton removed for Unit 1 and $4,593/
SO2 ton removed for Unit 2.\134\ We estimate the cost-
effectiveness of enhanced DSI to be approximately $4,951/SO2
ton removed for Unit 1 and $4,581/SO2 ton removed for Unit
2.\135\ Based on our cost estimates for DSI, we find that DSI is less
cost-effective than dry scrubbers or wet scrubbers for Independence
Units 1 and 2.\136\ Although the anticipated visibility benefits of DSI
at the Independence facility were not modeled, we expect that these
would be less than that for dry scrubbers or wet scrubbers, since DSI
and enhanced DSI typically have a lower SO2 removal
efficiency than scrubber controls. Further, we expect that the
installation and operation of DSI or enhanced DSI would likely present
the same potential issues discussed by Entergy in its SO2
BART analysis for White Bluff. Specifically, Entergy stated that before
DSI technology could be selected as BART for White Bluff, a
demonstration test would need to be performed to confirm its
feasibility, achievable performance, and balance of plant impacts
(brown plume formation, ash handling modifications, landfill/leachate
considerations, and impact to mercury control). In addition, Entergy
claimed that DSI has not yet been demonstrated on units comparable to
those at White Bluff. Because of the similarities between the White
Bluff and Independence facilities, we expect that these same potential
issues related to the installation and operation of DSI or enhanced DSI
would also apply to the Independence facility. In light of all this, we
expect that even if ADEQ had considered DSI and enhanced DSI in its
reasonable progress analysis for the Independence facility, it likely
would not have changed the state's final determination on reasonable
progress. Therefore, under these particular circumstances, we do not
consider the omission of consideration of DSI and enhanced DSI as
control options for SO2 at the Independence facility an
impediment to approving the reasonable progress analysis.
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\133\ We are relying on Entergy's ``adjusted costs,'' which
reflect Entergy's exclusion of line items not allowed under EPA's
Control Cost Manual. See ``Entergy Updated BART Five-Factor Analysis
for Units 1 and 2,'' dated August 18, 2017, Table 4-4. This analysis
is found under Appendix D of the Arkansas Regional Haze
SO2 and PM SIP revision.
\134\ See the file titled ``EPA Cost Calcs_DSI and enhanced
DSI_Independence.xlsx,'' which can be found in the docket for this
proposed rulemaking.
\135\ Id.
\136\ This is based on a comparison of our cost estimates for
DSI with Entergy's cost estimates for dry scrubbers and the FIP's
cost estimates for wet scrubbers for Independence Units 1 and 2.
Entergy's cost estimates for dry scrubbers and the FIP's cost
estimates for wet scrubbers for Independence Units 1 and 2 are
discussed earlier in this notice under Section II.C.4.a.
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In its reasonable progress analysis for the Independence facility,
the statutory factor that appears to have been the most significant in
Arkansas' reasonable progress determination is the cost of compliance,
as well as visibility, which the state deemed to be a relevant factor
for consideration in its analysis. Arkansas discussed its concerns
regarding the significant capital cost of scrubber controls, noted that
the evaluation of the $/dv metric demonstrated a greater difference in
cost between dry FGD and low sulfur coal compared to the $/ton metric,
and ultimately concluded that all the controls it evaluated would cost
millions of dollars for what it considers to be little visibility
benefit. We believe
[[Page 62233]]
that Arkansas' weighing of the four statutory factors and other factors
it deemed relevant in its reasonable progress analysis for the
Independence facility was reasonable. Considering the state's concerns
about the high capital costs and high $/dv of the evaluated controls
and given that the state is requiring Independence Units 1 and 2 to
switch to low sulfur coal within 3 years under the long-term strategy,
which is expected to reduce SO2 emissions and result in
visibility improvements at Arkansas' Class I areas, it is not
unreasonable for Arkansas to conclude that SO2 controls
under the reasonable progress requirements are not necessary for the
Independence facility in the first implementation period. We are
proposing to fully approve Arkansas' focused reasonable progress
analysis, which applied the four statutory factors directly to the
Independence facility, and its determination that no additional
controls under the reasonable progress requirements are necessary to
achieve reasonable progress for the first implementation period. Our
proposed approval is based on the following: (1) The state's discussion
of the key pollutants and source categories that contribute to
visibility impairment in Arkansas' Class I areas per the CENRAP's
source apportionment modeling; (2) the state's identification of a
group of large SO2 point sources in Arkansas for potential
evaluation of controls under reasonable progress; (3) the state's
rationale for narrowing down its list of potential sources to evaluate
under the reasonable progress requirements; \137\ and (4) the state's
evaluation and reasonable weighing of the four statutory factors along
with consideration of the visibility benefits of controls for the
Independence facility.
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\137\ As explained above, part of ADEQ's basis for determining
the sources for which to conduct a narrow reasonable progress
analysis was that certain sources were subject to BART analyses and
determinations in the first implementation period. For the Domtar
facility in particular, the state relied on the fact that a FIP is
in place to address the BART requirements. We propose to agree that
this is an appropriate basis on which find that nothing further is
needed for reasonable progress at this source. If, in the future,
Arkansas submits a further SIP revision addressing the Domtar
Ashdown Mill, EPA will evaluate whether the analysis and
determinations therein satisfy the reasonable progress requirements
as well as BART.
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We are also proposing to find that the method used by Arkansas to
estimate revised 2018 RPGs for the 20% worst days for Caney Creek and
Upper Buffalo is appropriate. We agree with Arkansas that this is the
same method utilized by us to revise the RPGs in the Arkansas Regional
Haze FIP. We are also proposing to find that Arkansas' use of the most
recent 3 years of data (2014-2016) as opposed to use of the 5 most
recent years of data (2009-2013) with the exclusion of the minimum and
maximum values, as we used in the Arkansas FIP, is appropriate because
it reflects updated data and we also agree with Arkansas that it will
ensure that recent changes in dispatch at Arkansas EGUs are captured.
Therefore, we are proposing to agree with Arkansas' revised 2018 RPGs
of 22.47 dv for Caney Creek and 22.51 dv for Upper Buffalo.
As discussed elsewhere in this proposed rulemaking, BART controls
for Domtar Power Boilers No. 1 and 2 are not addressed in the Arkansas
Regional Haze SO2 and PM SIP Revision, and we are not
proposing to withdraw the FIP's BART emission limits for the facility
at this time. If and when ADEQ submits a SIP revision to address BART
requirements for Domtar Power Boilers No. 1 and No. 2, we will evaluate
any conclusions ADEQ has drawn in that submission with respect to the
need to conduct a reasonable progress analysis for Domtar. As long as
the BART requirements for Domtar continue to be addressed by the
measures in the FIP, however, we propose to agree with ADEQ's
conclusion that nothing further is needed to satisfy the reasonable
progress requirements for the first implementation period. With respect
to the RPGs for Arkansas' Class I areas, if and when ADEQ submits a SIP
revision addressing Domtar, we will assess that future SIP revision to
determine if changes are needed based on any differences between the
SIP-based measures and the measures currently contained in the FIP.
D. Long-Term Strategy
Section 169A(b) of the CAA and 40 CFR 51.308(d)(3) require that
states include in their SIPs a 10 to 15-year strategy, referred to as
the long-term strategy, for making reasonable progress for each Class I
area within their state. This long-term strategy 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 for a
particular Class I area. The long-term strategy must include
``enforceable emissions limitations, compliance schedules, and other
measures as necessary to achieve the reasonable progress goals'' for
all Class I areas within, or affected by emissions from, the
state.\138\
---------------------------------------------------------------------------
\138\ 40 CFR 51.308(d)(3).
---------------------------------------------------------------------------
Section 51.308(d)(3)(v) requires that a state consider certain
elements in developing its long-term strategy for each Class I area.
These considerations are the following: (1) Emission reductions due to
ongoing air pollution control programs, including measures to address
reasonably attributable visibility impairment (RAVI); (2) measures to
mitigate the impacts of construction activities; (3) emissions
limitations and schedules for compliance to achieve the reasonable
progress goal; (4) source retirement and replacement schedules; (5)
smoke management techniques for agricultural and forestry management
purposes including plans as currently exist within the state for these
purposes; (6) enforceability of emissions limitations and control
measures; and (7) the anticipated net effect on visibility due to
projected changes in point, area, and mobile source emissions over the
period addressed by the long-term strategy. Since states are required
to consider emissions limitations and schedules of compliance to
achieve the RPGs for each Class I area, the BART emission limits that
are in a state's regional haze SIP are elements of the state's long-
term strategy for each Class I area. In our March 12, 2012, final
action on the 2008 Arkansas Regional Haze SIP, since we disapproved a
portion of Arkansas' BART determinations for Arkansas' two Class I
areas, we also disapproved the corresponding emissions limitations and
schedules of compliance elements of the state's long-term strategy,
while approving remaining elements under section 51.308(d)(3)(v).
As discussed above, the state is making enforceable Entergy's
commitment to switch Independence Units 1 and 2 to low sulfur coal and
comply with an SO2 emission limit of 0.60 lb/MMBtu within 3
years as part of the long-term strategy. We are proposing to approve
Arkansas' decision to make enforceable the 0.60 lb/MMBtu SO2
emission limit for Independence Units 1 and 2 as part of the long-term
strategy and we are also proposing to approve the other components of
the long-term strategy addressed by the August 8, 2018 SIP revision. We
are proposing to find that Arkansas' long-term strategy is approved
with respect to sources other than the Domtar Ashdown Mill. Because we
disapproved the majority of ADEQ's 2008 BART determinations for the
Domtar facility and promulgated a FIP to satisfy these requirements,
the corresponding components of the long-term strategy for Domtar are
also currently satisfied by the FIP. No further action by ADEQ is
required at this time; the Domtar-related components will remain
covered by the FIP and the approved portion of the 2008 Arkansas
Regional Haze SIP unless and until EPA
[[Page 62234]]
has received and approved a SIP revision containing the required
analyses and determinations for this facility.
E. Required Consultation
The Regional Haze Rule requires states to provide the designated
Federal Land Managers (FLMs) with an opportunity for consultation at
least 60 days prior to holding any public hearing on a SIP revision for
regional haze for the first implementation period. Arkansas sent
letters to the FLMs on October 27, 2017, providing notification of the
proposed SIP revision and providing electronic access to the draft SIP
revision and related documents.\139\ ADEQ also engaged in telephone
communications with the FLMs and considered and addressed comments
submitted by the FLMs on the proposed SIP revision.\140\
---------------------------------------------------------------------------
\139\ See Arkansas Regional Haze SO2 and PM SIP
revision, Tab E.
\140\ ADEQ included copies of correspondence with the FLM's,
included comments received from the FLMs in Tab E of the Arkansas
Regional Haze SO2 and PM SIP revision.
---------------------------------------------------------------------------
The Regional Haze Rule at section 51.308(d)(3)(i) also provides
that if a state has emissions that are reasonably anticipated to
contribute to visibility impairment in a Class I area located in
another state, the state must consult with the other state(s) in order
to develop coordinated emission management strategies. Since Missouri
has two Class I areas impacted by Arkansas sources, Arkansas sent a
letter to the Missouri Department of Natural Resources (MDNR) on
October 27, 2017, providing notification of the proposed SIP revision
and providing electronic access to the draft SIP revision and related
documents.\141\ Missouri did not provide comments to Arkansas on the
proposed SIP revision.
---------------------------------------------------------------------------
\141\ See Arkansas Regional Haze SO2 and PM SIP
revision, Tab E.
---------------------------------------------------------------------------
We are proposing to find that Arkansas provided an opportunity for
consultation to the FLMs and to Missouri on the proposed SIP revision,
as required under section 51.308(i)(2) and 51.308(d)(3)(i). We are also
proposing to find that Arkansas has appropriately considered and
provided written responses to comments from the FLMs in the final SIP
submission. Therefore, we are proposing to find that Arkansas has
satisfied the consultation requirements under sections 51.308(i)(2) and
51.308(d)(3)(i).
F. Interstate Visibility Transport Under Section 110(a)(2)(D)(i)(II)
The SIP revision also includes a discussion on interstate
visibility transport. Specifically, the SIP revision discusses the
impacts of Arkansas sources on Missouri's Class I areas, as well as the
most recent IMPROVE monitoring data for Missouri's Class I areas. The
SIP revision concludes that Missouri is on track to achieve its
visibility goals, that the visibility progress observed indicates that
sources in Arkansas are not interfering with the achievement of
Missouri's RPGs for Hercules Glades and Mingo, and that no additional
controls on sources within Arkansas are necessary to ensure that other
states' visibility goals for their Class I areas are met. We are
deferring proposing action on the interstate visibility transport
portion of the SIP revision until a future proposed rulemaking.
G. Clean Air Act Section 110(l)
Section 110(l) of the CAA states that ``[t]he Administrator shall
not approve a revision of a plan if the revision would interfere with
any applicable requirement concerning attainment and reasonable further
progress or any other applicable requirement of this chapter.'' We
believe an approval of the Arkansas Regional Haze SO2 and PM
SIP revision and concurrent withdrawal of the corresponding parts of
the FIP, as proposed, will meet the Clean Air Act's 110(1) provisions
concerning attainment and maintenance. No areas in Arkansas are
currently designated nonattainment for any NAAQS pollutants. As all
areas in Arkansas are attaining the NAAQS with current emissions
levels, further reductions from current emission levels because of
compliance with the emission limits contained in this SIP revision will
not interfere with attainment or maintenance. The SIP will result in
emission reductions beyond the status quo.
Additionally, we do not believe an approval of the Arkansas
Regional Haze SO2 and PM SIP revision and concurrent
withdrawal of the corresponding parts of the FIP would interfere with
the CAA requirements for BART or reasonable progress because our
proposed approval of the SIP revision is supported by our evaluation of
the state's conclusions and our rationale explaining why we are
proposing to find that the BART and reasonable progress requirements
under the CAA are met, as discussed under sections II.B and II.C of
this notice. With respect to BART requirements, the SIP would replace
federal determinations regarding SO2 and PM control
requirements for EGUs in Arkansas with the state's own determinations.
We do note that the majority of the state's SO2 and PM BART
determinations in the SIP revision are essentially identical to the
BART determinations contained in the Arkansas Regional Haze FIP. The
only exception to this is White Bluff Units 1 and 2, for which the FIP
requires an SO2 emission limit of 0.06 lb/MMBtu with a 5-
year compliance date, based on the installation of dry scrubbers. The
Arkansas Regional Haze SO2 and PM SIP revision does not
require the SO2 emission limit of 0.06 lb/MMBtu, but it does
require that Entergy move forward with its announced plans to cease
coal combustion at White Bluff Units 1 and 2 by the end of 2028 and to
meet an interim SO2 emission limit of 0.60 lb/MMBtu prior to
ceasing coal combustion. Once the units cease coal combustion,
SO2 emissions from White Bluff Units 1 and 2 are expected to
significantly decrease. Therefore, we expect that the BART controls
contained in the SIP revision are comparable to the BART controls
required under the FIP in the long term. More importantly, our proposed
approval of the SIP revision does not violate CAA section 110(l) with
respect to BART requirements because the state's BART decisions in the
SIP revision, which we are proposing to approve, are adequately
supported by BART five factor analyses that have been adopted and
incorporated into the SIP revision.
With respect to reasonable progress, we are proposing to approve
Arkansas' determination that no additional controls under the
reasonable progress requirements are necessary to achieve reasonable
progress for the first implementation period. In contrast to the
Arkansas Regional Haze FIP, the Arkansas Regional Haze SO2
and PM SIP revision does not require an SO2 emission limit
of 0.06 lb/MMBtu with a 5-year compliance date for Independence Units 1
and 2 based on the installation of dry scrubber controls under the
reasonable progress requirements. Nevertheless, as discussed in Section
II.C of this notice, we are proposing to find that the reasonable
progress requirements under section 51.308(d)(1) have been fully
addressed for the first implementation period, based on Arkansas'
discussion of the key pollutants and source categories that contribute
to visibility impairment in Arkansas' Class I areas per the CENRAP's
source apportionment modeling; its identification of a group of large
SO2 point sources in Arkansas for potential evaluation of
controls under reasonable progress; the state's rationale for narrowing
down its list of potential sources to evaluate under the reasonable
progress requirements; and its analysis
[[Page 62235]]
with reasonable weighing of the four statutory factors along with
consideration of the visibility benefits of controls for the
Independence facility. Therefore, even though the SIP revision would
allow for an increase in SO2 emissions from the Independence
facility compared to the FIP, our proposed approval of the SIP revision
and concurrent withdrawal of the corresponding parts of the FIP does
not violate CAA section 110(l) with respect to reasonable progress
because we are proposing to find that Arkansas has provided a reasoned
basis to support its determination that the scrubber controls are not
needed for reasonable progress.
III. Proposed Action
A. Arkansas Regional Haze SIP Revision
The EPA is proposing to approve the following revisions to the
Arkansas Regional Haze SIP submitted to EPA on August 8, 2018: The
SO2 and PM BART requirements for the AECC Bailey Plant Unit
1; the SO2 and PM BART requirements for the AECC McClellan
Plant Unit 1; the SO2 BART requirements for Flint Creek
Plant Boiler No. 1; the SO2 BART requirements for the White
Bluff Plant Units 1 and 2; the SO2, NOX, and PM
BART requirements for the White Bluff Auxiliary Boiler; and the
prohibition on burning of fuel oil at Lake Catherine Unit 4 until
SO2 and PM BART determinations for the fuel oil firing
scenario are approved into the SIP by EPA. These BART requirements have
now been made enforceable by the state through Administrative Orders
that have been adopted and incorporated in the SIP revision. We are
proposing to approve these Administrative Orders as source-specific
BART revisions to the SIP. The BART requirements and associated
Administrative Orders are listed under Table 15 below. We are proposing
to withdraw our February 12, 2018,\142\ approval of Arkansas' reliance
on participation in the CSAPR ozone season NOX trading
program to satisfy the NOX BART requirement for the White
Bluff Auxiliary Boiler given that Arkansas erroneously identified the
Auxiliary Boiler as participating in CSAPR for ozone season
NOX. We are proposing to replace our prior approval of
Arkansas' determination for the White Bluff Auxiliary Boiler with our
proposed approval of the source specific NOX BART emission
limit contained in the August 8, 2018, SIP revision. We are proposing
to approve ADEQ's revised identification of the 6A Boiler at the
Georgia-Pacific Crossett Mill as BART-eligible and the additional
information and technical analysis presented in the SIP revision in
support of the determination that the Georgia-Pacific Crossett Mill 6A
and 9A Boilers are not subject to BART.
---------------------------------------------------------------------------
\142\ 83 FR 5927.
---------------------------------------------------------------------------
We are also proposing to find that the reasonable progress
requirements under section 51.308(d)(1) have been fully addressed for
the first implementation period. Specifically, we are proposing to
approve the state's focused reasonable progress analysis and the
reasonable progress determination that no additional SO2
controls at Independence Units 1 and 2 or any other Arkansas sources
are necessary under reasonable progress for the first implementation
period. We are also proposing to agree with the state's revised RPGs
for Arkansas' Class I areas. We are basing our proposed approval of the
reasonable progress provisions and revised RPGs on the state's
discussion of the key pollutants and source categories that contribute
to visibility impairment in Arkansas' Class I areas per the CENRAP's
source apportionment modeling; the state's identification of a group of
large SO2 point sources in Arkansas for potential evaluation
of controls under reasonable progress; the state's rationale for
narrowing down its list of potential sources to evaluate under the
reasonable progress requirements; and the state's evaluation and
reasonable weighing of the four statutory factors along with
consideration of the visibility benefits of controls for the
Independence facility. The August 8, 2018, SIP revision does not
address BART and associated long-term strategy requirements for the
Domtar Ashdown Mill Power Boilers No. 1 and 2, and we are not proposing
to withdraw the FIP's BART emission limits for the facility at this
time. If and when ADEQ submits a SIP revision to address BART
requirements for Domtar Power Boilers No. 1 and No. 2, we will evaluate
any conclusions ADEQ has drawn in that submission with respect to the
need to conduct a reasonable progress analysis for Domtar. As long as
the BART requirements for Domtar continue to be addressed by the
measures in the FIP, however, we propose to agree with ADEQ's
conclusion that nothing further is needed to satisfy the reasonable
progress requirements for the first implementation period. With respect
to the RPGs for Arkansas' Class I areas, if and when ADEQ submits a SIP
revision addressing Domtar, we will assess that future SIP revision to
determine if changes are needed based on any differences between the
SIP-based measures and the measures currently contained in the FIP.
We are proposing to approve the components of the long-term
strategy under section 51.308(d)(3) addressed by the August 8, 2018,
SIP revision, including the BART measures contained in the SIP revision
and the SO2 emission limit of 0.60 lb/MMBtu for Independence
Units 1 and 2 based on the use of low sulfur coal. These requirements
for Independence Units 1 and 2 have now been made enforceable by the
state through an Administrative Order that has been adopted and
incorporated in the SIP revision. We are proposing to approve this
Administrative Order as a source-specific revision to the SIP. The
SO2 emission limit and associated Administrative Order for
the Independence facility are listed under Table 16 below. We are
proposing to find that Arkansas' long-term strategy is approved with
respect to sources other than the Domtar Ashdown Mill. We are also
proposing to find that Arkansas has provided an opportunity for
consultation to the FLMs and to Missouri on the proposed SIP revision,
as required under section 51.308(i)(2) and 51.308(d)(3)(i). The BART
emission limits we are proposing to approve are presented in Table 15;
the SO2 emission limits under the long-term strategy and
associated Administrative Order we are proposing to approve for the
Independence facility are presented in Table 16; and Arkansas' revised
2018 RPGs are presented in Table 17.
[[Page 62236]]
Table 15--SIP Revision BART Emission Limits and Administrative Orders Proposed for Approval
----------------------------------------------------------------------------------------------------------------
SIP revision SO2 SIP revision PM SIP revision NOX
Subject-to-BART source BART emission BART emission BART emission Administrative
limits limits limits order
----------------------------------------------------------------------------------------------------------------
AECC Bailey Unit 1.............. 0.5% limit on 0.5% limit on Already SIP- Administrative
sulfur content of sulfur content of approved. Order LIS No. 18-
fuel combusted*. fuel combusted*. 071.
AECC McClellan Unit 1........... 0.5% limit on 0.5% limit on Already SIP- Administrative
sulfur content of sulfur content of approved. Order LIS No. 18-
fuel combusted*. fuel combusted*. 071.
AEP Flint Creek Boiler No. 1.... 0.06 lb/MMBtu*.... Already SIP- Already SIP- Administrative
approved. approved. Order LIS No. 18-
072.
Entergy Lake Catherine Unit 4 Unit is allowed to Unit is allowed to Already SIP- Administrative
(fuel oil firing scenario). burn only natural burn only natural approved. Order LIS No. 18-
gas*. gas*. 073.
Entergy White Bluff Unit 1...... 0.60 lb/MMBtu..... Already SIP- Already SIP- Administrative
(Interim emission approved. approved. Order LIS No. 18-
limit with a 3- 073.
year compliance
date and
cessation of coal
combustion by end
of 2028).
Entergy White Bluff Unit 2...... 0.60 lb/MMBtu..... Already SIP- Already SIP- Administrative
(Interim emission approved. approved. Order LIS No. 18-
limit with a 3- 073.
year compliance
date and
cessation of coal
combustion by end
of 2028).
Entergy White Bluff Auxiliary 105.2 lb/hr*...... 4.5 lb/hr*........ 32.2 lb/hr*....... Administrative
Boiler. Order LIS No. 18-
073.
----------------------------------------------------------------------------------------------------------------
* This BART emission limit required by the SIP revision is the same as what was required under the Arkansas
Regional Haze FIP.
Table 16--SIP Revision Emission Limits Under Reasonable Progress and
Administrative Orders Proposed for Approval
------------------------------------------------------------------------
SIP revision SO2
Source emission limits Administrative
order
------------------------------------------------------------------------
Entergy Independence Unit 1..... 0.60 lb/MMBtu Administrative
Order LIS No. 18-
073.
Entergy Independence Unit 2..... 0.60 lb/MMBtu Administrative
Order LIS No. 18-
073.
------------------------------------------------------------------------
Table 17--Arkansas' Revised 2018 RPGs
------------------------------------------------------------------------
2018 RPG 20%
Class I area worst days (dv)
------------------------------------------------------------------------
Caney Creek........................................... 22.47
Upper Buffalo......................................... 22.51
------------------------------------------------------------------------
B. Partial FIP Withdrawal
We are proposing to withdraw those portions of the Arkansas
Regional Haze FIP at 40 CFR 52.173 that impose SO2 and PM
BART requirements on Bailey Unit 1; SO2 and PM BART
requirements on McClellan Unit 1; SO2 BART requirements on
Flint Creek Boiler No. 1; the provisions concerning BART for the fuel
oil firing scenario for Lake Catherine Unit 4; SO2 BART
requirements for White Bluff Units 1 and 2; SO2 and PM BART
requirements for the White Bluff Auxiliary Boiler; and the
SO2 emission limits under reasonable progress for
Independence Units 1 and 2. We are proposing that these portions of the
FIP will be replaced by the portion of the Arkansas Regional Haze
SO2 and PM SIP revision that we are proposing to approve in
this action. Since we are proposing to withdraw certain portions of the
FIP, we are also proposing to redesignate the FIP by revising the
numbering of certain paragraphs under section 40 CFR 52.173. Our
proposed redesignation of the numbering of these paragraphs is non-
substantive and does not mean we are reopening these parts for public
comment in this proposed rulemaking.
C. Clean Air Act Section 110(l)
We are proposing to find that an approval of a portion of the
Arkansas Regional Haze SO2 and PM SIP revision and
concurrent withdrawal of the corresponding parts of the FIP, as
proposed, will meet the Clean Air Act's 110(1) provisions.
IV. Incorporation by Reference
In this action, we are proposing to include in a final rule
regulatory text that includes incorporation by reference. In accordance
with the requirements of 1 CFR 51.5, we are proposing to incorporate by
reference revisions to the Arkansas source specific requirements as
described in the Proposed Action section above. We have made, and will
continue to make, these documents generally available electronically
through www.regulations.gov and in hard copy at the EPA Region 6 office
(please contact Dayana Medina, 214-665-7241, [email protected] for
more information).
V. Statutory and Executive Order Reviews
Under the CAA, the Administrator is required to approve a SIP
submission that complies with the provisions of the Act and applicable
Federal regulations. 42 U.S.C. 7410(k); 40 CFR 52.02(a). Thus, in
reviewing SIP submissions, the EPA's role is to approve state choices,
provided that they meet the criteria of the CAA. Accordingly, this
action merely proposes to approve state law as meeting Federal
requirements and does not impose additional requirements beyond those
imposed by state law. For that reason, this action:
Is not a ``significant regulatory action'' subject to
review by the Office of Management and Budget under Executive Orders
12866 (58 FR 51735, October 4, 1993) and 13563 (76 FR 3821, January 21,
2011);
Is not an Executive Order 13771 (82 FR 9339, February 2,
2017) regulatory action because SIP approvals are exempted under
Executive Order 12866;
[[Page 62237]]
Does not impose an information collection burden under the
provisions of the Paperwork Reduction Act (44 U.S.C. 3501 et seq.);
Is certified as not having a significant economic impact
on a substantial number of small entities under the Regulatory
Flexibility Act (5 U.S.C. 601 et seq.);
Does not contain any unfunded mandate or significantly or
uniquely affect small governments, as described in the Unfunded
Mandates Reform Act of 1995 (Pub. L. 104-4);
Does not have Federalism implications as specified in
Executive Order 13132 (64 FR 43255, August 10, 1999);
Is not an economically significant regulatory action based
on health or safety risks subject to Executive Order 13045 (62 FR
19885, April 23, 1997);
Is not a significant regulatory action subject to
Executive Order 13211 (66 FR 28355, May 22, 2001);
Is not subject to requirements of section 12(d) of the
National Technology Transfer and Advancement Act of 1995 (15 U.S.C. 272
note) because this action does not involve technical standards; and
Does not provide EPA with the discretionary authority to
address, as appropriate, disproportionate human health or environmental
effects, using practicable and legally permissible methods, under
Executive Order 12898 (59 FR 7629, February 16, 1994).
In addition, the SIP is not approved to apply on any Indian
reservation land or in any other area where EPA or an Indian tribe has
demonstrated that a tribe has jurisdiction. In those areas of Indian
country, the proposed rule does not have tribal implications and will
not impose substantial direct costs on tribal governments or preempt
tribal law as specified by Executive Order 13175 (65 FR 67249, November
9, 2000).
List of Subjects in 40 CFR Part 52
Environmental protection, Air pollution control, Best available
retrofit technology, Incorporation by reference, Intergovernmental
relations, Ozone, Particulate matter, regional haze, Reporting and
recordkeeping requirements, Sulfur dioxide, Visibility.
Dated: November 21, 2018.
David Gray,
Acting Regional Administrator, Region 6.
Title 40, chapter I, of the Code of Federal Regulations is proposed
to be amended as follows:
PART 52--APPROVAL AND PROMULGATION OF IMPLEMENTATION PLANS
0
1. The authority citation for part 52 continues to read as follows:
Authority: 42 U.S.C. 7401 et seq.
Subpart E--Arkansas
0
2. In Sec. 52.170:
0
a. In paragraph (d), the table titled ``EPA-Approved Arkansas Source-
Specific Requirements'' is amended by revising the heading ``Permit
No.'' to ``Permit or Order No.'' and adding the entries ``Arkansas
Electric Cooperative Corporation Carl E. Bailey Plant'', ``Arkansas
Electric Cooperative Corporation John L. McClellan'', ``Entergy
Arkansas, Inc. Lake Catherine Plant'', ``Entergy Arkansas, Inc. White
Bluff Plant'', and ``Entergy Arkansas, Inc. Independence Plant''.
0
b. In paragraph (e), the third table titled ``EPA-Approved Non-
Regulatory Provisions and Quasi-Regulatory Measures in the Arkansas
SIP'' is amended by adding the entry ``Arkansas Regional Haze
SO2 and PM SIP Revision'' at the end of the third table.
The revision and additions read as follows:
Sec. 52.170 Identification of plan.
* * * * *
(d) * * *
(e) * * *
* * * * *
EPA-Approved Arkansas Source-Specific Requirements
----------------------------------------------------------------------------------------------------------------
State approval/
Name of source Permit or order no. effective EPA approval date Comments
date
----------------------------------------------------------------------------------------------------------------
Arkansas Electric Cooperative Administrative 8/7/2018 [Date of Unit 1.
Corporation Carl E. Bailey Plant. Order LIS No. 18- publication of the
071. final rule in the
Federal Register]
[Federal Register
citation of the
final rule].
Arkansas Electric Cooperative Administrative 8/7/2018 [Date of Unit 1.
Corporation John L. McClellan. Order LIS No. 18- publication of the
072. final rule in the
Federal Register]
[Federal Register
citation of the
final rule].
Entergy Arkansas, Inc. Lake Administrative 8/7/2018 [Date of Unit 4.
Catherine Plant. Order LIS No. 18- publication of the
073. final rule in the
Federal Register]
[Federal Register
citation of the
final rule].
Entergy Arkansas, Inc. White Administrative 8/7/2018 [Date of Units 1, 2, and the
Bluff Plant. Order LIS No. 18- publication of the Auxiliary Boiler.
073. final rule in the
Federal Register]
[Federal Register
citation of the
final rule].
Entergy Arkansas, Inc. Administrative 8/7/2018 [Date of Units 1 and 2.
Independence Plant. Order LIS No. 18- publication of the
073. final rule in the
Federal Register]
[Federal Register
citation of the
final rule].
----------------------------------------------------------------------------------------------------------------
[[Page 62238]]
EPA-Approved Non-regulatory Provisions and Quasi-Regulatory Measures in the Arkansas SIP
----------------------------------------------------------------------------------------------------------------
Applicable
geographic or State submittal/
Name of SIP provision nonattainment effective date EPA approval date Explanation
area
----------------------------------------------------------------------------------------------------------------
* * * * * * *
Arkansas Regional Haze SO2 and Statewide........ August 8, 2018... [Date of Regional Haze SIP
PM SIP Revision. publication of submittal addressing
the final rule SO2 and PM BART
in the Federal requirements for
Register] Arkansas EGUs, NOX
[Federal BART requirement for
Register the White Bluff
citation of the Auxiliary Boiler, and
final rule]. reasonable progress
requirements for SO2
for the first
implementation
period.
----------------------------------------------------------------------------------------------------------------
0
3. Section 52.173 is amended by:
0
a. Revising the introductory text of paragraph (c) and paragraph
(c)(1);
0
b. In paragraph (c)(2) revising the definition ``Boiler-operating-
day'';
0
c. Removing paragraphs (c)(3) through (12), and (22) through (24);
0
d. Redesignating paragraphs (c)(13) through (21) as paragraphs (c)(3)
through (11);
0
e. Redesignating paragraphs (c)(25) through (27) as paragraphs (c)(12)
through (14);
0
f. Revising newly redesignated paragraphs (c)(4), (c)(5),(c)(7),
(c)(8), (c)(10), (c)(11), and (c)(12);
0
g. Adding paragraphs (g) and (h).
The revisions and additions read as follows:
Sec. 52.173 Visibility protection.
* * * * *
(c) Federal implementation plan for regional haze. Requirements for
Domtar Ashdown Paper Mill Power Boilers No. 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 Domtar Ashdown Paper Mill Power Boilers No. 1 and
2.
(2) * * *
Boiler-operating-day means 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.
* * * * *
(4) 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)(3) of this
section by November 28, 2016.
(5) Compliance determination and reporting and recordkeeping
requirements for Domtar Ashdown Paper Mill Power Boiler No. 1. (i)(A)
SO2 emissions resulting from combustion of fuel oil shall be
determined by assuming that the SO2 content of the fuel
delivered to the fuel inlet of the combustion chamber is equal to the
SO2 being emitted at the stack. The owner or operator must
maintain records of the sulfur content by weight of each fuel oil
shipment, where a ``shipment'' is considered delivery of the entire
amount of each order of fuel purchased. Fuel sampling and analysis may
be performed by the owner or operator, an outside laboratory, or a fuel
supplier. All records pertaining to the sampling of each shipment of
fuel oil, including the results of the sulfur content analysis, must be
maintained by the owner or operator and made available upon request to
EPA and ADEQ representatives. SO2 emissions resulting from
combustion of bark shall be determined by using the following site-
specific curve equation, which accounts for the SO2
scrubbing capabilities of bark combustion: Y= 0.4005 * X-0.2645
Where:
Y = pounds of sulfur emitted per ton of dry fuel feed to the boiler.
X = pounds of sulfur input per ton of dry bark.
(B) The owner or operator must confirm the site-specific curve
equation through stack testing. By October 27, 2017, the owner or
operator must provide a report to EPA showing confirmation of the site
specific-curve equation accuracy. Records of the quantity of fuel input
to the boiler for each fuel type for each day must be compiled no later
than 15 days after the end of the month and must be maintained by the
owner or operator and made available upon request to EPA and ADEQ
representatives. Each boiler-operating-day of the 30-day rolling
average for the boiler must be determined by adding together the pounds
of SO2 from that boiler-operating-day and the preceding 29
boiler-operating-days and dividing the total pounds of SO2
by the sum of the total number of boiler operating days (i.e., 30). The
result shall be the 30 boiler-operating-day rolling average in terms of
lb/day emissions of SO2. Records of the total SO2
emitted for each day must be compiled no later than 15 days after the
end of the month and must be maintained by the owner or operator and
made available upon request to EPA and ADEQ representatives. Records of
the 30 boiler-operating-day rolling averages for SO2 as
described in this paragraph (c)(5)(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)(3) of this section. The compliance
determination requirements and the reporting and recordkeeping
requirements under paragraph (c)(5)(i) of this section would not apply
and confirmation of the accuracy of the site-specific curve equation
under paragraph (c)(5)(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)(3) of this section, the owner or operator
shall conduct stack testing using EPA Reference Method 7E, found at 40
CFR part 60, Appendix A, once every 5 years, beginning 1 year from the
effective date of our final rule, which corresponds to October 27,
2017. 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)(3) 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
[[Page 62239]]
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)(5)(iii) of this section would not
apply.
* * * * *
(7) 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)(6) of this section by October 27, 2021.
(8) 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 in
this paragraph (c)(8)(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) The owner or operator shall continue to maintain and operate a
CEMS for SO2 and NOX on the boiler 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 40 CFR 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)(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.
(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)(6) of this section. Under these
circumstances, the compliance determination requirements under
paragraphs (c)(8)(i) through (iii) of this section would not apply to
the SO2 emission limit listed in paragraph (c)(6) 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)(6) 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)(8)(i) through (iii) of
this section would not apply to the NOX emission limit.
* * * * *
(10) 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)(9) of this section by November 28,
2016.
(11) 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
[[Page 62240]]
with the PM BART requirement under paragraph (c)(9) of this section.
(12) 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 Division, U.S. Environmental Protection
Agency, Region 6, to the attention of Mail Code: 6MM, 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:
* * * * *
(g) Measures addressing best available retrofit technology (BART)
for electric generating unit (EGU) emissions of sulfur dioxide
(SO2) and particulate matter. The BART requirements for
SO2 and PM emissions from EGUs in Arkansas and
NOX emissions from the White Bluff Auxiliary Boiler are
satisfied by the Arkansas Regional Haze SO2 and PM SIP
Revision approved [Date 30 days after date of publication of the final
rule in the Federal Register].
(h) Other measures addressing reasonable progress. The reasonable
progress requirements for SO2 and PM emissions are satisfied
by the Arkansas Regional Haze SO2 and PM SIP Revision
approved [Date 30 days after date of publication of the final rule in
the Federal Register], the Arkansas Regional Haze FIP, and the 2008
Arkansas Regional Haze SIP.
[FR Doc. 2018-26073 Filed 11-29-18; 8:45 am]
BILLING CODE 6560-50-P
