[Federal Register Volume 80, Number 67 (Wednesday, April 8, 2015)]
[Proposed Rules]
[Pages 18943-19005]
[FR Doc No: 2015-06726]

Vol. 80

Wednesday,

No. 67

April 8, 2015

Part II

Environmental Protection Agency

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40 CFR Part 52

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

Federal Register / Vol. 80 , No. 67 / Wednesday, April 8, 2015 /
Proposed Rules

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 52

[EPA-R06-OAR-2015-0189; FRL-9924-85-Region 6]

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

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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SUMMARY: The Environmental Protection Agency (EPA) is proposing to
promulgate a Federal Implementation Plan (FIP) to address certain
regional haze and visibility transport requirements for the State of
Arkansas. This FIP would address the requirements of the Regional Haze
Rule (RHR) and interstate visibility transport for those portions of
Arkansas' State Implementation Plan (SIP) we disapproved in our final
action published on March 12, 2012. Specifically, the proposed FIP
addresses the requirements for Best Available Retrofit Technology
(BART) for those sources for which we did not approve Arkansas' BART
determinations, Reasonable Progress Goals (RPGs), reasonable progress
controls and a long-term strategy, as well as the interstate visibility
transport requirements for pollutants that affect visibility in Class I
areas in nearby states. Specific to the reasonable progress controls
requirement, we are proposing in the alternative two options for
controlling the emissions from the Entergy Independence Plant that is
not subject to BART. Under Option 1, we are proposing controls for
emissions of SO2, and NOX. If we take final
action on this finding, the source will be subject to controls for both
pollutants. Alternatively, under Option 2, we are proposing controls
for only emissions of SO2 for this planning period. In
particular, we are soliciting comments on the alternate proposed
Options 1 and 2.

DATES: Comments: Comments must be received on or before May 16, 2015.
    Public Hearing: We are holding information sessions--for the
purpose of providing additional information and informal discussion for
our proposal, and public hearings--to accept oral comments into the
record, as follows:
    Date: Thursday, April 16, 2015.
    Time: Information Session: 9 a.m.-9:45 a.m. (break from 9:45 a.m.-
10 a.m.)
    Public hearing: 10 a.m.-11:30 a.m. (break from 11:30 a.m.-1 p.m.)
    Information Session: 1 p.m.-1:45 p.m. (break from 1:45 p.m.-2 p.m.)
    Public hearing: 2 p.m.-7:30 p.m. (including break from 4 p.m.-4:30
p.m.).
    Please see the ADDRESSES section for the location of the hearing in
North Little Rock, AR.

ADDRESSES: Submit your comments, identified by Docket No. EPA-R06-OAR-
2015-0189, by one of the following methods:
     Federal e-Rulemaking Portal: http://www.regulations.gov.
Follow the online instructions for submitting comments.
     Email<EMAIL_ADDRESS>     Mail: Mr. Guy Donaldson, Chief, Air Planning Section (6PD-
L), Environmental Protection Agency, 1445 Ross Avenue, Suite 1200,
Dallas, Texas 75202-2733.
     Hand or Courier Delivery: Mr. Guy Donaldson, Chief, Air
Planning Section (6PD-L), Environmental Protection Agency, 1445 Ross
Avenue, Suite 700, Dallas, Texas 75202-2733. Such deliveries are
accepted only between the hours of 8 a.m. and 4 p.m. weekdays, and not
on legal holidays. Special arrangements should be made for deliveries
of boxed information.
     Fax: Mr. Guy Donaldson, Chief, Air Planning Section (6PD-
L), at fax number<PHONE_NUMBER>.
    Instructions: Direct your comments to Docket No. EPA-R06-OAR-2015-
0189. Our policy is that all comments received will be included in the
public docket without change and may be made available online at
www.regulations.gov, including any personal information provided,
unless the comment includes information claimed to be Confidential
Business Information (CBI) or other information whose disclosure is
restricted by statute. Do not submit information that you consider to
be CBI or otherwise protected through www.regulations.gov or email. The
www.regulations.gov Web site is an ``anonymous access'' system, which
means we will not know your identity or contact information unless you
provide it in the body of your comment. If you send an email comment
directly to us without going through www.regulations.gov your email
address will be automatically captured and included as part of the
comment that is placed in the public docket and made available on the
Internet. If you submit an electronic comment, we recommend that you
include your name and other contact information in the body of your
comment and with any disk or CD-ROM you submit. If we cannot read your
comment due to technical difficulties and cannot contact you for
clarification, we may not be able to consider your comment. Electronic
files should avoid the use of special characters and any form of
encryption, and be free of any defects or viruses.
    Docket: All documents in the docket are listed in the
www.regulations.gov index. Although listed in the index, some
information is not publicly available, e.g., CBI or other information
whose disclosure is restricted by statute. Certain other material, such
as copyrighted material, will be publicly available only in hard copy.
SIP materials which are incorporated by reference into 40 Code of
Federal Regulations (CFR) part 52 are available for inspection at the
following location: Environmental Protection Agency, Region 6, 1445
Ross Avenue, Suite 700, Dallas, TX 75202. Publicly available materials
are available either electronically in www.regulations.gov or in hard
copy at the Region 6 office. The Regional Office hours are Monday
through Friday, 8:30 to 4:30, excluding Federal holidays.
    Hearing location: Arkansas Department of Environmental Quality,
Commission Room, 1st floor, 5301 Northshore Drive, North Little Rock,
AR 72118.
    The public hearing will provide interested parties the opportunity
to present information and opinions to us concerning our proposal.
Interested parties may also submit written comments, as discussed in
the proposal. Written statements and supporting information submitted
during the comment period will be considered with the same weight as
any oral comments and supporting information presented at the public
hearing. We will not respond to comments during the public hearings.
When we publish our final action, we will provide written responses to
all significant oral and written comments received on our proposal. To
provide opportunities for questions and discussion, we will hold an
information session prior to the public hearing. During the information
session, EPA staff will be available to informally answer questions on
our proposed action. Any comments made to EPA staff during an
information session must still be provided orally during the public
hearing, or formally in writing within 30 days after completion of the
hearings, in order to be considered in the record. At the public
hearings, the hearing officer may limit the time available for each
commenter to address the proposal to three minutes or less if the
hearing officer determines it to be appropriate. We will not be
providing equipment for commenters to

show overhead slides or make computerized slide presentations. Any
person may provide written or oral comments and data pertaining to our
proposal at the public hearings. Verbatim English language transcripts
of the hearing and written statements will be included in the
rulemaking docket.

FOR FURTHER INFORMATION CONTACT: To schedule your inspection, contact
Ms. Dayana Medina at<PHONE_NUMBER> or via electronic mail at
<EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION: Throughout this document wherever ``we,''
``us,'' or ``our'' is used, we mean the EPA.

Table of Contents

I. Background
II. Overview of Proposed Actions
    A. Regional Haze
    B. Interstate Transport of Pollutants That Affect Visibility
    C. History of State Submittals and Our Actions
    D. Our Authority To Promulgate a FIP
III. Our Proposed BART Analyses and Determinations
    A. Identification of BART-Eligible Sources and Subject to BART
Sources
    1. Georgia Pacific-Crossett Mill 6A and 9A Power Boilers
    2. AECC Carl E. Bailey Generating Station Unit 1
    B. BART Factors
    C. BART Determinations and Proposed Federally Enforceable Limits
    1. AECC Carl E. Bailey Generating Station
    2. AECC John L. McClellan Generating Station
    3. AEP Flint Creek Power Plant
    4. Entergy White Bluff Plant
    5. Entergy Lake Catherine Plant
    6. Domtar Ashdown Paper Mill
IV. Our Proposed Reasonable Progress Analysis and Determinations
    A. Reasonable Progress Analysis of Point Sources
    1. Entergy Independence Plant Units 1 and 2
    B. Reasonable Progress Goals
V. Our Proposed Long-Term Strategy
VI. Our Proposal for Interstate Visibility Transport
VII. Summary of Proposed Actions
    A. Regional Haze
    B. Interstate Visibility Transport
VIII. Statutory and Executive Order Reviews

I. Background

    Regional haze is visibility impairment that is produced by a
multitude of sources and activities that are located across a broad
geographic area and emit fine particulates (PM2.5) (e.g.,
sulfates, nitrates, organic carbon (OC), elemental carbon (EC), and
soil dust), and their precursors (e.g., sulfur dioxide
(SO2), nitrogen oxides (NOX), and in some cases,
ammonia (NH3) and volatile organic compounds (VOC)). Fine
particle precursors react in the atmosphere to form PM2.5,
which impairs visibility by scattering and absorbing light. Visibility
impairment reduces the clarity, color, and visible distance that one
can see. PM2.5 can also cause serious health effects and
mortality in humans and contributes to 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 visibility impairment caused by air
pollution occurs virtually all the time at most national parks and
wilderness areas. The average visual range \1\ in many Class I areas
(i.e., national parks and memorial parks, wilderness areas, and
international parks meeting certain size criteria) in the western
United States is 100-150 kilometers, or about one-half to two-thirds of
the visual range that would exist without anthropogenic air pollution.
In most of the eastern Class I areas of the United States, the average
visual range is less than 30 kilometers, or about one-fifth of the
visual range that would exist under estimated natural conditions. 64 FR
35715 (July 1, 1999).
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    \1\ Visual range is the greatest distance, in kilometers or
miles, at which a dark object can be viewed against the sky.
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    In section 169A of the 1977 Amendments to the Clean Air Act (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.\2\ On December 2, 1980, EPA promulgated regulations to
address visibility impairment in Class I areas that is ``reasonably
attributable'' to a single source or small group of sources, i.e.,
``reasonably attributable visibility impairment.'' \3\ These
regulations represented the first phase in addressing visibility
impairment. EPA deferred action on regional haze that emanates from a
variety of sources until monitoring, modeling, and scientific knowledge
about the relationships between pollutants and visibility impairment
were improved.
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    \2\ Areas designated as mandatory Class I Federal areas consist
of National Parks exceeding 6000 acres, wilderness areas and
national memorial parks exceeding 5000 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.''
    \3\ 45 FR 80084 (December 2, 1980).
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    Congress added section 169B to the CAA in 1990 to address regional
haze issues, and we promulgated regulations addressing regional haze in
1999.\4\ The Regional Haze Rule (RHR) revised the existing visibility
regulations to integrate into the regulations 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 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.\5\
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    \4\ 64 FR 35714 (July 1, 1999), codified at 40 CFR part 51,
subpart P (Regional Haze Rule).
    \5\ See 40 CFR 51.308(b). EPA's regional haze regulations
require subsequent updates to the regional haze SIPs. 40 CFR
51.308(g)-(i).
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II. Overview of Proposed Actions

A. Regional Haze

    We are proposing to promulgate a FIP as described in this notice
and summarized in this section to address those portions of Arkansas'
regional haze SIP that we disapproved on March 12, 2012.\6\ In our
March 12, 2012 final action, we disapproved Arkansas' BART control
analyses and determinations for nine units at six facilities and the
Reasonable Progress Goals (RPGs) analysis and RPGs set by Arkansas, and
partially disapproved the long-term strategy for making reasonable
progress. We are proposing this FIP because Arkansas has not provided a
revision to its SIP to address the deficiencies identified in our March
12, 2012 partial disapproval. We believe, however, it is preferable for
states to take the lead in implementing the Regional Haze requirements
as envisioned by the Clean Air Act. We will work with the State of
Arkansas if it chooses to develop a SIP

to meet the Regional Haze requirements to replace this proposed FIP.
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    \6\ 77 FR 14604, March 12, 2012.
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    The FIP we are proposing includes BART control determinations for
sources in Arkansas without previously approved BART determinations and
associated compliance schedules and requirements for equipment
maintenance, monitoring, testing, recordkeeping, and reporting for all
affected sources and units. The BART sources addressed in this FIP
cause or contribute to visibility impairment at one or more Class I
areas in Arkansas and Missouri. The two Class I areas in Arkansas are
the Caney Creek Wilderness Area and the Upper Buffalo Wilderness Area.
The two Class I areas in Missouri are the Hercules-Glades Wilderness
Area and the Mingo National Wildlife Refuge. In this FIP, we are
proposing SO2, NOX, and PM BART control
determinations for nine units at six facilities in Arkansas. We are
proposing SO2, NOX, and PM BART determinations
for Unit 1 of the Arkansas Electric Cooperative Corporation (AECC) Carl
E. Bailey Generating Station; SO2, NOX, and PM
BART determinations for Unit 1 of the AECC John L. McClellan Generating
Station; SO2 and NOX BART determinations for
Boiler No. 1 of the American Electric Power (AEP) Flint Creek Power
Plant; SO2 and NOX BART determinations for Units
1 and 2 and SO2, NOX, and PM BART determinations
for the Auxiliary Boiler of the Entergy White Bluff Plant;
NOX BART determination for Unit 4 of the Entergy Lake
Catherine Plant; SO2 and NOX BART determinations
for Power Boiler No. 1 and SO2, NOX and PM BART
determinations for Power Boiler No. 2 of the Domtar Ashdown Mill.
Additionally, for the reasonable progress requirements, we are
proposing in the alternative two options for controlling the emissions
from the Entergy Independence Plant that is not subject to BART. Under
Option 1, under the reasonable progress requirements, we are proposing
controls for emissions of SO2 and NOX for Units 1
and 2 of the Entergy Independence Plant. Alternatively, under Option 2,
we are proposing controls for only emissions of SO2 for the
first planning period. We solicit comments on this proposed alternative
approach. We are also soliciting public comment on any alternative
control measures for Entergy White Bluff Units 1 and 2 and Independence
Units 1 and 2 that would address the BART and reasonable progress
requirements for these four units for this regional haze planning
period. The measures in the FIP that we are proposing will reduce
emissions that contribute to regional haze in Arkansas' Class I areas
and other nearby Class I areas. RPGs are interim visibility goals
towards meeting the CAA's national visibility goal of preventing any
future, and remedying any existing, impairment of visibility resulting
from manmade air pollution in Class I areas. This proposed FIP and the
portion of the Arkansas regional haze SIP that we approved on March 12,
2012, together would ensure that progress is made toward natural
visibility conditions at these Class I areas. This proposed action and
the accompanying documents that are available in the Docket explain the
basis for our proposed Arkansas Regional Haze FIP. Please refer to our
previous rulemaking on the Arkansas regional haze SIP for additional
background regarding the CAA, regional haze, and our RHR.\7\
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    \7\ 77 FR 14604, March 12, 2012.
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B. Interstate Transport of Pollutants That Affect Visibility

    We propose that a combination of those portions of the Arkansas
regional haze SIP that we previously approved and the measures in the
FIP will satisfy the visibility requirement of CAA section
110(a)(2)(D)(i)(II) for the 1997 8-hour ozone and 1997 PM2.5
national ambient air quality standards (NAAQS). CAA section
110(a)(2)(D)(i)(II) requires that states have a SIP, or submit a SIP
revision, containing provisions ``prohibiting any source or other type
of emission activity within the state from emitting any air pollutant
in amounts which will . . . interfere with measures required to be
included in the applicable implementation plan for any other State
under part C [of the CAA] to protect visibility.'' Because of the
impacts on visibility from the interstate transport of pollutants, we
interpret these ``good neighbor'' provisions of section 110 of the Act
as requiring states to include in their SIPs measures to prohibit
emissions that would interfere with the reasonable progress goals set
to protect Class I areas in other states. For Arkansas, we interpret
this to mean that the State must include in its SIP a demonstration
that emissions from Arkansas sources and activities will not have the
prohibited impacts on other states' existing SIPs. We refer herein to
this requirement as the interstate transport visibility requirement.
The Arkansas Department of Environmental Quality (ADEQ) submitted a SIP
revision to address this requirement on April 2, 2008, and submitted
supplemental information on September 27, 2011. The April 2, 2008
submittal stated that Arkansas is relying on the Air Pollution Control
and Ecology Commission (APCEC) Regulation 19, Chapter 15, also known as
the State BART rulemaking, to satisfy the requirements of section
110(a)(2)(D)(i)(II) with respect to visibility transport. The April 2,
2008 SIP submittal, which was submitted prior to Arkansas' submission
of the Arkansas regional haze SIP, also stated that it is not possible
to assess whether there is any interference with the measures in the
applicable SIP for another state designed to protect visibility for the
1997 8-hour ozone and PM2.5 NAAQS until Arkansas submits and
we approve the Arkansas regional haze SIP. In our final rule published
on March 12, 2012, we partially approved and partially disapproved the
SIP submittal with respect to the interstate transport visibility
requirement under CAA section 110(a)(2)(D)(i)(II), triggering the
obligation for us to promulgate a FIP or to fully approve a revised SIP
submission from Arkansas to ensure that the requirement is fully
addressed.\8\ Today's notice describes our proposed FIP, which we
propose to find will fully address the deficiencies we identified in
our prior partial disapproval action of Arkansas' SIP submittal with
respect to the interstate visibility transport requirement under CAA
section 110(a)(2)(D)(i)(II) for the 1997 8-hour ozone and 1997
PM2.5 NAAQS.
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    \8\ Id.
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C. History of State Submittals and Our Actions

    As discussed above, Arkansas submitted a SIP revision on April 2,
2008, to address the interstate transport visibility requirement of CAA
section 110(a)(2)(D)(i)(II) for the 1997 8-hour ozone and 1997
PM2.5 NAAQS. To address the first regional haze
implementation period, Arkansas submitted a regional haze SIP on
September 23, 2008. On August 3, 2010, Arkansas submitted a SIP
revision with non-substantive revisions to the APCEC Regulation 19,
Chapter 15, which identified the BART-eligible and subject-to-BART
sources in Arkansas and established the BART emission limits that
subject-to-BART sources are required to comply with. On September 27,
2011, the State submitted supplemental information on the Arkansas
regional haze SIP. We are hereafter referring to these regional haze
submittals collectively as the ``2008 Arkansas RH SIP.'' On March 12,
2012, we partially approved and partially disapproved the 2008 Arkansas
RH SIP

and the April 2, 2008 SIP submittal concerning the interstate transport
visibility requirements for the 1997 8-hour ozone and 1997
PM2.5 NAAQS.\9\
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    \9\ Id.
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    Our partial disapproval of the 2008 Arkansas RH SIP included a
disapproval of the following BART determinations made by Arkansas:
     SO2, NOX, and PM BART for the AECC
Carl E. Bailey Generating Station Unit 1;
     SO2, NOX, and PM BART for the AECC
John L. McClellan Generating Station Unit 1;
     SO2 and NOX BART for the AEP Flint
Creek Power Plant No. 1 Boiler;
     SO2 and NOX BART for the bituminous
and sub-bituminous coal firing scenarios for the Entergy White Bluff
Plant Units 1 and 2;
     SO2, NOX, and PM BART for the
Entergy White Bluff Plant Auxiliary Boiler;
     NOX BART for the natural gas firing scenario
for the Entergy Lake Catherine Plant Unit 4;
     SO2, NOX, and PM BART for the fuel
oil firing scenario for the Entergy Lake Catherine Plant Unit 4;
     SO2 and NOX BART for the Domtar
Ashdown Mill No. 1 Power Boiler; and
     SO2, NOX, and PM BART for the Domtar
Ashdown Mill No. 2 Power Boiler.
    In our final action, we also disapproved Arkansas' determinations
that the Georgia Pacific-Crossett Mill 6A Boiler is not BART-eligible,
and that the 6A and 9A Boilers are not subject to BART. By partially
disapproving Arkansas' BART determinations, we also partially
disapproved the corresponding provisions of APCEC Regulation 19,
Chapter 15. We also disapproved Arkansas' RPGs for its two Class I
areas, the Caney Creek Wilderness Area and the Upper Buffalo Wilderness
Area, because Arkansas did not meet the requirement under section
169A(g)(1) of the CAA and 40 CFR 51.308(d)(1)(i)(A) to consider the
four statutory factors when establishing its RPGs. Additionally, we
partially disapproved Arkansas' long-term strategy because it relied on
other disapproved portions of the SIP.

D. Our Authority To Promulgate a FIP

    Under section 110(c) of the Act, whenever we disapprove a mandatory
SIP submission in whole or in part, we are required to promulgate a FIP
within 2 years unless we approve a SIP revision correcting the
deficiencies before promulgating a FIP. Specifically, CAA section
110(c) provides that the Administrator shall promulgate a FIP within 2
years after the Administrator disapproves a state implementation plan
submission ``unless the State corrects the deficiency, and the
Administrator approves the plan or plan revision, before the
Administrator promulgates such Federal implementation plan.'' The term
``Federal implementation plan'' is defined in section 302(y) of the CAA
in pertinent part as a plan promulgated by the Administrator to correct
an inadequacy in a SIP.
    Thus, because we partially disapproved the 2008 Arkansas RH SIP and
the SIP submittal addressing the interstate transport visibility
requirement, we are required to promulgate a FIP for Arkansas, unless
we first approve a SIP revision that corrects the disapproved portions
of these SIP submittals. As Arkansas has not as yet submitted a revised
SIP following our partial disapproval, we are proposing a FIP to
address those portions of the SIP that we disapproved.

III. Our Proposed BART Analyses and Determinations

    Following our 2012 disapproval of the 2008 Arkansas RH SIP,
Arkansas began the process of generating additional technical
information and analysis for the BART determinations. Arkansas gathered
technical documentation from the companies whose BART determinations we
disapproved. These documents were provided to us and are the basis for
our evaluation of BART determinations for the facilities with prior
disapproved BART determinations.

A. Identification of BART-Eligible Sources 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 (70 FR 39158) and the RHR (40 CFR 51.301): (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 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 to consider exempting some of them
from BART because they may not reasonably be anticipated to cause or
contribute to any visibility impairment in a Class I area. 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 a Class I area is not
``subject to BART,'' and for such sources, a state need not apply the
five statutory factors to make a BART determination.
1. Georgia Pacific-Crossett Mill 6A and 9A Power Boilers
    In our March 12, 2012 final action, we approved Arkansas'
identification of BART-eligible sources except for the Georgia-Pacific
Crossett Mill 6A Boiler. 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. Our basis and analyses for our disapproval of
Arkansas' determinations that the 6A Boiler is not BART-eligible and
that the 6A and 9A Boilers are not subject to BART is found in our
October 17, 2011 proposed rulemaking, March 12, 2012 final rulemaking,
and the associated TSDs.\10\
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    \10\ 76 FR 64186 and 77 FR 14604.
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    A revised Title V permit for the Georgia-Pacific Crossett Mill was
issued on August 4, 2011, and again on May 23, 2012. Although no
pollution controls were installed, the permitted emission limits for
SO2 and PM10 for the 6A Boiler and
SO2, NOX, and PM10 for the 9A Boiler
were revised to be more stringent. In a letter dated May 18, 2012,\11\
Georgia-Pacific explained to ADEQ that it had conducted additional
dispersion modeling in 2011 based on the currently enforceable Title V
permit limits for the 6A and 9A Boilers.\12\ The results of the 2011
modeling analysis are summarized in the table below. Based on modeling
of the current permit limits, the boilers' maximum visibility impact
was modeled to be 0.359 dv at Caney Creek (assuming 2002 meteorology).
In the letter to ADEQ, Georgia-Pacific stated its belief that the 2011
dispersion modeling analysis and the current Title V permit that
enforces the modeled limits are sufficient to

demonstrate no cause or contribution to visibility impairment by the 6A
and 9A Boilers, and that the boilers are therefore not subject to BART.
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    \11\ May 18, 2012 letter from James W. Cutbirth, Environmental
Services Superintendent at Georgia-Pacific Crossett Paper
Operations, to Mary Pettyjohn, ADEQ. A copy of this letter can be
found in the docket for this proposed rulemaking.
    \12\ See ADEQ Operating Air Permit No. 0597-AOP-R14, issued on
May 23, 2012. A copy of the air permit can be found in the docket
for this proposed rulemaking.

                       Table 1--Maximum Modeled Visibility Impacts From 6A and 9A Boilers
                              [Georgia-Pacific's 2011 Dispersion Modeling Analysis]
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                                                                          Maximum Visibility Impact  (dv)
                                                                 -----------------------------------------------
                          Class I area                                 2001            2002            2003
                                                                    meteorology     meteorology     meteorology
----------------------------------------------------------------------------------------------------------------
Caney Creek.....................................................            0.16           0.359           0.296
Upper Buffalo...................................................           0.099           0.074           0.099
Hercules-Glades.................................................            0.08           0.288           0.125
Mingo...........................................................           0.123           0.093           0.168
Sipsey..........................................................           0.171           0.184           0.119
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    Following discussions with us and ADEQ, Georgia-Pacific provided
additional information and documentation to support its contention that
the 6A and 9A Boilers are not subject to BART. Georgia-Pacific
calculated maximum 24-hour emission rates from the 2001-2003 baseline
period using fuel usage data, and then showed that these estimated
maximum 24-hour emission rates are below the revised emission rates it
used in the 2011 BART screening modeling. In a letter dated April 1,
2013, Georgia-Pacific provided spreadsheets with fuel usage data for
the 6A and 9A Boilers for each day during the 2001-2003 baseline
period.\13\ The 6A Boiler burned only natural gas during the 2001-2003
baseline period, while the 9A Boiler burned both natural gas and bark.
Georgia-Pacific used emission factors from AP-42, Compilation of Air
Pollutant Emission Factors,\14\ to calculate 24-hour emission rates for
SO2, NOX, and PM10 (lb/hr) for the 6A
and 9A Boilers for each day during the baseline years. The gas and bark
usage value for each day was multiplied by the corresponding AP-42
emission factor to calculate the 24-hour emission rate for each day
during the baseline period.\15\ Georgia-Pacific then determined the
maximum 24-hour emission rates for the 6A and 9A Boilers during the
baseline period (see table below).\16\
---------------------------------------------------------------------------

    \13\ April 1, 2013 letter from James W. Cutbirth, Environmental
Services Superintendent at Georgia-Pacific Crossett Paper
Operations, to Mary Pettyjohn, ADEQ. A copy of this letter and all
attachments can be found in the docket for this proposed rulemaking.
    \14\ AP-42, Compilation of Air Pollutant Emission Factors, has
been published since 1972 as the primary compilation of EPA's
emission factor information. It contains emission factors and
process information for more than 200 air pollution source
categories. The emission factors have been developed and compiled
from source test data, material balance studies, and engineering
estimates. The Fifth Edition of AP-42 was published in January 1995.
Since then, EPA has published supplements and updates to the fifteen
chapters available in Volume I, Stationary Point and Area Sources.
The latest emissions factors are available at http://www.epa.gov/ttnchie1/ap42/.
    \15\ Please see the TSD for example calculations of the 24-hour
emissions rates for the 6A and 9A Boilers. See also the April 1,
2013 letter from James W. Cutbirth, Environmental Services
Superintendent at Georgia-Pacific Crossett Paper Operations, to Mary
Pettyjohn, ADEQ. The attachments to the April 1, 2013 letter include
spreadsheets with the calculated 24-hour emission rates for each day
during the 2001-2003 baseline period for the 6A and 9A Boilers. The
letter and all attachments are found in the docket for this proposed
rulemaking.
    \16\ The maximum 24-hour emission rate for PM10 for
the 9A Boiler is based on the results of stack testing Georgia-
Pacific conducted when the boiler was firing bark and gas, since the
stack test results yielded a higher emission rate than what Georgia-
Pacific calculated using AP-42 emission factors.

    Table 2--Georgia-Pacific Crossett Mill 6A and 9A Boiler Maximum 24-Hour Emission Rates From the 2001-2003
                                                 Baseline Period
----------------------------------------------------------------------------------------------------------------
                                                                      Maximum 24-Hour Emission Rates (lb/hr)
                              Unit                               -----------------------------------------------
                                                                        SO2             NOX            PM10
----------------------------------------------------------------------------------------------------------------
6A Boiler.......................................................             0.2            90.7             2.5
9A Boiler.......................................................            17.9           174.1            72.0
----------------------------------------------------------------------------------------------------------------

    Georgia-Pacific then compared the calculated maximum 24-hour
emission rates from the baseline period with the emission rates it
modeled in the 2011 BART screening modeling and with the current Title
V permit limits (see table below).\17\ A comparison of these values
shows that the calculated maximum 24-hour emission rates for each
pollutant are below the emission rates Georgia-Pacific modeled in the
2011 BART screening modeling, and also below the currently enforceable
Title V permit limits.
---------------------------------------------------------------------------

    \17\ See ADEQ Operating Air Permit No. 0597-AOP-R14, issued on
May 23, 2012. A copy of the air permit can be found in the docket
for this proposed rulemaking.

Table 3--Georgia-Pacific Crossett Mill--Comparison of Maximum 24-Hour Emission Rates With Modeled Emission Rates
                                            and Title V Permit Limits
----------------------------------------------------------------------------------------------------------------
                                                                        SO2             NOX            PM10
----------------------------------------------------------------------------------------------------------------
                                                    6A Boiler
----------------------------------------------------------------------------------------------------------------
Calculated Maximum 24-hr Emission Rate (lb/hr)..................             0.2            90.7             2.5

Modeled Emission Rate (lb/hr)...................................             0.3           120.0             3.3
Title V permit Limit (lb/hr)....................................             0.3           120.0             3.3
----------------------------------------------------------------------------------------------------------------
                                                    9A Boiler
----------------------------------------------------------------------------------------------------------------
Calculated Maximum 24-hr Emission Rate (lb/hr)..................            17.9           174.1            72.0
Modeled Emission Rate (lb/hr)...................................           200.0           218.0            75.8
Title V permit Limit (lb/hr)....................................           199.8           196.0            77.4
----------------------------------------------------------------------------------------------------------------

    Because the 2011 BART screening modeling showed visibility impacts
below 0.5 dv from the 6A and 9A Boilers and the recently estimated
maximum 24-hour emission rates from the 2001-2003 baseline period are
below the modeled emission rates, we propose that it is reasonable to
conclude that the boilers had visibility impacts below 0.5 dv during
the baseline period. Accordingly, we believe that
Georgia[hyphen]Pacific's newly provided analysis and documentation, as
described above and in our TSD in more detail, is appropriate to
demonstrate that the 6A and 9A Boilers are not subject to BART. In
comparison to the information available to us when we issued our March
12, 2012 final action on the 2008 Arkansas RH SIP, we believe this
newly provided analysis allows for a more accurate assessment of
whether or not the 6A and 9A Boilers are subject to BART. Based on this
newly provided information, we are proposing to find that while the 6A
Boiler is a BART-eligible source, it is not subject to BART. The 9A
Boiler is also BART-eligible (as the State determined in the 2008
Arkansas RH SIP), but we are also proposing to find that the 9A Boiler
is not subject to BART. Therefore, it is not necessary to perform a
BART five factor analysis or to make BART determinations for the
Georgia-Pacific Crossett Mill 6A and 9A Boilers.
2. AECC Carl E. Bailey Generating Station Unit 1
    In our March 12, 2012 final action on the 2008 Arkansas RH SIP, we
noted that the original meteorological databases generated by the
Central Regional Air Planning Association (CENRAP) and used by Arkansas
to conduct its modeling analyses did not include surface and upper air
meteorological observations as EPA guidance recommends. Thus, in its
evaluation to determine if a source exceeds the 0.5 dv contribution
threshold at potentially affected Class I areas, Arkansas used the
maximum value (i.e., 1st high value) of modeled visibility impacts
instead of the 98th percentile value (i.e., 8th high value). The use of
the maximum modeled values in the 2008 Arkansas RH SIP was agreed to by
us, representatives of the Federal Land Managers, and CENRAP
stakeholders. In our March 12, 2012 final action, we also approved
Arkansas' determination that the AECC Carl E. Bailey Generating Station
(AECC Bailey) Unit 1 is BART-eligible and subject to BART, based on the
maximum value of modeled visibility impacts.
    Following our March 12, 2012 final action on the 2008 Arkansas RH
SIP, AECC hired a consultant to conduct revised modeling of AECC Bailey
Unit 1. Unlike the modeling submitted in the 2008 Arkansas RH SIP, the
revised modeling shows visibility impacts from Bailey Unit 1 below 0.5
dv, which is the threshold used by Arkansas to determine if a source is
subject to BART. However, we already approved Arkansas' determination
that the AECC Bailey Unit 1 is subject to BART in our March 12, 2012
final action on the 2008 Arkansas RH SIP.
    We do not have the discretion to reopen the issue of whether the
source is subject to BART because we already approved the portion of
the 2008 Arkansas RH SIP in which Arkansas determined AECC Bailey Unit
1 is subject to BART and Arkansas has not provided us a SIP revision to
replace the previous determination.\18\ We cannot re-consider our
approval of that portion of the 2008 Arkansas RH SIP to have been in
error because Arkansas did not submit the revised modeling to us with a
request to remove the source from BART and the modeling approach used
by Arkansas in that SIP is consistent with our regional haze
regulations and was agreed to by us, representatives of the Federal
Land Managers, and CENRAP stakeholders prior to submittal of the 2008
Arkansas RH SIP. Therefore, our proposed FIP is not reopening the issue
of whether the source is subject to BART, and our final approval of
Arkansas' determination that the source is subject to BART remains in
place and in the subsection that follows we evaluate AECC Bailey Unit 1
under BART.
---------------------------------------------------------------------------

    \18\ 77 FR 14604, March 12, 2012.
---------------------------------------------------------------------------

B. BART Factors

    The purpose of the BART analysis is to identify and evaluate the
best system of continuous emission reduction based on the BART
Guidelines.\19\ In determining BART, a state, or EPA if promulgating a
FIP, 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.
See also 40 CFR 51.308(e)(1)(ii)(A). Following the BART Guidelines, the
BART analysis is broken down into five steps. Steps 1 through 3 address
the availability, technical feasibility and effectiveness of retrofit
control options. The consideration of the five statutory factors occurs
during steps 4 and 5 of the process.
---------------------------------------------------------------------------

    \19\ See July 6, 2005 BART Guidelines, 40 CFR 51, Regional Haze
Regulations and Guidelines for Best Available Retrofit Technology
Determinations.
---------------------------------------------------------------------------

    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.
     Factor 1: Costs of compliance.
     Factor 2: Energy and nonair quality environmental impacts
of compliance.
     Factor 3: Existing pollution control technology in use at
the source.
     Factor 4: Remaining useful life of the facility.
    Step 5--Evaluate Visibility Impacts
     Factor 5: Degree of improvement in visibility which may
reasonably be

anticipated to result from the use of retrofit control technology.

C. BART Determinations and Proposed Federally Enforceable Limits

1. AECC Carl E. Bailey Generating Station
    The AECC Bailey Unit 1 is a wall-fired boiler with a gross output
of 122 megawatts (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 natural gas and fuel oil. The fuel oil burned is
currently subject to a sulfur content limit of 2.3% by weight. AECC
hired a consultant to perform a BART five factor analysis for Bailey
Unit 1.\20\
---------------------------------------------------------------------------

    \20\ See the following BART analyses: ``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; and ``BART Five Factor Analysis-
NOX Analysis, Addendum to the July 24, 2012 BART Five
Factor Analysis, Arkansas Electric Cooperative Corporation Bailey
and McClellan Generating Stations,'' dated December 2013, Version 3.
A copy of these two BART analyses can be found in the docket for our
proposed rulemaking.
---------------------------------------------------------------------------

    The table below summarizes the baseline emission rates modeled for
the source. The SO2 and NOX baseline emission
rates are the highest actual 24-hour emission rates based on 2001-2003
continuous emission monitoring system (CEMS) data, while the PM
baseline emission rates are based on stack testing and AP-42 emission
factors.

                                                 Table 4--Baseline Emission Rates for AECC Bailey Unit 1
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Inorganic                              Organic
                                                       SO2 (lb/    NOX (lb/      Total    condensable  Coarse soil   Fine soil  condensable   Elemental
                 Unit/Fuel scenario                       hr)         hr)      PM10\21\    (SO4) (lb/   (PMc) (lb/  (PMf) (lb/    PM (SOA)   carbon (EC)
                                                                                (lb/hr)       hr)          hr)          hr)       (lb/hr)      (lb/hr)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Bailey, Unit 1--Natural Gas firing..................         0.5       443.8        10.2          0.3          0.0         0.0          7.4          2.6
Bailey, Unit 1--Fuel Oil firing.....................     2,375.8       408.8        55.8          4.6         13.7        34.1          0.8          2.7
--------------------------------------------------------------------------------------------------------------------------------------------------------

    The NOX and PM baseline emission rates used in AECC's
revised modeling for the fuel oil firing scenario were revised from
what the State modeled in the 2008 Arkansas RH SIP. The revised
NOX emission rates for the fuel oil firing scenario are
higher than what was modeled in the 2008 Arkansas RH SIP, while the
revised PM10 emission rates for fuel oil firing scenario are
lower than what was modeled in the 2008 Arkansas RH SIP. We have some
concern with AECC's use of the PM10 baseline emission rates,
which are based on stack testing, because there is no discussion
provided on how the stack test results are representative of the
maximum 24-hour emissions. However, because the visibility impacts due
to PM10 emissions from Bailey Unit 1 are so small, we
believe a closer inspection of the revised PM10 emission
rates and any further updates to these would likely not result in
significant changes to the modeled visibility impacts and would not
affect our proposed BART decision. As shown in the table below, the
percentage of the visibility impairment attributable to PM10
from Bailey Unit 1 at the Class I area with the highest baseline
visibility impacts (Mingo) is 8.10% for the natural gas firing scenario
and 1.26% for the fuel oil firing scenario. Most of the visibility
impairment is attributable to NO3 (83.34%) for the natural
gas firing scenario and to SO4 (93.95%) for the fuel oil
firing scenario. Therefore, we did not take further steps to adjust the
PM10 emission rates or conduct additional modeling.
---------------------------------------------------------------------------

    \21\ The National Park Service PM speciation worksheets are
typically used to speciate PM10 into SO4, PMc,
PMf, SOA, and EC.
---------------------------------------------------------------------------

    AECC's modeling for the baseline emission rates uses the CALPUFF
dispersion model to determine the baseline visibility impairment
attributable to Bailey Unit 1 at the four Class I areas impacted by
emissions from BART sources in Arkansas. These Class I areas are the
Caney Creek Wilderness Area, Upper Buffalo Wilderness Area, Hercules-
Glades Wilderness Area, and Mingo National Wildlife Refuge. The
baseline (i.e., existing) visibility impairment attributable to each
unit at each Class I area is summarized in the table below.

                         Table 5--98th Percentile Baseline Visibility Impairment Attributable to AECC Bailey Unit 1 (2001-2003)
--------------------------------------------------------------------------------------------------------------------------------------------------------

--------------------------------------------------------------------------------------------------------------------------------------------------------
Unit/Fuel scenario                                                               Maximum            98th            98th            98th            98th
                                                                             ([Delta]dv)      percentile      percentile      percentile      percentile
                                                                                ([Delta]dv)           % SO4           % NO3          % PM10
--------------------------------------------------------------------------------------------------------------------------------------------------------
Bailey Unit 1--Natural Gas firing.........  Caney Creek.................           0.219           0.083            0.28           96.36            3.35
                                            Upper Buffalo...............           0.170           0.072            0.29           95.02            3.43
                                            Hercules-Glades.............           0.238           0.073            0.22           92.76            3.67
                                            Mingo.......................           0.443           0.102            0.45           83.34            8.10
Bailey Unit 1--Fuel Oil firing............  Caney Creek.................           0.970           0.330           87.19           12.11            0.57
                                            Upper Buffalo...............           0.696           0.348           90.73            8.42            0.83
                                            Hercules-Glades.............           0.687           0.368           82.74           14.39            2.08
                                            Mingo.......................           1.592           0.379           93.95            4.68            1.26
--------------------------------------------------------------------------------------------------------------------------------------------------------

    a. Proposed BART Analysis and Determination for SO2. The source
does not have existing SO2 pollution control technology.
AECC identified all available control technologies, eliminated options
that are not technically feasible, and evaluated the control
effectiveness of the remaining control options. Each technically
feasible control option was then evaluated in terms of a five factor
BART analysis.
    AECC's BART evaluation considered both flue gas desulfurization
(FGD) and fuel switching as possible controls. AECC found that FGD
applications have not been used historically for SO2 control
on fuel oil-fired units in the U.S.

electric industry and therefore considered it a technically infeasible
option for control of Bailey Unit 1. Accordingly, AECC did not further
consider FGD for SO2 BART. We concur with AECC's decision to
focus the SO2 BART evaluation on fuel switching. Switching
to a fuel with a lower sulfur content is expected to reduce
SO2 emissions in proportion to the reduction in the sulfur
content of the fuel, assuming that the fuels have similar heat
contents. Bailey Unit 1 burns primarily natural gas, but is also
permitted to burn fuel oil. The baseline fuel AECC assumed in the BART
analysis is No. 6 fuel oil with 1.81% sulfur content, based on the
average sulfur content of the fuel oil from the most recent shipment
received by the facility in December 2006. According to the facility, a
portion of the fuel oil from this shipment still remains in storage at
the facility for future use. AECC evaluated switching to the fuel types
shown in the table below.

Table 6--Control Effectiveness of Fuel Switching Options for AECC Bailey
                                 Unit 1
------------------------------------------------------------------------
                                                           Estimated SO2
                 Fuel switching options                       control
                                                           efficiency %
------------------------------------------------------------------------
No. 6 fuel oil, 1% sulfur...............................              45
No. 6 fuel oil, 0.5% sulfur.............................              72
Diesel, 0.05% sulfur....................................              97
Natural gas.............................................            99.9
------------------------------------------------------------------------

    AECC estimated the average cost-effectiveness of switching Bailey
Unit 1 to No. 6 fuel oil with 1% sulfur content to be $1,198 per ton of
SO2 removed. Switching from the baseline fuel to No. 6 fuel
oil with 0.5% sulfur content was estimated to cost $2,559 per ton of
SO2 removed. The results of AECC's cost analysis are
summarized in the table below. For the natural gas switching scenario,
AECC found that the current cost of natural gas is actually lower than
the cost of the baseline fuel. Therefore, the average cost-
effectiveness of switching from the baseline fuel to natural gas is
denoted as a negative value (cost savings) in the table below.
---------------------------------------------------------------------------

    \22\ The average cost-effectiveness was calculated by dividing
the total annual differential cost of switching from the baseline
fuel oil to the lower sulfur fuel.
    \23\ The incremental cost-effectiveness calculation compares the
costs and performance level of a control option to those of the next
most stringent option, as shown in the following formula (with
respect to cost per emissions reduction): Incremental Cost
Effectiveness (dollars per incremental ton removed) = (Total
annualized costs of control option)--(Total annualized costs of next
control option)/(Control option annual emissions)--Next control
option annual emissions). See BART Guidelines, 40 CFR Part 51,
Appendix Y, section IV.D.4.e.

                                      Table 7--AECC Bailey Unit 1: Summary of Costs Associated with Fuel Switching
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Total
                                                                                annual
                                      Average    Baseline   Controlled    Annual      Annual                  differential   Average cost   Incremental
      Fuel switching scenario         sulfur     emission    emission    emissions  fuel usage  Fuel cost ($/    cost of    effectiveness       cost
                                      content   rate ( SO2   rate (SO2  reductions   (Mgal/yr)     MMBtu)         fuel       \22\ ($/ton)  effectiveness
                                        (%)        tpy)        tpy)     ( SO2 tpy)                            switching ($/                 \23\ ($/ton)
                                                                                yr)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Baseline..........................        1.81       37.03  ..........  ..........      252.86         16.00  ............  .............  .............
No. 6 Fuel Oil--1%................        1.00  ..........       20.67       16.36      252.86         16.50       19,596           1,198  .............
No. 6 Fuel Oil--0.5%..............        0.50  ..........       10.23       26.80      252.86         17.75       68,587           2,559         4,693
Diesel............................        0.05  ..........        0.99       36.05      287.86         20.95      194,003           5,382        13,558
Natural Gas.......................        0.04  ..........        0.01       37.02       38.77          6.19     -384,550         -10,387      -596,446
--------------------------------------------------------------------------------------------------------------------------------------------------------

    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. The evaluation noted that
switching to natural gas may have energy impacts during periods of
natural gas curtailment. During periods of natural gas curtailment,
natural gas infrastructure maintenance, and other emergencies, the AECC
Bailey Generating Station relies on the fuel oil stored at the plant to
maintain electrical reliability. AECC's evaluation notes that because
of this, it is important to maintain the ability to burn fuel oil at
AECC Bailey, even if fuel oil is currently more expensive than natural
gas.
    With regard to consideration of the remaining useful life of Unit
1, this factor does not impact the SO2 BART analysis because
the emissions control approaches being evaluated for BART do not
require capital cost expenditures. Thus, there are no control costs
that need to be amortized over the lifetime of the unit.
    AECC assessed the visibility improvement associated with fuel
switching by comparing the 98th percentile modeled visibility impact of
the baseline scenario to the 98th percentile modeled visibility impact
of each control scenario. The table below shows a comparison of the
baseline visibility impacts and the visibility impacts of the different
fuel switching control scenarios that were evaluated, including the
cumulative visibility benefits.

                                        Table 8--AECC Bailey Unit 1: Summary of 98th Percentile Visibility Impacts and Improvement due to Fuel Switching
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Natural gas
                                                                                --------------------------------------------------------------------------------------------------------------
                                           Baseline   No. 6 fuel  No. 6 fuel                                                                                Visibility                Visibility
              Class I area                visibility    oil--1%    oil--0.5%    Diesel     Visibility    Visibility     Visibility    Visibility     Visibility  improvement   Visibility  improvement
                                            impact      sulfur      sulfur                   impact      improvement      impact      improvement      impact        from        impact        from
                                         ([Delta]dv)                                      ([Delta]dv)   from baseline  ([Delta]dv)   from baseline  ([Delta]dv)    baseline   ([Delta]dv)    baseline
                                                                                ([Delta]dv)                  ([Delta]dv)                ([Delta]dv)               ([Delta]dv)
--------------------------------------------------------------------------------------------------------------------------------------------------------------- ---------------------------------------
Caney Creek............................        0.330       0.193       0.137       0.142        0.188           0.084        0.246           0.083        0.247
Upper Buffalo..........................        0.348       0.194       0.154       0.127        0.221           0.069        0.279           0.072        0.276
Hercules-Glades........................        0.368       0.206       0.162       0.135        0.233           0.069        0.299           0.073        0.295
Mingo..................................        0.379       0.206       0.173       0.170        0.209           0.095        0.284           0.102        0.277
Cumulative Visibility Improvement        ...........  ..........       0.626  ..........        0.851  ..............        1.108  ..............        1.095
 ([Delta]dv)...........................
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

    The table above shows that switching to No. 6 fuel oil with 1%
sulfur content at Bailey Unit 1 is projected to result in 0.173 dv
visibility improvement at Mingo (based on the 98th percentile modeled
visibility impacts). The visibility improvement at each of the other
three affected Class I areas is projected to be slightly less than that
amount, while the cumulative visibility improvement at the four Class I
areas is projected to be 0.626 dv. Switching to No. 6 fuel oil with
0.5% sulfur content is projected to result in meaningful visibility
improvement. It is projected to result in 0.233 dv visibility
improvement at Hercules-Glades. The visibility improvement at each of
the other three affected Class I areas is projected to be slightly less
than that amount, while the cumulative visibility improvement at the
four Class I areas is projected to be 0.851 dv. Switching to diesel or
natural gas is also projected to result in meaningful visibility
improvement. The visibility improvement at Hercules-Glades is projected
to be 0.299 dv for switching to diesel and 0.295 dv for switching to
natural gas, and slightly less than that amount at each of the other
three affected Class I areas. The cumulative visibility improvement at
the four Class I areas is projected to be 1.108 dv for switching to
diesel and 1.095 dv for switching to natural gas.
    Our Proposed SO2 BART Determination: Taking into
consideration the five factors, we are proposing to determine that BART
for the AECC Bailey Unit 1 is switching to fuels with 0.5% or lower
sulfur content by weight. The cost effectiveness of switching to No. 6
fuel oil with 0.5% sulfur content is within the range of what we
consider to be cost-effective for BART and it is projected to result in
considerable visibility improvement compared to the baseline at the
affected Class I areas. Switching to No. 6 fuel oil with 0.5% sulfur
content has an estimated average cost-effectiveness of $2,559 per ton
of SO2 removed and is projected to result in visibility
improvement ranging from 0.188 to 0.233 dv at each modeled Class I
area, and a cumulative visibility improvement of 0.851 dv at the four
modeled Class I areas. Switching to natural gas would currently cost
less than the baseline fuel and is projected to result in even greater
visibility improvement than switching to No. 6 fuel oil with 0.5%
sulfur content. However, 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 gas (40 CFR part 51, Appendix Y, section
IV.D.1). Because 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 are not proposing to require a switch to
natural gas for Unit 1. Switching to diesel is projected to result in
an almost identical level of visibility improvement at each Class I
area as switching to natural gas. The incremental visibility
improvement of switching to diesel compared to switching to No. 6 fuel
oil with a sulfur content of 0.5% is projected to range from 0.058 dv
to 0.075 dv at each affected Class I area but the average cost-
effectiveness is estimated to be $5,382 per ton of SO2
removed and the incremental cost-effectiveness compared to switching to
No. 6 fuel oil with a sulfur content of 0.5% is estimated to be $13,558
per ton of SO2 removed, which we do not consider to be very
cost-effective in view of the incremental visibility improvement.
Because diesel also 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 are not proposing to require a switch to diesel for Unit
1. We are proposing to determine that SO2 BART for Bailey
Unit 1 is switching to fuels with 0.5% or lower sulfur content by
weight. We propose to require that the facility purchase no fuel after
the effective date of the rule that does not meet the sulfur content
requirement and that 5 years from the effective date of the rule no
fuel be burned that does not meet the requirement. We propose that any
higher sulfur fuel oil that remains from the facility's 2006 fuel oil
shipment cannot be burned past this point. As discussed above, the
unit's baseline fuel is No. 6 fuel oil with 1.81% sulfur content, based
on the average sulfur content of the fuel oil from the most recent fuel
oil shipment received by the facility in 2006. Based on our discussions
with the facility, it is our understanding that the unit burns fuel oil
primarily during periods of natural gas curtailment and during periodic
testing and that the facility still has stockpiles of fuel oil from the
most recent shipment. Because the unit burns primarily natural gas and
does not ordinarily burn fuel oil on a frequent basis, we believe it is
appropriate to allow the facility 5 years to burn its existing supply
of No. 6 fuel oil, as the normal course of business dictates and in
accordance with any operating restrictions enforced by ADEQ. We believe
that a shorter compliance date may result in the facility burning its
existing supply of higher sulfur No. 6 fuel oil relatively quickly,
resulting in a high amount of SO2 emissions being emitted by
the unit over a short period of time. This is not the intent of our
regional haze regulations. We are also proposing regulatory text that
includes monitoring, reporting, and recordkeeping requirements
associated with this proposed determination.
    b. Proposed BART Analysis and Determination for NOX. AECC's BART
evaluation examined BART controls for NOX for AECC Bailey
Unit 1. Bailey Unit 1 does not currently have pollution control
equipment for NOX. AECC's evaluation identified all
available control technologies, eliminated options that are not
technically feasible, and evaluated the control effectiveness of the
remaining control options. Each technically feasible control option was
then evaluated in terms of a five factor BART analysis.
    For NOX BART, AECC's evaluation considered both
combustion and post-combustion controls. The combustion controls
evaluated by AECC consisted of flue gas recirculation (FGR), overfire
air (OFA), and low NOX burners (LNB). The post-combustion
controls evaluated consisted of selective catalytic reduction (SCR) and
selective non-catalytic reduction (SNCR). AECC found that some boilers
may be restricted from installing OFA retrofits due to physical size
and space restraints. For purposes of the NOX BART
evaluation, AECC assumed OFA to be a technically feasible option for
Bailey Unit 1, but noted that if OFA was determined to be BART based on
the evaluation of the five BART factors, then further analyses would
have to be performed to determine if: (1) The dimensions of AECC
Bailey's main boilers have sufficient upper furnace volume for OFA
mixing and complete combustion and (2) the furnace meets the physical
space requirements for OFA ports and air supply ducts. The remaining
NOX control options were found to be technically feasible.
    AECC evaluated three control scenarios: A combination of combustion
controls (FGR, OFA, and LNB); the combination of combustion controls
and SNCR; and SCR. Based on literature estimates, AECC found that the
estimated NOX control range for oil and gas wall-fired
boilers, such as Bailey Unit 1, is approximately 0.2-0.4 lb/MMBtu using
FGR and 0.2-0.3 lb/MMBtu using OFA.\24\ When LNB is combined with OFA
and FGR, AECC

estimated that a NOX controlled emission rate of 0.15--0.20
lb/MMBtu can be achieved at Bailey Unit 1. The NOX
controlled emission rate of combustion controls combined with SNCR is
estimated to be 0.12 lb/MMBtu. The NOX control efficiency of
SCR is estimated to be 80-90% for gas fired boilers and 70-80% for oil
fired boilers, which corresponds to a controlled emission rate of 0.04-
0.08 lb/MMBtu for Bailey Unit 1.
---------------------------------------------------------------------------

    \24\ ``Controlling Nitrogen Oxides Under the Clean Air Act: A
Menu of Options,'' section II, dated July 1994, State and
Territorial Air Pollution Program Administrators (STAPPA) and
Association of Local Air Pollution Control Officials (ALAPCO).
---------------------------------------------------------------------------

    AECC's cost analysis for NOX controls was based on
``budgetary'' cost estimates it obtained by AECC from the pollution
control equipment vendor, Babcock Power Systems. AECC estimated the
capital and operating costs of controls based on the vendor's
estimates, engineering estimates, and published calculation methods
using EPA's Air Pollution Control Cost Manual (EPA Control Cost
Manual).\25\ We are not aware of any enforceable shutdown date for the
AECC Bailey Generating Station, nor did AECC's evaluation indicate any
future planned shutdown. This means that the anticipated useful life of
the boiler is expected to be at least as long as the capital cost
recovery period of controls. Therefore, a 30-year amortization period
was assumed in the NOX BART analysis as the remaining useful
life of Unit 1. The table below summarizes the estimated cost for
installation and operation of NOX controls for Bailey Unit
1.
---------------------------------------------------------------------------

    \25\ EPA's ``Air Pollution Control Cost Manual,'' Sixth edition,
January 2002, is located at www.epa.gov/ttncatc1/products.html#cccinfo.

                                                                  Table 9--Summary of NOX Control Costs for AECC Bailey Unit 1
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Natural gas      Fuel oil
                                                                   Baseline       controlled      controlled      Controlled        Annual                       Average cost-  Incremental cost-
                       Control scenario                          emission rate  emission level  emission level   emission rate     emissions     Total annual    effectiveness  effectiveness($/
                                                                   (NOX tpy)      (lb/MMBtu)      (lb/MMBtu)       (NOX tpy)      reductions      cost ($/yr)       ($/ton)           ton)
                                                                                \26\            \27\                          (NOX tpy)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Combustion Controls...........................................           49.81            0.15            0.15           30.83           18.98         700,477          36,905  ................
Combustion Controls + SNCR....................................           49.81            0.12            0.12           24.79           25.02       1,223,157          48,884           86,536
SCR \28\......................................................           49.81            0.04            0.08            9.65           40.16       1,555,718          38,738           21,966
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

    AECC estimated the average cost-effectiveness of installing and
operating combustion controls to be $36,905 per ton of NOX
removed for Bailey Unit 1. The combination of combustion controls and
SNCR was estimated to cost $48,884 per ton of NOX removed,
while SCR was estimated to cost $38,738 per ton of NOX
removed. In its evaluation, AECC also explained that it expects the
cost-effectiveness of NOX controls to be lower (i.e.,
greater dollars per ton removed) in future years due to projected
reduced operation of the unit.
---------------------------------------------------------------------------

    \26\ See the preceding paragraphs for a discussion of the
expected controlled emission rates for natural gas vs. fuel oil
firing.
    \27\ Id.
---------------------------------------------------------------------------

    AECC did not identify any energy or non-air quality environmental
impacts associated with the use of LNB, OFA, or FGR. As for SCR and
SNCR, we are not aware of any unusual circumstances at the facility
that could create non-air quality environmental impacts associated with
the operation of these controls greater than experienced elsewhere and
that may therefore provide a basis for their elimination as BART (40
CFR part 51, Appendix Y, section IV.D.4.i.2.). Therefore, we do not
believe there are any energy or non-air quality environmental impacts
associated with NOX controls at AECC Bailey Unit 1 that
would affect our proposed BART determination.
    AECC assessed the visibility improvement associated with
NOX controls by modeling the NOX emission rates
associated with each control option using CALPUFF, and then comparing
the visibility impairment associated with the baseline emission rates
to the visibility impairment associated with the controlled emission
rates as measured by the 98th percentile modeled visibility impact. The
tables below show a comparison of the baseline (i.e., existing)
visibility impacts and the visibility impacts associated with
NOX controls.

         Table 10--AECC Bailey Unit 1: Summary of the 98th Percentile Visibility Impacts and Improvement Due to NOX Controls--Natural Gas Firing
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                Combustion controls         Combustion controls + SNCR                  SCR
                                             Baseline    -----------------------------------------------------------------------------------------------
                                            visibility                      Visibility                      Visibility                      Visibility
              Class I area                    impact        Visibility      improvement     Visibility      improvement     Visibility      improvement
                                            ([Delta]dv)       impact       from baseline      impact       from baseline      impact       from baseline
                                                            ([Delta]dv)     ([Delta]dv)     ([Delta]dv)     ([Delta]dv)     ([Delta]dv)     ([Delta]dv)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Caney Creek.............................           0.083           0.039           0.044           0.032           0.051           0.014           0.069
Upper Buffalo...........................           0.072           0.034           0.038           0.028           0.044           0.013           0.059
Hercules-Glades.........................           0.073           0.035           0.038           0.029           0.044           0.013           0.06
Mingo...................................           0.102           0.051           0.051           0.043           0.059           0.021           0.081
Cumulative Visibility Improvement         ..............  ..............           0.171  ..............           0.198  ..............           0.269
 ([Delta]dv)............................
--------------------------------------------------------------------------------------------------------------------------------------------------------

          Table 11--AECC Bailey Unit 1: Summary of the 98th Percentile Visibility Impacts and Improvement Due to NOX Controls--Fuel Oil Firing
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                Combustion controls         Combustion controls + SNCR                  SCR
                                             Baseline    -----------------------------------------------------------------------------------------------
                                            visibility                      Visibility                      Visibility                      Visibility
              Class I area                    impact        Visibility      improvement     Visibility      improvement     Visibility      improvement
                                            ([Delta]dv)       impact       from baseline      impact       from baseline      impact       from baseline
                                                            ([Delta]dv)     ([Delta]dv)     ([Delta]dv)     ([Delta]dv)     ([Delta]dv)     ([Delta]dv)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Caney Creek.............................           0.330           0.325           0.005           0.325           0.005           0.323           0.007
Upper Buffalo...........................           0.347           0.332           0.015           0.329           0.018           0.325           0.022
Hercules-Glades.........................           0.367           0.339           0.028           0.333           0.034           0.325           0.042
Mingo...................................           0.378           0.369           0.009           0.367           0.011           0.364           0.014
Cumulative Visibility Improvement         ..............  ..............           0.057  ..............           0.068  ..............           0.085
 ([Delta]dv)............................
--------------------------------------------------------------------------------------------------------------------------------------------------------

    The tables above show that the installation and operation of
NOX controls is projected to result in a very modest
visibility improvement from the baseline. Combustion controls at Bailey
Unit 1 are projected to result in visibility improvement of up to 0.051
dv at any single Class I area for the natural gas firing scenario and
0.028 dv for the fuel oil firing scenario (based on the 98th percentile
modeled visibility impacts). A combination of combustion controls and
SNCR is projected to result in only slight incremental visibility
improvement over combustion controls alone. For example, a combination
of combustion controls and SNCR at Bailey Unit 1 is projected to result
in visibility improvement of up to 0.059 dv at any single Class I area
for natural gas firing and 0.034 dv for fuel oil firing, which is an
incremental visibility improvement of 0.008 dv for natural gas firing
and 0.006 dv for fuel oil firing compared to combustion controls alone.
Similarly, the installation and operation of SCR is projected to result
in only slight incremental visibility improvement compared to a
combination of combustion controls and SNCR.
    Our Proposed NOX BART Determination: Taking into consideration the
five factors, we are proposing to determine that NOX BART
for the AECC Bailey Unit 1 is no additional controls, and are proposing
that the facility's existing NOX emission limit satisfies
BART for NOX. We are proposing the existing emission limit
of 887 lb/hr for NOX BART for Bailey Unit 1.\29\ As
discussed above, the operation of combustion controls at Bailey Unit 1
is projected to result in a maximum visibility improvement of 0.051 dv
(Mingo), and a smaller amount of visibility improvement at each of the
other affected Class I areas. The installation and operation of
combustion controls at Bailey Unit 1 has an average cost-effectiveness
of $36,905 per ton of NOX removed, which is not within the
range of what we consider cost-effective. We believe the relatively
small visibility benefit projected from the operation of combustion
controls both when combusting fuel oil and natural gas does not justify
the estimated cost of those controls. The operation of a combination of
combustion controls and SNCR is estimated to cost $48,884 per ton of
NOX removed, which is also not within the range of what we
consider cost-effective. A combination of combustion controls and SNCR
is projected to result in only slight incremental visibility benefit
compared to combustion controls alone. The operation of SCR is
estimated to cost $38,738 per ton of NOX removed, which is
not cost-effective, and is projected to result in only slight
incremental visibility benefit compared to a combination of combustion
controls and SNCR. We are proposing to find that NOX BART
for Bailey Unit 1 is no additional controls and are proposing that the
existing NOX emission limit of 887 lb/hr is BART for
NOX and that compliance be demonstrated using the unit's
existing CEMS. We are proposing that this emission limitation be
complied with for BART purposes from the date of effectiveness of the
finalized action. We are also proposing regulatory text that includes
monitoring, reporting, and recordkeeping requirements associated with
these emission limits.
---------------------------------------------------------------------------

    \29\ See ADEQ Operating Air Permit No. 0154-AOP-R4, Section IV,
Specific Conditions No. 1 and 7.
---------------------------------------------------------------------------

    c. Proposed BART Analysis and Determination for PM. PM emissions
are inherently low when burning natural gas. Bailey Unit 1 does not
currently have pollution control equipment for PM. AECC's BART
evaluation 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.
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.\30\ Therefore, switching to No. 6 fuel oil
with a lower sulfur content is expected to result in lower filterable
PM emissions. AECC's evaluation considered switching to No. 6 fuel oil
with 1% sulfur content by weight, No. 6 fuel oil with 0.5% sulfur
content by weight, diesel, and natural gas. These are the same lower
sulfur fuel types evaluated in the SO2 BART analysis for the
unit.
---------------------------------------------------------------------------

    \30\ See ``AP-42, Compilation of Air Pollutant Emission
Factors,'' section <IP_ADDRESS>, and Table 1.3-1, available at http://www.epa.gov/ttnchie1/ap42/.
---------------------------------------------------------------------------

    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, dry ESPs and fabric filters
are deemed technically infeasible for use at Bailey Unit 1. Wet ESPs,
cyclones, wet scrubbers, and fuel switching were identified as
technically feasible options for Bailey Unit 1. AECC noted that
although cyclones and wet scrubbers are considered technically feasible
for use at these boiler types, they are not very efficient at
controlling particles in the smaller size fraction, particularly
particles smaller than a few microns. However, the majority of the PM
emissions from Bailey Unit 1 are greater than a few microns in size.

    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 other technically feasible control technologies are
estimated to have the following PM control efficiency: Wet ESP--up to
90%, cyclone--85%, and wet scrubber--55%.
    AECC evaluated the capital costs, operating costs, and average
cost-effectiveness of wet ESPs, cyclones, and wet scrubbers. It also
evaluated the average cost-effectiveness of switching to No. 6 fuel oil
with 1% sulfur content, No. 6 fuel oil with 0.5% sulfur content,
diesel, and natural gas. AECC developed the capital and operating costs
of a wet ESP and wet scrubber using the Electric Power Research
Institute's (EPRI) Integrated Emissions Control Cost Estimating
Workbook (IECCOST) Software. The capital costs of controls (except for
fuel switching) were annualized over a 15-year period and then added to
the annual operating costs to obtain the total annualized costs. The
table below summarizes the average cost-effectiveness of PM controls.
The average cost-effectiveness was determined by dividing the
annualized cost of controls by the annual PM emissions reductions. The
annual emissions reductions were determined by subtracting the
estimated controlled annual emission rates from the baseline annual
emission rates. AECC estimated the baseline and controlled annual
emission rates by conducting a mass balance on the sulfur content of
the various fuels evaluated.
    We disagree with two aspects of AECC's cost evaluation for PM
controls. First, the total annual cost numbers associated with fuel
switching should be the same as those used in the SO2 BART
cost analysis for Bailey Unit 1 (see Table 7). In earlier draft
versions of AECC's BART analysis, which were provided to us for review,
the cost numbers for fuel switching used in the PM and SO2
BART analyses were identical. In response to comments provided by us,
the total annual cost and average cost-effectiveness numbers for fuel
switching were revised in the final version of AECC's SO2
BART analysis. However, it appears that AECC overlooked updating these
cost numbers in the final PM BART analysis.\31\ In the table below, we
have revised the total annual cost of fuel switching for the PM BART
analysis to be consistent with the cost estimates from AECC's
SO2 BART analysis, and we have also updated the PM average
cost-effectiveness values. The second aspect of AECC's cost evaluation
for PM controls that we disagree with is the use of a 15-year capital
cost recovery period for calculating the average cost-effectiveness of
a wet ESP, wet scrubber, and cyclone. As previously discussed, we are
not aware of any enforceable shutdown date for the AECC Bailey
Generating Station, nor did AECC's evaluation indicate any future
planned shutdown. 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. 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., less dollars per ton removed).
However, after considering all five BART factors, we do not believe
AECC's assumption of a 15-year amortization period has an impact on our
proposed BART decision and therefore we did not revise the amortization
period or the average cost-effectiveness calculations for the PM
control options. This is discussed in more detail below. The table
below summarizes the estimated cost for fuel switching and the
installation and operation of PM control equipment for Bailey Unit 1.
---------------------------------------------------------------------------

    \31\ The final version of AECC's BART analysis for
SO2 and PM, upon which our analysis is largely based, is
titled ``BART Five Factor Analysis Arkansas Electric Cooperative
Corporation Bailey and McClellan Generating Stations, March 2014,
Version 4.'' A copy of AECC's analysis can be found in the docket
for our proposed rulemaking.

             Table 12--Summary of Cost of PM Controls for AECC Bailey Unit 1--Baseline Is No. 6 Fuel Oil With 1.81% Sulfur Content by Weight
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                        Baseline                   Controlled      Annual                                                   Incremental
                                        emission       Control      emission      emissions   Capital cost  Total annual   Average cost-       cost-
          Control scenario              rate (PM     efficiency     rate (PM     reductions        ($)       cost ($/yr)   effectiveness   effectiveness
                                          tpy)           (%)          tpy)        (PM tpy)                                    ($/ton)         ($/ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Wet Scrubber........................         25.63          55.0         11.53         14.09   140,957,713    50,150,862       3,558,286  ..............
No. 6 Fuel oil--1% S................         25.63          65.7          8.80         16.83  ............        19,596           1,164     -18,296,082
Cyclone.............................         25.63          85.0          3.84         21.78       989,479     1,188,630          54,570         236,168
No. 6 Fuel oil--0.5% S..............         25.63          89.3          2.75         22.88  ............        68,587           2,997      -1,020,948
Wet ESP.............................         25.63          90.0          2.56         23.06   105,141,431    22,638,340         981,583     125,387,517
Natural Gas.........................         25.63          99.0          0.26         25.37  ............      -384,550         -15,157      -9,966,619
Diesel..............................         25.63          99.5          0.13         25.50  ............       194,003           7,608       4,450,408
--------------------------------------------------------------------------------------------------------------------------------------------------------

    The table above shows that the average cost-effectiveness values of
all add-on PM control technology options evaluated for AECC Bailey Unit
1 ranged from approximately $55,000 per ton of PM removed to more than
$3.5 million per ton of PM removed. The incremental cost-effectiveness
of add-on PM control technology options ranged from $236,168 to
$125,387,517 per ton of PM removed. Switching to No. 6 fuel oil with
either a 1% or 0.5% sulfur content was found to be within the range of
what we generally consider cost-effective for BART. Switching to No. 6
fuel oil with 1% sulfur content is estimated to cost $1,164 per ton of
PM removed, while switching to No. 6 fuel oil with 0.5% sulfur content
is estimated to cost $2,997 per ton of PM removed. As discussed in the
SO2 BART analysis, the current cost of natural gas is
actually lower than the cost of the baseline fuel. Therefore, the
average cost-effectiveness of switching from the baseline fuel to
natural gas is denoted as a negative value in the table above. As
discussed above, AECC also explained that it expects the average cost-
effectiveness of PM control equipment to be lower (i.e., greater
dollars per ton removed) in future years due to projected reduced
operation of the unit due to a change in the management of the load
control area in which the facility is located.
    AECC did not identify any energy or non-air quality environmental
impacts associated with fuel switching, but did identify impacts
associated with the use of wet ESPs and wet scrubbers due to their
electricity usage. Energy use in and of itself does not disqualify a
technology (40 CFR part 51, Appendix Y, section IV.D.4.h.1.). In
addition, the cost of the electricity needed to operate this equipment
has already been factored into the cost of controls. AECC also

noted that both wet ESPs and wet scrubbers generate wastewater streams
that must either be treated on-site or sent to a waste water treatment
plant, and the wastewater treatment process will generate a filter cake
that would likely require landfilling. The BART Guidelines provide that
the fact that a control device creates liquid and solid waste that must
be disposed of does not necessarily argue against selection of that
technology as BART, particularly if the control device has been applied
to similar facilities elsewhere and the solid or liquid waste is
similar to those other applications. (40 CFR part 51, Appendix Y,
section IV.D.4.i.2.). We are not aware of any unusual circumstances at
the AECC Bailey Generating Station that could potentially create
greater problems than experienced elsewhere related to the treatment of
wastewater and any necessary landfilling, nor did AECC's evaluation
discuss or mention any such unusual circumstances. Therefore, the need
to treat wastewater or landfill any filter cake or other waste in and
of itself does not provide a basis for disqualification or elimination
of a wet ESP or wet scrubber.
    As previously discussed, we are not aware of any enforceable
shutdown date for the AECC Bailey Generating Station, nor did AECC's
evaluation indicate any future planned shutdown. Therefore, we believe
it is appropriate to assume a 30-year amortization period in the PM
BART analysis as the remaining useful life of the unit. Assuming a 30-
year amortization period, these controls would have a lower estimated
total annual cost and would therefore have an improved cost-
effectiveness (i.e., less dollars per ton removed) than estimated in
AECC's evaluation. However, we did not adjust the amortization period
because we do not believe this has an impact on our proposed BART
decision. As discussed in the subsection below, the visibility benefit
expected from the installation and operation of PM control equipment is
too small to justify the cost of these controls. Therefore, we did not
revise the amortization period and the average cost-effectiveness
calculations for the PM control equipment options.
    As switching to lower sulfur fuels has impacts on both
SO2 and PM emissions, AECC's assessment of the visibility
improvement associated with fuel switching is addressed in the
SO2 BART analysis for Bailey Unit 1. Table 8 summarizes the
visibility improvement associated with controlled emission rates for
SO2 and PM as a result of fuel switching. AECC assessed the
visibility improvement associated with wet ESPs, wet scrubbers, and
cyclones by modeling the PM emission rates associated with each control
option using CALPUFF, and then comparing the visibility impairment
associated with the baseline emission rates to the visibility
impairment associated with the controlled emission rates as measured by
the 98th percentile modeled visibility impact. The controlled
PM10 emission rates associated with wet ESPs, wet scrubbers,
and cyclones were calculated by reducing the uncontrolled annual
PM10 emission rates by the pollutant removal efficiency of
each control technology. The SO2 and NOX emission
rates modeled in the controlled scenarios are the same as those from
the baseline scenario, as it is assumed that SO2 and
NOX emissions would remain unchanged. The table below shows
a comparison of the baseline (i.e., existing) visibility impacts and
the visibility impacts associated with PM controls.

                    Table 13--AECC Bailey Unit 1: Summary of the 98th Percentile Visibility Impacts and Improvement From PM Controls
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Wet ESP                  Wet scrubber                 Cyclone
                                                                        --------------------------------------------------------------------------------
                                                             Baseline                  Visibility                 Visibility                 Visibility
                       Class I area                         visibility    Visibility   improvement   Visibility   improvement   Visibility   improvement
                                                              impact        impact        from         impact        from         impact        from
                                                            ([Delta]dv)  ([Delta]dv)    baseline    ([Delta]dv)    baseline    ([Delta]dv)    baseline
                                                                                ([Delta]dv)                ([Delta]dv)                ([Delta]dv)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Caney Creek..............................................         0.330        0.327         0.003        0.328         0.002        0.328         0.002
Upper Buffalo............................................         0.347        0.343         0.004        0.345         0.002        0.345         0.002
Hercules-Glades..........................................         0.367        0.356         0.011        0.360         0.007        0.361         0.006
Mingo....................................................         0.378        0.371         0.007        0.374         0.004        0.374         0.004
Cumulative Visibility Improvement ([Delta]dv)............  ............  ...........         0.025  ...........         0.015  ...........         0.014
--------------------------------------------------------------------------------------------------------------------------------------------------------

    The table above shows that the operation of a wet ESP, wet
scrubber, or cyclone at Bailey Unit 1 is projected to result in minimal
visibility improvement at the four affected Class I areas. The modeled
visibility improvement from switching to No. 6 fuel oil with 1% sulfur
content, No. 6 fuel oil with 0.5% sulfur content, diesel, or natural
gas is summarized in Table 8. The modeled visibility improvement shown
in Table 8 reflects both SO2 and PM emissions reductions as
a result of switching to fuels with lower sulfur content. However, the
majority of the baseline visibility impact at each Class I area when
burning the baseline fuel oil is due to SO2 emissions, while
PM10 emissions contribute only a small portion of the
baseline visibility impacts at each Class I area (see Table 5).
Accordingly, the majority of the visibility improvement associated with
switching to lower sulfur fuels can reasonably be expected to be the
result of a reduction in SO2 emissions.
    Our Proposed PM BART Determination: Taking into consideration the
five factors, we propose to determine that PM BART for the AECC Bailey
Unit 1 does not require add-on controls. Consistent with our proposed
determination for SO2 BART, we are proposing that PM BART is
satisfied by Unit 1 switching to fuels with 0.5% or lower sulfur
content by weight. As discussed above, we disagree with AECC's use of a
15-year amortization period in the cost analysis for a wet ESP, wet
scrubber, and cyclone. Assuming a 30-year amortization period, these
controls would have lower estimated total annual costs and would
therefore have an improved cost-effectiveness (i.e., less dollars per
ton removed) compared to what was estimated in AECC's evaluation.
However, after considering all five BART factors, even if we revised
AECC's cost estimates to reflect a 30-year amortization period,
resulting in a lower total annual cost and improved cost-effectiveness,
we would still not be able to justify the cost of add-on controls in
light of the minimal visibility benefit of these controls (see the
table above).
    We are proposing to determine that PM BART for Bailey Unit 1 is
switching to fuels with 0.5% or lower sulfur

content by weight. We propose to require that the facility purchase no
fuel after the effective date of the rule that does not meet the sulfur
content requirement and that 5 years from the effective date of the
rule no fuel be burned that does not meet the requirement. We propose
that any higher sulfur fuel oil that remains from the facility's 2006
fuel oil shipment cannot be burned past this point. As previously
discussed, the unit's baseline fuel is No. 6 fuel oil with 1.81% sulfur
content, based on the average sulfur content of the fuel oil from the
most recent shipment received by the facility in 2006. Based on our
discussions with the facility, it is our understanding that the unit
burns fuel oil primarily during periods of natural gas curtailment and
during periodic testing and that the facility still has stockpiles of
fuel oil from the most recent fuel oil shipment. Because the unit burns
primarily natural gas and does not ordinarily burn fuel oil on a
frequent basis, we believe it is appropriate to allow the facility 5
years to burn its existing supply of No. 6 fuel oil, as the normal
course of business dictates and in accordance with any operating
restrictions enforced by ADEQ. We believe that a shorter compliance
date may result in the facility burning its existing supply of higher
sulfur No. 6 fuel oil relatively quickly, resulting in a high amount of
SO2 emissions being emitted by the unit over a short period
of time. This is not the intent of our regional haze regulations. We
are also proposing regulatory text that includes monitoring, reporting,
and recordkeeping requirements associated with this proposed
determination.
2. AECC John L. McClellan Generating Station
    The AECC McClellan Unit 1 is subject to BART. As mentioned
previously, we disapproved Arkansas' BART determinations for
SO2, NOX, and PM for McClellan Unit 1 in our
March 12, 2012 final action (77 FR 14604). The AECC McClellan Unit 1 is
a wall-fired boiler with a gross output of 134 MW and a maximum heat
input rate of 1,436 MMBtu/hr. The unit is currently permitted to burn
natural gas and fuel oil. The fuel oil burned is currently subject to a
sulfur content limit of 2.8% by weight. AECC, through its consultant,
performed a five-factor analysis for McClellan Unit 1 (AECC's BART
analysis).\32\
---------------------------------------------------------------------------

    \32\ See the following BART analyses: ``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; and ``BART Five Factor Analysis-
NOX Analysis, Addendum to the July 24, 2012 BART Five
Factor Analysis, Arkansas Electric Cooperative Corporation Bailey
and McClellan Generating Stations,'' dated December 2013, Version 3.
A copy of these two BART analyses can be found in the docket for our
proposed rulemaking.
---------------------------------------------------------------------------

    The table below summarizes the baseline emission rates for the
source. The SO2 and NOX baseline emission rates
are the highest actual 24-hour emission rates based on 2001-2003 CEMS
data, while the PM baseline emission rates are based on stack testing
and AP-42 emission factors.

                                               Table 14--Baseline Emission Rates for AECC McClellan Unit 1
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Total
                       Unit/fuel scenario                          SO2 (lb/   NOX (lb/  PM10 (lb/   SO4 (lb/   PMc (lb/   PMf (lb/   SOA (lb/   EC (lb/
                                                                     hr)        hr)        hr)        hr)        hr)        hr)        hr)        hr)
--------------------------------------------------------------------------------------------------------------------------------------------------------
McClellan, Unit 1--Natural Gas..................................        0.6      423.9       10.9        0.3        0.0        0.0        7.9        2.7
McClellan, Unit 1--Fuel Oil.....................................    2,747.5      579.8       59.4        5.9       14.2       35.4       1.00        2.8
--------------------------------------------------------------------------------------------------------------------------------------------------------

    The NOX and PM baseline emission rates AECC modeled for
the fuel oil firing scenario were updated from what the State modeled
in the 2008 Arkansas RH SIP. The revised NOX emission rates
for the fuel oil firing scenario are higher than what was modeled in
the 2008 Arkansas RH SIP, while the revised PM10 emission
rates for fuel oil firing scenario are lower than what was modeled in
the 2008 Arkansas RH SIP. We have some concern with AECC's use of the
PM10 baseline emission rates, which were based on stack
testing, because there is no discussion provided on how the stack test
results are representative of the maximum 24-hour emissions. However,
because the visibility impacts due to PM10 emissions from
McClellan Unit 1 are so small, we believe a closer inspection of the
revised PM10 emission rates and any further updates to these
would likely not result in significant changes to the modeled
visibility impacts and would not affect our proposed BART decision. As
shown in the table below, the percentage of the visibility impairment
attributable to PM10 at the Class I area with the highest
visibility impacts (Caney Creek) is 6.63% for the natural gas firing
scenario and 0.53% for the fuel oil firing scenario. Most of the
visibility impairment is attributable to NO3 (87.09%) for
the natural gas firing scenario and to SO4 (89.86%) for the
fuel oil firing scenario. Therefore, we did not take further steps to
adjust the PM10 emission rates or conduct additional
modeling.
    AECC modeled the baseline emission rates using the CALPUFF
dispersion model to determine the baseline visibility impairment
attributable to McClellan Unit 1 at the four Class I areas impacted by
emissions from BART sources in Arkansas. These Class I areas are the
Caney Creek Wilderness Area, Upper Buffalo Wilderness Area, Hercules-
Glades Wilderness Area, and Mingo National Wildlife Refuge. The
baseline (i.e., existing) visibility impairment attributable to
McClellan Unit 1 at each Class I area is summarized in the table below.

                             Table 15--98th Percentile Baseline Visibility Impairment Attributable to AECC McClellan Unit 1
                                                                       [2001-2003]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                               98th            98th            98th            98th            98th
                   Unit/fuel scenario                         Maximum       Percentile     Percentile (%   Percentile (%   Percentile (%   Percentile (%
                                                            ([Delta]dv)     ([Delta]dv)        SO4)            NO3)            PM10)           NO2)
--------------------------------------------------------------------------------------------------------------------------------------------------------
McClellan Unit 1--Natural Gas:
    Caney Creek.........................................           0.670           0.125            0.39           87.09            6.63            5.89

    Upper Buffalo.......................................           0.258           0.052            0.34           91.78            4.82            3.05
    Hercules-Glades.....................................           0.092           0.040            0.74           86.01           10.18            3.07
    Mingo...............................................           0.132           0.058            0.33           91.96            5.13            2.58
McClellan Unit 1--Fuel Oil:
    Caney Creek.........................................           3.007           0.622           89.86            9.62            0.53            0.00
    Upper Buffalo.......................................           1.323           0.266           98.47            0.95            0.58            0.00
    Hercules-Glades.....................................           0.662           0.231           78.67           20.16            1.17            0.01
    Mingo...............................................           0.547           0.228           80.90           17.89            1.20            0.01
--------------------------------------------------------------------------------------------------------------------------------------------------------

    a. Proposed BART Analysis and Determination for SO2. AECC's BART
evaluation examined BART controls for SO2 for the AECC
McClellan Unit 1. The source does not have existing SO2
pollution control technology. AECC identified all available control
technologies, eliminated options that are not technically feasible, and
evaluated the control effectiveness of the remaining control options.
Each technically feasible control option was then evaluated in terms of
a five factor BART analysis.
    The AECC evaluation considered both FGD and fuel switching as
possible controls. AECC found that FGD applications have not been used
historically for SO2 control on fuel oil-fired units in the
U.S. electric industry and therefore considered it a technically
infeasible option for control of McClellan Unit 1. Accordingly, AECC
did not further consider FGD for SO2 BART. We concur with
AECC's decision to focus the SO2 BART evaluation on fuel
switching. Switching to a fuel with a lower sulfur content is expected
to reduce SO2 emissions in proportion to the reduction in
the sulfur content of the fuel, assuming the fuels have similar heat
contents. McClellan Unit 1 burns primarily natural gas, but is also
permitted to burn fuel oil. The baseline fuel AECC assumed in the BART
analysis is No. 6 fuel oil with 1.38% sulfur content, based on the
average sulfur content of the fuel oil from the most recent fuel oil
shipment received by the facility in April 2009. A portion of the fuel
oil from this shipment still remains in storage at the facility for
future use. AECC evaluated switching to the fuel types shown in the
table below.

   Table 16--Control Effectiveness of Fuel Switching Options for AECC
                            McClellan Unit 1
------------------------------------------------------------------------
                                                          Estimated SO2
                 Fuel switching options                      control
                                                          efficiency (%)
------------------------------------------------------------------------
No. 6 fuel oil, 1% sulfur..............................             28
No. 6 fuel oil, 0.5% sulfur............................             64
Diesel, 0.05% sulfur...................................             96
Natural gas............................................             99.9
------------------------------------------------------------------------

    AECC estimated the average cost-effectiveness of switching to No. 6
fuel oil with 1% sulfur content to be $2,613 per ton of SO2
removed for McClellan Unit 1. Switching from the baseline fuel to No. 6
fuel oil with 0.5% sulfur content was estimated to cost $3,823 per ton
of SO2 removed. The results of AECC's cost analysis are
summarized in the table below. For the natural gas switching scenario,
AECC found that the current cost of natural gas is actually lower than
the cost of the baseline fuel. Therefore, the average cost-
effectiveness of switching from the baseline fuel to natural gas is
denoted as a negative value (cost savings) in the table below.

                                    Table 17--AECC McClellan Unit 1: Summary of Costs Associated With Fuel Switching
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Total annual
                                  Average      Baseline    Controlled     Annual    Annual fuel               differential   Average cost   Incremental
    Fuel switching scenario        sulfur      emission     emission    emissions   usage (Mgal/  Fuel cost   cost of fuel  effectiveness       cost
                                content (%)   rate (SO2    rate (SO2    reductions      yr)       ($/MMBtu)   switching ($/    ($/ton)     effectiveness
                                                 tpy)         tpy)      (SO2 tpy)                                  yr)                        ($/ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Baseline......................         1.38       209.43  ...........  ...........     1,882.15        16.00  ............  .............  .............
No. 6 Fuel Oil--1%............         1.00  ...........       153.61        55.81     1,882.15        16.50       145,866         2,613   .............
No. 6 Fuel Oil--0.5%..........         0.50  ...........        75.88       133.55     1,882.15        17.75       510,532         3,823          4,691
Diesel........................         0.05  ...........         7.31       202.11     2,142.73        20.95     1,444,077         7,145         13,616
Natural Gas...................         0.04  ...........         0.07       209.35       288.56         5.97    -2,926,874       -13,980       -603,723
--------------------------------------------------------------------------------------------------------------------------------------------------------

    The AECC BART 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. The evaluation
noted that switching to natural gas may have energy impacts during
periods of natural gas curtailment. During periods of natural gas
curtailment, natural gas infrastructure maintenance, and other
emergencies, the McClellan Generating Station relies on the fuel oil
stored at the plant to maintain electrical reliability. The AECC
evaluation notes that because of this, it is important to maintain the
ability to burn fuel oil at McClellan, even if fuel oil is currently
more expensive to burn than natural gas.
    With regard to consideration of the remaining useful life of Unit
1, this factor does not impact the SO2 BART analysis because
the emissions control approaches being evaluated for BART do not
require capital cost expenditures. Thus, there are no control costs
that need to be amortized over the lifetime of the unit.

    AECC assessed the visibility improvement associated with fuel
switching by comparing the 98th percentile modeled visibility impact of
the baseline scenario (i.e., existing) to the 98th percentile modeled
visibility impact of each control scenario. The table below shows a
comparison of the baseline visibility impacts and the visibility
impacts of the different fuel switching control scenarios that were
evaluated, including the cumulative visibility benefits.

                  Table 18--AECC McClellan Unit 1: Summary of 98th Percentile Visibility Impacts and Improvement Due to Fuel Switching
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                              No. 6 fuel oil--1% sulfur     No. 6 fuel oil--0.5%              Diesel                  Natural gas
                                             ---------------------------           sulfur          -----------------------------------------------------
                                   Baseline                             ---------------------------
                                  visibility                Visibility                 Visibility                 Visibility                 Visibility
          Class I area              impact     Visibility   improvement   Visibility   improvement   Visibility   improvement   Visibility   improvement
                                 ([Delta]dv)     impact        from         impact        from         impact        from         impact        from
                                              ([Delta]dv)    baseline    ([Delta]dv)    baseline    ([Delta]dv)    baseline    ([Delta]dv)    baseline
                                                            ([Delta]dv)                ([Delta]dv)                ([Delta]dv)                ([Delta]dv)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Caney Creek....................        0.622        0.537         0.085        0.322        0.3           0.174         0.448        0.125        0.497
Upper Buffalo..................        0.266        0.231         0.035        0.146        0.12          0.073         0.193        0.052        0.214
Hercules-Glades................        0.231        0.202         0.029        0.115        0.116         0.062         0.169        0.040        0.191
Mingo..........................        0.228        0.193         0.035        0.136        0.092         0.080         0.148        0.058        0.17
Cumulative Visibility            ...........  ...........         0.184  ...........        0.628   ...........         0.958  ...........        1.072
 Improvement ([Delta]dv).......
--------------------------------------------------------------------------------------------------------------------------------------------------------

    The table above shows that switching to No. 6 fuel oil with 1%
sulfur content at McClellan Unit 1 is projected to result in visibility
improvement of 0.085 dv at Caney Creek. The visibility improvement at
each of the other three affected Class I areas is projected to be 0.035
dv or less, while the cumulative visibility improvement at the four
Class I areas is projected to be 0.184 dv. Switching to No. 6 fuel oil
with 0.5% sulfur content is projected to result in considerable
visibility improvement. It is projected to result in 0.3 dv visibility
improvement at Caney Creek. The visibility improvement at each of the
other three affected Class I areas is projected to be 0.12 dv or less,
while the cumulative visibility improvement at the four Class I areas
is projected to be 0.628 dv. Switching to diesel or natural gas is also
projected to result in considerable visibility improvement. The
visibility improvement at Caney Creek is projected to be 0.448 dv for
switching to diesel and 0.497 dv for switching to natural gas. The
cumulative visibility improvement at the four Class I areas is
projected to be 0.958 dv for switching to diesel and 1.072 dv for
switching to natural gas.
    Our Proposed SO2 BART Determination: Taking into consideration the
five factors, we are proposing to determine that BART for McClellan
Unit 1 is switching to fuels with 0.5% or lower sulfur content by
weight. The cost of switching to No. 6 fuel oil with 0.5% sulfur
content is within the range of what we consider to be cost-effective
for BART and it is projected to result in considerable visibility
improvement compared to the baseline at the affected Class I areas.
Switching to No. 6 fuel oil with 0.5% sulfur content has an estimated
average cost-effectiveness of $3,823 per ton of SO2 removed
and is projected to result in visibility improvement ranging from 0.092
to 0.3 dv at each modeled Class I area, and a cumulative visibility
improvement of 0.628 dv at the four affected Class I areas. Switching
to natural gas currently would cost less than the baseline fuel and is
projected to result in even greater visibility improvement than
switching to No. 6 fuel oil with 0.5% sulfur content. However, 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 gas (40
CFR part 51, Appendix Y, section IV.D.1). Because 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 are not
proposing to require a switch to natural gas for Unit 1. Switching to
diesel is projected to result in considerable visibility improvement.
The visibility improvement of switching to diesel is projected to range
from 0.148 to 0.448 dv at each modeled Class I area, and the cumulative
visibility improvement is 0.958 dv at the four affected Class I areas.
The incremental visibility improvement of switching to diesel compared
to switching to No. 6 fuel oil with a sulfur content of 0.5% is
projected to range from 0.056 dv to 0.148 dv at each affected Class I
area. However, the average cost-effectiveness of switching to diesel is
estimated to be $7,145 and the incremental cost-effectiveness compared
to No. 6 fuel oil with a sulfur content of 0.5% is $13,616 per ton of
SO2 removed, which we do not consider to be cost-effective
in view of the incremental visibility improvement. Since diesel also
has a sulfur content by weight that is well below 0.5%, the facility
may elect to use this fuel type to comply with BART, but we are not
proposing to require a switch to diesel for Unit 1. We are proposing to
determine that SO2 BART for McClellan Unit 1 is switching to