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, 64186-64221 [2011-26336]
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Federal Register / Vol. 76, No. 200 / Monday, October 17, 2011 / Proposed Rules
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
Environmental Protection
Agency (EPA).
ACTION: Proposed rule.
AGENCY:
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: https://
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),
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SUMMARY:
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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 https://
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 https://
www.regulations.gov or e-mail. The
https://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 https://
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 https://
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 https://
www.regulations.gov or in hard copy at
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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
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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
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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 longterm 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
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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.
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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.
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
1 CAA
section 110(c)(1).
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applicable SIP for another state
designed to protect visibility for the 8hour 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
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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
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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that would exist under estimated
natural conditions. Id.
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 § 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.
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
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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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.
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
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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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
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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.
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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
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
5 The preamble to the RHR provides additional
details about the deciview. 64 FR 35714, 35725
(July 1, 1999).
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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
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.
6 Guidance for Estimating Natural Visibility
Conditions Under the Regional Haze Rule,
September 2003, EPA–454/B–03–005, available at
https://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 https://www.epa.gov/ttncaaa1/t1/
memoranda/rh_tpurhr_gd.pdf, (hereinafter referred
to as our ‘‘2003 Tracking Progress Guidance’’).
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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
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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impairment at the Class I State’s areas.
40 CFR 51.308(d)(1)(iv).
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 ‘‘BARTeligible’’ 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.
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).
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
8 The set of ‘‘major stationary sources’’ potentially
subject to BART are listed in CAA section
169A(g)(7).
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).
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64191
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.
States must address all visibilityimpairing 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
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.
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BART Guidelines means the collection
of individual emission units at a facility
that together comprises the BARTeligible 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 sourcespecific 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
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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
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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
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• 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.
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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
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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
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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).
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
A. Affected Class I Areas
concentrations of fine particle
In accordance with 40 CFR 51.308(d), components adjusted by site-specific
estimates of humidity. This calculation
ADEQ has identified two Class I areas
within its borders, the Caney Creek
uses the IMPROVE equation, which is a
Wilderness Area (Caney Creek) in
formula for estimating light extinction
Ouachita National Forest and the Upper from the estimated natural
Buffalo Wilderness Area (Upper Buffalo) concentrations of fine particle
in the Ozark National Forest. ADEQ is
components (or from components
responsible for developing RPGs for
measured by the IMPROVE monitors).
these two Class I areas. ADEQ has also
As documented in EPA’s 2003 Natural
determined that Arkansas emissions
Visibility Guidance, EPA allows states
cause and contribute to visibility
to use ‘‘refined’’ or alternative
impairment at the two Class I areas in
approaches to 2003 EPA guidance to
Missouri: Hercules Glades Wilderness
estimate the values that characterize the
Area (Hercules Glades) and Mingo
natural visibility conditions of Class I
National Wildlife Refuge (Mingo). The
areas. One alternative approach is to
TSD for the CENRAP Emissions and Air develop and justify the use of
Quality Modeling to Support Regional
alternative estimates of natural
Haze State Implementation (TSD for
concentrations of fine particle
CENRAP modeling) demonstrates
components. Another alternative is to
Arkansas sources are responsible for a
use the ‘‘new IMPROVE equation’’ that
visibility extinction of approximately
was adopted for use by the IMPROVE
7.1 inverse megameters 12 (Mm¥1) at
Steering Committee in December
2005 16. The purpose of this refinement
Hercules Glades and for a visibility
extinction of approximately 4.95 Mm¥1 to the ‘‘old IMPROVE equation’’ is to
at Mingo on the worst 20% days for
provide more accurate estimates of the
2002.13 As discussed in section IV.C.3 of various factors that affect the calculation
this proposed rulemaking, ADEQ
of light extinction.
ADEQ opted to use the new IMPROVE
consulted with the appropriate state air
equation to calculate the ‘‘refined’’
quality agency in Missouri to reach an
agreement on whether it is necessary for natural visibility conditions. This is an
acceptable approach under our 2003
Arkansas to commit to additional
emission reductions that would help
14 Guidance for Estimating Natural Visibility
Missouri achieve its RPGs for Hercules
Conditions Under the Regional Haze Rule, EPA–
Glades and Mingo.
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
11 The TSD can be found in the docket for this
proposal at https://www.regulations.gov. The docket
number is EPA–R06–OAR–2008–0727.
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 × 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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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.
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.
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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.
the natural visibility conditions
calculation, ADEQ chose to use the new
IMPROVE equation.
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.
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
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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
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
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).
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 https://
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 https://vista.cira.colostate.edu/
improve/Publications/GrayLit/029_NaturalCondII/
naturalhazelevelsIIreport.ppt.
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).
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TABLE 1—SUMMARY OF UNIFORM RATE OF PROGRESS
Visibility metric
Caney Creek
Baseline Conditions ................................................................................................................................
Natural Visibility ......................................................................................................................................
Total Improvement by 2064 ....................................................................................................................
Improvement for this SIP by 2018 ..........................................................................................................
Uniform Rate of Progress .......................................................................................................................
26.36 dv .................
11.58 dv .................
14.78 dv .................
3.45 dv ...................
0.246 dv/year .........
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.
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.
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.
1. Establishment of the Reasonable
Progress Goal
2. ADEQ’s Reasonable Progress ‘‘Four
Factor’’ Analysis
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
In establishing a RPG for a Class I
Federal area located within a state, the
State is required by CAA § 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
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.
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).
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C. Evaluation of Arkansas’ Reasonable
Progress Goals
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Upper Buffalo
26.27 dv.
11.57 dv.
14.70 dv.
3.43 dv.
0.245 dv/year.
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
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the conclusion that its goals provide for
reasonable progress. We provided
comments to ADEQ on the draft
Arkansas RH SIP to that effect.21
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
21 See
Appendix 2.1 of the Arkansas RH SIP
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(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.
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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 BARTeligible 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
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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
64197
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 plants of
more than 250 MMBTU/hr heat input.
AEP Flint Creek Power Plant ..................
Benton ....................
Boiler
AECC Carl E. Bailey Generating .............
Woodruff .................
Boiler
AECC John L. McClellan Generating ......
Ouachita .................
Boiler
Entergy Lake Catherine Plant .................
Hot Spring ...............
Unit 4 Boiler
Entergy Robert E. Ritchie Plant ..............
Phillips ....................
Unit 2
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/International ..........
Jefferson .................
No. 4 Recovery
Georgia-Pacific Crossett Mill ...................
Ashley .....................
9A Boiler
Green Bay Packaging ..............................
Conway ...................
Recovery Boiler
Potlatch Forest Products/Clearwater .......
Desha .....................
Power Boiler
Petroleum ....................................................
Lion Oil Company ....................................
Union ......................
No. 7 Catalyst
Sulfur recovery ............................................
Albermarle Corporation South Plant ........
Columbia .................
Tail Gas
Sintering plants ...........................................
Big River Industries—Arkalite ..................
Crittenden ...............
Kiln A
Chemical process plants ............................
Albermarle Corporation South Plant ........
Columbia .................
No. 1 Boiler
No. 2 Boiler
Future Fuels/Eastman Chemical .............
Independence .........
3 Coal Boilers
El Dorado Chemical Company ................
Union ......................
West Nitric Acid
East Nitric Acid
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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 GeorgiaPacific Crossett Mill, as being BARTeligible. 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
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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 GeorgiaPacific 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
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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
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.’’
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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.
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 BARTeligible 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 BARTeligible.
In the RH SIP, ADEQ did not identify
Boilers SN–301A and SN–302A at the
Great Lakes Chemical Plant as BARTeligible, 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
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.
25 ADEQ Operating Air Permit for the Great Lakes
Chemical Corporation—Central Plant (Permit No.
1077–AOP–R1). This permit can be viewed at
https://www.adeq.state.ar.us/ftproot/pub/
WebDatabases/PermitsOnline/Air/1077-AOPR1.pdf.
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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.
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 BARTeligible 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
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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 visibilityimpairing 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.
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
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 https://www.src.com/
verio/download/download.htm.
27 CENRAP BART Modeling Guidelines, T. W.
Tesche, D. E. McNally, and G. J. Schewe (Alpine
Geophysics LLC), December 15, 2005, available at
https://www.deq.state.ok.us/aqdnew/
RulesAndPlanning/Regional_Haze/SIP/
Appendices/index.htm.
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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.
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
Facility name
BART emission units
Source category
AECC Carl E. Bailey Generating Station ...
Unit 1 ........................................................
fossil fuel-fired steam electric plants ........
Pollutants
evaluated
SO2
NOX
PM10
AECC John L. McClellan Generating Station.
Unit 1 ........................................................
fossil fuel-fired steam electric plants ........
SO2
NOX
PM10
AEP Flint Creek Power Plant .....................
Boiler No. 1 ...............................................
fossil fuel-fired steam electric plants ........
SO2
NOX
PM10
Entergy Lake Catherine Plant .....................
Unit 4 ........................................................
fossil fuel-fired steam electric plants ........
SO2
NOX
PM10
Entergy White Bluff Plant ............................
Units 1, 2, and Auxiliary Boiler .................
fossil fuel-fired steam electric plants ........
SO2
NOX
PM10
Domtar Ashdown Mill ..................................
Power Boilers No. 1 and 2 .......................
kraft pulp mill ............................................
SO2
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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
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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
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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
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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 GeorgiaPacific 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
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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
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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
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
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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
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
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.
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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.
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 BARTeligible 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
31 70
PO 00000
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64201
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 precontrol 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.
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
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.
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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 costeffective. 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
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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
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. https://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. https://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.
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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.
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
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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
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:
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.
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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
38 ADEQ Operating Air Permit for AEP-Flint
Creek Power Plan (Permit No. 0276–AOP–R5). This
permit can be viewed at https://
www.adeq.state.ar.us/ftproot/pub/WebDatabases/
PermitsOnline/Air/0276-AOP-R5.pdf.
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.
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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
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 Ddv at Caney Creek; 3.781 Ddv at Upper
Buffalo; 3.983 Ddv at Hercules Glade; 2.596 Ddv at
Mingo; 1.420 Ddv 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
Ddv), Upper Buffalo (2.089 Ddv), and Hercules
Glade (1.541 Ddv), 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: https://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: https://
airpermit.dnr.state.ga.us/gaairpermits/Permit
PDF.aspx?id=PDF-PI-18499.
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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.
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
45 U.S. EPA, Region 9, Prevention of Significant
Deterioration Permit, Desert Rock Energy Company,
July 31, 2008. Available at: https://
www.regulations.gov/search/Regs/home.html
#docketDetail?R=EPA-R09-OAR-2007-1110.
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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.
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 postcombustion 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
46 See ADEQ Operating Air Permit for Entergy
Arkansas Inc.-Lake Catherine Plant (Permit No.
1717–AOP–R4). This permit can be viewed at
https://www.adeq.state.ar.us/ftproot/pub/
WebDatabases/PermitsOnline/Air/1717-AOPR4.pdf.
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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.
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 postcombustion 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
47 Our comments on this matter are documented
in Appendix 9.3B of the Arkansas RH SIP.
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
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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.
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 postcombustion 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
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).
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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
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and PM emissions may prove to be costeffective 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 subbituminous 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
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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 subbituminous coal firing scenarios is the
existing PM emission limit for Units 1
and 2.
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
51 ADEQ Operating Air Permit for Entergy
Services Inc.—White Bluff Plant (Permit No. 0263–
AOP–R6). This permit can be viewed at https://
www.adeq.state.ar.us/ftproot/pub/WebDatabases/
PermitsOnline/Air/0263-AOP-R6.pdf.
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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
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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 costeffectiveness 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 costeffective, 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.
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
52 See
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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 costeffectiveness 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
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).
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tuning, OFA, and LNB is BART for NOX
for Units 1 and 2, achieving an emission
limit of 0.15 lb/MMBtu for the subbituminous coal firing scenario and 0.28
lb/MMBtu for the bituminous coal firing
scenario. ADEQ agreed with the
Entergy’s determination.
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 postcontrol 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.
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
54 The maximum modeled pre-control Ddv values
at surrounding Class I areas due to the three subjectto-BART units at White Bluff are: Caney Creek=
8.816 Ddv; Upper Buffalo= 7.750 Ddv; Hercules
Glade=6.314 Ddv; Mingo=5.617; and Sipsey=5.843.
See Appendix 9.2C of the Arkansas RH SIP.
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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 postcontrol 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.
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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 noncondensable 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.
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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.
Regarding BART for SO2 for Power
Boiler No. 1, Domtar noted precombustion controls such as fuel
switching/blending and fuel cleaning
are ineffective, as wood has low sulfur
content. Domtar also noted postcombustion 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
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.
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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 precontrol modeling demonstrates the No.
1 Power Boiler emits more than onethird 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.
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
57 Compilation of Air Pollutant Emission Factors,
Volume I: Stationary Point and Area Sources, AP–
42, 5th Edition, January 1995.
58 See EPA’s Air Pollution Control Fact Sheet on
FGD control technology, available at https://
www.epa.gov/ttn/catc/dir1/ffdg.pdf.
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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.
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
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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.
In Step 3 of the BART analysis,
Domtar evaluated the control
effectiveness of the control options it
59See
the docket for this rulemaking to view the
Title V permit for the Temple Inland Kraft
Linerboard Mill.
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64209
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 costeffectiveness 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
60 ADEQ’s post-control modeling, showing the
visibility improvement resulting from BART
controls, demonstrates that the visibility impact of
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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.
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).
TABLE 4—BART DETERMINATIONS SATISFYING SECTION 51.308(e)
Facility name
BART
emission unit
Pollutant
American Electric Power Flint Creek Power Plant ..............
Boiler No. 1 .............
PM10 .......................................
existing PM emission limit
(0.1 lb/MMBtu).
Entergy Lake Catherine Plant ..............................................
Unit 4 .......................
natural gas
firing.
SO2 ..............
No BART Determination.
PM10 .............
existing PM emission limit
(45 lb/hr).
bituminous
coal firing.
PM10 .............
existing PM emission limit
(0.1 lb/MMBtu).
sub-bituminous
coal firing.
PM10 .............
existing PM emission limit
(0.1 lb/MMBtu).
bituminous
coal firing.
PM10 .............
existing PM emission limit
(0.1 lb/MMBtu).
sub-bituminous
coal firing.
PM10 .............
existing PM emission limit
(0.1 lb/MMBtu).
Entergy White Bluff Plant .....................................................
Unit 1 .......................
Unit 2 .......................
Domtar Ashdown Mill ...........................................................
No. 1 Power Boiler ..
BART emission limit 61
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 Corporation Carl E. Bailey
Generating Station.
Unit 1 .......................
SO2 .........................................
Use of fuel oil with 1% sulfur content.
NOX ........................................
No BART Determination.
PM ..........................................
No BART Determination.
SO2 .........................................
Use of fuel oil with 1% sulfur content.
NOX ........................................
No BART Determination.
PM ..........................................
No BART Determination.
SO2 .........................................
0.15 lb/MMBtu.
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Arkansas Electric Cooperative
McClellan Generating Station.
Corporation
John
L.
American Electric Power Flint Creek Power Plant ..............
Power Boilers No. 1 and 2 combined will be 2.038
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Unit 1 .......................
Boiler No. 1 .............
Ddv at Caney Creek and 1.029 Ddv at Upper Buffalo
after ADEQ’s BART controls are put in place.
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61 Emission limits are based on a 30-day rolling
average.
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TABLE 5—BART DETERMINATIONS NOT SATISFYING SECTION 51.308(e)—Continued
BART
emission unit
Facility name
Pollutant
BART emission limit 62
NOX ........................................
SO2 ..............
0.562 lb/MMBtu.
0.25 lb/MMBtu.
0.037 lb/MMBtu.
SO2 ..............
0.15 lb/MMBtu.
NOX ..............
0.28 lb/MMBtu.
SO2 ..............
0.15 lb/MMBtu.
NOX ..............
0.15 lb/MMBtu.
SO2 ..............
0.15 lb/MMBtu.
NOX ..............
0.28 lb/MMBtu.
SO2 ..............
0.15 lb/MMBtu.
NOX ..............
Unit 1 .......................
0.15 lb/MMBtu.
PM ................
Entergy White Bluff Plant .....................................................
NOX ..............
NOX ..............
Unit 4 .......................
natural gas
firing.
fuel oil firing
Entergy Lake Catherine Plant ..............................................
0.23 lb/MMBtu.
0.15 lb/MMBtu.
bituminous
coal firing.
sub-bituminous
coal firing.
Unit 2 .......................
bituminous
coal firing.
sub-bituminous
coal firing.
Auxiliary Boiler ........
Boiler to be operated no
more than 4360 hrs annually.
No. 1 Power Boiler ..
SO2 .........................................
1.12 lb/MMBtu.
NOX ........................................
0.46 lb/MMBtu.
SO2 .........................................
1.2 lb/MMBtu.
NOX ........................................
0.45 lb/MMBtu.
PM10 .......................................
Domtar Ashdown Mill ...........................................................
All ............................................
0.1 lb/MMBtu.
No. 2 Power Boiler ..
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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
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
62 Emission limits are based on a 30-day rolling
average.
63 See Arkansas Pollution Control and Ecology
Commission Reg. 19.1504(B).
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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
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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
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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.
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
64 On March 26, 2010, the Arkansas Pollution
Control & Ecology Commission, Arkansas’
rulemaking body, granted all Arkansas subject-toBART 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.
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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 GeorgiaPacific 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 subbituminous 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 (subbituminous 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.
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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 statespecific 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
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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, nonroad and on-road mobile sources, and
biogenic sources for the baseline year of
64213
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 .........................................................
Area ..........................................................
Non-road mobile ......................................
On-road mobile ........................................
Biogenic ...................................................
92,205
29,889
5,490
3,902
0
1
152,436
49
2,480
0
72,419
27,450
62,472
141,894
18,960
44,329
93,548
54,785
48,599
1,385,666
12,406
148,433
5,673
3,784
0
7,837
68,000
5,220
3,021
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 .........................................................
Area ..........................................................
Non-road mobile ......................................
On-road mobile ........................................
Biogenic ...................................................
106,461
31,169
211
442
0
2,575
201,722
49
3,412
0
71,107
31,531
34,305
33,640
18,960
55,603
107,387
31,475
19,924
1,385,666
19,799
148,592
3,678
949
0
13,775
69,585
3,387
949
0
Total ..................................................
138,283
207,758
189,542
1,600,055
173,019
87,695
jlentini on DSK4TPTVN1PROD with PROPOSALS2
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
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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 https://
www.epa.gov/scram001/guidance/guide/final-03-
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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
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 https://www.epa.gov/
ttnchie1/eidocs/eiguid/, EPA–454/R–05–
001
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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).
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 ..........................................................
NO3 ..........................................................
POA ..........................................................
EC ............................................................
SOIL .........................................................
CM ............................................................
87.05
13.78
10.50
4.80
1.12
3.73
75.10
4.06
1.29
0.19
0.19
0.21
0.09
0.64
1.33
0.33
0.01
0.04
1.19
4.70
0.46
0.86
0.01
0.03
1.70
2.45
1.34
1.79
0.01
0.02
5.66
1.37
5.32
1.40
0.87
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
48.95
7.57
9.93
3.17
1.29
3.58
39.83
2.84
1.76
0.24
0.35
0.24
0.07
0.53
1.18
0.30
0.01
0.04
0.12
0.97
0.14
0.16
0.01
0.03
0.44
1.33
1.03
0.94
0.01
0.01
5.31
1.37
5.09
1.31
0.87
3.02
Sum ...................................................
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SO4 ..........................................................
NO3 ..........................................................
POA ..........................................................
EC ............................................................
SOIL .........................................................
CM ............................................................
85.84
45.27
2.12
1.44
3.76
16.96
1 Totals
include contributions from boundary conditions and secondary organic matter.
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),
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(EC), soil dust, and coarse mass (CM). These
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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
64215
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 ...........................................................
NO3 ..........................................................
POA ..........................................................
EC ............................................................
SOIL .........................................................
CM ............................................................
83.18
13.30
10.85
4.72
1.21
6.85
72.17
3.93
1.06
0.16
0.20
0.29
0.08
0.61
1.33
0.31
0.02
0.05
1.15
4.14
0.47
0.80
0.01
0.05
1.67
2.71
1.38
1.93
0.01
0.02
5.24
1.23
5.75
1.30
0.93
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 ...........................................................
NO3 ..........................................................
POA ..........................................................
EC ............................................................
SOIL .........................................................
CM ............................................................
45.38
9.22
10.17
3.07
1.40
6.53
37.09
3.48
1.48
0.21
0.40
0.36
0.06
0.63
1.20
0.28
0.01
0.05
0.12
1.10
0.14
0.15
0.01
0.04
0.42
1.81
1.01
0.99
0.01
0.02
4.95
1.48
5.49
1.21
0.93
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.
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
67 See Appendix E of the TSD for CENRAP
Emissions and Air Quality Modeling To Support
jlentini on DSK4TPTVN1PROD with PROPOSALS2
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
Regional Haze State Implementation, found in
Appendix 8.1 of the Arkansas RH SIP.
c. Arkansas’ Contribution to Visibility
Impairment in Class I Areas Outside the
State
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TABLE 12—PERCENT CONTRIBUTION FROM ARKANSAS EMISSIONS TO TOTAL VISIBILITY IMPAIRMENT AT CLASS I AREAS
ON 20% WORST DAYS 68
2002
(percent)
Class I area
State
Upper Buffalo ............................................................
Caney Creek .............................................................
Hercules Glades .......................................................
Mingo ........................................................................
Wichita Mountains ....................................................
Mammoth Cave ........................................................
Bondville ...................................................................
Breton Island ............................................................
Cadiz .........................................................................
Arkansas ...................................................................
Arkansas ...................................................................
Missouri ....................................................................
Missouri ....................................................................
Oklahoma .................................................................
Kentucky ...................................................................
Illinois ........................................................................
Louisiana ..................................................................
Kentucky ...................................................................
jlentini on DSK4TPTVN1PROD with PROPOSALS2
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.
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
68 Contributions less than 1% were excluded from
Table 12.
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 × 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.
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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.
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
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10.2
10.1
5.9
3.3
2.0
1.0
1.2
1.1
0.9
2018
(percent)
14.0
13.1
7.6
4.4
2.3
1.8
1.5
1.3
1.2
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
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jlentini on DSK4TPTVN1PROD with PROPOSALS2
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
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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, regionalscale, 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,
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64217
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 BARTeligible 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.
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
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.
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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.
jlentini on DSK4TPTVN1PROD with PROPOSALS2
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
72 Arkansas’ part II Visibility Protection SIP
contained RAVI provisions and was approved by
EPA on July 21, 1988 (53 FR 27514).
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the monitoring and LTS provisions. We
discuss the relevant monitoring
provisions in the section that follows.
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.
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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
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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).
jlentini on DSK4TPTVN1PROD with PROPOSALS2
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).
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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 fiveyear 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 8hour 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
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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 codevelop 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’
73 A copy of the Arkansas Pollution Control and
Ecology Commission’s Minute Order can be viewed
at https://www.adeq.state.ar.us/ftproot/Pub/
commission/minute_orders/10-08_Petition_from_
Variance_Entergy_Swepco_AECC.pdf.
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BART determinations, a portion of the
emission reductions committed to by
Arkansas and relied upon by other
states will not be realized.
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
jlentini on DSK4TPTVN1PROD with PROPOSALS2
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).
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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 BARTeligible 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:
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• 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 GeorgiaPacific 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.
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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
jlentini on DSK4TPTVN1PROD with PROPOSALS2
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
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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
PO 00000
Frm 00037
Fmt 4701
Sfmt 9990
64221
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
E:\FR\FM\17OCP2.SGM
17OCP2
]]>Agencies
[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.
-----------------------------------------------------------------------
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: https://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 https://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 https://www.regulations.gov or e-
mail. The https://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 https://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 https://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 https://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.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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.''
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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).
---------------------------------------------------------------------------
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).
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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 https://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 https://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.
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\8\ The set of ``major stationary sources'' potentially subject
to BART are listed in CAA section 169A(g)(7).
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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).
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\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).
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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.
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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\
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\11\ The TSD can be found in the docket for this proposal at
https://www.regulations.gov. The docket number is EPA-R06-OAR-2008-
0727.
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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.
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\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.
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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.
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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 pe
