[Federal Register Volume 80, Number 67 (Wednesday, April 8, 2015)]
[Proposed Rules]
[Pages 18944-19005]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2015-06726]



[[Page 18943]]

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

[[Page 18944]]


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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 protected].
     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 214-665-7263.
    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

[[Page 18945]]

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 (214) 665-7241 or via electronic mail at 
[email protected].

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

[[Page 18946]]

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

[[Page 18947]]

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

[[Page 18948]]

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

    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

[[Page 18949]]

 
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

[[Page 18950]]

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.

[[Page 18951]]

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)...........................
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------


[[Page 18952]]

    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

[[Page 18953]]

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)............................
--------------------------------------------------------------------------------------------------------------------------------------------------------


[[Page 18954]]


          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 1.3.3.1, 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.

[[Page 18955]]

    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

[[Page 18956]]

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

[[Page 18957]]

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

[[Page 18958]]

 
    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.

[[Page 18959]]

    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 
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 2009 fuel oil shipment cannot be 
burned past this point. As discussed above, the unit's baseline fuel is 
No. 6 fuel oil with 1.38% sulfur content, based on the average sulfur 
content of the fuel oil from the most recent shipment received by the 
facility in 2009. 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

[[Page 18960]]

requirements associated with this proposed determination.
    b. Proposed BART Analysis and Determination for NOX. The AECC 
evaluation examined BART controls for NOX for McClellan Unit 
1. McClellan Unit 1 does not currently have pollution control equipment 
for NOX. 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.
    For NOX BART, the AECC evaluation considered both 
combustion and post-combustion controls. The combustion controls 
evaluated by AECC consisted of FGR, OFA, and LNB. The post-combustion 
controls evaluated consisted of SCR and 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 
McClellan 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 McClellan'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 McClellan Unit 1, is approximately 0.2-0.4 lb/MMBtu 
using FGR and 0.2-0.3 lb/MMBtu using OFA.\33\ 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 McClellan Unit 1. The 
NOX controlled emission rate of combustion controls combined 
with SNCR is estimated to be 0.10-0.12 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 0.05-0.12 lb/MMBtu for McClellan Unit 1.
---------------------------------------------------------------------------

    \33\ ``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 from the pollution control 
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 the EPA Control Cost 
Manual. We are not aware of any enforceable shutdown date for the 
McClellan 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 McClellan 
Unit 1.

                                                                Table 19--Summary of NOX Control Costs for AECC McClellan Unit 1
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                    Natural gas      Fuel oil                         Annual
                                                                     Baseline       controlled      controlled      Controlled       emissions     Total annual    Average cost     Incremental
                        Control scenario                           emission rate  emission level  emission level   emission rate    reductions      cost ($/yr)    effectiveness   cost  ($/ton)
                                                                     (NOX tpy)      (lb/MMBtu)      (lb/MMBtu)         (tpy)         (NOX tpy)                        ($/ton)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Combustion Controls.............................................          294.04            0.15            0.15          174.89          119.15         746,051           6,261  ..............
Combustion Controls + SNCR......................................          294.04            0.12            0.10          136.40          157.64       1,990,988          12,630          32,344
SCR.............................................................          294.04            0.05            0.12           64.98          229.06       1,732,870           7,565          -3,614
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

    AECC estimated the average cost-effectiveness of installing and 
operating combustion controls to be $6,261 per ton of NOX 
removed. The combination of combustion controls and SNCR was estimated 
to cost $12,630 per ton of NOX removed, while SCR was 
estimated to cost $7,565 per ton of NOX removed. In its 
evaluation, AECC also explained that AECC expects the average 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.
    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 McClellan 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.

[[Page 18961]]



       Table 20--AECC McClellan Unit 1: Summary of the 98th Percentile Visibility Impacts and Improvement Due to NOX Controls--Natural Gas Firing
                                                                       [2001-2003]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                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.............................           0.125           0.068           0.057           0.056           0.069           0.027           0.098
Upper Buffalo...........................           0.052           0.028           0.024           0.023           0.029           0.012           0.04
Hercules-Glades.........................           0.040           0.021           0.019           0.018           0.022           0.009           0.031
Mingo...................................           0.058           0.031           0.027           0.026           0.032           0.012           0.046
Cumulative Visibility Improvement         ..............  ..............           0.127  ..............           0.152  ..............           0.215
 ([Delta]dv)............................
--------------------------------------------------------------------------------------------------------------------------------------------------------


         Table 21--AECC McClellan Unit 1: Summary of the 98th Percentile Visibility Impacts and Improvement Due to NOX Controls--Fuel Oil Firing
                                                                       [2001-2003]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                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.............................           0.621           0.554           0.067           0.542           0.079           0.548           0.073
Upper Buffalo...........................           0.266           0.264           0.002           0.264           0.002           0.264           0.002
Hercules-Glades.........................           0.230           0.209           0.021           0.203           0.027           0.207           0.023
Mingo...................................           0.227           0.203           0.024           0.200           0.027           0.201           0.026
Cumulative Visibility Improvement         ..............  ..............           0.114  ..............           0.135  ..............           0.124
 ([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 
McClellan Unit 1 are projected to result in visibility improvement of 
up to 0.057 dv at any single Class I area for the natural gas firing 
scenario and 0.067 dv for the fuel oil firing scenario. A combination 
of combustion controls and SNCR is projected to result in only slight 
incremental visibility improvement compared to combustion controls 
alone. For example, a combination of combustion controls and SNCR at 
McClellan Unit 1 is projected to result in visibility improvement of up 
to 0.069 dv at any single Class I area for natural gas firing and 0.079 
dv for fuel oil firing, which is an incremental visibility improvement 
for each fuel firing scenario of 0.012 dv going from combustion 
controls to combustion controls in combination with SNCR. 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, except for the fuel oil firing scenario. 
For the fuel oil firing scenario, SCR is projected to result in 
slightly less than or equal visibility improvement than 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 McClellan Unit 1 is no additional controls, and are proposing that 
the facility's existing NOX emission limits satisfy BART for 
NOX. We are proposing the existing emission limits of 869.1 
lb/hr for natural gas firing and 705.8 lb/hr for fuel oil firing for 
NOX BART for McClellan Unit 1.\34\ As discussed above, the 
operation of combustion controls at McClellan Unit 1 is projected to 
result in a maximum visibility improvement of 0.067 dv (Caney Creek), 
and a smaller amount of visibility improvement at each of the other 
Class I areas. The installation and operation of combustion controls at 
McClellan Unit 1 has an average cost-effectiveness of $6,261 per ton of 
NOX removed, which is not within the range of what we 
generally consider to be 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 high estimated cost of those controls. The operation of a 
combination of combustion controls and SNCR is estimated to cost 
$12,630 per ton of NOX removed, which is not 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 $7,565 per 
ton of NOX removed, which is not generally considered 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 McClellan 
Unit 1 is no additional controls and are proposing that the existing 
NOX emission limits of 869.1 lb/hr for natural gas firing 
and 705.8 lb/hr for fuel oil firing are BART for NOX and 
that compliance be demonstrated using the unit's existing CEMS. We are 
proposing that these emissions limitations be complied with for BART 
purposes from the date of effectiveness of the finalized

[[Page 18962]]

action. We are also proposing regulatory text that includes monitoring, 
reporting, and recordkeeping requirements associated with these 
emission limits.
---------------------------------------------------------------------------

    \34\ See ADEQ Operating Air Permit No. 0181-AOP-R5, Section IV, 
Specific Condition No. 1, 3, and 13.
---------------------------------------------------------------------------

    c. Proposed BART Analysis and Determination for PM. McClellan Unit 
1 does not currently have pollution control equipment for PM. For PM 
BART, AECC's evaluation considered the following control technologies: 
Dry 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 McClellan Unit 1, has inherent ash 
that contributes to emissions of filterable PM. Reductions in 
filterable PM emissions are directly related to the sulfur content of 
the fuel.\35\ Therefore, switching to No. 6 fuel oil with a lower 
sulfur content is expected to result in lower filterable PM emissions. 
The AECC 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.
---------------------------------------------------------------------------

    \35\ See ``AP-42, Compilation of Air Pollutant Emission 
Factors,'' section 1.3.3.1, and Table 1.3-1, available at http://www.epa.gov/ttnchie1/ap42/.
---------------------------------------------------------------------------

    The AECC 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 McClellan Unit 1. Wet 
ESPs, cyclones, wet scrubbers, and fuel switching were identified as 
technically feasible options for McClellan 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 McClellan 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. AECC 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 for McClellan Unit 1. First, the total annual cost numbers 
associated with fuel switching should be the same as those used in the 
SO2 BART cost analysis (see Table 17). In earlier draft 
versions of AECC's 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.\36\ 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 McClellan 
Generating Station, nor did AECC's BART 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 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 equipment 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 McClellan Unit 
1.
---------------------------------------------------------------------------

    \36\ 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 22--Summary of Cost of PM Controls for AECC McClellan Unit 1
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                      Annual                                        Average PM      Incremental
                                                                     Baseline         Control       Controlled       emissions     Capital cost    Total annual        cost            cost
                        Control scenario                           emission rate  efficiency (%)   emission rate   reduction (PM        ($)         cost ($/yr)    effectiveness   effectiveness
                                                                     (PM tpy)                        (PM tpy)          tpy)                                           ($/ton)         (S/ton)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
No. 6 Fuel oil--1% S............................................          136.08            43.6           76.70           59.38  ..............         145,866           2,456  ..............
Wet Scrubber....................................................          136.08            55.0           61.23           74.84     146,303,011      52,056,542         695,549       3,357,741
No. 6 Fuel oil--0.5% S..........................................          136.08            82.4           23.94          112.14  ..............         510,532           4,553      -1,381,931
Cyclone.........................................................          136.08            85.0           20.41          115.67       1,432,971       1,721,384          14,882         343,018
Wet ESP.........................................................          136.08            90.0           13.61          122.47     151,509,333      32,605,907         266,237       4,541,842

[[Page 18963]]

 
Natural Gas.....................................................          136.08            99.0            1.36          134.72  ..............      -2,926,874         -21,725      -2,900,635
Diesel..........................................................          136.08            99.2            1.10          134.98  ..............       1,444,077          10,698      16,811,350
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

    The table above shows that the average cost-effectiveness values of 
all add-on PM control technology options evaluated for McClellan Unit 1 
ranged in cost-effectiveness from approximately $15,000 to $700,000 per 
ton of PM removed, based on AECC's cost estimates. The incremental 
cost-effectiveness of add-on PM control technology options ranged from 
$343,018 to $16,811,350 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 $2,456 
per ton of PM removed, while switching to No. 6 fuel oil with 0.5% 
sulfur content is estimated to cost $4,553 per ton of PM removed at 
McClellan Unit 1. 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 units due to a change in the 
management of the load control area the facilities are located in. Less 
projected operating time is expected to result in lower annual 
emissions, which in turn would result in decreased average cost-
effectiveness for the add-on PM control technology options.
    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 McClellan Generating Station that could potentially create 
greater problems than experienced elsewhere related to the treatment of 
wastewater and any necessary landfilling, nor did the AECC BART 
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 McClellan Generating Station, nor did the 
AECC 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) compared to what was 
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 McClellan Unit 1. Table 18 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.

[[Page 18964]]



                   Table 23--AECC McClellan Unit 1: Summary of the 98th Percentile Visibility Impacts and Improvement From PM Controls
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                      Wet ESP                      Wet scrubber                       Cyclone
                                             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.............................           0.621           0.617           0.004           0.619           0.002           0.619           0.002
Upper Buffalo...........................           0.266           0.263           0.003           0.264           0.002           0.265           0.001
Hercules-Glades.........................           0.230           0.227           0.003           0.228           0.002           0.229           0.001
Mingo...................................           0.227           0.223           0.004           0.224           0.003           0.225           0.002
                                         ---------------------------------------------------------------------------------------------------------------
Cumulative Visibility Improvement         ..............  ..............           0.014  ..............           0.009  ..............           0.006
 ([Delta]dv)............................
--------------------------------------------------------------------------------------------------------------------------------------------------------

    The table above shows that the operation of a wet ESP, wet 
scrubber, and cyclone at McClellan 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; and 
natural gas are summarized in Table 18. The modeled visibility 
improvement shown in Table 18 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 15). 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 AECC McClellan 
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 a lower estimated total annual cost 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 in light of the minimal 
visibility benefit of these controls (see the table above).
    We are proposing to determine that PM BART for McClellan 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 2009 fuel oil 
shipment cannot be burned past this point. As discussed above, the 
unit's baseline fuel is No. 6 fuel oil with 1.38% sulfur content, based 
on the average sulfur content of the fuel oil from the most recent 
shipment received by the facility in 2009. 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.
3. AEP Flint Creek Power Plant
    The AEP Flint Creek Power Plant Unit 1 is subject to BART. We 
previously disapproved Arkansas' BART determination for SO2 
and NOX for Flint Creek Unit 1 in our March 12, 2012 final 
action (77 FR 14604). Flint Creek Unit 1 is a dry bottom wall-fired 
boiler with a nominal generating capacity rating of 558 MW and a 
nominal design maximum heat input rate of 6,324 MMBtu/hr. The unit 
burns primarily low-sulfur western coal and is currently equipped with 
an ESP and low NOX burners. AEP hired a consultant to 
prepare a BART five-factor analysis for the AEP Flint Creek Unit 1 (AEP 
BART analysis).\37\
---------------------------------------------------------------------------

    \37\ See ``BART Five Factor Analysis Flint Creek Power Plant 
Gentry, Arkansas (AFIN 04-00107),'' dated September 2013, Version 4, 
prepared by Trinity Consultants Inc. in conjunction with American 
Electric Power Service Corporation for the Southwestern Electric 
Power Company Flint Creek Power Plant. A copy of this BART analysis 
is found in the docket for our proposed rulemaking.
---------------------------------------------------------------------------

    The table below summarizes the baseline emission rates for this 
source. The SO2 and NOX baseline emission rates 
are the highest actual 24-hour emission rates based on 2001-2003 CEMS 
data. The emission rates for the PM10 species reflect the 
breakdown of the filterable and condensable PM10 determined 
from the National Park Service (NPS) ``speciation spreadsheet'' for Dry 
Bottom Boiler Burning Pulverized Coal using only ESP.\38\ The sulfate 
(SO4) emission rate was calculated using an EPRI methodology 
that considers the SO2 to SO4 conversion rate and 
SO4 reduction

[[Page 18965]]

factors for various downstream equipment.\39\
---------------------------------------------------------------------------

    \38\ The NPS Workbook, ``PC Dry Bottom ESP Example.xls'' updated 
03/2006, was obtained from the NPS Web site: http://www.nature.nps.gov/air/Permits/ect/index.cfm. Trinity input the 
following parameters into the workbook for speciation determination: 
total PM10 emission rate of 192.5 lb/hr, heat value of 
8,500 Btu/lb, sulfur content of 0.31%, ash content of 4.9%.
    \39\ Electric Power Research Institute (EPRI) Estimating Total 
Sulfuric Acid Emissions from Stationary Power Plants: Version 2010a. 
EPRI, Palo Alto, CA: 2010.

                    Table 24--AEP Flint Creek Unit 1: Baseline Maximum 24-Hour Emission Rates
----------------------------------------------------------------------------------------------------------------
                               SO2 (lb/    SO4 (lb/    NOX (lb/    PMc (lb/    PMf (lb/    SOA (lb/
           Source                 hr)         hr)         hr)         hr)         hr)         hr)     EC (lb/hr)
----------------------------------------------------------------------------------------------------------------
Unit 1 (SN-01)..............    4,728.4         3.1     1,945.0        65.1        50.1        15.1         1.9
----------------------------------------------------------------------------------------------------------------

    AEP modeled the baseline emission rates using the CALPUFF 
dispersion model to determine the baseline visibility impairment 
attributable to Flint Creek 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., 2001-2003) visibility impairment attributable to the 
source at each Class I area is summarized in the table below.

                 Table 25--Baseline Visibility Impairment Attributable to AEP Flint Creek Unit 1
                                                   [2001-2003]
----------------------------------------------------------------------------------------------------------------
                                                                                     Hercules-
                      Unit                          Caney Creek    Upper Buffalo      Glades           Mingo
----------------------------------------------------------------------------------------------------------------
AEP Flint Creek Unit 1:
    Maximum ([Delta]dv).........................           1.318           2.426           2.103           1.488
    98th Percentile ([Delta]dv).................           0.963           0.965           0.657           0.631
----------------------------------------------------------------------------------------------------------------

    a. Proposed BART Analysis and Determination for SO2. AEP 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 AEP evaluation considered Dry Sorbent Injection (DSI), dry FGD 
(i.e., dry scrubber), and wet FGD (i.e., wet scrubber) for 
SO2 BART. All three options were identified as technically 
feasible for use at Flint Creek Unit 1. The AEP evaluation noted that 
depending on residence time, gas stream temperature, and limitations of 
the particulate control device, DSI control efficiency can range 
between 40 to 60%.\40\ Dry FGD control efficiency generally ranges from 
60 to 95%. There are various designs of dry FGD systems, including 
Spray Dryer Absorber (SDA), Circulating Dry Scrubbing (CDS), and Novel 
Integrated Desulfurization (NID) technology. According to AEP's 
evaluation, discussions with vendors indicated that an outlet emission 
rate of 0.06 lb/MMBtu at Flint Creek Unit 1 would be achievable with 
NID technology. AEP noted that it has no data to suggest that lower 
emission levels are sustainably achievable with the NID technology in a 
retrofit application, and that equipment vendors did not guarantee 
better performance than this. An emission rate of 0.06 lb/MMBtu 
represents 92% control from the unit's baseline 30-day average rate of 
0.75 lb/MMBtu. AEP's analysis notes that dry FGD using lime as the 
reagent is capable of achieving 80 to 95% control when used with lower 
sulfur coals such as those burned at Flint Creek Unit 1. The remainder 
of AEP's analysis focused on wet FGD and dry FGD (NID). We concur with 
AEP's decision to focus the remainder of the analysis on the two 
control options with the highest control efficiency.
---------------------------------------------------------------------------

    \40\ ``Assessment of Control Technology Options for BART-
Eligible Sources: Steam Electric Boilers, Industrial Boilers, Cement 
Plants and Paper and Pulp Facilities'' Northeast States for 
Coordinated Air Use Management (NESCAUM), March 2005.
---------------------------------------------------------------------------

    The estimated capital and operating costs of wet FGD and dry FGD 
(NID) developed by AEP and used in the cost-effectiveness calculations 
were based on EPA's Control Cost Manual and supplemented, where 
available, with vendor and site-specific information obtained by AEP. 
AEP annualized the capital cost of controls over a 30-year amortization 
period and then added these to the annual operating costs to obtain the 
total annualized costs. The average cost-effectiveness was calculated 
by dividing the total annualized cost of controls by the annual 
SO2 emissions reductions. AEP estimated the average cost-
effectiveness of a wet FGD system to be $4,919 per ton of 
SO2 removed, while the average cost-effectiveness of NID was 
estimated to be $3,845 per ton of SO2 removed (see table 
below).
    We disagree with one aspect of AEP's cost analysis.\41\ AEP's cost 
estimates are based on 2016 dollars, which means that they were 
escalated to a future build date. BART cost analyses should be based on 
present dollars, and the EPA Control Cost Manual approach explicitly 
excludes future escalation, as cost comparisons should be made on a 
current real dollar basis. Escalation of costs from past to the current 
year of analysis is permitted, as costs are compared based on the time 
of estimate, but future escalation is not allowed. We expect that de-
escalation to 2014 dollars would result in lower cost numbers and 
overall lower average cost-effectiveness values for all controls 
evaluated. We believe that wet FGD and NID are both more cost-effective 
(i.e., less dollars per SO2 ton removed) than what has been 
estimated by AEP. However, we did not adjust the cost numbers and the 
cost-effectiveness values because we do not expect this to change our 
proposed BART decision. This is discussed in more detail below in the 
subsection titled ``Our Proposed SO2 BART Determination.''
---------------------------------------------------------------------------

    \41\ See ``BART Five Factor Analysis Flint Creek Power Plant 
Gentry, Arkansas (AFIN 04-00107),'' dated September 2013, Version 4, 
prepared by Trinity Consultants Inc. in conjunction with American 
Electric Power Service Corporation for the Southwestern Electric 
Power Company Flint Creek Power Plant. AEP's SO2 control 
cost calculations are found in Appendix A of the BART analysis. An 
Excel file titled ``Consolidated Spreadsheet_2013-09-09'' containing 
spreadsheets with cost information was also provided by AEP Flint 
Creek in support of the cost analysis. A copy of the BART analysis 
and the Excel file is found in the docket for our proposed 
rulemaking.

[[Page 18966]]



                                                              Table 26--Summary of Cost of SO2 Controls for AEP Flint Creek Unit 1
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                      Annual                                                        Incremental
                                                                     Baseline       Controlled      Controlled       emissions     Capital cost    Total annual    Average cost        cost-
                       Control technology                          emission rate   emission rate   emission rate    reductions          ($)         cost ($/yr)    effectiveness   effectiveness
                                                                     (SO2 tpy)    (SO2 lb/MMBtu)     (SO2 tpy)       (SO2 tpy)                                        ($/ton)         ($/ton)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
NID.............................................................          11,641            0.06           1,120          10,521     281,738,024      40,448,089           3,845  ..............
Wet Scrubber....................................................          11,641            0.04             747          10,894     374,427,351      53,592,663           4,919          35,240
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

    AEP's evaluation noted that the potential negative energy and non-
air quality environmental impacts are greater with wet FGD systems than 
dry FGD systems. AEP noted that wet FGD requires increased water use 
and generates large volumes of wastewater and solid waste/sludge that 
must be treated or stabilized before landfilling, placing additional 
burden on the wastewater treatment and solid waste management 
capabilities. We do not expect that water availability would affect the 
feasibility of wet FGD at Flint Creek Unit 1 because the facility is 
not located in an exceptionally arid region. Additionally, 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 (40 CFR 
part 51, Appendix Y, section IV.D.4.i.2.). In cases where the facility 
can demonstrate that there are unusual circumstances that would create 
greater problems than experienced elsewhere, this may provide a basis 
for the elimination of that control option as BART. But in this case, 
AEP has not indicated that there are any such unusual circumstances. 
Another potential negative energy and non-air quality environmental 
impact associated with wet FGD is the potential for increased power 
requirements and greater reagent usage compared to dry FGD. The costs 
associated with increased power requirements and greater reagent usage 
have already been factored into the cost analysis for wet FGD.
    AEP assessed the visibility improvement associated with wet FGD and 
NID technology by modeling the SO2 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 table 
below compares the baseline (i.e., existing) visibility impacts with 
the visibility impacts associated with SO2 controls.

 Table 27--AEP Flint Creek Unit 1: Summary of the 98th Percentile Visibility Impacts and Improvement Due to SO2
                                                    Controls
----------------------------------------------------------------------------------------------------------------
                                                          NID Technology                   Wet scrubber
                                     Baseline    ---------------------------------------------------------------
                                    visibility                      Visibility                      Visibility
          Class I area                impact        Visibility      improvement     Visibility      improvement
                                    ([Delta]dv)       impact       from baseline      impact       from baseline
                                                    ([Delta]dv)     ([Delta]dv)     ([Delta]dv)     ([Delta]dv)
----------------------------------------------------------------------------------------------------------------
Caney Creek.....................           0.963           0.348           0.615           0.334           0.629
Upper Buffalo...................           0.965           0.501           0.464           0.488           0.477
Hercules-Glades.................           0.657           0.312           0.345           0.305           0.352
Mingo...........................           0.631           0.217           0.414           0.208           0.423
                                 -------------------------------------------------------------------------------
Cumulative Visibility             ..............  ..............           1.838  ..............           1.881
 Improvement ([Delta]dv)........
----------------------------------------------------------------------------------------------------------------

    The table above shows that the installation and operation of 
SO2 controls is projected to result in considerable 
visibility improvement from the baseline at the four impacted Class I 
areas. Installation and operation of NID technology is projected to 
result in visibility improvement of up to 0.615 dv at any single Class 
I area (based on the 98th percentile modeled visibility impacts), while 
wet FGD is projected to result in visibility improvement of up to 0.629 
dv. Wet FGD is projected to result in very minimal incremental 
visibility benefit over NID technology, with the projected incremental 
visibility improvement over NID ranging from 0.007 to 0.014 dv at each 
Class I area.
    Our Proposed SO2 BART Determination: Taking into 
consideration the five factors, we propose to determine that BART for 
AEP Flint Creek Unit 1 is an emission limit of 0.06 lb/MMBtu on a 30 
boiler-operating-day rolling average based on the installation and 
operation of NID. The operation of NID is projected to result in 
visibility improvement ranging from 0.352 to 0.629 dv at each affected 
Class I area (98th percentile basis), and based on AEP's evaluation, is 
estimated to have an average cost-effectiveness of $3,845 per ton of 
SO2 removed. By comparison, AEP estimated wet FGD to have an 
average cost-effectiveness of $4,919 per ton of SO2 removed 
and the incremental cost-effectiveness of wet FGD compared to NID is 
estimated to be $35,240 per ton of SO2 removed. As discussed 
above, we believe that AEP's escalation of the cost of controls to 2016 
dollars has likely resulted in the over-estimation of the average cost-
effectiveness. Therefore, we believe wet FGD and NID are both more 
cost-effective (i.e., less dollars per ton of SO2 removed) 
than estimated by AEP (see table above). However, we did not adjust the 
cost numbers and cost-effectiveness calculations because we do not 
believe that doing so would change our proposed BART determination. We 
believe that the average cost-effectiveness of both control options was 
likely over-estimated and the costs associated with wet FGD would 
continue to be higher than the costs associated with NID if the 
estimates were adjusted, yet the installation and operation of wet FGD 
is projected to result in minimal incremental visibility improvement 
over NID. We are proposing to determine that SO2 BART

[[Page 18967]]

for Flint Creek Unit 1 is an emission limit of 0.06 lb/MMBtu on a 30 
boiler-operating-day rolling average based on the installation and 
operation of NID. We believe that the full compliance time \42\ of 5 
years is warranted for a new scrubber retrofit and so propose to 
require compliance with this requirement no later than 5 years from the 
effective date of the final rule. We are proposing to require that 
compliance be demonstrated using the unit's existing CEMS. We are also 
proposing regulatory text that includes monitoring, reporting, and 
recordkeeping requirements associated with this emission limit.
---------------------------------------------------------------------------

    \42\ Section 51.308(e)(1)(iv), requires, ``each source subject 
to BART be required to install and operate BART as expeditiously as 
practicable, but in no event later than 5 years after approval of 
the implementation plan revision.''
---------------------------------------------------------------------------

    b. Proposed BART Analysis and Determination for NOX. 
AEP's BART evaluation examined BART controls for NOX for 
Flint Creek Unit 1 by identifying all available control technologies, 
eliminating options that are not technically feasible, and evaluating 
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, the AEP evaluation considered both 
combustion and post-combustion controls. The combustion controls 
considered by AEP consisted of FGR, OFA, and LNB. The post-combustion 
controls considered consisted of SCR and SNCR. All control options 
evaluated were found to be technically feasible. AEP estimated that FGR 
would be able to achieve a controlled emission rate of 0.23-0.29 lb/
MMBtu at Unit 1, which is a less stringent emission rate than would be 
achieved with LNB/OFA. Therefore, FRG was not further considered in the 
BART evaluation, while LNB/OFA were further considered. AEP evaluated 
three control scenarios: (1) LNB with OFA (LNB/OFA); (2) the 
combination of LNB with OFA and SNCR (LNB/OFA + SNCR); and (3) SCR. The 
baseline NOX emission rate assumed by AEP in the analysis is 
0.31 lb/MMBtu. AEP estimated that the installation and operation of 
LNB/OFA at Flint Creek Unit 1 would achieve a NOX control 
level of approximately 0.23 lb/MMBtu on a 30 boiler-operating-day 
averaging basis. It also estimated that LNB/OFA + SNCR would achieve a 
NOX control level of approximately 0.20 lb/MMBtu, and that 
SCR would achieve a NOX control level of approximately 0.07 
lb/MMBtu, also on a 30 boiler-operating-day averaging basis.
    AEP estimated the capital costs, operating costs, and average cost-
effectiveness of controls based on vendor estimates and published 
calculation methods. AEP noted that the EPA Control Cost Manual was 
followed to the extent possible and estimates were supplemented with 
vendor and site-specific information where available. The cost analysis 
assumed a 30-year amortization period for LNB/OFA and for SCR, and a 
20-year amortization period for SNCR. We discuss the appropriateness of 
the choice of amortization periods below. The total annual costs were 
estimated by annualizing the capital cost of controls over either a 30-
year or 20-year period and then adding to this value the annual 
operating cost of controls. AEP determined the annual tons reduced 
associated with each NOX control option by subtracting the 
estimated controlled annual emission rate from the baseline annual 
emission rate. The baseline annual emission rate is the average rate as 
reported by AEP Flint Creek in the 2001-2003 air emission inventories. 
The average cost-effectiveness of NOX controls was 
calculated by dividing the total annual cost of each control option by 
the estimated annual NOX emissions reductions. The table 
below summarizes the average-cost effectiveness of NOX 
controls for Flint Creek Unit 1.

                                                                  Table 28--Summary of NOX Control Costs for Flint Creek Unit 1
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                      Annual                                                        Incremental
                                                                     Baseline       Controlled      Controlled       emissions     Capital cost    Total annual    Average cost        cost-
                       Control technology                          emission rate  emission level   emission rate    reductions          ($)         cost ($/yr)    effectiveness   effectiveness
                                                                     (NOX tpy)    (NOX lb/MMBtu)     (NOX tpy)       (NOX tpy)                                        ($/ton)         ($/ton)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
LNB/OFA.........................................................           5,120            0.23           4,295             826      16,000,000       1,454,621           1,761  ..............
LNB/OFA/SNCR....................................................           5,120            0.20           3,772           1,348      23,124,235       4,177,782           3,099           5,217
SCR.............................................................           5,120            0.07           1,251           3,869     121,440,000      13,769,599           3,559           3,805
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

    AEP estimated the average cost-effectiveness of installing and 
operating LNB/OFA to be $1,761 per ton of NOX removed, while 
the combination of LNB/OFA + SNCR is estimated to cost $3,099 per ton 
of NOX removed, and SCR is estimated to cost $3,559 per ton 
of NOX removed.
    AEP did not identify any energy or non-air quality environmental 
impacts associated with the use of LNB/OFA. 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 the operation of NOX controls at AEP Flint 
Creek Unit 1 that would affect our proposed BART determination.
    Flint Creek Unit 1 is currently equipped with early generation low 
NOX burners for control of NOX emissions. 
Consideration of the presence of existing pollution control technology 
at each source is reflected in the BART analysis in two ways: First, in 
the consideration of available control technologies, and second, in the 
development of baseline emission rates for use in cost calculations and 
visibility modeling. The baseline emission rate used in the cost 
calculations and visibility modeling reflects the operation of these 
controls. The newer generation low NOX burners evaluated by 
AEP are expected to achieve a higher level of NOX control 
than the currently installed early generation low NOX 
burners.
    We are not aware of any enforceable shutdown date for the AEP Flint 
Creek Power Plant, nor did AEP'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. AEP assumed a 30-year amortization period in the evaluation 
of LNB, OFA, and SCR as the remaining useful life of the unit, and a 
20-year amortization period in the evaluation of SNCR. We disagree with 
AEP's assumption of a 20-year amortization period in the cost analysis 
of SNCR. Any air pollution controls on the unit are expected to have 
the same

[[Page 18968]]

life as the boiler. Therefore, we believe it is appropriate to assume a 
30-year amortization period for SNCR, as was done for SCR and 
combustion controls. Assuming a 30-year amortization period, SNCR would 
have a lower estimated total annual cost and would therefore have an 
improved cost-effectiveness (i.e., less dollars per ton removed) 
compared to what was estimated in AEP's evaluation. However, we did not 
adjust the amortization period assumed in AEP's evaluation because we 
do not believe this has an impact on our proposed BART decision. As 
discussed in the subsection below, the incremental visibility benefit 
expected from the installation and operation of SNCR is too small to 
justify the cost of this control compared to combustion controls alone. 
Therefore, we did not revise the amortization period and the average 
cost-effectiveness calculations for SNCR.
    AEP 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 rate to 
the visibility impairment associated with the controlled emission rates 
as measured by the 98th percentile modeled visibility impact. The table 
below shows a comparison of the baseline (i.e., existing) visibility 
impacts and the visibility impacts associated with NOX 
controls.

                 Table 29--AEP Flint Creek Unit 1: Summary of the 98th Percentile Visibility Impacts and Improvement due to NOX Controls
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                 LNB/OFA                 LNB/OFA + SNCR                   SCR
                                                                       ---------------------------------------------------------------------------------
                                                             Baseline                 Visibility                 Visibility
                       Class I area                         visibility   Visibility   improvement   Visibility   Improvement   Visibility    Visibility
                                                              impact       impact        from         impact        from         Impact     Improvement
                                                           ([Delta]dv)  ([Delta]dv)    baseline    ([Delta]dv)    Baseline    ([Delta]dv)  from Baseline
                                                                                      ([Delta]dv)                ([Delta]dv)                 ([Delta]dv)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Caney Creek..............................................        0.963       0.882*        0.081*        0.849         0.114        0.718          0.245
Upper Buffalo............................................        0.965        0.939         0.026        0.932         0.033        0.895          0.07
Hercules-Glades..........................................        0.657        0.633         0.024        0.623         0.034        0.573          0.084
Mingo....................................................        0.631        0.617         0.014        0.612         0.019        0.588          0.043
Cumulative Visibility Improvement ([Delta]dv)............  ...........  ...........         0.145  ...........           0.2  ...........          0.442
--------------------------------------------------------------------------------------------------------------------------------------------------------
* EPA identified a discrepancy in the results presented by AEP and reran the model for the 2003 model year. These values have been adjusted to reflect
  the results of the EPA model run.

    As shown in the table above, the installation and operation of LNB/
OFA is projected to result in visibility improvement of up to 0.081 dv 
at any single Class I area, based on the 98th percentile visibility 
impairment. The installation and operation of LNB/OFA + SNCR is 
projected to result in visibility improvement of up to 0.114 dv over 
the baseline. The installation and operation of SCR is projected to 
result in visibility improvement of up to 0.245 dv in any single Class 
I area. The combination of LNB/OFA + SNCR would result in slight 
incremental visibility benefit over LNB/OFA at Caney Creek and in 
negligible incremental visibility benefit at the other three affected 
Class I areas. SCR would result in 0.131 dv incremental visibility 
benefit over LNB/OFA + SNCR at Caney Creek and less than half as much 
incremental visibility benefit at the other three affected Class I 
areas.
    Our Proposed NOX BART Determination: Taking into consideration the 
five factors, we propose to determine that NOX BART for 
Flint Creek Unit 1 is an emission limit of 0.23 lb/MMBtu on a 30 
boiler-operating-day rolling average based on the installation and 
operation of new LNB/OFA. The operation of new LNB/OFA is projected to 
result in visibility improvement ranging from 0.014 to 0.081 dv at each 
affected Class I area (98th percentile basis) and is projected to have 
a cumulative visibility improvement of 0.145 dv across the four 
affected Class I areas. The operation of LNB/OFA is estimated to have 
an average cost-effectiveness of $1,761 per ton of NOX 
removed, which we consider to be very cost-effective. By comparison, 
the operation of LNB/OFA + SNCR is projected to result in small 
incremental visibility improvement over LNB/OFA, but is estimated to 
have an average cost-effectiveness of $3,099 per ton of NOX 
removed and an incremental cost-effectiveness of $5,217 per ton of 
NOX removed. We believe that AEP's assumption of a 20-year 
amortization period for SNCR has likely resulted in lower cost-
effectiveness for SNCR. Therefore, we believe LNB/OFA + SNCR is more 
cost-effective (i.e., less dollars per ton of NOX removed) 
than estimated by AEP (see table above). However, we did not adjust the 
cost numbers and cost-effectiveness values because we do not believe 
that doing so would change our proposed BART determination, as the 
installation and operation of LNB/OFA + SNCR is projected to result in 
minimal incremental visibility improvement over LNB/OFA alone such that 
the additional cost of SNCR is not justified.
    The operation of SCR is projected to result in visibility 
improvement ranging from 0.043 to 0.245 dv at each Class I area, and 
has an average cost-effectiveness of $3,559 per ton of NOX 
removed. The incremental visibility benefit of SCR compared to LNB/OFA 
+ SNCR is projected to be 0.131 dv at Caney Creek and is projected to 
range from 0.024 to 0.05 dv at the remaining Class I areas. The 
incremental cost-effectiveness of SCR is estimated to be $3,805 per ton 
of NOX removed. Although we are not adjusting the cost 
estimate for the reason discussed above, we note that AEP's assumption 
of a 20-year amortization period for SNCR has the effect of making the 
average cost-effectiveness of SCNR appear lower (i.e., greater dollars 
per ton removed), while the incremental cost-effectiveness of SCR over 
LNB/OFA + SNCR appears to be higher (i.e., less dollars per ton 
removed) than it actually is. Therefore, an adjustment of the 
amortization period and average cost effectiveness for SNCR is expected 
to result in an incremental cost effectiveness for SCR that is less 
favorable than currently estimated. While we believe the average and 
incremental cost-effectiveness of SCR, as calculated by AEP, is within 
the range of what we consider to be cost-effective, we do not believe 
the 0.131 dv incremental visibility benefit of SCR over LNB/OFA + SCNR 
at a single Class I area warrants the higher costs associated with SCR. 
We are proposing to determine that NOX BART for Flint

[[Page 18969]]

Creek Unit 1 is an emission limit of 0.23 lb/MMBtu on a 30 boiler-
operating-day rolling average based on the installation and operation 
of new LNB/OFA. We are proposing to require that compliance be 
demonstrated using the unit's existing CEMS. We consider 3 years to be 
an adequate time for the installation of NOX combustion 
controls and thus propose to require compliance with this requirement 
no later than 3 years from the effective date of the final rule. We are 
also proposing regulatory text that includes monitoring, reporting, and 
recordkeeping requirements associated with this emission limit.
4. Entergy White Bluff Plant
    The Entergy White Bluff Plant Unit 1, Unit 2, and the Auxiliary 
Boiler are subject to BART. As mentioned previously, we disapproved 
Arkansas' BART determinations for SO2 and NOX for 
Units 1 and 2 and the BART determination for all pollutants for the 
Auxiliary Boiler in our March 12, 2012 final action (77 FR 14604). 
White Bluff Units 1 and 2 are identical tangentially-fired boilers with 
a maximum net power rating of 850 MW each and a nominal heat input 
capacity of 8,950 MMBtu/hr each. The boilers burn sub-bituminous coal 
as the primary fuel and No. 2 fuel oil or biofuel as a start-up fuel. 
Units 1 and 2 are currently equipped with ESPs for control of PM 
emissions. The Auxiliary Boiler is a 183 MMBtu/hr auxiliary boiler that 
burns only No. 2 fuel oil or biodiesel, and its purpose is to provide 
steam for the start-up of the two primary boilers, Units 1 and 2. The 
Auxiliary Boiler is typically only used in the rare instance when both 
of the main boilers are not operating.
    Entergy hired a consultant to conduct a BART five-factor analysis 
for White Bluff Units 1, 2, and the Auxiliary Boiler (Entergy BART 
analysis).\43\ The table below summarizes the baseline emission rates 
Entergy assumed in the BART analysis for the subject to BART units. The 
SO2 and NOX baseline emission rates are the 
highest actual 24-hour emission rates based on data from the Clean Air 
Markets Division (CAMD) database from 2001-2003 for SO2 and 
from 2009-2011 for NOX. The 2001-2003 period was not used as 
the baseline for NOX because that period no longer 
represents actual operation of the boilers. In 2006, Entergy completed 
the addition of a neural network system and conducted extensive boiler 
tuning that substantially reduced NOX emissions, resulting 
in an actual change in operations and emissions between the original 
baseline period (2001-2003) and current operations. Neural network 
systems are online enhancements to digital control systems (DCS) and 
plant information systems that improve boiler performance parameters 
such as heat rate, NOX emissions, and carbon monoxide (CO) 
levels. According to information provided by the facility, the purpose 
of the neural network system was to monitor and control the heat rate 
at Units 1 and 2.\44\ The neural network system installed at Units 1 
and 2 is optimized first for monitoring and controlling the heat rate, 
and second for minimizing NOX emissions. We believe the use 
of 2009-2011 as the new baseline period for NOX for Units 1 
and 2 is consistent with the BART Guidelines, which provide that ``The 
baseline emissions rate should represent a realistic depiction of 
anticipated annual emissions for the source.'' \45\ The PM10 
emission rates are based on emission factors from AP-42 for PM 
filterable and PM condensable with a 99% control efficiency for ESP 
applied to the PM10 filterable. The emission rates for the 
PM10 species reflect the breakdown of the PM10 
determined from the National Park Service (NPS) ``speciation 
spreadsheet'' for Dry Bottom Boiler Burning Pulverized Coal using only 
ESP.\46\ To estimate sulfuric acid emissions to model for the baseline 
and control cases, AEP assumed all inorganic PM was SO4. We 
note that this methodology can overestimate the amount of sulfuric acid 
emitted from the facility and we recommend that sulfuric acid emissions 
from power plants be calculated by estimating the amount of 
H2SO4 produced and the amount of 
H2SO4 removed by control equipment using 
information from the Electric Power Research Institute (EPRI).\47\ 
Rather than assuming that 100% of inorganic condensable PM is 
SO4, the EPRI method estimates the amount of SO2 
that is oxidized to SO3, assumes that 100% of SO3 
is converted to H2SO4, and then accounts for 
losses due to downstream equipment. The sulfuric acid emissions for the 
base and control scenarios may be slightly overestimated in AEP's 
modeling. However, in this specific situation, we do not anticipate 
that this difference would significantly impact the relative benefits 
of the SO2 controls examined or impact our BART 
determination since the overall impacts and benefits of control are 
large.
---------------------------------------------------------------------------

    \43\ See ``Revised BART Five Factor Analysis White Bluff Steam 
Electric Station Redfield, Arkansas (AFIN 35-00110),'' dated October 
2013, prepared by Trinity Consultants Inc. in conjunction with 
Entergy Services Inc. We refer to this BART analysis as ``Entergy's 
BART analysis'' throughout this proposed rulemaking, and a copy of 
it is found in the docket for our proposed rulemaking.
    \44\ See the ``S&L NOX Control Technology Study,'' 
which is found in Appendix E to the ``Revised BART Five Factor 
Analysis White Bluff Steam Electric Station Redfield, Arkansas (AFIN 
35-00110),'' dated October 2013, prepared by Trinity Consultants 
Inc. in conjunction with Entergy Services Inc. A copy of this BART 
analysis and its appendices is found in the docket for our proposed 
rulemaking.
    \45\ 40 CFR part 51, Appendix Y, section IV.D.4.c.
    \46\ The NPS Workbook, ``PC Dry Bottom ESP Example.xls'' updated 
03/2006, was obtained from the NPS Web site: http://www.nature.nps.gov/air/Permits/ect/index.cfm. Trinity input the 
following parameters into the workbook for speciation determination: 
total PM10 emission rate of 118.6 lb/hr, heat value of 
8,950 Btu/lb, sulfur content of 0.27%, ash content of 4.87%.
    \47\ Electric Power Research Institute (EPRI) Estimating Total 
Sulfuric Acid Emissions from Stationary Power Plants: Version 2010a. 
EPRI, Palo Alto, CA: 2010

                                         Table 30--Entergy White Bluff: Baseline Maximum 24-Hour Emission Rates
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                          Total
                      Subject to BART Unit                        SO2  (lb/  NOX  (lb/  PM10  (lb/ SO4  (lb/  PMc  (lb/  PMf  (lb/  SOA  (lb/   EC  (lb/
                                                                     hr)        hr)        hr)        hr)        hr)        hr)        hr)        hr)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Unit 1 (SN-01)..................................................    7,763.5    3,001.4      118.6       36.8       40.4       31.1        9.2        1.2
Unit 2 (SN-02)..................................................    7,825.1    3,527.4      118.6       36.8       40.4       31.1        9.2        1.2
Auxiliary Boiler (SN-05)........................................        5.8       31.7        2.8        0.9        0.5        1.2        0.2        0.1
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Entergy modeled the baseline emission rates using the CALPUFF 
dispersion model to determine the baseline visibility impairment 
attributable to White Bluff Unit 1, Unit 2, and the Auxiliary Boiler 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

[[Page 18970]]

Wildlife Refuge. The baseline (i.e., existing) visibility impairment 
attributable to the source at each Class I area is summarized in the 
table below.

                  Table 31--Baseline Visibility Impairment Attributable to Entergy White Bluff
                                                   [2001-2003]
----------------------------------------------------------------------------------------------------------------
                                                                              Upper      Hercules-
                            Unit                              Caney Creek    Buffalo       Glades       Mingo
----------------------------------------------------------------------------------------------------------------
    Unit 1 (SN-01)..........................................
        Maximum ([Delta]dv).................................        4.194        2.339        2.230        1.569
        98th Percentile ([Delta]dv).........................        1.628        1.140        1.041        0.887
    Unit 2 (SN-02)..........................................
        Maximum ([Delta]dv).................................        4.437        2.385        2.263        1.701
        98th Percentile ([Delta]dv).........................        1.695        1.185        1.060        0.903
    Auxiliary Boiler (SN-05)................................
        Maximum ([Delta]dv).................................        0.036        0.014        0.008        0.019
        98th Percentile ([Delta]dv).........................         0.01        0.004        0.004        0.008
----------------------------------------------------------------------------------------------------------------

    a. Proposed SO2 BART Analysis and Determination for Units 1 and 2. 
In its 2008 RH SIP Arkansas evaluated FGD controls (both wet and dry 
scrubbers) and determined that SO2 BART for White Bluff 
Units 1 and 2 is the presumptive emission limit of 0.15 lb/MMBtu based 
on the installation of FGD controls. In our March 12, 2012 final action 
(77 FR 14604), we disapproved Arkansas' SO2 BART 
determination because wet and dry FGD were evaluated at the presumptive 
emission limit only and not at the most stringent level of control 
these technologies are capable of achieving. In our October 17, 2011 
proposed action we discussed that, considering the coal burned in this 
case, wet FGD is typically capable of achieving a controlled emission 
rate of 0.04 lb/MMBtu, while dry FGD is typically capable of achieving 
a controlled emission rate of 0.06 lb/MMBtu (76 FR 64186). We also 
discussed that operating these controls at the most stringent 
achievable controlled emission rate versus the presumptive emission 
limit was not expected to increase the capital cost of controls. 
Rather, it was expected that a more stringent level of control would 
increase the operation and maintenance costs as a result of increased 
reagent usage, among other things. However, we expected the increase in 
annualized cost to be offset by the increase in tons of SO2 
removed, causing the cost effectiveness ($/ton) to remain the same or 
slightly improve (i.e., lower $/ton). The fact that wet and dry FGD 
were not evaluated at the most stringent level of control they are 
capable of achieving, even though installation and operation of these 
control technologies at that control level was still expected to be 
cost-effective was the primary reason for our March 12, 2012 
disapproval of Arkansas' SO2 BART determination for White 
Bluff Units 1 and 2. We note that the 2008 Arkansas RH SIP included FGD 
controls for White Bluff Units 1 and 2, and that Entergy submitted an 
application for a Title V permit modification for the White Bluff 
facility on February 4, 2009, for the installation of a dry FGD system 
(i.e., dry scrubbers) to satisfy the SO2 BART 
requirement.\48\ However, Entergy suspended the project for the 
installation of these SO2 controls after our final 
disapproval of SO2 BART for Units 1 and 2.
---------------------------------------------------------------------------

    \48\ See the document titled ``Response of Entergy Arkansas, 
Inc. to Arkansas Public Service Commission Order No. 17.'' A copy of 
this document can be found in the docket for this proposed 
rulemaking.
---------------------------------------------------------------------------

    The Entergy BART analysis \49\ considered Dry Sorbent Injection 
(DSI), dry FGD (dry scrubbers), and wet FGD (wet scrubbers) for 
SO2 BART. All three options were identified as technically 
feasible for use at White Bluff Units 1 and 2. Entergy's evaluation 
noted that DSI control efficiency ranges between 40 to 60%,\50\ dry FGD 
control efficiency ranges from 60 to 95%, and wet FGD ranges from 80-
95% control efficiency, but can achieve up to 97% control efficiency 
when burning higher sulfur coal. Entergy evaluated wet FGD at an outlet 
SO2 emission rate of 0.04 lb/MMBtu for Units 1 and 2. The 
remainder of Entergy's analysis focused on wet FGD and dry FGD. We 
concur with Entergy's decision to focus the remainder of the analysis 
on the two control options with the highest control efficiency.
---------------------------------------------------------------------------

    \49\ See ``Revised BART Five Factor Analysis White Bluff Steam 
Electric Station Redfield, Arkansas (AFIN 35-00110),'' dated October 
2013, prepared by Trinity Consultants Inc. in conjunction with 
Entergy Services Inc. We refer to this BART analysis as ``Entergy's 
BART analysis'' throughout this proposed rulemaking, and a copy of 
it is found in the docket for our proposed rulemaking.
    \50\ ``Assessment of Control Technology Options for BART-
Eligible Sources: Steam Electric Boilers, Industrial Boilers, Cement 
Plants and Paper and Pulp Facilities'' Northeast States for 
Coordinated Air Use Management (NESCAUM), March 2005.
---------------------------------------------------------------------------

    Our Dry Scrubbing Cost Analysis for Entergy White Bluff: Entergy's 
estimates of the capital and direct operating and maintenance costs of 
a dry scrubber were based on vendor estimates. Estimates of the 
indirect operating costs were based on calculation methods from our 
Control Cost Manual. The estimates of the capital and operating and 
maintenance costs of wet FGD were based on vendor estimates obtained by 
Entergy for a system estimated to achieve 97% control and calculation 
methods from our Control Cost Manual.
    We have reviewed the cost analysis that is part of Entergy's 
evaluation and have analyzed it for compliance with the Regional Haze 
Rule, and disagree with several aspects of the cost analysis and have 
made adjustments to it as necessary.\51\ First, we found that Entergy 
assumed in its dry FGD cost analysis that it will burn a coal 
corresponding to an uncontrolled SO2 emission rate of 2.0 
lb/MMBtu--far in excess of the sulfur level of the coals it has 
historically burned, presumably for future fuel flexibility. For the 
years 2009-2013, the maximum monthly SO2 emission rate for 
Unit 1 is 0.653 lbs/MMBtu and that for Unit 2 is 0.679 lbs/MMBtu. Thus, 
Entergy has costed SO2 dry scrubber systems for the White 
Bluff facility that are overdesigned compared to its historical needs. 
Such a system, being capable of a much higher level of sulfur removal 
than is currently required, has a correspondingly higher cost. Entergy 
selected its SO2 emission baseline by using ``the average 
rate from 2001-2003, as reported by Entergy in their air

[[Page 18971]]

emission inventories,'' \52\ while selecting its annualized costs based 
on a 2.0 lb/MMBtu coal. In calculating baseline emissions, the BART 
Guidelines assume the source in question is otherwise unchanged in the 
future, except for the addition of BART controls.\53\ Thus, we believe 
it is appropriate to adjust the cost analysis presented in Entergy's 
report.\54\ Additionally, the cost estimate for dry FGD presented in 
Entergy's report includes line items that have not been documented, 
appear to be already covered in other cost items, or do not appear to 
be valid costs under our Control Cost Manual methodology. This includes 
line items such as capital suspense,\55\ Entergy internal costs, and 
certain line items under balance of plant (BOP) costs. Please see our 
SO2 Cost TSD for more details concerning the adjustments we 
propose to make to the White Bluff dry FGD cost analysis. A summary of 
our adjusted cost analysis, which is based on 2013 dollars, is 
presented in the table below.
---------------------------------------------------------------------------

    \51\ See ``Technical Support Document for the SDA Control Cost 
Analysis for the Entergy White Bluff and Independence Facilities 
Arkansas Regional Haze Federal Implementation Plan (SO2 
Cost TSD).'' A copy of this document is found in the docket for our 
proposed rulemaking.
    \52\ Revised Bart Five Factor Analysis, White Bluff Steam 
Electric Station, Redfield, Arkansas (AFIN 35-00110), dated October 
2013, prepared by Trinity Consultants Inc. in conjunction with 
Entergy Services Inc., Page 5-5.
    \53\ 70 FR 39167.
    \54\ See ``Technical Support Document for the SDA Control Cost 
Analysis for the Entergy White Bluff and Independence Facilities 
Arkansas Regional Haze Federal Implementation Plan (SO2 
Cost TSD),'' for a detailed discussion of how Entergy's cost 
analysis was adjusted.
    \55\ Entergy states capital suspense ``is a distribution of 
overhead costs associated with administrators, engineers, and 
supervisors and includes function specific rates and A&G (Corporate 
Accounting) rates. Function specific capital suspense is dependent 
upon the personal hours allocated to a specific project for a time 
period. However, the percent of a total project that is dedicated to 
capital suspense is not a constant. Rather, it is dependent upon the 
yearly total capital expense budget and the budgeted capital 
spending for a specific function.'' See Entergy Response to EPA 
Region 6 comments on Entergy White Bluff draft BART Report 06/10/
13.Page 9. A copy of this document is found in the docket for this 
proposed rulemaking.

 Table 32--Summary of EPA Dry FGD Cost Analysis for White Bluff Units 1
                                  and 2
------------------------------------------------------------------------
                                   White Bluff  Unit   White Bluff  Unit
              Item                         1                   2
------------------------------------------------------------------------
Total Annualized Cost...........    $31,981,230         $31,981,230
Interest Rate (%)...............              7                   7
Equipment Lifetime (years)......             30                  30
Capital Recovery Factor (CRF)...              0.0806              0.0806
SO2 Emission Rate (lbs/MMBtu)...              0.65                0.68
Controlled SO2 Emission Rate (%)             90.81               91.16
SO2 Emission Baseline (tons)....         15,816              16,697
SO2 Emission Reduction (tons)...         14,363              15,221
Cost Effectiveness ($/ton)......         $2,227              $2,101
------------------------------------------------------------------------

    Our Wet Scrubbing Cost Analysis for Entergy White Bluff: Entergy 
uses a 2012 contractor wet FGD estimate for the White Bluff Units 1 and 
2 as the starting point for its cost analysis.\56\ It then used 
multiplier approximations from our Control Cost Manual \57\ to 
calculate the Total Capital Investment (TCI). Entergy then calculated 
the direct annual costs, using fixed and variable O&M costs from 
another 2011 contractor cost summary as a surrogate for the apparently 
unavailable direct annual costs from the 2012 estimate.\58\ Following 
this, Entergy calculated the indirect annual costs using additional 
multiplier approximations from our Control Cost Manual.\59\ Lastly, 
Entergy calculated the annualized capital cost in the usual manner by 
multiplying the TCI by the capital recovery factor.
---------------------------------------------------------------------------

    \56\ White Bluff Station Unit 1 & 2, Wet FGD--2.0 lb/MMBtu, 
Order Of Magnitude Cost Estimate Summary. Attached as Attachment C 
to the 6/10/13 Entergy Response to EPA comments on the White Bluff 
draft BART Report. Pdf page 29. Below is
    \57\ Section 5.2 Post-Combustion Controls, Chapter 1--Wet 
Scrubbers for Acid Gas, Table 1.3.
    \58\ 6/10/13 Entergy Response to EPA comments on the White Bluff 
draft BART Report. Pdf page 11. This information was supplemented 
with a cut sheet from the 2011 S&L report via email from David 
Triplett on 2-10-15. Entergy declined to provide the full report, 
citing confidentiality concerns.
    \59\ Section 5.2 Post-Combustion Controls, Chapter 1--Wet 
Scrubbers for Acid Gas, Table 1.4.
---------------------------------------------------------------------------

    As with its dry FGD cost estimates, Entergy designed its wet FGD 
systems to burn coal corresponding to an uncontrolled SO2 
emission rate of 2.0 lb/MMBtu, which are overdesigned compared to its 
historical needs. Please see our SO2 Cost TSD for more 
details concerning the adjustments we propose to make to the White 
Bluff wet FGD cost analysis, which is similar to our dry FGD analysis. 
A summary of our adjusted cost analysis, which is based on 2013 
dollars, is presented in the table below:

 Table 33--Summary of EPA Wet FGD Cost Analysis for White Bluff Units 1
                                  and 2
------------------------------------------------------------------------
                                   White Bluff  Unit   White Bluff  Unit
              Item                         1                   2
------------------------------------------------------------------------
Total Annualized Cost...........    $49,526,167         $49,526,167
Interest Rate (%)...............              7                   7
Equipment Lifetime (years)......             30                  30
Capital Recovery Factor (CRF)...              0.0806              0.0806
SO2 Emission Rate (lbs/MMBtu)...              0.65                0.68
Controlled SO2 Emission Rate (%)             93.87               94.11
SO2 Emission Baseline (tons)....         15,816              16,697
SO2 Emission Reduction (tons)...         14,847              15,713
Cost Effectiveness ($/ton)......         $3,336              $3,152
------------------------------------------------------------------------

    Entergy's evaluation noted that the potential negative non-air 
quality environmental impacts are greater with wet FGD systems than dry 
FGD systems. Entergy noted that wet scrubbers require increased water 
use and generate large

[[Page 18972]]

volumes of wastewater and solid waste/sludge that must be treated or 
stabilized before landfilling, placing additional burden on the 
wastewater treatment and solid waste management capabilities. We do not 
expect that water availability would affect the feasibility of a wet 
scrubber since the facility is not located in an exceptionally arid 
region. Additionally, 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 (40 CFR part 51, Appendix Y, section IV.D.4.i.2.). 
In cases where the facility can demonstrate that there are unusual 
circumstances there that would create greater problems than experienced 
elsewhere, this may provide a basis for the elimination of that control 
option as BART. But in this case, Entergy White Bluff has not indicated 
that there are any such unusual circumstances. Another potential 
negative energy and non-air quality environmental impact associated 
with wet FGD systems is the potential for increased power requirements 
and greater reagent usage compared to dry FGD. The costs associated 
with increased power requirements and greater reagent usage have 
already been factored into the cost analysis for the wet FGD system.
    Entergy assessed the visibility improvement associated with wet FGD 
and a dry FGD by modeling the SO2 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 compare the baseline (i.e., existing) visibility impacts 
with the visibility impacts associated with SO2 controls.

 Table 34--Entergy White Bluff Unit 1: Summary of the 98th Percentile Visibility Impacts and Improvement Due to
                                                  SO2 Controls
----------------------------------------------------------------------------------------------------------------
                                            Visibility impact ([Delta]dv)        Visibility
                                          ---------------------------------   improvement over      Incremental
                                                                                baseline (dv)       visibility
               Class I area                              Dry               ---------------------- improvement of
                                            Baseline   scrubber   Wet FGD      Dry                  wet FGD vs.
                                                                             scrubber   Wet FGD    dry  scrubber
----------------------------------------------------------------------------------------------------------------
Caney Creek..............................      1.628      0.815      0.794      0.813      0.834           0.021
Upper Buffalo............................      1.140      0.378      0.350      0.762      0.790           0.028
Hercules-Glades..........................      1.041      0.358      0.360      0.683      0.681          -0.002
Mingo....................................      0.887      0.267      0.271      0.620      0.616          -0.004
                                          ----------------------------------------------------------------------
    Total................................      4.696      1.818      1.775      2.878      2.921           0.043
----------------------------------------------------------------------------------------------------------------


 Table 35--Entergy White Bluff Unit 2: Summary of the 98th Percentile Visibility Impacts and Improvement Due to
                                                  SO2 Controls
----------------------------------------------------------------------------------------------------------------
                                            Visibility impact ([Delta]dv)        Visibility
                                          ---------------------------------   improvement over      Incremental
                                                                                baseline (dv)       visibility
               Class I area                              Dry               ---------------------- improvement of
                                            Baseline   scrubber   Wet FGD      Dry                  wet FGD vs.
                                                                             scrubber   Wet FGD    dry  scrubber
----------------------------------------------------------------------------------------------------------------
Caney Creek..............................      1.695      0.941      0.920      0.754      0.775           0.021
Upper Buffalo............................      1.185      0.418      0.405      0.767      0.780           0.013
Hercules-Glades..........................      1.061      0.415      0.416      0.645      0.644          -0.001
Mingo....................................      0.903      0.310      0.315      0.593      0.588          -0.005
                                          ----------------------------------------------------------------------
    Total................................      4.844      2.084      2.056      2.759      2.787           0.028
----------------------------------------------------------------------------------------------------------------

    The tables above show that the installation and operation of 
SO2 controls is projected to result in considerable 
visibility improvement over the baseline at the four impacted Class I 
areas. Installation and operation of dry FGD is projected to result in 
visibility improvement of up to 0.813 dv at any single Class I area for 
Unit 1 and 0.767 dv for Unit 2, based on the 98th percentile visibility 
impairment. Installation and operation of wet FGD is projected to 
result in visibility improvement of up to 0.834 dv at any single Class 
I area for Unit 1 and 0.780 dv for Unit 2. The installation and 
operation of wet FGD is projected to result in very minimal incremental 
visibility benefit over dry FGD at Caney Creek and Upper Buffalo, while 
at Hercules-Glades and Mingo, it is projected to result in slightly 
less visibility improvement than dry FGD (i.e., a slight visibility 
disbenefit).
    Our Proposed SO2 BART Determination: Based on our cost 
analysis, a dry FGD system is estimated to have an average cost-
effectiveness of $2,227 per ton of SO2 removed for Unit 1 
and $2,101 per ton of SO2 removed for Unit 2. By comparison, 
a wet FGD system is estimated to have an average cost-effectiveness of 
$3,336 per ton of SO2 removed for Unit 1 and $3,152 per ton 
of SO2 removed for Unit 2. Therefore, considering the five 
BART factors and the slight visibility benefit at Caney Creek and Upper 
Buffalo and slight disbenefit at Hercules-Glades and Mingo of wet FGD 
over dry FGD, we are proposing to determine that SO2 BART 
for White Bluff Units 1 and 2 is an emission limit of 0.06 lb/MMBtu on 
a 30 boiler-operating-day rolling average based on the installation and 
operation

[[Page 18973]]

of dry FGD or another control technology that achieves that level of 
control. We are proposing to require compliance with this requirement 
no later than 5 years from the effective date of the final rule, 
consistent with the regional haze regulations.\60\ We are proposing to 
require that compliance be demonstrated using the unit's existing CEMS. 
We are also proposing regulatory text that includes monitoring, 
reporting, and recordkeeping requirements associated with this emission 
limit.
---------------------------------------------------------------------------

    \60\ 40 CFR 51.308(e)(1)(iv).
---------------------------------------------------------------------------

    b. Proposed NOX BART Analysis and Determination for 
Units 1 and 2. Entergy identified all available control technologies, 
eliminated options that are not technically feasible, and evaluated the 
control effectiveness of the remaining NOX control options 
for Units 1 and 2. Each technically feasible control option was then 
evaluated in terms of a five factor BART analysis.
    For NOX BART, Entergy's BART evaluation considered both 
combustion and post-combustion controls. The combustion controls 
evaluated consisted of FGR, separated overfire air (SOFA), and LNB. The 
post-combustion controls evaluated consisted of SCR and SNCR. Entergy 
found that FGR technology is not currently offered by vendors for coal-
fired units. Therefore, it did not consider FGR to be a technically 
feasible control technology for the coal-fired White Bluff Units 1 and 
2. All other available NOX control options were identified 
as technically feasible. Entergy evaluated three control scenarios: LNB 
with SOFA (LNB/SOFA); the combination of LNB, SOFA, and SNCR (LNB/SOFA 
+ SNCR); and the combination of LNB, SOFA, and SCR (LNB/SOFA + SCR). 
According to Entergy, the baseline NOX emission rate is 
approximately 0.31 lb/MMBtu for Unit 1 and 0.36 lb/MMBtu for Unit 2. 
Entergy relied on literature control ranges and efficiencies, as well 
as vendor estimates to arrive at the expected controlled emission rates 
for White Bluff Units 1 and 2. Based on contractor evaluations, SOFA is 
expected to achieve a controlled NOX emission rate of 0.28-
0.32 lb/MMBtu for Units 1 and 2. When LNB is combined with SOFA, it is 
expected to achieve a controlled NOX emission rate of 0.15 
lb/MMBtu. When SNCR is combined with LNB and SOFA, it is expected to 
achieve a controlled NOX emission rate of 0.13 lb/MMBtu for 
Units 1 and 2, and when SCR is combined with LNB and SOFA it is 
expected to achieve a controlled NOX emission rate of 0.055 
lb/MMBtu.
    Entergy estimated the capital costs, operating costs, and average 
cost-effectiveness of LNB, SOFA, SNCR, and SCR. The capital and 
operating costs of controls were based on vendor estimates specific to 
Units 1 and 2. The total annual costs were estimated by annualizing the 
capital cost of controls over a 30-year period and then adding to this 
value the annual operating cost of controls. Entergy determined the 
annual emissions reductions associated with each NOX control 
option by subtracting the estimated controlled annual emission rate 
from the baseline annual emission rate. The baseline annual emission 
rate is the average rate as reported by Entergy in the 2009-2011 air 
emission inventories. The average cost-effectiveness of controls was 
calculated by dividing the total annual cost of each control option by 
the estimated annual NOX emissions reductions.
    We note that Entergy's cost estimate for each NOX 
control option includes capital suspense in the total capital 
costs.\61\ A capital cost suspense of $955,673 for both units for LNB/
SOFA; $1,745,429 for both units for LNB/SOFA + SNCR; and $20,552,528 
for Unit 1 and $21,332,288 for Unit 2 for LNB/SOFA + SCR is included in 
the capital costs. As discussed above, Entergy described capital 
suspense as a distribution of overhead costs associated with 
administrators, engineers, and supervisors that includes function 
specific rates and corporate accounting rates. However, we do not 
believe capital suspense should be included in the cost analysis 
because those costs have not been documented by Entergy and do not 
appear to be valid costs under the Control Cost Manual methodology. We 
have adjusted the cost estimate of NOX controls by 
subtracting the capital suspense line item from the capital costs.\62\ 
Based on our adjustment of Entergy's cost estimate, the average cost-
effectiveness of LNB/SOFA is estimated to be $350 per ton of 
NOX removed for Unit 1 and $340 per ton of NOX 
removed for Unit 2, while the average cost-effectiveness of LNB/SOFA + 
SNCR is estimated to be $1,758 per ton of NOX removed for 
Unit 1 and $1,449 per ton of NOX removed for Unit 2 (see 
table below). The average cost-effectiveness of LNB/SOFA + SCR is 
estimated to be $3,552 per ton of NOX removed for Unit 1 and 
$2,749 per ton of NOX removed for Unit 2.
---------------------------------------------------------------------------

    \61\ See ``Revised BART Five Factor Analysis White Bluff Steam 
Electric Station Redfield, Arkansas (AFIN 35-00110),'' dated October 
2013, prepared by Trinity Consultants Inc. in conjunction with 
Entergy Services Inc. Entergy's NOX control cost 
estimates are found in Appendix A of the BART analysis and Appendix 
E contains the ``NOX Control Technology Cost and 
Performance Study'' prepared by Sargent & Lundy on behalf of 
Entergy. A copy of the BART analysis and all appendices are found in 
the docket for our proposed rulemaking.
    \62\ See the spreadsheet titled ``EPA NOX Control 
Cost revisions_White Bluff.'' A copy of this spreadsheet is found in 
the docket for our proposed rulemaking.

                                                              Table 36--Summary of NOX Control Costs for White Bluff Units 1 and 2
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                   Annual
                                                                  Baseline       Controlled      Controlled       emissions     Capital cost    Total annual    Average cost   Incremental cost-
                      Control technology                        emission rate  emission level   emission rate  reduction (NOX        ($)         cost ($/yr)    effectiveness  effectiveness ($/
                                                                  (NOX tpy)      (lb/MMBtu)         (tpy)           tpy)                                           ($/ton)            ton)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                         Unit 1 (SN-01)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
LNB/SOFA.....................................................           7,249            0.15           4,145           3,104       9,505,533       1,085,904             350  .................
LNB/SOFA/SNCR................................................           7,249            0.13           3,593           3,657      19,625,896       6,430,580           1,758              9,665
LNB/SOFA/SCR.................................................           7,249           0.055           1,520           5,729     209,776,610      20,349,142           3,552              6,717
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                         Unit 2 (SN-02)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
LNB/SOFA.....................................................           8,185            0.15           4,060           4,125      13,532,533       1,403,376             340  .................
LNB/SOFA/SNCR................................................           8,185            0.13           3,519           4,666      23,652,896       6,759,102           1,449              9,900
LNB/SOFA/SCR.................................................           8,185           0.055           1,489           6,697     185,415,610      18,407,977           2,749              5,736
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

    Entergy did not identify any energy or non-air quality 
environmental impacts associated with the use of LNB/SOFA. As for SCR 
and SNCR, we are not aware of any unusual circumstances at the facility 
that could create non-air quality

[[Page 18974]]

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 the operation 
of NOX controls at Entergy White Bluff Units 1 and 2 that 
would affect our proposed BART determination.
    Consideration of the presence of existing pollution control 
technology at each source is reflected in the BART analysis in two 
ways: First, in the consideration of available control technologies, 
and second, in the development of baseline emission rates for use in 
cost calculations and visibility modeling. Other than the installation 
of a neural net system in 2006 to optimize boiler combustion efficiency 
that resulted in lower NOX emissions compared to the 2001-
2003 baseline, White Bluff Units 1 and 2 have no existing 
NOX pollution control technology. The lower NOX 
emissions achieved as a co-benefit of installing the neural net system 
is reflected in the analysis by the use of 2009-2011 as the baseline 
for the NOX BART analysis.
    Entergy 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 rate 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 37--Entergy White Bluff Unit 1: Summary of the 98th Percentile Visibility Impacts and Improvement due to NOX Controls
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                     LNB/SOFA                     LNB/SOFA + SNCR                 LNB/SOFA + 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.............................           1.628           1.462           0.166           1.428             0.2           1.359           0.269
Upper Buffalo...........................           1.140           1.039           0.101           1.029           0.111           0.991           0.149
Hercules-Glades.........................           1.041           0.865           0.176           0.844           0.197           0.832           0.209
Mingo...................................           0.887           0.849           0.038           0.842           0.045           0.817            0.07
Cumulative Visibility Improvement         ..............  ..............           0.481  ..............           0.553  ..............           0.697
 ([Delta]dv)............................
--------------------------------------------------------------------------------------------------------------------------------------------------------


               Table 38--Entergy White Bluff Unit 2: Summary of the 98th Percentile Visibility Impacts and Improvement due to NOX Controls
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                     LNB/SOFA                     LNB/SOFA + SNCR                 LNB/SOFA + 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.............................           1.695            1.47           0.225           1.437           0.258           1.368           0.327
Upper Buffalo...........................           1.185           1.046           0.139           1.035            0.15           0.997           0.188
Hercules-Glades.........................           1.060           0.870           0.190           0.849           0.211           0.838           0.222
Mingo...................................           0.903           0.856           0.047           0.849           0.054           0.823            0.08
Cumulative Visibility Improvement         ..............  ..............           0.601  ..............           0.673  ..............           0.817
 ([Delta]dv)............................
--------------------------------------------------------------------------------------------------------------------------------------------------------

    The tables above show that the installation and operation of LNB/
SOFA is projected to result in visibility improvement of up to 0.176 dv 
at any single Class I area for Unit 1 and 0.225 dv for Unit 2, based on 
the 98th percentile visibility impairment. The installation and 
operation of LNB/SOFA + SNCR is projected to result in visibility 
improvement of up to 0.2 dv in any single Class I area for Unit 1 and 
0.258 dv for Unit 2. The installation and operation of LNB/SOFA + SCR 
is projected to result in visibility improvement of up to 0.269 dv in 
any single Class I area for Unit 1 and 0.327 dv for Unit 2. The 
combination of LNB/SOFA + SNCR would result in minimal incremental 
visibility benefit over LNB/SOFA at all affected Class I areas for both 
units. The combination of LNB/SOFA + SCR at Unit 1 would result in 
incremental visibility benefit over LNB/SOFA + SNCR of 0.069 dv at 
Caney Creek; 0.038 dv at Upper Buffalo; 0.012 dv at Hercules-Glades; 
and 0.025 dv at Mingo. The combination of LNB/SOFA + SCR at Unit 2 
would result in incremental visibility benefit over LNB/SOFA + SNCR of 
0.069 dv of at Caney Creek; 0.038 dv at Upper Buffalo; 0.011 dv at 
Hercules-Glades; and 0.026 dv at Mingo.
    Our Proposed NOX BART Determination for Units 1 and 2: Taking into 
consideration the five factors, we propose to determine that BART for 
White Bluff Units 1 and 2 is an emission limit of 0.15 lb/MMBtu on a 30 
boiler-operating-day rolling average based on the installation and 
operation of LNB/SOFA. The operation of LNB/SOFA is projected to result 
in visibility improvement ranging from 0.038 to 0.176 dv for Unit 1 and 
0.047 to 0.225 dv for Unit 2 at each of the affected Class I areas 
(98th percentile basis). Based on our adjustments to the cost analysis 
included in Entergy's evaluation, the operation of LNB/SOFA is 
estimated to have an average cost-effectiveness of $350 per ton of 
NOX removed for Unit 1 and $340 per ton of NOX 
removed for Unit 2, which we

[[Page 18975]]

consider to be very cost-effective. The operation of LNB/SOFA + SNCR is 
estimated to have an average cost-effectiveness of $1,758 per ton of 
NOX removed for Unit 1 and $1,449 per ton of NOX 
removed for Unit 2. The incremental cost-effectiveness of LNB/SOFA + 
SNCR compared to LNB/SOFA is $9,665 per ton of NOX removed 
for Unit 1 and $9,900 per ton of NOX removed for Unit 
2.While the average cost-effectiveness of LNB/SOFA + SNCR is still very 
cost effective, the incremental visibility benefit of LNB/SOFA + SNCR 
compared to LNB/SOFA is estimated to range from 0.007 to 0.034 dv for 
Unit 1 and 0.007 to 0.033 dv for Unit 2 at each of the affected Class I 
areas. We do not believe this small amount of incremental visibility 
benefit justifies the incremental cost of LNB/SOFA + SNCR.
    The operation of LNB/SOFA + SCR at Unit 1 is projected to result in 
up to 0.269 dv visibility improvement over the baseline at any single 
Class I area, and based on our adjustments to Entergy's cost analysis, 
has an average cost-effectiveness of $3,552 per ton of NOX 
removed. LNB/SOFA + SCR at Unit 1 is projected to result in up to 0.069 
dv of incremental visibility improvement over LNB/SOFA + SNCR at any 
single Class I area, and its incremental cost-effectiveness is 
estimated to be $6,717 per ton of NOX removed. The operation 
of LNB/SOFA + SCR at Unit 2 is projected to result in up to 0.327 dv 
visibility improvement over the baseline at any single Class I area, 
and has an average cost-effectiveness of $2,749 per ton of 
NOX removed. LNB/SOFA + SCR at Unit 2 is also projected to 
result in up to 0.069 dv of incremental visibility improvement over 
LNB/SOFA + SNCR at any single Class I area, and its incremental cost-
effectiveness is estimated to be $5,736 per ton of NOX 
removed. Although the average and incremental cost-effectiveness of 
LNB/SOFA + SCR at Units 1 and 2 is still within the range of what we 
consider to be cost-effective, we believe the incremental visibility 
benefit over LNB/SOFA + SNCR of up to 0.069 dv at a single Class I area 
is relatively small considering the incremental cost-effectiveness of 
$6,717 per ton of NOX removed for Unit 1 and $5,736 per ton 
of NOX removed for Unit 2. Therefore, we are proposing to 
determine that NOX BART for White Bluff Units 1 and 2 is an 
emission limit of 0.15 lb/MMBtu on a 30 boiler-operating-day rolling 
average based on the installation and operation of LNB/SOFA. We are 
proposing to require compliance with this requirement no later than 3 
years from the effective date of the final rule, consistent with our 
regional haze regulations.\63\ We are proposing to require that 
compliance be demonstrated using the unit's existing CEMS. We are also 
proposing regulatory text that includes monitoring, reporting, and 
recordkeeping requirements associated with this emission limit.
---------------------------------------------------------------------------

    \63\ 40 CFR 51.308(e)(1)(iv).
---------------------------------------------------------------------------

    c. Proposed BART Analysis and Determination for the Auxiliary 
Boiler. As shown in the table above, the baseline visibility impairment 
attributable to the Auxiliary Boiler is 0.01 [Delta]dv at Caney Creek 
and even lower at the other modeled Class I areas (98th percentile 
basis). The BART Rule provides:

    ``Consistent with the CAA and the implementing regulations, 
States can adopt a more streamlined approach to making BART 
determinations where appropriate. Although BART determinations are 
based on the totality of circumstances in a given situation, such as 
the distance of the source from a Class I area, the type and amount 
of pollutant at issue, and the availability and cost of controls, it 
is clear that in some situations, one or more factors will clearly 
suggest an outcome. Thus, for example, a State need not undertake an 
exhaustive analysis of a source's impact on visibility resulting 
from relatively minor emissions of a pollutant where it is clear 
that controls would be costly and any improvements in visibility 
resulting from reductions in emissions of that pollutant would be 
negligible.'' (70 FR 39116).

    Given the very small baseline visibility impacts from the Auxiliary 
Boiler, we believe it is appropriate to take a streamlined approach for 
determining BART in this case. Because of the very low baseline 
visibility impacts from the Auxiliary Boiler at each modeled Class I 
area, we believe that the visibility improvement that could be achieved 
through the installation and operation of controls would be negligible, 
such that the cost of those controls could not be justified. Therefore, 
we are proposing that the existing emission limits satisfy BART for 
SO2, NOX, and PM. We are proposing that the 
existing emission limit of 105.2 lb/hr is BART for SO2, the 
existing emission limit of 32.2 lb/hr is BART for NOX, and 
the existing emission limit of 4.5 lb/hr is BART for PM for the 
Auxiliary Boiler.\64\ Because we are proposing a BART emission limit 
that represents current operations and no control equipment 
installation is necessary, we are proposing that these emissions 
limitations be complied with for BART purposes from the date of 
effectiveness of the finalized action.
---------------------------------------------------------------------------

    \64\ See ADEQ Operating Air Permit No. 0263-AOP-R7, Section IV, 
Specific Condition No. 32.
---------------------------------------------------------------------------

5. Entergy Lake Catherine Plant
    The Entergy Lake Catherine Unit 4 is subject to BART. We previously 
disapproved Arkansas' BART determinations for NOX for the 
natural gas firing scenario and for SO2, NOX, and 
PM for the fuel oil firing scenario in our March 12, 2012 final action 
(77 FR 14604). Lake Catherine Unit 4 is a tangentially-fired boiler 
with a nominal net power rating of 558 MW and a nominal heat input 
capacity of 5,850 MMBtu/hr. The boiler is permitted to burn natural gas 
and No. 6 fuel oil. Entergy hired a consultant to conduct a BART five-
factor analysis for Lake Catherine Unit 4 (Entergy's BART 
analysis).\65\ Entergy's analysis states that Lake Catherine Unit 4 has 
not burned fuel oil since prior to the 2001-2003 baseline period, 
currently does not burn fuel oil, and that Entergy does not project to 
burn fuel oil at the unit in the foreseeable future. Therefore, 
Entergy's analysis \66\ addresses BART for the natural gas firing 
scenario and does not consider emissions from fuel oil firing. 
Entergy's analysis states that if conditions change such that it 
becomes economic to burn fuel oil, the facility will submit a BART five 
factor analysis for the fuel oil firing scenario to the State to be 
submitted to us as a SIP revision, and that fuel oil combustion will 
not take place until final EPA approval of BART for the fuel oil firing 
scenario. We concur with this commitment.\67\ Before fuel oil firing is 
allowed to take place at Lake Catherine Unit 4, revised BART 
determinations must be promulgated for all pollutants for the fuel oil 
firing scenario through a FIP and/or through our action upon and 
approval of revised BART

[[Page 18976]]

determinations submitted by the State as a SIP revision. We approved 
Arkansas' BART determinations for Lake Catherine Unit 4 for 
SO2 and PM for the natural gas firing scenario in our March 
12, 2012 final action (77 FR 14604). Therefore, the only BART 
determination that remains to be addressed for the natural gas firing 
scenario is NOX BART.
---------------------------------------------------------------------------

    \65\ See ``Revised BART Five Factor Analysis Lake Catherine 
Steam Electric Station Malvern, Arkansas (AFIN 30-00011),'' dated 
May 2014, prepared by Trinity Consultants Inc. in conjunction with 
Entergy Services Inc. A copy of this BART analysis is found in the 
docket for our proposed rulemaking.
    \66\ See ``Revised BART Five Factor Analysis Lake Catherine 
Steam Electric Station Malvern, Arkansas (AFIN 30-00011),'' dated 
May 2014, prepared by Trinity Consultants Inc. in conjunction with 
Entergy Services Inc. A copy of this BART analysis is found in the 
docket for our proposed rulemaking.
    \67\ As stated in the regulatory text for this proposed 
rulemaking, if Lake Catherine Unit 4 decides to begin burning fuel 
oil, we will complete a BART analysis for each pollutant for the 
fuel oil firing scenario after receiving notification that the 
source will begin burning fuel oil and we will revise the FIP as 
necessary in accordance with Regional Haze Rule requirements, 
including the BART provisions in 40 CFR 51.308(e). Alternatively, if 
the State submits a SIP revision with BART determinations for the 
fuel oil firing scenario, we will take action on the State's 
submittal.
---------------------------------------------------------------------------

    The table below summarizes the baseline emission rates for Lake 
Catherine Unit 4. The SO2 and NOX baseline 
emission rates are the highest actual 24-hour emission rates based on 
CAMD data from 2001-2003 for natural gas burning. The PM10 
emission rate reflects the breakdown of the filterable and condensable 
PM10 determined from AP-42 Table 1.4-2 Combustion of Natural 
Gas.

                          Table 39--Entergy Lake Catherine Unit 4 (Natural Gas Firing): Baseline Maximum 24-Hour Emission Rates
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                           SO2 (lb/    NOX (lb/   Total PM10   SO4 (lb/    PMc (lb/    PMf (lb/    SOA (lb/
                         Source                               hr)         hr)       (lb/hr)       hr)         hr)         hr)         hr)     EC (lb/hr)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Unit 4..................................................        3.1     2,456.4        44.3         1.5         0.0         0.0        31.8        11.0
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Entergy modeled the baseline emission rates using the CALPUFF 
dispersion model to determine the baseline visibility impairment 
attributable to Lake Catherine Unit 4 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 the source at each Class I area is summarized in the 
table below.

   Table 40--Baseline Visibility Impairment Attributable to Entergy Lake Catherine Unit 4--Natural Gas Firing
                                                   [2001-2003]
----------------------------------------------------------------------------------------------------------------
                                                                                     Hercules-
                      Unit                          Caney Creek    Upper Buffalo      Glades           Mingo
----------------------------------------------------------------------------------------------------------------
Unit 4 (SN-01):
    Maximum ([Delta]dv).........................           3.480           2.044           1.016           0.763
    98th Percentile ([Delta]dv).................           1.371           0.489           0.387           0.429
----------------------------------------------------------------------------------------------------------------

    a. Proposed NOX BART Analysis and Determination. Entergy identified 
all available control technologies, eliminated options that are not 
technically feasible, and evaluated the control effectiveness of the 
remaining control options for Lake Catherine Unit 4. Each technically 
feasible control option was then evaluated in terms of a five factor 
BART analysis.
    For NOX BART, the Entergy BART analysis evaluated both 
combustion and post-combustion controls. The combustion controls 
evaluated consisted of Burners out of Service (BOOS), FGR, SOFA, and 
LNB. The post-combustion controls evaluated consisted of SCR and SNCR. 
In its evaluation, Entergy noted that SNCR combined with LNB/SOFA was 
being evaluated as a control option for Lake Catherine Unit 4, but SNCR 
is not adaptable to all gas-fired boilers. All other available 
NOX control options were identified as technically feasible.
    The baseline NOX emission rate Entergy used in the 
analysis is 0.48 lb/MMBtu. Entergy relied on literature control ranges 
and efficiencies and vendor estimates in arriving at the expected 
controlled emission rates for Lake Catherine Unit 4. BOOS is a staged 
combustion technique in which fuel is introduced through operational 
burners in the lower furnace zone to create fuel-rich conditions, while 
not introducing fuel to other burners. The removal of fuel from certain 
zones reduces the temperature and the production of thermal 
NOX. Additional air is then supplied to the non-operational 
burners to complete combustion. Based on a NOX control study 
developed by Sargent & Lundy on behalf of Entergy (Sargent & Lundy 
NOX Control Study), the estimated controlled NOX 
level for Unit 4 while operating BOOS at maximum load is 0.24 lb/
MMBtu.\68\ Based on the level of control expected to be achieved by 
BOOS and the expected utilization levels at Unit 4, Entergy believes 
that an emission rate of 0.22 lb/MMBtu is achievable on a 30 boiler-
operating-day rolling average basis. Entergy estimated the controlled 
NOX level for Unit 4 operating with FGR to be 0.19 lb/MMBtu. 
Entergy estimated that when operated without additional controls, SOFA 
results in NOX emissions for gas fired boilers of 0.2--0.4 
lb/MMBtu. When operated without additional controls, the estimated 
controlled NOX emission rate for gas fired boilers operating 
with LNB is approximately 0.25 lb/MMBtu, and when combined with SOFA, 
the estimated controlled NOX emission rate is 0.19 lb/MMBtu. 
When SNCR is combined with LNB/SOFA it is estimated that the controlled 
NOX emission rate is 0.14 lb/MMBtu, and when SCR is combined 
with LNB/SOFA it is estimated that the controlled NOX 
emission rate is 0.03 lb/MMBtu.
---------------------------------------------------------------------------

    \68\ See ``NOX Control Technology Cost and 
Performance Study,'' Final Report, Rev. 4, dated May 16, 2013, 
prepared by Sargent & Lundy. A copy of this report is included as 
Attachment D to Entergy's BART Five Factor Analysis for Lake 
Catherine Unit 4, which can be found in the docket for this proposed 
rulemaking.
---------------------------------------------------------------------------

    In its evaluation, Entergy noted that the Sargent & Lundy 
NOX Control Study estimated that FGR would result in the 
same controlled emission level as LNB/SOFA, but at a higher cost. 
Therefore, Entergy's evaluation did not further consider FGR. The 
remainder of the analysis focused on four control scenarios: (1) BOOS; 
(2) LNB/SOFA; (3) the combination of LNB/SOFA + SNCR; and (4) the 
combination of LNB/SOFA + SCR. Entergy estimated the capital costs, 
operating costs, and cost- effectiveness of these four control 
scenarios based on cost estimates provided by Sargent & Lundy.\69\ The 
capital cost of each NOX control was annualized over a 30-
year period and

[[Page 18977]]

then added to the annual operating costs to obtain the total annualized 
costs.\70\ The annual emissions reductions associated with each 
NOX control option were determined by subtracting the 
estimated controlled annual emission rate from the baseline annual 
emission rate. The baseline annual emission rate was calculated using 
the baseline emission level of 0.48 lb/MMBtu and an annual heat input 
reflecting a 10% capacity factor.\71\ Entergy assumed a 10% capacity 
factor because the annual capacity factor of the unit during each of 
the years from 2003-2011 was under 10%, and Entergy anticipates that 
future annual capacity factors are expected to be comparable to those 
experienced by the unit in 2003-2011. We agree that assuming a 10% 
capacity factor is consistent with the BART Guidelines, which provide 
that the baseline emission rate should represent a realistic depiction 
of anticipated annual emissions for the source.\72\
---------------------------------------------------------------------------

    \69\ The capital and operating cost estimates for each control 
option are found in Appendix A to Entergy's BART Five Factor 
Analysis for Lake Catherine Unit 4, which can be found in the docket 
for this proposed rulemaking.
    \70\ Based on Entergy's evaluation, it is anticipated that BOOS 
can be implemented at Unit 4 without any capital expenditures, but 
there are one-time costs associated with BOOS implementation. To 
provide an ``apples-to-apples'' comparison with the other 
NOX control options, these one-time additional costs were 
treated as if they were a capital expenditure in calculating the 
cost effectiveness.
    \71\ The annual heat input reflecting a 10% annual capacity 
factor is 5,124,600 MMBtu/yr (5,850 MMBtu/hr * 8760 hrs/yr * 10% = 
5,124,600 MMBtu/yr).
    \72\ 40 CFR Appendix Y to Part 51--Guidelines for BART 
Determinations Under the Regional Haze Rule, section IV.D.4.d.
---------------------------------------------------------------------------

    The controlled annual emission rates were based on the lb/MMBtu 
levels believed to be achievable from the control technologies 
multiplied by the annual heat input. The average cost-effectiveness of 
NOX controls was calculated by dividing the total annual 
cost of each control option by the estimated annual NOX 
emissions reductions. The incremental cost-effectiveness of controls 
when compared to BOOS was also calculated. The table below summarizes 
the cost of NOX controls for Lake Catherine Unit 4. Based on 
Entergy's analysis, the average cost-effectiveness of BOOS at a 
NOX controlled emission rate of 0.22 lb/MMBtu is estimated 
to be $138 per ton of NOX removed, while the average cost-
effectiveness of LNB/SOFA is estimated to be $1,596 per ton of 
NOX removed. The average cost-effectiveness of a combination 
of LNB/SOFA + SNCR is estimated to be $3,827 per ton of NOX 
removed, while the average cost-effectiveness of the combination of 
LNB/SOFA + SCR is estimated to be $6,223 per ton of NOX 
removed.
    We disagree with two aspects of Entergy's cost analysis.\73\ First, 
Entergy's cost estimates for LNB/SOFA, LNB/SOFA + SNCR, and LNB/SOFA + 
SCR include capital suspense as a line item under the capital costs. 
However, we do not believe capital suspense should be included in the 
cost analysis because those costs have not been documented by Entergy 
and do not appear to be valid costs under the Control Cost Manual 
methodology. Second, Entergy's cost estimates for these controls also 
include Allowance for Funds Used During Construction (AFUDC). AFUDC is 
the cost of capital that is incurred to finance a project during the 
construction period, and is not a valid cost under the methodology in 
the EPA Control Cost Manual. The exclusion of capital suspense and 
AFUDC from the capital cost estimates results in lower total annual 
costs and improved average cost-effectiveness (i.e., less dollars per 
NOX ton removed) for the aforementioned NOX 
control options compared to what is estimated in Entergy's evaluation. 
In the table below, we have revised the cost-effectiveness of 
NOX controls for Unit 4 to reflect our adjustments to 
Entergy's cost estimates.\74\
---------------------------------------------------------------------------

    \73\ See ``Revised BART Five Factor Analysis Lake Catherine 
Steam Electric Station Malvern, Arkansas (AFIN 30-00011),'' dated 
May 2014, prepared by Trinity Consultants Inc. in conjunction with 
Entergy Services Inc. Entergy's NOX control cost 
estimates are found in Appendices A and D of the BART analysis. A 
copy of the BART analysis, including the appendices, is found in the 
docket for our proposed rulemaking.
    \74\ See the spreadsheet titled ``EPA NOX Control 
Cost revisions_Lake Catherine.xlsx.'' A copy of this spreadsheet is 
found in the docket for our proposed rulemaking.

                                            Table 41--Summary of NOX Control Costs for Lake Catherine Unit 4
                                                                  [Natural gas firing]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                          Baseline     Controlled    Controlled      Annual                                                 Incremental
                                          emission      emission      emission      emissions   Capital cost  Total annual   Average cost       cost
                                         rate  (NOX    level  (lb/   rate  (NOX     reduction        ($)      cost  ($/yr)  effectiveness  effectiveness
                                            tpy)         MMBtu)         tpy)        (NOX tpy)                                   ($/ton)        ($/ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
BOOS..................................         1,236          0.22           564           673       893,000        92,964            138
LNB/SOFA..............................         1,236          0.19           495           742    10,508,863     1,075,905          1,450         14,246
LNB/SOFA/SNCR.........................         1,236          0.14           371           865    26,015,863     3,047,525          3,523         16,029
LNB/SOFA/SCR..........................         1,236          0.03            77          1159    70,370,863     6,506,935          5,614         11,767
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Entergy did not identify any energy or non-air quality 
environmental impacts associated with the use of BOOS, LNB, or SOFA. 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 the operation of NOX 
controls at Entergy Lake Catherine Unit 4 that would affect our 
proposed BART determination.
    Lake Catherine Unit 4 is not currently equipped with any 
NOX pollution control equipment. The baseline emission rates 
used in the cost calculations and visibility modeling reflects this.
    Entergy 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 rate to 
the visibility impairment associated with the controlled emission rates 
as measured by the 98th percentile modeled visibility impact. The table 
below shows a comparison of the baseline (i.e., existing) visibility 
impacts and the visibility impacts associated with NOX 
controls.

[[Page 18978]]



               Table 42--Entergy Lake Catherine Unit 4: Summary of 98th Percentile Visibility Impacts and Improvement due to NOX Controls
                                                                  [Natural gas firing]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                         BOOS                     LNB/SOFA               LNB/SOFA + SNCR             LNB/SOFA + SCR
                                             -----------------------------------------------------------------------------------------------------------
                                   Baseline                 Visibility                 Visibility                 Visibility                 Visibility
          Class I area            visibility   Visibility   improvement   Visibility   improvement   Visibility   improvement   Visibility   improvement
                                    impact       impact        from         impact        from         impact        from         impact        from
                                 ([Delta]dv)  ([Delta]dv)    baseline    ([Delta]dv)    baseline    ([Delta]dv)    baseline    ([Delta]dv)    baseline
                                                            ([Delta]dv)                ([Delta]dv)                ([Delta]dv)                ([Delta]dv)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Caney Creek....................       1.371        0.775          0.596       0.683          0.688       0.529          0.842       0.163          1.208
Upper Buffalo..................       0.532        0.284          0.248       0.25           0.282       0.193          0.339       0.057          0.475
Hercules-Glades................       0.387        0.212          0.175       0.185          0.202       0.141          0.246       0.043          0.344
Mingo..........................       0.429        0.233          0.196       0.204          0.225       0.154          0.275       0.042          0.387
Cumulative Visibility            ...........  ...........         1.215  ...........         1.397  ...........         1.702  ...........         2.414
 Improvement ([Delta]dv).......
--------------------------------------------------------------------------------------------------------------------------------------------------------

    The table above shows that the installation and operation of BOOS 
is projected to result in visibility improvement of up to 0.596 dv at 
any single Class I area (based on the 98th percentile modeled 
visibility impacts), while LNB/SOFA is projected to result in 
visibility improvement of up to 0.688 dv. The installation and 
operation of the combination of LNB/SOFA + SNCR is projected to result 
in visibility improvement of up to 0.842 dv at any single Class I area, 
while the combination of LNB/SOFA + SCR is projected to result in 
visibility improvement of up to 1.208 dv. The installation and 
operation of LNB/SOFA is projected to result in 0.092 dv of incremental 
visibility benefit over BOOS at Caney Creek, and much lower incremental 
visibility benefit over BOOS at the other Class I areas. The 
combination of LNB/SOFA + SNCR is projected to result in 0.154 dv of 
incremental visibility benefit over LNB/SOFA at Caney Creek, and 0.057 
dv or less incremental visibility benefit at the other affected Class I 
areas. The combination of LNB/SOFA + SCR is projected to result in 
0.366 dv of incremental visibility benefit over LNB/SOFA + SNCR at 
Caney Creek, 0.136 dv at Upper Buffalo, 0.098 [Delta]dv at Hercules-
Glades, and 0.112 dv at Mingo.
    Our Proposed NOX BART Determination: Taking into consideration the 
five factors, we are proposing to determine that NOX BART 
for Lake Catherine Unit 4 for the natural gas firing scenario is an 
emission limit of 0.22 lb/MMBtu on a 30 boiler-operating-day rolling 
average based on the installation and operation of BOOS. The operation 
of BOOS is projected to result in visibility improvement ranging from 
0.175 to 0.596 dv at each affected Class I area (98th percentile 
basis). The cumulative visibility improvement across the four affected 
Class I areas is projected to be 1.215 dv. The operation of BOOS is 
estimated to have an average cost-effectiveness of $138 per ton of 
NOX removed, which we consider to be very cost-effective. By 
comparison, the installation and operation of LNB/SOFA is estimated to 
have an average cost-effectiveness of $1,450 per ton of NOX 
removed, which is still very cost-effective. However, the incremental 
cost-effectiveness of LNB/SOFA over BOOS is $14,246 per ton of 
NOX ton removed, while the incremental visibility benefits 
are only 0.027 to 0.092 dv (depending on the Class I area). As 
discussed in the preceding paragraph, the operation of a combination of 
LNB/SOFA + SNCR is projected to result in visibility improvement over 
the baseline ranging from 0.246 to 0.842 dv at each affected Class I 
area and an incremental visibility improvement over LNB/SOFA ranging 
from 0.05 to 0.154 dv at each Class I area. However, the combination of 
LNB/SOFA + SNCR has an average cost-effectiveness of $3,523 per ton of 
NOX removed and an incremental cost-effectiveness compared 
to LNB/SOFA of $16,029 per ton of NOX removed. We believe 
that the high incremental costs of the combination of LNB/SOFA + SNCR 
when compared to LNB/SOFA do not justify the amount of incremental 
visibility benefit projected at the affected Class I areas. The 
operation of a combination of LNB/SOFA + SCR is projected to result in 
considerable visibility improvement over the baseline, ranging from 
0.344 to 1.208 dv at each affected Class I area. The incremental 
visibility benefit of the combination of LNB/SOFA + SCR over LNB/SOFA + 
SNCR ranges from 0.098 to 0.366 dv at each Class I area. However, the 
combination of LNB/SOFA + SCR has an average cost-effectiveness of 
$5,614 per ton of NOX removed and an incremental cost-
effectiveness (compared to the combination of LNB/SOFA + SNCR) of 
$11,767 per ton of NOX removed. While the incremental 
visibility benefit is considerable, we do not consider the average and 
the incremental cost-effectiveness values of the combination of LNB/
SOFA + SCR to be cost-effective. Therefore, we are proposing to 
determine that NOX BART for Lake Catherine Unit 4 for the 
natural gas firing scenario is an emission limit of 0.22 lb/MMBtu on a 
30 boiler-operating-day rolling average based on the installation and 
operation of BOOS. We are proposing to require compliance with this 
requirement no later than 3 years from the effective date of the final 
rule, consistent with our regional haze regulations.\75\ We are 
proposing to require that compliance be demonstrated using the unit's 
existing CEMS. We are inviting public comment specifically on whether 
this proposed NOX emission limit is appropriate or whether 
an emission limit based on more stringent NOX controls would 
be appropriate. We are also proposing regulatory text that includes 
monitoring, reporting, and recordkeeping requirements associated with 
this emission limit.
---------------------------------------------------------------------------

    \75\ 40 CFR 51.308(e)(1)(iv).
---------------------------------------------------------------------------

6. Domtar Ashdown Paper Mill
    The Domtar Ashdown Paper Mill Power Boilers No. 1 and 2 are subject 
to BART. As mentioned previously, we disapproved Arkansas' BART 
determinations for SO2 and NOX for Power Boiler 
No. 1 and the BART determination for SO2, NOX, 
and PM for the No. 2 Power Boiler in our March 12, 2012 final action 
(77 FR 14604). The No. 1 Power Boiler has a heat input rating of 580 
MMBtu/hr and an average steam generation rate of approximately 120,000 
lb/hr. The No. 1 Power Boiler combusts primarily bark, but is also 
permitted to burn wood waste, tire-

[[Page 18979]]

derived fuel (TDF), municipal yard waste, pelletized paper fuel (PPF), 
fuel oil, reprocessed fuel oil, and natural gas. It is equipped with a 
traveling grate, a combustion air system, and a wet ESP. The No. 2 
Power Boiler has a heat input rating of 820 MMBtu/hr and an average 
steam generation rate of approximately 600,000 lb/hr. The No. 2 Power 
Boiler combusts primarily pulverized bituminous coal, but is also 
permitted to burn bark, PPF, TDF, municipal yard waste, fuel oil, used 
oil, natural gas, petroleum coke, and reprocessed fuel oil. It is 
equipped with a traveling grate, combustion air system including OFA, 
multiclones for particulate removal, and two venturi scrubbers in 
parallel for removal of remaining particulates and SO2. 
Domtar hired a consultant to perform a BART five-factor analysis for 
the Domtar Ashdown Mill Power Boilers No. 1 and 2 (Domtar's 2014 BART 
analysis).\76\ In this proposal, we also refer to certain parts of the 
Domtar BART evaluation submitted by the State in the 2008 Arkansas RH 
SIP, which we are hereafter referring to as the ``2006/2007 Domtar BART 
analysis.'' \77\ Although we already took action on that SIP submittal, 
we reference the 2006/2007 Domtar BART analysis as it contains the best 
available information we have related to certain NOX 
controls for Power Boilers No. 1 and 2.
---------------------------------------------------------------------------

    \76\ See ``Supplemental BART Determination Information Domtar 
A.W. LLC, Ashdown Mill (AFIN 41-00002),'' originally dated June 28, 
2013 and revised on May 16, 2014, prepared by Trinity Consultants 
Inc. in conjunction with Domtar A.W. LLC. A copy of this BART 
analysis is found in the docket for our proposed rulemaking.
    \77\ See ``Best Available Retrofit Technology Determination 
Domtar Industries Inc., Ashdown Mill (AFIN 41-00002),'' originally 
dated October 31, 2006 and revised on March 26, 2007, prepared by 
Trinity Consultants Inc. This BART analysis is part of the 2008 
Arkansas RH SIP, upon which EPA took final action on March 12, 2012 
(77 FR 14604). A copy of this BART analysis is found in the docket 
for this proposed rulemaking.
---------------------------------------------------------------------------

    The table below summarizes the baseline emission rates for Power 
Boilers No. 1 and 2. The SO2 baseline emission rate for 
Power Boiler No. 1 used in Domtar's 2014 BART analysis is the highest 
actual 24-hour emission rate estimated using maximum 24-hour fuel usage 
rates during 2009-2011 and sulfur content values for each fuel 
type.\78\ The 2009-2011 period was used as the baseline in Domtar's 
evaluation for Power Boiler No. 1 because a wet ESP was installed on 
Power Boiler No. 1 in 2007 to meet the Maximum Achievable Control 
Technology (MACT) standards under CAA section 112, resulting in a 
reduction in PM and SO2 emissions from Power Boiler No. 1. 
Therefore, we believe that the 2009-2011 period is more representative 
of the boiler's current emissions than 2001-2003. We believe the use of 
2009-2011 as the new baseline period for Power Boiler No. 1 is 
consistent with the BART Guidelines, which provide that the baseline 
emissions rate should represent a realistic depiction of anticipated 
annual emissions for the source.\79\ The NOX and PM baseline 
emission rates used for Power Boiler No. 1 are the highest actual 24-
hour emission rates estimated using the maximum heat input from 2009-
2011 and emission factors developed from the analysis of stack testing 
the facility had previously conducted. For Power Boiler No. 2, the 
baseline emission rates are the highest actual 24-hour emission rates 
based on a combination of 2001-2003 CEMS data, source-specific stack 
testing results, and emission factors from AP-42.
---------------------------------------------------------------------------

    \78\ In Domtar's 2014 BART analysis, 2009-2011 was used as the 
baseline period for Power Boiler No. 1 because a wet ESP was 
installed on Power Boiler No. 1 in 2007. The installation of the wet 
ESP resulted in a reduction in PM and SO2 emissions from 
Power Boiler No. 1. Therefore, 2009-2011 is more representative of 
the boiler's emissions than 2001-2003.
    \79\ 40 CFR part 51, Appendix Y, section IV.D.4.c.

                     Table 43--Domtar Ashdown Mill: Baseline Maximum 24-Hour Emission Rates
----------------------------------------------------------------------------------------------------------------
                                                         NOX Emissions (lb/ SO2 Emissions (lb/      PM10/PMf
                  Subject to BART unit                          hr)                hr)         Emissions (lb/hr)
----------------------------------------------------------------------------------------------------------------
Power Boiler No. 1.....................................              207.4               21.0               30.4
Power Boiler No. 2.....................................              526.8              788.2               81.6
----------------------------------------------------------------------------------------------------------------

    Domtar modeled the baseline emission rates using the CALPUFF 
dispersion model to determine the baseline visibility impairment 
attributable to the Domtar Ashdown Mill's Power Boilers No. 1 and 2 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 visibility impairment 
attributable to the source at each Class I area is summarized in the 
table below.

                Table 44--Baseline Visibility Impairment Attributable to the Domtar Ashdown Mill
----------------------------------------------------------------------------------------------------------------
                                                                                     Hercules-
                  Emission unit                     Caney Creek    Upper Buffalo      Glades           Mingo
----------------------------------------------------------------------------------------------------------------
Power Boiler No. 1:
    Maximum ([Delta]dv).........................           0.476           0.090           0.077           0.060
    98th Percentile ([Delta]dv).................           0.335           0.038           0.020           0.014
Power Boiler No. 2:
    Maximum ([Delta]dv).........................           1.603           0.381           0.329           0.246
    98th Percentile ([Delta]dv).................           0.844           0.146           0.105           0.065
----------------------------------------------------------------------------------------------------------------

    a. Proposed SO2 BART Analysis and Determination for Power Boiler 
No. 1. The table above shows that the baseline visibility impairment 
attributable to Power Boiler No. 1 is relatively low based on the 98th 
percentile visibility impacts, ranging from 0.014-0.335 dv at each 
Class I area. An examination of the species contribution to the 98th 
percentile visibility impacts shows that SO2 emissions 
contribute a very small portion of the visibility impairment

[[Page 18980]]

attributable to Power Boiler No. 1 (see the table below). The 
SO4 species contributes only 2.23--4.03% of the visibility 
impairment attributable to Power Boiler No. 1 at the modeled Class I 
areas. We also note that Power Boiler No. 1 combusts primarily bark, 
which results in very low SO2 emissions due to the low 
sulfur content of bark.

                      Table 45--Baseline Visibility Impairment and Species Contribution for Domtar Ashdown Mill--Power Boiler No. 1
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                               98th         Species contribution to 98th percentile visibility impacts
                                                                            Percentile   ---------------------------------------------------------------
              Emissions unit                        Class I area            visibility         98th            98th            98th            98th
                                                                           impacts (dv)    Percentile %    Percentile %    Percentile %    Percentile %
                                                                               \80\             SO4             NO3            PM10             NO2
--------------------------------------------------------------------------------------------------------------------------------------------------------
Power Boiler No. 1........................  Caney Creek.................           0.335            2.23           85.26            6.68            5.83
                                            Upper Buffalo...............           0.038            2.75           85.89            8.03            3.32
                                            Hercules-Glades.............           0.020            2.70           91.82            3.94            1.55
                                            Mingo.......................           0.014            4.03           90.06            5.13            0.78
--------------------------------------------------------------------------------------------------------------------------------------------------------

    As noted above, we believe that the BART Rule provides that states, 
or EPA in this case, can adopt a more streamlined approach to making 
BART determinations where appropriate.\81\ Considering the very low 
baseline visibility impairment that is due to SO2 emissions 
from Power Boiler No. 1 and the fact that the boiler combusts primarily 
bark, which has a low sulfur content, we believe that any visibility 
improvement that could be achieved as a result of emissions reductions 
associated with the installation and operation of SO2 
controls would be negligible, and that the cost of those controls could 
not be justified. Therefore, we are proposing that the SO2 
baseline emission rate of 21.0 lb/hr satisfies SO2 BART for 
Power Boiler No. 1. We are proposing this SO2 emission rate 
on a 30 boiler-operating-day averaging basis, where in this particular 
case boiler-operating-day is defined as a 24-hour period between 12 
midnight and the following midnight during which any fuel is fed into 
and/or combusted at any time in the Power Boiler. Power Boiler No. 1 is 
not currently equipped with a CEMS. To demonstrate compliance with this 
SO2 BART emission limit we are proposing to require the 
facility to use a site-specific curve equation,\82\ provided to us by 
the facility, to calculate the SO2 emissions from Power 
Boiler No. 1 when combusting bark, and to confirm the curve equation 
using stack testing.\83\ We are also proposing that to calculate the 
SO2 emissions from fuel oil combustion, the facility must 
assume that the SO2 inlet is equal to the SO2 
being emitted at the stack. We are inviting public comment on whether 
this method of demonstrating compliance with the proposed BART emission 
limit is appropriate. Since this proposed BART determination does not 
require the installation of control equipment, we are proposing that 
this SO2 emission limit be complied with by the effective 
date of the final action.
---------------------------------------------------------------------------

    \80\ The visibility impact shown represents the highest 98th 
percentile value among the three modeled years.
    \81\ 70 FR 39116.
    \82\ The curve equation is Y = 0.4005 * X - 0.2645, where Y = 
pounds of sulfur emitted per ton dry fuel feed to the boiler and X = 
pounds of sulfur input per ton of dry bark. The purpose of this 
equation is to factor in the degree of SO2 scrubbing 
provided by the combustion of bark.
    \83\ Background information and an explanation of the site 
specific curve equation provided by Domtar can be found in the 
documents titled ``Site Specific Curve Equation Background_Domtar PB 
No1,'' and ``1PB SO2 Emissions from Curve.'' Copies of 
these documents can be found in the docket for this proposed 
rulemaking.
---------------------------------------------------------------------------

    b. Proposed NOX BART Analysis and Determination for Power Boiler 
No. 1. For NOX BART, Domtar's 2014 BART analysis evaluated 
SNCR and Methane de-NOX (MdN). In the 2006/2007 Domtar BART 
analysis, which was submitted in the 2008 Arkansas RH SIP, other 
NOX controls were also evaluated but found by Arkansas to be 
either already in use or not technically feasible for use at Power 
Boiler No. 1. Fuel blending, boiler operational modifications, and 
boiler tuning/optimization are already in use at the source, while FGR, 
LNB, Ultra Low NOX Burners (ULNB), OFA, and SCR were 
determined to be technically infeasible for use at Power Boiler No. 1. 
Domtar did not further evaluate these NOX controls in its 
2014 BART analysis for Power Boiler No. 1, focusing instead on SNCR and 
MdN.
    MdN utilizes the injection of natural gas together with 
recirculated flue gases to create an oxygen-rich zone above the 
combustion grate. Air is then injected at a higher furnace elevation to 
burn the combustibles. In response to comments provided by us regarding 
Domtar's 2014 BART analysis, Domtar stated that discussions regarding 
the technical infeasibility of MdN in the 2006/2007 Domtar BART 
analysis, submitted as part of the 2008 Arkansas RH SIP, remain 
correct.\84\ The 2006/2007 Domtar BART analysis submitted in the 2008 
Arkansas RH SIP discussed that MdN has not been fully demonstrated for 
this source type and incorporates FGR, which is technically infeasible 
for use at Power Boiler No. 1. Domtar also stated it recently completed 
additional research and found that since the 2006/2007 Domtar BART 
analysis, MdN has not been placed into operation in power boilers at 
paper mills or any comparable source types. We are also not aware of 
any power boilers at paper mills that operate MdN for NOX 
control, and agree that this control can be considered technically 
infeasible for use at Power Boiler No. 1 and do not further consider it 
in this evaluation. Domtar also questioned the technical feasibility of 
SNCR for bark fired boilers and boilers with high load swings such as 
Power Boiler No. 1, but in response to our comments, SNCR was evaluated 
for Power Boiler No. 1 in Domtar's 2014 BART analysis.
---------------------------------------------------------------------------

    \84\ See the document titled ``Domtar Responses to ADEQ 
Regarding Region 6 Comments on Domtar BART Analysis,'' p. 10. A copy 
of this document can be found in the docket for our proposed 
rulemaking.
---------------------------------------------------------------------------

    Domtar's 2014 BART analysis evaluated SNCR at removal efficiencies 
of 20%, 32.5%, and 45% for Power Boiler No. 1. The estimated 32.5% and 
45% removal efficiencies were based on equipment vendor estimates that 
came from the vendor's proposal,\85\ which according to the facility, 
is not an appropriations request level quote and

[[Page 18981]]

therefore needs further refinement.\86\ For example, Domtar's 2014 BART 
analysis discusses that for a base loaded pulp mill boiler with steady 
flue gas flow patterns and temperature distribution across the flue gas 
pathway, SNCR can achieve a 45% removal efficiency. However, Power 
Boiler No. 1 is not a base loaded boiler. Domtar's 2014 BART analysis 
states that for pulp mill boilers with fluctuating loads (i.e., high 
load swing), such as Power Boiler No. 1, SNCR is used primarily for 
polishing purposes (i.e., < 20 to 30% NOX reduction) and it 
is uncertain whether higher removal efficiencies are achievable on a 
long-term basis. The facility believes that 20% removal efficiency, 
which has been demonstrated at a similar bark fired power boiler at 
another paper mill, is the most reasonable estimate of the removal 
efficiency of SNCR for Power Boiler No. 1.
---------------------------------------------------------------------------

    \85\ Fuel Tech Proposal titled ``Domtar Paper Ashdown, 
Arkansas--NOX Control Options, Power Boilers 1 and 2,'' 
dated June 29, 2012. A copy of the vendor proposal is included under 
Appendix D to the ``Supplemental BART Determination Information 
Domtar A.W. LLC, Ashdown Mill (AFIN 41-00002),'' originally dated 
June 28, 2013 and revised on May 16, 2014, prepared by Trinity 
Consultants Inc. in conjunction with Domtar A.W. LLC. A copy of this 
BART analysis and its appendices is found in the docket for our 
proposed rulemaking.
    \86\ See the document titled ``Domtar Responses to ADEQ 
Regarding Region 6 Comments on Domtar BART Analysis,'' p. 9. A copy 
of this document can be found in the docket for our proposed 
rulemaking.
---------------------------------------------------------------------------

    In Domtar's 2014 BART analysis, the capital costs, operating costs, 
and cost-effectiveness of SNCR were calculated based on methods and 
assumptions found in our Control Cost Manual, and supplemented with 
mill-specific cost information for water, fuels, and ash disposal and 
urea solution usage estimates from the equipment vendor. The capital 
cost was annualized over a 30-year period and then added to the annual 
operating cost to obtain the total annualized costs. The annual 
emissions reductions associated with each NOX control option 
were determined by subtracting the estimated controlled annual emission 
rate from the baseline annual emission rate. The baseline annual 
emissions used in the calculations are the uncontrolled actual 
emissions from the 2009-2011 baseline period. The average cost-
effectiveness was calculated by dividing the total annual cost by the 
estimated annual NOX emissions reductions. The table below 
summarizes the cost of NOX controls for Power Boiler No. 1.

                                            Table 46--Summary of Cost of NOX Controls for Power Boiler No. 1
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                           Annual
                                         Baseline       NOX Control       emissions     Capital cost    Total annual    Average cost   Incremental cost-
       NOX Control  scenarios          emission rate   efficiency (%)  reduction (NOX        ($)         cost ($/yr)    effectiveness  effectiveness ($/
                                         (NOX tpy)                          tpy)                                           ($/ton)            ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
SNCR--20%...........................             440             20                88       2,152,365       1,118,178          12,700  .................
SNCR--32.5%.........................             440             32.5             143       2,423,587       1,144,103           7,996                471
SNCR--45%...........................             440             45               198       2,707,431       1,513,602           7,640              6,718
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Domtar's 2014 BART analysis did not identify any energy or non-air 
quality environmental impacts associated with the use of SNCR. We are 
not aware of any unusual circumstances at the facility that create 
greater non-air quality environmental impacts than experienced 
elsewhere that may provide a basis for the elimination of these control 
options 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 the operation of NOX 
controls at Power Boiler No. 1 that would affect our proposed BART 
determination.
    Consideration of the presence of existing pollution control 
technology at the source is reflected in the BART analysis in two ways: 
First, in the consideration of available control technologies, and 
second, in the development of baseline emission rates for use in cost 
calculations and visibility modeling. Power Boiler No. 1 is currently 
equipped with a combustion air system to optimize boiler combustion 
efficiency, which has the co-benefit of reducing emissions. The 
baseline emission rate used in the cost calculations and visibility 
modeling reflects the use of the existing combustion air system.
    In the 2014 BART analysis, Domtar assessed the visibility 
improvement associated with SNCR by modeling the NOX 
emission rates associated with each control option using CALPUFF, and 
then comparing the visibility impairment associated with the baseline 
emission rate to the visibility impairment associated with the 
controlled emission rates as measured by the 98th percentile modeled 
visibility impact. The table below shows a comparison of the baseline 
(i.e., existing) visibility impacts and the visibility impacts 
associated with SNCR.

             Table 47--Domtar Ashdown Mill Power Boiler No. 1: Summary of the 98th Percentile Visibility Impacts and Improvement Due to SNCR
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                            SNCR--20%                   SNCR--32.5%                   SNCR--45%
                                                        Baseline  --------------------------------------------------------------------------------------
                                                       visibility                 Visibility                   Visibility                   Visibility
                     Class I area                        impact     Visibility    improvement    Visibility    improvement    Visibility    improvement
                                                          (dv)        impact     from baseline     impact     from baseline     impact     from baseline
                                                                   ([Delta]dv)    ([Delta]dv)   ([Delta]dv)    ([Delta]dv)   ([Delta]dv)    ([Delta]dv)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Caney Creek..........................................       0.335       0.274            0.061       0.237            0.098       0.199            0.136
Upper Buffalo........................................       0.038       0.031            0.007       0.027            0.011       0.023            0.015
Hercules-Glades......................................       0.020       0.017            0.003       0.014            0.006       0.012            0.008
Mingo................................................       0.014       0.011            0.003       0.009            0.005       0.008            0.006
Cumulative Visibility Improvement ([Delta]dv)........  ..........  ...........           0.074  ...........            0.12  ...........           0.165
--------------------------------------------------------------------------------------------------------------------------------------------------------

    The table above shows that the installation and operation of SNCR 
is projected to result in visibility improvements of up to 0.136 dv at 
any single Class I area when operated at 45% removal efficiency, 0.098 
dv when operated at 32.5% removal efficiency, and 0.061 dv when 
operated at 20%

[[Page 18982]]

removal efficiency (based on the 98th percentile modeled visibility 
impacts).
    Our Proposed NOX BART Determination: Taking into consideration the 
five factors, we are proposing to determine that NOX BART 
for the Domtar Ashdown Mill Power Boiler No. 1 is an emission limit of 
207.4 lb/hr on a 30 boiler-operating-day rolling average, where boiler-
operating-day is defined as a 24-hour period between 12 midnight and 
the following midnight during which any fuel is fed into and/or 
combusted at any time in the Power Boiler. This emission limit is based 
on the boiler's NOX baseline emission rate and therefore 
represents current operating conditions. MdN was determined to be not 
technically feasible for use at Power Boiler No. 1 because it has not 
been fully demonstrated for this source type and incorporates FGR, 
which is technically infeasible for use at the boiler. The installation 
and operation of SNCR is projected to result in some visibility 
improvement at the Class I areas. As discussed in more detail above, we 
concur with Domtar's position that 20% removal efficiency is the most 
reasonable estimate of the level of NOX control SNCR can 
achieve at Power Boiler No. 1. When operated at 20% removal efficiency, 
SNCR is projected to result in visibility improvement of up to 0.061 dv 
at any single Class I area and is estimated to cost $12,700 per ton of 
NOX removed. We do not believe this high cost justifies the 
modest visibility improvement projected from the installation and 
operation of SNCR at 20% removal efficiency. Although there is 
uncertainty as to whether SNCR can achieve a long term removal 
efficiency of 45% or even 32.5% at Power Boiler No. 1, we believe that 
the associated costs are also too high to justify the small projected 
visibility benefits. Installation and operation of SNCR at a 45% 
removal efficiency is projected to result in a visibility improvement 
of up to 0.136 dv at any single Class I area and is estimated to cost 
$7,640 per ton of NOX removed. The operation of SNCR at a 
32.5% removal efficiency is projected to result in visibility 
improvement of up to 0.098 dv at any single Class I area and is 
estimated to cost $7,996 per ton of NOX removed. Therefore, 
we are proposing to determine that NOX BART for Power Boiler 
No. 1 is no additional control and are proposing that an emission limit 
of 207.4 lb/hr on a 30 boiler-operating-day rolling average satisfies 
NOX BART. In this particular case, we are defining boiler-
operating-day as a 24-hour period between 12 midnight and the following 
midnight during which any fuel is fed into and/or combusted at any time 
in the Power Boiler. Power Boiler No. 1 is not currently equipped with 
a CEMS. To demonstrate compliance with this NOX BART 
emission limit we are proposing to require annual stack testing. We are 
inviting public comment on the appropriateness of this method for 
demonstrating compliance with the NOX BART emission limit 
for Power Boiler No. 1. Since this proposed BART determination does not 
require the installation of control equipment, we are proposing that 
this NOX emission limit be complied with by the effective 
date of the final action. We are also proposing regulatory text that 
includes monitoring, reporting, and recordkeeping requirements 
associated with this proposed BART determination.
    c. Proposed SO2 BART Analysis and Determination for Power Boiler 
No. 2. Power Boiler No. 2 is currently equipped with two venturi wet 
scrubbers in parallel for removal of particulates and SO2. 
Domtar's 2014 BART analysis evaluated upgrades to the existing venturi 
wet scrubbers and new add-on spray scrubbers for Power Boiler No. 
2.\87\ Domtar's analysis explains that it contracted with a vendor to 
evaluate upgrades to the existing venturi scrubbers and provide a quote 
for a new add-on spray scrubber system that would be installed 
downstream of the existing venturi scrubbers.\88\ Domtar's analysis 
states that the existing venturi scrubbers achieve an SO2 
control efficiency of approximately 90% and notes that this is within 
the normal range for the highest control efficiency achieved by 
SO2 control technologies. Domtar's analysis indicates that 
the upgrades it considered for the existing venturi scrubbers include: 
(1) The elimination of bypass reheat, (2) the installation of liquid 
distribution rings, (3) the installation of perforated trays, (4) 
improvements to the auxiliary system requirement, and (5) a redesign of 
spray header and nozzle configuration. Domtar's analysis states that 
any additional control that could potentially be achieved from 
implementation of such upgrades would be marginal, but the facility was 
unable to quantify the potential additional control. Therefore, it was 
determined that the installation of new add-on spray scrubbers to 
operate downstream of the existing scrubbers was more feasible than any 
upgrade option. The remainder of Domtar's analysis focused on the add-
on spray scrubber option. Based on the information provided to Domtar 
by the vendor, the add-on spray scrubbers would utilize sodium 
hydroxide (NaOH), bleach plant EO filtrate (i.e., bleaching filtrate), 
and water as the scrubbing reagent. The add-on spray scrubbers are 
estimated to achieve 90% control efficiency above the SO2 
removal the existing venturi scrubbers are currently achieving. In 
Domtar's analysis, it is estimated that a controlled SO2 
emission rate of 78.8 lb/hr would be achieved by the operation of add-
on spray scrubbers installed downstream of the existing venturi 
scrubbers.
---------------------------------------------------------------------------

    \87\ See ``Supplemental BART Determination Information Domtar 
A.W. LLC, Ashdown Mill (AFIN 41-00002),'' originally dated June 28, 
2013 and revised on May 16, 2014, prepared by Trinity Consultants 
Inc. in conjunction with Domtar A.W. LLC. A copy of this BART 
analysis is found in the docket for our proposed rulemaking.
    \88\ See ``Lundberg Budget Proposal Spray Scrubber--Domtar 
Industries, Ashdown, AR,'' dated April 17, 2014. The vendor proposal 
is found under Appendix D to Domtar's BART analysis titled 
``Supplemental BART Determination Information Domtar A.W. LLC, 
Ashdown Mill (AFIN 41-00002),'' originally dated June 28, 2013 and 
revised on May 16, 2014, prepared by Trinity Consultants Inc. in 
conjunction with Domtar A.W. LLC.
---------------------------------------------------------------------------

    Domtar's estimates of the capital and operating and maintenance 
costs of add-on spray scrubbers for Power Boiler No. 2 were based on 
the equipment vendor's budget proposal and on calculation methods from 
our Control Cost Manual. Domtar annualized the capital cost of the add-
on spray scrubbers over a 30-year amortization period and then added 
these to the annual operating costs to obtain the total annualized 
cost.\89\ The average cost-effectiveness in dollars per ton removed was 
calculated by dividing the total annualized cost by the annual 
SO2 emissions reductions. The average cost-effectiveness of 
the add-on spray scrubbers for Power Boiler No. 2 was estimated to be 
$5,258 per ton of SO2 removed (see table below). Domtar's 
analysis notes that because of constricted space, there is no existing 
property or adequate structure to support the add-on spray scrubber 
equipment. In our discussions with Domtar, the facility indicated that 
the installation of add-on spray scrubbers would require construction 
at the facility to accommodate the equipment, but an estimate of these 
costs was not available and therefore not factored into the cost 
estimates presented in Domtar's analysis.
---------------------------------------------------------------------------

    \89\ See Appendices B and D to the ``Supplemental BART 
Determination Information Domtar A.W. LLC, Ashdown Mill (AFIN 41-
00002),'' originally dated June 28, 2013 and revised on May 16, 
2014, prepared by Trinity Consultants Inc. in conjunction with 
Domtar A.W. LLC.

[[Page 18983]]



                                       Table 48--Summary of Costs for Add-On Spray Scrubber for Power Boiler No. 2
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                             Baseline   Controlled                Annual                 Annual      Annual      Total
                                             emission    emission   Controlled   emissions   Capital   direct O&M   indirect     annual    Average cost
            Control technology               rate (SO2  level (lb/   emission   reductions    cost *    cost ($/    O&M cost    cost ($/   effectiveness
                                               tpy)         hr)     rate (tpy)   (SO2 tpy)     ($)         yr)       ($/yr)       yr)         ($/ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Add-on Spray Scrubber.....................       2,078        78.8         208       1,870  7,175,000   8,833,382     421,789  9,833,378           5,258
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Capital cost does not include new construction to accommodate equipment.

    Domtar's 2014 BART analysis did not identify any energy or non-air 
quality environmental impacts associated with the use of add-on spray 
scrubbers. We are not aware of any unusual circumstances at the 
facility that create non-air quality environmental impacts associated 
with the use of add-on spray scrubbers greater than experienced 
elsewhere that may therefore provide a basis for the elimination of 
this control option 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 this control option 
at Power Boiler No. 2 that would affect our proposed BART 
determination.
    Consideration of the presence of existing pollution control 
technology at the source is reflected in the BART analysis in two ways: 
First, in the consideration of available control technologies, and 
second, in the development of baseline emission rates for use in cost 
calculations and visibility modeling. Power Boiler No. 2 is equipped 
with multiclones for particulate removal and two venturi scrubbers in 
parallel for control of SO2 emissions. It is also equipped 
with a combustion air system including overfire air to optimize boiler 
combustion efficiency, which also helps control emissions. The baseline 
emission rate used in the cost calculations and visibility modeling 
reflects the use of these existing controls. As discussed above, 
Domtar's analysis also evaluated upgrades to the existing venturi 
scrubbers to potentially achieve greater SO2 control 
efficiency. Another option we have identified to achieve greater 
SO2 control efficiency of the existing scrubbers involves 
using additional scrubbing reagent, but this was not considered in 
Domtar's 2014 BART analysis. Our analysis of this control option is 
presented below, following the analysis of add-on spray scrubbers.
    In the 2014 BART analysis, Domtar assessed the visibility 
improvement associated with the add-on spray scrubbers by modeling the 
controlled SO2 emission rate using CALPUFF, and then 
comparing the visibility impairment associated with the controlled 
emission rate to that of the baseline emission rate as measured by the 
98th percentile modeled visibility impact. The table below shows a 
comparison of the baseline (i.e., existing) visibility impacts and the 
visibility impacts associated with the add-on spray scrubbers. The 
installation and operation of add-on spray scrubbers is projected to 
result in visibility improvement of 0.146 dv at Caney Creek. The 
visibility improvement is projected to range from 0.026-0.053 dv at 
each of the other Class I areas.

     Table 49--Domtar Ashdown Mill Power Boiler No. 2: Summary of the 98th Percentile Visibility Impacts and
                                    Improvement Due to Add-on Spray Scrubbers
----------------------------------------------------------------------------------------------------------------
                                                                                   Add-on spray scrubbers
                                                                           -------------------------------------
                                                              Baseline                             Visibility
                      Class I area                       visibility impact  Visibility impact   improvement from
                                                             \90\ (dv)         ([Delta]dv)          baseline
                                                                                                  ([Delta]dv)
----------------------------------------------------------------------------------------------------------------
Caney Creek............................................              0.844              0.698              0.146
Upper Buffalo..........................................              0.146              0.093              0.053
Hercules-Glades........................................              0.105              0.054              0.051
Mingo..................................................              0.065              0.039              0.026
Cumulative Visibility Improvement ([Delta]dv)..........  .................  .................              0.276
----------------------------------------------------------------------------------------------------------------

    As mentioned above, another option not evaluated in Domtar's 2014 
BART analysis is the optimization of the existing venturi scrubbers to 
achieve a higher SO2 control efficiency through the use of 
additional scrubbing reagent. Following discussions between us and 
Domtar, the facility provided additional information regarding the 
existing venturi scrubbers, including a description of the internal 
structure of the scrubbers, whether any scrubber upgrades have taken 
place, the type of reagent used, how the facility determines how much 
reagent to use, and the SO2 control efficiency.\91\ Domtar 
confirmed that no upgrades to the scrubbers have ever been performed 
and stated that 100% of the flue gas is treated by the scrubber 
systems. The scrubbing solution used in the venturi scrubbers is made 
up of three components: 15% caustic solution (i.e., NaOH), bleach plant 
EO filtrate (typical pH above 9.0), and demineralizer anion rinse water 
(approximately 2.5% NaOH). The bleach plant EO filtrate and 
demineralizer anion rinse water are both waste byproducts from the 
processes at the plant. The 15% caustic solution is added to adjust the 
pH of the scrubbing solution and maintain it within the required range 
to ensure that sufficient SO2 is removed from the flue gas 
in the scrubber to meet the permitted SO2

[[Page 18984]]

emission limit of 1.20 lb/MMBtu on a three hour average. Each venturi 
scrubber has a recirculation tank that is equipped with level control 
systems to ensure that an adequate supply of the scrubbing solution is 
maintained. There are pH controllers in place that provide signals for 
the 15% caustic flow controllers to adjust the flow of the caustic 
solution to bring the pH into the desired set point range. The pH 
controllers are overridden in the event that SO2 levels 
measured at the stack by the CEMS are above the operator set point of 
0.86 lb/MMBtu on a two hour average (the SO2 permit limit is 
1.20 lb/MMBtu on a three hour average). This allows additional caustic 
feed to the scrubber solution to increase the pH and reduce the 
SO2 measured at the stack. According to Domtar, the scrubber 
systems operate in this manner to maintain continuous compliance with 
permitted emission limits.
---------------------------------------------------------------------------

    \90\ The baseline visibility impacts reflect the operation of 
the existing venturi scrubbers.
    \91\ See the following: Letters dated July 9, 2014; July 21, 
2014; August 15, 2014; August 29, 2014; and September 12, 2014, from 
Annabeth Reitter, Corporate Manager of Environmental Regulation, 
Domtar, to Dayana Medina, U.S. EPA Region 6. Copies of these letters 
and all attachments are found in the docket for our proposed 
rulemaking.
---------------------------------------------------------------------------

    Domtar provided monthly average data for 2011, 2012, and 2013 on 
monitored SO2 emissions from Power Boiler No. 2, mass of the 
fuel burned for each fuel type, and the percent sulfur content of each 
fuel type burned.\92\ Based on the information provided by Domtar, the 
monthly average SO2 control efficiency of the existing 
scrubbers for the 2011-2013 period ranged from 57% to 90%. The data 
indicate that the monthly average control efficiency of the scrubbers 
is usually below 90%. The information provided also indicates that the 
facility could add more scrubbing solution to achieve greater 
SO2 removal than what is necessary to meet permit limits. We 
believe that it is feasible for the facility to use additional 
scrubbing solution to consistently achieve at least a 90% 
SO2 removal on a monthly average basis. To estimate the 
SO2 annual emissions reductions expected from increasing the 
control efficiency of the scrubbers through the use of additional 
scrubbing solution, we calculated the annual average SO2 
control efficiency of the existing scrubbers. Based on the monthly 
average SO2 control efficiency data for the 2011-2013 
period, we estimated the annual average SO2 control 
efficiency for the three-year period to be approximately 69%.\93\ 
Considering the baseline annual emissions for Power Boiler No. 2 are 
2,078 SO2 tpy, and assuming that the scrubbers currently 
operate at an annual average control efficiency of 69%, we have 
estimated that the uncontrolled annual emissions would be 6,769 
SO2 tpy and that operating the scrubbers at 90% control 
efficiency would result in controlled annual emissions of 677 
SO2 tpy. By subtracting the controlled annual emission rate 
of 677 SO2 tpy from the baseline annual emission rate of 
2,078 SO2 tpy, we estimate that increasing the control 
efficiency of the existing venturi scrubbers from current levels to 90% 
control efficiency would result in annual emissions reductions of 1,401 
SO2 tpy from baseline levels.\94\ Based on the cost 
information provided by the facility, increasing the monthly average 
SO2 control efficiency of the existing venturi scrubbers 
from current levels to 90% control efficiency would require replacing 
two scrubber pumps, which involves capital costs of $200,000.\95\ It 
would also require additional scrubbing reagent, treatment of 
additional wastewater, treatment of additional raw water, and 
additional energy usage, which involves annual operation and 
maintenance costs of approximately $1.96 million. Based on the 
information provided by Domtar, we estimate the average cost-
effectiveness of using additional scrubbing reagent to increase the 
SO2 control efficiency of the existing venturi scrubbers 
from the current control efficiency (estimated to be 69%) to 90% is 
$1,411 per ton of SO2 removed. The cost information is 
presented in the table below. To determine the controlled emission rate 
that corresponds to the operation of the existing venturi scrubbers at 
a 90% removal efficiency, we first determined the SO2 
emission rate that corresponds to the operation of the scrubbers at the 
current control efficiency of 69%. Based on emissions data we obtained 
from Domtar, we determined that the No. 2 Power Boiler's annual average 
SO2 emission rate for the years 2009-2011 was 280.9 lb/
hr.\96\ This annual average SO2 emission rate corresponds to 
the operation of the scrubbers at a 69% removal efficiency. We also 
estimated that 100% uncontrolled emissions would correspond to an 
emission rate of approximately 915 lb/hr. Application of 90% control 
efficiency to this results in a controlled emission rate of 91.5 lb/hr, 
or 0.11 lb/MMBtu based on the boiler's maximum heat input of 820 
MMBtu.\97\
---------------------------------------------------------------------------

    \92\ August 29, 2014 letter from Annabeth Reitter, Corporate 
Manager of Environmental Regulation, Domtar, to Dayana Medina, U.S. 
EPA Region 6. A copy of this letter and an Excel file attachment 
titled ``Domtar 2PB Monthly SO2 Data,'' are found in the 
docket for our proposed rulemaking.
    \93\ See the spreadsheet titled ``Domtar 2PB Monthly 
SO2 Data.'' This spreadsheet was included as an 
attachment to the August 29, 2014 letter from Annabeth Reitter, 
Corporate Manager of Environmental Regulation, Domtar, to Dayana 
Medina, U.S. EPA Region 6. See also the spreadsheet titled ``Domtar 
PB No2--Cost Effectiveness calculations.'' Copies of these documents 
can be found in the docket for this proposed rulemaking.
    \94\ See the spreadsheet titled ``Domtar PB No2--Cost 
Effectiveness calculations.'' A copy of this spreadsheet can be 
found in the docket for this proposed rulemaking.
    \95\ September 30, 2014 letter from Annabeth Reitter, Corporate 
Manager of Environmental Regulation, Domtar, to Dayana Medina, U.S. 
EPA Region 6. See also the spreadsheet titled ``Domtar PB No2--Cost 
of Using Additional Scrubbing Reagent. Copies of these documents can 
be found in the docket for this proposed rulemaking.
    \96\ See the spreadsheet titled ``Domtar 2PB Monthly 
SO2 Data.'' This spreadsheet was included as an 
attachment to the August 29, 2014 letter from Annabeth Reitter, 
Corporate Manager of Environmental Regulation, Domtar, to Dayana 
Medina, U.S. EPA Region 6. See also the spreadsheet titled ``No2 
Boiler_Monthly Avg SO2 emission rate and calculations.'' 
Copies of these documents can be found in the docket for this 
proposed rulemaking.
    \97\ See the spreadsheet titled ``No2 Boiler_Monthly Avg 
SO2 emission rate and calculations.'' A copy of this 
spreadsheet can be found in the docket for this proposed rulemaking.
    \98\ The capital costs consist of two new pumps for the existing 
scrubber system.
    \99\ The operation and maintenance costs consist of the 
following costs: Additional scrubbing reagent, treatment of 
additional wastewater, treatment of additional raw water, and 
additional energy usage.

   Table 50--Summary of Cost of Using Additional Scrubbing Reagent To Increase Control Efficiency of Existing Venturi Scrubbers at Power Boiler No. 2
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                            Baseline                     Annual                 Operation &
                                                            emission     Controlled    emissions     Capital    maintenance     Total      Average cost
                     Control option                         rate (SO2     emission     reductions  costs \98\  cost \99\ ($/ annual cost   effectiveness
                                                              tpy)       rate (tpy)    (SO2 tpy)       ($)          yr)         ($/yr)        ($/ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Use of Additional Scrubbing Reagent.....................         2,078           677        1,401     200,000     1,960,434    1,976,554           1,411
--------------------------------------------------------------------------------------------------------------------------------------------------------



[[Page 18985]]

Using the visibility modeling analysis of the baseline visibility 
impacts from Power Boiler No. 2 and the visibility improvement 
projected from the installation and operation of new add-on spray 
scrubbers, we have extrapolated the visibility improvement projected as 
a result of using additional scrubbing reagent to increase the 
SO2 control efficiency of the existing venturi scrubbers 
from the current control efficiency (estimated to be 69%) to 90%, or an 
outlet emission rate of 0.11 lb/MMBtu. We have assumed that the maximum 
24-hour baseline emission rate used in the visibility modeling 
represents the operation of the existing venturi scrubbers at a 69% 
control efficiency. We estimate that the visibility improvement of 
using additional scrubbing reagent to increase the SO2 
control efficiency of the existing venturi scrubbers to 90% control 
efficiency is 0.139 dv at Caney Creek and 0.05 dv or less at each of 
the other Class I areas (see table below).

     Table 51--Domtar Ashdown Mill Power Boiler No. 2: Summary of the 98th Percentile Visibility Impacts and
                              Improvement From Use of Additional Scrubbing Reagent
----------------------------------------------------------------------------------------------------------------
                                                  Add-on spray scrubber  impacts   Estimated impacts from use of
                                                               (dv)                   additional reagent (dv)
                                     Baseline    ---------------------------------------------------------------
          Class I area              visibility                      Visibility                      Visibility
                                    impact (dv)     Visibility      improvement     Visibility      improvement
                                                    impact (dv)    from baseline    impact (dv)    from baseline
                                                                       (dv)                            (dv)
----------------------------------------------------------------------------------------------------------------
Caney Creek.....................           0.844           0.698           0.146           0.705           0.139
Upper Buffalo...................           0.146           0.093           0.053           0.096            0.05
Hercules-Glades.................           0.105           0.054           0.051           0.057           0.048
Mingo...........................           0.065           0.039           0.026            0.04           0.025
Cumulative Visibility             ..............  ..............           0.276  ..............           0.262
 Improvement (dv)...............
----------------------------------------------------------------------------------------------------------------

    Our Proposed SO2 BART Determination: Taking into consideration the 
five factors, we propose to determine that SO2 BART for 
Power Boiler No. 2 is an emission limit of 0.11 lb/MMBtu on a 30 
boiler-operating-day rolling average, which we estimate is 
representative of operating the existing scrubbers at 90% control 
efficiency. In this particular case, we define boiler-operating-day as 
a 24-hour period between 12 midnight and the following midnight during 
which any fuel is fed into and/or combusted at any time in the Power 
Boiler. We are inviting public comment specifically on the 
appropriateness of this proposed SO2 emission limit. We 
believe that this emission limit can be achieved by using additional 
scrubbing reagent in the operation of the existing venturi scrubbers. 
We estimate that operating the existing scrubbers to achieve this level 
of control would result in visibility improvement of 0.139 dv at Caney 
Creek and 0.05 dv or lower at each of the other Class I areas. We 
estimate the cumulative visibility improvement at the four Class I 
areas to be 0.262 dv. Based on the cost information provided by the 
facility, we have estimated that the use of additional scrubbing 
reagent to increase the control efficiency of the existing venturi 
scrubbers is estimated to cost $1,411 per ton of SO2 
removed. Based on Domtar's BART analysis, new add-on spray scrubbers 
that would be operated downstream of the existing venturi scrubbers are 
projected to result in visibility improvement of 0.146 dv at Caney 
Creek and 0.053 dv or lower at each of the other Class I areas. The 
cumulative visibility improvement at the four Class I areas is 
projected to be 0.276 dv. The cost of add-on spray scrubbers is 
estimated to be $5,258 per ton of SO2 removed, not including 
additional construction costs that would likely be incurred to make 
space to house the new scrubbers. We do not believe that the amount of 
visibility improvement that is projected from the installation and 
operation of new add-on spray scrubbers would justify their high 
average cost-effectiveness. The incremental visibility improvement of 
new add-on spray scrubbers compared to using additional scrubbing 
reagent to increase the control efficiency of the existing venturi 
scrubbers ranges from 0.001 to 0.007 dv at each Class I area, yet the 
incremental cost-effectiveness is estimated to be $16,752. We do not 
believe the incremental visibility benefit warrants the higher cost 
associated with new add-on spray scrubbers. Therefore, we are proposing 
to determine that SO2 BART for Power Boiler No. 2 is an 
emission limit of 0.11 lb/MMBtu on a 30 boiler-operating-day rolling 
averaging basis, and are inviting comment on the appropriateness of 
this emission limit. We propose to require the facility to demonstrate 
compliance with this emission limit using the existing CEMS. Since the 
SO2 emission limit we are proposing can be achieved with the 
use of the existing venturi scrubbers but will require scrubber pump 
upgrades and additional scrubbing reagent, we propose to require 
compliance with this BART emission limit no later than 3 years from the 
effective date of the final action, but are inviting public comment on 
the appropriateness of a compliance date anywhere from 1-5 years.
    d. Proposed NOX BART Analysis and Determination for Power Boiler 
No. 2. For NOX BART, Domtar's 2014 BART analysis evaluated 
LNB, SNCR, and Methane de-NOX (MdN). In the 2006/2007 Domtar 
BART analysis, which was submitted in the 2008 Arkansas RH SIP, other 
NOX controls were also evaluated but found by the State to 
be either already in use or not technically feasible for use at Power 
Boiler No. 2. Fuel blending, boiler operational modifications, and 
boiler tuning/optimization are already in use at the source, while FGR, 
OFA, and SCR were found to be technically infeasible for use at Power 
Boiler No. 2. Domtar did not further evaluate these NOX 
controls, and instead focused on LNB, SNCR, and MdN in its 2014 BART 
analysis for Power Boiler No. 2.
    MdN utilizes the injection of natural gas together with 
recirculated flue gases to create an oxygen-rich zone above the 
combustion grate. Air is then injected at a higher furnace elevation to 
burn the combustibles. In response to comments provided by us regarding 
Domtar 2014 BART analysis, Domtar stated that discussions regarding the 
technical infeasibility of MdN in the 2006/2007 Domtar BART analysis, 
submitted as part of the 2008 Arkansas RH SIP,

[[Page 18986]]

remain correct.\100\ The 2006/2007 Domtar BART analysis submitted in 
the 2008 Arkansas RH SIP discussed that MdN has not been fully 
demonstrated for this type of boiler and incorporates FGR, which is 
considered technically infeasible for use at Power Boiler No. 2. Domtar 
also stated it recently completed additional research and found that 
since the 2006/2007 Domtar BART analysis, MdN has not been placed into 
operation in power boilers at paper mills or any comparable source 
types. We are also not aware of any power boilers at paper mills that 
operate MdN for NOX control, and agree that this control can 
be considered technically infeasible for use at Power Boiler No. 2 and 
do not further consider it in this evaluation. Domtar also questioned 
the technical feasibility of SNCR for boilers with high load swing such 
as Power Boiler No. 2, but in response to comments from us, SNCR was 
evaluated in Domtar's 2014 BART analysis.
---------------------------------------------------------------------------

    \100\ A copy of Domtar's response is found in the docket for 
this proposed rulemaking. See email from Kelly Crouch, dated May 16, 
2014.
---------------------------------------------------------------------------

    Based on vendor estimates, the 2006/2007 Domtar BART analysis 
estimated the potential control efficiency of LNB to be 30%. In 
Domtar's 2014 BART analysis, SNCR was evaluated at a control efficiency 
of 27.5% and 35% for Power Boiler No. 2. These values were based on 
SNCR control efficiency estimates that came from the equipment vendor's 
proposal,\101\ which according to the facility, is not an 
appropriations request level quote and therefore requires further 
refinement.\102\ For example, Domtar's 2014 BART analysis discusses 
that for a base loaded coal boiler with steady flue gas flow patterns 
and temperature distribution across the flue gas pathway, SNCR is 
typically capable of achieving 50% NOX reduction. However, 
Power Boiler No. 2 is not a base loaded boiler and does not have steady 
flue gas flow patterns or steady temperature distribution across the 
flue gas pathway. To demonstrate the wide range in temperature at Power 
Boiler No. 2 and its relationship to steam demand, Domtar obtained an 
analysis of furnace exit gas temperatures for Power Boiler No. 2 from 
an engineering consultant.\103\ The furnace exit gas temperatures were 
analyzed for a 12-day period that according to Domtar is representative 
of typical boiler operations. The consultant's report indicated that 
furnace exit gas temperatures are representative of temperatures in the 
upper portion of the furnace, which is the optimal location for 
installation of the SNCR injection nozzles. The consultant estimated 
that 1700-1800[deg]F represents the temperature range at which SNCR can 
be expected to reach 40% control efficiency at the current boiler 
operating conditions. It was found that there is wide variability in 
the furnace exit gas temperatures for Power Boiler No. 2, with 
temperatures ranging from 1000-2000[deg]F. The data also indicate that 
there is a direct positive relationship between boiler steam demand and 
furnace exit gas temperatures. It was also found that Power Boiler No. 
2 operated in the optimal temperature zone at which SNCR can be 
expected to reach 40% control efficiency for only a total of 20 hours 
over the 12-day period analyzed (288 continuous hours), which is 
approximately 7% of the time. According to Domtar, the significant 
temperature swings, which are due to load following and steam demand 
variability, create a scenario where urea injection will either be too 
high or too low. When not enough urea is injected, NOX 
removal will be less than projected and when too much urea is injected, 
excess ammonia slip will occur. Domtar stated that the observed 
significant temperature swings demonstrate that it will be difficult to 
maintain stable, optimal furnace temperatures at which urea can be 
injected to effectively reduce NOX with minimal ammonia 
slip. We agree that because of the wide variability in steam demand and 
wide range in furnace temperature observed at Power Boiler No. 2, the 
NOX control efficiency of SNCR at the boiler would not reach 
optimal control levels on a long-term basis. We also believe there is 
uncertainty as to the level of control efficiency that SNCR would be 
able to achieve on a long-term basis for Power Boiler No. 2. However, 
we further consider SNCR in the remainder of the analysis.
---------------------------------------------------------------------------

    \101\ Fuel Tech Proposal titled ``Domtar Paper Ashdown, 
Arkansas- NOX Control Options, Power Boilers 1 and 2,'' 
dated June 29, 2012. A copy of the vendor proposal is included under 
Appendix D to the ``Supplemental BART Determination Information 
Domtar A.W. LLC, Ashdown Mill (AFIN 41-00002),'' originally dated 
June 28, 2013 and revised on May 16, 2014, prepared by Trinity 
Consultants Inc. in conjunction with Domtar A.W. LLC. A copy of this 
BART analysis and its appendices is found in the docket for our 
proposed rulemaking.
    \102\ See the document titled ``Domtar Responses to ADEQ 
Regarding Region 6 Comments on Domtar BART Analysis,'' p. 9. A copy 
of this document can be found in the docket for our proposed 
rulemaking.
    \103\ September 12, 2014 letter from Annabeth Reitter, Corporate 
Manager of Environmental Regulation, Domtar, to Dayana Medina, U.S. 
EPA Region 6. A copy of this letter and its attachments are found in 
the docket for our proposed rulemaking.
---------------------------------------------------------------------------

    In the 2006/2007 Domtar BART analysis, the capital cost, operating 
cost, and cost-effectiveness of LNB were estimated based on vendor 
estimates. The analysis was based on a 10-year amortization period, 
based on the equipment's life expectancy. However, since we believe a 
30-year equipment life is a more appropriate estimate for LNB, we have 
revised the cost estimate for LNB.\104\ The annual emissions reductions 
used in the cost-effectiveness calculations were determined by 
subtracting the estimated controlled annual emission rate from the 
baseline annual emission rate. We have also revised the average cost-
effectiveness calculations presented in the 2006/2007 Domtar BART 
analysis for LNB by using the boiler's actual annual uncontrolled 
NOX emissions rather than the maximum 24-hour emission rate 
as the baseline annual emissions. The table below summarizes the 
estimated cost of LNB for Power Boiler No. 2, based on the cost 
estimates in the 2006/2007 Domtar BART analysis our revisions discussed 
above.
---------------------------------------------------------------------------

    \104\ See the spreadsheet titled ``Domtar PB No. 2 LNB_cost 
revisions.'' A copy of this spreadsheet is found in the docket for 
this proposed rulemaking.
---------------------------------------------------------------------------

    In Domtar's 2014 BART analysis, the capital costs, operating costs, 
and cost-effectiveness of SNCR were calculated based on methods and 
assumptions found in our Control Cost Manual, and supplemented with 
mill-specific cost information for water, fuels, and ash disposal and 
urea solution usage estimates from the equipment vendor. The two SNCR 
control scenarios evaluated were 27.5% and 35% control efficiencies. 
The capital cost was annualized over a 30-year period and then added to 
the annual operating cost to obtain the total annualized costs. The 
annual emissions reductions associated with each NOX control 
option were determined by subtracting the estimated controlled annual 
emission rate from the baseline annual emission rate. The baseline 
annual emissions used in the calculations are the uncontrolled actual 
emissions from the 2001-2003 baseline period. The average cost-
effectiveness was calculated by dividing the total annual cost by the 
estimated annual NOX emissions reductions. The table below 
summarizes the cost of SNCR for Power Boiler No. 2.

[[Page 18987]]



                                            Table 52--Summary of Cost of NOX Controls for Power Boiler No. 2
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                              Annual
                                             Baseline       NOX Removal      emissions      Capital     Total annual    Average cost   Incremental cost-
          NOX Control scenario             emission rate   efficiency of  reduction (NOX    cost ($)     cost ($/yr)    effectiveness  effectiveness ($/
                                             (NOX tpy)     controls (%)        tpy)                                        ($/ton)            ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
SNCR--27.5%.............................           1,536            27.5             422    2,681,678         843,575           1,998  .................
LNB.....................................           1,536              30             461    6,131,745         899,605           1,951              1,437
SNCR--35%...............................           1,536              35             537    2,877,523       1,026,214           1,909              1,666
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Domtar's 2014 BART analysis did not identify any energy or non-air 
quality environmental impacts associated with the use of LNB or 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 NOX controls greater than experienced elsewhere 
and that may therefore provide a basis for the elimination of these 
control options 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 Power Boiler No. 2 that would affect our proposed BART 
determination.
    Consideration of the presence of existing pollution control 
technology at the source is reflected in the BART analysis in two ways: 
First, in the consideration of available control technologies, and 
second, in the development of baseline emission rates for use in cost 
calculations and visibility modeling. Power Boiler No. 2 is equipped 
with multiclones for particulate removal and two venturi scrubbers in 
parallel for control of SO2 emissions. It is also equipped 
with a combustion air system including overfire air to optimize boiler 
combustion efficiency, which also helps control emissions. The 
NOX baseline emission rate used in the cost calculations and 
visibility modeling reflects the use of these existing controls.
    In the 2014 BART analysis, Domtar assessed the visibility 
improvement associated with LNB and SNCR by modeling the NOX 
emission rates associated with each control option using CALPUFF, and 
then comparing the visibility impairment associated with the baseline 
emission rate to the visibility impairment associated with the 
controlled emission rates as measured by the 98th percentile modeled 
visibility impact. The table below shows a comparison of the baseline 
(i.e., existing) visibility impacts and the visibility impacts 
associated with LNB and SNCR.

         Table 53--Domtar Ashdown Mill Power Boiler No. 2: Summary of the 98th Percentile Visibility Impacts and Improvement Due to NOX Controls
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                          SNCR--27.5% Control           LNB 30% Control            SNCR--35% Control
                                                                              efficiency                  efficiency                  efficiency
                                                           Baseline  -----------------------------------------------------------------------------------
                      Class I area                        visibility                Visibility                  Visibility                  Visibility
                                                             impact   Visibility    improvement   Visibility    improvement   Visibility    improvement
                                                             (dv)        impact   from  baseline     impact   from  baseline     impact   from  baseline
                                                                         (dv)          (dv)          (dv)          (dv)          (dv)          (dv)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Caney Creek.............................................       0.844       0.678           0.166       0.663           0.181       0.632           0.212
Upper Buffalo...........................................       0.146       0.134           0.012       0.132           0.014       0.129           0.017
Hercules-Glades.........................................       0.105       0.095           0.010       0.094           0.011       0.092           0.013
Mingo...................................................       0.065       0.060           0.005       0.060           0.005       0.059           0.006
Cumulative Visibility Improvement (dv)..................  ..........  ..........           0.193  ..........           0.211  ..........           0.248
--------------------------------------------------------------------------------------------------------------------------------------------------------

    The table above shows that the installation and operation of SNCR 
when operated at 35% control efficiency, if feasible, is projected to 
result in visibility improvement of 0.212 dv at Caney Creek and 0.017 
dv or less at each of the other Class I areas. When operated at 27.5% 
control efficiency, if feasible, SNCR is projected to result in 
visibility improvement of 0.166 dv at Caney Creek and 0.012 dv or less 
at each of the other Class I areas. The installation and operation of 
LNB is projected to result in visibility improvement of 0.181 dv at 
Caney Creek and 0.014 dv or less at each of the other Class I areas.
    Our Proposed NOX BART Determination: Taking into 
consideration the five factors, we are proposing to determine that 
NOX BART for the Domtar Ashdown Mill Power Boiler No. 2 is 
an emission limit of 345 lb/hr on a 30 boiler-operating-day rolling 
averaging basis, based on the installation and operation of LNB. In 
this particular case, we define boiler-operating-day as a 24-hour 
period between 12 midnight and the following midnight during which any 
fuel is fed into and/or combusted at any time in the Power Boiler. MdN 
was determined to be not technically feasible for use at Power Boiler 
No. 2 because it has not been fully demonstrated for this type of 
boiler and incorporates FGR, which is technically infeasible for use at 
the boiler. The installation and operation of SNCR is projected to 
result in some visibility improvement at the Class I areas when 
operated at 27.5% and 35% control efficiency. However, based on the 
information provided by the facility, we believe that because of the 
wide variability in steam demand and wide range in furnace temperature 
observed in Power Boiler No. 2, the NOX control efficiency 
of SNCR at the boiler would not reach optimal control levels on a long-
term basis. There is uncertainty as to the level of control efficiency 
that SNCR would be able to achieve on a long-term basis for Power 
Boiler No. 2. The installation and operation of LNB is projected to 
result in visibility improvement of 0.181 dv at Caney Creek and 0.005-
0.014 dv at each of the other Class I areas. The installation and 
operation of LNB is estimated to cost $1,951 per ton of NOX 
removed, which

[[Page 18988]]

we consider to be cost-effective. Therefore, we are proposing to 
determine that NOX BART for Power Boiler No. 2 is an 
emission limit of 345 lb/hr on a 30 boiler-operating-day rolling 
average basis, based on the installation and operation of LNB. We are 
proposing to require compliance with this emission limit no later than 
3 years from the effective date of the final rule, and are inviting 
public comment on the appropriateness of this compliance date. We are 
proposing that the facility demonstrate compliance with this emission 
limit using the existing CEMS. We are also proposing regulatory text 
that includes monitoring, reporting, and recordkeeping requirements 
associated with this emission limit.
    e. PM BART Analysis and Determination for Power Boiler No. 2. PM 
BART for Power Boiler No. 2 is addressed in Domtar's 2014 BART 
analysis. Power Boiler No. 2 is subject to the Boiler MACT standards 
required under CAA section 112, and found at 40 CFR part 63, subpart 
DDDDD--National Emission Standards for Hazardous Air Pollutants for 
Major Sources: Industrial, Commercial, and Institutional Boilers and 
Process Heaters. Domtar streamlined the BART analysis for Power Boiler 
No. 2 by relying on the Boiler MACT standards for PM to satisfy the PM 
BART requirement. Power Boiler No. 2 was determined to fall under the 
``biomass hybrid suspension grate'' subcategory for the Boiler 
MACT.\105\ As such, Power Boiler No. 2 is subject to the Boiler MACT PM 
emission limit of 0.44 lb/MMBtu. The BART Guidelines provide that for 
VOC and PM sources subject to MACT standards, the BART analysis may be 
streamlined by including a discussion of the MACT controls and whether 
any major new technologies have been developed subsequent to the MACT 
standards.\106\ The BART Guidelines discuss that there are many VOC and 
PM sources that are well controlled because they are regulated by the 
MACT standards, and in many cases it will be unlikely that emission 
controls more stringent than the MACT standards will be identified 
without identifying control options that would cost many thousands of 
dollars per ton. Therefore, the BART Guidelines provide that unless 
there are new technologies subsequent to the MACT standards which would 
lead to cost-effective increases in the level of control, the MACT 
standards may be relied on for purposes of BART. Domtar's 2014 BART 
analysis does not discuss whether any new technologies subsequent to 
the MACT standards have become available and whether they would lead to 
cost-effective increases in the level of PM control for Power Boiler 
No. 2. However, Domtar at one point estimated the cost of installing 
both an add-on spray scrubber and wet ESP on Power Boiler No. 2. Based 
on this cost information previously provided by Domtar,\107\ we have 
determined that a wet ESP alone would have a purchased equipment cost 
(PEC) of $3.22 million and capital costs of approximately $11.3 
million. The total annual cost of a wet ESP alone is estimated to be 
approximately $1.96 million. The average annual PM emissions from Power 
Boiler No. 2 for the 2001-2003 baseline period were 183 tpy. Assuming 
that the wet ESP has a 95% control efficiency for PM emissions, we 
estimate that it would remove 174 PM tpy. Based on this, we estimate 
that the average cost-effectiveness of installing and operating a wet 
ESP on Power Boiler No. 2 is $11,254 per PM ton removed. Additionally, 
an examination of the species contribution to the 98th percentile 
visibility impacts shows that PM emissions contribute a very small 
portion of the visibility impairment attributable to Power Boiler No. 
2. As shown in the table below, the baseline visibility impairment 
attributable to Power Boiler No. 2 is 0.844 dv at Caney Creek and 0.146 
dv or less at each of the other Class I areas, based on the 98th 
percentile visibility impacts. The PM species contribute only 1.06-
4.58% of the baseline visibility impairment attributable to Power 
Boiler No. 2 at the modeled Class I areas.
---------------------------------------------------------------------------

    \105\ See letter dated October 28, 2013, from Thomas Rheaume, 
Permits Branch Manager, ADEQ, to Ms. Kelly Crouch, Manager of 
Environmental, Energy, and Pulp Tech. at Domtar Ashdown Mill. A copy 
of this letter is found in the docket for this proposed rulemaking.
    \106\ 40 CFR part 51, Appendix Y, section IV.C.
    \107\ The cost estimate of new add-on spray scrubbers and a wet 
ESP for Power Boiler No. 2 is found in Appendix B to the analysis 
titled ``Supplemental BART Determination Information Domtar A.W. 
LLC, Ashdown Mill (AFIN 41-00002),'' dated June 28, 2013, prepared 
by Trinity Consultants Inc. in conjunction with Domtar A.W. LLC. A 
copy of the BART analysis is found in the docket for our proposed 
rulemaking.

                      Table 54--Baseline Visibility Impairment and Species Contribution for Domtar Ashdown Mill--Power Boiler No. 2
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                               98th         Species contribution to 98th percentile visibility impacts
                                                                            Percentile   ---------------------------------------------------------------
              Emissions unit                        Class I area            visibility         98th            98th            98th            98th
                                                                           impacts  (dv)   Percentile %    Percentile %    Percentile %    Percentile %
                                                                               \108\            SO4             NO3            PM10             NO2
--------------------------------------------------------------------------------------------------------------------------------------------------------
Power Boiler No. 2........................  Caney Creek.................           0.844           22.04           70.68            4.58            2.69
                                            Upper Buffalo...............           0.146           76.99           20.76            2.26            0.00
                                            Hercules-Glades.............           0.105           61.17           37.68            1.06            0.09
                                            Mingo.......................           0.065           81.46           15.47            3.07            0.00
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Because of the very low baseline visibility impacts that are due to 
PM emissions from Power Boiler No. 2, we believe that there is 
potential for a very small amount of visibility improvement from the 
installation and operation of a wet ESP. We conclude that the 
installation and operation of a wet ESP for PM control is not cost-
effective in light of the relatively small improvement in visibility. 
Therefore, we are proposing to find that the current Boiler MACT PM 
standard of 0.44 lb/MMBtu satisfies the PM BART requirement for Power 
Boiler No. 2. We are also proposing that the same method for 
demonstrating compliance with the Boiler MACT PM standard is to be used 
for demonstrating compliance with the PM BART emission limit. Because 
we are proposing a BART emission limit that represents current/baseline 
operations and no control equipment installation is necessary, we are 
proposing that this emission limitation be complied with for BART 
purposes from the date of effectiveness of the finalized action.
---------------------------------------------------------------------------

    \108\ The visibility impact shown represents the highest 98th 
percentile value among the three modeled years.

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

[[Page 18989]]

IV. Our Proposed Reasonable Progress Analysis and Determinations

    The Regional Haze Rule does not mandate specific milestones or 
rates of progress towards achieving the national visibility goal, but 
instead calls for states to establish goals that provide for 
``reasonable progress'' toward achieving natural (i.e., ``background'') 
visibility conditions. The Regional Haze Rule and section 169A of the 
CAA require the states, or us in the case of a FIP, to set RPGs by 
considering four factors: The costs of compliance, the time necessary 
for compliance, the energy and non-air quality environmental impacts of 
compliance, and the remaining useful life of any potentially affected 
sources (collectively ``the RP factors'').\109\ States, or us in the 
case of a FIP, have considerable flexibility in how they take these 
factors into consideration, as noted in our Reasonable Progress 
Guidance.\110\ The RPGs must provide for an improvement in visibility 
on the most impaired days, and ensure no degradation in visibility on 
the least impaired days during the planning period.\111\ Furthermore, 
if the projected progress for the worst days is less than the Uniform 
Rate of Progress (URP), then the state or EPA must demonstrate, based 
on the factors above, that it is not reasonable to provide for a rate 
of progress consistent with the URP.\112\
---------------------------------------------------------------------------

    \109\ 40 CFR 51.308(d)(1)(i)(A) and CAA section 169A(g)(1).
    \110\ Guidance for Setting Reasonable Progress Goals Under the 
Regional Haze Program, June 1, 2007, memorandum from William L. 
Wehrum, Acting Assistant Administrator for Air and Radiation, to EPA 
Regional Administrators, EPA Regions 1-10 (pp. 4-2, 5-1).
    \111\ Id.
    \112\ 40 CFR 51.308(d)(1)(ii).
---------------------------------------------------------------------------

    In our final action on the Arkansas RH SIP published on March 12, 
2012, we disapproved the RPGs established by Arkansas for Caney Creek 
and Upper Buffalo because Arkansas did not establish the RPGs in 
accordance with the requirements of the CAA and the RHR.\113\ 
Specifically, Arkansas did not take into consideration the four RP 
factors in establishing its RPGs for Caney Creek and Upper Buffalo, 
stating that it was an unnecessary exercise. Arkansas believed, 
incorrectly, that no additional analysis of potential reasonable 
progress measures was necessary because visibility projections for the 
Class I areas indicated improvements in visibility consistent with the 
URP. As discussed in our disapproval action, a state must determine 
whether additional control measures are reasonable based on a 
consideration of the four RP factors. Accordingly, in this proposed 
rule, we are evaluating the four RP factors to determine whether 
additional controls are reasonable and we are establishing RPGs for 
Caney Creek and Upper Buffalo after consideration of the RP factors.
---------------------------------------------------------------------------

    \113\ 77 FR 14604, March 12, 2012.
---------------------------------------------------------------------------

A. Reasonable Progress Analysis of Point Sources

    A discussion of the particular pollutants that contribute to 
visibility impairment at Arkansas' two Class I areas was provided in 
our October 17, 2011 proposed action on the 2008 Arkansas RH SIP (see 
76 FR 64186). In that proposed action, we explained that CENRAP used 
CAMx with its Particulate Source Apportionment (PSAT) tool to provide 
source apportionment by geographic region and major source category 
(i.e., point, natural, on-road, non-road, and area sources). Sulfate 
from all the source categories combined contributed 87.05 inverse 
megameters (Mm-\-1\) out of 133.93 Mm-\1\ of 
light extinction at Caney Creek and 83.18 Mm-\1\ out of 
131.79 Mm-\1\ of light extinction at Upper Buffalo on the 
20% worst days in 2002, which is approximately 65% and 63% of the total 
light extinction at each Class I area, respectively. Nitrate from all 
source categories combined contributed 13.78 Mm-\1\ out of 
133.93 Mm-\1\ of light extinction at Caney Creek and 13.30 
Mm-\1\ out of 131.79 Mm-\1\ of light extinction 
at Upper Buffalo, which is approximately 10% of the total light 
extinction in 2002 on the 20% worst days at each Class I area. The 
source category point sources contributed 81.04 Mm-\1\ out 
of 133.93 Mm-\1\ of light extinction at Caney Creek and 
77.80 Mm-\1\ out of 131.79 Mm-\1\ of light 
extinction at Upper Buffalo on the 20% worst days in 2002 (see the 
tables below). This represents approximately 60% of the total light 
extinction at each Class I area. Each of the source categories other 
than the point source category, contribute a much smaller proportion of 
the total light extinction at each Class I area. We are therefore 
focusing only on the point sources category in our reasonable progress 
analysis for this regional haze planning period. Sulfate from point 
sources contributed 75.1 Mm-\1\ out of 133.93 
Mm-\1\ of light extinction at Caney Creek and 72.17 
Mm-\1\ out of 131.79 Mm-\1\ of light extinction 
at Upper Buffalo, which is approximately 56% of the total light 
extinction at Caney Creek and 55% of the total light extinction at 
Upper Buffalo. Nitrate from point sources contributed 4.06 
Mm-\1\ out of 133.93 Mm-\1\ of light extinction 
at Caney Creek and 3.93 Mm-\1\ out of 131.79 
Mm-\1\ of light extinction at Upper Buffalo, which is 
approximately 3% of the total light extinction at each Class I area. On 
the 20% worst days in 2002, sulfate from Arkansas point sources 
contributed 2.20% of the total light extinction at Caney Creek and 
1.99% at Upper Buffalo, and nitrate from Arkansas point sources 
contributed 0.27% of the total light extinction at Caney Creek and 
0.14% at Upper Buffalo.\114\ For both Caney Creek and Upper Buffalo, 
SO2 emissions (sulfate precursor) are the principal driver 
of regional haze on the 20% worst days in Arkansas' Class I areas, as 
visibility impairment in 2002 on the 20% worst days is largely due to 
sulfate from point sources.
---------------------------------------------------------------------------

    \114\ See the CENRAP TSD and the August 27, 2007 CENRAP PSAT 
tool (CENRAP_PSAT_Tool_ENVIRON_Aug27_2007.mdb). A copy of the CENRAP 
TSD and instructions for accessing the August 27, 2007 CENRAP PSAT 
tool can be found in the docket for this proposed rulemaking.

                      Table 55--Modeled Baseline Light Extinction for 20% Worst Days at Caney Creek Wilderness Area in 2002 (Mm-1)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                             Total \1\         Point          Natural         On-road        Non-road          Area
--------------------------------------------------------------------------------------------------------------------------------------------------------
SO4.....................................................           87.05           75.10            0.09            1.19            1.70            5.66
NO3.....................................................           13.78            4.06            0.64            4.70            2.45            1.37
POA.....................................................           10.50            1.29            1.33            0.46            1.34            5.32
EC......................................................            4.80            0.19            0.33            0.86            1.79            1.40
SOIL....................................................            1.12            0.19            0.01            0.01            0.01            0.87
CM......................................................            3.73            0.21            0.04            0.03            0.02            3.19
                                                         -----------------------------------------------------------------------------------------------

[[Page 18990]]

 
Sum.....................................................          133.93           81.04            2.45            7.26            7.31           17.81
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\Totals include contributions from boundary conditions. Sums include secondary organic matter.


                           Table 56--Modeled Baseline Light Extinction for 20% at Upper Buffalo Wilderness Area in 2002 (Mm-1)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                             Total \1\         Point          Natural         On-road        Non-road          Area
--------------------------------------------------------------------------------------------------------------------------------------------------------
SO4.....................................................           83.18           72.17            0.08            1.15            1.67            5.24
NO3.....................................................           13.30            3.93            0.61            4.14            2.71            1.23
POA.....................................................           10.85            1.06            1.33            0.47            1.38            5.75
EC......................................................            4.72            0.16            0.31            0.80            1.93            1.30
SOIL....................................................            1.21            0.20            0.02            0.01            0.01            0.93
CM......................................................            6.85            0.29            0.05            0.05            0.02            6.02
                                                         -----------------------------------------------------------------------------------------------
Sum.....................................................          131.79           77.80            2.39            6.62            7.72           20.46
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\Totals include contributions from boundary conditions. Sums include secondary organic matter.

    The CENRAP's 2018 visibility projections show the total extinction 
at Caney Creek for the 20% worst days is estimated to be 85.84 Mm-1, 
which is a reduction of approximately 36% from 2002 levels (see table 
below). The total extinction at Upper Buffalo for the 20% worst days in 
2018 is estimated to be 86.16 Mm-1, which is a reduction of 
approximately 35% from 2002 levels (see the table below).Sulfate from 
all source categories combined is projected to contribute 48.95 
Mm-1 out of 85.84 Mm-1 of light extinction at 
Caney Creek on the 20% worst days in 2018, or approximately 57% of the 
total light extinction. Nitrate from all source categories combined is 
projected to contribute 7.57 Mm-1 out of 85.84 
Mm-1 of light extinction at Caney Creek on the 20% worst 
days in 2018, or approximately 9% of the total light extinction. The 
other source categories are each projected to continue contributing a 
much smaller proportion of the total light extinction at each Class I 
area. At Upper Buffalo, sulfate from all source categories combined is 
projected to contribute 45.38 Mm-1 out of 86.16 
Mm-1 of light extinction on the 20% worst days in 2018, 
which is approximately 53% of the total light extinction. Nitrate from 
all source categories combined is projected to contribute 9.22 
Mm-1 out of 86.16 Mm-1 of light extinction on the 
20% worst days at Upper Buffalo, which is approximately 11% of the 
total light extinction. Sulfate from point sources is projected to 
contribute 39.83 Mm-1 out of 85.84 Mm-1 of light 
extinction at Caney Creek on the 20% worst days in 2018, or 
approximately 46% of the total light extinction. Nitrate from point 
sources is projected to contribute 2.84 Mm-1 out of 85.84 
Mm-1 of light extinction at Caney Creek on the 20% worst 
days, which is approximately 3% of the total light extinction. At Upper 
Buffalo, sulfate from point sources is projected to contribute 37.09 
Mm-1 out of 86.16 Mm-1 of light extinction on the 
20% worst days in 2018, which is approximately 43% of the total light 
extinction. On the 20% worst days in 2018, sulfate from Arkansas point 
sources is projected to contribute 3.58% of the total light extinction 
at Caney Creek and 3.20% at Upper Buffalo, and nitrate from Arkansas 
point sources is projected to contribute 0.29% of the total light 
extinction at Caney Creek and 0.25% at Upper Buffalo.\115\ Based on the 
2018 visibility projections, sulfate from point sources is expected to 
continue being the principal driver of regional haze on the 20% worst 
days at Arkansas Class I areas.
---------------------------------------------------------------------------

    \115\ See the CENRAP TSD and the August 27, 2007 CENRAP PSAT 
tool (CENRAP_PSAT_Tool_ENVIRON_Aug27_2007.mdb). A copy of the CENRAP 
TSD and instructions for accessing the August 27, 2007 CENRAP PSAT 
tool can be found in the docket for this proposed rulemaking.

                       Table 57--Modeled Future Light Extinction for 20% Worst Days at Caney Creek Wilderness Area in 2018 (Mm-1)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                             Total \1\         Point          Natural         On-road        Non-road          Area
--------------------------------------------------------------------------------------------------------------------------------------------------------
SO4.....................................................           48.95           39.83            0.07            0.12            0.44            5.31
NO3.....................................................            7.57            2.84            0.53            0.97            1.33            1.37
POA.....................................................            9.93            1.76            1.18            0.14            1.03            5.09
EC......................................................            3.17            0.24            0.30            0.16            0.94            1.31
SOIL....................................................            1.29            0.35            0.01            0.01            0.01            0.87
CM......................................................            3.58            0.24            0.04            0.03            0.01            3.02
                                                         -----------------------------------------------------------------------------------------------
Sum.....................................................           85.84           45.27            2.12            1.44            3.76           16.96
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\Totals include contributions from boundary conditions and secondary organic matter.


[[Page 18991]]


                      Table 58--Modeled Future Light Extinction for 20% Worst Days at Upper Buffalo Wilderness Area in 2018 (Mm-1)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                             Total \1\         Point          Natural         On-road        Non-road          Area
--------------------------------------------------------------------------------------------------------------------------------------------------------
SO4.....................................................           45.38           37.09            0.06            0.12            0.42            4.95
NO3.....................................................            9.22            3.48            0.63            1.10            1.81            1.48
POA.....................................................           10.17            1.48            1.20            0.14            1.01            5.49
EC......................................................            3.07            0.21            0.28            0.15            0.99            1.21
SOIL....................................................            1.40            0.40            0.01            0.01            0.01            0.93
CM......................................................            6.53            0.36            0.05            0.04            0.02            5.65
Sum.....................................................           86.16           43.02            2.24            1.57            4.25           19.71
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Totals include contributions from boundary conditions and secondary organic matter.

    As a starting point in our analysis to determine whether additional 
controls on Arkansas sources are reasonable in the first regional haze 
planning period, we examined the most recent SO2 and 
NOX emissions inventories for point sources in Arkansas. 
Based on the 2011 National Emissions Inventory (NEI), the Entergy White 
Bluff Plant, the Entergy Independence Plant, and the AEP Flint Creek 
Power Plant are the three largest point sources of SO2 and 
NOx emissions in Arkansas (see table below).\116\ The combined annual 
emissions from these three sources make up approximately 84% of the 
statewide SO2 point-source emissions and 55% of the 
statewide NOX point-source emissions. We have evaluated 
White Bluff Units 1 and 2 and Flint Creek Unit 1 for controls under 
BART and are proposing to require these units to install SO2 
and NOX controls to meet the BART requirements. We believe 
that our five-factor BART analysis for these three units is adequate 
for this first planning period to eliminate these sources from further 
consideration of controls under the reasonable progress requirements 
for this first regional haze planning period. Compliance with the BART 
requirements is anticipated to result in a substantial reduction in 
SO2 and NOX emissions from these two facilities. 
The Entergy Independence Plant is not subject to BART, but its 
emissions were 30,398 SO2 tpy and 13,411 NOX tpy 
based on the 2011 NEI. The Entergy Independence Plant is the second 
largest source of SO2 and NOX point-source 
emissions in Arkansas, accounting for approximately 36% of the 
SO2 point-source emissions and 21% of the NOX 
point-source emissions in the State. Additionally, as we discuss in 
more detail in the proceeding subsection, the White Bluff and 
Independence Plants are sister facilities with nearly identical units. 
Based on this, we expect that the cost-effectiveness of controls will 
be very similar for the two facilities.
---------------------------------------------------------------------------

    \116\ See NEI 2011 v1. A spreadsheet containing the emissions 
inventory is found in the docket for our proposed rulemaking.

                    Table 59--Ten Largest SO2 and NOX Point Sources in Arkansas (NEI 2011 v1)
----------------------------------------------------------------------------------------------------------------
                                                                                    NEI 2011 v1 Emissions (tpy)
                 Facility name                               County              -------------------------------
                                                                                        SO2             NOX
----------------------------------------------------------------------------------------------------------------
Entergy Arkansas--White Bluff.................  Jefferson.......................        * 31,684        * 16,013
Entergy-Services Inc--Independence Plant......  Independence....................          30,398          13,411
Flint Creek Power Plant (SWEPCO)..............  Benton..........................         * 8,620         * 5,326
FutureFuel Chemical Company...................  Independence....................           3,421             385
Plum Point Energy Station Unit 1..............  Mississippi.....................           2,830           1,525
Evergreen Packaging--Pine Bluff...............  Jefferson.......................           1,755           1,010
Domtar A.W. LLC, Ashdown Mill.................  Little River....................         * 1,603         * 3,152
Albemarle Corporation--South Plant............  Columbia........................           1,279             443
Nucor-Yamato Steel Company....................  Mississippi.....................             607             263
Ash Grove Cement Company......................  Little River....................             440           1,081
Georgia-Pacific LLC--Crossett Paper...........  Ashley..........................             215           2,402
Marion Intermodal.............................  Crittenden......................              12           1,328
Natural Gas Pipeline Co of America #308.......  Randolph........................             0.4           3,194
Natural Gas Pipeline Co of America #307.......  White...........................             0.4           2,941
Natural Gas Pipeline Co of America #305.......  Miller..........................             0.3           1,731
----------------------------------------------------------------------------------------------------------------
* Proposed FIP controls under BART requirements will result in emission reductions.

    Because in our March 12, 2012 final partial approval and partial 
disapproval of the 2008 Arkansas RH SIP we made a finding that Arkansas 
did not complete a reasonable progress analysis and did not properly 
demonstrate that additional controls were not reasonable under 40 CFR 
51.308(d)(1)(i)(A) and we disapproved the RPGs it established for Caney 
Creek and Upper Buffalo, we are required to complete the reasonable 
progress analysis and establish revised RPGs, unless we first approve a 
SIP revision that corrects the disapproved portions of the SIP 
submittal. As Arkansas has not as yet submitted a revised SIP following 
our partial disapproval, we must now complete the reasonable progress 
analysis and establish revised RPGs for Caney Creek and Upper Buffalo. 
We believe it is appropriate that our evaluation of the reasonable 
progress factors focuses on the Entergy Independence Power Plant

[[Page 18992]]

because it is a significant source of SO2 and 
NOX, as it is the second largest point source for both 
NOX and SO2 point source emissions in the State.
    We believe it is appropriate to evaluate Entergy Independence even 
though Arkansas Class I areas and those outside of Arkansas most 
significantly impacted by Arkansas sources are projected to meet the 
URP for the first planning period. This is because we believe that in 
determining whether reasonable progress is being achieved, it would be 
unreasonable to ignore a source representing more than a third of the 
State's SO2 emissions and a significant portion of 
NOX point source emissions. The preamble to the Regional 
Haze Rule also states that the URP does not establish a ``safe harbor'' 
for the state in setting its progress goals.\117\ If the state 
determines that the amount of progress identified through the URP 
analysis is reasonable based upon the statutory factors, the state, or 
us in the case of a FIP, should identify this amount of progress as its 
reasonable progress goal for the first long-term strategy, unless it 
determines that additional progress beyond this amount is also 
reasonable. If the state or we determine that additional progress is 
reasonable based on the statutory factors, that amount of progress 
should be adopted as the goal for the first long-term strategy.
---------------------------------------------------------------------------

    \117\ See 64 FR 35732.
---------------------------------------------------------------------------

    In this proposed rulemaking, we are proposing controls for the 
largest and third largest point sources for both NOX and 
SO2 emissions in Arkansas under the BART requirements. As 
these two BART sources combined with Independence make up a large 
majority of the SO2 point source emissions (84%) and a large 
proportion of the NOX point source emissions (55%) in 
Arkansas, we believe that a sufficient amount of point source emissions 
in the State would be addressed in this first regional haze planning 
period by addressing the Independence facility in our reasonable 
progress analysis, which as we note above is the second largest source 
of both SO2 and NOX. We are proposing under 
Option 1 to control Entergy Independence for the first planning period 
for both SO2 and NOX. Alternatively, under Option 
2, for the first planning period, we are proposing to control Entergy 
Independence only for SO2. The fourth largest SO2 
and NOX point sources in Arkansas are the Future Fuel 
Chemical Company, with emissions of 3,421 SO2 tpy, and the 
Natural Gas Pipeline Company of America #308, with emissions of 3,194 
NOX tpy (2011 NEI). In comparison to the emissions of the 
top three sources, emissions from these two facilities are relatively 
small. Therefore, we are not proposing controls in this first planning 
period for these two facilities because we believe it is appropriate to 
defer the consideration of any additional sources besides Independence 
to future regional haze planning periods. For Independence, however, 
under Option 1, in combination with the BART sources we would be 
addressing 84% of the SO2 point source emissions in the 
State and over 55% of the NOX point source emissions. Under 
Option 2, we would be deferring the consideration of additional 
NOX controls to future regional haze planning periods. In 
the next section, we describe our consideration of the four reasonable 
progress factors for the Entergy Independence Plant as well as the 
CALPUFF modeling we conducted to assess the potential visibility 
benefits of controls.\118\
---------------------------------------------------------------------------

    \118\ While visibility is not an explicitly listed factor to 
consider when determining whether additional controls are 
reasonable, the purpose of the four-factor analysis is to determine 
what degree of progress toward natural visibility conditions is 
reasonable. Therefore, it is appropriate to consider the projected 
visibility benefit of the controls when determining if the controls 
are needed to make reasonable progress.
---------------------------------------------------------------------------

1. Entergy Independence Plant Units 1 and 2
    a. Reasonable Progress Analysis for SO2 Controls--Costs of 
Compliance: The Entergy Independence Plant is an electric generating 
station with two nearly identical coal-fired units (Units 1 and 2) with 
a nameplate capacity of 900 MW each. Units 1 and 2 are tangentially-
fired boilers that burn sub-bituminous coal as their primary fuel and 
No. 2 fuel oil or Bio-diesel as the start-up fuel. To verify that the 
White Bluff and Independence Plants are sister facilities, we have 
constructed a master spreadsheet \119\ that contains information 
concerning ownership, location, boiler type, environmental controls and 
other pertinent information on these facilities. The spreadsheet 
includes information contained within EIA Forms 860 and 923. According 
to EIA,\120\ the boilers were manufactured by Combustion Engineering 
with installation dates of 1974 for White Bluff, and 1983 and 1984 for 
Independence. The two units at White Bluff and the two units at 
Independence are tangentially firing boilers having nameplate 
capacities of 900 MW and similar gross ratings. All four units burn 
coal from the Powder River Basin (PRB) of Wyoming with similar 
characteristics. All four units employ cold side ESPs for particulate 
collection. Other pertinent characteristics are similar. The layout of 
the White Bluff and Independence facilities are also very similar.\121\ 
Due to the similarity of these facilities, we applied the total 
annualized dry FGD and wet FGD costs we developed for the White Bluff 
units to the Independence units. However, we adjusted the cost-
effectiveness ($/ton) due to the differing baseline SO2 
emissions from the units.
---------------------------------------------------------------------------

    \119\ This spreadsheet, entitled ``EIA Consolidated Data_WB and 
Ind_Y2012.xlsx,'' is located in the docket for our proposed 
rulemaking.
    \120\ See ``EIA Consolidated Data_WB and IND_Y2012.xlsx.''
    \121\ See ``Technical Support Document for the SDA Control Cost 
Analysis for the Entergy White Bluff and Independence Facilities 
Arkansas Regional Haze Federal Implementation Plan (SO2 
Cost TSD),'' Figures 1 and 2.
---------------------------------------------------------------------------

    Consistent with the cost estimate we developed for White Bluff, we 
estimated a total annual cost for dry FGD at Independence of 
approximately $31,981,230 at each unit.\122\ We expect dry FGD to 
achieve a controlled emission level of 0.06 lb/MMBtu, and estimate that 
the annual emissions reductions at Unit 1 would be 12,912 
SO2 tpy, assuming baseline emissions \123\ of 14,269 
SO2 tpy (see table below). The average cost-effectiveness of 
dry FGD at Unit 1 is estimated to be $2,477 per SO2 ton 
removed. For Unit 2, we estimate that the annual emissions reductions 
would be 13,990 SO2 tpy, assuming baseline emissions of 
15,511 SO2 tpy. The average cost-effectiveness of dry FGD at 
Unit 2 is estimated to be $2,286 per SO2 ton removed.
---------------------------------------------------------------------------

    \122\ See ``Technical Support Document for the SDA Control Cost 
Analysis for the Entergy White Bluff and Independence Facilities 
Arkansas Regional Haze Federal Implementation Plan (SO2 
Cost TSD).'' A copy of this TSD is found in the docket for our 
proposed rulemaking.
    \123\ Baseline emissions were determined by examining annual 
SO2 emissions for the years 2009-2013, eliminating the 
year with the highest emissions and the year with the lowest 
emissions, and obtaining the average of the three remaining years.

[[Page 18993]]



                                        Table 60--Summary of Dry FGD Costs for Entergy Independence Units 1 and 2
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                  Controlled      Annual emissions                        Average cost
                           Unit                            Baseline emission    emission level    reductions (SO2   Total annual cost  effectiveness ($/
                                                             rate (SO2 tpy)       (lb/MMBtu)            tpy)              ($/yr)              ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Unit 1...................................................             14,269               0.06             12,912        $31,981,230             $2,477
Unit 2...................................................             15,511               0.06             13,990         31,981,230              2,286
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Because our proposed BART determination for the White Bluff 
facility is that dry FGD is more cost-effective (lower $/ton) than wet 
FGD, and that the additional visibility benefits obtained as a result 
of the greater level of control wet FGD offers over dry FGD are not 
worth the additional cost of wet FGD, we expect that the same would 
apply to Independence Units 1 and 2. Therefore, our evaluation of 
SO2 controls for Independence Units 1 and 2 focuses on dry 
FGD. Nevertheless, we have calculated the cost-effectiveness of wet FGD 
for Independence Units 1 and 2 using the total annualized cost estimate 
provided by Entergy for White Bluff Units 1 and 2, with certain 
adjustments we made to the cost estimate provided by the facility.\124\ 
Consistent with our estimate for White Bluff, we estimated a total 
annual cost for wet FGD at Independence of approximately $49,526,167 at 
each unit.\125\ We expect wet FGD to achieve a controlled emission 
level of 0.04 lb/MMBtu, and estimate that the annual emissions 
reductions at Unit 1 would be 13,364 SO2 tpy, assuming 
baseline emissions \126\ of 14,269 SO2 tpy (see table 
below). The average cost-effectiveness of wet FGD at Unit 1 is 
estimated to be $3,706 per SO2 ton removed. For Unit 2, we 
estimate that the annual emissions reductions would be 14,497 
SO2 tpy, assuming baseline emissions of 15,511 
SO2 tpy. The average cost-effectiveness of wet FGD at Unit 2 
is estimated to be $3,416 per SO2 ton removed.
---------------------------------------------------------------------------

    \124\ See our discussion above of the cost analysis for 
SO2 BART for White Bluff Units 1 and 2, under section 
III.C.4 of this proposed rulemaking.
    \125\ See our Cost Analysis TSD titled ``Technical Support 
Document for the SDA Control Cost Analysis for the Entergy White 
Bluff and Independence Facilities Arkansas Regional Haze Federal 
Implementation Plan (SO2 Cost TSD).'' The TSD is found in 
the docket for our proposed rulemaking.
    \126\ Baseline emissions were determined by examining annual 
SO2 emissions for the years 2009-2013, eliminating the 
year with the highest emissions and the year with the lowest 
emissions, and obtaining the average of the three remaining years.

                                        Table 61--Summary of Wet FGD Costs for Entergy Independence Units 1 and 2
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                  Controlled      Annual emissions                        Average cost
                           Unit                            Baseline emission    emission level    reductions (SO2   Total annual cost  effectiveness ($/
                                                             rate (SO2 tpy)       (lb/MMBtu)            tpy)              ($/yr)              ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Unit 1...................................................             14,269               0.04             13,463        $49,526,167             $3,706
Unit 2...................................................             15,511               0.04             14,532         49,526,167              3,416
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Time Necessary for Compliance: As is generally the case for 
installation of scrubber controls on EGUs, we expect that 5 years from 
the date of our final action would be sufficient time for Independence 
to install and operate either dry or wet FGD controls at Units 1 and 2 
and to comply with the associated emission limits.
    Energy and Non-Air Quality Environmental Impacts of Compliance: The 
installation and operation of wet FGD at Independence Units 1 and 2 
would require greater energy usage and reagent usage compared to dry 
FGD. The cost of this additional energy usage and reagent usage has 
already been factored into the cost analysis. Non-air quality 
environmental impacts associated with wet FGD systems include increased 
water usage and the generation of large volumes of wastewater and solid 
waste/sludge that must be treated or stabilized before landfilling. 
Because the facility is not located in an exceptionally arid region, we 
do not anticipate that there would be water-availability issues that 
would affect the feasibility of wet FGD. Lastly, wet FGD systems have 
the potential for increased particulate and sulfuric acid mist releases 
that contribute to regional haze, which we are taking into 
consideration through an evaluation of the visibility benefits of each 
control option.
    Remaining Useful Life: Independence Units 1 and 2 were installed in 
1983 and 1984. Unit 1 was placed into operation in 1983 and Unit 2 was 
placed into operation in 1985. As there is no enforceable shut-down 
date for Units 1 and 2, we assume an equipment life of 30 years.\127\
---------------------------------------------------------------------------

    \127\ As we note in our Oklahoma FIP, we typically assume a 30 
year equipment life for scrubbers, as we do here. Please see 
Response to Technical Comments for Sections E. through H. of the 
Federal Register Notice for the Oklahoma Regional Haze and 
Visibility Transport Federal Implementation Plan, Docket No. EPA-
R06-OAR-2010-0190. Page 35.
---------------------------------------------------------------------------

    Degree of Improvement in Visibility: While visibility is not an 
explicitly listed factor to consider when determining whether 
additional controls are reasonable under the reasonable progress 
requirements, the purpose of the four-factor analysis is to determine 
what degree of progress toward natural visibility conditions is 
reasonable. Therefore, it is appropriate to consider the projected 
visibility benefit of the controls when determining if the controls are 
needed to make reasonable progress.\128\ There are four Class I areas 
within 300 km of the Entergy Independence Plant. We conducted CALPUFF 
modeling to determine the visibility improvement of SO2 
controls at these Class I areas, based on the 98th percentile 
visibility impacts.\129\ As shown in the tables below, both dry FGD and 
wet FGD are projected to result in considerable visibility improvement 
from the baseline at each modeled Class I area. For Unit 1, dry FGD is 
projected to result in almost 0.5 dv of visibility improvement at each 
modeled Class I area, and for Unit 2 it is projected to result in 
almost or slightly greater than

[[Page 18994]]

0.5 dv of visibility improvement at each Class I area. The incremental 
visibility improvement of wet FGD over dry FGD is projected to be 
minimal, ranging from 0.008-0.028 dv at each Class I area for Unit 1 
and 0.009-0.022 dv for Unit 2.
---------------------------------------------------------------------------

    \128\ See 79 FR at 74838, 74840, and 74874.
    \129\ See Appendix C to the TSD, titled ``Technical Support 
Document for Visibility Modeling Analysis for Entergy Independence 
Generating Station,'' for a detailed discussion of the visibility 
modeling protocol and model inputs. A copy of the TSD and its 
appendices is found in the docket for this proposed rulemaking.

                          Table 62--Entergy Independence Unit 1: EPA Modeled 98th Percentile Visibility Impacts of SO2 Controls
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Visibility impact ([Delta]dv)       Visibility improvement   Incremental
                                                                           ---------------------------------------    over baseline (dv)      visibility
                         Class I area                            Distance                                         -------------------------- improvement
                                                                   (km)       Baseline     Dry FGD      Wet FGD                               of wet FGD
                                                                                                                     Dry FGD      Wet FGD    vs. dry FGD
--------------------------------------------------------------------------------------------------------------------------------------------------------
Caney Creek..................................................          277        1.133        0.657         0.64        0.476        0.493        0.017
Upper Buffalo................................................          180        0.845        0.385        0.377        0.460        0.468        0.008
Hercules-Glades..............................................          173        0.793        0.295        0.267        0.498        0.526        0.028
Mingo........................................................          174        0.739        0.298        0.284        0.441        0.455        0.014
                                                              ------------------------------------------------------------------------------------------
    Total....................................................  ...........         3.51        1.635        1.568        1.875        1.942        0.067
--------------------------------------------------------------------------------------------------------------------------------------------------------


                          Table 63--Entergy Independence Unit 2: EPA Modeled 98th Percentile Visibility Impacts of SO2 Controls
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Visibility impact ([Delta]dv)       Visibility improvement   Incremental
                                                                           ---------------------------------------    over baseline (dv)      visibility
                         Class I area                            Distance                                         -------------------------- improvement
                                                                   (km)       Baseline     Dry FGD      Wet FGD                               of wet FGD
                                                                                                                     Dry FGD      Wet FGD    vs. dry FGD
--------------------------------------------------------------------------------------------------------------------------------------------------------
Caney Creek..................................................          277        1.412        0.865        0.843        0.547        0.569        0.022
Upper Buffalo................................................          180        0.997        0.509        0.499        0.488        0.498         0.01
Hercules-Glades..............................................          173        0.977        0.364        0.355        0.613        0.622        0.009
Mingo........................................................          174        0.883        0.388        0.374        0.495        0.509        0.014
                                                              ------------------------------------------------------------------------------------------
    Total....................................................  ...........        4.269        2.126        2.071        2.143        2.198        0.055
--------------------------------------------------------------------------------------------------------------------------------------------------------


                     Table 64--Entergy Independence: EPA Modeled 98th Percentile Visibility Impacts of SO2 Controls (Facility-wide)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Visibility impact ([Delta]dv)       Visibility improvement   Incremental
                                                                           ---------------------------------------    over baseline (dv)      visibility
                         Class I area                            Distance                                         -------------------------- improvement
                                                                   (km)       Baseline     Dry FGD      Wet FGD                               of wet FGD
                                                                                                                     Dry FGD      Wet FGD    vs. dry FGD
--------------------------------------------------------------------------------------------------------------------------------------------------------
Caney Creek..................................................          277        2.412        1.474        1.442        0.938         0.97        0.032
Upper Buffalo................................................          180        1.764        0.876         0.86        0.888        0.904        0.016
Hercules-Glades..............................................          173        1.704        0.648        0.608        1.056        1.096         0.04
Mingo........................................................          174        1.547        0.676        0.649        0.871        0.898        0.027
                                                              ------------------------------------------------------------------------------------------
    Total....................................................  ...........        7.427        3.674        3.559        3.753        3.868        0.115
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Proposed RP Determination for SO2: Based on our analysis 
of the four RP factors, as well as the considerable projected 
visibility improvement, we propose to require compliance with an 
emission limit of 0.06 lb/MMBtu for Independence Units 1 and 2 based on 
a 30 boiler-operating-day rolling average basis. We propose to find 
that this emission limit, which is based on the installation and 
operation of dry FGD, is cost-effective at $2,477 per SO2 
ton removed for Unit 1 and $2,286 per SO2 ton removed for 
Unit 2, and would result in significant visibility benefits at the 
Caney Creek and Upper Buffalo Wilderness Areas and the two Class I 
areas in Missouri. Under either Option 1 or 2, we are proposing 
SO2 controls on Independence Units 1 and 2 for the first 
planning period. We note that more recent emission data show an overall 
increase in SO2 emissions from the facility. Therefore 
anticipated visibility improvement from controls would be anticipated 
to be larger and the $/SO2 ton reduced would be smaller had 
we used a more recent time period for the baseline emissions modeled. 
We found that in this instance, the cost of wet FGD on a dollars per 
ton removed basis is higher than that of dry FGD. We found the cost of 
wet FGD to be $3,706 and $3,416 per ton of SO2 removed at 
Units 1 and 2, respectively. We found the cost of dry FGD to be $2,477 
and $2,286 per ton of SO2 removed for Units 1 and 2, 
respectively. We do not believe that the minimal amount of incremental 
visibility improvement projected to result from wet FGD justifies the 
higher cost compared to dry FGD. We are proposing to require compliance 
with an emission limit of 0.06 lb/MMBtu based on a 30 boiler-operating-
day rolling average basis for Independence Units 1 and 2 no later than 
5 years from the effective date of the final rule, based on the 
installation and operation of dry FGD. We are proposing that the 
facility demonstrate compliance with this emission limit using the 
existing CEMS. We are also proposing regulatory text that includes 
monitoring, reporting, and recordkeeping requirements associated with 
this emission limit.
    b. Reasonable Progress Analysis for NOX controls. As 
noted previously, monitoring data as well as CENRAP's CAMx source 
apportionment modeling results for 2002 and 2018 show that visibility 
impairment is not projected to be significantly impacted by nitrate on 
the 20% worst days at Caney Creek or Upper Buffalo. Point source 
emissions of NOX are projected to contribute to

[[Page 18995]]

less than 5% of the total impairment on the 20% worst days in both 2002 
and 2018. The CENRAP CAMx source apportionment modeling does not 
provide visibility impairment estimates for individual facilities.
    As part of our analysis for Independence, we performed modeling 
using CALPUFF to assess the facility's individual visibility impact and 
the visibility benefit of controls, as was done for the subject-to-BART 
units discussed above including the sister facility, White Bluff. 
CALPUFF is the recommended model \130\ for visibility impact analysis 
for BART determinations and other single source visibility modeling 
where the Class I areas of interest are within 300 km of the source. 
This modeling provided information on the total visibility impairment 
from emissions from the source, including impacts from SO2 
and NOX emissions. The primary goal of this modeling was to 
assess the potential visibility benefit of SO2 controls, 
given the relatively large emissions of SO2 from the 
facility and that SO2 emissions are the primary cause of 
visibility impairment on the 20% worst days at the Class I areas of 
interest. The results of this analysis of SO2 controls are 
discussed in the section above. These CALPUFF results also indicated 
that impacts from NOX emissions can be significant on some 
days, and as discussed further below, NOX emission controls 
can be anticipated to result in a sizeable reduction in the maximum 
impacts from the facility. The analysis of the sister facility, Entergy 
Independence, revealed similar results.
---------------------------------------------------------------------------

    \130\ 70 FR 39104.
---------------------------------------------------------------------------

    In evaluating CALPUFF modeling results for BART, the 98th 
percentile ranked impact (H8H) was used consistent with our guideline 
techniques in conducting the CALPUFF modeling. CALPUFF modeling 
provides an assessment of the near maximum (98th percentile) visibility 
impairment on nearby Class I areas from the source of interest based on 
the facility's maximum short term emissions modeled over a three year 
period. It is important to note that a specific facility's maximum 
impact on a Class I area may not correlate with the same meteorological 
conditions or days when visibility is most impaired at a particular 
Class I area since CALPUFF modeling is only for one facility and does 
not include other facilities and emissions sources. Because of the 
nature of visibility impairment, we consider it appropriate to assess 
visibility impacts from a single source against a natural background. 
Visibility impairment on the 20% worst days may be driven by impacts 
from other facilities and different meteorological conditions. 
Identification of the 20% worst days is determined by IMPROVE monitor 
data during the baseline period at each Class I area. The source 
apportionment results for the 20% worst days are then based on CAMx 
modeling using a single year of meteorological data (2002) and using 
estimates of actual emissions from 2002 and projected to 2018 for all 
emission sources in the modeling domain (continental U.S.). Due in 
large part to the difference in metrics between the maximum impact as 
modeled by CALPUFF and the average impact during the 20% worst days, 
the CALPUFF modeling results discussed below indicate a more 
significant impact than suggested by the source apportionment CAMx 
results. We also note that differences in the metrics examined (maximum 
98th percentile impact versus average impact during the 20% worst 
days), emissions modeled (single-source maximum 24-hour actual 
emissions versus actual emissions from all emission sources \131\), and 
differences in chemistry models result in CAMx visibility analysis 
results for a source or group of sources being much lower in magnitude 
than visibility impacts as modeled by CALPUFF.
---------------------------------------------------------------------------

    \131\ Emissions used in CALPUFF modeling represented the maximum 
24-hour emission rate. Based on evaluation of some sources that had 
both annual and maximum 24-hour actual data, EPA recommended that 
sources could use an emission rate that was double the annual 
emission rate (used in CAMx) to approximate the maximum 24-hour 
actual emission rates for some sources for CALPUFF modeling when 
there was not enough data to generate a maximum 24-hr actual 
emission rate.
---------------------------------------------------------------------------

    The single source CALPUFF modeling shows that sizeable reductions 
to the maximum 98th percentile visibility impact from the Independence 
facility may be achieved through NOX controls. We recognize, 
however, that at this time, point source NOX emissions are 
not the main contributors to visibility impairment on the 20% worst 
days at Arkansas' Class I areas, as projected by CAMx source 
apportionment modeling. Also, Arkansas Class I areas are projected to 
achieve progress greater than that needed to meet the URP. Because our 
assessment of the Independence facility indicates that it is 
potentially one of the largest single contributors to visibility 
impairment at Class I areas in Arkansas, we believe that it is 
appropriate to evaluate the appropriateness of NOX controls 
during this planning period.
    As discussed above, due to the similarity of these facilities, we 
applied the total annualized LNB/SOFA cost developed by Entergy for 
White Bluff Units 1 and 2, with one line item revision made by us, to 
Independence Units 1 and 2.\132\ However, we adjusted the cost-
effectiveness ($/ton) due to the differing NOX emissions 
from the units. Since our proposed BART determination for the White 
Bluff facility is that LNB/SOFA is more cost effective (lower $/ton) 
than SNCR or SCR, and that the additional visibility benefits obtained 
as a result of the greater level of control SNCR and SCR offer over 
combustion controls are not worth the additional cost of SNCR or SCR, 
we expect that the same would apply to Independence Units 1 and 2. 
Therefore, our evaluation of NOX controls for Independence 
Units 1 and 2 will focus solely on LNB/SOFA.
---------------------------------------------------------------------------

    \132\ See our discussion above of the cost analysis for 
NOX BART for White Bluff Units 1 and 2, under section 
III.C.4 of this proposed rulemaking.
---------------------------------------------------------------------------

    Consistent with the cost estimate developed for White Bluff, we 
estimated a total annual cost for LNB/SOFA at Independence of 
approximately $1,085,904 at Unit 1 and $1,403,376 at Unit 2.\133\ We 
expect LNB/SOFA to achieve a controlled emission level of 0.15 lb/
MMBtu, and estimate that the annual emissions reductions at Unit 1 
would be 2,710 NOX tpy, assuming baseline emissions \134\ of 
6,329 NOX tpy (see table below). The average cost-
effectiveness of LNB/SOFA at Unit 1 is estimated to be $401 per 
NOX ton removed. For Unit 2, we estimate that the annual 
emissions reductions would be 3,217 NOX tpy, assuming 
baseline emissions of 6,384 NOX tpy. The average cost-
effectiveness of LNB/SOFA at Unit 2 is estimated to be $436 per 
NOX ton removed.
---------------------------------------------------------------------------

    \133\ See the spreadsheet titled ``Independence Cost 
Spreadsheet_LNB-SOFA.'' A copy of this spreadsheet is found in the 
docket for our proposed rulemaking.
    \134\ Baseline emissions were determined by examining annual 
NOX emissions for the years 2009-2013, eliminating the 
year with the highest emissions and the year with the lowest 
emissions, and obtaining the average of the three remaining years.

[[Page 18996]]



                                       Table 65--Summary of LNB/SOFA Costs for Entergy Independence Units 1 and 2
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                  Controlled      Annual emissions                        Average cost
                           Unit                            Baseline emission    emission level    reductions (NOX   Total annual cost  effectiveness ($/
                                                             rate (NOX tpy)       (lb/MMBtu)            tpy)              ($/yr)              ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Unit 1                                                                 6,329               0.15              2,710         $1,085,904               $401
Unit 2                                                                 6,384               0.15              3,217          1,403,376                436
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Time Necessary for Compliance: As is generally the case for 
installation of NOX controls on EGUs, we expect that 3 years 
from the date of our final action would be sufficient time for 
Independence to install and operate LNB/SOFA controls at Units 1 and 2 
and to comply with the associated emission limits.
    Energy and Non-Air Quality Environmental Impacts of Compliance: We 
are not aware of any energy or non-air quality environmental impacts 
that would preclude LNB/SOFA from consideration at Independence Units 1 
and 2.
    Remaining Useful Life: Independence Units 1 and 2 were installed in 
1983 and 1984. Unit 1 was placed into operation in 1983 and Unit 2 was 
placed into operation in 1985. As there is no enforceable shut-down 
date for Units 1 and 2, we presume that the units would continue to 
operate for greater than 30 years and fully amortize the cost of 
controls. In our analysis of the cost of controls we have assumed an 
equipment life of 30 years.
    Degree of Improvement in Visibility: While visibility is not an 
explicitly listed factor to consider when determining whether 
additional controls are reasonable under the reasonable progress 
requirements, the purpose of the four-factor analysis is to determine 
what degree of progress toward natural visibility conditions is 
reasonable. Therefore, it is appropriate to consider the projected 
visibility benefit of the controls when determining if the controls are 
needed to make reasonable progress.\135\ There are four Class I areas 
within 300 km of the Entergy Independence Plant. We conducted CALPUFF 
modeling to determine the visibility improvement of NOX 
controls at these Class I areas, based on the 98th percentile 
visibility impacts.\136\ As shown in the table below, LNB/SOFA is 
projected to result in a visibility improvement from the baseline at 
each modeled Class I area.\137\ On a facility-wide basis, the 
installation and operation of LNB/SOFA on Units 1 and 2 is projected to 
result in 0.461 dv in visibility improvement at Caney Creek, while the 
projected visibility improvement at each of the other modeled Class I 
areas ranges from 0.213-0.264 dv. We also conducted a modeling run of 
both LNB/OFA and dry FGD, which shows projected visibility benefits 
ranging from 1.18-1.48 dv at each Class I area.\138\ As discussed 
above, more recent emission data show an overall increase in 
SO2 emissions from the facility. Therefore anticipated 
visibility improvement from controls would be anticipated to be larger 
and there would be an improvement in the cost-effectiveness (i.e., 
lower dollars per ton removed) of controls had we used a more recent 
time period for the baseline emissions modeled.
---------------------------------------------------------------------------

    \135\ See 79 FR at 74838, 74840, and 74874.
    \136\ See Appendix C to the TSD, titled ``Technical Support 
Document for Visibility Modeling Analysis for Entergy Independence 
Generating Station,'' for a detailed discussion of the visibility 
modeling protocol and model inputs. A copy of the TSD and its 
appendices is found in the docket for this proposed rulemaking.
    \137\ Id.
    \138\ This is discussed in more detail in Appendix C to the TSD, 
titled ``Technical Support Document for Visibility Modeling Analysis 
for Entergy Independence Generating Station.''

 Table 66--Entergy Independence Units 1 and 2 (Facility-Wide): EPA Modeled 98th Percentile Visibility Impacts of
                                                    LNB/SOFA
----------------------------------------------------------------------------------------------------------------
                                                                  Visibility impact  ([Delta]dv)    Visibility
                                                                 --------------------------------   improvement
                  Class I area                    Distance  (km)                                    of LNB/SOFA
                                                                  Baseline \139\     LNB/SOFA      over baseline
                                                                                                       (dv)
----------------------------------------------------------------------------------------------------------------
Caney Creek.....................................             277           2.054           1.593           0.461
Upper Buffalo...................................             180           1.724           1.476           0.248
Hercules-Glades.................................             173           1.482           1.218           0.264
Mingo...........................................             174           1.492           1.279           0.213
                                                 ---------------------------------------------------------------
    Total.......................................  ..............           6.752           5.566           1.186
----------------------------------------------------------------------------------------------------------------

    Proposed RP Determination for NOX: As discussed above, based on the 
CENRAP's CAMx modeling, sulfate from point sources is the driver of 
regional haze at Caney Creek and Upper Buffalo on the 20% worst days in 
both 2002 and 2018. Nitrate from point sources is not considered a 
driver of regional haze at these Class I areas on the 20% worst days, 
contributing only approximately 3% of the total light extinction. The 
Regional Haze Rule requires that the established RPGs provide for an 
improvement in visibility for the most impaired days (i.e., the 20% 
worst days) over the period of the implementation plan and ensure no 
degradation in visibility for the least impaired days over the same 
period (40 CFR 51.308(d)(1)). Because of the small contribution of 
nitrate from point sources to the total light extinction at Caney Creek 
and Upper Buffalo on the most impaired days, we do not expect that 
NOX controls under the reasonable progress requirements 
would offer as much improvement on the most impaired days compared to 
SO2 controls. However, upon evaluation of the four 
reasonable progress factors, we found that the installation and 
operation of LNB/SOFA at Independence Units 1 and 2 is estimated to 
cost $401/NOX ton

[[Page 18997]]

removed at Unit 1 and $436/NOX ton removed at Unit 2, which 
we consider to be very cost-effective. These NOX controls 
are also projected to result in significant visibility improvements at 
Arkansas and Missouri Class I areas, based on CALPUFF modeling using 
the 98th percentile modeled visibility impacts. Therefore, under Option 
1, for the first planning period, we are proposing both an 
SO2 emission limit as described above and a NOX 
emission limit of 0.15 lb/MMBtu on a 30 boiler-operating-day averaging 
basis based on the installation and operation of LNB/SOFA, in light of 
their cost-effectiveness and visibility benefit based on CALPUFF 
modeling, even though nitrate from point sources is projected to 
contribute a very small proportion of the total light extinction at 
Caney Creek and Upper Buffalo on the 20% worst days in 2018. Based on 
our visibility modeling of both LNB/OFA and dry FGD, proposed Option 1 
is projected to have visibility benefits ranging from 1.18--1.48 dv at 
each Class I area.\140\ Under Option 2, we are proposing only 
SO2 controls for Independence Units 1 and 2 under the 
reasonable progress requirements. Based on our visibility modeling of 
dry FGD, proposed Option 2 is projected to have visibility benefits 
ranging from 0.87--1.06 dv at each Class I area. We specifically 
solicit public comment on this proposed alternative approach.
---------------------------------------------------------------------------

    \139\ Baseline NOX emissions were updated to the 
maximum 24-hr emissions from 2011-2013 for the evaluation of the 
anticipated benefit from NOX controls.
    \140\ See Appendix C to the TSD, titled ``Technical Support 
Document for Visibility Modeling Analysis for Entergy Independence 
Generating Station,'' for a detailed discussion of the visibility 
modeling protocol and model inputs. A copy of the TSD and its 
appendices is found in the docket for this proposed rulemaking.
---------------------------------------------------------------------------

    In addition to options 1 and 2, we also solicit public comment on 
any alternative SO2 and NOX control measures that 
would address the regional haze requirements for Entergy White Bluff 
Units 1 and 2 and Entergy Independence Units 1 and 2 for this planning 
period. This includes, but is not limited to, a combination of early 
unit shutdowns and other emissions control measures that would achieve 
greater reasonable progress than the BART and reasonable progress 
requirements we have proposed for these four units in this rulemaking.

B. Reasonable Progress Goals

    We propose RPGs for Caney Creek and Upper Buffalo that are 
consistent with the combination of control measures from the approved 
portion of the 2008 Arkansas RH SIP and our proposed Arkansas RH FIP. 
In total, these final and proposed controls to meet the BART and RP 
requirements will result in higher emissions reductions and 
commensurate visibility improvements beyond what was in the 2008 
Arkansas RH SIP. Development of refined numerical RPGs for Arkansas' 
Class I areas would require photochemical grid modeling of a multistate 
area, involving thousands of emission sources, unlike the comparatively 
simple single-source CALPUFF modeling used for individual BART 
assessments. In order to accurately reflect all emissions reductions 
expected to occur during this planning period, the new photochemical 
modeling would require an update of the emissions inventory for 
Arkansas and the surrounding states to include not just the actions 
under this FIP, but all EPA and state regulatory actions on point, 
area, and mobile sources. After the inventory is developed and reviewed 
by the affected states for accuracy, it must be converted to a model-
ready format before air quality modeling can be used to estimate the 
future visibility levels at the Class I areas. This modeling would 
require specialized and extensive computing hardware and expertise. 
Developing all of the necessary input files, running the photochemical 
model, and post-processing the model outputs would take several months 
at a minimum. Therefore, we are not conducting new photochemical grid 
modeling to establish revised numeric RPGs for Caney Creek and Upper 
Buffalo.
    In order to provide RPGs that account for emission reductions from 
the FIP controls, we have used a method similar to the one used in our 
Regional Haze FIP for Hawaii \141\ and Arizona,\142\ which is based on 
a scaling of visibility extinction components in proportion to emission 
changes. To determine the new RPGs for Caney Creek and Upper Buffalo, 
we started with the 2018 projection of extinction components from the 
CENRAP's CAMx photochemical modeling with source apportionment. The 
2018 CAMx emission scenario included some assumptions of state BART 
determinations and other SIP controls, as well as projected emissions 
from other point, area, and mobile sources. We scaled the modeled 
visibility extinction components for sulfate (SO4) and 
nitrate (NO3) from point sources in Arkansas in proportion 
to the FIP's emission reductions for SO2 and NOX, 
respectively. The sulfate scaling factor was the 2018 CENRAP emission 
inventory for Arkansas point source SO2 emissions with FIP 
controls for BART and RP sources in place, divided by the original 2018 
CENRAP emission inventory for Arkansas point source SO2 
emissions. We conducted the same scaling exercise with nitrate and 
NOX. The scaled sulfate and nitrate extinctions were added 
to the unscaled extinctions for organic mass and other components to 
get total extinction, and then this was used to calculate post-FIP RPGs 
in deciviews. Although we recognize that this method is not refined, it 
allows us to translate the emission reductions contained in this 
proposed FIP into quantitative RPGs, based on modeling previously 
performed by the CENRAP. These RPGs reflect rates of progress that are 
faster than the rates projected by Arkansas. The revised RPGs for the 
first planning period for the 20% worst days are 22.27 dv for Caney 
Creek and 22.33 dv for Upper Buffalo. The results of our analysis are 
shown in the table below.\143\ The RPG calculation was performed for 
both our proposed Options 1 and 2. Under Option 1 we are proposing to 
control Entergy Independence Units 1 and 2 for the first planning 
period for both SO2 and NOX. Alternatively, under 
Option 2, we are proposing to control Entergy Independence Units 1 and 
2 only for SO2 for the first planning period. Due to the 
small impact from all Arkansas point source NOx emissions combined on 
the 20% worst days and the scaling approach utilized to estimate the 
adjustment to the RPG, the difference between the two proposed options 
results in a very small difference in the calculated RPGs for Caney 
Creek and Upper Buffalo (less than 0.003 dv). We note that some FIP 
controls will not be in place by 2018, however, for the purpose of this 
calculation, we included reductions from all FIP controls. Arkansas 
will have to re-evaluate during the next regional haze planning period 
what BART and reasonable progress controls are in place and re-
calculate the RPGs for the next planning period as needed. We also note 
that RPGs, unlike the emission limits that apply to specific RP 
sources, are not directly enforceable.\144\ Rather, they are an 
analytical framework considered by us in evaluating whether measures in 
the implementation plan are sufficient to

[[Page 18998]]

achieve reasonable progress.\145\ Arkansas may choose to use these RPGs 
for purposes of its progress report, or may develop new RPGs for 
approval by us along with its progress report, based on new modeling or 
other appropriate techniques, in accordance with the requirements of 40 
CFR 51.308(d)(1).
---------------------------------------------------------------------------

    \141\ See 77 FR 31692, 31708.
    \142\ See 79 FR 52420, 52468.
    \143\ Please see Appendix C to the TSD, titled ``Technical 
Support Document for Visibility Modeling Analysis for Entergy 
Independence Generating Station,'' and the RPG calculation 
spreadsheet for additional details on calculations. These documents 
are found in the docket for our proposed rulemaking.
    \144\ 40 CFR 51.308(d)(1)(v).
    \145\ 64 FR 35733 and 40 CFR 51.308(d)(1)(v).

                                             Table 67--Proposed Reasonable Progress Goals for 20% Worst Days
                                                                     [In Deciviews]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                               2018
                      Class I area                           2000-2004     2064 Natural      2018 URP      Projection by   Estimated FIP   Estimated FIP
                                                             Baseline       conditions                        CENRAP          effect         2018 RPG
--------------------------------------------------------------------------------------------------------------------------------------------------------
Caney Creek.............................................           26.36           11.58           22.91           22.48           -0.21           22.27
Upper Buffalo...........................................           26.27           11.57           22.84           22.52           -0.19           22.33
--------------------------------------------------------------------------------------------------------------------------------------------------------

V. Our Proposed Long-Term Strategy

    Section 169A(b) of the CAA and 40 CFR 51.308(d)(3) require that 
states include in their SIP a 10 to 15-year strategy, referred to as 
the long-term strategy, for making reasonable progress for each Class I 
area within their state. This long-term strategy is the compilation of 
all control measures a state will use during the implementation period 
of the specific SIP submittal to meet any applicable RPGs for a 
particular Class I area. The long-term strategy must include 
``enforceable emissions limitations, compliance schedules, and other 
measures as necessary to achieve the reasonable progress goals'' for 
all Class I areas within, or affected by emissions from, the 
state.\146\
---------------------------------------------------------------------------

    \146\ 40 CFR 51.308(d)(3).
---------------------------------------------------------------------------

    Section 51.308(d)(3)(v) requires that a state consider certain 
factors (the long-term strategy factors) in developing its long-term 
strategy for each Class I area. These factors are the following: (1) 
Emission reductions due to ongoing air pollution control programs, 
including measures to address RAVI; (2) measures to mitigate the 
impacts of construction activities; (3) emissions limitations and 
schedules for compliance to achieve the reasonable progress goal; (4) 
source retirement and replacement schedules; (5) smoke management 
techniques for agricultural and forestry management purposes including 
plans as currently exist within the state for these purposes; (6) 
enforceability of emissions limitations and control measures; and (7) 
the anticipated net effect on visibility due to projected changes in 
point, area, and mobile source emissions over the period addressed by 
the long-term strategy. Since states are required to consider emissions 
limitations and schedules of compliance to achieve the RPGs for each 
Class I area, the BART emission limits that are in the state's regional 
haze SIP are an element of the state's long-term strategy (40 CFR 
51.308(d)(3)) for each Class I area. In our March 11, 2012 final action 
on the 2008 Arkansas RH SIP, since we disapproved a portion of 
Arkansas' BART determinations and both RPGs for Arkansas' two Class I 
areas, we also disapproved these elements and approved all other 
elements of Arkansas' long-term strategy. The BART limits and two RPGs 
for Arkansas' Class I areas that are in this proposed FIP address our 
March 11, 2011 disapproval of Arkansas' BART limits and two RPGs. We 
propose to find that the proposed BART limits and two RPGs that are in 
this proposed FIP also correct the deficiency in Arkansas' long-term 
strategy for each of its Class I areas.

VI. Our Proposal for Interstate Visibility Transport

    We received the Arkansas Interstate Visibility Transport SIP that 
addresses the interstate visibility transport requirements of CAA 
section 110(a)(2)(D)(i)(II) for the 1997 8-hour ozone and 
PM2.5 NAAQS on April 2, 2008. In its Interstate Visibility 
Transport SIP, Arkansas stated that its regional haze regulation, the 
APC&E Commission Regulation 19, chapter 15, codifying its Regional Haze 
SIP, satisfies the requirement of section 110(a)(2)(D)(i)(II) regarding 
the protection of visibility, and that it was not possible to assess 
whether there is any interference with measures in the applicable SIP 
for another state designed to protect visibility for the 8-hour ozone 
and PM2.5 NAAQS in other states until Arkansas submits and 
we approve the 2008 Arkansas RH SIP. In our March 12, 2012 final 
action, we partially approved and partially disapproved the Arkansas 
Interstate Visibility Transport SIP because we partially approved and 
partially disapproved the 2008 Arkansas RH SIP. In particular, we 
disapproved a large portion of Arkansas' BART determinations, and as a 
result, the corresponding emissions reductions other states had relied 
upon in their RPG demonstrations under the RHR would not take place. 
Therefore, we made a finding that Arkansas' SIP does not fully ensure 
that emissions from sources in Arkansas do not interfere with other 
states' visibility programs as required by section 110(a)(2)(D)(i)(II) 
of the CAA. Our proposed regional haze FIP would address all 
disapproved BART determinations for sources in Arkansas as well as all 
other disapproved portions of the 2008 Arkansas RH SIP. Our proposed 
regional haze FIP together with our prior approval of portions of the 
Arkansas Regional Haze SIP would ensure that the emissions reductions 
other sates relied upon in their RPG demonstrations take place. 
Therefore, we propose to find that the deficiencies we identified in 
our prior disapproval action on the Arkansas Interstate Visibility 
Transport SIP are addressed by our proposed regional haze FIP along 
with our prior approval of portions of the Arkansas Regional Haze SIP. 
We are also proposing to find that the requirements of CAA section 
110(a)(2)(D)(i)(II) with respect to visibility transport for the 1997 
8-hour ozone and PM2.5 NAAQS will be satisfied by the 
combination of the emission control measures in this proposed regional 
haze FIP and the previously approved portion of the Arkansas Interstate 
Visibility Transport SIP.

VII. Summary of Proposed Actions

A. Regional Haze

    We propose to promulgate a FIP to address those portions of 
Arkansas' regional haze SIP that we disapproved on March 12, 2012, 
which include requirements for BART, reasonable progress, and the long-
term strategy.\147\ The FIP we are proposing includes BART emission 
limits for sources in Arkansas to reduce emissions that contribute to 
regional haze in Arkansas' two Class I areas and other nearby Class I 
areas and make reasonable progress for

[[Page 18999]]

the first regional haze planning period for Arkansas' two Class I 
areas. This includes more stringent SO2 emission limits in 
comparison to what the 2008 Arkansas RH SIP contained for the AECC Carl 
E. Bailey Generating Station Unit 1, the AECC John L McClellan 
Generating Station Unit 1, the AEP Flint Creek Power Plant Unit 1, 
Entergy White Bluff Plant Units 1 and 2, and the Domtar Ashdown Paper 
Mill Power Boiler No. 2. We are also proposing in the alternative two 
options for addressing the reasonable progress requirements for this 
first planning period by controlling the Entergy Independence Power 
Plant for both the Caney Creek and Upper Buffalo Class I areas. Under 
Option 1, we propose to require SO2 and NOX 
emission reductions from the Entergy Independence Power Plant under the 
reasonable progress requirements. Under Option 2, we are also proposing 
only SO2 controls for Independence Units 1 and 2 under the 
reasonable progress requirements. In particular, we are inviting public 
comment on the alternate proposed Options 1 and 2. We also solicit 
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 regional haze requirements for these four units for this planning 
period. We also propose to find that the proposed BART and reasonable 
progress limits and RPGs that are in this proposed FIP correct the 
deficiency in Arkansas' long-term strategy for both Class I areas. Our 
proposed FIP, once finalized, along with the previously approved 
portion of the Arkansas regional haze SIP, will constitute Arkansas' 
regional haze program for the first planning period that ends in 2018.
---------------------------------------------------------------------------

    \147\ 77 FR 14604.
---------------------------------------------------------------------------

B. Interstate Visibility Transport

    We propose to find that the deficiencies we identified in our prior 
disapproval action on the Arkansas Interstate Visibility Transport SIP 
to address the requirement of CAA section 110(a)(2)(D)(i)(II) with 
respect to visibility transport for the 1997 8-hour ozone and 1997 
PM2.5 NAAQS will be remedied by our proposed Arkansas 
Regional Haze FIP along with our March 2, 2012 partial approval of 
certain elements of the 2008 Arkansas RH SIP. In its Interstate 
Visibility Transport SIP, Arkansas stated that its regional haze 
regulation, the APC&E Commission Regulation 19, chapter 15, codifying 
the Arkansas Regional Haze SIP, satisfies the requirement of section 
110(a)(2)(D)(i)(II) regarding the protection of visibility, and that it 
was not possible to assess whether there is any interference with 
measures in the applicable SIP for another state designed to protect 
visibility for the 8-hour ozone and PM2.5 NAAQS in other 
states until Arkansas submits and we approve the 2008 Arkansas RH SIP. 
Since our FIP addresses the portions of Arkansas Regional Haze SIP that 
we previously disapproved, we propose to find that the requirements of 
CAA section 110(a)(2)(D)(i)(II) with respect to visibility transport 
for the 1997 8-hour ozone and PM2.5 NAAQS will be satisfied 
by the combination of this proposed regional haze FIP and the 
previously approved portion of the Arkansas Interstate Visibility 
Transport SIP.

VIII. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Overview

    This proposed action is not a ``significant regulatory action'' 
under the terms of Executive Order 12866 (58 FR 51735, October 4, 1993) 
and is therefore not subject to review under Executive Orders 12866 and 
13563 (76 FR 3821, January 21, 2011). The proposed FIP would not 
constitute a rule of general applicability, because it only proposes 
source specific requirements for particular, identified facilities (six 
total).

B. Paperwork Reduction Act

    This proposed action does not impose an information collection 
burden under the provisions of the Paperwork Reduction Act, 44 U.S.C. 
3501 et seq. Because it does not contain any information collection 
activities, the Paperwork Reduction Act does not apply. See 5 CFR 
1320(c).

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA) generally requires an agency 
to conduct a regulatory flexibility analysis of any rule subject to 
notice and comment rulemaking requirements unless the agency certifies 
that the rule will not have a significant economic impact on a 
substantial number of small entities. Small entities include small 
businesses, small not-for-profit enterprises, and small governmental 
jurisdictions. For purposes of assessing the impacts of today's rule on 
small entities, small entity is defined as: (1) A small business as 
defined by the Small Business Administration's (SBA) regulations at 13 
CFR 121.201; (2) a small governmental jurisdiction that is a government 
of a city, county, town, school district or special district with a 
population of less than 50,000; and (3) a small organization that is 
any not-for-profit enterprise which is independently owned and operated 
and is not dominant in its field. After considering the economic 
impacts of today's proposed rule on small entities, I certify that this 
action will not have a significant impact on a substantial number of 
small entities. In making this determination, the impact of concern is 
any significant adverse economic impact on small entities. An agency 
may certify that a rule will not have a significant economic impact on 
a substantial number of small entities if the rule relieves regulatory 
burden, has no net burden or otherwise has a positive economic effect 
on the small entities subject to the rule. This rule does not impose 
any requirements or create impacts on small entities. This proposed SIP 
action under Section 110 of the CAA will not in-and-of itself create 
any new requirements on small entities but simply approves or 
disapproves certain state requirements for inclusion into the SIP. 
Accordingly, it affords no opportunity for the EPA to fashion for small 
entities less burdensome compliance or reporting requirements or 
timetables or exemptions from all or part of the rule. The fact that 
the CAA prescribes that various consequences (e.g., emission 
limitations) may or will flow from this action does not mean that the 
EPA either can or must conduct a regulatory flexibility analysis for 
this action. We have therefore concluded that, this action will have no 
net regulatory burden for all directly regulated small entities.

D. Unfunded Mandates Reform Act

    Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public 
Law 104-4, establishes requirements for Federal agencies to assess the 
effects of their regulatory actions on state, local, and Tribal 
governments and the private sector. Under Section 202 of UMRA, EPA 
generally must prepare a written statement, including a cost-benefit 
analysis, for proposed and final rules with ``Federal mandates'' that 
may result in expenditures to state, local, and Tribal governments, in 
the aggregate, or to the private sector, of $100 million or more 
(adjusted for inflation) in any one year. Before promulgating an EPA 
rule for which a written statement is needed, Section 205 of UMRA 
generally requires EPA to identify and consider a reasonable number of 
regulatory alternatives and adopt the least costly, most cost-
effective, or least burdensome alternative that achieves the objectives 
of the rule. The provisions of Section

[[Page 19000]]

205 of UMRA do not apply when they are inconsistent with applicable 
law. Moreover, Section 205 of UMRA allows EPA to adopt an alternative 
other than the least costly, most cost-effective, or least burdensome 
alternative if the Administrator publishes with the final rule an 
explanation why that alternative was not adopted. Before EPA 
establishes any regulatory requirements that may significantly or 
uniquely affect small governments, including Tribal governments, it 
must have developed under Section 203 of UMRA a small government agency 
plan. The plan must provide for notifying potentially affected small 
governments, enabling officials of affected small governments to have 
meaningful and timely input in the development of EPA regulatory 
proposals with significant Federal intergovernmental mandates, and 
informing, educating, and advising small governments on compliance with 
the regulatory requirements.
    EPA has determined that Title II of UMRA does not apply to this 
proposed rule. In 2 U.S.C. Section 1502(1) all terms in Title II of 
UMRA have the meanings set forth in 2 U.S.C. Section 658, which further 
provides that the terms ``regulation'' and ``rule'' have the meanings 
set forth in 5 U.S.C. Section 601(2). Under 5 U.S.C. Section 601(2), 
``the term `rule' does not include a rule of particular applicability 
relating to . . . facilities.'' Because this proposed rule is a rule of 
particular applicability relating to six named facilities, EPA has 
determined that it is not a ``rule'' for the purposes of Title II of 
UMRA.

E. Executive Order 13132: Federalism

    This proposed action does not have federalism implications. It will 
not have substantial direct effects on the states, on the relationship 
between the national government and the states, or on the distribution 
of power and responsibilities among the various levels of government.

F. Executive Order 13175: Consultation and Coordination With Indian 
Tribal Governments

    This proposed rule does not have tribal implications, as specified 
in Executive Order 13175. It will not have substantial direct effects 
on tribal governments. Thus, Executive Order 13175 does not apply to 
this rulemaking.

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

    Executive Order 13045: Protection of Children From Environmental 
Health Risks and Safety Risks \148\ applies to any rule that: (1) Is 
determined to be economically significant as defined under Executive 
Order 12866; and (2) concerns an environmental health or safety risk 
that we have reason to believe may have a disproportionate effect on 
children. EPA interprets EO 13045 as applying only to those regulatory 
actions that concern health or safety risks, such that the analysis 
required under Section 5-501 of the EO has the potential to influence 
the regulation. This action is not subject to Executive Order 13045 
because it is not economically significant as defined in Executive 
Order 12866, and because the EPA does not believe the environmental 
health or safety risks addressed by this action present a 
disproportionate risk to children. This action is not subject to EO 
13045 because it implements specific standards established by Congress 
in statutes. However, to the extent this proposed rule will limit 
emissions of SO2, NOX, and PM, the rule will have 
a beneficial effect on children's health by reducing air pollution.
---------------------------------------------------------------------------

    \148\ 62 FR 19885 (Apr. 23, 1997).
---------------------------------------------------------------------------

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

    This proposed action is not subject to Executive Order 13211 (66 FR 
28355 (May 22, 2001)), because it is not a significant regulatory 
action under Executive Order 12866.

I. National Technology Transfer and Advancement Act

    Section 12 of the National Technology Transfer and Advancement Act 
(NTTAA) of 1995 requires Federal agencies to evaluate existing 
technical standards when developing a new regulation. To comply with 
NTTAA, EPA must consider and use ``voluntary consensus standards'' 
(VCS) if available and applicable when developing programs and policies 
unless doing so would be inconsistent with applicable law or otherwise 
impractical. EPA believes that VCS are inapplicable to this action. 
Today's action does not require the public to perform activities 
conducive to the use of VCS.

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

    Executive Order 12898 (59 FR 7629, February 16, 1994), establishes 
federal executive policy on environmental justice. Its main provision 
directs federal agencies, to the greatest extent practicable and 
permitted by law, to make environmental justice part of their mission 
by identifying and addressing, as appropriate, disproportionately high 
and adverse human health or environmental effects of their programs, 
policies, and activities on minority populations and low-income 
populations in the United States. We have determined that this proposed 
rule, if finalized, will not have disproportionately high and adverse 
human health or environmental effects on minority or low-income 
populations because it increases the level of environmental protection 
for all affected populations without having any disproportionately high 
and adverse human health or environmental effects on any population, 
including any minority or low-income population. This proposed federal 
rule limits emissions of NOX, SO2, and PM from 
six facilities in Arkansas.

List of Subjects in 40 CFR Part 52

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

    Dated: March 6, 2015.
Samuel Coleman, P.E.
Acting Regional Administrator, Region 6.

    Title 40, chapter I, of the Code of Federal Regulations is proposed 
to be amended as follows:

PART 52--APPROVAL AND PROMULGATION OF IMPLEMENTATION PLANS

0
1. The authority citation for part 52 continues to read as follows:

    Authority:  42 U.S.C. 7401 et seq.

Subpart E--Arkansas

0
2. Section 52.173 is amended by adding paragraphs (c) and (d) to read 
as follows:


Sec.  52.173  Visibility protection.

* * * * *
    (c) Requirements for AECC Carl E. Bailey Unit 1; AECC John L. 
McClellan Unit 1; AEP Flint Creek Unit 1; Entergy White Bluff Units 1, 
2, and Auxiliary Boiler; Entergy Lake Catherine Unit 4; Domtar Ashdown 
Paper Mill Power Boilers No. 1 and 2; and Entergy Independence Units 1 
and 2 affecting visibility.
    (1) Applicability. The provisions of this section shall apply to 
each owner

[[Page 19001]]

or operator, or successive owners or operators, of the sources 
designated as: AECC Carl E. Bailey Unit 1; AECC John L. McClellan Unit 
1; AEP Flint Creek Unit 1; Entergy White Bluff Units 1, 2, and 
Auxiliary Boiler; Entergy Lake Catherine Unit 4; Domtar Ashdown Paper 
Mill Power Boilers No. 1 and 2; and Entergy Independence Units 1 and 2.
    (2) Definitions. All terms used in this part but not defined herein 
shall have the meaning given them in the Clean Air Act and in parts 51 
and 60 of CFR title 40. For the purposes of this section:
    24-hour period means the period of time between 12:01 a.m. and 12 
midnight.
    Air pollution control equipment includes selective catalytic 
control units, baghouses, particulate or gaseous scrubbers, and any 
other apparatus utilized to control emissions of regulated air 
contaminants which would be emitted to the atmosphere.
    Boiler-operating-day for electric generating units listed under 
paragraph (c)(1) of this section means any 24- hour period between 
12:00 midnight and the following midnight during which any fuel is 
combusted at any time at the steam generating unit. For power boilers 
listed under paragraph (c)(1) of this section, we define boiler-
operating-day as any 24-hour period between 12:00 midnight and the 
following midnight during which any fuel is fed into and/or combusted 
at any time in the Power Boiler.
    Daily average means the arithmetic average of the hourly values 
measured in a 24-hour period.
    Heat input means heat derived from combustion of fuel in a unit and 
does not include the heat input from preheated combustion air, 
recirculated flue gases, or exhaust gases from other sources. Heat 
input shall be calculated in accordance with 40 CFR part 75.
    Owner or Operator means any person who owns, leases, operates, 
controls, or supervises any of the units or power boilers listed under 
paragraph (c)(1) of this section.
    Regional Administrator means the Regional Administrator of EPA 
Region 6 or his/her authorized representative.
    Unit means one of the natural gas, fuel oil, or coal fired boilers 
covered under paragraph (c) of this section.
    (3) Emissions limitations for AECC Bailey Unit 1 and AECC McClellan 
Unit 1. The individual SO2, NOX, and PM emission 
limits for each unit shall be as listed in the following table.

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

    (4) Compliance dates for AECC Bailey Unit 1 and AECC McClellan 
Unit. The owner or operator of each unit shall comply with the 
SO2 and PM requirements listed in paragraph (c)(3) of this 
section within 5 years of the effective date of this rule. As of the 
effective date of this rule, the owner/operator of each unit shall not 
purchase fuel for combustion at the unit that does not meet the sulfur 
content limit in paragraph (c)(3) of this section. Five years from the 
effective date of the rule only fuel that meets the sulfur content 
limit in paragraph (c)(3) of this section shall be burned at each unit. 
The owner/operator of each unit shall comply with the NOX 
emission limits in paragraph (c)(3) of this section as of the effective 
date of this rule.
    (5) Compliance determinations for AECC Bailey Unit 1 and AECC 
McClellan Unit--(i) SO2 and PM. To determine compliance with the 
SO2 and PM requirements listed in paragraph (c)(3) of this 
section, the owner/operator shall sample and analyze each shipment of 
fuel to determine the sulfur content, except for natural gas shipments. 
A ``shipment'' is considered delivery of the entire amount of each 
order of fuel purchased. Fuel sampling and analysis may be performed by 
the owner or operator of an affected unit, an outside laboratory, or a 
fuel supplier.
    (ii) NOX. To determine compliance with the NOX emission 
limits of paragraph (c)(3) of this section, the owner/operator shall 
determine the average emissions (arithmetic average of three contiguous 
one hour periods) of NOX as measured by a CEMS and converted 
to pounds per hour using corresponding average (arithmetic average of 
three contiguous one hour periods) stack gas flow rates.
    (iii) The owner or operator shall continue to maintain and operate 
a CEMS for NOX on the units listed in paragraph (c)(3) of 
this section in accordance with 40 CFR 60.8 and 60.13(e), (f), and (h), 
and appendix B of part 60. The owner or operator shall comply with the 
quality assurance procedures for CEMS found in 40 CFR part 75. 
Compliance with the emission limits for NOX shall be 
determined by using data from a CEMS.
    (iv) Continuous emissions monitoring shall apply during all periods 
of operation of the units listed in paragraph (c)(3) of this section, 
including periods of startup, shutdown, and malfunction, except for 
CEMS breakdowns, repairs, calibration checks, and zero and span 
adjustments. Continuous monitoring systems for measuring NOX 
and diluent gas shall complete a minimum of one cycle of operation 
(sampling, analyzing, and data recording) for each successive 15-minute 
period. Hourly averages shall be computed using at least one data point 
in each fifteen minute quadrant of an hour. Notwithstanding this 
requirement, an hourly average may be computed from at least two data 
points separated by a minimum of 15 minutes (where the unit operates 
for more than one quadrant in an hour) if data are unavailable as a 
result of performance of calibration, quality assurance, preventive 
maintenance activities, or backups of data from data acquisition and 
handling system, and recertification events. When valid NOX 
pounds per hour emission data are not obtained because of continuous 
monitoring system breakdowns, repairs, calibration checks, or zero and 
span adjustments, emission data must be obtained by using other 
monitoring systems approved by the EPA to provide emission data for a 
minimum of 18 hours in each 24 hour period and at least 22 out of 30 
successive boiler operating days.
    (6) Emissions limitations for AEP Flint Creek Unit 1 and Entergy 
White Bluff Units 1 and 2. The individual SO2 and 
NOX emission limits for each unit shall be as listed in the 
following table in pounds per million British thermal units (lb/MMBtu) 
as averaged over a rolling 30 boiler-operating-day period.

[[Page 19002]]



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

    (7) Compliance dates for AEP Flint Creek Unit 1 and Entergy White 
Bluff Units 1 and 2. The owner or operator of each unit shall comply 
with the SO2 emission limit listed in paragraph (c)(6) of 
this section within 5 years of the effective date of this rule and the 
NOX emission limit within 3 years of the effective date of 
this rule.
    (8) Compliance determination for AEP Flint Creek Unit 1 and Entergy 
White Bluff Units 1 and 2. (i) For each unit, SO2 and 
NOX emissions for each calendar day shall be determined by 
summing the hourly emissions measured in pounds of SO2 or 
pounds of NOX. For each unit, heat input for each boiler-
operating-day shall be determined by adding together all hourly heat 
inputs, in millions of BTU. Each boiler-operating-day of the thirty-day 
rolling average for a unit shall be determined by adding together the 
pounds of SO2 or NOX from that day and the 
preceding 29 boiler-operating-days and dividing the total pounds of 
SO2 or NOX by the sum of the heat input during 
the same 30 boiler-operating-day period. The result shall be the 30 
boiler-operating-day rolling average in terms of lb/MMBtu emissions of 
SO2 or NOX. If a valid SO2 or 
NOX pounds per hour or heat input is not available for any 
hour for a unit, that heat input and SO2 or NOX 
pounds per hour shall not be used in the calculation of the 30 boiler-
operating-day rolling average for SO2 or NOX.
    (ii) The owner or operator shall continue to maintain and operate a 
CEMS for SO2 and NOX on the units listed in 
paragraph (c)(6) of this section in accordance with 40 CFR 60.8 and 
60.13(e), (f), and (h), and Appendix B of Part 60. The owner or 
operator shall comply with the quality assurance procedures for CEMS 
found in 40 CFR part 75. Compliance with the emission limits for 
SO2 and NOX shall be determined by using data 
from a CEMS.
    (iii) Continuous emissions monitoring shall apply during all 
periods of operation of the units listed in paragraph (c)(6) of this 
section, including periods of startup, shutdown, and malfunction, 
except for CEMS breakdowns, repairs, calibration checks, and zero and 
span adjustments. Continuous monitoring systems for measuring 
SO2 and NOX and diluent gas shall complete a 
minimum of one cycle of operation (sampling, analyzing, and data 
recording) for each successive 15-minute period. Hourly averages shall 
be computed using at least one data point in each fifteen minute 
quadrant of an hour. Notwithstanding this requirement, an hourly 
average may be computed from at least two data points separated by a 
minimum of 15 minutes (where the unit operates for more than one 
quadrant in an hour) if data are unavailable as a result of performance 
of calibration, quality assurance, preventive maintenance activities, 
or backups of data from data acquisition and handling system, and 
recertification events. When valid SO2 or NOX 
pounds per hour emission data are not obtained because of continuous 
monitoring system breakdowns, repairs, calibration checks, or zero and 
span adjustments, emission data must be obtained by using other 
monitoring systems approved by the EPA to provide emission data for a 
minimum of 18 hours in each 24 hour period and at least 22 out of 30 
successive boiler operating days.
    (9) Emissions limitations for Entergy White Bluff Auxiliary Boiler. 
The individual SO2, NOX, and PM emission limits 
for the unit shall be as listed in the following table in pounds per 
hour (lb/hr).

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

    (10) Compliance dates for Entergy White Bluff Auxiliary Boiler. The 
owner or operator of the unit shall comply with the SO2, 
NOX, and PM emission limits listed in paragraph (c)(9) of 
this section as of the effective date of this rule.
    (11) Emissions limitations for Entergy Lake Catherine Unit 4. The 
individual NOX emission limit for the unit for natural gas 
firing shall be as listed in the following table in pounds per million 
British thermal units (lb/MMBtu) as averaged over a rolling 30 boiler-
operating-day period. The unit shall not burn fuel oil until BART 
determinations are promulgated for the unit for SO2, 
NOX, and PM for the fuel oil firing scenario through a FIP 
and/or through EPA action upon and approval of revised BART 
determinations submitted by the State as a SIP revision.

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

    (12) Compliance dates for Entergy Lake Catherine Unit 4. The owner 
or operator of the unit shall comply with the NOX emission 
limit listed in paragraph (c)(11) of this section within 3 years of the 
effective date of this rule.
    (13) Compliance determination for Entergy Lake Catherine Unit 4. 
(i) NOX emissions for each calendar day shall be determined 
by summing the hourly emissions measured in pounds of NOX. 
The heat input for each boiler-operating-day shall be determined by 
adding together all hourly heat inputs, in millions of BTU. Each 
boiler-operating-day of the thirty-day rolling average for the unit 
shall be determined by adding together the pounds of NOX 
from that day and the preceding 29 boiler-operating-days and dividing 
the total pounds of NOX by the sum of the heat input during 
the same 30 boiler-operating-day period. The result shall be the 30 
boiler-operating-day rolling average in terms of lb/MMBtu emissions of 
NOX. If a valid NOX pounds per hour or heat input 
is not available for any hour for the unit, that heat input and 
NOX pounds per hour shall not be used in the calculation of 
the 30 boiler-operating-day rolling average for NOX.
    (ii) The owner or operator shall continue to maintain and operate a 
CEMS for NOX on the unit listed in paragraph (c)(11) of this 
section in accordance with 40 CFR 60.8 and 60.13(e), (f), and (h), and 
appendix B of

[[Page 19003]]

part 60. The owner or operator shall comply with the quality assurance 
procedures for CEMS found in 40 CFR part 75. Compliance with the 
emission limit for NOX shall be determined by using data 
from a CEMS.
    (iii) Continuous emissions monitoring shall apply during all 
periods of operation of the unit listed in paragraph (c)(11) of this 
section, including periods of startup, shutdown, and malfunction, 
except for CEMS breakdowns, repairs, calibration checks, and zero and 
span adjustments. Continuous monitoring systems for measuring 
NOX and diluent gas shall complete a minimum of one cycle of 
operation (sampling, analyzing, and data recording) for each successive 
15-minute period. Hourly averages shall be computed using at least one 
data point in each fifteen minute quadrant of an hour. Notwithstanding 
this requirement, an hourly average may be computed from at least two 
data points separated by a minimum of 15 minutes (where the unit 
operates for more than one quadrant in an hour) if data are unavailable 
as a result of performance of calibration, quality assurance, 
preventive maintenance activities, or backups of data from data 
acquisition and handling system, and recertification events. When valid 
NOX pounds per hour emission data are not obtained because 
of continuous monitoring system breakdowns, repairs, calibration 
checks, or zero and span adjustments, emission data must be obtained by 
using other monitoring systems approved by the EPA to provide emission 
data for a minimum of 18 hours in each 24 hour period and at least 22 
out of 30 successive boiler operating days.
    (14) Emissions limitations for Domtar Ashdown Paper Mill Power 
Boiler No.1. The individual SO2 and NOX emission 
limits for the power boiler shall be as listed in the following table 
in pounds per hour (lb/hr) as averaged over a rolling 30 boiler-
operating-day period. For this power boiler, boiler-operating-day is 
defined as a 24-hour period between 12 midnight and the following 
midnight during which any fuel is fed into and/or combusted at any time 
in the power boiler.

----------------------------------------------------------------------------------------------------------------
                                                                SO2 Emission limit (lb/  NOX Emission limit (lb/
                             Unit                                         hr)                      hr)
----------------------------------------------------------------------------------------------------------------
Domtar Ashdown Paper Mill Power Boiler No. 1..................                     21.0                    207.4
----------------------------------------------------------------------------------------------------------------

    (15) Compliance dates for Domtar Ashdown Mill Power Boiler No. 1. 
The owner or operator of the power boiler shall comply with the 
SO2 and NOX emission limits listed in paragraph 
(c)(14) of this section as of the effective date of this rule.
    (16) Compliance determination for Domtar Ashdown Paper Mill Power 
Boiler No. 1. (i) SO2 emissions for each calendar day shall 
be determined by summing the hourly emissions measured in pounds of 
SO2. SO2 emissions from combustion of bark shall 
be determined by using the following site-specific curve equation, 
which accounts for the SO2 scrubbing capabilities of bark 
combustion:

Y= 0.4005 * X-0.2645

Where:

Y= pounds of sulfur emitted per ton of dry fuel feed to the boiler
X= pounds of sulfur input per ton of dry bark


The owner or operator shall confirm the site-specific curve equation 
through stack testing. No later than 1 year after the effective date of 
this rule, the owner or operator shall provide a report to EPA showing 
confirmation of the site specific-curve equation accuracy. Stack 
SO2 emissions from combustion of fuel oil shall be 
determined by assuming that the SO2 inlet is equal to the 
SO2 being emitted at the stack.
    (ii) To demonstrate compliance with the NOX emission 
limit under paragraph (c)(14) of this section, the owner or operator 
shall conduct annual stack testing.
    (iii) Each boiler-operating-day of the thirty-day rolling average 
for the power boiler shall be determined by adding together the pounds 
of SO2 or NOX from that day and the preceding 29 
boiler-operating-days and dividing the total pounds of SO2 
or NOX by the sum of the total number of hours during the 
same 30 boiler-operating-day period. The result shall be the 30 boiler-
operating-day rolling average in terms of lb/hr emissions of 
SO2 or NOX. If a valid SO2 or 
NOX pounds per hour is not available for any hour for the 
power boiler, that SO2 or NOX pounds per hour 
shall not be used in the calculation of the applicable 30 boiler-
operating-day rolling average.
    (17) SO2 and NOX emissions limitations for Domtar Ashdown Paper 
Mill Power Boiler No.2. The individual SO2 and 
NOX emission limits for the power boiler shall be as listed 
in the following table in pounds per hour (lb/hr) or pounds per million 
British thermal units (lb/MMBtu) as averaged over a rolling 30 boiler-
operating-day period. For this power boiler, boiler-operating-day is 
defined as a 24-hour period between 12 midnight and the following 
midnight during which any fuel is fed into and/or combusted at any time 
in the power boiler.

----------------------------------------------------------------------------------------------------------------
                                                                SO2 Emission limit (lb/  NOX Emission limit (lb/
                             Unit                                        MMBtu)                    hr)
----------------------------------------------------------------------------------------------------------------
Domtar Ashdown Paper Mill Power Boiler No. 2..................                     0.11                      345
----------------------------------------------------------------------------------------------------------------

    (18) SO2 and NOX compliance dates for Domtar Ashdown Mill Power 
Boiler No. 2. The owner or operator of the power boiler shall comply 
with the SO2 and NOX emission limits listed in 
paragraph (c)(17) of this section within 3 year of the effective date 
of this rule.
    (19) SO2 and NOX compliance determination for Domtar Ashdown Mill 
Power Boiler No. 2. (i) SO2 emissions for each calendar day 
shall be determined by summing the hourly emissions measured in pounds 
of SO2. The heat input for each boiler-operating-day shall 
be determined by adding together all hourly heat inputs, in millions of 
BTU. Each boiler-operating-day of the thirty-day rolling average for a 
unit shall be determined by adding together the pounds of 
SO2 from that day and the preceding 29 boiler-operating-days 
and dividing the total pounds of SO2 by the sum of the heat 
input during the same 30 boiler-operating-day period. The result shall 
be the 30 boiler-operating-day rolling average in terms of lb/MMBtu 
emissions of SO2. If a valid SO2 pounds per hour 
or heat input is not available for any hour for a unit, that heat input 
and SO2 pounds per hour shall not be used in the calculation 
of the 30 boiler-operating-day rolling average for SO2.

[[Page 19004]]

    (ii) NOX emissions for each calendar day shall be 
determined by summing the hourly emissions measured in pounds of 
NOX. Each boiler-operating-day of the thirty-day rolling 
average for the power boiler shall be determined by adding together the 
pounds of NOX from that day and the preceding 29 boiler-
operating-days and dividing the total pounds of NOX by the 
sum of the total number of hours during the same 30 boiler-operating-
day period. The result shall be the 30 boiler-operating-day rolling 
average in terms of lb/hr emissions of NOX. If a valid 
NOX pounds per hour is not available for any hour for the 
power boiler, that NOX pounds per hour shall not be used in 
the calculation of the 30 boiler-operating-day rolling average for 
NOX.
    (iii) The owner or operator shall continue to maintain and operate 
a CEMS for SO2 and NOX on the power boiler listed 
in paragraph (c)(17) of this section in accordance with 40 CFR 60.8 and 
60.13(e), (f), and (h), and Appendix B of Part 60. The owner or 
operator shall comply with the quality assurance procedures for CEMS 
found in 40 CFR part 75. Compliance with the emission limits for 
SO2 and NOX shall be determined by using data 
from a CEMS.
    (iv) Continuous emissions monitoring shall apply during all periods 
of operation of the units listed in paragraph (c)(17) of this section, 
including periods of startup, shutdown, and malfunction, except for 
CEMS breakdowns, repairs, calibration checks, and zero and span 
adjustments. Continuous monitoring systems for measuring SO2 
and NOX and diluent gas shall complete a minimum of one 
cycle of operation (sampling, analyzing, and data recording) for each 
successive 15-minute period. Hourly averages shall be computed using at 
least one data point in each fifteen minute quadrant of an hour. 
Notwithstanding this requirement, an hourly average may be computed 
from at least two data points separated by a minimum of 15 minutes 
(where the unit operates for more than one quadrant in an hour) if data 
are unavailable as a result of performance of calibration, quality 
assurance, preventive maintenance activities, or backups of data from 
data acquisition and handling system, and recertification events. When 
valid SO2 or NOX pounds per hour emission data 
are not obtained because of continuous monitoring system breakdowns, 
repairs, calibration checks, or zero and span adjustments, emission 
data must be obtained by using other monitoring systems approved by the 
EPA to provide emission data for a minimum of 18 hours in each 24 hour 
period and at least 22 out of 30 successive boiler operating days.
    (20) PM Emissions limitations for Domtar Ashdown Paper Mill Power 
Boiler No.2. The individual particulate matter emission limit for the 
power boiler shall be as listed in the following table in pounds per 
million British thermal units (lb/MMBtu).

------------------------------------------------------------------------
                                                      PM Emission limit
                       Unit                              (lb/MMBtu)
------------------------------------------------------------------------
Domtar Ashdown Paper Mill Power Boiler No. 2......                  0.44
------------------------------------------------------------------------

    (21) PM compliance dates for Domtar Ashdown Mill Power Boiler No. 
2. The owner or operator of the power boiler shall comply with the PM 
emission limit listed in paragraph (c)(20) of this section as of the 
effective date of this rule.
    (22) PM compliance determination for Domtar Ashdown Paper Mill 
Power Boiler No.2. Compliance with the PM emission limit listed in 
paragraph (c)(20) of this section shall be determined by maintaining 
the 30-day rolling average wet scrubber pressure drop and the 30-day 
rolling average wet scrubber liquid flow rate at or above the lowest 
one-hour average pressure drop and the lowest one-hour average liquid 
flow rate, respectively, measured during the most recent performance 
test demonstrating compliance with the PM emission limit according to 
40 CFR 63.7530(b) and Table 7 to subpart DDDDD of part 63. The pressure 
drop and liquid flow rate monitoring system data shall be collected 
according to 40 CFR 63.7525 and 63.7535; data shall be reduced to 30-
day rolling averages; and the 30-day rolling average pressure drop and 
liquid flow-rate shall be maintained at or above the operating limits 
established during the performance test according to 40 CFR 63.7530(b).
    (23) Emissions limitations for Entergy Independence Units 1 and 2. 
The individual emission limits for each unit shall be as listed in the 
following table in pounds per million British thermal units (lb/MMBtu) 
as averaged over a rolling 30 boiler-operating-day period. EPA is 
taking comment on two possible options. Under Option 1, the 
SO2 and a NOX emission limits as listed in the 
following table shall apply to each unit. Under Option 2, only the 
SO2 emission limit as listed in the following table shall 
apply to each unit. EPA expects only to finalize one of these options.

 
 
----------------------------------------------------------------------------------------------------------------
Unit                                                                    SO2 Emission limit    NOX Emission limit
                                                                                (lb/MMBtu)            (lb/MMBtu)
----------------------------------------------------------------------------------------------------------------
Option 1.............................  Entergy Independence Unit 1                    0.06                  0.15
                                        and 2.
Option 2.............................  Entergy Independence Unit 1                    0.06  ....................
                                        and 2.
----------------------------------------------------------------------------------------------------------------

    (24) Compliance dates for Entergy Independence Units 1 and 2. The 
owner or operator of each unit shall comply with the SO2 
emission limit in paragraph (c)(23) of this section within 5 years of 
the effective date of this rule and the NOX emission limit 
within 3 years of the effective date of this rule.
    (25) Compliance determination for Entergy Independence Units 1 and 
2. (i) For each unit, SO2 and NOX emissions for 
each calendar day shall be determined by summing the hourly emissions 
measured in pounds of SO2 or pounds of NOX. For 
each unit, heat input for each boiler-operating-day shall be determined 
by adding together all hourly heat inputs, in millions of BTU. Each 
boiler-operating-day of the thirty-day rolling average for a unit shall 
be determined by adding together the pounds of SO2 or 
NOX from that day and the preceding 29 boiler-operating-days 
and dividing the total pounds of SO2 or NOX by 
the sum of the heat input during the same 30 boiler-operating-day 
period. The result shall be the 30 boiler-operating-day rolling average 
in terms of lb/MMBtu emissions of SO2 or NOX. If 
a valid SO2 or NOX pounds per hour or heat input 
is not available for any hour for a unit, that heat input and 
SO2 or NOX pounds per hour shall not be used in 
the calculation of the applicable 30 boiler-operating-day rolling 
average.
    (ii) The owner or operator shall continue to maintain and operate a 
CEMS for SO2 and NOX on the units listed in 
paragraph (c)(23) of this section in accordance with 40 CFR 60.8 and 
60.13(e), (f), and (h), and appendix B of part 60. The owner or 
operator shall comply with the quality assurance procedures for CEMS 
found in 40 CFR part 75. Compliance with the emission limits for 
SO2 and NOX shall be determined by using data 
from a CEMS.

[[Page 19005]]

    (iii) Continuous emissions monitoring shall apply during all 
periods of operation of the units listed in paragraph (c)(23) of this 
section, including periods of startup, shutdown, and malfunction, 
except for CEMS breakdowns, repairs, calibration checks, and zero and 
span adjustments. Continuous monitoring systems for measuring 
SO2 and NOX and diluent gas shall complete a 
minimum of one cycle of operation (sampling, analyzing, and data 
recording) for each successive 15-minute period. Hourly averages shall 
be computed using at least one data point in each fifteen minute 
quadrant of an hour. Notwithstanding this requirement, an hourly 
average may be computed from at least two data points separated by a 
minimum of 15 minutes (where the unit operates for more than one 
quadrant in an hour) if data are unavailable as a result of performance 
of calibration, quality assurance, preventive maintenance activities, 
or backups of data from data acquisition and handling system, and 
recertification events. When valid SO2 or NOX 
pounds per hour emission data are not obtained because of continuous 
monitoring system breakdowns, repairs, calibration checks, or zero and 
span adjustments, emission data must be obtained by using other 
monitoring systems approved by the EPA to provide emission data for a 
minimum of 18 hours in each 24 hour period and at least 22 out of 30 
successive boiler operating days.
    (26) Reporting and recordkeeping requirements. Unless otherwise 
stated all requests, reports, submittals, notifications, and other 
communications to the Regional Administrator required under paragraph 
(c) of this section shall be submitted, unless instructed otherwise, to 
the Director, Multimedia Planning and Permitting Division, U.S. 
Environmental Protection Agency, Region 6, to the attention of Mail 
Code: 6PD, at 1445 Ross Avenue, Suite 1200, Dallas, Texas 75202-2733. 
For each unit subject to the emissions limitation under paragraph (c) 
of this section, the owner or operator shall comply with the following 
requirements:
    (i) For each emissions limit under paragraph (c) of this section 
where compliance shall be determined by using data from a CEMS, comply 
with the notification, reporting, and recordkeeping requirements for 
CEMS compliance monitoring in 40 CFR 60.7(c) and (d).
    (ii) For each day, provide the total SO2 emitted that 
day by AEP Flint Creek Unit 1, Entergy White Bluff Units 1 and 2, 
Domtar Ashdown Mill Power Boilers No. 1 and 2, and Entergy Independence 
Units 1 and 2. For each day, provide the total NOX emitted 
that day by AECC Bailey Unit 1, AECC McClellan Unit 1, AEP Flint Creek 
Unit 1, Entergy White Bluff Units 1 and 2, Entergy Lake Catherine Unit 
4, Domtar Ashdown Mill Power Boiler No. 2, and Entergy Independence 
Units 1 and 2. For any hours on any unit or power boiler where data for 
hourly pounds or heat input is missing, identify the unit number and 
monitoring device that did not produce valid data that caused the 
missing hour.
    (27) Equipment operations. At all times, including periods of 
startup, shutdown, and malfunction, the owner or operator shall, to the 
extent practicable, maintain and operate the unit including associated 
air pollution control equipment in a manner consistent with good air 
pollution control practices for minimizing emissions. Determination of 
whether acceptable operating and maintenance procedures are being used 
will be based on information available to the Regional Administrator 
which may include, but is not limited to, monitoring results, review of 
operating and maintenance procedures, and inspection of the unit.
    (28) Enforcement. (i) Notwithstanding any other provision in this 
implementation plan, any credible evidence or information relevant as 
to whether the unit would have been in compliance with applicable 
requirements if the appropriate performance or compliance test had been 
performed, can be used to establish whether or not the owner or 
operator has violated or is in violation of any standard or applicable 
emission limit in the plan.
    (ii) Emissions in excess of the level of the applicable emission 
limit or requirement that occur due to a malfunction shall constitute a 
violation of the applicable emission limit.
    (d) Measures addressing partial disapproval of portion of 
Interstate Visibility Transport SIP for the 1997 8-hour ozone and 
PM2.5 NAAQS. (1) The deficiencies identified in EPA's 
partial disapproval of the portion of the SIP pertaining to adequate 
provisions to prohibit emissions in Arkansas from interfering with 
measures required in another state to protect visibility, submitted on 
March 28, 2008, and supplemented on September 27, 2011 are satisfied by 
Sec.  52.173.
    (2) [Reserved]

[FR Doc. 2015-06726 Filed 4-3-15; 11:15 am]
 BILLING CODE 6560-50-P