Document ID: EPA-R06-OAR-2008-0727-0001
Agency: epa
Document Type: Proposed Rule
Title: AR006.001 Approval and Promulgation of Implementation Plans; Arkansas;  Regional Haze State Implementation Plan; Interstate Transport State Implementation Plan To Address Pollution Affecting Visibility and Regional Haze. 36 pages rxh. NOTE: November 16, 2011 (76 FR 70952), Comment period extended to December 22, 2011.
Posted Date: 2011-10-17T04:00Z

[Federal Register Volume 76, Number 200 (Monday, October 17, 2011)]
[Proposed Rules]
[Pages 64186-64221]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2011-26336]

[[Page 64185]]

Vol. 76

Monday,

No. 200

October 17, 2011

Part II

Environmental Protection Agency

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40 CFR Part 52

Approval and Promulgation of Implementation Plans; Arkansas; Regional 
Haze State Implementation Plan; Interstate Transport State 
Implementation Plan To Address Pollution Affecting Visibility and 
Regional Haze; Proposed Rule

  Federal Register / Vol. 76, No. 200 / Monday, October 17, 2011 / 
Proposed Rules  

[[Page 64186]]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 52

[EPA-R06-OAR-2008-0727; FRL-9478-2]

Approval and Promulgation of Implementation Plans; Arkansas; 
Regional Haze State Implementation Plan; Interstate Transport State 
Implementation Plan To Address Pollution Affecting Visibility and 
Regional Haze

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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SUMMARY: EPA is proposing to partially approve and partially disapprove 
a revision to the Arkansas State Implementation Plan (SIP) submitted by 
the State of Arkansas through the Arkansas Department of Environmental 
Quality (ADEQ) on September 23, 2008, August 3, 2010, and supplemented 
on September 27, 2011, that addresses regional haze (RH) for the first 
implementation period. These revisions were submitted to address the 
requirements of the Clean Air Act (CAA or Act) and our rules that 
require states to prevent any future and remedy any existing man-made 
impairment of visibility in mandatory Class I areas caused by emissions 
of air pollutants from numerous sources located over a wide geographic 
area (also referred to as the ``regional haze program''). EPA is also 
proposing to partially approve and partially disapprove a portion of a 
SIP revision submitted by the State of Arkansas on April 2, 2008, and 
supplemented on September 27, 2011, to address the interstate transport 
requirements of the CAA that the Arkansas SIP contain adequate 
provisions to prohibit emissions from interfering with measures 
required in another state to protect visibility. This action is being 
taken under section 110 and part C of the CAA.

DATES: Comments must be received on or before November 16, 2011.

ADDRESSES: Submit your comments, identified by Docket No. EPA-R06-OAR-
2008-0727, by one of the following methods:
     Federal e-Rulemaking Portal: http://www.regulations.gov. 
Follow the online instructions for submitting comments.
     E-mail: Mr. Guy Donaldson at donaldson.guy@epa.gov. Please 
also send a copy by e-mail to the person listed in the FOR FURTHER 
INFORMATION CONTACT section below.
     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 1200, 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-2008-
0727. Our policy is that all comments received will be included in the 
public docket without change and may be made available online at http://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 http://www.regulations.gov or e-
mail. The http://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 e-mail comment directly to us without going through http://www.regulations.gov your e-mail 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, any form of encryption, and be free of any defects or 
viruses.
    Docket: All documents in the docket are listed in the http://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. 
Publicly available docket materials are available either electronically 
in http://www.regulations.gov or in hard copy at the Air Planning 
Section (6PD-L), Environmental Protection Agency, 1445 Ross Avenue, 
Suite 700, Dallas, Texas 75202-2733. The file will be made available by 
appointment for public inspection in the Region 6 FOIA Review Room 
between the hours of 8:30 a.m. and 4:30 p.m. weekdays except for legal 
holidays. Contact the person listed in the FOR FURTHER INFORMATION 
CONTACT paragraph below or Mr. Bill Deese at 214-665-7253 to make an 
appointment. If possible, please make the appointment at least two 
working days in advance of your visit. There will be a 15 cent per page 
fee for making photocopies of documents. On the day of the visit, 
please check in at our Region 6 reception area at 1445 Ross Avenue, 
Suite 700, Dallas, Texas.
    The State submittal is also available for public inspection during 
official business hours, by appointment, at the Arkansas Department of 
Environmental Quality, 5301 Northshore Drive, North Little Rock, AR 
72118-5317.

FOR FURTHER INFORMATION CONTACT: Ms. Dayana Medina, Air Planning 
Section (6PD-L), Environmental Protection Agency, Region 6, 1445 Ross 
Avenue, Suite 700, Dallas, Texas 75202-2733, telephone 214-665-7241; 
fax number 214-665-7263; e-mail address medina.dayana@epa.gov.

SUPPLEMENTARY INFORMATION: Throughout this document wherever ``we,'' 
``us,'' or ``our'' is used, we mean the EPA.

Table of Contents

I. Overview of Proposed Actions
    A. Regional Haze
    B. Interstate Transport and Visibility
II. What is the background for our proposed actions?
    A. Regional Haze
    B. Roles of Agencies in Addressing Regional Haze
    C. The 1997 NAAQS for Ozone and PM2.5 and CAA 
110(a)(2)(D)(i)
III. What are the requirements for regional haze SIPs?
    A. The CAA and the Regional Haze Rule
    B. Determination of Baseline, Natural, and Current Visibility 
Conditions
    C. Determination of Reasonable Progress Goals
    D. Best Available Retrofit Technology
    E. Long-Term Strategy
    F. Coordinating Regional Haze and Reasonably Attributable 
Visibility Impairment
    G. Monitoring Strategy and Other SIP Requirements
    H. Consultation With States and Federal Land Managers
IV. Our Analysis of Arkansas' Regional Haze SIP
    A. Affected Class I Areas
    B. Determination of Baseline, Natural and Current Visibility 
Conditions

[[Page 64187]]

    1. Estimating Natural Visibility Conditions
    2. Estimating Baseline Visibility Conditions
    3. Natural Visibility Impairment
    4. Uniform Rate of Progress
    C. Evaluation of Arkansas' Reasonable Progress Goals
    1. Establishment of the Reasonable Progress Goals
    2. ADEQ's Reasonable Progress ``Four Factor'' Analysis
    3. Reasonable Progress Consultation
    D. Evaluation of Arkansas' BART Determinations
    1. Identification of BART-Eligible Sources
    2. Identification of Sources Subject to BART
    a. Modeling Methodology
    b. Contribution Threshold
    c. Sources Identified by ADEQ as Subject to BART
    3. BART Determinations
    a. AECC Bailey Unit 1 and AECC McClellan Unit 1 BART 
Determinations
    b. AEP Flint Creek Boiler No. 1 BART Determination
    c. Entergy Lake Catherine Unit 4 BART Determination
    d. Entergy White Bluff Units 1, 2, and Auxiliary Boiler BART 
Determinations
    e. Domtar Power Boilers No. 1 and 2 BART Determinations
    f. ADEQ BART Results and Summary
    4. Arkansas' Regional Haze Rule
    E. Long-Term Strategy
    1. Emissions Inventories
    a. Arkansas' 2002 Emission Inventory
    b. Arkansas' 2018 Emission Inventory
    2. Visibility Projection Modeling
    3. Sources of Visibility Impairment
    a. Sources of Visibility Impairment in Caney Creek
    b. Sources of Visibility Impairment in Upper Buffalo
    c. Arkansas' Contribution to Visibility Impairment in Class I 
Areas Outside the State
    4. Consultation and Emissions Reductions for Other States' Class 
I Areas
    5. Mandatory Long-Term Strategy Factors
    a. Reductions Due to Ongoing Air Pollution Programs
    b. Measures To Mitigate the Impacts of Construction Activities
    c. Emissions Limitations and Schedules of Compliance
    d. Source Retirement and Replacement Schedules
    e. Agricultural and Forestry Smoke Management Techniques
    f. Enforceability of Emissions Limitations and Control Measures
    g. Anticipated Net Effect on Visibility Due to Projected Changes
    6. Our Conclusion on Arkansas' Long-Term Strategy
    F. Coordination of RAVI and Regional Haze Requirements
    G. Monitoring Strategy and Other SIP Requirements
    H. Federal Land Manager Coordination
    I. Periodic SIP Revisions and Five-Year Progress Reports
    J. Determination of the Adequacy of Existing Implementation Plan
V. Our Analysis of Arkansas' Interstate Visibility Transport SIP 
Provisions
VI. Proposed Action
    A. Regional Haze
    B. Interstate Transport and Visibility
VII. Statutory and Executive Order Reviews

I. Overview of Proposed Actions

A. Regional Haze

    We are proposing to partially approve and partially disapprove 
Arkansas' RH SIP revision submitted on September 23, 2008, August 3, 
2010, and supplemented on September 27, 2011, as discussed in sections 
IV and VI of this proposed rulemaking. Specifically, we are proposing 
to approve the following: the State's identification of affected Class 
I areas; the establishment of baseline and natural visibility 
conditions; the Uniform Rate of Progress (URP); the State's reasonable 
progress goal (RPG) consultation and the long-term strategy (LTS) 
consultation; the regional haze monitoring strategy and other SIP 
requirements under section 51.308(d)(4); the State's commitment to 
submit periodic regional haze SIP revisions and periodic progress 
reports describing progress towards the RPGs; the State's commitment to 
make a determination of the adequacy of the existing SIP at the time a 
progress report is submitted; and the State's consultation and 
coordination with Federal land managers (FLMs).
    We are proposing to partially approve and partially disapprove 
those portions addressing the State's identification of BART-eligible 
sources and subject to BART sources; the requirements for best 
available retrofit technology (BART); the State's RH Rule; and the LTS. 
Specifically, we are proposing to approve the State's identification of 
BART-eligible sources, with the exception of the 6A Boiler at the 
Georgia-Pacific Crossett Mill, which we find to be BART-eligible. We 
are proposing to approve the State's identification of subject to BART 
sources, with the exception of the 6A and 9A Boilers at the Georgia-
Pacific Crossett Mill, which we find to be subject to BART. We are also 
proposing to approve the following BART determinations made by ADEQ: 
The PM BART determination for the No. 1 Boiler of the American Electric 
Power (AEP) Flint Creek plant; the SO2 and PM BART 
determinations for the natural gas firing scenario for Unit 4 of the 
Entergy Lake Catherine plant; the PM BART determinations for both the 
bituminous and sub-bituminous coal firing scenarios for Units 1 and 2 
of the Entergy White Bluff plant; and the PM BART determination for the 
No. 1 Power Boiler of the Domtar Ashdown Mill. We are proposing to 
disapprove the following BART determinations made by ADEQ: The 
SO2, NOX, and PM BART determinations for both 
Unit 1 of the Arkansas Electric Cooperative Corporation (AECC) Bailey 
plant and Unit 1 of the AECC McClellan plant; the SO2 and 
NOX BART determinations for the No. 1 Boiler of the AEP 
Flint Creek plant; the NOX BART determination for the 
natural gas firing scenario and the SO2, NOX, and 
PM BART determinations for the fuel oil firing scenario for Unit 4 of 
the Entergy Lake Catherine plant; the SO2 and NOX 
BART determinations for both the bituminous and sub-bituminous coal 
firing scenarios for Units 1 and 2 of the Entergy White Bluff plant; 
the BART determination for the Auxiliary Boiler of the Entergy White 
Bluff Plant; the SO2 and NOX BART determinations 
for the No. 1 Power Boiler of the Domtar Ashdown Mill; and the 
SO2, NOX and PM BART determinations for the No. 2 
Power Boiler of the Domtar Ashdown Mill. We are proposing to disapprove 
these BART determinations because they do not comply with our 
regulations under 40 CFR 51.308(e). The Arkansas RH Rule, the Arkansas 
Pollution Control and Ecology Commission (APC&E Commission) Regulation 
19, Chapter 15, was submitted by ADEQ on September 23, 2008, as part of 
the RH SIP. On August 3, 2010, we received a SIP submittal from ADEQ 
revising several chapters of APC&E Commission Regulation 19, including 
chapter 15. The revisions to Chapter 15 of APC&E Commission Regulation 
19 that we received on August 3, 2010, are mostly non-substantive edits 
to the original rule we received on September 23, 2008. Therefore, in 
this proposed rulemaking we are proposing to take action on chapter 15 
of APC&E Regulation 19 contained in the submittal we received on 
September 23, 2008, and as revised by the submittal we received on 
August 3, 2010. We are proposing to approve the portions of APC&E 
Commission Regulation 19, chapter 15, which we received on September 
23, 2008, and as revised on August 3, 2010, that are consistent with 
the portions of the Arkansas RH SIP we are proposing to approve and we 
are proposing to disapprove the portions that are consistent with other 
portions of the Arkansas RH SIP we are proposing to disapprove. We are 
proposing to partially approve and partially disapprove the State's LTS 
because the LTS only partially satisfies the requirements under section 
51.308(d)(3), and a portion of it relies on portions of the RH SIP we 
are proposing to disapprove.

[[Page 64188]]

    We are proposing to disapprove the reasonable progress goals (RPGs) 
under section 51.308(d)(1) because Arkansas did not consider the 
factors that states are required to consider in establishing RPGs under 
the CAA and section 51.308(d)(1)(A).
    Under the CAA,\1\ we must, within 24 months following a final 
disapproval, either approve a SIP or promulgate a Federal 
Implementation Plan (FIP). At this time, we are not proposing a FIP for 
the portions of the Arkansas RH SIP we are proposing to disapprove 
because ADEQ has expressed its intent to revise the Arkansas RH SIP by 
correcting the deficiencies we have identified in this proposal. We are 
electing to not propose a FIP at this time in order to provide Arkansas 
time to correct these deficiencies.
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    \1\ CAA section 110(c)(1).
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B. Interstate Transport and Visibility

    We are proposing to partially approve and partially disapprove a 
portion of the SIP revision we received from the State of Arkansas on 
April 2, 2008, for the purpose of addressing the ``good neighbor'' 
provisions of the CAA section 110(a)(2)(D)(i) for the 1997 8-hour ozone 
NAAQS and the PM2.5 NAAQS. Section 110(a)(2)(D)(i)(II) of 
the Act 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 whichwill * * * 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 
the ``good neighbor'' provisions of section 110 of the Act described 
above as requiring states to include in their SIPs either measures to 
prohibit emissions that would interfere with the reasonable progress 
goals set to protect Class I areas in other states, or a demonstration 
that emissions from Arkansas sources and activities will not have the 
prohibited impacts on other states' existing SIPs.
    Arkansas stated in its April 2, 2008 submittal that it is relying 
on the Arkansas RH Rule, the APC&E Commission Regulation 19, Chapter 
15, to satisfy the requirements of section 110(a)(2)(D)(i)(II) that 
emissions from Arkansas sources not interfere with measures required in 
the SIP of any other state under part C of the CAA to protect 
visibility. ADEQ also stated in its April 2, 2008 submittal 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 8-hour ozone and PM2.5 NAAQS until ADEQ 
submits and EPA approves Arkansas' RH SIP.
    In developing their Regional Haze SIP and RPGs, Arkansas and 
potentially impacted States collaborated through the Central Regional 
Air Planning (CENRAP) association. Each State developed its Regional 
Haze Plans and RPGs based on the CENRAP modeling. The CENRAP modeling 
was based in part on the emissions reductions each state intended to 
achieve by 2018. In the case of Arkansas, some of the emissions 
reductions included in the modeling, and thus relied upon by other 
States, were from BART controls on Arkansas subject to BART sources. In 
the State's September 27, 2011 supplemental submission, ADEQ clarified 
that the base year modeling inventory used by CENRAP in the 2002 base 
case modeling was prepared by the CENRAP Modeling Workgroup and its 
consultants, and was derived primarily from the 2002 National Emissions 
Inventory (NEI). ADEQ also clarified that it provided the CENRAP 
Modeling Workgroup with the controlled BART source emission limits 
contained in the State's RH Rule, the APC&E Commission Regulation 19, 
Chapter 15, for inclusion in the CENRAP's 2018 future case modeling. 
The State's RH Rule became effective October 15, 2007, and incorporates 
BART requirements for Arkansas' subject to BART sources. The current 
language of the regulation requires Arkansas' subject to BART sources 
to comply with BART requirements no later than five years after EPA 
approval of the RH SIP or 6 years after the effective date of the 
regulation, whichever is first. However, on March 26, 2010, the 
Arkansas Pollution Control and Ecology Commission, the environmental 
policy-making body for Arkansas, granted all Arkansas subject to BART 
sources a variance from the compliance deadline imposed by the State's 
RH Rule, such that these sources are now required to comply with BART 
requirements no later than 5 years after EPA approval of the RH SIP. 
Compliance with these BART requirements will ensure that Arkansas 
obtains its share of the emission reductions relied upon by other 
states to meet the RPGs for their Class I areas. Since compliance of 
Arkansas' subject to BART sources with BART requirements is dependent 
upon our approval of the RH SIP, and since we are proposing to 
disapprove the portion of the RH SIP which includes some of Arkansas' 
BART determinations, a portion of the emission reductions committed to 
by Arkansas and relied upon by other states will not be realized and, 
as a consequence, Arkansas' emissions will interfere with other states' 
SIPs to protect visibility. Therefore, we are proposing to partially 
approve and partially disapprove the portion of the Arkansas Interstate 
Transport SIP submittal that addresses the visibility requirement of 
section 110(a)(2)(D)(i)(II) that emissions from Arkansas sources not 
interfere with measures required in the SIP of any other state under 
part C of the CAA to protect visibility.

II. What is the background for our proposed actions?

A. Regional Haze

    RH is visibility impairment that is produced by a multitude of 
sources and activities which are located across a broad geographic area 
and emit fine particles (PM2.5) (e.g., sulfates, nitrates, 
organic carbon, elemental carbon, and soil dust) and their precursors 
(e.g., SO2, nitrogen oxides (NOX), and in some 
cases, ammonia (NH3) and volatile organic compounds (VOCs)). 
Fine particle precursors react in the atmosphere to form 
PM2.5 (e.g., sulfates, nitrates, organic carbon, elemental 
carbon, and soil dust), which also impair visibility by scattering and 
absorbing light. Visibility impairment reduces the clarity, color, and 
visible distance that one can see. PM2.5 also can 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 park and 
wilderness areas. The average visual range \2\ 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. 
64 FR 35714, 35715 (July 1, 1999). 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

[[Page 64189]]

that would exist under estimated natural conditions. Id.
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    \2\ 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 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, 
impairment of visibility in mandatory Class I Federal areas \3\ which 
impairment results from man-made air pollution.'' CAA Sec.  169A(a)(1). 
The terms ``impairment of visibility'' and ``visibility impairment'' 
are defined in the Act to include a reduction in visual range and 
atmospheric discoloration. Id. section 169A(g)(6). In 1980, we 
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'' (RAVI). 45 FR 80084 (December 2, 1980). These regulations 
represented the first phase in addressing visibility impairment. We 
deferred action on RH that emanates from a variety of sources until 
monitoring, modeling and scientific knowledge about the relationships 
between pollutants and visibility impairment improved.
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    \3\ 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. See CAA section 
162(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. See 
44 FR 69122, November 30, 1979. The extent of a mandatory Class I 
area includes subsequent changes in boundaries, such as park 
expansions. CAA section 162(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'' (FLM). See 
CAA section 302(i). When we use the term ``Class I area'' in this 
action, we mean a ``mandatory Class I Federal area.''
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    Congress added section 169B to the CAA in 1990 to address RH 
issues, and we promulgated regulations addressing RH in 1999. 64 FR 
35714 (July 1, 1999), codified at 40 CFR part 51, subpart P. The 
Regional Haze Rule (RHR) revised the existing visibility regulations to 
integrate into the regulations provisions addressing RH impairment and 
established a comprehensive visibility protection program for Class I 
areas. The requirements for RH, found at 40 CFR 51.308 and 51.309, are 
included in our visibility protection regulations at 40 CFR 51.300-309. 
Some of the main elements of the RH requirements are summarized in 
section III. The requirement to submit a RH SIP applies to all 50 
states, the District of Columbia and the Virgin Islands.\4\ States were 
required to submit the first implementation plan addressing RH 
visibility impairment no later than December 17, 2007. 40 CFR 
51.308(b). We received the Arkansas RH SIP on September 23, 2008.
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    \4\ Albuquerque/Bernalillo County in New Mexico must also submit 
a regional haze SIP to completely satisfy the requirements of 
section 110(a)(2)(D) of the CAA for the entire State of New Mexico 
under the New Mexico Air Quality Control Act (section 74-2-4).
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B. Roles of Agencies in Addressing Regional Haze

    Successful implementation of the RH program will require long-term 
regional coordination among states, tribal governments and various 
federal agencies. As noted above, pollution affecting the air quality 
in Class I areas can be transported over long distances, even hundreds 
of kilometers. Therefore, to address effectively the problem of 
visibility impairment in Class I areas, states need to develop 
strategies in coordination with one another, taking into account the 
effect of emissions from one jurisdiction on the air quality in 
another.
    Because the pollutants that lead to RH can originate from sources 
located across broad geographic areas, we have encouraged the states 
and tribes across the United States to address visibility impairment 
from a regional perspective. Five regional planning organizations 
(RPOs) were developed to address RH and related issues. The RPOs first 
evaluated technical information to better understand how their states 
and tribes impact Class I areas across the country, and then pursued 
the development of regional strategies to reduce emissions of 
particulate matter (PM) and other pollutants leading to RH.
    The CENRAP is an organization of states, tribes, federal agencies 
and other interested parties that identifies RH and visibility issues 
and develops strategies to address them. CENRAP is one of the five RPOs 
across the U.S. and includes the states and tribal areas of Nebraska, 
Kansas, Oklahoma, Texas, Minnesota, Iowa, Missouri, Arkansas, and 
Louisiana.

C. The 1997 NAAQS for Ozone and PM2.5 and CAA 110(a)(2)(D)(i)

    On July 18, 1997, we promulgated new NAAQS for 8-hour ozone and for 
PM2.5. 62 FR 38652. Section 110(a)(1) of the CAA requires 
states to submit SIPs to address a new or revised NAAQS within 3 years 
after promulgation of such standards, or within such shorter period as 
we may prescribe. Section 110(a)(2) of the CAA lists the elements that 
such new SIPs must address, including section 110(a)(2)(D)(i), which 
pertains to the interstate transport of certain emissions. Thus, states 
were required to submit SIPs that satisfy the applicable requirements 
under sections 110(a)(1) and (2), including the requirements of section 
110(a)(2)(D)(i), by July 2000. States, including Arkansas, did not meet 
the statutory July 2000 deadline for submission of these SIPs. 
Accordingly, on April 25, 2005, EPA made findings of failure to submit, 
notifying all states, including Arkansas, of their failure to make the 
required SIP submission to address interstate transport under section 
110(a)(2)(D)(i). 70 FR 21147. This finding started a 24-month FIP clock 
under section 110(c). Pursuant to section 110(c), we are required to 
promulgate a FIP to address the applicable interstate transport 
requirements, unless the State makes the required submission and we 
fully approve such submission, within the 24-month period.
    On August 15, 2006, we issued our ``Guidance for State 
Implementation Plan (SIP) Submissions to Meet Current Outstanding 
Obligations Under Section 110(a)(2)(D)(i) for the 8-Hour Ozone and 
PM2.5 National Ambient Air Quality Standards'' (2006 
Guidance). We developed the 2006 Guidance to make recommendations to 
states for making submissions to meet the requirements of section 
110(a)(2)(D)(i) for the 1997 8-hour ozone standards and the 1997 
PM2.5 standards.
    As identified in the 2006 Guidance, the ``good neighbor'' 
provisions in section 110(a)(2)(D)(i) of the CAA require each state to 
submit a SIP that prohibits emissions that adversely affect another 
state in the ways contemplated in the statute. Section 110(a)(2)(D)(i) 
contains four distinct requirements related to the impacts of 
interstate transport. The SIP must prevent sources in the state from 
emitting pollutants in amounts which will: (1) Contribute significantly 
to nonattainment of the NAAQS in other states; (2) interfere with 
maintenance of the NAAQS in other states; (3) interfere with provisions 
to prevent significant deterioration of air quality in other states; or 
(4) interfere with efforts to protect visibility in other states. In 
this action, we only address the fourth element regarding visibility.
    The 2006 Guidance stated that states may make a simple SIP 
submission confirming that it is not possible at that time to assess 
whether there is any

[[Page 64190]]

interference with measures in the applicable SIP for another state 
designed to ``protect visibility'' for the 8-hour ozone and 
PM2.5 NAAQS until RH SIPs are submitted and approved. RH 
SIPs were required to be submitted by December 17, 2007. See 74 FR 2392 
(January 15, 2009).
    On April 2, 2008, we received a SIP revision from Arkansas to 
address the interstate transport provisions of CAA 110(a)(2)(D)(i) for 
the 1997 ozone and PM2.5 NAAQS. For the reasons discussed in 
section V of this proposed rulemaking, a portion of the emission 
reductions committed to by Arkansas and relied upon by other states 
will not be realized and Arkansas' emissions will interfere with other 
states' SIPs to protect visibility. Therefore, we are proposing to 
partially approve and partially disapprove the portion of the Arkansas 
Interstate Transport SIP submittal that addresses the requirement that 
emissions from Arkansas sources not interfere with measures required in 
the SIP of any other state to protect visibility. See CAA section 
110(a)(2)(D)(i)(II).
    We recognize that we have an outstanding obligation to promulgate a 
FIP for the portion of the Arkansas Interstate Transport SIP submittal 
we are proposing to disapprove. However, because we are not proposing a 
FIP for the portions of the Arkansas RH SIP we are proposing to 
disapprove at this time in order to provide Arkansas time to correct 
the deficiencies identified in this proposal, we are likewise not 
proposing a FIP at this time for the disapproved portion of the 
Arkansas Interstate Transport SIP. We believe it is appropriate to 
address the concerns with the Regional Haze SIP and the Interstate 
Transport SIP at the same time and it is appropriate, in this instance, 
to allow the state an opportunity to address the deficiencies we have 
identified in this proposed action before imposing a FIP. If we were to 
propose a FIP for the disapproved portion of the Arkansas Interstate 
Transport SIP without also proposing a FIP for the disapproved portions 
of the Arkansas RH SIP, this could potentially result in Arkansas' 
subject to BART sources being required to install two successive levels 
of control measures, the first in order to meet the requirements of 
section 110(a)(2)(D)(i), and the second in order to meet the 
requirements of the RH program. This would result in an inefficient use 
of resources by both the affected sources and us.

III. What are the requirements for regional haze SIPs?

    The following is a summary and basic explanation of the regulations 
covered under the RHR. See 40 CFR 51.308 for a complete listing of the 
regulations under which this SIP was evaluated.

A. The CAA and the Regional Haze Rule

    RH SIPs must assure reasonable progress towards the national goal 
of achieving natural visibility conditions in Class I areas. Section 
169A of the CAA and our implementing regulations require states to 
establish long-term strategies for making reasonable progress toward 
meeting this goal. Implementation plans must also give specific 
attention to certain stationary sources that were in existence on 
August 7, 1977, but were not in operation before August 7, 1962, and 
require these sources, where appropriate, to install BART controls for 
the purpose of eliminating or reducing visibility impairment. The 
specific RH SIP requirements are discussed in further detail below.

B. Determination of Baseline, Natural, and Current Visibility 
Conditions

    The RHR establishes the deciview (dv) as the principal metric for 
measuring visibility. See 70 FR 39104. This visibility metric expresses 
uniform changes in the degree of haze in terms of common increments 
across the entire range of visibility conditions, from pristine to 
extremely hazy conditions. Visibility is sometimes expressed in terms 
of the visual range, which is the greatest distance, in kilometers or 
miles, at which a dark object can just be distinguished against the 
sky. The deciview is a useful measure for tracking progress in 
improving visibility, because each deciview change is an equal 
incremental change in visibility perceived by the human eye. Most 
people can detect a change in visibility of one deciview.\5\
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    \5\ The preamble to the RHR provides additional details about 
the deciview. 64 FR 35714, 35725 (July 1, 1999).
---------------------------------------------------------------------------

    The deciview is used in expressing Reasonable Progress Goals (RPGs) 
(which are interim visibility goals towards meeting the national 
visibility goal), defining baseline, current, and natural conditions, 
and tracking changes in visibility. The RH SIPs must contain measures 
that ensure ``reasonable progress'' toward the national goal of 
preventing and remedying visibility impairment in Class I areas caused 
by man-made air pollution by reducing anthropogenic emissions that 
cause RH. The national goal is a return to natural conditions, i.e., 
man-made sources of air pollution would no longer impair visibility in 
Class I areas.
    To track changes in visibility over time at each of the 156 Class I 
areas covered by the visibility program (40 CFR 81.401-437), and as 
part of the process for determining reasonable progress, states must 
calculate the degree of existing visibility impairment at each Class I 
area at the time of each RH SIP submittal and periodically review 
progress every five years midway through each 10-year implementation 
period. To do this, the RHR requires states to determine the degree of 
impairment (in deciviews) for the average of the 20 percent least 
impaired (``best'') and 20 percent most impaired (``worst'') visibility 
days over a specified time period at each of their Class I areas. In 
addition, states must also develop an estimate of natural visibility 
conditions for the purpose of comparing progress toward the national 
goal. Natural visibility is determined by estimating the natural 
concentrations of pollutants that cause visibility impairment and then 
calculating total light extinction based on those estimates. We have 
provided guidance to states regarding how to calculate baseline, 
natural and current visibility conditions.\6\
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    \6\ Guidance for Estimating Natural Visibility Conditions Under 
the Regional Haze Rule, September 2003, EPA-454/B-03-005, available 
at http://www.epa.gov/ttncaaa1/t1/memoranda/rh_envcurhr_gd.pdf, 
(hereinafter referred to as ``our 2003 Natural Visibility 
Guidance''); and Guidance for Tracking Progress Under the Regional 
Haze Rule, (EPA-454/B-03-004, September 2003, available at http://www.epa.gov/ttncaaa1/t1/memoranda/rh_tpurhr_gd.pdf, (hereinafter 
referred to as our ``2003 Tracking Progress Guidance'').
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    For the first RH SIPs that were due by December 17, 2007, 
``baseline visibility conditions'' were the starting points for 
assessing ``current'' visibility impairment. Baseline visibility 
conditions represent the degree of visibility impairment for the 20 
percent least impaired days and 20 percent most impaired days for each 
calendar year from 2000 to 2004. Using monitoring data for 2000 through 
2004, states are required to calculate the average degree of visibility 
impairment for each Class I area, based on the average of annual values 
over the five-year period. The comparison of initial baseline 
visibility conditions to natural visibility conditions indicates the 
amount of improvement necessary to attain natural visibility, while the 
future comparison of baseline conditions to the then current conditions 
will indicate the amount of progress made. In general, the 2000-2004 
baseline period is considered the time from which improvement in 
visibility is measured.

[[Page 64191]]

C. Determination of Reasonable Progress Goals

    The vehicle for ensuring continuing progress towards achieving the 
natural visibility goal is the submission of a series of RH SIPs from 
the states that establish two RPGs (i.e., two distinct goals, one for 
the ``best'' and one for the ``worst'' days) for every Class I area for 
each (approximately) 10-year implementation period. See 70 FR 3915; see 
also 64 FR 35714. The RHR does not mandate specific milestones or rates 
of progress, but instead calls for states to establish goals that 
provide for ``reasonable progress'' toward achieving natural (i.e., 
``background'') visibility conditions. In setting RPGs, states must 
provide for an improvement in visibility for the most impaired days 
over the (approximately) 10-year period of the SIP, and ensure no 
degradation in visibility for the least impaired days over the same 
period. Id.
    States have significant discretion in establishing RPGs, but are 
required to consider the following factors established in section 169A 
of the CAA and in our RHR at 40 CFR 51.308(d)(1)(i)(A): (1) The costs 
of compliance; (2) the time necessary for compliance; (3) the energy 
and non-air quality environmental impacts of compliance; and (4) the 
remaining useful life of any potentially affected sources. States must 
demonstrate in their SIPs how these factors are considered when 
selecting the RPGs for the best and worst days for each applicable 
Class I area. States have considerable flexibility in how they take 
these factors into consideration, as noted in our Reasonable Progress 
Guidance \7\. In setting the RPGs, states must also consider the rate 
of progress needed to reach natural visibility conditions by 2064 
(referred to hereafter as the ``Uniform Rate of Progress (URP)'' and 
the emission reduction measures needed to achieve that rate of progress 
over the 10-year period of the SIP. Uniform progress towards 
achievement of natural conditions by the year 2064 represents a rate of 
progress, which states are to use for analytical comparison to the 
amount of progress they expect to achieve. In setting RPGs, each state 
with one or more Class I areas (``Class I State'') must also consult 
with potentially ``contributing states,'' i.e., other nearby states 
with emission sources that may be affecting visibility impairment at 
the Class I State's areas. 40 CFR 51.308(d)(1)(iv).
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    \7\ Guidance for Setting Reasonable Progress Goals under the 
Regional Haze Program, June 1, 2007, memorandum from William L. 
Wehrum, Acting Assistant Administrator for Air and Radiation, to EPA 
Regional Administrators, EPA Regions 1-10 (pp.4-2, 5-1).
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D. Best Available Retrofit Technology

    Section 169A of the CAA directs states to evaluate the use of 
retrofit controls at certain larger, often uncontrolled, older 
stationary sources with the potential to emit greater than 250 tons or 
more of any pollutant in order to address visibility impacts from these 
sources. Specifically, section 169A(b)(2)(A) of the Act requires states 
to revise their SIPs to contain such measures as may be necessary to 
make reasonable progress towards the natural visibility goal, including 
a requirement that certain categories of existing major stationary 
sources \8\ built between 1962 and 1977 procure, install, and operate 
the ``Best Available Retrofit Technology'' (BART), as determined by the 
state or us in the case of a plan promulgated under section 110(c) of 
the CAA. Under the RHR, States are directed to conduct BART 
determinations for such ``BART-eligible'' sources that may be 
anticipated to cause or contribute to any visibility impairment in a 
Class I area. Rather than requiring source-specific BART controls, 
states also have the flexibility to adopt an emissions trading program 
or other alternative program as long as the alternative provides 
greater reasonable progress towards improving visibility than BART.
---------------------------------------------------------------------------

    \8\ The set of ``major stationary sources'' potentially subject 
to BART are listed in CAA section 169A(g)(7).
---------------------------------------------------------------------------

    We promulgated regulations addressing RH in 1999, 64 FR 35714 (July 
1, 1999), codified at 40 CFR part 51, subpart P.\9\ These regulations 
require all states to submit implementation plans that, among other 
measures, contain either emission limits representing BART for certain 
sources constructed between 1962 and 1977, or alternative measures that 
provide for greater reasonable progress than BART. 40 CFR 51.308(e).
---------------------------------------------------------------------------

    \9\ In American Corn Growers Ass'n v. EPA, 291 F.3d 1 (D.C. Cir. 
2002), the U.S Court of Appeals for the District of Columbia Circuit 
issued a ruling vacating and remanding the BART provisions of the 
regional haze rule. In 2005, we issued BART guidelines to address 
the court's ruling in that case. See 70 FR 39104 (July 6, 2005).
---------------------------------------------------------------------------

    On July 6, 2005, we published the Guidelines for BART 
Determinations Under the Regional Haze Rule at Appendix Y to 40 CFR 
part 51 (``BART Guidelines'') to assist states in determining which of 
their sources should be subject to the BART requirements and in 
determining appropriate emission limits for each applicable source. 70 
FR 39104. In making a BART determination for a fossil fuel-fired 
electric generating plant with a total generating capacity in excess of 
750 megawatts (MW), a state must use the approach set forth in the BART 
Guidelines. A state is encouraged, but not required, to follow the BART 
Guidelines in making BART determinations for other types of sources.
    The process of establishing BART emission limitations can be 
logically broken down into three steps: first, states identify those 
sources which meet the definition of ``BART-eligible source'' set forth 
in 40 CFR 51.301 \10\; second, states determine whether such sources 
``emits any air pollutant which may reasonably be anticipated to cause 
or contribute to any impairment of visibility in any such area'' (a 
source which fits this description is ``subject to BART,'') and; third, 
for each source subject to BART, states then identify the appropriate 
type and the level of control for reducing emissions.
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    \10\ BART-eligible sources are those sources that have the 
potential to emit 250 tons or more of a visibility-impairing air 
pollutant, were put in place between August 7, 1962 and August 7, 
1977, and whose operations fall within one or more of 26 
specifically listed source categories.
---------------------------------------------------------------------------

    States must address all visibility-impairing pollutants emitted by 
a source in the BART determination process. The most significant 
visibility impairing pollutants are SO2, NOX, and 
PM. We have stated that states should use their best judgment in 
determining whether VOC or ammonia compounds impair visibility in Class 
I areas.
    Under the BART Guidelines, states may select an exemption threshold 
value for their BART modeling, below which a BART-eligible source would 
not be expected to cause or contribute to visibility impairment in any 
Class I area. The state must document this exemption threshold value in 
the SIP and must state the basis for its selection of that value. Any 
source with emissions that model above the threshold value would be 
subject to a BART determination review. The BART Guidelines acknowledge 
varying circumstances affecting different Class I areas. States should 
consider the number of emission sources affecting the Class I areas at 
issue and the magnitude of the individual sources' impacts. Any 
exemption threshold set by the state should not be higher than 0.5 dv. 
See also 40 CFR part 51, Appendix Y, section III.A.1.
    In their SIPs, states must identify potential BART sources, 
described as ``BART-eligible sources'' in the RHR, and document their 
BART control determination analyses. The term ``BART-eligible source'' 
used in the

[[Page 64192]]

BART Guidelines means the collection of individual emission units at a 
facility that together comprises the BART-eligible source. In making 
BART determinations, section 169A(g)(2) of the CAA requires that states 
consider the following factors: (1) The costs of compliance; (2) the 
energy and non-air 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. States are free to determine the weight and 
significance to be assigned to each factor. See 40 CFR 
51.308(e)(1)(ii).
    A RH SIP must include source-specific BART emission limits and 
compliance schedules for each source subject to BART. Once a state has 
made its BART determination, the BART controls must be installed and in 
operation as expeditiously as practicable, but no later than five years 
after the date of our approval of the RH SIP. CAA section 169(g)(4) and 
40 CFR 51.308(e)(1)(iv). In addition to what is required by the RHR, 
general SIP requirements mandate that the SIP must also include all 
regulatory requirements related to monitoring, recordkeeping, and 
reporting for the BART controls on the source. See CAA section 110(a). 
As noted above, the RHR allows states to implement an alternative 
program in lieu of BART so long as the alternative program can be 
demonstrated to achieve greater reasonable progress toward the national 
visibility goal than would BART.

E. Long-Term Strategy (LTS)

    Consistent with the requirement in section 169A(b) of the CAA that 
states include in their regional haze SIP a 10 to 15 year strategy for 
making reasonable progress, Section 51.308(d)(3) of the RHR requires 
that states include a LTS in their RH SIPs. The LTS is the compilation 
of all control measures a state will use during the implementation 
period of the specific SIP submittal to meet any applicable RPGs. The 
LTS must include ``enforceable emissions limitations, compliance 
schedules, and other measures as necessary to achieve the reasonable 
progress goals'' for all Class I areas within, or affected by emissions 
from, the state. 40 CFR 51.308(d)(3).
    When a state's emissions are reasonably anticipated to cause or 
contribute to visibility impairment in a Class I area located in 
another state, the RHR requires the impacted state to coordinate with 
the contributing states in order to develop coordinated emissions 
management strategies. 40 CFR 51.308(d)(3)(i). Also, a state with a 
Class I area impacted by emissions from another state must consult with 
such contributing state, (id.) and must also demonstrate that it has 
included in its SIP all measures necessary to obtain its share of 
emission reductions needed to meet the reasonable progress goals for 
the Class I area. Id. at (d)(3)(ii). In such cases, the contributing 
state must demonstrate that it has included, in its SIP, all measures 
necessary to obtain its share of the emission reductions needed to meet 
the RPGs for the Class I area. The RPOs have provided forums for 
significant interstate consultation, but additional consultations 
between states may be required to sufficiently address interstate 
visibility issues. This is especially true where two states belong to 
different RPOs.
    States should consider all types of anthropogenic sources of 
visibility impairment in developing their LTS, including stationary, 
minor, mobile, and area sources. At a minimum, states must describe how 
each of the following seven factors listed below are taken into account 
in developing their LTS: (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 RPG; 
(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; (7) the 
anticipated net effect on visibility due to projected changes in point, 
area, and mobile source emissions over the period addressed by the LTS. 
40 CFR 51.308(d)(3)(v).

F. Coordinating Regional Haze and Reasonably Attributable Visibility 
Impairment

    As part of the RHR, we revised 40 CFR 51.306(c) regarding the LTS 
for RAVI to require that the RAVI plan must provide for a periodic 
review and SIP revision not less frequently than every three years 
until the date of submission of the state's first plan addressing RH 
visibility impairment, which was due December 17, 2007, in accordance 
with 40 CFR 51.308(b) and (c). On or before this date, the state must 
revise its plan to provide for review and revision of a coordinated LTS 
for addressing RAVI and RH, and the state must submit the first such 
coordinated LTS with its first RH SIP. Future coordinated LTS and 
periodic progress reports evaluating progress towards RPGs, must be 
submitted consistent with the schedule for SIP submission and periodic 
progress reports set forth in 40 CFR 51.308(f) and 51.308(g), 
respectively. The periodic review of a state's LTS must report on both 
RH and RAVI impairment and must be submitted to us as a SIP revision.

G. Monitoring Strategy and Other SIP Requirements

    Section 51.308(d)(4) of the RHR includes the requirement for a 
monitoring strategy for measuring, characterizing, and reporting of RH 
visibility impairment that is representative of all mandatory Class I 
Federal areas within the state. The strategy must be coordinated with 
the monitoring strategy required in section 51.305 for RAVI. Compliance 
with this requirement may be met through ``participation'' in the 
Interagency Monitoring of Protected Visual Environments (IMPROVE) 
network, i.e., review and use of monitoring data from the network. The 
monitoring strategy is due with the first RH SIP, and it must be 
reviewed every five (5) years. The monitoring strategy must also 
provide for additional monitoring sites if the IMPROVE network is not 
sufficient to determine whether RPGs will be met.
    The SIP must also provide for the following:
     Procedures for using monitoring data and other information 
in a state with mandatory Class I areas to determine the contribution 
of emissions from within the state to RH visibility impairment at Class 
I areas both within and outside the state;
     Procedures for using monitoring data and other information 
in a state with no mandatory Class I areas to determine the 
contribution of emissions from within the state to RH visibility 
impairment at Class I areas in other states;
     Reporting of all visibility monitoring data to the 
Administrator at least annually for each Class I area in the state, and 
where possible, in electronic format;
     Developing a statewide inventory of emissions of 
pollutants that are reasonably anticipated to cause or contribute to 
visibility impairment in any Class I area. The inventory must include 
emissions for a baseline year, emissions for the most recent year for 
which data are available, and estimates of future projected emissions. 
A state must also make a commitment to update the inventory 
periodically; and

[[Page 64193]]

     Other elements, including reporting, recordkeeping, and 
other measures necessary to assess and report on visibility.
    The RHR requires control strategies to cover an initial 
implementation period extending to the year 2018, with a comprehensive 
reassessment and revision of those strategies, as appropriate, every 10 
years thereafter. Periodic SIP revisions must meet the core 
requirements of section 51.308(d) with the exception of BART. The 
requirement to evaluate sources for BART applies only to the first RH 
SIP. Facilities subject to BART must continue to comply with the BART 
provisions of section 51.308(e), as noted above. Periodic SIP revisions 
will assure that the statutory requirement of reasonable progress will 
continue to be met.

H. Consultation With States and Federal Land Managers

    The RHR requires that states consult with Federal Land Managers 
(FLMs) before adopting and submitting their SIPs. 40 CFR 51.308(i). 
States must provide FLMs an opportunity for consultation, in person and 
at least 60 days prior to holding any public hearing on the SIP. This 
consultation must include the opportunity for the FLMs to discuss their 
assessment of impairment of visibility in any Class I area and to offer 
recommendations on the development of the RPGs and on the development 
and implementation of strategies to address visibility impairment. 
Further, a state must include in its SIP a description of how it 
addressed any comments provided by the FLMs. Finally, a SIP must 
provide procedures for continuing consultation between the state and 
FLMs regarding the state's visibility protection program, including 
development and review of SIP revisions, five-year progress reports, 
and the implementation of other programs having the potential to 
contribute to impairment of visibility in Class I areas.

IV. Our Analysis of Arkansas' Regional Haze SIP

    On September 23, 2008, we received a RH SIP revision from the State 
of Arkansas for approval into the Arkansas SIP. We received a 
supplemental submission to the RH SIP revision on September 27, 2011. 
In addition, we received a submittal revising several chapters of APC&E 
Commission Regulation 19, including Chapter 15 (Arkansas' RH Rule), on 
August 3, 2010. In this proposed rulemaking, the only portions of the 
August 3, 2010, submittal we are proposing to take action on are those 
addressing Chapter 15 of APC&E Commission Regulation 19. The following 
is a discussion of our evaluation of these submissions. The parts of 
the submittals that are interrelated are discussed together, in order 
to provide the reader with a more ready understanding of our 
evaluation. See the Technical Support Document (TSD) for this proposal 
for a step-wise evaluation of ADEQ's submissions in the order in which 
the regulations appear in 40 CFR 51.308, and a more comprehensive 
technical analysis.\11\
---------------------------------------------------------------------------

    \11\ The TSD can be found in the docket for this proposal at 
http://www.regulations.gov. The docket number is EPA-R06-OAR-2008-
0727.
---------------------------------------------------------------------------

A. Affected Class I Areas

    In accordance with 40 CFR 51.308(d), ADEQ has identified two Class 
I areas within its borders, the Caney Creek Wilderness Area (Caney 
Creek) in Ouachita National Forest and the Upper Buffalo Wilderness 
Area (Upper Buffalo) in the Ozark National Forest. ADEQ is responsible 
for developing RPGs for these two Class I areas. ADEQ has also 
determined that Arkansas emissions cause and contribute to visibility 
impairment at the two Class I areas in Missouri: Hercules Glades 
Wilderness Area (Hercules Glades) and Mingo National Wildlife Refuge 
(Mingo). The TSD for the CENRAP Emissions and Air Quality Modeling to 
Support Regional Haze State Implementation (TSD for CENRAP modeling) 
demonstrates Arkansas sources are responsible for a visibility 
extinction of approximately 7.1 inverse megameters \12\ 
(Mm-1) at Hercules Glades and for a visibility extinction of 
approximately 4.95 Mm-1 at Mingo on the worst 20% days for 
2002.\13\ As discussed in section IV.C.3 of this proposed rulemaking, 
ADEQ consulted with the appropriate state air quality agency in 
Missouri to reach an agreement on whether it is necessary for Arkansas 
to commit to additional emission reductions that would help Missouri 
achieve its RPGs for Hercules Glades and Mingo.
---------------------------------------------------------------------------

    \12\ An inverse megameter is the direct measurement unit for 
visibility impairment data. It is the amount of light scattered and 
absorbed as it travels over a distance of one million meters. 
Deciviews (dv) can be calculated from extinction data as follows: dv 
= 10 x ln (bext(Mm-1)/10), where dv stands for 
``deciviews;'' ln stands for ``natural logarithm;'' and 
bext stands for ``extinction value.''
    \13\ See Appendix E of the TSD for CENRAP Emissions and Air 
Quality Modeling to Support Regional Haze State Implementation, 
found in Appendix 8.1 of the Arkansas RH SIP.
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B. Determination of Baseline, Natural and Current Visibility Conditions

    As required by section 51.308(d)(2)(i) of the RHR and in accordance 
with EPA's 2003 Natural Visibility Guidance,\14\ ADEQ calculated 
baseline/current \15\ and natural visibility conditions for its two 
Class I areas, Caney Creek and Upper Buffalo, on the most impaired and 
least impaired days, as summarized below (and further described in the 
TSD).
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    \14\ Guidance for Estimating Natural Visibility Conditions Under 
the Regional Haze Rule, EPA-454/B-03-005, September 2003.
    \15\ Since this is the first RH SIP submittal, the calculated 
baseline visibility condition and the current visibility condition 
will be the same. It is expected that subsequent RH SIP submittals 
will reflect different calculated numbers for baseline and current 
visibility conditions due to the change in conditions.
---------------------------------------------------------------------------

1. Estimating Natural Visibility Conditions
    Natural background visibility, as defined in EPA's 2003 Natural 
Visibility Guidance, is estimated by calculating the expected light 
extinction using default estimates of natural concentrations of fine 
particle components adjusted by site-specific estimates of humidity. 
This calculation uses the IMPROVE equation, which is a formula for 
estimating light extinction from the estimated natural concentrations 
of fine particle components (or from components measured by the IMPROVE 
monitors). As documented in EPA's 2003 Natural Visibility Guidance, EPA 
allows states to use ``refined'' or alternative approaches to 2003 EPA 
guidance to estimate the values that characterize the natural 
visibility conditions of Class I areas. One alternative approach is to 
develop and justify the use of alternative estimates of natural 
concentrations of fine particle components. Another alternative is to 
use the ``new IMPROVE equation'' that was adopted for use by the 
IMPROVE Steering Committee in December 2005 \16\. The purpose of this 
refinement to the ``old IMPROVE equation'' is to provide more accurate 
estimates of the various factors that affect the calculation of light 
extinction.
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    \16\ The IMPROVE program is a cooperative measurement effort 
governed by a steering committee composed of representatives from 
Federal agencies (including representatives from EPA and the FLMs) 
and RPOs. The IMPROVE monitoring program was established in 1985 to 
aid the creation of Federal and State implementation plans for the 
protection of visibility in Class I areas. One of the objectives of 
IMPROVE is to identify chemical species and emission sources 
responsible for existing anthropogenic visibility impairment. The 
IMPROVE program has also been a key participant in visibility-
related research, including the advancement of monitoring 
instrumentation, analysis techniques, visibility modeling, policy 
formulation and source attribution field studies.
---------------------------------------------------------------------------

    ADEQ opted to use the new IMPROVE equation to calculate the 
``refined'' natural visibility conditions. This is an acceptable 
approach under our 2003

[[Page 64194]]

Natural Visibility Guidance. For Caney Creek, ADEQ used the new IMPROVE 
equation to calculate the ``refined'' natural visibility value for the 
20 percent worst days to be 11.58 deciviews and for the 20 percent best 
days to be 4.23 deciviews. For Upper Buffalo, ADEQ used the new IMPROVE 
equation to calculate the ``refined'' natural visibility value for the 
20 percent worst days to be 11.57 deciviews and for the 20 percent best 
days to be 4.18 deciviews. We have reviewed ADEQ's estimates of the 
natural visibility conditions for Caney Creek and Upper Buffalo and are 
proposing to find these acceptable using the new IMPROVE equation.
    The new IMPROVE equation takes into account the most recent review 
of the science \17\ and it accounts for the effect of particle size 
distribution on light extinction efficiency of sulfate 
(SO4), nitrate (NO3), and organic carbon. It also 
adjusts the mass multiplier for organic carbon (particulate organic 
matter) by increasing it from 1.4 to 1.8. New terms are added to the 
equation to account for light extinction by sea salt and light 
absorption by gaseous nitrogen dioxide. Site-specific values are used 
for Rayleigh scattering (scattering of light due to atmospheric gases) 
to account for the site-specific effects of elevation and temperature. 
Separate relative humidity enhancement factors are used for small and 
large size distributions of ammonium sulfate and ammonium nitrate and 
for sea salt. The terms for the remaining contributors, elemental 
carbon (light-absorbing carbon), fine soil, and coarse mass terms, do 
not change between the original and new IMPROVE equations.
---------------------------------------------------------------------------

    \17\ The science behind the revised IMPROVE equation is 
summarized in Appendix 5.1 of the Arkansas RH SIP and in numerous 
published papers. See for example: Hand, J.L., and Malm, W.C., 2006, 
Review of the IMPROVE Equation for Estimating Ambient Light 
Extinction Coefficients--Final Report. March 2006. Prepared for 
Interagency Monitoring of Protected Visual Environments (IMPROVE), 
Colorado State University, Cooperative Institute for Research in the 
Atmosphere, Fort Collins, Colorado, available at http://vista.cira.colostate.edu/improve/publications/GrayLit/016_IMPROVEeqReview/IMPROVEeqReview.htm and Pitchford, Marc., 2006, 
Natural Haze Levels II: Application of the New IMPROVE Algorithm to 
Natural Species Concentrations Estimates. Final Report of the 
Natural Haze Levels II Committee to the RPO Monitoring/Data Analysis 
Workgroup. September 2006, available at http://vista.cira.colostate.edu/improve/Publications/GrayLit/029_NaturalCondII/naturalhazelevelsIIreport.ppt.
---------------------------------------------------------------------------

2. Estimating Baseline Visibility Conditions
    As required by section 51.308(d)(2)(i) of the RHR and in accordance 
with EPA's 2003 Natural Visibility Guidance \18\, ADEQ calculated 
baseline visibility conditions for Caney Creek and Upper Buffalo. The 
baseline condition calculation begins with the calculation of light 
extinction, using the IMPROVE equation. The IMPROVE equation sums the 
light extinction \19\ resulting from individual pollutants, such as 
sulfates and nitrates. As with the natural visibility conditions 
calculation, ADEQ chose to use the new IMPROVE equation.
---------------------------------------------------------------------------

    \18\ Guidance for Estimating Natural Visibility Conditions Under 
the Regional Haze Rule, EPA-454/B-03-005, September 2003.
    \19\ The amount of light lost as it travels over one million 
meters. The haze index, in units of deciviews (dv), is calculated 
directly from the total light extinction, bext expressed 
in inverse megameters (Mm-1), as follows: HI = 10 
ln(bext/10).
---------------------------------------------------------------------------

    The period for establishing baseline visibility conditions is 2000-
2004, and baseline conditions must be calculated using available 
monitoring data. 40 CFR 51.308(d)(2). The IMPROVE monitor at Caney 
Creek was installed between 2000 and 2002, and therefore ADEQ used 
visibility data for 2002-2004. The resulting baseline conditions 
represent an average for 2002-2004. ADEQ calculated the baseline 
conditions at Caney Creek as 26.36 deciviews on the 20 percent worst 
days, and 11.24 deciviews on the 20 percent best days. In calculating 
the baseline conditions at Upper Buffalo, ADEQ used visibility data for 
2000-2004. ADEQ calculated the baseline conditions at Upper Buffalo as 
26.27 deciviews on the 20 percent worst days, and 11.71 deciviews on 
the 20 percent best days. We have reviewed ADEQ's estimation of 
baseline visibility conditions at Caney Creek and Upper Buffalo and are 
proposing to find these estimates acceptable.
3. Natural Visibility Impairment
    To address 40 CFR 51.308(d)(2)(iv)(A), ADEQ also calculated the 
number of deciviews by which baseline conditions exceed natural 
visibility conditions for the best and worst days at Caney Creek and 
Upper Buffalo. At Caney Creek for the 20 percent worst days, ADEQ 
calculated the number of deciviews by which baseline conditions exceed 
natural visibility conditions to be 14.78 dv (baseline of 26.36 dv-
natural conditions of 11.58 dv). For the 20 percent best days at Caney 
Creek, the baseline conditions exceed natural visibility conditions by 
7.01 dv (baseline of 11.24 dv-natural conditions of 4.23 dv). At Upper 
Buffalo for the 20% worst days, ADEQ calculated the number of deciviews 
by which baseline conditions exceed natural visibility conditions to be 
14.7 dv (baseline of 26.27 dv-natural conditions of 11.57 dv). For the 
20 percent best days at Upper Buffalo, the baseline conditions exceed 
natural visibility conditions by 7.53 dv (baseline of 11.71 dv-natural 
conditions of 4.18 dv). We have reviewed ADEQ's estimates of the 
natural visibility impairment at Caney Creek and Upper Buffalo and are 
proposing to find these estimates acceptable.
4. Uniform Rate of Progress
    In setting the RPGs, ADEQ analyzed and determined the Uniform Rate 
of Progress (URP) needed to reach natural visibility conditions by the 
year 2064. In so doing, ADEQ compared the baseline visibility 
conditions to the natural visibility conditions in Caney Creek and 
compared the baseline visibility conditions to the natural visibility 
conditions in Upper Buffalo (as described above), and determined the 
uniform rate of progress needed in order to attain natural visibility 
conditions by 2064. ADEQ constructed the URP consistent with the 
requirements of the RHR and our 2003 Tracking Progress Guidance by 
plotting a straight graphical line from the baseline level of 
visibility impairment for 2000-2004 to the level of visibility 
conditions representing no anthropogenic impairment in 2064 for Caney 
Creek and for Upper Buffalo.
    Using a baseline visibility value of 26.36 dv and a ``refined'' 
natural visibility value of 11.58 dv for the 20 percent worst days for 
Caney Creek, ADEQ calculated the URP to be approximately 0.246 dv per 
year. This results in a total reduction of 14.78 dv that are necessary 
to reach the natural visibility condition of 11.58 dv in 2064 for Caney 
Creek. The URP results in a visibility improvement of 3.45 dv for Caney 
Creek for the period covered by this SIP revision submittal (up to and 
including 2018).
    Using a baseline visibility value of 26.27 dv and a ``refined'' 
natural visibility value of 11.57 dv for the 20 percent worst days for 
Upper Buffalo, ADEQ calculated the URP to be approximately 0.245 dv per 
year. This results in a total reduction of 14.70 dv that are necessary 
to reach the natural visibility condition of 11.57 dv in 2064 for Upper 
Buffalo. The URP results in a visibility improvement of 3.43 dv for 
Upper Buffalo for the period covered by this SIP revision submittal (up 
to and including 2018).

[[Page 64195]]

                                  Table 1--Summary of Uniform Rate of Progress
----------------------------------------------------------------------------------------------------------------
           Visibility metric                         Caney Creek                         Upper Buffalo
----------------------------------------------------------------------------------------------------------------
Baseline Conditions....................  26.36 dv...........................  26.27 dv.
Natural Visibility.....................  11.58 dv...........................  11.57 dv.
Total Improvement by 2064..............  14.78 dv...........................  14.70 dv.
Improvement for this SIP by 2018.......  3.45 dv............................  3.43 dv.
Uniform Rate of Progress...............  0.246 dv/year......................  0.245 dv/year.
----------------------------------------------------------------------------------------------------------------

    We are proposing to find that ADEQ has appropriately calculated the 
URP and has satisfied the requirement in section 51.308(d)(1)(i)(B).

C. Evaluation of Arkansas' Reasonable Progress Goals

    We are proposing to disapprove Arkansas's Reasonable Progress Goals 
because the State did not establish the RPGs for Caney Creek and Upper 
Buffalo in accordance with the requirements of the RHR. As a result, 
ADEQ's RH SIP fails to ensure adequate reasonable progress toward 
meeting the national visibility goal. Section 169A(g)(1) of the CAA and 
section 51.308(d)(1)(i)(A) of the RHR require states to take into 
account certain factors in establishing its reasonable progress goals 
and to demonstrate how those factors were taken into consideration in 
selecting the goals. ADEQ did not do so. We do note that ADEQ did 
consult with other states regarding the development of RPGs in 
accordance with the RHR, but this is not enough for us to approve the 
RPGs.
1. Establishment of the Reasonable Progress Goal
    ADEQ adopted the CENRAP modeled 2018 visibility conditions as the 
RPGs for Caney Creek and Upper Buffalo Class I areas. ADEQ established 
a RPG of 22.48 dv for Caney Creek for 2018 for the 20% worst days. This 
represents a 3.88 dv improvement over a baseline of 26.36 dv. For Upper 
Buffalo, ADEQ established a RPG of 22.52 dv for 2018 for the 20% worst 
days, which represents a 3.75 dv improvement over a baseline of 26.27 
dv. ADEQ calculated that under its RPGs, it would attain natural 
visibility conditions in 2062 for Caney Creek and 2063 for Upper 
Buffalo. The CENRAP's projections for 2018 for the 20% best days for 
Caney Creek and Upper Buffalo, which represent ADEQ's RPGs for the 20% 
best days, are shown in Figures 10.4 and 10.6 of the RH SIP and in 
Appendix D to the TSD for CENRAP Emissions and Air Quality Modeling to 
Support RH State Implementation.\20\ A comparison of ADEQ's RPGs to 
baseline conditions on the least impaired days shows that control of 
Arkansas sources will result in no degradation in visibility conditions 
in the first planning period. The CENRAP modeling shows that for the 
20% best days, there would be a 0.89 dv and a 0.91 dv improvement in 
visibility from the baseline for Caney Creek and Upper Buffalo, 
respectively.
---------------------------------------------------------------------------

    \20\ The TSD for CENRAP Emissions and Air Quality Modeling to 
Support RH State Implementation is found in Appendix 8.1 of the 
Arkansas RH SIP.
---------------------------------------------------------------------------

    ADEQ established RPGs that ensure no degradation in visibility for 
the least impaired days. See 40 CFR 51.308(d)(1). However, in setting 
its RPGs for its Class I areas for the 20% worst days, the State relied 
on the fact that the emission reductions from BART and from the 
implementation of other requirements of the CAA would result in RPGs 
that provided for a slightly greater rate of improvement in visibility 
than would be needed to attain the URP. Based on this fact, ADEQ did 
not undertake any further analysis. As discussed below, we do not 
believe this provides sufficient analysis under section 169A of the CAA 
and our RHR, and discuss it further in the next section.
2. ADEQ's Reasonable Progress ``Four Factor'' Analysis
    In establishing a RPG for a Class I Federal area located within a 
state, the State is required by CAA Sec.  169A(g)(1) and 40 CFR 
51.308(d)(1)(i)(A) to ``[c]onsider 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, and include a demonstration showing how these factors 
were taken into consideration in selecting the goal.'' In addition to 
this explicit statutory requirement, the RHR also establishes an 
analytical requirement to ensure that each State considers carefully 
the suite of emission reduction measures necessary to attain the URP. 
The RHR provides that EPA will consider both the State's consideration 
of the four factors in section 51.308(d)(1)(i)(A) and its analysis of 
the URP ``[i]n determining whether the State's goal for visibility 
improvement provides for reasonable progress.'' 40 CFR 
51.308(d)(1)(iii). As explained in the preamble to the RHR, the URP 
analysis was adopted to ensure that States use a common analytical 
framework and to ensure an informed and equitable decision making 
process to ensure a transparent process that would, among other things, 
ensure that the public would be provided with the information necessary 
to understand the emission reductions needed, the costs of such 
measures, and other factors associated with improvements in visibility. 
64 FR at 35733. The preamble to the Rule (64 FR 35732) also makes clear 
that the URP does not establish a ``safe harbor'' for the State in 
setting its progress goals:

    If the State determines that the amount of progress identified 
through the [URP] analysis is reasonable based upon the statutory 
factors, the State should identify this amount of progress as its 
reasonable progress goal for the first long-term strategy, unless it 
determines that additional progress beyond this amount is also 
reasonable. If the State determines that additional progress is 
reasonable based on the statutory factors, the State should adopt 
that amount of progress as its goal for the first long-term 
strategy.

    In establishing its RPGs for 2018 for the 20% worst days, ADEQ 
relied on the improvements in visibility that are anticipated to result 
from federal, State, and local control programs that are either 
currently in effect or with mandated future-year emission reduction 
schedules that predate 2018, including BART emission limitations 
established by ADEQ. Based on the emissions reductions from these 
measures, CENRAP modeled the projected visibility conditions 
anticipated at each Class I area in 2018 and ADEQ used these results to 
establish RPGs.
    ADEQ argued that because this rate of progress, if sustained, will 
result in a return to natural visibility prior to 2064, no additional 
analysis was required and would be an unnecessary exercise. We 
consistently informed States, including Arkansas, throughout the 
regional haze development process that the above interpretation of the 
statute and our regulations is incorrect. ADEQ cannot rely solely on 
meeting the URP to justify

[[Page 64196]]

the conclusion that its goals provide for reasonable progress. We 
provided comments to ADEQ on the draft Arkansas RH SIP to that 
effect.\21\
---------------------------------------------------------------------------

    \21\ See Appendix 2.1 of the Arkansas RH SIP
---------------------------------------------------------------------------

    States do have discretion in setting RPGs, but are required to go 
beyond the URP analysis in establishing RPGs. ADEQ made no attempt to 
determine whether additional progress would be reasonable based on the 
statutory factors. It does not appear that such an analysis would have 
been an unnecessary exercise, as claimed by ADEQ. As discussed in 
section IV.D.2 of this proposed rulemaking, there are at least two 
point sources in Arkansas not subject to the BART requirements that 
contribute to visibility impairment at Arkansas' Class I areas. This 
conclusion is based on the information in the RH SIP indicating that 
these sources have predicted impacts exceeding the 0.5 dv threshold 
ADEQ used to determine whether BART sources contribute to visibility 
impairment. Given their contribution to visibility impairment, these 
two sources are potential candidates for emissions controls under 
reasonable progress, as may be other Arkansas point sources whose 
visibility impact was not evaluated by ADEQ. Also, as discussed in 
section IV.E.3 of this proposed notice, Arkansas sources are projected 
to remain significant contributors to visibility impairment in 2018 and 
thus providing further support that additional analysis should have 
been performed according to the statutory factors.
    Given that ADEQ did not provide an analysis that considered the 
four statutory factors under 40 CFR 51.308(d)(1)(i)(A) to evaluate the 
potential of controlling certain sources or source categories for 
addressing visibility impacts from man-made sources, it is not possible 
to assess whether any additional control measures for improving 
visibility are reasonable. Section 51.308(d)(1)(iii) requires that in 
determining whether the State's goal for visibility improvement 
provides for reasonable progress towards natural visibility conditions, 
the Administrator will evaluate the demonstrations developed by the 
State pursuant to paragraphs (d)(1)(i) and (d)(1)(ii) of this section. 
Consequently, for the reasons outlined above, we are proposing to find 
that Arkansas has not satisfied the requirements to establish 
reasonable progress goals under section 51.308(d)(1)(i)(A).
3. Reasonable Progress Consultation
    ADEQ worked with the Missouri Department of Natural Resources 
(MDNR) and CENRAP to jointly develop the consultation strategy. 
Consultations were held jointly by Arkansas and Missouri. ADEQ used 
CENRAP as the main vehicle for facilitating collaboration with FLMs and 
other states in developing its RH SIP. ADEQ was able to use CENRAP 
generated products, such as regional photochemical modeling results and 
visibility projections, and source apportionment modeling to assist in 
identifying neighboring states' contributions to the visibility 
impairment at Caney Creek and Upper Buffalo.
    ADEQ determined that in addition to Arkansas, the following states 
have a significant contribution to decreased visibility in one or both 
of Arkansas' Class I areas: Illinois, Indiana, Kentucky, Missouri, 
Ohio, Oklahoma, Tennessee, and Texas. ADEQ sent a letter dated February 
26, 2007, to these states, requesting that they participate in the 
consultation process for the Arkansas RH SIP. These states complied 
with ADEQ's request and participated in the consultation process for 
the Arkansas RH SIP. ADEQ and MDNR jointly conducted three 
consultations in the form of conference calls on April 3, May 11, and 
June 7, 2007. Participants in the consultation process included states 
and tribes, CENRAP and other Regional Planning Organizations (RPOs), 
EPA, and FLMs.
    At the three consultations held by ADEQ and MDNR, a URP was 
developed for each Class I area in Arkansas and Missouri (Caney Creek 
and Upper Buffalo in Arkansas, and Hercules Glades and Mingo in 
Missouri). The participating states also determined that regional 
modeling and other findings based on existing and proposed controls 
arising from local, state, and federal requirements indicated that the 
two Class I areas in Arkansas and the two Class I areas in Missouri are 
on the glidepath and are expected to meet the rate of progress goals 
for the first implementation period ending in 2018. ADEQ determined 
that additional emissions reductions from other States are not 
necessary to address visibility impairment at Caney Creek and the Upper 
Buffalo for the first implementation period ending in 2018, and all 
states participating in its consultations agreed with this. Therefore, 
we are proposing to find that Arkansas has satisfied the requirement 
under section 308(d)(1)(iv) to consult with other States which may 
reasonably be anticipated to cause or contribute to visibility 
impairment at Arkansas' two Class I areas.

D. Evaluation of Arkansas' BART Determinations

    Arkansas' RH Rule, APC&E Commission Regulation 19, chapter 15, was 
included in the Arkansas RH SIP submittal, and became effective on 
October 15, 2007. On August 3, 2010, we received a SIP revision from 
ADEQ containing amendments to several chapters of APC&E Commission 
Regulation 19, including Chapter 15. The revisions to Chapter 15 of 
APC&E Commission Regulation 19, contained in the August 3, 2010 
submittal, are mostly non-substantive amendments to the rule we 
received on September 23, 2008. Chapter 15 of Regulation 19 
incorporates by reference the definitions contained in section 40 CFR 
51.301 of the Act, as in effect on June 22, 2007. Chapter 15 also 
identifies the Arkansas BART-eligible sources, the subject to BART 
sources and their BART requirements, and the BART compliance 
provisions. The rules further provide that the source's air quality 
permit be revised to incorporate the resulting source-specific 
requirements. The State's RH Rule and our proposed action on it are 
discussed in section IV.D.4 of this proposed rulemaking.
    BART is an element of Arkansas' LTS for the first implementation 
period. As discussed in more detail in section III.D. of this preamble, 
the BART evaluation process consists of three components: (1) An 
identification of all the BART-eligible sources, (2) an assessment of 
whether those BART-eligible sources are in fact subject to BART and (3) 
a determination of any BART controls. ADEQ addressed these steps as 
follows:
1. Identification of BART-Eligible Sources
    The first step of a BART evaluation is to identify all the BART-
eligible sources within the state's boundaries. ADEQ identified the 
BART-eligible sources in Arkansas by utilizing the three eligibility 
criteria in the BART Guidelines (70 FR 39158) and our regulations (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 was in 
existence on August 6, 1977; and (3) potential emissions of any 
visibility-impairing pollutant from subject units are 250 tons or more 
per year. ADEQ initially screened its emissions inventory and 
permitting database to identify major facilities with emission units in 
one or more of the 26 BART source categories. Following this, ADEQ used 
its databases

[[Page 64197]]

and records to identify facilities in these source categories with 
potential emissions of 250 tons per year (tpy) or more of the following 
visibility impairing pollutants: sulfur dioxide (SO2), 
nitrogen dioxide (NOX), particulate matter equal to or 
smaller than ten microns (PM10), volatile organic compounds 
(VOC) or ammonia (NH3). Using its databases and records, 
ADEQ then determined which of these facilities had units that were in 
existence on August 7, 1977 and began operation after August 7, 1962. 
ADEQ contacted the sources, when necessary, to obtain or confirm this 
information. From this, ADEQ determined there are 18 facilities with 
BART-eligible units. Table 2 lists Arkansas' BART-eligible sources, as 
identified by Arkansas in Table 9.1 of the RH SIP:

                            Table 2--Facilities With BART-Eligible Units in Arkansas
----------------------------------------------------------------------------------------------------------------
        BART source category                Facility name                 County             Unit description
----------------------------------------------------------------------------------------------------------------
Fossil fuel-fired steam electric     AEP Flint Creek Power Plant  Benton................  Boiler
 plants of more than 250 MMBTU/hr
 heat input.
                                    ----------------------------------------------------------------------------
                                     AECC Carl E. Bailey          Woodruff..............  Boiler
                                      Generating.
                                    ----------------------------------------------------------------------------
                                     AECC John L. McClellan       Ouachita..............  Boiler
                                      Generating.
                                    ----------------------------------------------------------------------------
                                     Entergy Lake Catherine       Hot Spring............  Unit 4 Boiler
                                      Plant.
                                    ----------------------------------------------------------------------------
                                     Entergy Robert E. Ritchie    Phillips..............  Unit 2
                                      Plant.
                                    ----------------------------------------------------------------------------
                                     Entergy White Bluff Plant..  Jefferson.............  Unit 1
                                                                                         -----------------------
                                                                                          Unit 2
                                                                                         -----------------------
                                                                                          Auxiliary Boiler
----------------------------------------------------------------------------------------------------------------
Kraft pulp mills...................  Domtar Ashdown Mill........  Little River..........  No. 1 Power
                                                                                         -----------------------
                                                                                          No. 2 Power
                                    ----------------------------------------------------------------------------
                                     Delta Natural Kraft........  Jefferson.............  Recovery Boiler
                                    ----------------------------------------------------------------------------
                                     Evergreen Packaging/         Jefferson.............  No. 4 Recovery
                                      International.
                                    ----------------------------------------------------------------------------
                                     Georgia-Pacific Crossett     Ashley................  9A Boiler
                                      Mill.
                                    ----------------------------------------------------------------------------
                                     Green Bay Packaging........  Conway................  Recovery Boiler
                                    ----------------------------------------------------------------------------
                                     Potlatch Forest Products/    Desha.................  Power Boiler
                                      Clearwater.
----------------------------------------------------------------------------------------------------------------
Petroleum..........................  Lion Oil Company...........  Union.................  No. 7 Catalyst
----------------------------------------------------------------------------------------------------------------
Sulfur recovery....................  Albermarle Corporation       Columbia..............  Tail Gas
                                      South Plant.
----------------------------------------------------------------------------------------------------------------
Sintering plants...................  Big River Industries--       Crittenden............  Kiln A
                                      Arkalite.
----------------------------------------------------------------------------------------------------------------
Chemical process plants............  Albermarle Corporation       Columbia..............  No. 1 Boiler
                                      South Plant.
                                                                                         -----------------------
                                                                                          No. 2 Boiler
                                    ----------------------------------------------------------------------------
                                     Future Fuels/Eastman         Independence..........  3 Coal Boilers
                                      Chemical.
                                    ----------------------------------------------------------------------------
                                     El Dorado Chemical Company.  Union.................  West Nitric Acid
                                                                                         -----------------------
                                                                                          East Nitric Acid
                                                                                         -----------------------
                                                                                          Nitric Acid
----------------------------------------------------------------------------------------------------------------

    We note that in chapter 15 of APC&E Regulation 19, contained in the 
RH SIP submittal we received on September 23, 2008, and as revised by 
the submittal we received on August 3, 2010, ADEQ identified one more 
unit (not listed in Table 2), the 6A Boiler at the Georgia-Pacific 
Crossett Mill, as being BART-eligible. ADEQ did not identify the 6A 
Boiler as BART-eligible in the RH SIP narrative. Appendix 9.1A states 
the 6A Boiler began operation prior to August 7, 1962, and that it 
falls out of the BART eligibility criteria because of its start of 
operations date. On September 27, 2011, ADEQ submitted supplemental 
information clarifying that the Georgia-Pacific Crossett Mill provided 
ADEQ a copy of a boiler inspection report for the 6A Boiler, which 
states that the inspection of the new boiler took place on August 6, 
1962, to determine if the boiler complied with the State and American 
Society of Mechanical Engineers (ASME) codes.\22\ However, ADEQ stated 
it cannot say with certainty whether the 6A boiler was in operation as 
of August 6, 1962, or at a later date.\23\ Since there is not 
sufficient

[[Page 64198]]

information to determine the date of start of operations of the 6A 
Boiler, we cannot make the determination that the boiler is not BART-
eligible. Therefore, we are proposing to find that the 6A Boiler at the 
Georgia-Pacific Crossett Mill is BART-eligible.
---------------------------------------------------------------------------

    \22\ A copy of the boiler inspection report for the 6A Boiler at 
the Georgia-Pacific Crossett Mill can be found in the docket for 
this proposed rulemaking.
    \23\ The BART Guidelines define ``in operation'' as ``engaged in 
activity related to the primary design function of the source.''
---------------------------------------------------------------------------

    In the RH SIP, ADEQ identified one unit (the No. 4 recovery boiler) 
at International Paper/Evergreen Packaging as BART-eligible (shown in 
Table 2). ADEQ included two other units (the No. 1 and 2 Power Boilers) 
at International Paper/Evergreen Packaging in its evaluation to 
determine what sources are subject to BART. The International Paper/
Evergreen Packaging No. 1 and No. 2 Power Boilers are not BART-eligible 
because they were constructed and were in operation prior to August 7, 
1962.\24\ We agree that the No. 1 and 2 Power Boilers at International 
Paper/Evergreen Packaging are not BART-eligible.
---------------------------------------------------------------------------

    \24\ On May 27, 1958, the Arkansas Department of Labor performed 
an annual inspection of the International Paper No. 1 and 2 Boilers. 
On June 26, 1958, the Arkansas Department of Labor issued an 
inspection certificate to the International Paper Company for the 
No. 1 and 2 Boilers. Since the No. 1 and 2 Boilers were in operation 
prior to August 7, 1962, they fall out of the startup date criteria 
for BART eligibility. The inspection certificate for the can be 
viewed in the docket for this proposed rulemaking.
---------------------------------------------------------------------------

    In the RH SIP, ADEQ did not identify Boilers SN-301A and SN-302A at 
the Great Lakes Chemical Plant as BART-eligible, but since these units 
were at one point believed to be BART-eligible, ADEQ included these 
units in its evaluation to determine what sources are subject to BART. 
EPA reviewed the federally enforceable operating permit for the Great 
Lakes Chemical Plant and determined that Boilers SN-301A and SN-302A 
are not BART-eligible because they are boilers with a heat input rating 
less than 250 MMBtu/hr and are not integral to the process, as the 
permit states they are used to supply heat to the process.\25\ The BART 
Guidelines provide that an individual fossil fuel boiler smaller than 
250 MMBtu/hr that does not fall into source Category 1 (i.e., Fossil-
fuel fired steam electric plants of more than 250 MMBtu/hr heat input), 
falls into one of the other source categories for BART eligibility only 
if it is an integral part of a process description at a plant. If the 
boiler is integral to the process description at a plant, it falls into 
the source category of the process which it serves. In general, if the 
boiler serves the process in any way beyond contributing heat, it is 
integral to the process. Based on information in the current operating 
air permit for the Great Lakes Chemical Plant, we agree that Boilers 
SN-301A and SN-302A are not BART-eligible.
---------------------------------------------------------------------------

    \25\ ADEQ Operating Air Permit for the Great Lakes Chemical 
Corporation--Central Plant (Permit No. 1077-AOP-R1). This permit can 
be viewed at http://www.adeq.state.ar.us/ftproot/pub/WebDatabases/PermitsOnline/Air/1077-AOP-R1.pdf.
---------------------------------------------------------------------------

    As discussed above, there is a discrepancy between the BART-
eligible sources identified in the RH SIP narrative, and those 
identified in the State's RH Rule. Because ADEQ submitted supplemental 
information on September 27, 2011, clarifying that it did not know with 
certainty the startup date of operations of the 6A Boiler at the 
Georgia-Pacific Crossett Mill, we are proposing to find that the 6A 
Boiler is BART-eligible. We are proposing to approve ADEQ's 
identification of the remaining BART-eligible sources.
2. Identification of Sources Subject to BART
    The second step of the BART evaluation is to identify those BART-
eligible sources that may reasonably be anticipated to cause or 
contribute to visibility impairment at any Class I area, i.e. those 
sources that are subject to BART. The BART Guidelines allow states to 
consider exempting some BART-eligible sources from further BART review 
because they may not reasonably be anticipated to cause or contribute 
to any visibility impairment in a Class I area. Consistent with the 
BART Guidelines, ADEQ required each of its BART-eligible sources to 
develop and submit dispersion modeling to assess the extent of their 
contribution to visibility impairment at surrounding Class I areas.
    The BART Guidelines direct states to address SO2, 
NOX and direct PM (including both PM10 and 
PM2.5) emissions as visibility-impairing pollutants, and 
States must exercise their ``best judgment to determine whether VOC or 
ammonia emissions from a source are likely to have an impact on 
visibility in an area.'' See 70 FR 39162. CENRAP modeling demonstrated 
that VOCs from anthropogenic sources are not significant visibility-
impairing pollutants at Caney Creek and Upper Buffalo. Ammonia 
emissions in Arkansas are primarily due to area sources, such as 
livestock and fertilizer application. Because these are not point 
sources, they are not subject to BART. The emissions inventory prepared 
for the CENRAP modeling demonstrates that ammonia from point sources 
are not significant visibility-impairing pollutants in Arkansas. ADEQ 
further argued that only specific VOCs form secondary organic aerosols 
that affect visibility and that these compounds are a fraction of the 
total VOCs reported in Arkansas' emissions inventory. ADEQ does not 
have the breakdown of VOC emissions necessary to model only those that 
impair visibility. Because CALPUFF, EPA's prescribed screening model, 
cannot simulate formation of particles from anthropogenic VOCs, nor 
their visibility impacts, ADEQ did not evaluate emissions of VOCs in 
making BART determinations. We have reviewed this information and 
propose to agree with ADEQ's decision to address only SO2, 
NOX, and PM as visibility impairing pollutants because VOC 
emissions from anthropogenic sources are not significant visibility-
impairing pollutants at Caney Creek and Upper Buffalo and ammonia 
emissions in Arkansas are primarily due to area sources.
a. Modeling Methodology
    The BART Guidelines provide that states may choose to use the 
CALPUFF \26\ modeling system or another appropriate model to predict 
the visibility impacts from a single source on a Class I area and to 
therefore, determine whether an individual source is anticipated to 
cause or contribute to impairment of visibility in Class I areas, i.e., 
``is subject to BART''. The Guidelines state that we believe CALPUFF is 
the best regulatory modeling application currently available for 
predicting a single source's contribution to visibility impairment (70 
FR 39162). ADEQ used the CALPUFF modeling system to determine whether 
individual sources in Arkansas were subject to or exempt from BART.
---------------------------------------------------------------------------

    \26\ Note that our reference to CALPUFF encompasses the entire 
CALPUFF modeling system, which includes the CALMET, CALPUFF, and 
CALPOST models and other pre and post processors. The different 
versions of CALPUFF have corresponding versions of CALMET, CALPOST, 
etc. which may not be compatible with previous versions (e.g., the 
output from a newer version of CALMET may not be compatible with an 
older version of CALPUFF). The different versions of the CALPUFF 
modeling system are available from the model developer at http://www.src.com/verio/download/download.htm.
---------------------------------------------------------------------------

    The BART Guidelines also recommend that states develop a modeling 
protocol for making individual source attributions, and suggest that 
states may want to consult with us and their RPO to address any issues 
prior to modeling. The CENRAP states, including Arkansas, developed the 
``CENRAP BART Modeling Guidelines''.\27\ Stakeholders, including

[[Page 64199]]

EPA, FLMs, industrial sources, trade groups, and other interested 
parties, actively participated in the development and review of the 
CENRAP protocol. CENRAP provided readily available modeling data bases 
for use by states to conduct their analyses. We note that the original 
meteorological databases generated by CENRAP did not include 
observations as EPA guidance recommends, therefore sources were 
evaluated using the 1st High values instead of the 8th High values. The 
use of the 1st High modeling values was agreed to by EPA, 
representatives of the Federal Land Managers, and CENRAP stakeholders. 
We are proposing to find the chosen model and the general modeling 
methodology for screening modeling acceptable.
---------------------------------------------------------------------------

    \27\ CENRAP BART Modeling Guidelines, T. W. Tesche, D. E. 
McNally, and G. J. Schewe (Alpine Geophysics LLC), December 15, 
2005, available at http://www.deq.state.ok.us/aqdnew/RulesAndPlanning/Regional_Haze/SIP/Appendices/index.htm.
---------------------------------------------------------------------------

b. Contribution Threshold
    For states using modeling to determine the applicability of BART to 
single sources, the BART Guidelines note that the first step is to set 
a contribution threshold to assess whether the impact of a single 
source is sufficient to cause or contribute to visibility impairment at 
a Class I area. The BART Guidelines state that, ``[a] single source 
that is responsible for a 1.0 deciview change or more should be 
considered to `cause' visibility impairment.'' 70 FR 39104, 39161. The 
BART Guidelines also state that ``the appropriate threshold for 
determining whether a source contributes to visibility impairment may 
reasonably differ across states,'' but, ``[a]s a general matter, any 
threshold that you use for determining whether a source `contributes' 
to visibility impairment should not be higher than 0.5 deciviews.'' Id. 
Further, in setting a contribution threshold, states should ``consider 
the number of emissions sources affecting the Class I areas at issue 
and the magnitude of the individual sources' impacts. The Guidelines 
affirm that states are free to use a lower threshold if they conclude 
that the location of a large number of BART-eligible sources in 
proximity of a Class I area justifies this approach. Considering the 
number of sources affecting Arkansas' Class I areas and the magnitude 
of each source's impact, ADEQ used a contribution threshold of 0.5 dv 
for determining which sources are subject to BART. We agree with the 
State's selection of this threshold value.
c. Sources Identified by ADEQ as Subject to BART
    Following the elimination of those sources that were found to have 
visibility impacts well below the 0.5 dv threshold, ADEQ identified the 
sources contained in Table 3 as being subject to BART.

                                  Table 3--Sources in Arkansas Subject to BART
----------------------------------------------------------------------------------------------------------------
                                                                                                  Pollutants
           Facility name                 BART emission units           Source category            evaluated
----------------------------------------------------------------------------------------------------------------
AECC Carl E. Bailey Generating       Unit 1....................  fossil fuel-fired steam     SO2
 Station.                                                         electric plants.
                                                                                            --------------------
                                                                                             NOX
                                                                                            --------------------
                                                                                             PM10
----------------------------------------------------------------------------------------------------------------
AECC John L. McClellan Generating    Unit 1....................  fossil fuel-fired steam     SO2
 Station.                                                         electric plants.
                                                                                            --------------------
                                                                                             NOX
                                                                                            --------------------
                                                                                             PM10
----------------------------------------------------------------------------------------------------------------
AEP Flint Creek Power Plant........  Boiler No. 1..............  fossil fuel-fired steam     SO2
                                                                  electric plants.
                                                                                            --------------------
                                                                                             NOX
                                                                                            --------------------
                                                                                             PM10
----------------------------------------------------------------------------------------------------------------
Entergy Lake Catherine Plant.......  Unit 4....................  fossil fuel-fired steam     SO2
                                                                  electric plants.
                                                                                            --------------------
                                                                                             NOX
                                                                                            --------------------
                                                                                             PM10
----------------------------------------------------------------------------------------------------------------
Entergy White Bluff Plant..........  Units 1, 2, and Auxiliary   fossil fuel-fired steam     SO2
                                      Boiler.                     electric plants.
                                                                                            --------------------
                                                                                             NOX
                                                                                            --------------------
                                                                                             PM10
----------------------------------------------------------------------------------------------------------------
Domtar Ashdown Mill................  Power Boilers No. 1 and 2.  kraft pulp mill...........  SO2
                                                                                            --------------------
                                                                                             NOX
                                                                                            --------------------
                                                                                             PM10
----------------------------------------------------------------------------------------------------------------

    In Appendix 9.2B of the RH SIP, ADEQ provided screening modeling 
results for all sources identified in the RH SIP as BART-eligible 
sources, as well as for the SN-301A and SN-302A Boilers at the Great 
Lakes Chemical plant, the No. 1 and No. 2 Power Boilers at 
International Paper/Evergreen Packaging, and the 6A and 9A Boilers at 
the Georgia-Pacific Crossett Mill (as discussed above). Our evaluation 
of these results showed that four facilities that ADEQ did not identify 
as subject to BART had modeled visibility impacts that exceed the 0.5 
dv contribution

[[Page 64200]]

threshold used by ADEQ to determine what sources are subject to BART. 
Our evaluation to determine whether these sources are subject to BART 
or not is discussed below:
     As discussed in section V.D.1., ADEQ included the No. 1 
and No. 2 Power Boilers at International Paper/Evergreen Packaging and 
the SN-301A and SN-302A Boilers at the Great Lakes Chemical plant in 
its modeling evaluation to determine what sources are subject to BART. 
As already discussed elsewhere in this proposed notice, we are 
proposing to approve ADEQ's identification of these two sources as not 
BART-eligible and not subject to BART.
     As discussed in section IV.D.2.a. of this proposed 
rulemaking, the original meteorological databases generated by CENRAP 
did not include observations as EPA guidance recommends. Therefore, in 
their evaluation to determine if a source exceeds the 0.5 dv 
contribution threshold at nearby Class I areas, states used the 1st 
high values (i.e., maximum value) of modeled visibility impacts instead 
of the 8th high values (i.e., 98th percentile value). The use of the 
1st high modeled values was agreed to by EPA, representatives of the 
Federal Land Managers, and CENRAP stakeholders. ADEQ's modeling shows 
that Future Fuels/Eastman Chemical has a modeled visibility impact of 
0.711 dv at Hercules-Glade. Further examination of the modeling results 
reveals that only one day of the three years modeled exceeds the 0.5 dv 
contribution threshold value at any Class I area. Since only one day is 
projected above the threshold, we believe it is very unlikely that a 
refined modeling approach using updated meteorological data, which 
would allow for the use of the 98th percentile modeled visibility 
impact rather than the maximum impact, would show modeled impacts above 
the threshold. Therefore, we are proposing that this facility is not 
subject to BART.
     The visibility modeling provided in Appendix 9.2B of the 
Arkansas RH SIP shows that the 9A Boiler of the Georgia-Pacific 
Crossett Mill has visibility impacts exceeding the 0.5 dv contribution 
threshold, with a visibility impact above 1 dv at Caney Creek and 
Hercules-Glade. EPA also reviewed ADEQ's revised modeling for this 
source, which looked at the visibility impacts of both the 6A and 9A 
Boilers at the Georgia-Pacific Crossett Mill. Using updated emission 
rates, ADEQ's revised modeling showed projected visibility impacts of 
the two boilers combined below the 0.5 dv threshold. The revised 
emission rates were based on stack test results and assumptions based 
on worst case monthly fuel usage, from the perspective of total 
emissions. However, from the data provided, it is unclear if the 
modeled emissions are representative of the actual maximum 24 hour 
emissions from the highest emitting day over the modeled period. There 
is no supporting technical analysis discussing the assumptions made in 
the revised emission estimates and explaining how stack test data was 
used to estimate maximum emissions nor is fuel usage information 
provided for the modeled period. We are proposing to disapprove ADEQ's 
determination that the Georgia-Pacific Crossett Mill's 6A and 9A 
Boilers are not subject to BART because ADEQ has not modeled the 
visibility impact of the 6A and 9A Boilers using acceptable estimates 
of maximum 24 hour emissions, and as a result we do not know if the 
boilers have a combined visibility impact below the 0.5 dv contribution 
threshold or not. Based on the permit allowables and available 
information, the two boilers are subject to BART and require a full 
BART analysis.
    We are proposing to approve ADEQ's identification of subject to 
BART sources, except for ADEQ's determination that the Georgia-Pacific 
Crossett Mill 6A and 9A Boilers are not subject to BART.
3. BART Determinations
    The third step of a BART evaluation is to perform the BART 
analysis. BART is a source-specific control determination, based on 
consideration of several factors set out in section 169A(g)(2) of the 
CAA. These factors include the costs of compliance and the degree of 
improvement in visibility associated with the use of possible control 
technologies. EPA issued BART Guidelines (Appendix Y to Part 51) in 
2005 to clarify the BART provisions based on the statutory and 
regulatory BART requirements (70 FR 39164). The BART Guidelines 
describe the BART analysis as consisting of the following five basic 
steps:
     Step 1: Identify All Available Retrofit Control 
Technologies,
     Step 2: Eliminate Technically Infeasible Options,
     Step 3: Evaluate Control Effectiveness of Remaining 
Control Technologies,
     Step 4: Evaluate Impacts and Document the Results, and
     Step 5: Evaluate Visibility Impacts.
    We note the BART Guidelines (Appendix Y to part 51) provide that 
states must follow the guidelines in making BART determinations on a 
source-by-source basis for 750 MW power plants but are not required to 
use the process in the guidelines when making BART determinations for 
other types of sources. States with subject to BART units with a 
generating capacity less than 750 MW are strongly encouraged to follow 
the BART Guidelines in making BART determinations, but they are not 
required to do so. However, the requirement to perform a BART analysis 
that considers ``the technology available, the costs of compliance, the 
energy and nonair quality environmental impacts of compliance, any 
pollution control equipment in use at the source, the remaining useful 
life of the source, and the degree of improvement in visibility which 
may reasonably be anticipated to result from the use of such 
technology,'' is found in section 51.308(e)(1)(ii)(A) and the RHR, and 
applies to all subject to BART sources.
    All of the sources that are subject to BART presented in Table 3 
are fossil fuel fired electricity generating units, with the exception 
of the Domtar Ashdown Mill, which is a kraft pulp mill. ADEQ performed 
BART determinations for these sources for NOx, SO2, and PM.
    We have found several problems in these BART determinations, which 
lead us to propose disapproval of some of ADEQ's BART determinations. 
We discuss these problems in detail in the individual BART 
determination sections, and we summarize some general issues in the 
paragraphs that follow.
    For some sources, ADEQ did not adequately consider whether retrofit 
controls should be required based on a flawed analysis of the source's 
potential visibility impacts. ADEQ assumed that if pre-control modeling 
\28\ conducted on the basis of a single pollutant showed that the 
source's emissions of the pollutant in question did not ``contribute'' 
to visibility impairment, then further BART analysis for that pollutant 
was unnecessary. This approach is unacceptable. Due to the nonlinear 
nature and complexity of atmospheric chemistry and chemical 
transformation among pollutants, ideally all relevant pollutants should 
be modeled together to predict the total visibility impact at each 
Class I area receptor.\29\ At a minimum, NOX and 
SO2

[[Page 64201]]

emissions should be modeled together to determine the visibility 
impacts attributable to these pollutants when evaluating controls and 
combinations of controls in determining BART for a source. Predicting 
the impacts of PM on visibility is relatively straight-forward, unlike 
predicting the impacts of SO2 and NOX. Using 
CALPUFF on a pollutant specific basis to model only the impact of PM 
emissions on visibility is an acceptable approach to determine whether 
a source should be subject to review for PM controls, or alternatively, 
that the source is not subject to BART for PM. ADEQ applied a threshold 
of 0.5 dv for determining whether a source ``contributes'' to 
visibility impairment on a per-pollutant basis. As discussed above, the 
State selected a threshold of 0.5 dv for the initial screening modeling 
that included all pollutants. Clearly, a lower threshold value is 
needed in evaluating pollutant-specific modeling for sources that emit 
more than one visibility impairing pollutant. Furthermore, this 
approach is only acceptable for PM-specific modeling. We note that a 
State may establish de minimis levels of emissions (applicable on a 
plant-wide basis) of visibility impairing pollutants to exclude some 
sources from further evaluation when the emissions are so minimal that 
they are unlikely to contribute to regional haze.\30\
---------------------------------------------------------------------------

    \28\ Throughout this document, any reference to ``ADEQ 
modeling'' refers to modeling performed or reviewed by ADEQ.
    \29\ Memo from Joseph Paisie (Geographic Strategies Group, 
OAQPS) to Kay Prince (Branch Chief EPA Region 4) on Regional Haze 
Regulations and Guidelines for Best Available Retrofit Technology 
(BART) Determinations, July 19, 2006.
    \30\ ``States may choose to identify de minimis levels of 
pollutants at BART-eligible sources (but are not required to do so). 
De minimis values should be identified with the purpose of excluding 
only those emissions so minimal that they are unlikely to contribute 
to regional haze. Any de minimis values that you adopt must not be 
higher than the PSD applicability levels: 40 tons/yr for 
SO2 and NOX and 15 tons/yr for 
PM10. These de minimis levels may only be applied on a 
plant-wide basis.'' 40 CFR Appendix Y to part 51.
---------------------------------------------------------------------------

    For some BART determinations, ADEQ did not properly determine BART, 
but instead concluded that the presumptive limits in the BART 
Guidelines could be adopted in place of a careful source-specific 
analysis of the appropriate level of controls. As noted above, EPA 
issued BART Guidelines in 2005 that address the BART determination 
process by laying out a step by step process for taking into 
consideration the factors relevant to a BART determination. In that 
rulemaking, EPA also established presumptive BART limits for certain 
electric generating units (EGUs) located at power plants 750 MW or 
greater in size based variously on the size of the unit, the type of 
unit, the type of fuel used, and the presence or absence of 
controls.\31\ Having identified controls that the Agency considered to 
be generally cost-effective across all affected units, the EPA took 
into account the substantial degree of visibility improvement 
anticipated to result from the use of such controls on these EGUs and 
concluded that such BART-eligible sources should at least meet the 
presumptive limits. The presumptive limits accordingly are the starting 
point in a BART determination for these units--unless the State 
determines that the general assumptions underlying EPA's analysis are 
not applicable in a particular case. EPA did not provide that States 
could avoid a source-specific BART determination by adopting the 
presumptive limits. In fact, nothing on the record would support the 
conclusion that the presumptive limits represent the ``best available 
retrofit controls'' for all EGUs at these large power plants. EPA did 
not address the question of whether in specific cases more stringent 
controls would be called for but rather simply concluded that it could 
not reach a generalized conclusion as to the appropriateness of more 
stringent controls for categories of EGUs. As a result, the BART Rule 
does not establishing a ``safe harbor'' from more stringent regulation 
under the BART provisions. We have consistently informed ADEQ in 
comments to its draft SIP and in conversations that foregoing a BART 
analysis is not acceptable.
---------------------------------------------------------------------------

    \31\ 70 FR at 39131-39136.
---------------------------------------------------------------------------

    For the BART determinations for which ADEQ did perform a full BART 
analysis that considered the statutory factors under section 
51.308(e)(1)(ii)(A), we are proposing to find that ADEQ did not 
adequately consider one or more of the factors it is required to 
consider in determining whether retrofit controls should be required.
    For more details, please see our evaluation of the BART 
determination for each subject to BART unit, below, and the TSD.
a. AECC Bailey Unit 1 and AECC McClellan Unit 1 BART Determinations
    The AECC Bailey Unit 1 and the AECC McClellan Unit 1 are BART-
eligible sources. The AECC Bailey Unit 1 is a boiler with a gross 
output of 122 MW and a maximum heat input rate of 1350 MMBtu/hr, and is 
currently permitted to burn both natural gas and fuel oil. The fuel oil 
burned at the plant is subject to an operating air permit sulfur 
content limit of 2.3% by weight. The AECC McClellan Unit 1 is a boiler 
with a gross output of 134 MW and a maximum heat input rate of 1436 
MMBtu/hr, and is currently permitted to burn both natural gas and fuel 
oil. The fuel oil burned at the plant is subject to an operating air 
permit sulfur content limit of 2.8% by weight.
    Regarding BART for NOX and PM, ADEQ conducted pollutant 
specific pre-control CALPUFF \32\ modeling for the AECC Bailey Unit 1 
and the AECC McClellan Unit 1. AECC stated that the results of the 
NOX modeling show that NOX does not cause or 
contribute to visibility impacts.\33\ Based on this, AECC determined 
and ADEQ agreed it was not necessary to make a BART determination for 
NOX for either the AECC Bailey Unit 1 or AECC McClellan Unit 
1. However, the ADEQ's modeling results presented indicate that the 
predicted visibility impacts from NOX are as high as 0.347 
dv at Mingo due to emissions from the AECC Bailey Unit 1, and 0.421 dv 
at Caney Creek due to emissions from the AECC McClellan Unit 1. As 
stated above, NOX and SO2 emissions should be 
modeled together due to the nonlinear nature and complexity of 
atmospheric chemistry and chemical transformation among pollutants. 
Evaluation of the screening modeling results for these units reveals 
that on some of the most impacted days, NOX is a significant 
contributor to the visibility impairment due to these units. Post-
control modeling performed by ADEQ, applying the use of 1% sulfur fuel, 
show that these units would continue to cause or contribute to 
visibility impairment at a number of Class I areas, with NOX 
emissions responsible for over 50% of the impairment on some days under 
this control scenario. In light of the relatively high impacts due to 
NOX, a combination of NOX and SO2 
controls may prove to be cost-effective and provide for substantial 
visibility improvement and should therefore be evaluated.
---------------------------------------------------------------------------

    \32\ The CALPUFF modeling system consists of a meteorological 
data pre-processor (CALMET), an air dispersion model (CALPUFF), and 
post-processor programs (POSTUTIL, CALSUM, CALPOST). The CALPUFF 
modeling system is the recommended model for conducting BART 
visibility analysis.
    \33\ Arkansas Electric Cooperative Corporation Best Available 
Retrofit Technology Engineering Analysis prepared by Stephen Cain, 
October 20, 2006.
---------------------------------------------------------------------------

    For PM BART, AECC decided and ADEQ agreed that PM does not cause 
visibility impacts because the PM emissions are less than those of 
NOX at these units. This conclusion is not supported in the 
record by PM visibility modeling results, additional technical 
analysis, or reference to a permit limit for PM that restricts 
emissions below a level that will impact visibility. Neither the State 
nor AECC have completed a BART analysis that considers the

[[Page 64202]]

statutory factors under section 51.308(e)(1)(ii)(A) that states are 
required to consider in determining what type and level of control is 
BART for a source for NOX and PM, or fully demonstrated that 
these units have sufficient pollution controls in place for these 
pollutants such that additional controls would likely achieve very low 
emissions reductions, have minimal visibility benefit, and not be cost-
effective. Therefore, we are proposing to disapprove the NOX 
and PM BART determinations for these two units.
    Regarding BART for SO2 for the two sources, AECC 
performed a BART analysis to determine what retrofit controls are BART 
for AECC Bailey Unit 1 and AECC McClellan Unit 1. In Step 1 of this 
BART analysis, AECC identified use of fuel oil with 1% sulfur content 
and installation of a scrubber as the only two control options 
available. This is a problem because 1% sulfur fuel oil is not the 
maximum level of control available when it comes to the use of low 
sulfur fuel as a control strategy for SO2 emissions. After 
completing the remaining steps of the BART analysis, AECC determined 
and ADEQ agreed that BART for the AECC Bailey Unit 1 and the AECC 
McClellan Unit 1 is use of fuel oil with 1% sulfur content. Our 
evaluation of AECC's BART analysis beyond Step 1 can be found in the 
TSD. We are not discussing in this proposed notice our evaluation of 
AECC's BART analysis for the AECC Bailey Unit 1 and the AECC McClellan 
Unit 1 beyond Step 1, as we are proposing that AECC did not properly 
complete the first step of the BART analysis and thus we find that AECC 
and ADEQ did not properly follow the requirements of section 
51.308(e)(1)(ii)(A) in determining BART. Specifically, we are proposing 
that AECC and ADEQ did not properly ``take into consideration the 
technology available'' by failing to consider the maximum level of 
control each control option is capable of achieving. The BART 
Guidelines (Appendix Y to Part 41) provide that in identifying all 
options, you must identify the most stringent option (i.e., maximum 
level of control each technology is capable of achieving) as well a 
reasonable set of options for analysis. The requirement to consider the 
most stringent level of control when making BART determinations is also 
found in the RHR (64 FR 35740), which provides that in establishing 
source specific BART emission limits, the State should identify and 
consider in the BART analysis the maximum level of emission reduction 
that has been achieved in other recent retrofits at existing sources in 
the source category. The visibility regulations define BART as ``an 
emission limitation based on the degree of reduction achievable through 
the application of the best system of continuous emission reduction.'' 
Since recent retrofits at existing sources provide a good indication of 
the current ``best system'' for controlling emissions, these controls 
must be considered in the BART analysis. In considering use of fuel oil 
with low sulfur content as a control option in the BART analysis, AECC 
did not identify and consider the maximum level of control achievable 
from the use of low sulfur fuel oil, and thus the BART analysis is 
flawed.
    Sulfur content in fuel oil currently can be found in industry to be 
0.5% by weight or less. AECC should have considered the use of fuel oil 
with 0.5% sulfur content or less in the BART analysis for the two units 
in question. We are aware of several fossil-fuel fired steam electric 
plants throughout the country that are currently limited by permit to 
burn fuel oil with a sulfur content of 0.5% or less by weight. 
Connecticut limits the sulfur content of fuel oil to a maximum 0.3% 
\34\ and New York requires facilities to comply with the use of fuel 
oil with varying sulfur content limits, with facilities in New York 
City being required to use fuel oil with a maximum 0.3% sulfur 
content.\35\ Lowering the sulfur content in fuel oil is also a part of 
the long-term strategy recommended by the Mid-Atlantic/Northeast 
Visibility Union (MANE-VU) states to reduce and prevent regional 
haze.\36\ The MANE-VU states in the inner zone (New Jersey, New York, 
Delaware, and Pennsylvania) plan to reduce the sulfur content of No. 6 
residual fuel oil to 0.3-0.5% sulfur by weight by no later than 
2012.\37\ Therefore, the use of fuel oil with a 0.5% sulfur content or 
lower is technically feasible and either AECC or ADEQ should have 
evaluated its cost effectiveness for the AECC Bailey Unit 1 and the 
AECC McClellan Unit 1. In addition, an operating air permit restriction 
to use only natural gas as the fuel source for the two units would have 
also been acceptable. As part of the BART analysis, ADEQ and/or AECC 
must perform a cost analysis in which all cost estimates are properly 
documented and must evaluate the visibility impacts of all technically 
feasible control options considered before making a BART determination.
---------------------------------------------------------------------------

    \34\ Connecticut Department of Environmental Protection (DEP). 
``22a-174-19a: Control of Sulfur Dioxide Emissions from Power Plants 
and Other Large Stationary Sources of Air Pollution,'' Regulations 
of Connecticut State Agencies, Title 22a: Abatement of Air 
Pollution, December 28, 2000. http://www.dep.state.ct.us/air2/regs/mainregs/sec19a.pdf.
    \35\ New York State Department of Environmental Conservation 
(DEC). ``Subpart 225-1: Fuel Composition and Use-Sulfur 
Limitations,'' Environmental Conservation Rules and Regulations, May 
8, 2005. http://www.dec.state.ny.us/website/regs/subpart225_1.html.
    \36\ MANE-VU is an RPO that includes the following states: 
Maine, New Hampshire, Vermont, Massachusetts, Rhode Island, 
Connecticut, New York, New Jersey, Pennsylvania, Maryland, Delaware, 
and also the District of Columbia.
    \37\ See 76 FR 27973.
---------------------------------------------------------------------------

    Therefore, for the reasons expressed above, we are proposing to 
disapprove the SO2, NOX, and PM BART 
determinations for the AECC Bailey Unit 1 and the AECC McClellan Unit 
1.
b. AEP Flint Creek No. 1 Boiler BART Determination
    The AEP Flint Creek No. 1 Boiler is a BART-eligible source. The 
unit has a gross output of 558 MW and a maximum heat input rate of 6324 
MMBtu/hr, and burns primarily low sulfur western coal, but can also 
combust fuel oil and tire derived fuels (TDF). Fuel oil firing is only 
allowed during startup and shutdown of the boiler, startup and shutdown 
of the pulverizer mills, for flame stabilization when the coal is 
frozen, for fuel oil tank maintenance, to prevent boiler tube failure 
in extreme cold weather, and when the unit is offline for maintenance.
    Regarding BART for PM, ADEQ conducted pre-control CALPUFF modeling 
for the AEP Flint Creek No. 1 Boiler showing that PM10 and 
PM2.5 emissions from the source have minimal visibility 
impacts at each Class I area within 300 km. Based on this, AEP decided 
and ADEQ agreed that the existing PM emission limit in the operating 
air permit, which is achievable through the use of the existing 
electrostatic precipitator (ESP), is BART for PM for AEP Flint Creek 
No. 1 Boiler. We reviewed the CALPUFF visibility modeling submitted by 
ADEQ for AEP Flint Creek No. 1 Boiler, and agree that PM10 
and PM2.5 emissions from the source have minimal visibility 
impacts at each Class I area within 300 km. As explained in section 
IV.D.3 of this proposed rulemaking, using CALPUFF on a pollutant 
specific basis to model only the impact of PM emissions on visibility 
is an acceptable approach to determine whether a source should be 
subject to review for PM controls. In the case of the AEP Flint Creek 
No. 1 Boiler, we have found that the visibility impact due to PM 
emissions alone is so minimal such that the installation of any 
additional PM controls on the unit would likely

[[Page 64203]]

achieve very low emissions reductions, have minimal visibility benefit, 
and not be cost-effective. Therefore, we are proposing to approve 
ADEQ's determination that PM BART for AEP Flint Creek No. 1 Boiler is 
the existing PM emission limit. The federally enforceable operating air 
permit for the source sets the PM emission limit for the unit at 0.1 
lb/MMBtu.\38\
---------------------------------------------------------------------------

    \38\ ADEQ Operating Air Permit for AEP-Flint Creek Power Plan 
(Permit No. 0276-AOP-R5). This permit can be viewed at http://www.adeq.state.ar.us/ftproot/pub/WebDatabases/PermitsOnline/Air/0276-AOP-R5.pdf.
---------------------------------------------------------------------------

    Regarding BART for SO2 and NOX, neither AEP 
nor ADEQ performed a BART analysis that considered the statutory 
factors states are required to consider in determining what retrofit 
controls are BART for the AEP Flint Creek No. 1 Boiler. Instead, AEP 
determined and ADEQ agreed that BART for SO2 is the 
presumptive limit of 0.15 lb/MMBtu and that BART for NOX is 
the presumptive limit of 0.23 lb/MMBtu for AEP Flint Creek No. 1 
Boiler.\39\ We are aware that the AEP Flint Creek Power Plant has a 558 
MW generating capacity, and is therefore not required to follow the 
BART Guidelines in making BART determinations for the No. 1 Boiler. 
However, this facility and/or the State must still conduct a BART 
analysis as specified in 40 CFR 51.308(e)(1)(ii)(A), which provides 
that:

    \39\ The ``presumptive limits'' are the rebuttable specific 
limits established in the BART Rule for SO2 and 
NOX for certain EGUs based on fuel type, unit size, cost 
effectiveness, and the presence or absence of pre-existing controls.

    The determination of BART must be based on an analysis of the 
best system of continuous emission control technology available and 
associated emission reductions achievable for each BART-eligible 
source that is subject to BART within the State. In this analysis, 
the State must take into consideration the technology available, the 
costs of compliance, the energy and nonair quality environmental 
impacts of compliance, any pollution control equipment in use at the 
source, the remaining useful life of the source, and the degree of 
improvement in visibility which may reasonably be anticipated to 
---------------------------------------------------------------------------
result from the use of such technology.

    Therefore, we are proposing to disapprove ADEQ's BART finding since 
neither AEP nor ADEQ conducted a BART analysis considering the best 
system of controls for BART for SO2 and NOX for 
AEP Flint Creek No. 1 Boiler. The source and/or ADEQ should have 
performed a BART analysis for SO2 and NOX. 
Controls achieving more than the SO2 and NOX 
presumptive limits are available and should be considered in the BART 
analysis, especially considering the magnitude of the visibility impact 
of the AEP Flint Creek No. 1 Boiler on the Class I areas within 300 
km.\40\ For instance, selective catalytic reduction (SCR) controls are 
routinely designed and have routinely achieved a NOX control 
efficiency of 90% and a NOX emission rate as low as 0.04 lb/
MMBtu,\41\ based on a 30-day rolling average. Furthermore, SCR system 
designers analyzed EPA's Clean Air Market's CEMS data to determine the 
NOX levels that are currently being achieved by over 100 
SCR-equipped coal-fired boilers, and found that 25 of these units are 
achieving NOX emissions less than 0.05 lb/MMBtu on an hourly 
average basis.\42\ Flue gas desulfurization (FGD) units (i.e., wet and 
dry scrubbers), are a type of post-combustion control for 
SO2 emissions. In a report for the National Lime 
Association, Sargent & Lundy stated that vendors guarantee 
SO2 reduction efficiencies of up to 95%, or as low as 0.06 
lb/MMBtu SO2 for dry scrubbers.\43\ The Longleaf Energy 
Station in Georgia has two 600 MW boilers that burn coal and are 
equipped with a dry scrubber capable of achieving SO2 
emissions of 0.065 lb/MMBtu on a 30-day rolling average when the 
uncontrolled SO2 emission rate is less than or equal to 1 
lb/MMBtu.\44\ The Desert Rock Energy Company, a 1500 MW coal fired 
power plant in New Mexico, is equipped with a wet scrubber and has an 
SO2 emission limit of 0.060 lb/MMBtu, averaged over a 24-
hour period.\45\ We note that a 24-hour average is much more stringent 
than a 30-day rolling average.
---------------------------------------------------------------------------

    \40\ ADEQ's CALPUFF visibility modeling indicates the highest 
modeled visibility impact of AEP Flint Creek No. 1 Boiler on nearby 
Class I areas is: 3.970 [Delta]dv at Caney Creek; 3.781 [Delta]dv at 
Upper Buffalo; 3.983 [Delta]dv at Hercules Glade; 2.596 [Delta]dv at 
Mingo; 1.420 [Delta]dv at Sipsey. ADEQ's post-control visibility 
modeling shows that the State's BART determinations would result in 
the source still causing visibility impairment at Caney Creek (1.573 
[Delta]dv), Upper Buffalo (2.089 [Delta]dv), and Hercules Glade 
(1.541 [Delta]dv), and contributing to visibility impairment at 
Mingo (0.927) (Appendix 9.2B of the Arkansas Regional Haze SIP).
    \41\ See, e.g., William J. Gretta and others, The SCR Retrofit 
Design for the Seminole Generating Station, PowerGen, 2008, Hitachi 
SCR at Seminole Electric Delivers 0.04 lb/MMBtu NOX 
(Preliminary Results), FGD and DeNOX Newsletter, December 
2009, No. 380, and NOX CEMS data reported to Clean Air 
Markets.
    \42\ Clay Erickson, Robert Lisauskas, and Anthony Licata, What 
New in SCRs, DOE's Environmental Control Conference, May 16, 2006, 
p. 28. Available here: http://www.netl.doe.gov/publications/proceedings/06/ecc/pdfs/Licata.pdf; LG&E Energy, Selective Catalytic 
Reduction: From Planning to Operation, Competitive Power College, 
December 2005, p. 75-77.
    \43\ See also Sargent & Lundy, IPM Model--Revisions to Cost and 
Performance for APC Technologies, SDA FGD Cost Development 
Methodology, Final, August 2010, p. 1 (``It should be noted that the 
lowest available SO2 emission guarantees, from the 
original equipment manufacturers of SDA FGD systems, are 0.06 lb/
MMBtu.'').
    \44\ Georgia Environmental Protection Division, Longleaf Energy 
Station, Permit No. 4911-099-0033-P-01-0, April 9, 2010. Available 
at: http://airpermit.dnr.state.ga.us/gaairpermits/PermitPDF.aspx?id=PDF-PI-18499.
    \45\ U.S. EPA, Region 9, Prevention of Significant Deterioration 
Permit, Desert Rock Energy Company, July 31, 2008. Available at: 
http://www.regulations.gov/search/Regs/home.html#docketDetail?R=EPA-R09-OAR-2007-1110.
---------------------------------------------------------------------------

    Therefore, for the reasons expressed above, we are proposing to 
disapprove ADEQ's determination of SO2 and NOX 
BART for the AEP Flint Creek No. 1 Boiler.
c. Entergy Lake Catherine Unit 4 BART Determination
    The Entergy Lake Catherine Unit 4 is a BART-eligible source. Unit 4 
is a combustion engineering tilting tangential fired boiler powering a 
552 MW generator. The unit has a maximum heat input rate of 5850 MMBtu/
hr and burns primarily natural gas with No. 6 fuel oil as the secondary 
fuel. There is currently no emission control equipment connected to the 
boiler. Class I areas within 300 km of the facility include Caney 
Creek, Upper Buffalo, and Hercules Glades.
    Since Unit 4 is permitted to burn both natural gas and No. 6 fuel 
oil, ADEQ made BART determinations for both natural gas firing and fuel 
oil firing scenarios. The Arkansas RH SIP contains the CALPUFF pre-
control modeling files for the natural gas firing scenario, and ADEQ 
also provided the modeling files for the fuel oil firing scenario. 
CALPUFF post-control modeling results for both gas and oil firing were 
also included in the Arkansas RH SIP. In the State's September 27, 2011 
supplemental submittal, ADEQ brought to our attention that per an 
inspection report dated July 28, 2011, Entergy Lake Catherine Unit 4 is 
no longer capable of burning fuel oil. ADEQ noted that the fuel tanks 
at the source have been emptied and the pipework necessary to burn fuel 
oil is in the process of being removed. ADEQ stated the source does 
maintain the ability to burn natural gas. We note that since the source 
has not modified its permit and ADEQ has not revised its RH SIP to 
reflect this change, we are not disregarding the BART emission limits 
for the source for fuel oil firing in this proposed rulemaking.
    Regarding BART for SO2 and PM for the natural gas firing 
scenario, Entergy stated that most of the visibility-causing emissions 
from Unit 4 are due to NOX since SO2 and PM 
emissions from natural gas-fired boilers are generally very low. 
Therefore, for the natural gas

[[Page 64204]]

firing scenario for Unit 4, Entergy made no BART determination for 
SO2, and determined that BART for PM is the existing PM 
emission limit in the operating air permit. ADEQ agreed with the 
Entergy's determination. Revisions to the State's RH Rule, Chapter 15 
of APC&E Commission Regulation 19, which were submitted to us on August 
3, 2010, state the existing PM emission limit as of October 15, 2007 is 
PM BART for the natural gas firing scenario for Entergy Lake Catherine 
Unit 4. This corresponds to an emission limit of 45 lb/hr PM.\46\ We 
agree that SO2 and PM emissions from natural gas-fired 
boilers are generally very low, and therefore we are proposing to 
approve ADEQ's decision not to make a BART determination for 
SO2 for the natural gas firing scenario for Unit 4. Since we 
have found that the visibility impact of Unit 4 due to PM emissions 
alone (from natural gas firing) is so minimal such that the 
installation of any additional PM controls on the unit would likely 
achieve very low emissions reductions, have minimal visibility 
benefits, and not be cost-effective, we are also proposing to approve 
ADEQ's determination that BART for PM for Unit 4 for the natural gas 
firing scenario is the existing PM emission limit as of October 15, 
2007, or 45.0 lb/hr.
---------------------------------------------------------------------------

    \46\ See ADEQ Operating Air Permit for Entergy Arkansas Inc.-
Lake Catherine Plant (Permit No. 1717-AOP-R4). This permit can be 
viewed at http://www.adeq.state.ar.us/ftproot/pub/WebDatabases/PermitsOnline/Air/1717-AOP-R4.pdf.
---------------------------------------------------------------------------

    Regarding BART for NOX for the natural gas firing and 
fuel oil firing scenarios, Entergy conducted a BART analysis to 
determine what retrofit controls are BART for Lake Catherine Unit 4. In 
Step 1 of the BART analysis for NOX, Entergy considered a 
combination of the following NOX combustion controls for the 
natural gas firing scenario: boiler tuning, burners out of service 
(BOOS), induced flue gas recirculation (IFGR), overfire air (OFA), and 
low NOX burners (LNB). Entergy considered a combination of 
the following NOX combustion controls for the fuel oil 
firing scenario: boiler tuning, boiler modifications, BOOS, and forced 
flue gas recirculation (FFGR). However, Entergy did not consider post-
combustion controls for NOX, such as selective catalytic 
reduction (SCR) and selective non-catalytic reduction (SNCR), even 
though these controls are technically feasible and available 
technologies for reducing NOX emissions currently used by 
similar facilities. We provided comments to ADEQ to this effect on May 
1, 2007.\47\ In response to our comments, Arkansas included in its RH 
SIP submittal the results of a computerized model it obtained from 
Entergy, which according to the source, evaluated Unit 4's performance 
and the capital and operation and maintenance costs associated with 
each identified control technology. Entergy reported that the results 
of the computerized model showed that post-combustion controls, such as 
SCR and SNCR, had a cost that would be uneconomical to install. The 
results of this computer model are discussed further in our discussion 
of Step 4 of the BART analysis.
---------------------------------------------------------------------------

    \47\ Our comments on this matter are documented in Appendix 9.3B 
of the Arkansas RH SIP.
---------------------------------------------------------------------------

    For Step 3 of the NOX BART analysis, Entergy evaluated 
the control effectiveness of the control options considered in Step 1 
for both the natural gas and fuel oil firing scenarios. We generally 
agree with Entergy's evaluation of the control effectiveness of all 
control options considered. In Step 4 of the BART analysis, Entergy 
considered the costs of compliance for each control option. In 
evaluating the costs of compliance, Entergy analyzed the cost-
effectiveness in annualized dollars per ton of NOX removed 
($/ton) of the control options identified in Step 1 of the BART 
analysis for NOX for the natural gas and fuel oil firing 
scenarios. We note there are two flaws in Entergy's cost-analysis. 
Entergy provided no documentation or detailed breakdown of the cost 
estimates. The results of the computer model the source used to 
determine the cost-effectiveness of post-combustion controls also did 
not provide documentation or a detailed breakdown of the cost 
estimates. We have no basis to verify the validity of neither the cost 
estimates nor Entergy's determination based on the cost estimation 
analysis for BART. The basis for cost estimates should be documented 
either with data supplied by a vendor (i.e., budget estimates or bids) 
or by a referenced source. This was not done in the BART analysis. 
Furthermore, Unit 4 is a peaking unit,\48\ and Entergy attempted to 
account for this by assuming a 10% capacity factor \49\ in the 
calculation of the metrics for tons removed and $/ton removed for all 
control options considered in Step 1 of the BART analysis. The computer 
model Entergy used to estimate the cost effectiveness of post-
combustion controls likewise assumed a 10% capacity factor in the 
calculation of the metrics for tons removed and $/ton removed. Given 
that there are no permit requirements in place that would limit the 
operation of this unit to 10% capacity, the facility can legally be 
operated well above the 10% capacity factor assumed by Entergy. Thus, 
any cost effectiveness analysis based on a 10% capacity factor is 
likely to significantly inflate the cost per ton of controlling this 
unit. In support of the 10% capacity utilization factor, Entergy stated 
that the unit has operated, on average, at a capacity of 6.9% for the 
past three years. However, past use of this unit was much higher--
approximately 46% on average--over the 2001-2005 period.\50\ Given the 
variability in capacity utilization of this unit over the past ten 
years, the assumed 10% capacity utilization should be supported by an 
enforceable limit. Therefore, we are proposing to disapprove ADEQ's 
NOX BART determination for both the natural gas and fuel oil 
firing scenarios for Lake Catherine Unit 4.
---------------------------------------------------------------------------

    \48\ 40 CFR 72.2 defines a peaking unit as ``[a] unit that has 
(i) An average capacity factor of no more than 10.0 percent during 
the previous three calendar years and (ii) A capacity factor of no 
more than 20.0 percent in each of those calendar years.''
    \49\ 40 CFR 72.2 defines capacity factor as either ``(1) The 
ratio of a unit's actual annual electric output (expressed in MWe/
hr) to the unit's nameplate capacity (or maximum observed hourly 
gross load (in MWe/hr) if greater than the nameplate capacity) times 
8760 hours; or (2) The ratio of a unit's annual heat input (in 
million British thermal units or equivalent units of measure) to the 
unit's maximum rated hourly heat input rate (in million British 
thermal units per hour or equivalent units of measure) times 8,760 
hours.
    \50\ Table 2-1 of the ``BART Analysis for Lake Catherine Plant- 
Unit 4,'' prepared by Robert Paine, December 2006 notes that Unit 4 
was operated 6,988 hours in 2001 (79.7% utilization); 5,651 hours in 
2002 (64.5% utilization); 3,972 hours in 2003 (45.3% utilization); 
1,534 hours in 2004 (17.5% utilization); and 2,059 hours in 2005 
(23.5% utilization).
---------------------------------------------------------------------------

    For SO2 BART for the fuel oil-firing scenario, Entergy 
identified only one available control option in Step 1 of the BART 
analysis- use of fuel oil with low sulfur content. ADEQ agreed with the 
source's decision. Entergy only considered the use of fuel oil with 1%, 
0.5%, and 0.2% sulfur content by weight. We note use of fuel oil with 
1% sulfur content is the base case, as Entergy stated the source's 
current Title V permit limits the sulfur content of fuel oil used to 
1%. Entergy did not consider any post-combustion SO2 
controls in the BART analysis, even though post-combustion control 
technologies, such as wet and dry scrubbers, are currently being used 
by comparable facilities to control SO2 emissions. As such, 
Entergy did not identify and consider control technologies that are 
capable of the maximum level of control that is achievable, as is 
required by the BART guidelines and the RHR. In Step 3 of the

[[Page 64205]]

BART analysis, Entergy considered the control effectiveness of all 
technically feasible control options identified in Step 1 by using AP-
42 factors for 1%, 0.5%, and 0.2% sulfur residual oil to determine the 
amount of sulfur dioxide emissions that would be eliminated by use of 
low sulfur fuel oil. Entergy found that based on a 10% capacity factor, 
use of 0.5% sulfur fuel oil would result in 1,059 tpy SO2 
removed from the baseline and use of 0.2% sulfur fuel oil would result 
in 1,802 tpy SO2 removed from the baseline. In Step 4 of the 
BART analysis, Entergy considered the costs of compliance for each 
control option. Entergy provided no documentation or detailed breakdown 
of the costs estimates for low sulfur fuel oil. Therefore, we have no 
basis to verify the validity of either the cost estimates or ADEQ's 
BART determination based on the cost estimation. The basis for cost 
estimates should be documented, and should clearly indicate the amount 
of fuel oil that corresponds to the annual cost listed in the cost-
analysis. After conducting post-control visibility modeling, Entergy 
determined and ADEQ agreed that SO2 BART for the fuel oil 
firing scenario is an SO2 emission limit of 0.562 lb/MMBtu 
on a 30 day rolling average. The RH SIP provides conflicting 
information on whether this emission limit corresponds to use of 1% or 
0.5% sulfur fuel oil. On September 27, 2011, ADEQ submitted a 
supplemental submittal clarifying that the 0.562 lb/MMBtu emission 
limit corresponds to use of 0.5% sulfur content fuel oil. However, for 
the reasons discussed above, we are proposing to find that the source 
and ADEQ did not properly follow the requirements of section 
51.308(e)(1)(ii)(A) in determining SO2 BART for the fuel oil 
firing scenario. Specifically, we are proposing that ADEQ did not 
properly take into consideration ``the technology available'' and ``the 
costs of compliance.''
    Regarding BART for PM for the fuel oil firing scenario, Entergy 
identified the PM10 emission rates associated with use of 
1%, 0.5%, and 0.2% sulfur fuel oil. Entergy determined PM BART for Unit 
4 for the fuel oil firing scenario is 0.037 lb/MMBtu on a 30 day 
rolling average. ADEQ's September 27, 2011 supplemental submittal 
clarified that this PM emission limit corresponds to use of 0.5% sulfur 
content fuel oil. ADEQ and Entergy did not consider any post-combustion 
controls in the BART analysis for PM for the fuel oil firing scenario. 
We note the use of a wet scrubber system that controls both 
SO2 and PM emissions may prove to be cost-effective and 
provide for substantial visibility improvement and should therefore be 
considered in Unit 4's BART analysis.
    We are proposing to find that Entergy and ADEQ did not properly 
follow the requirements of section 51.308(e)(1)(ii)(A) in determining 
BART for NOX for both the natural gas and fuel oil firing 
scenarios and BART for SO2 and PM for the fuel oil firing 
scenario for the Entergy Lake Catherine Unit 4. Specifically, we are 
proposing that ADEQ did not properly take into consideration ``the 
technology available'' and ``the costs of compliance.'' For the reasons 
identified above, we are proposing to disapprove ADEQ's BART 
determinations for PM, NOX, and SO2 under oil 
firing conditions, and NOX under natural gas firing 
conditions. We are proposing to approve ADEQ's BART determination for 
the Entergy Lake Catherine Unit 4 for PM under gas firing conditions 
and ADEQ's decision to make no BART determination for SO2 
under gas firing conditions.
d. Entergy White Bluff Units 1, 2, and Auxiliary Boiler BART 
Determinations
    The White Bluff Units 1 and 2 and the Auxiliary Boiler are BART-
eligible sources. Units 1 and 2 are coal fired boilers with a maximum 
power rating of 850 MW each and a heat input rate of 8700 MMBtu/hr 
each. Units 1 and 2 are permitted to burn both sub-bituminous and 
bituminous coal as the primary fuel and No. 2 fuel oil or bio-diesel as 
the start-up fuel. The Auxiliary Boiler is a 183 MMBtu/hr boiler that 
is permitted to burn only No. 2 fuel oil or biodiesel. The Class I 
areas located within 300 km of the facility are Caney Creek, Upper 
Buffalo, and Hercules Glades. Since Units 1 and 2 are permitted to burn 
both bituminous and sub-bituminous coal, ADEQ made separate BART 
determinations for bituminous sub-bituminous coal firing.
    Regarding BART for PM for Units 1 and 2, neither Entergy nor ADEQ 
performed a BART analysis to determine what retrofit controls are BART 
for Units 1 and 2. The source's rationale for this, which ADEQ agreed 
with, was its belief that most of the visibility-causing emissions from 
Units 1 and 2 are due to SO2 and NOX, and 
PM10 emissions are well-controlled with existing 
electrostatic precipitators (ESPs). We reviewed the CALPUFF visibility 
modeling submitted by ADEQ for Entergy White Bluff, and agree that PM 
emissions from the source have minimal visibility impacts at each Class 
I area within 300 km. Revisions to the Arkansas RH Rule (APC&E 
Commission Regulation 19, chapter 15) that were submitted to us by ADEQ 
on August 3, 2010, state the PM BART emission limit for White Bluff 
Units 1 and 2 is the existing PM emission limit in the air permit as of 
October 15, 2007. The federally enforceable operating air permit states 
the PM emissions from the two units are controlled with ESPs and 
requires that the two units comply with a PM emission standard of 0.10 
lb/MMBtu.\51\ Since we have found that the visibility impact of the 
source due to PM emissions alone is so minimal such that the 
installation of any additional PM controls on the units would likely 
achieve very low emissions reductions, have minimal visibility 
benefits, and not be cost-effective, we are proposing to approve ADEQ's 
determination that PM BART for both the bituminous and sub-bituminous 
coal firing scenarios is the existing PM emission limit for Units 1 and 
2.
---------------------------------------------------------------------------

    \51\ ADEQ Operating Air Permit for Entergy Services Inc.--White 
Bluff Plant (Permit No. 0263-AOP-R6). This permit can be viewed at 
http://www.adeq.state.ar.us/ftproot/pub/WebDatabases/PermitsOnline/Air/0263-AOP-R6.pdf.
---------------------------------------------------------------------------

    Regarding SO2 BART for White Bluff Units 1 and 2, 
Entergy performed a BART analysis and determined that the presumptive 
limits of 0.15 lb/MMBtu for both the sub-bituminous and bituminous coal 
firing scenarios for SO2 for Units 1 and 2 apply to the two 
units because they are greater than 200 MW each. Although Entergy 
performed a BART analysis for BART for SO2, it considered 
only those control options that meet the presumptive limit of 0.15 lb/
MMBtu, without considering whether a more stringent SO2 
emission limit is BART for Units 1 and 2. As stated elsewhere in this 
proposed rulemaking, the BART guidelines and the RHR require 
consideration of the most stringent control technology in the BART 
analysis. Because the control technology options considered in the BART 
analysis are capable of achieving a lower emission limit than the 
presumptive limit for this facility, and these controls are being 
currently used by similar facilities to control SO2 
emissions to an emission limit lower than the presumptive limit, 
consideration of these technologies and the lowest emission limit 
achievable must be included in the BART analysis.
    In Step 1 of the SO2 BART analysis for Units 1 and 2, 
Entergy identified two available options to control the units to the 
presumptive SO2 limit: limestone forced oxidation (wet 
scrubbing) and lime spray dryer (dry scrubbing). Entergy did not 
identify either control option as technically infeasible. In Step

[[Page 64206]]

3 of the BART analysis, Entergy evaluated the control effectiveness of 
the two control options, stating the wet scrubber can achieve up to 95% 
control efficiency while the dry scrubber can achieve up to 92% control 
efficiency. In Step 4 of the BART analysis, Entergy evaluated the costs 
of compliance for the two control options. Entergy determined the 
installation of a wet scrubber would have an annualized cost of 
$17,023,735 with a cost effectiveness of $620/ton SO2 
removed at Unit 1 and an annualized cost of $17,159,021 with a cost-
effectiveness of $620/ton SO2 removed at Unit 2. Entergy 
also determined the installation of a dry scrubber would have an 
annualized cost of $34,035,909 with a cost effectiveness of $1280/ton 
SO2 removed at Unit 1 and an annualized cost of $34,306,388 
with a cost-effectiveness of $1280/ton SO2 removed at Unit 
2. In Step 5 of the BART analysis, Entergy evaluated the visibility 
impacts of the two control options. However, Entergy's modeling 
underestimated the visibility benefit anticipated from the use of wet 
or dry scrubbers because it modeled both control options at the same 
SO2 emission rate of 0.15 lb/MMBtu, rather than at the 
achievable control effectiveness of 92% removal for dry scrubbing and 
95% for wet scrubbing. We also note that Entergy deviated from the 
modeling protocol and used the 98th percentile (8th highest modeled 
day) in this analysis instead of the maximum modeled visibility impact. 
Entergy's post-control modeling showed that the visibility benefits for 
dry scrubbers and wet scrubbers is nearly the same (with dry scrubbing 
being slightly better due to a hotter plume and lower sulfuric acid 
emissions), while the annualized cost of a dry scrubber is nearly twice 
that of a wet scrubber. Entergy determined and ADEQ agreed that BART 
for SO2 for Units 1 and 2 is installation and operation of a 
wet scrubber at each unit to achieve the presumptive BART limit of 0.15 
lb/MMBtu for both the sub-bituminous and the bituminous coal firing 
scenarios. Entergy considered a wet scrubber achieving 0.15 lb/MMBtu to 
be the most stringent technology available. But as discussed elsewhere, 
wet scrubbers and dry scrubbers have been documented to achieve much 
lower emissions, including emissions as low as .065 lbs/MMBtu for dry 
scrubbers. Therefore, the evaluation is not acceptable. In addition, we 
note that the 0.15 lb/MMBtu presumptive BART limit established by ADEQ 
corresponds to 82% control removal of the wet scrubber at Unit 1 and 
80% control removal at Unit 2, as indicated by ADEQ in the Arkansas RH 
SIP narrative.\52\ Table A-1 in Appendix A of the BART analysis 
indicates the cost-effectiveness of installing and operating a wet 
scrubber is $620/ton SO2 removed. Although Table A-1 
indicates such cost-effectiveness value corresponds to operation of the 
wet scrubber at 95% control efficiency, neither ADEQ nor Entergy 
provided a breakdown of the cost estimates and we were therefore unable 
to verify whether it in fact corresponds to 95% control efficiency or 
if it corresponds to 80% control efficiency at Unit 2 and 82% control 
efficiency at Unit 1. Even if the $620/ton SO2 removed cost-
effectiveness value corresponds to only 82% control efficiency for Unit 
1 and 80% control efficiency for Unit 2, we believe that the 
incremental cost of operating the wet scrubber at 95% vs. 80% and 82% 
control efficiency is relatively minimal, and is likely cost-effective. 
Since Entergy and ADEQ considered only the 0.15 lb/MMBtu SO2 
presumptive limit in the BART analysis for Units 1 and 2, even though a 
lower limit is technically achievable and more than likely cost-
effective, we are proposing to disapprove ADEQ's determination that 
BART for SO2 for Units 1 and 2 is the presumptive limit of 
0.15 lb/MMBtu on a 30-day rolling average for both the sub-bituminous 
and bituminous coal firing scenarios.
---------------------------------------------------------------------------

    \52\ See Table 9.3a of the Arkansas RH SIP.
---------------------------------------------------------------------------

    Regarding NOX BART for White Bluff Units 1 and 2, 
Entergy performed a BART analysis in which available combustion control 
technologies to control NOX to the presumptive limit of 0.15 
lb/MMBtu for the sub-bituminous coal-firing scenario and 0.28 lb/MMBtu 
for the bituminous coal-firing scenario were considered. As in the 
SO2 BART analysis for Units 1 and 2, Entergy did not 
consider establishing NOX BART emission limits more 
stringent than the NOX presumptive limits. In Step 1 of the 
NOX BART analysis, Entergy considered the following control 
options: boiler tuning, OFA, and LNB. Entergy did not evaluate post-
combustion controls such as SCR and SNCR or any other NOX 
control options capable of emission limits more stringent than the 
presumptive limits, when these are technically feasible and available 
and are currently being used by comparable facilities to control 
NOX emissions at rates more stringent than the presumptive 
limit. Since Entergy did not identify the maximum control technology 
available as a control option in Step 1 of the BART analysis, the 
subsequent analysis in the remaining steps was incomplete. However, for 
the sake of providing a fuller picture of our evaluation of Entergy's 
BART analysis for NOX for White Bluff Units 1 and 2, we 
discuss the remaining steps of the BART analysis.
    Entergy did not identify any of the NOX controls it 
listed in Step 1 of the BART analysis as being technically infeasible. 
In Step 3 of the BART analysis, Entergy evaluated the control 
effectiveness of the control options. Entergy determined boiler tuning 
will result in 37% control removal; a combination of boiler tuning and 
OFA will result in 53.6% control removal; and a combination of boiler 
tuning, OFA, and LNB will result in 69% control efficiency at each 
unit. In Step 4 of the BART analysis, Entergy evaluated the costs of 
compliance for the control options considered and determined that a 
combination of boiler tuning, OFA, and LNB has a control effectiveness 
of $463/ton NOX removed for Unit 1 and $437/ton 
NOX removed for Unit 2. We note Entergy's cost analysis of 
the NOX control options included no documentation or 
detailed breakdown of the costs. We have no basis to verify the 
validity of neither the cost estimates nor Entergy and ADEQ's 
determination based on the analysis of cost estimation for BART. The 
basis for cost estimates must be documented either with data supplied 
by an equipment vendor (i.e., budget estimates or bids) or by a 
referenced source. This was not done. Without either ADEQ or Entergy 
providing a breakdown of costs of material, labor, operation and 
maintenance, etc, we cannot verify the accuracy of Entergy's cost 
effectiveness determination. Furthermore, the cost-effectiveness 
analysis is problematic because Entergy assumed, and ADEQ agreed with, 
an 85% utilization of the two units when the units are capable of 100% 
utilization and there is no federally enforceable limit of 85% 
utilization in place.\53\ Since the two units are technically and 
legally capable of operating at 100% utilization, a cost estimate 
assuming 85% utilization may underestimate the amount of emission 
reductions achieved by the controls and therefore under-represent the 
potential cost-effectiveness of such controls. In Step 5 of the BART 
analysis, Entergy evaluated the visibility impacts of the control 
options and subsequently determined that a combination of boiler

[[Page 64207]]

tuning, OFA, and LNB is BART for NOX for Units 1 and 2, 
achieving an emission limit of 0.15 lb/MMBtu for the sub-bituminous 
coal firing scenario and 0.28 lb/MMBtu for the bituminous coal firing 
scenario. ADEQ agreed with the Entergy's determination.
---------------------------------------------------------------------------

    \53\ Based on operating hours provided by Entergy for Units 1 
and 2, Unit 1 was operated 92.5% of the time in 2003, and Unit 2 was 
operated 92.7% of the time in 2004. See Table 2-1, under Section 2.2 
of the BART analysis for Entergy White Bluff Units 1 and 2 (found in 
Appendix 9.3A of the RH SIP).
---------------------------------------------------------------------------

    As already explained in our evaluation of BART for SO2 
for Units 1 and 2, we disagree with Entergy and ADEQ's approach of not 
considering an emission limit more stringent than the presumptive limit 
when comparable facilities have used control technologies to reduce 
emissions below the presumptive limit. Also, as explained elsewhere in 
this notice, the BART Rule does not suggest the presumptive limits 
should be viewed as establishing a safe harbor from more stringent 
regulation under the BART provisions. ADEQ's CALPUFF pre-control 
modeling indicates the three subject to BART units at White Bluff 
together cause visibility impairment at Caney Creek, Upper Buffalo, 
Hercules Glade, Mingo, and Sipsey.\54\ A considerable portion of this 
visibility impairment is due to NOX emissions. ADEQ's post-
control modeling indicates the three subject to BART units at White 
Bluff combined would still cause visibility impairment at all five 
Class I areas modeled (Caney Creek, Upper Buffalo, Hercules Glade, 
Mingo and Sipsey), and that a considerable portion of the post-control 
modeled visibility impairment is due to NOX emissions. In 
light of the post-control modeling results, ADEQ and/or Entergy should 
have considered additional post-combustion controls, such as SNCR and 
SCR, that are capable of achieving NOX emission limits well 
below the NOX presumptive limits, and have been widely used 
by similar facilities to achieve emissions at rates below the 
presumptive limit. Therefore, we are proposing to disapprove ADEQ's 
determination that BART for NOX for White Bluff Units 1 and 
2 is 0.15 lb/MMBtu for the sub-bituminous coal firing scenario and 0.28 
lb/MMBtu for the bituminous coal firing scenario.
---------------------------------------------------------------------------

    \54\ The maximum modeled pre-control [Delta]dv values at 
surrounding Class I areas due to the three subject-to-BART units at 
White Bluff are: Caney Creek= 8.816 [Delta]dv; Upper Buffalo= 7.750 
[Delta]dv; Hercules Glade=6.314 [Delta]dv; Mingo=5.617; and 
Sipsey=5.843. See Appendix 9.2C of the Arkansas RH SIP.
---------------------------------------------------------------------------

    With regard to the Auxiliary Boiler, neither ADEQ nor Entergy 
conducted a BART analysis that considered the statutory factors states 
are required to consider in determining what level of control is BART 
for a source, whether this be an emission limit or a work practice 
standard. The Arkansas RH SIP narrative states ADEQ decided to 
establish work practice standards for this source pursuant to 40 CFR 
51.308(e)(1)(iii), rather than establish BART emission limits for 
SO2, NOX, and PM. APC&E Commission Regulation 19, 
Chapter 15, established that BART for the Auxiliary Boiler is a 
restriction to operate no more than 4360 hours annually. Since ADEQ's 
pre and post-control visibility modeling shows the visibility impact on 
surrounding Class I areas of all three units at the facility combined, 
we are not able to assess the visibility impact on Class I areas of the 
Auxiliary Boiler alone. The operating permit indicates the Auxiliary 
Boiler combusts No. 2 fuel oil or biodiesel to provide steam for Unit 1 
and 2 start-up activities. The restriction established by ADEQ as BART 
would allow the Auxiliary Boiler to operate 50% of the time on an 
annual basis. In practice, an auxiliary boiler that is only needed for 
start-up is typically operated much less than that. We are proposing to 
find that ADEQ did not properly follow the requirements of section 
51.308(e)(1)(ii)(A) because neither ADEQ nor Entergy performed a BART 
analysis for the Auxiliary Boiler for their chosen work practice 
standard. We are proposing to disapprove ADEQ's determination that BART 
for the White Bluff Auxiliary Boiler is a restriction to operate no 
more than 4360 hours annually.
e. Domtar Power Boilers No. 1 and 2 BART Determinations
    The Domtar Power Boilers No. 1 and 2 are BART-eligible sources. The 
Power Boilers generate steam and electricity for the other processes 
within the Domtar kraft pulp mill. The No. 1 Power Boiler has a heat 
input rating of 580 MMBtu/hr and is permitted to burn bark, wood waste, 
municipal yard waste, recycled sanitary products composed of cellulose 
and polypropylene, pelletized paper fuel (PPF), No. 6 fuel oil, used 
oil generated on site, reprocessed fuel oil, tire derived fuel (TDF), 
and natural gas. The No. 1 Power Boiler is equipped with a traveling 
grate, a combustion air system, and a wet ESP for removal of PM 
emissions. According to the operating air permit, the No. 1 Power 
Boiler's permitted emission rate for PM/PM10 is 0.07 lb/
MMBtu. The operating air permit provides that the sulfur content of the 
fuel oil used at the No.1 Power Boiler shall not exceed 3.0% by weight 
and that the No. 1 Power Boiler shall not use more than 2,700,000 
gallons of fuel oil for any consecutive 12-month period. The permit 
also limits the total amount of TDF used at the Power Boilers No. 1, 2, 
and 3 combined to 220 tons in any 24-hour period.
    The No. 2 Power Boiler has a heat input rating of 820 MMBtu/hr and 
burns primarily pulverized bituminous coal, but is also permitted to 
burn non-condensable gases (NCGs), bark and wood chips used to absorb 
oil spills, wood waste, municipal yard waste, natural gas, used oil 
generated on site, recycled sanitary products based on cellulose and 
polypropylene, No. 6 fuel oil, reprocessed fuel oil, TDF, and petroleum 
coke. The No. 2 Power Boiler is equipped with a traveling grate, 
combustion air system including OFA, multiclones for removal of PM 
emissions, and two venturi scrubbers in parallel for removal of 
remaining PM emissions and SO2. According to the operating 
air permit, the No. 2 Power Boiler's permitted emission rate for PM/
PM10 is 0.1 lb/MMBtu.
    Regarding BART for PM, Domtar stated the No. 1 and 2 Power Boilers 
were at the time subject to the Boiler Maximum Achievable Control 
Technology (MACT) PM emission standard of 0.07 lb/MMBtu. A wet ESP was 
installed at the No. 1 Power Boiler to meet the 0.07 lb/MMBtu Boiler 
MACT PM emission standard. Domtar also stated that the No. 2 Power 
Boiler's existing wet scrubber is capable of meeting the Boiler MACT PM 
emission standard. Domtar noted that in the BART Guidelines, EPA 
encourages the use of streamlined approaches for BART determinations 
and elected to forego a BART analysis and to presumptively rely on the 
0.07 lb/MMBtu Boiler MACT PM emission standard in existence at the time 
to meet the BART PM requirements for both the No. 1 and No. 2 Power 
Boilers. We note the BART Guidelines (Appendix Y to Part 51) provide 
that for VOC and PM sources subject to MACT standards, States may 
streamline the BART analysis by including a discussion of the MACT 
controls and whether any major new technologies have been developed 
subsequent to the MACT standards. The 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, sources may 
rely on the MACT standards for purposes of BART.
    Concerning Power Boiler No. 1, Domtar provided a discussion of 
other PM control technologies available at the time, and determined 
that a wet ESP with a PM emission limit of 0.07 lb/MMBtu on a 30-day 
rolling average is BART for Power Boiler No. 1. ADEQ agreed with 
Domtar's determination. We agree that ADEQ's determination for BART for 
PM for Power Boiler No. 1 is consistent with the BART Guidelines and 
are proposing to approve it.

[[Page 64208]]

Concerning Power Boiler No. 2, Domtar stated that the unit was subject 
to the Boiler MACT \55\ PM emission standard in existence at the time 
(0.07 lb/MMBtu), and indicated its intent to presumptively rely on such 
standard to meet BART PM requirements for Power Boiler No. 2. However, 
instead of adopting 0.07 lb/MMBtu as the BART PM emission limit for 
Power Boiler No. 2, ADEQ adopted 0.10 lb/MMBtu as the BART PM emission 
limit. Since ADEQ did not select the Boiler MACT PM emission standard 
current at the time the BART determination was made as the BART PM 
emission limit for Power Boiler No. 2, ADEQ cannot elect to take the 
streamlined approach provided in the BART Guidelines. If ADEQ chooses 
to take the streamlined approach provided in the BART Guidelines, ADEQ 
must select the Boiler MACT PM standard if it determines there are no 
new and cost-effective technologies or available upgrades developed 
subsequent to the MACT standard. Otherwise, ADEQ and/or Domtar must 
perform a complete BART analysis that considers the statutory factors 
under section 51.308(e)(ii)(A) to determine BART for PM for Power 
Boiler No. 2. Furthermore, ADEQ's pre-control visibility modeling 
indicates a considerable portion of the combined visibility impact of 
No. 1 and 2 Power Boilers at Caney Creek is due to PM emissions.\56\ 
Therefore, we are proposing to disapprove ADEQ's determination that 
BART for PM10 for Power Boiler No. 2 is 0.10 lb/MMBtu on a 
30-day rolling average, and we are proposing to approve ADEQ's 
determination that BART for PM10 for Power Boiler No. 1 is 
0.07 lb/MMBtu on a 30-day rolling average.
---------------------------------------------------------------------------

    \55\ The MACT standards are part of the National Emission 
Standards for Hazardous Air Pollutants for Source Categories 
(NESHAP), provided under 40 CFR 63.
    \56\ ADEQ's pre-control modeling files are found in Appendix 
9.2B of the Arkansas RH SIP. Since ADEQ's visibility modeling shows 
the visibility impact of No. 1 and 2 Power Boilers combined, we were 
unable to assess the visibility impact of No. 2 Power Boiler 
individually on surrounding Class I areas.
---------------------------------------------------------------------------

    Regarding BART for SO2 for Power Boiler No. 1, Domtar 
noted pre-combustion controls such as fuel switching/blending and fuel 
cleaning are ineffective, as wood has low sulfur content. Domtar also 
noted post-combustion controls such as flue gas desulfurization (FGD) 
and (i.e., wet and dry scrubbers) have not been installed on wood-fired 
boilers because of the relatively low SO2 emissions from 
wood combustion. Domtar determined that due to the low sulfur content 
of wood, SO2 emissions from wood combustion are inherently 
low and ``have a negligible impact on visibility impairment.'' Domtar 
determined SO2 BART for Power Boiler No. 1 is no additional 
SO2 controls beyond the existing fuel restrictions (fuel oil 
with a maximum 3.0% sulfur content and a usage limitation of 2,700,000 
gallons of fuel oil per consecutive 12-month period) are necessary. 
ADEQ agreed with Domtar's determination and decided that an emission 
limit of 1.12 lb/MMBtu on a 30-day rolling average is BART for 
SO2 for Power Boiler No. 1. We note that ADEQ's CALPUFF pre-
control modeling demonstrates the No. 1 Power Boiler emits more than 
one-third of the total modeled emissions of SO2 from the two 
sources.
    We agree that due to the low sulfur content of wood, SO2 
emissions from wood-fired boilers are generally relatively low. Table 
1.6-2 of EPA's Compilation of Air Pollutant Emission Factors indicates 
the combustion of wood waste has a typical SO2 emission rate 
of 0.025 lb/MMBtu.\57\ In light of this, we question the 
appropriateness of an SO2 emission limit of 1.12 lb/MMBtu 
for Power Boiler No. 1. Neither ADEQ nor Domtar provided any support 
for this emission limit. Domtar stated that approximately 75 percent of 
the heat input for Power Boiler No. 1 is supplied by bark. A unit 
combusting primarily bark should be capable of achieving an 
SO2 emission rate much lower than 1.12 lb/MMBtu. The 
facility's current permit for this unit limits its annual 
SO2 emissions to 214 tons per year (tons/year), which is a 
low figure. Therefore, there appears to be a mismatch between ADEQ's 
relatively high BART SO2 emission limit and what the 
facility actually needs, based on its current permit. As part of its 
BART analysis, ADEQ and/or Domtar should have conducted a fuel 
inventory of this boiler in order to explore this issue. Other sources 
of potential sulfur emissions should have been investigated, including 
emissions resulting from burning fuel oil and TDF. ADEQ should also 
have considered lowering the sulfur content of fuel oil burned at the 
source, and/or lowering the limit on fuel oil usage. If Power Boiler 
No. 1 truly needs such a high SO2 emission limit, then ADEQ 
and/or the Domtar should have investigated the feasibility, 
effectiveness, and cost of SO2 controls. Therefore, we are 
proposing to find that ADEQ did not properly follow the requirements of 
section 51.308(e)(1)(ii)(A) in determining BART. We are proposing to 
disapprove ADEQ's determination that BART for SO2 for Power 
Boiler No. 1 is 1.12 lb/MMBtu on a 30-day rolling average.
---------------------------------------------------------------------------

    \57\ Compilation of Air Pollutant Emission Factors, Volume I: 
Stationary Point and Area Sources, AP-42, 5th Edition, January 1995.
---------------------------------------------------------------------------

    Regarding BART for SO2 for Power Boiler No. 2, neither 
ADEQ nor Domtar performed a BART analysis that considered the statutory 
factors under section 51.308(e)(ii)(A). Domtar stated the unit is 
equipped with a wet scrubber for control of SO2 and PM 
emissions. According to Domtar, the existing wet scrubber currently 
achieves an SO2 control efficiency of approximately 90%. 
Domtar indicated that the BART Guidelines provide an option to skip the 
comprehensive BART analysis for subject to BART units already equipped 
with the most stringent controls available, including all possible 
improvements to control devices, as long as these are made federally 
enforceable for the purpose of implementing BART for the source. Domtar 
stated that since wet scrubbing is the most effective method of 
controlling SO2 emissions and it has not identified any 
feasible upgrades to the existing wet scrubber, no BART analysis is 
necessary. ADEQ agreed with Domtar, and determined that no additional 
SO2 removal is needed for the No. 2 Power Boiler, and BART 
for SO2 is 1.20 lb/MMBtu on a 30-day rolling average using 
the existing wet scrubber.
    We agree that the BART Guidelines allow sources to forego the BART 
analysis when the source already has the most stringent controls 
available in place and all possible improvements to control devices 
have been made. However, we disagree that a 1.20 lb/MMBtu 
SO2 emissions rate corresponds to the most stringent control 
available. We note FGD systems are capable of SO2 reduction 
efficiencies up to 98%.\58\ Therefore, the 90% reduction efficiency 
claimed by Domtar does not correspond to the highest SO2 
control efficiency wet scrubbers are capable of achieving. The highest 
SO2 control efficiency issue aside, although Domtar stated 
it did not identify any feasible upgrades to the existing wet scrubber, 
it provided no documentation of what upgrades were considered and why 
they were found to be technical infeasible. In considering all possible 
improvements to the scrubber, Domtar should have evaluated options that 
not only improve the design removal efficiency of the scrubber vessel 
itself, but also considered upgrades that can improve the overall 
SO2 removal efficiency of the scrubber system. For example, 
the

[[Page 64209]]

BART Guidelines state that improving maintenance practices, adjusting 
scrubber chemistry, and increasing auxiliary equipment redundancy are 
some ways to improve average SO2 removal efficiencies. For 
the reasons discussed above, we are proposing to find that ADEQ did not 
properly follow the requirements of section 51.308(e)(1)(ii)(A) in 
determining BART for SO2 for Power Boiler No. 2. We are 
proposing to disapprove ADEQ's determination that BART for 
SO2 for the No. 2 Power Boiler is 1.20 lb/MMBtu on a 30-day 
rolling average using the existing wet scrubber.
---------------------------------------------------------------------------

    \58\ See EPA's Air Pollution Control Fact Sheet on FGD control 
technology, available at http://www.epa.gov/ttn/catc/dir1/ffdg.pdf.
---------------------------------------------------------------------------

    Regarding BART for NOX for Power Boilers No. 1 and 2, 
Domtar performed a BART analysis to determine what controls are BART 
for the two boilers. In Step 1 of the NOX BART analysis, 
Domtar identified the following control technologies: boiler tuning/
optimization, fuel blending, FGR, LNB, OFA, SCR, SNCR, and reburning/
methane de-NOX. Domtar stated the source has employed and 
intends to continue to employ the latest boiler optimization and tuning 
techniques, and that such control technologies are considered part of 
the base case for Power Boilers No. 1 and 2. Similarly, Domtar 
explained it historically mixes 10-15% (heat input basis) wood with 
coal in the No. 2 Power Boiler and therefore fuel blending is 
considered part of the base case for the No. 2 Power Boiler. In Step 3 
of the BART analysis, Domtar evaluated the technical feasibility of 
each control option. Domtar explained that since wood is inherently low 
in nitrogen content, fuel blending is not technically feasible for 
wood-fired boilers, and therefore eliminated this as a control option 
for Power Boiler No. 1. Regarding FGR, Domtar asserted that only 
thermal NOX can be controlled by FGR. As most NOX 
emissions from the No. 1 and No. 2 Power Boilers are due to fuel 
NOX rather than thermal NOX, Domtar determined 
FGR is technically infeasible for both power boilers. Domtar stated 
that combustion modification with LNB is used in both gas/oil-fired and 
coal fired units, but is not used for wood-fired boilers. Therefore, 
Domtar determined use of LNB is technically infeasible for Power Boiler 
No. 1. Regarding use of OFA, Domtar stated the source was informed by 
one OFA vendor that while OFA results in decreased NOX 
emissions, the primary purpose is combustion optimization, and 
implementation of OFA can actually increase NOX emissions in 
certain circumstances. Based on this, Domtar determined an OFA system 
upgrade at Power Boilers No. 1 and 2 is technically infeasible and 
eliminated this as a control option for both units in question. Domtar 
determined that methane de-NOX is the only technically 
feasible NOX control option for Power Boiler No. 1 and 
methane de-NOX and LNB are the only two technically feasible 
NOX control options for Power Boiler No. 2. In so doing, 
Domtar determined that SCR and SNCR are technically infeasible control 
options for No. 1 and 2 Power Boilers because they are not suited for 
power boilers that experience wide temperature variances and high load 
swings. We note a review of the RACT/BACT/LAER Clearinghouse (Process 
types 11.120 and 11.190) indicates there are several wood-fired utility 
boilers that employ SNCR. In particular, a similar source, the bark 
boiler at Temple Inland Kraft Linerboard Mill in Orange, Texas, employs 
SNCR, Low Excess Air (LEA), and low NOX gas burners.\59\ The 
Temple Inland Kraft boiler has a NOX emission limit of 0.166 
lb/MMBtu on a 30 day rolling average. Like the Domtar Power Boilers No. 
1 and 2, the Temple Inland Kraft boiler exhibits load swing. We also 
note there are other similarities in the operating parameters of the 
bark boiler at Temple Inland Kraft and Power Boiler No. 1 (the bark 
boiler) at Domtar. Like Power Boiler No. 1 at Domtar, the bark boiler 
at Temple Inland Kraft is permitted to burn, among other fuel sources, 
bark/wood biomass, natural gas, and tire-derived fuel. The Temple 
Inland Kraft bark boiler has a maximum heat input rating of 656 MMBtu/
hr, while Domtar Power Boiler No. 1 has a maximum heat input rating of 
580 MMBtu/hr. In conducting its BART analysis, ADEQ and/or Domtar 
should have more carefully considered the use of post-combustion 
control technologies, such as SNCR, for both power boilers at Domtar, 
since SNCR is a control technology that has been used at similar 
facilities to control NOX emissions. Because ADEQ eliminated 
some of the control options as being technically infeasible in Step 2 
of the BART analysis, the subsequent analysis in remaining steps was 
incomplete. However, for the sake of providing a fuller picture of our 
evaluation of Domtar's BART analysis for NOX for Domtar 
Power Boilers No. 1 and 2, we discuss the remaining steps of the BART 
analysis.
---------------------------------------------------------------------------

    \59\See the docket for this rulemaking to view the Title V 
permit for the Temple Inland Kraft Linerboard Mill.
---------------------------------------------------------------------------

    In Step 3 of the BART analysis, Domtar evaluated the control 
effectiveness of the control options it considered technically 
feasible. Domtar determined that methane de-NOX has a 
potential control efficiency of 50%, whereas LNB has a potential 
control efficiency of 30%. In Step 4 of the BART analysis, Domtar 
evaluated the cost of compliance for each control option. Domtar 
determined the cost-effectiveness of methane de-NOX is 
$7,262/ton NOX removed at Power Boiler No. 1 and $4,259/ton 
NOX removed at Power Boiler No. 2, while the cost-
effectiveness of LNB is $1,465/ton NOX removed at Power 
Boiler No. 1. Domtar eliminated consideration of methane de-
NOX at Power Boilers No. 1 and 2 due to its high cost. Since 
Domtar eliminated the only control option considered for Power Boiler 
No. 1 prematurely (before evaluating visibility impacts), it 
determined, and ADEQ agreed, that there are no NOX controls 
available for Power Boiler No. 1 and ADEQ established a BART 
NOX emission limit of 0.46 lb/MMBtu on a 30-day rolling 
average for Power Boiler No. 1. This would result in no additional 
NOX emission reductions at Power Boiler No. 1 beyond 
baseline conditions.
    Also based on the cost-effectiveness analysis, Domtar determined 
that BART for Power Boiler No. 2 is LNB and ADEQ established a BART 
NOX emission limit of 0.45 lb/MMBtu on a 30-day rolling 
average for Power Boiler No. 2. After making BART determinations for 
the No. 1 and 2 Power Boilers, ADEQ modeled the visibility impacts of 
the controls it selected as BART. We note Domtar and ADEQ's approach 
for making NOX BART determinations for the No. 1 and 2 Power 
Boilers is flawed, as the RHR and the BART Guidelines provide that the 
visibility impacts of all technically feasible control options, which 
corresponds to Step 5 of the BART analysis, must be considered before a 
BART determination is made. ADEQ and Domtar eliminated methane de-
NOX in the BART analysis for Power Boilers No. 1 and 2 due 
to high cost before evaluating the visibility impacts of this control 
option. Thereby, ADEQ modeled only the visibility impacts of LNB for 
Power Boiler No. 2.
    ADEQ stated its post-control visibility modeling demonstrates the 
BART determinations for PM, SO2, and NOX for 
Power Boilers No. 1 and 2 will result in a combined visibility 
improvement of 9.9% at Caney Creek and 12.9% at Upper Buffalo.\60\ We 
note this is very

[[Page 64210]]

minimal visibility improvement and that there is ample room for the 
additional visibility improvement that would result from BART controls 
more stringent than those selected by ADEQ and Domtar.
---------------------------------------------------------------------------

    \60\ ADEQ's post-control modeling, showing the visibility 
improvement resulting from BART controls, demonstrates that the 
visibility impact of Power Boilers No. 1 and 2 combined will be 
2.038 [Delta]dv at Caney Creek and 1.029 [Delta]dv at Upper Buffalo 
after ADEQ's BART controls are put in place.
---------------------------------------------------------------------------

    We are proposing to find that ADEQ did not properly follow the 
requirements of section 51.308(e)(1)(ii)(A) in determining 
NOX BART for Power Boilers No.1 and 2. Specifically, we are 
proposing that ADEQ did not properly take into consideration ``the 
technology available'' and ``the degree of improvement in visibility 
which may reasonably be anticipated to result from the use of such 
technology.'' We disagree with Domtar and ADEQ's assessment that use of 
SNCR at the two power boilers is technically infeasible. In addition, 
ADEQ did not model the visibility impacts of all technically feasible 
control options before making NOX BART determinations. For 
these reasons, we are proposing to disapprove ADEQ's determination that 
BART for NOX for Power Boiler No. 1 is a NOX 
emission limit of 0.46 lb/MMBtu (which would achieve no NOX 
emission reductions beyond the baseline) and that BART for 
NOX for Power Boiler No. 2 is a NOX emission 
limit of 0.45 lb/MMBtu (achieved by use of LNB).
f. ADEQ BART Results and Summary
    We have reviewed ADEQ's BART determinations for the sources listed 
in Table 3, above. For the reasons discussed above, and as discussed in 
more detail in the TSD, we are proposing to find that ADEQ has 
partially satisfied the BART requirement of section 51.308(e). We are 
proposing to find that the BART determinations listed in Table 4 
satisfy the BART requirement of section 51.308(e). We are proposing to 
find that the BART determinations listed in Table 5 do not satisfy the 
BART requirement of section 51.308(e). We are also proposing to find 
that the 6A and 9A Boilers at the Georgia-Pacific Crossett Mill are 
subject to BART and require a full BART analysis to satisfy the BART 
requirement of section 51.308(e).
---------------------------------------------------------------------------

    \61\ Emission limits are based on a 30-day rolling average.

                                                Table 4--BART Determinations Satisfying Section 51.308(e)
--------------------------------------------------------------------------------------------------------------------------------------------------------
           Facility name                   BART emission unit                         Pollutant                          BART emission limit \61\
--------------------------------------------------------------------------------------------------------------------------------------------------------
American Electric Power Flint       Boiler No. 1...................  PM10......................................  existing PM emission limit (0.1 lb/
 Creek Power Plant.                                                                                               MMBtu).
--------------------------------------------------------------------------------------------------------------------------------------------------------

 
 
--------------------------------------------------------------------------------------------------------------------------------------------------------
Entergy Lake Catherine Plant......  Unit 4........................  natural gas firing...  SO2..................  No BART Determination.
                                                                                          --------------------------------------------------------------
                                                                                           PM10.................  existing PM emission limit (45 lb/hr).
--------------------------------------------------------------------------------------------------------------------------------------------------------
Entergy White Bluff Plant.........  Unit 1........................  bituminous coal        PM10.................  existing PM emission limit (0.1 lb/
                                                                     firing.                                       MMBtu).
                                                                   -------------------------------------------------------------------------------------
                                                                    sub-bituminous coal    PM10.................  existing PM emission limit (0.1 lb/
                                                                     firing.                                       MMBtu).
                                   ---------------------------------------------------------------------------------------------------------------------
                                    Unit 2........................  bituminous coal        PM10.................  existing PM emission limit (0.1 lb/
                                                                     firing.                                       MMBtu).
                                                                   -------------------------------------------------------------------------------------
                                                                    sub-bituminous coal    PM10.................  existing PM emission limit (0.1 lb/
                                                                     firing.                                       MMBtu).
--------------------------------------------------------------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------------------------------------------------------------

Domtar Ashdown Mill...............  No. 1 Power Boiler.............  PM10......................................  0.07 lb/MMBtu.
--------------------------------------------------------------------------------------------------------------------------------------------------------

                                              Table 5--BART Determinations Not Satisfying Section 51.308(e)
--------------------------------------------------------------------------------------------------------------------------------------------------------
           Facility name                   BART emission unit                         Pollutant                           BART emission limit 62
--------------------------------------------------------------------------------------------------------------------------------------------------------
Arkansas Electric Cooperative       Unit 1.........................  SO2.......................................  Use of fuel oil with 1% sulfur content.
 Corporation Carl E. Bailey
 Generating Station.
                                                                    ------------------------------------------------------------------------------------
                                                                     NOX.......................................  No BART Determination.
                                                                    ------------------------------------------------------------------------------------
                                                                     PM........................................  No BART Determination.
--------------------------------------------------------------------------------------------------------------------------------------------------------
Arkansas Electric Cooperative       Unit 1.........................  SO2.......................................  Use of fuel oil with 1% sulfur content.
 Corporation John L. McClellan
 Generating Station.
                                                                    ------------------------------------------------------------------------------------
                                                                     NOX.......................................  No BART Determination.
                                                                    ------------------------------------------------------------------------------------
                                                                     PM........................................  No BART Determination.
--------------------------------------------------------------------------------------------------------------------------------------------------------
American Electric Power Flint       Boiler No. 1...................  SO2.......................................  0.15 lb/MMBtu.
 Creek Power Plant.
                                                                    ------------------------------------------------------------------------------------

[[Page 64211]]

 
                                                                     NOX.......................................  0.23 lb/MMBtu.
--------------------------------------------------------------------------------------------------------------------------------------------------------

 
 
--------------------------------------------------------------------------------------------------------------------------------------------------------
Entergy Lake Catherine Plant......  Unit 4........................  natural gas firing...  NOX..................  0.15 lb/MMBtu.
                                                                   -------------------------------------------------------------------------------------
                                                                    fuel oil firing......  SO2..................  0.562 lb/MMBtu.
                                                                                          --------------------------------------------------------------
                                                                                           NOX..................  0.25 lb/MMBtu.
                                                                                          --------------------------------------------------------------
                                                                                           PM...................  0.037 lb/MMBtu.
--------------------------------------------------------------------------------------------------------------------------------------------------------
Entergy White Bluff Plant.........  Unit 1........................  bituminous coal        SO2..................  0.15 lb/MMBtu.
                                                                     firing.
                                                                                          --------------------------------------------------------------
                                                                                           NOX..................  0.28 lb/MMBtu.
                                                                                          --------------------------------------------------------------
                                                                    sub-bituminous coal    SO2..................  0.15 lb/MMBtu.
                                                                     firing.
                                                                                          --------------------------------------------------------------
                                                                                           NOX..................  0.15 lb/MMBtu.
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                    Unit 2........................  bituminous coal        SO2..................  0.15 lb/MMBtu.
                                                                     firing.
                                                                                          --------------------------------------------------------------
                                                                                           NOX..................  0.28 lb/MMBtu.
                                                                   -------------------------------------------------------------------------------------
                                                                    sub-bituminous coal    SO2..................  0.15 lb/MMBtu.
                                                                     firing.
                                                                                          --------------------------------------------------------------
                                                                                           NOX..................  0.15 lb/MMBtu.
                                   ---------------------------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------------------------------------------------------------

                                    Auxiliary Boiler...............  All.......................................  Boiler to be operated no more than 4360
                                                                                                                  hrs annually.
--------------------------------------------------------------------------------------------------------------------------------------------------------
Domtar Ashdown Mill...............  No. 1 Power Boiler.............  SO2.......................................  1.12 lb/MMBtu.
                                                                    ------------------------------------------------------------------------------------
                                                                     NOX.......................................  0.46 lb/MMBtu.
                                   ---------------------------------------------------------------------------------------------------------------------
                                    No. 2 Power Boiler.............  SO2.......................................  1.2 lb/MMBtu.
                                                                    ------------------------------------------------------------------------------------
                                                                     NOX.......................................  0.45 lb/MMBtu.
                                                                    ------------------------------------------------------------------------------------
                                                                     PM10......................................  0.1 lb/MMBtu.
--------------------------------------------------------------------------------------------------------------------------------------------------------

4. Arkansas' Regional Haze Rule
    APC&E Commission Regulation 19, Chapter 15 requires each source 
subject to BART to install and operate BART no later than 6 years after 
the effective date of ADEQ's regulation or 5 years after we approve 
this RH SIP, which ever comes first.\63\
---------------------------------------------------------------------------

    \62\ Emission limits are based on a 30-day rolling average.
    \63\ See Arkansas Pollution Control and Ecology Commission Reg. 
19.1504(B).
---------------------------------------------------------------------------

    ADEQ originally submitted Arkansas' RH Rule, the APC&E Commission 
Regulation 19, Chapter 15, along with the Arkansas RH SIP, which we 
received on September 23, 2008. On August 3, 2010, we received a SIP 
revision submittal from ADEQ revising several chapters of APC&E 
Commission Regulation 19, including chapter 15. The revisions to 
Chapter 15 of APC&E Commission Regulation 19 that we received on August 
3, 2010 are mostly non-substantive amendments that revise the original 
version of the rule we received on September 23, 2008. Therefore, in 
this proposed rulemaking we are proposing to take action on the version 
of Chapter 15 of APC&E Regulation 19 contained in the submittal we 
received on September 23, 2008, as revised by the submittal received on 
August 3, 2010. The only portion of the August 3, 2010 SIP submittal we 
are proposing to take action on in this rulemaking is that portion 
revising chapter 15 of APC&E Regulation 19. In this proposed 
rulemaking, we are not proposing to take action on the portions of the 
August 3, 2010 SIP submittal that revise other chapters of APC&E 
Commission Regulation 19, as those chapters are not related to regional 
haze. We will take action on the revisions to other chapters of APC&E 
Commission Regulation 19 at a later time.
    We are proposing to partially approve and partially disapprove 
chapter 15 of APC&E Commission Regulation 19. We are proposing to 
approve those portions of chapter 15 of APC&E Commission Regulation 19 
that incorporate the BART determinations we are proposing to approve 
and those portions that are consistent with our overall action on the 
Arkansas RH SIP. Specifically, we are proposing to approve the 
following sections of chapter 15 of APC&E Commission Regulation 19: 
Reg. 19.1501, which establishes the purpose

[[Page 64212]]

of the rule; Reg. 19.1502, which incorporates by reference the 
definitions contained in 40 CFR 51.301, as in effect on June 22, 2007; 
Reg. 19.1503, which identifies the State's BART-eligible sources; the 
portion of Reg. 19.1504(A) that identifies AECC Bailey Generating 
Station (Unit 1), AECC McClellan Generating Station (Unit 1), Domtar 
Ashdown Mill (Power Boilers No. 1 and 2), Lake Catherine (Unit 4), 
White Bluff (Units 1, 2, and the Auxiliary Boiler), and AEP Flint Creek 
(Boiler No. 1) as subject to BART sources; Reg. 19.1504(B), which 
requires each source subject to BART to install and operate BART as 
expeditiously as possible, but no later than 6 years after the 
effective date of the State's regulation or 5 years after EPA approval 
of the RH SIP (whichever comes first); \64\ Reg. 19.1504(C), which 
requires each source subject to BART to maintain the control equipment 
required by chapter 15, and establish procedures to ensure such 
equipment is properly operated and maintained; Reg. 19.1505(A)(3), 
which establishes PM BART for AEP Flint Creek Power Plant, Boiler 1; 
Reg. 19.1505(D)(3), which establishes PM BART for Domtar Ashdown Mill, 
Power Boiler No. 1; Reg. 19.1505(F)(3), which establishes PM BART 
(bituminous coal) for Entergy White Bluff, Unit 1; Reg. 19.1505(G)(3), 
which establishes PM BART (sub-bituminous coal) for Entergy White 
Bluff, Unit 1; Reg. 19.1505(I)(3), which establishes PM BART 
(bituminous coal) for Entergy White Bluff, Unit 2; Reg. 19.1505(J)(3), 
which establishes PM BART (sub-bituminous coal) for Entergy White 
Bluff, Unit 2; Reg. 19.1505(M)(2), which establishes PM BART (natural 
gas) for Entergy Lake Catherine Unit 4; Reg.19.1506, which provides the 
compliance provisions for the subject to BART sources; and Reg. 
19.1507, which provides that the Part 70 permit of each facility 
subject to BART shall be subject to re-opening.
---------------------------------------------------------------------------

    \64\ On March 26, 2010, the Arkansas Pollution Control & Ecology 
Commission, Arkansas' rulemaking body, granted all Arkansas subject-
to-BART sources a variance from the compliance deadline imposed by 
the State's RH Rule, such that these sources are now required to 
comply with BART requirements no later than 5 years after EPA 
approval of the RH SIP.
---------------------------------------------------------------------------

    We are proposing to disapprove the portion of Chapter 15 of APC&E 
Commission Regulation 19 that fails to identify the 6A and 9A Boilers 
at the Georgia-Pacific Mill as subject to BART sources, and the 
portions that incorporate the State's BART determinations we are 
proposing to disapprove. Specifically, we are proposing to disapprove 
the following sections of Chapter 15 of the Arkansas Pollution Control 
and Ecology Commission Regulation 19: the portion of Reg. 19.1504(A) 
that fails to identify the 6A and 9A Boilers at the Georgia-Pacific 
Crossett Mill as subject to BART sources; Reg. 19.1505(A)(1), which 
establishes SO2 BART for AEP Flint Creek Power Plant, Boiler 
1; Reg. 19.1505(A)(2), which establishes NOX BART for AEP 
Flint Creek Power Plant, Boiler 1; Reg. 19.1505(B), which establishes 
SO2 BART for AECC Bailey Generating Station, Unit 1; Reg. 
19.1505(C), which establishes SO2 BART for AECC McClellan 
Generating Station, Unit 1; Reg 19.1505(D)(1), which establishes 
SO2 BART for Domtar Ashdown Mill, Power Boiler No. 1; Reg. 
19.1505(D)(2), which establishes NOX BART for Domtar Ashdown 
Mill, Power Boiler No. 1; Reg. 19.1505(E)(1), which establishes 
SO2 BART for Domtar Ashdown Mill, Power Boiler No. 2; Reg. 
19.1505(E)(2), which establishes NOX BART for Domtar Ashdown 
Mill, Power Boiler No. 2; Reg. 19.1505(E)(3), which establishes PM BART 
for Domtar Ashdown Mill, Power Boiler No. 2; Reg. 19.1505(F)(1), which 
establishes SO2 BART (bituminous coal) for Entergy White 
Bluff, Unit 1; Reg. 19.1505(F)(2), which establishes NOX 
BART (bituminous coal) for Entergy White Bluff, Unit 1; Reg. 
19.1505(G)(1), which establishes SO2 BART (sub-bituminous 
coal) for Entergy White Bluff, Unit 1; Reg. 19.1505(G)(2), which 
establishes NOX BART (sub-bituminous coal) for Entergy White 
Bluff, Unit 1; Reg. 19.1505(H), which provides that when burning a mix 
of bituminous and sub-bituminous coal at White Bluff Unit 1, the 
NOX BART limits shall be prorated using the percentage of 
each coal being used; Reg. 19.1505(I)(1), which establishes 
SO2 BART (bituminous coal) for Entergy White Bluff, Unit 2; 
Reg. 19.1505(I)(2), which establishes NOX BART (bituminous 
coal) for Entergy White Bluff, Unit 2; Reg. 19.1505(J)(1), which 
establishes SO2 BART (sub-bituminous coal) for Entergy White 
Bluff, Unit 2; Reg. 19.1505(J)(2), which establishes NOX 
BART (sub-bituminous coal) for Entergy White Bluff, Unit 2; Reg. 
19.1505(K), which provides that when burning a mix of bituminous and 
sub-bituminous coal at White Bluff Unit 2, the NOX BART 
limits shall be prorated using the percentage of each coal being used; 
Reg. 19.1505(L), which establishes BART for Entergy White Bluff, 
Auxiliary Boiler; Reg. 19.1505(M)(1), which establishes NOX 
BART (natural gas) for Entergy Lake Catherine Unit 4; Reg. 
19.1505(N)(1), which establishes SO2 BART (fuel oil) for 
Entergy Lake Catherine Unit 4; Reg. 19.1505(N)(2), which establishes 
NOX BART (fuel oil) for Entergy Lake Catherine Unit 4; and 
Reg. 19.1505(N)(3), which establishes PM BART (fuel oil) for Entergy 
Lake Catherine Unit 4.

E. Long-Term Strategy

    As described in section IV.E of this action, the LTS is a 
compilation of state-specific control measures relied on by the state 
for achieving its RPGs. Arkansas' LTS for the first implementation 
period addresses the emissions reductions from federal, state, and 
local controls that take effect in the state from the end of the 
baseline period starting in 2004 until 2018. The Arkansas LTS was 
developed by ADEQ, in coordination with the CENRAP RPO, through an 
evaluation of the following components: (1) Construction of a CENRAP 
2002 baseline emission inventory; (2) construction of a CENRAP 2018 
emission inventory, including reductions from CENRAP member state 
controls required or expected under federal and state regulations, 
(including BART); (3) modeling to determine visibility improvement and 
apportion individual state contributions; (4) state consultation; and 
(5) application of the LTS factors.
1. Emissions Inventories
    Section 51.308(d)(3)(iii) requires that Arkansas document the 
technical basis, including modeling, monitoring and emissions 
information, on which it relied upon to determine its apportionment of 
emission reduction obligations necessary for achieving reasonable 
progress in each mandatory Class I Federal area it affects. Arkansas 
must identify the baseline emissions inventory on which its strategies 
are based. Section 51.308(d)(3)(iv) requires that Arkansas identify all 
anthropogenic sources of visibility impairment considered by the state 
in developing its long-term strategy. This includes major and minor 
stationary sources, mobile sources, and area sources. Arkansas met 
these requirements by relying on technical analyses developed by its 
RPO, CENRAP, and approved by all state participants, as described 
below.
    The emissions inventory used in the RH technical analyses was 
developed by CENRAP with assistance from Arkansas. ADEQ provided a 
statewide emissions inventory for 2002- representing the mid-point of 
the 2000-2004 baseline period, and a projected emissions inventory for 
2018, the end of the first 10-year planning period. The 2018 inventory 
is based on visibility modeling conducted by CENRAP. The 2018 emissions 
inventory was

[[Page 64213]]

developed by projecting 2002 emissions and applying reductions expected 
from federal and state regulations affecting the emissions of the 
visibility-impairing pollutants NOX, PM, SO2, and 
VOCs.
a. Arkansas' 2002 Emission Inventory
    ADEQ and CENRAP developed an emission inventory for five inventory 
source classifications: Point, area, non-road and on-road mobile 
sources, and biogenic sources for the baseline year of 2002. Arkansas' 
2002 emissions inventory provides estimates of annual emissions for 
haze producing pollutants by source category as summarized in Table 6, 
based on information in section 7.0 of Arkansas' RH SIP.

                                                       Table 6--Arkansas' 2002 Emissions Inventory
                                                                       [Tons/year]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                SO2             NH3             NOX            VOCs            PM10            PM2.5
--------------------------------------------------------------------------------------------------------------------------------------------------------
Point...................................................          92,205               1          72,419          44,329          12,406           7,837
Area....................................................          29,889         152,436          27,450          93,548         148,433          68,000
Non-road mobile.........................................           5,490              49          62,472          54,785           5,673           5,220
On-road mobile..........................................           3,902           2,480         141,894          48,599           3,784           3,021
Biogenic................................................               0               0          18,960       1,385,666               0               0
                                                         -----------------------------------------------------------------------------------------------
    Total...............................................         131,485         154,967         323,195       1,626,927         170,296          84,078
--------------------------------------------------------------------------------------------------------------------------------------------------------

    See the TSD for details on how the 2002 emissions inventory was 
constructed. We are proposing that Arkansas' 2002 emission inventory is 
acceptable.
b. Arkansas' 2018 Emission Inventory
    In constructing Arkansas' 2018 emission inventory, ADEQ used a 
combination of our Economic Growth Analysis System (EGAS 6), our mobile 
emissions factor model (MOBILE 6), our off-road emissions factor model 
(NONROAD), and the Integrated Planning Model (IPM) for electric 
generating units. CENRAP developed emissions for five inventory source 
classifications: point, area, non-road and on-road mobile sources, and 
biogenic sources. CENRAP used the 2002 emission inventory, described 
above, to estimate emissions in 2018. All control strategies expected 
to take effect prior to 2018 are included in the projected emission 
inventory. Arkansas' 2018 emissions inventory provides estimates of 
annual emissions for haze producing pollutants by source category as 
summarized in Table 7, based on information in section 7.0 of the 
Arkansas RH SIP.

                                                       Table 7--Arkansas' 2018 Emissions Inventory
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                SO2             NH3             NOX            VOCs            PM10            PM2.5
--------------------------------------------------------------------------------------------------------------------------------------------------------
Point...................................................         106,461           2,575          71,107          55,603          19,799          13,775
Area....................................................          31,169         201,722          31,531         107,387         148,592          69,585
Non-road mobile.........................................             211              49          34,305          31,475           3,678           3,387
On-road mobile..........................................             442           3,412          33,640          19,924             949             949
Biogenic................................................               0               0          18,960       1,385,666               0               0
                                                         -----------------------------------------------------------------------------------------------
    Total...............................................         138,283         207,758         189,542       1,600,055         173,019          87,695
--------------------------------------------------------------------------------------------------------------------------------------------------------

    See the TSD for details on how the 2018 emissions inventory was 
constructed. CENRAP and ADEQ used this and other state's 2018 emission 
inventories to construct visibility projection modeling for 2018. We 
are proposing that Arkansas' 2018 emission inventory is acceptable.
2. Visibility Projection Modeling
    CENRAP performed modeling for the RH LTS for its member states, 
including Arkansas. The modeling analysis is a complex technical 
evaluation that began with selection of the modeling system. CENRAP 
used (1) The Mesoscale Meteorological Model (MM5) meteorological model, 
(2) the Sparse Matrix Operator Kernel Emissions (SMOKE) modeling system 
to generate hourly gridded speciated emission inputs, (3) the Community 
Multiscale Air Quality (CMAQ) photochemical grid model and (4) the 
Comprehensive Air Quality model with extensions (CAMx), as a secondary 
corroborative model. CAMx was also utilized with its Particulate Source 
Apportionment Technology (PSAT) tool to provide source apportionment 
for both the baseline and future case visibility modeling.
    The photochemical modeling of RH for the CENRAP states for 2002 and 
2018 was conducted on the 36-km resolution national regional planning 
organization domain that covered the continental United States, 
portions of Canada and Mexico, and portions of the Atlantic and Pacific 
Oceans along the east and west coasts. The CENRAP states' modeling was 
developed consistent with our guidance.\65\
---------------------------------------------------------------------------

    \65\ Guidance on the Use of Models and Other Analyses for 
Demonstrating Attainment of Air Quality Goals for Ozone, 
PM2.5, and Regional Haze, (EPA-454/B-07-002), April 2007, 
located at http://www.epa.gov/scram001/guidance/guide/final-03-pm-rh-guidance.pdf Emissions Inventory Guidance for Implementation of 
Ozone and Particulate Matter National Ambient Air Quality Standards 
(NAAQS) and Regional Haze Regulations, August 2005, updated November 
2005 (``our Modeling Guidance''), located at http://www.epa.gov/ttnchie1/eidocs/eiguid/index.html, EPA-454/R-05-001
---------------------------------------------------------------------------

    CENRAP examined the model performance of the regional modeling for 
the areas of interest before determining whether the CMAQ model results 
were suitable for use in the RH assessment of the LTS and for use in 
the modeling assessment. The 2002 modeling efforts were used to 
evaluate air quality/visibility modeling for a historical episode--in 
this case, for calendar year 2002--to demonstrate the suitability of 
the modeling systems for subsequent planning, sensitivity, and 
emissions control strategy modeling. Model performance evaluation is 
performed by comparing output from

[[Page 64214]]

model simulations with ambient air quality data for the same time 
period to determine whether the model's performance is sufficiently 
accurate to justify using the model for simulating future conditions. 
Once CENRAP determined the model performance to be acceptable, it used 
the model to determine the 2018 RPGs using the current and future year 
air quality modeling predictions, and compared the RPGs to the URP. The 
results of CENRAP's visibility projection modeling are discussed in the 
section that follows.
3. Sources of Visibility Impairment
    Visibility impairment in Class I areas is the result of local air 
pollution as well as transport of regional pollution across long 
distances. CENRAP used CAMx with its Particulate Source Apportionment 
Technology (PSAT) tool to provide source apportionment by geographic 
region and major source category. The pollutants causing the highest 
levels of light extinction are associated with the sources causing the 
most visibility impairment.
a. Sources of Visibility Impairment in Caney Creek
    Tables 8 and 9 show the modeled contributions to total extinction 
at Caney Creek for each source category and species for 2002 and 2018, 
respectively.\66\ Visibility impairment at Caney Creek in 2002 on the 
worst 20% days is largely due to SO4 from point sources that 
contributes over half (75.1 Mm-\1\) of the total extinction 
of 133.93 Mm-\1\. The largest contributions of 
SO4 come from Texas (11.55 Mm-\1\ from all source 
categories) and the eastern United States (17.98 Mm-\1\). 
Overall, the largest source region contributions to visibility 
impairment in 2002 are from the eastern United States (19.16 
Mm-\1\), Texas (14.89 Mm-\1\), and Arkansas 
(13.57 Mm-\1\).
---------------------------------------------------------------------------

    \66\ The species contributing to visibility extinction at Caney 
Creek and Upper Buffalo, shown on Tables 8-11, are the following: 
sulfate (SO4), nitrate (NO3), primary organic 
aerosols (POA), elemental carbon (EC), soil dust, and coarse mass 
(CM). These species' precursors are SO2, NOX, 
and in some cases, NH3 and VOCs.
---------------------------------------------------------------------------

    In 2018, Arkansas sources will contribute the most to visibility 
impairment at Caney Creek, as large reductions in impairment from point 
sources in East Texas and the eastern U.S. will occur while 
SO4 emissions, particularly from point sources, are expected 
to increase in Arkansas. The 2018 projection shows the total extinction 
at Caney Creek for the worst 20% days is estimated to be 85.84 
Mm-\1\, a reduction of approximately 36% from 2002 levels. 
Anticipated reductions of SO4 emissions from point sources 
in Texas, the eastern United States, Indiana, and Ohio will account for 
a decrease of 24.41 Mm-\1\ in total light extinction, which 
is approximately half of the total expected reduction between 2002 and 
2018. Even with such large expected reductions in SO4 
emissions from point sources in 2018, extinction due to point sources 
will still be the highest contributor to visibility impairment on the 
worst 20% days, accounting for over half of the total extinction. 
Visibility impairment from all Arkansas sources will decrease by 2.32 
Mm-\1\, almost entirely due to expected reductions from 
mobile sources. Total reductions in NO3 emissions from 
mobile sources will contribute a decrease in total extinction of 
approximately 9 Mm-\1\. There is an under-prediction bias in 
the model that must be considered when examining source apportionment 
results for SO4. Use of a 12 km resolution modeling grid in 
CAMX reduced the summertime SO4 bias but required large 
computational expense. The use of higher resolution modeling should be 
reconsidered in future modeling efforts.

                              Table 8--Projected 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
                                                         -----------------------------------------------------------------------------------------------
    Sum.................................................          133.93           81.04            2.45            7.26            7.31           17.81
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Totals include contributions from boundary conditions and secondary organic matter.

                              Table 9--Projected 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 64215]]

b. Sources of Visibility Impairment in Upper Buffalo
    Tables 10 and 11 show the contributions to total extinction at 
Upper Buffalo for each source category and species for 2002 and 2018, 
respectively. Visibility impairment at Upper Buffalo in 2002 on the 
worst 20% days is largely due to SO4 from point sources that 
contributes over half (72.17 Mm-\1\) of the total extinction 
of 131.79 Mm-\1\. The largest contributions of visibility 
impairment due to SO4 come from the eastern United States 
(18.56 Mm-\1\), Indiana (9.79 Mm-\1\), Illinois 
(8.06 Mm-\1\), and Kentucky (6.93 Mm-\1\). 
Overall, the largest source region contributions to visibility 
impairment in 2002 are from the eastern United States (20.00 
Mm-\1\), Arkansas (13.47 Mm-\1\), Indiana (10.20 
Mm-\1\), Illinois (9.64 Mm-\1\), and Missouri 
(9.60 Mm-\1\).
    In 2018, Arkansas sources will contribute the most to visibility 
impairment at Upper Buffalo, as large reductions in impairment from 
point sources in Indiana, Illinois, Ohio and the eastern U.S. will 
occur while SO4 emissions, particularly from point sources, 
are expected to increase in Arkansas. The 2018 projection shows the 
total extinction at Upper Buffalo for the worst 20% days is estimated 
to be 86.16 Mm-\1\, a reduction of approximately 35% from 
2002 levels. Anticipated reductions of SO4 emissions from 
point sources in the eastern United States, Indiana, Illinois, Kentucky 
and Ohio will account for a decrease of 28.43 Mm-\1\ in 
total light extinction, more than 60% of the total expected reduction 
in impairment between 2002 and 2018. Even with such large expected 
reductions in SO4 emissions from point sources in 2018, 
extinction due to point sources will still be the highest contributor 
to visibility impairment on the worst 20% days, accounting for 
approximately half of the total extinction. Visibility impairment from 
all Arkansas sources will decrease by 1.45 Mm-\1\, due to 
expected reductions from mobile sources. Total reductions in 
NO3 emissions from mobile sources will contribute a decrease 
in total extinction of approximately 8.5 Mm-\1\. There is an 
under-prediction bias in the model that must be considered when 
examining source apportionment results forSO4. Use of a 12 
km resolution modeling grid in CAMX reduced the summertime sulfate bias 
but required large computational expense. The use of higher resolution 
modeling should be reconsidered in future modeling efforts.

                            Table 10--Projected Light Extinction for 20% Worst Days 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 and secondary organic matter.

                            Table 11--Projected 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.

c. Arkansas' Contribution to Visibility Impairment in Class I Areas 
Outside the State
    CAMx PSAT results were also utilized to evaluate the impact of 
Arkansas emission sources in 2002 and 2018 on visibility impairment at 
Class I areas outside of the state. Arkansas sources are modeled to 
have contributions to the Class I areas in Missouri (Hercules-Glades 
and Mingo). Outside of Arkansas and Missouri, the largest contribution 
from Arkansas sources is at the Wichita Mountains Class I area in 
Oklahoma, amounting to 2.0% of the visibility impairment at Wichita 
Mountains in 2002 and 2.3% in 2018. Arkansas is also projected to 
contribute a small amount of visibility degradation at Class I areas in 
other states listed in Table 12. We agree that additional emission 
reductions in Arkansas, beyond those controlled through BART 
requirements, are not necessary to protect visibility at Class I areas 
outside of the state at this time. Table 12 summarizes the projected 
contribution from Arkansas emissions on visibility degradation at 9 
Class I areas for the 20 percent worst days in 2002 and 2018, as 
modeled by CENRAP.\67\
---------------------------------------------------------------------------

    \67\ See Appendix E of the TSD for CENRAP Emissions and Air 
Quality Modeling To Support Regional Haze State Implementation, 
found in Appendix 8.1 of the Arkansas RH SIP.

[[Page 64216]]

  Table 12--Percent Contribution From Arkansas Emissions to Total Visibility Impairment at Class I Areas on 20%
                                                 Worst Days \68\
----------------------------------------------------------------------------------------------------------------
                Class I area                               State               2002 (percent)    2018 (percent)
----------------------------------------------------------------------------------------------------------------
Upper Buffalo...............................  Arkansas......................              10.2              14.0
Caney Creek.................................  Arkansas......................              10.1              13.1
Hercules Glades.............................  Missouri......................               5.9               7.6
Mingo.......................................  Missouri......................               3.3               4.4
Wichita Mountains...........................  Oklahoma......................               2.0               2.3
Mammoth Cave................................  Kentucky......................               1.0               1.8
Bondville...................................  Illinois......................               1.2               1.5
Breton Island...............................  Louisiana.....................               1.1               1.3
Cadiz.......................................  Kentucky......................               0.9               1.2
----------------------------------------------------------------------------------------------------------------

4. Consultation and Emissions Reductions for Other States' Class I 
Areas
    As in the development of Arkansas' RPGs for Caney Creek and Upper 
Buffalo, ADEQ used CENRAP as its main vehicle for facilitating 
collaboration with FLMs and other states in satisfying its LTS 
consultation requirement. This helped ADEQ and other state 
environmental agencies analyze emission apportionments at Class I areas 
and develop coordinated RH SIP strategies.
---------------------------------------------------------------------------

    \68\ Contributions less than 1% were excluded from Table 12.
---------------------------------------------------------------------------

    Section 51.308(d)(3)(i) requires that Arkansas consult with other 
states if its emissions are reasonably anticipated to contribute to 
visibility impairment at that state's Class I area(s), and that 
Arkansas consult with other states if those states' emissions are 
reasonably anticipated to contribute to visibility impairment at Caney 
Creek and Upper Buffalo. ADEQ's consultations with other states are 
described in section V.C.3 above. The CENRAP visibility modeling 
demonstrates Arkansas sources are responsible for a visibility 
extinction of approximately 7.1 inverse megameters \69\ 
(Mm-1) at Hercules Glades and for a visibility extinction of 
approximately 4.95 Mm-1 at Mingo on the worst 20% days for 
2002.\70\ ADEQ consulted with Missouri, as well as with several other 
states whose emissions have a potential visibility impact at Caney 
Creek and Upper Buffalo. As already discussed elsewhere in this 
proposed notice, ADEQ neither requested additional emission reductions 
from other states, nor made a commitment to other states for additional 
emission reductions beyond those already factored in to the CENRAP's 
photochemical modeling for the 2018 visibility projections. All states 
participating in ADEQ's consultation process agreed with this decision.
---------------------------------------------------------------------------

    \69\ An inverse megameter is the direct measurement unit for 
visibility impairment data. It is the amount of light scattered and 
absorbed as it travels over a distance of one million meters. 
Deciviews (dv) can be calculated from extinction data as follows: dv 
= 10 x ln (bext(Mm-1)/10).
    \70\ See Appendix E of the TSD for CENRAP Emissions and Air 
Quality Modeling To Support Regional Haze State Implementation, 
found in Appendix 8.1 of the Arkansas RH SIP.
---------------------------------------------------------------------------

    We are proposing to find that ADEQ's consultations satisfy the 
requirements under section 51.308(d)(3)(i) and (ii).
5. Mandatory Long Term Strategy Factors
    Section 51.308(d)(3)(v) requires that Arkansas consider certain 
factors in developing its long-term strategy (the LTS factors). These 
include: (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. For the reasons outlined below, we are 
proposing to find that Arkansas has not satisfied all the requirements 
of Section 51.308(d)(3)(v).
a. Reductions Due to Ongoing Air Pollution Programs
    In addition to its BART determinations, Arkansas' LTS incorporates 
emission reductions due to a number of ongoing air pollution control 
programs. This includes EPA's Clean Air Interstate Rule (CAIR), which 
was expected to cap Arkansas' ozone season trading budget for annual 
NOx allocations at 9,596 tons by 2015. Consistent with EPA guidance and 
regulations (see 70 FR 39104, 39106 (July 6, 2005)), many states relied 
on EPA's Clean Air Interstate Rule (CAIR) to satisfy key elements of 
Regional Haze SIPs. The D.C. Circuit, however, found CAIR to be 
inconsistent with the requirements of the Act and remanded the rule to 
the Agency. North Carolina v. EPA, 531 F.3d 896, 929-30 (D.C. Cir. 
2008); modified on rehearing, North Carolina v. EPA, 550 F.3d 1176, 
1178 (D.C. Cir. 2008). In response to the remand of the CAIR rule, on 
July 6, 2011, EPA finalized the Transport Rule, also known as the 
Cross-State Air Pollution Rule (CSAPR), a rule intended to reduce the 
interstate transport of fine particulate matter and ozone (see 76 FR 
48208). Since Arkansas was subject to CAIR only for ozone season NOx, 
its Regional Haze SIP did not rely on CAIR to meet the requirements for 
BART or for attaining the in-state emissions reductions necessary to 
ensure reasonable progress. Instead, Arkansas evaluated controls for 
its potential BART sources. Arkansas made BART determinations for its 
subject to BART sources, including Electric Generating Units (EGUs) 
that might have been controlled under CAIR. Controls on these sources 
are an element of Arkansas' LTS for attaining the RPGs at Caney Creek 
and Upper Buffalo. In terms of the LTS, EPA anticipates that the 
Transport Rule will result in similar or better improvements in 
visibility than those predicted from CAIR at Class I areas in Arkansas. 
As a result, we do not expect the remand of CAIR to have a significant 
negative effect on the ability of Arkansas' LTS to ensure that Caney 
Creek and Upper Buffalo meet the RPGs in the State's RH SIP. We note 
that to assess whether a state's current strategies will be sufficient 
to meet its RPGs, the RHR requires a midcourse review by each state 
and, if necessary, a correction of the state's regional haze plan. See 
40 CFR 52.308(g). If for a particular Class I area, the emissions 
reductions resulting from the Transport

[[Page 64217]]

Rule do not provide similar or greater benefits than CAIR and if 
meeting the RPGs at one of its Class I areas is in jeopardy, the State 
will be required to address this circumstance in its five year review.
    ADEQ also considered the Tier 2 Vehicle Emission Standards in 
developing its LTS. Federal Tier 2 Vehicle Emission Standards for 
passenger cars and light trucks were fully implemented in 2007 and 
similar rules for heavy trucks were scheduled to be implemented by 
2009. These federal standards will result in reductions of emissions of 
PM, ozone precursors, and non-methane organic compounds. In developing 
its LTS, ADEQ also considered the Highway Diesel and Nonroad Diesel 
Rules, which mandated the use of lower sulfur fuels in diesel engines 
beginning in 2006 for highway diesel fuel, and 2007 for nonroad diesel 
fuel. These federal rules have resulted in more effective control of PM 
emissions from diesel engines by allowing the installation of control 
devices that were technically infeasible for fuels with higher sulfur 
content.
    We approved Arkansas' Visibility Protection SIP on February 10, 
1986 (51 FR 4910). We approved Arkansas' Part II Visibility Protection 
SIP, which addresses reasonably attributable visibility impairment 
(RAVI) at Caney Creek and Upper Buffalo, on July 21, 1988 (53 FR 
27514). As we note in section IV.H of this proposed notice, the FLMs 
did not identify any integral vistas in Arkansas. In addition, Caney 
Creek and Upper Buffalo are not experiencing RAVI, nor are any Arkansas 
sources affected by the RAVI provisions. For this reason, the Arkansas 
RH SIP does not incorporate any measures to specifically address RAVI.
b. Measures To Mitigate the Impacts of Construction Activities
    Section 51.308(d)(3)(v)(B) requires that Arkansas consider measures 
to mitigate the impacts of construction activities in developing its 
LTS. Construction-related activities are believed to be a small 
contributor to fine and coarse particulates. ADEQ notes that since the 
Arkansas Water and Air Pollution Control Act does not apply to land 
clearing, land grading, or road construction operations, ADEQ has 
limited opportunities to mitigate air emissions resulting from 
construction activities. However, ADEQ notes the federal General 
Conformity program requires assessment of the potential impacts of any 
construction-related emissions of criteria pollutants from federal 
projects in areas that have been designated as not attaining the 
National Ambient Air Quality Standards (NAAQS) for that pollutant. ADEQ 
also participates in the Blue Skyways Collaborative, a regional group 
that works collaboratively on the introduction of innovative, regional-
scale, transportation-related programs and projects. The State has 
directed grant funds to fleet managers and equipment suppliers as a 
means of subsidizing diesel retrofits and the biodiesel market.
c. Emissions Limitations and Schedules of Compliance
    Section 51.308(d)(3)(v)(C) requires that in developing its LTS, 
Arkansas consider emissions limitations and schedules of compliance to 
achieve the RPGs. The SIP contains emission limits and schedules of 
compliance for those sources subject to BART: the AECC Bailey Unit 1; 
the AECC McClellan Unit 1; the AEP Flint Creek Boiler No. 1; the 
Entergy Lake Catherine Unit 4; the Entergy White Bluff Units 1, 2, and 
the Auxiliary Boiler; and the Domtar Power Boilers No. 1 and 2. The 
schedules for implementation of BART for these sources are identified 
in Section 9.3 of the RH SIP and in the State's RH Rule included in 
Appendix 9.3C of the SIP. The BART emission limits established by ADEQ 
are an element of the LTS, and since we are proposing to disapprove a 
portion of ADEQ's BART determinations, we cannot propose to approve 
this element of the LTS.
d. Source Retirement and Replacement Schedules
    Section 51.308(d)(3)(v)(D) requires that Arkansas consider source 
retirement and replacement schedules in developing its LTS. ADEQ stated 
retirement and replacement will be managed in conformance with existing 
SIP requirements pertaining to the Prevention of Significant 
Deterioration (PSD) and the New Source Review (NSR) programs. ADEQ 
notes source retirement and replacement will be tracked through on-
going point source inventories.
e. Agricultural and Forestry Smoke Management Techniques
    Section 51.308(d)(3)(v)(E) requires that Arkansas consider smoke 
management techniques for agricultural and forestry management purposes 
in developing its LTS. ADEQ considered smoke management techniques for 
the purposes of agricultural and forestry management in its LTS. 
Regulation 18 of the Arkansas Pollution Control and Ecology Commission 
contains a general prohibition on ``open burning of refuse, garbage, 
trade waste, or other waste material,'' but exempts controlled fires 
used for forest and wildlife management and certain agricultural 
activities (ADEQ Reg. 18.602-18.603). In 2007, the Arkansas Forestry 
Commission approved revisions to the Arkansas Smoke Management Program 
(SMP). The Arkansas SMP is designed to assure that prescribed fires are 
planned and executed in a manner designed to minimize impacts 
associated with the smoke produced by prescribed fires. The Arkansas 
SMP recommends a written fire plan that includes measures that can be 
taken to reduce residual smoke from burning activities. The Arkansas 
SMP also includes a process to evaluate potential smoke impacts at 
sensitive receptors and guidelines for scheduling fires such that 
exposure of sensitive populations is minimized and visibility impacts 
in Class I areas are avoided.
f. Enforceability of Emissions Limitations and Control Measures
    Section 51.308(d)(3)(v)(F) requires that Arkansas ensure the 
enforceability of emission limitations and control measures used to 
meet reasonable progress goals. ADEQ has ensured that all emission 
limitations and control measures used to meet RPGs are enforceable by 
incorporating these into State regulations.\71\ The State's RH Rule, 
Chapter 15 of the APC&E Commission Regulation 19, contains the BART 
requirements for all subject to BART sources in Arkansas. ADEQ has also 
committed to issuing enforceable Part 70 air quality permits requiring 
BART-eligible sources subject to BART to install BART and achieve the 
associated BART emission limits. Subject sources must achieve the BART 
emission limits referenced above within five years of our approval of 
the SIP, as required by section 51.308(e)(1)(iv). ADEQ determined that 
emission limitations or control measures other than BART are not 
currently required in order to meet the established RPGs. As discussed 
previously, we disagree with this position and are proposing to 
disapprove the RPGs.
---------------------------------------------------------------------------

    \71\ See ``Arkansas Pollution Control and Ecology Commission 
Regulation No. 19--Regulations of the Arkansas Plan of 
Implementation for Air Pollution Control,'' found in Appendix 9.3C 
of the Arkansas RH SIP.
---------------------------------------------------------------------------

g. Anticipated Net Effect on Visibility Due to Projected Changes
    Section 51.308(d)(3)(v)(G) requires that in developing its LTS, 
Arkansas consider the anticipated net effect on visibility due to 
projected changes in point, area, and mobile source

[[Page 64218]]

emissions over the period addressed by the long-term strategy. In 
developing its RH SIP, ADEQ relied on the CENRAP's 2018 modeling 
projections, which show that net visibility is expected to improve by 
3.88 dv at Caney Creek and 3.75 dv at Upper Buffalo. CENRAP's 2018 
modeling projections account for changes in point, area, and on-road 
and non-road mobile emissions. The results of CENRAP's 2018 modeling 
projections are discussed in sections IV.E.2 and IV.E.3 of this 
proposed rulemaking.
6. Our Conclusion on Arkansas' Long Term Strategy
    We are proposing to partially approve and partially disapprove 
Arkansas' LTS. Because we are proposing to disapprove some of ADEQ's 
BART determinations, we are also proposing to disapprove the 
corresponding emission limits and schedules of compliance that Arkansas 
relied on as part of its LTS. With the exception of this element, the 
LTS satisfies the requirements of 40 CFR 51.308(d)(3), and we are 
proposing to approve these remaining elements.
F. Coordination of RAVI and Regional Haze Requirements
    Our visibility regulations direct states to coordinate their RAVI 
LTS and monitoring provisions with those for RH, as explained in 
section IV, above. Under our RAVI regulations, the RAVI portion of a 
state SIP must address any integral vistas identified by the FLMs 
pursuant to 40 CFR 51.304. See 40 CFR 51.302. An integral vista is 
defined in 40 CFR 51.301 as a ``view perceived from within the 
mandatory Class I Federal area of a specific landmark or panorama 
located outside the boundary of the mandatory Class I Federal area.'' 
Visibility in any mandatory Class I Federal area includes any integral 
vista associated with that area. The FLMs did not identify any integral 
vistas in Arkansas. In addition, Caney Creek and Upper Buffalo are not 
experiencing RAVI, nor are any Arkansas sources affected by the RAVI 
provisions. Thus, the Arkansas RH SIP submittal does not explicitly 
address the two requirements regarding coordination of RH with the RAVI 
LTS and monitoring provisions. However, Arkansas previously made a 
commitment to address RAVI should the FLM certify visibility impairment 
from an individual source.\72\ We are proposing to find that this RH 
submittal appropriately supplements and augments Arkansas' RAVI 
visibility provisions to address RH by updating the monitoring and LTS 
provisions. We discuss the relevant monitoring provisions in the 
section that follows.
---------------------------------------------------------------------------

    \72\ Arkansas' part II Visibility Protection SIP contained RAVI 
provisions and was approved by EPA on July 21, 1988 (53 FR 27514).
---------------------------------------------------------------------------

G. Monitoring Strategy and Other SIP Requirements

    Section 51.308(d)(4) requires the SIP contain a monitoring strategy 
for measuring, characterizing, and reporting of RH visibility 
impairment that is representative of all mandatory Class I Federal 
areas within the state. This monitoring strategy must be coordinated 
with the monitoring strategy required in Section 51.305 for reasonably 
attributable visibility impairment. As Section 51.308(d)(4) notes, 
compliance with this requirement may be met through participation in 
the IMPROVE network. Since the monitors at Caney Creek and Upper 
Buffalo are IMPROVE monitors, we are proposing that ADEQ has satisfied 
this requirement. See the TSD for details concerning the IMPROVE 
network.
    Section 51.308(d)(4)(i) requires the establishment of any 
additional monitoring sites or equipment needed to assess whether 
reasonable progress goals to address RH for all mandatory Class I 
Federal areas within the state are being achieved. The IMPROVE monitor 
at Upper Buffalo was installed in 1991. Shortly after the creation of 
CENRAP, its monitoring workgroup noted there was a visibility void in 
Southern Arkansas. In 2001, the Caney Creek Wilderness area IMPROVE 
monitor was added to help fill that void. ADEQ also commits in the 
Arkansas RH SIP to evaluate the monitoring network periodically and 
consider evaluation technology changes and the need for new monitors. 
With the addition of the monitor at Caney Creek, we are proposing to 
find that ADEQ has satisfied this requirement.
    Section 51.308(d)(4)(ii) requires that ADEQ establish procedures by 
which monitoring data and other information are used in determining the 
contribution of emissions from within Arkansas to RH visibility 
impairment at mandatory Class I Federal areas both within and outside 
the state. The monitor at Caney Creek is operated by Caney Creek 
Wilderness Area personnel, while the monitor at Upper Buffalo is 
operated by Upper Buffalo Wilderness Area personnel. The IMPROVE 
monitoring program is national in scope, and other states have similar 
monitoring and data reporting procedures, ensuring a consistent and 
robust monitoring data collection system. As section 51.308(d)(4) 
indicates, participation in the IMPROVE program constitutes compliance 
with this requirement. We are therefore proposing that ADEQ has 
satisfied this requirement.
    Section 51.308(d)(4)(iv) requires that the SIP must provide for the 
reporting of all visibility monitoring data to the Administrator at 
least annually for each mandatory Class I Federal area in the state. To 
the extent possible, Arkansas should report visibility monitoring data 
electronically. Section 51.308(d)(4)(vi) also requires that ADEQ 
provide for other elements, including reporting, recordkeeping, and 
other measures, necessary to assess and report on visibility. We are 
proposing that Arkansas' participation in the IMPROVE network ensures 
the monitoring data is reported at least annually, is easily 
accessible, and therefore complies with this requirement.
    Section 51.308(d)(4)(v) requires that ADEQ maintain a statewide 
inventory of emissions of pollutants that are reasonably anticipated to 
cause or contribute to visibility impairment in any mandatory Class I 
Federal area. The inventory must include emissions for a baseline year, 
emissions for the most recent year for which data are available, and 
estimates of future projected emissions. The State must also include a 
commitment to update the inventory periodically. Please refer to 
section V.G., above, where we discuss ADEQ's emission inventory. ADEQ 
has stated that it intends to update the Arkansas statewide emissions 
inventories periodically. We are proposing that this satisfies the 
requirement in section 51.308(d)(4)(v).

H. Federal Land Manager Coordination

    Both Caney Creek and Upper Buffalo are federally protected 
wilderness areas for which the United States Department of Agriculture 
(USDA) Forest Service is the FLM. Although the FLMs are very active in 
participating in the RPOs, the RHR grants the FLMs a special role in 
the review of the RH SIPs, summarized in section III.H., above. We view 
both the FLMs and the state environmental agencies as our partners in 
the RH process.
    Section 51.308(i)(1) requires that by November 29, 1999, Arkansas 
must have identified in writing to the FLMs the title of the official 
to which the FLM of Caney Creek and Upper Buffalo can submit any 
recommendations on the implementation of section 51.308. We acknowledge 
this section has been satisfied by all states via communication prior 
to this SIP.
    Under Section 51.308(i)(2), Arkansas was obligated to provide the 
Forest Service with an opportunity for consultation, in person and at 
least 60 days prior to holding a public hearing on it RH SIP. In 
practice, state environmental agencies have usually

[[Page 64219]]

provided all FLMs--the Forest Service, the Park Service, and the Fish 
and Wildlife Service, copies of their RH SIP, as the FLMs collectively 
have reviewed these RH SIPs. ADEQ followed this practice and sent its 
draft of this implementation plan revision to the federal land manager 
staff on February 22, 2008 and notified the federal land manager staff 
of the public hearing held on July 7, 2008.
    Section 51.308(i)(3) requires that ADEQ provide in its RH SIP a 
description of how it addressed any comments provided by the FLMs. ADEQ 
has provided that information in Appendix 2.1 of its RH SIP.
    Lastly, Section 51.308(i)(4) specifies the RH SIP must provide 
procedures for continuing consultation between the state and Federal 
Land Manager on the implementation of the visibility protection program 
required by section 51.308, including development and review of 
implementation plan revisions and 5-year progress reports, and on the 
implementation of other programs having the potential to contribute to 
impairment of visibility in the mandatory Class I Federal areas. ADEQ 
has stipulated in its RH SIP it will continue to coordinate and consult 
with the FLMs as required by section 51.308(i)(4). ADEQ states it 
intends to consult the FLMs in the development of future progress 
reports and plan revisions, as well as during the implementation of 
programs having the potential to contribute to visibility impairment at 
Caney Creek and Upper Buffalo. We are proposing that ADEQ has satisfied 
section 51.308(i).

I. Periodic SIP Revisions and Five-year Progress Reports

    ADEQ affirmed its commitment to complete items required in the 
future under our RHR. ADEQ acknowledged its requirement under 40 CFR 
51.308(f), to submit periodic progress reports and RH SIP revisions, 
with the first report due by July 31, 2018 and every ten years 
thereafter.
    ADEQ also acknowledged its requirement under 40 CFR 51.308(g), to 
submit a progress report in the form of a SIP revision to the us every 
five years following this initial submittal of the Arkansas RH SIP. The 
report will evaluate the progress made towards the RPGs for each 
mandatory Class I area located within Arkansas and in each mandatory 
Class I area located outside Arkansas which may be affected by 
emissions from within Arkansas. We are proposing that ADEQ has 
satisfied section 51.308(f) and (g).

J. Determination of the Adequacy of Existing Implementation Plan

    Section 51.308(h) requires that Arkansas take one of the listed 
actions, as appropriate, at the same time the State is required to 
submit any 5-year progress report to EPA in accordance with section 
51.308(g). ADEQ has committed in its SIP to take one of the actions 
listed under 51.308(h), depending on the findings of the five-year 
progress report. We are proposing that ADEQ has satisfied section 
51.308(h).

V. Our Analysis of Arkansas' Interstate Visibility Transport SIP 
Provisions

    We received a SIP from Arkansas to address the interstate transport 
requirements of CAA 110(a)(2)(D)(i) for the 1997 8-hour ozone and 
PM2.5 NAAQS on April 2, 2008. Concerning such CAA 
requirements preventing sources in the state from emitting pollutants 
in amounts which will interfere with efforts to protect visibility in 
other states, Arkansas stated that the State's RH Rule, the APC&E 
Commission Regulation 19, chapter 15, satisfies the requirement of 
section 110(a)(2)(D)(i) regarding the protection of visibility. 
Arkansas indicated in the April 2, 2008 submittal that at the time, 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 such time as Arkansas submits and EPA approves the 
Arkansas RH SIP.
    As an initial matter, we note that section 110(a)(2)(D)(i)(II) does 
not explicitly specify how we should ascertain whether a state's SIP 
contains adequate provisions to prevent emissions from sources in that 
state from interfering with measures required in another state to 
protect visibility. Thus, the statute is ambiguous on its face, and we 
must interpret that provision.
    Our 2006 Guidance recommended that a state could meet the 
visibility prong of the transport requirements of section 
110(a)(2)(D)(i)(II) of the CAA by submission of the RH SIP, due in 
December 2007. Our reasoning was that the development of the RH SIPs 
was intended to occur in a collaborative environment among the states. 
In fact, in developing their respective reasonable progress goals, 
CENRAP states consulted with each other through CENRAP's work groups. 
As a result of this process, the common understanding was that each 
state would take action to achieve the emissions reductions relied upon 
by other states in their reasonable progress demonstrations under the 
RHR. CENRAP states consulted in the development of reasonable progress 
goals, using the products of this technical consultation process to co-
develop their reasonable progress goals. In developing their visibility 
projections using photochemical grid modeling, CENRAP states assumed a 
certain level of emissions from sources within Arkansas, consistent 
with the BART determinations made by ADEQ. In the State's September 27, 
2011 supplemental submittal, ADEQ clarified that the base year modeling 
inventory used by CENRAP in the 2002 base case modeling was prepared by 
the CENRAP Modeling Workgroup and its consultants, and was derived 
primarily from the 2002 National Emissions Inventory (NEI). ADEQ also 
clarified that it provided the CENRAP Modeling Workgroup with the 
controlled BART source emission limits contained in the State's RH 
Rule, the APC&E Commission Regulation 19, Chapter 15, for inclusion in 
the CENRAP's 2018 future case modeling. ADEQ stated in its Interstate 
Transport SIP that it is relying on the State RH Rule to meet the 
visibility prong of the transport requirements of section 
110(a)(2)(D)(i)(II) of the CAA. The State's RH Rule became effective 
October 15, 2007. The current language of the regulation requires 
Arkansas' subject to BART sources to comply with BART requirements no 
later than five years after EPA approval of the RH SIP or 6 years after 
the effective date of the regulation, whichever is first. However, on 
March 26, 2010, the Arkansas Pollution Control & Ecology Commission, 
Arkansas' rulemaking body, granted all Arkansas subject to BART sources 
a variance from the compliance deadline imposed by the State's RH Rule, 
such that these sources are now required to comply with BART 
requirements no later than 5 years after EPA approval of the RH 
SIP.\73\ Compliance with these BART requirements will ensure that 
Arkansas obtains its share of the emission reductions relied upon by 
other states to meet the RPGs for their Class I areas. Since compliance 
of Arkansas' subject to BART sources with BART requirements is 
dependent upon our approval of the RH SIP, and since we are proposing 
to disapprove a portion of the RH SIP, including some of Arkansas'

[[Page 64220]]

BART determinations, a portion of the emission reductions committed to 
by Arkansas and relied upon by other states will not be realized.
---------------------------------------------------------------------------

    \73\ A copy of the Arkansas Pollution Control and Ecology 
Commission's Minute Order can be viewed at http://www.adeq.state.ar.us/ftproot/Pub/commission/minute_orders/10-08_Petition_from_Variance_Entergy_Swepco_AECC.pdf.
---------------------------------------------------------------------------

    As we are proposing to disapprove a majority of the BART 
determinations made by ADEQ for its subject to BART sources, we are 
proposing to find that the Arkansas SIP revision submittal does not 
fully ensure that emissions from sources in Arkansas do not interfere 
with other State's visibility programs as required by section 
110(a)(2)(D)(i)(II) of the CAA. Specifically, the BART determinations 
we are proposing to disapprove, will not result in the corresponding 
emission reductions other states relied on to achieve the RPGs in their 
Class I areas. Therefore, we are proposing to partially approve and 
partially disapprove the portion of the Arkansas Interstate Transport 
SIP submittal that addresses the visibility requirement of section 
110(a)(2)(D)(i)(II) that emissions from Arkansas sources not interfere 
with measures required in the SIP of any other state under part C of 
the CAA to protect visibility.

VI. Proposed Action

A. Regional Haze

    We are proposing to partially approve and partially disapprove 
Arkansas' RH SIP revision submitted on September 23, 2008, August 3, 
2010, and supplemented on September 27, 2011. Specifically, we are 
proposing to approve the following:
     The State's identification of affected Class I areas;
     The establishment of baseline and natural visibility 
conditions;
     The Uniform Rate of Progress (URP);
     The State's reasonable progress goal (RPG) consultation 
and the long-term strategy (LTS) consultation;
     The regional haze monitoring strategy and other SIP 
requirements under section 51.308(d)(4);
     The State's commitment to submit periodic regional haze 
SIP revisions and periodic progress reports describing progress towards 
the RPGs;
     The State's commitment to make a determination of the 
adequacy of the existing SIP at the time a progress report is 
submitted;
     And the State's consultation and coordination with Federal 
land managers (FLMs)
    We are proposing to disapprove the State's RPGs because Arkansas 
did not consider the four statutory factors that states are required to 
consider in establishing RPGs under the CAA and section 
51.308(d)(1)(A).
    We are proposing to partially approve and partially disapprove the 
portions of these submittals addressing the State's identification of 
subject to BART sources; the requirements for best available retrofit 
technology (BART); the State's RH Rule; and the LTS. Specifically, we 
are proposing to approve the following:
     The State's identification of BART-eligible sources, with 
the exception of the 6A Boiler at the Georgia-Pacific Crossett Mill, 
which we are proposing to find is BART-eligible;
     The State's identification of subject to BART sources, 
with the exception of its determination that the 6A and 9A Boilers at 
the Georgia-Pacific Crossett Mill are not subject to BART;
     The following BART determinations made by ADEQ: the PM 
BART determination for the No. 1 Boiler of the AEP Flint Creek plant; 
the SO2 and PM BART determinations for the natural gas 
firing scenario for Unit 4 of the Entergy Lake Catherine plant; the PM 
BART determinations for both the bituminous and sub-bituminous coal 
firing scenarios for Units 1 and 2 of the Entergy White Bluff plant; 
and the PM BART determination for the No. 1 Power Boiler of the Domtar 
Ashdown Mill;
     The portion of the submittal we received on September 23, 
2008, and as revised by the submittal received on August 3, 2010, that 
contains those portions of Chapter 15 of APC&E Commission Regulation 19 
which correspond to the portions of the Arkansas RH SIP we are 
proposing to approve. Specifically, we are proposing to approve the 
following sections of Chapter 15 of APC&E Commission Regulation 19: 
Reg. 19.1501; Reg. 19.1502; Reg. 19.1503; the portion of Reg. 
19.1504(A) that identifies AECC Bailey Generating Station (Unit 1), 
AECC McClellan Generating Station (Unit 1), Domtar Ashdown Mill (Power 
Boilers No. 1 and 2), Lake Catherine (Unit 4), White Bluff (Units 1, 2, 
and the Auxiliary Boiler), and AEP Flint Creek (Boiler No. 1) as 
subject to BART sources; Reg. 19.1504(B); Reg. 19.1504(C); Reg. 
19.1505(A)(3); Reg. 19.1505(D)(3); Reg. 19.1505(F)(3); Reg. 
19.1505(G)(3); Reg. 19.1505(I)(3); Reg. 19.1505(J)(3); Reg. 
19.1505(M)(2); Reg. 19.1506; and Reg. 19.1507; and
     The State's LTS, with the exception of the portion of the 
LTS that relied on the BART emission limits and schedules of compliance 
we are proposing to disapprove.
    We are proposing to disapprove the following:
     ADEQ's determination that the 6A and 9A Boilers of the 
Georgia-Pacific Crossett Mill are not subject to BART;
     The following BART determinations made by ADEQ: the 
NOX, PM, and SO2 BART determinations for both 
Unit 1 of the Arkansas Electric Cooperative Corporation (AECC) Bailey 
plant and Unit 1 of the AECC McClellan plant; the SO2 and 
NOX BART determinations for the No. 1 Boiler of the American 
Electric Power (AEP) Flint Creek plant; the NOx BART determination for 
the natural gas firing scenario and the PM, SO2, and 
NOX BART determinations for the fuel oil firing scenario for 
Unit 4 of the Entergy Lake Catherine plant; the SO2 and 
NOX BART determinations for both the bituminous and sub-
bituminous coal firing scenarios for Units 1 and 2 of the Entergy White 
Bluff plant; the BART determination for the Auxiliary Boiler of the 
Entergy White Bluff Plant; the SO2 and NOX BART 
determinations for the No. 1 Power Boiler of the Domtar Ashdown Mill; 
and the SO2, NOX, and PM BART determinations for 
the No. 2 Power Boiler of the Domtar Ashdown Mill;
     A portion of Arkansas' Regional Haze Rule, APC&E 
Commission Regulation 19, chapter 15, which we received on September 
23, 2008, and as revised by the submittal received on August 3, 2010. 
Specifically, we are proposing to disapprove the following sections of 
Chapter 15 of APC&E Commission Regulation 19: The portion of Reg. 
19.1504(A) that fails to identify the 6A and 9A Boilers at the Georgia-
Pacific Crossett Mill as subject to BART sources; Reg. 19.1505(A)(1); 
Reg. 19.1505(A)(2); Reg. 19.1505(B); Reg. 19.1505(C); Reg. 
19.1505(D)(1); Reg. 19.1505(D)(2); Reg. 19.1505(E)(1); Reg. 
19.1505(E)(2); Reg. 19.1505(E)(3); Reg. 19.1505(F)(1); Reg. 
19.1505(F)(2); Reg. 19.1505(G)(1); Reg. 19.1505(G)(2); Reg. 19.1505(H); 
Reg. 19.1505(I)(1); Reg. 19.1505(I)(2); Reg. 19.1505(J)(1); Reg. 
19.1505(J)(2); Reg. 19.1505(K); Reg. 19.1505(L); Reg. 19.1505(M)(1); 
Reg. 19.1505(N)(1); Reg. 19.1505(N)(2); and Reg. 19.1505(N)(3); and
     The portion of the State's LTS that relied on the BART 
emission limits and schedules of compliance we are proposing to 
disapprove.

B. Interstate Transport of Visibility

    We are also proposing to partially approve and partially disapprove 
a portion of a SIP revision submitted by the State of Arkansas for the 
purpose of addressing the ``good neighbor'' provisions of the CAA 
section 110(a)(2)(D)(i) for the 1997 8-hour ozone NAAQS and the 
PM2.5 NAAQS.

[[Page 64221]]

Specifically, we are proposing a partial approval and partial 
disapproval of the Arkansas Interstate Transport SIP provisions that 
address the requirement of section 110(a)(2)(D)(i)(II) that emissions 
from Arkansas sources not interfere with measures required in the SIP 
of any other state under part C of the CAA to protect visibility. 
Although the BART emission limits we are proposing to approve will 
result in the corresponding emission reductions other states relied on 
to achieve the RPGs in their Class I areas, the BART emission limits we 
are proposing to disapprove will not result in the corresponding 
emission reductions other states relied on to achieve the RPGs in their 
Class I areas. Therefore, ADEQ will obtain only a portion of its share 
of the emission reductions relied upon by other states to meet the RPGs 
for their Class I areas.

VII. Statutory and Executive Order Reviews

    Under the Clean Air Act, the Administrator is required to approve a 
SIP submission that complies with the provisions of the Act and 
applicable Federal regulations. 42 U.S.C. 7410(k); 40 CFR 52.02(a). 
Thus, in reviewing SIP submissions, EPA's role is to approve state 
choices, provided that they meet the criteria of the Clean Air Act. 
Accordingly, this action merely proposes to approve state law as 
meeting Federal requirements and does not impose additional 
requirements beyond those imposed by state law. For that reason, this 
action:
     Is not a ``significant regulatory action'' subject to 
review by the Office of Management and Budget under Executive Order 
12866 (58 FR 51735, October 4, 1993);
     Does not impose an information collection burden under the 
provisions of the Paperwork Reduction Act (44 U.S.C. 3501 et seq.);
     Is certified as not having a significant economic impact 
on a substantial number of small entities under the Regulatory 
Flexibility Act (5 U.S.C. 601 et seq.);
     Does not contain any unfunded mandate or significantly or 
uniquely affect small governments, as described in the Unfunded 
Mandates Reform Act of 1995 (Pub. L. 104-4);
     Does not have Federalism implications as specified in 
Executive Order 13132 (64 FR 43255, August 10, 1999);
     Is not an economically significant regulatory action based 
on health or safety risks subject to Executive Order 13045 (62 FR 
19885, April 23, 1997);
     Is not a significant regulatory action subject to 
Executive Order 13211 (66 FR 28355, May 22, 2001);
     Is not subject to requirements of section 12(d) of the 
National Technology Transfer and Advancement Act of 1995 (15 U.S.C. 272 
note) because application of those requirements would be inconsistent 
with the Clean Air Act; and
     Does not provide EPA with the discretionary authority to 
address, as appropriate, disproportionate human health or environmental 
effects, using practicable and legally permissible methods, under 
Executive Order 12898 (59 FR 7629, February 16, 1994).
    In addition, this rule does not have tribal implications as 
specified by Executive Order 13175 (65 FR 67249, November 9, 2000), 
because the SIP is not approved to apply in Indian country located in 
the state, and EPA notes that it will not impose substantial direct 
costs on tribal governments or preempt tribal law.

List of Subjects in 40 CFR Part 52

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

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

    Dated: October 3, 2011.
Al Armendariz,
Regional Administrator, Region 6.
[FR Doc. 2011-26336 Filed 10-14-11; 8:45 am]
BILLING CODE 6560-50-P