[Federal Register Volume 76, Number 55 (Tuesday, March 22, 2011)]
[Proposed Rules]
[Pages 16168-16197]
[FR Doc No: 2011-5799]

Vol. 76

Tuesday,

No. 55

March 22, 2011

Part III

Environmental Protection Agency

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

40 CFR Part 52

Approval and Promulgation of Implementation Plans; Oklahoma; Regional
Haze State Implementation Plan; Federal Implementation Plan for
Interstate Transport of Pollution Affecting Visibility and Best
Available Retrofit Technology Determinations; Proposed Rule

Federal Register / Vol. 76 , No. 55 / Tuesday, March 22, 2011 /
Proposed Rules

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

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 52

[EPA-R06-OAR-2010-0190; FRL-9279-7]

Approval and Promulgation of Implementation Plans; Oklahoma;
Regional Haze State Implementation Plan; Federal Implementation Plan
for Interstate Transport of Pollution Affecting Visibility and Best
Available Retrofit Technology Determinations

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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

SUMMARY: EPA is proposing to partially approve and partially disapprove
a revision to the Oklahoma State Implementation Plan (SIP) submitted by
the State of Oklahoma through the Oklahoma Department of Environmental
Quality (ODEQ) on February 19, 2010 that addresses regional haze for
the first implementation period. This revision was 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''). States are
required to assure reasonable progress toward the national goal of
achieving natural visibility conditions in Class I areas. EPA is
proposing to approve a portion of this SIP revision as meeting certain
requirements of the regional haze program and to partially approve and
partially disapprove those portions addressing the requirements for
best available retrofit technology (BART) and the long-term strategy
(LTS). EPA is proposing a Federal Implementation Plan (FIP) to
implement sulfur dioxide (SO2) emission limits on six
sources to address these issues. EPA also is proposing to disapprove
the State's submitted alternative to BART; EPA is taking no action on
the submitted reasonable progress goals at this time. In addition, EPA
is proposing to partially approve and partially disapprove a portion of
a revision to the Oklahoma SIP submitted by the State of Oklahoma on
May 10, 2007 and supplemented on December 10, 2007. We are taking
action on that portion of the submittals addressing the requirements of
CAA as it applies to visibility for the 1997 8-hour ozone and 1997
particulate matter (PM2.5) National Ambient Air Quality
Standards (NAAQS). This portion of the submittals addresses the
requirement that Oklahoma's SIP contain adequate provisions to prohibit
emissions from interfering with measures required in another state to
protect visibility. In this action, we propose a FIP to address the
deficiencies in this portion of Oklahoma's SIP submittals. The proposed
FIP will prevent emissions from six Oklahoma sources from interfering
with other states' measures to protect visibility and to implement
sulfur dioxide emission limits on these six sources to prevent such
interference.

DATES: Comments: Comments must be received on or before May 23, 2011.
    Public Hearing. An open house and public hearing for this proposal
is scheduled to be held on Wednesday April 13, 2011, at the Metro
Technology Centers, Springlake Campus, Business Conference Center,
Meeting Rooms H and I, 1900 Springlake Drive, Oklahoma City, OK 73111,
(405) 424-8324. The Metro Technology Centers Springlake Campus is
located at the intersection of Martin Luther King Ave. and Springlake
Dr. between NE. 36th and NE. 50th just south of the Oklahoma City Zoo
and Kirkpatrick Center. Parking for the Business Conference Center is
available at no charge. The open house will begin at 1 p.m. and end at
3 p.m. local time. The public hearing will be held from 4 p.m. until 6
p.m., and again from 7 p.m. until 9 p.m.
    The public hearing will provide interested parties the opportunity
to present information and opinions to EPA concerning our proposal.
Interested parties may also submit written comments, as discussed in
the proposal. Written statements and supporting information submitted
during the comment period will be considered with the same weight as
any oral comments and supporting information presented at the public
hearing. We will not respond to comments during the public hearing.
When we publish our final action, we will provide written responses to
all oral and written comments received on our proposal. To provide
opportunities for questions and discussion, we will hold an open house
prior to the public hearing. During the open house, EPA staff will be
available to informally answer questions on our proposed action. Any
comments made to EPA staff during the open house must still be provided
formally in writing or orally during the public hearing in order to be
considered in the record.
    At the public hearing, the hearing officer may limit the time
available for each commenter to address the proposal to 5 minutes or
less if the hearing officer determines it to be appropriate. We will
not be providing equipment for commenters to show overhead slides or
make computerized slide presentations. Any person may provide written
or oral comments and data pertaining to our proposal at the Public
Hearing. Verbatim transcripts, in English, of the hearing and written
statements will be included in the rulemaking docket.
    Addresses: Submit your comments, identified by Docket No. EPA-R06-
OAR-2010-0190, by one of the following methods:
     Federal e-Rulemaking Portal: http://www.regulations.gov.
Follow the online instructions for submitting comments.
     E-mail<EMAIL_ADDRESS>     Mail: Mr. Joe Kordzi, Air Planning Section (6PD-L),
Environmental Protection Agency, 1445 Ross Avenue, Suite 1200, Dallas,
Texas 75202-2733.
     Hand or Courier Delivery: Mr. Joe Kordzi, Air Planning
Section (6PD-L), Environmental Protection Agency, 1445 Ross Avenue,
Suite 700, Dallas, Texas 75202-2733. Such deliveries are accepted only
between the hours of 8 a.m. and 4 p.m. weekdays, and not on legal
holidays. Special arrangements should be made for deliveries of boxed
information.
     Fax: Mr. Joe Kordzi, Air Planning Section (6PD-L), at fax
number<PHONE_NUMBER>.
    Instructions: Direct your comments to Docket No. EPA-R06-OAR-2010-
0190. Our policy is that all comments received will be included in the
public docket without change and may be made available online at http://www.regulations.gov, including any personal information provided,
unless the comment includes information claimed to be Confidential
Business Information (CBI) or other information whose disclosure is
restricted by statute. Do not submit information that you consider to
be CBI or otherwise protected through www.regulations.gov or e-mail.
The http://www.regulations.gov Web site is an ``anonymous access''
system, which means we will not know your identity or contact
information unless you provide it in the body of your comment. If you
send an e-mail comment directly to us without going through
www.regulations.gov your e-mail address will be automatically captured
and included as part of the comment that is placed in the public docket
and made available on the Internet. If you submit an electronic
comment, we recommend that you include your name and other contact
information in the body of your comment and with any disk or CD-ROM you
submit. If we cannot read your comment due to

technical difficulties and cannot contact you for clarification, we may
not be able to consider your comment. Electronic files should avoid the
use of special characters, any form of encryption, and be free of any
defects or viruses.
    Docket: All documents in the docket are listed in the http://www.regulations.gov index. Although listed in the index, some
information is not publicly available, e.g., CBI or other information
whose disclosure is restricted by statute. Certain other material, such
as copyrighted material, will be publicly available only in hard copy.
Publicly available docket materials are available either electronically
in 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<PHONE_NUMBER> 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 the 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 Oklahoma Department of
Environmental Quality, 707 N Robinson, Oklahoma City, OK 73102.

FOR FURTHER INFORMATION CONTACT: Joe Kordzi, EPA Region 6 Air Planning
Section, telephone<PHONE_NUMBER>, e-mail address<EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION: Throughout this document wherever ``we,''
``us,'' or ``our'' is used, we mean the EPA.
    This action is being taken under section 110 and part C of the CAA.

Table of Contents

I. Overview of Proposed Actions
    A. Regional Haze
    B. Interstate Transport of Visibility
II. SIP and FIP Background
III. 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)
IV. 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
V. Our Analysis of Oklahoma's Regional Haze SIP
    A. Affected Class I Areas
    B. Determination of Baseline, Natural and Current Visibility
Conditions
    1. Estimating Natural Visibility Conditions
    2. Estimating Baseline Visibility Conditions
    3. Natural Visibility Impairment
    4. Uniform Rate of Progress
    C. Evaluation of Oklahoma's Reasonable Progress Goal
    1. Establishment of the Reasonable Progress Goal
    2. ODEQ's Reasonable Progress ``Four Factor'' Analysis
    3. Reasonable Progress Consultation
    D. Evaluation of Oklahoma's BART Determinations
    1. Identification of BART-Eligible Sources
    2. Identification of Sources Subject to BART
    a. Modeling Methodology
    b. Contribution Threshold
    c. BART Sources Exempted Due to Permit Modifications
    d. Sources Identified by ODEQ as Subject to BART
    3. BART Determinations
    a. OG&E Seminole Units 1, 2, and 3 BART Determinations
    b. OG&E Sooner Units 1 and 2 BART Determinations
    c. OG&E Muskogee Units 4 and 5 BART Determinations
    d. AEP/PSO Comanche Units 1 and 2 BART Determinations
    e. AEP/PSO Northeastern Unit 2, 3, and 4 BART Determination
    f. AEP/PSO Southwestern Unit 3 BART Determination
    g. ODEQ BART Results and Summary
    E. Evaluation of ODEQ's SO2 BART Determinations for
the OG&E and AEP/PSO Coal Fired Power Plant Units
    1. Cost Effectiveness
    a. Dry Scrubbing Cost Analyses
    b. Wet Scrubbing Cost Analyses
    2. Visibility Benefit
    3. Our Conclusion on Oklahoma's SO2 BART Evaluations
for the Six OG&E and AEP/PSO Units
    4. Alternative BART Determination
    F. Federal Implementation Plan To Address SO2 BART
for the Six Sources
    1. Introduction
    2. Appropriate Emission Limits
    a. Dry Scrubber Emission Limit
    b. Wet Scrubber Emission Limit
    3. Visibility Benefit From Dry and Wet Scrubbing
    4. EPA's SO2 BART Determination for the Six Units
    G. Long-Term Strategy
    1. Emissions Inventory
    a. Oklahoma's 2002 Emission Inventory
    b. Oklahoma's 2018 Emission Inventory
    2. Visibility Projection Modeling
    3. Consultation and Emissions Reductions for Other States' Class
I Areas
    4. Mandatory Long Term Strategy Factors
    H. Coordination of RAVI and Regional Haze Requirements
    I. Monitoring Strategy and Other SIP Requirements
    J. Federal Land Manager Coordination
    K. Periodic SIP Revisions and Five-Year Progress Reports
VI. Our Analysis of Oklahoma's Interstate Visibility Transport SIP
Provisions
VII. Proposed Actions
    A. Regional Haze
    B. Interstate Transport and Visibility
VIII. Statutory and Executive Order Reviews

I. Overview of Proposed Actions

A. Regional Haze

    We propose to partially approve and partially disapprove Oklahoma's
regional haze (RH) SIP revision submitted on February 19, 2010.
Specifically, we propose to disapprove the SO2 BART
determinations for Units 4 and 5 of the Oklahoma Gas and Electric
(OG&E) Muskogee plant; Units 1 and 2 of the OG&E Sooner plant; and
Units 3 and 4 of the American Electric Power/Public Service Company of
Oklahoma (AEP/PSO) Northeastern plant. We propose to disapprove these
SO2 BART determinations because they do not comply with our
regulations under 40 CFR 51.308(e).
    We are also proposing to disapprove the long term strategy (LTS)
under section 51.308(d)(3) because Oklahoma has not shown that the
strategy is adequate to achieve the reasonable progress goals set by
Oklahoma and by other nearby States. The visibility modeling used by
Oklahoma in support of its SIP revision submittal assumed
SO2 reductions from the six sources \1\ as identified above
that Oklahoma did not secure when making its BART determinations for
these sources. As we discuss elsewhere, ODEQ participated in the
Central Regional Air Planning Association (CENRAP) visibility modeling
development that assumed certain SO2 reductions from these
six BART sources. ODEQ also performed its consultations with other
states with the understanding that these reductions would be secured.
We propose a FIP to cure these defects in BART and the LTS.
---------------------------------------------------------------------------

    \1\ In this document, when we say ``six BART sources,'' or ``six
sources,'' we mean Units 4 and 5 of the Oklahoma Gas and Electric
Muskogee plant; Units 1 and 2 of the Oklahoma Gas and Electric
Sooner plant; and Units 3 and 4 of the American Electric Power/
Public Service Company of Oklahoma Northeastern plant.

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

    We are also proposing to approve the remaining sections of the RH
SIP submission, except as discussed below.
    We propose to find that Units 4 and 5 of the OG&E Muskogee plant,
Units 1 and 2 of the OG&E Sooner plant, and Units 3 and 4 of the AEP/
PSO Northeastern plant are subject to BART under 40 CFR 51.308(e).
Further, we propose a FIP that specifically imposes SO2 BART
emission limits on these sources. We propose that SO2 BART
for Units 4 and 5 of the OG&E Muskogee plant, Units 1 and 2 of the OG&E
Sooner plant, and Units 3 and 4 of the AEP/PSO Northeastern plant is an
SO2 emission limit of 0.06 lbs/MMBtu that applies singly to
each of these units on a 30 day rolling average. Additionally, we
propose monitoring, recordkeeping, and reporting requirements to ensure
compliance with these emission limitations.
    We propose that compliance with the emission limits be within three
(3) years of the effective date of our final rule. We solicit comments
on alternative timeframes, of from two (2) years up to five (5) years
from the effective date our final rule.
    Should OG&E and/or AEP/PSO elect to reconfigure the above units to
burn natural gas, as a means of satisfying their BART obligations under
section 51.308(e), that conversion should be completed within the same
time frame. We invite comments as to, considering the engineering and/
or management challenges of such a fuel switch, whether the full 5
years allowed under section 308(e)(1)(iv) following our final approval
would be appropriate.
    We propose to disapprove section VI.E of the Oklahoma RH SIP
entitled, ``Greater Reasonable Progress Alternative Determination.'' We
also propose to disapprove the separate executed agreements between
ODEQ and OG&E, and ODEQ and AEP/PSO entitled ``OG&E Regional Haze
Agreement, Case No. 10-024, and ``PSO Regional Haze Agreement, Case No.
10-025,'' housed within Appendix 6-5 of the RH SIP. We propose that
these portions of the submittal are severable from the BART
determinations and the LTS; therefore, no FIP is required.
    We are taking no action on whether Oklahoma has satisfied the
reasonable progress requirements of EPA's regional haze SIP
requirements found at section 51.308(d)(1).

B. Interstate Transport of Visibility

    We also propose to partially approve and partially disapprove a
portion of a SIP revision we received from the State of Oklahoma on May
10, 2007, as supplemented on December 10, 2007, 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 which will * * *
interfere with measures required to be included in the applicable
implementation plan for any other State under part C [of the CAA] to
protect visibility.'' Because of the impacts on visibility from the
interstate transport of pollutants, we interpret the ``good neighbor''
provisions of section 110 of the Act described above as requiring
states to include in their SIPs measures to prohibit emissions that
would interfere with the reasonable progress goals set to protect Class
I areas in other states.
    These SIP revisions were submitted to address the requirement that
Oklahoma's SIP must have adequate provisions to prohibit emissions from
adversely affecting another state's air quality through interstate
transport. Oklahoma indicates in its May 10, 2007 submittal that it
intended that its RH SIP be used to satisfy the requirements of section
110(a)(2)(D)(i)(II) that emissions from Oklahoma sources do not
interfere with measures required in the SIP of any other state under
part C of the CAA to protect visibility. Consistent with our proposed
actions with regard to Oklahoma's RH SIP revision submittal, we also
propose a partial approval and partial disapproval of the Oklahoma
Interstate Transport SIP revision submittals that address the
requirement of section 110(a)(2)(D)(i)(II).
    Specifically, we propose a partial approval and partial disapproval
of the Oklahoma Interstate Transport SIP revision submittals that
address the requirement of section 110(a)(2)(D)(i)(II) that emissions
from Oklahoma sources do not interfere with measures required in the
SIP of any other state under part C of the CAA to protect visibility.
We believe that the controls proposed under the proposed FIP, in
combination with the controls required by the portion of the Oklahoma
RH submittal that we propose to approve, will serve to prevent sources
in Oklahoma from emitting pollutants in amounts which will interfere
with efforts to protect visibility in other states.

II. SIP and FIP Background

    The CAA requires each state to develop a plan that provides for the
implementation, maintenance, and enforcement of the NAAQS. CAA section
110(a). We establish NAAQS under section 109 of the CAA. Currently, the
NAAQS address six criteria pollutants: Carbon monoxide; nitrogen
dioxide; ozone; lead; particulate matter; and sulfur dioxide. The plan
developed by a state is referred to as the SIP. The content of the SIP
is specified in section 110 of the CAA, other provisions of the CAA,
and applicable regulations. A primary purpose of the SIP is to provide
the air pollution regulations, control strategies, and other means or
techniques developed by the state to ensure that the ambient air within
that state meets the NAAQS. However, another important aspect of the
SIP is to ensure that emissions from within the state do not have
certain prohibited impacts upon the ambient air in other states through
the interstate transport of pollutants. CAA section 110(a)(2)(D).
States are required to update or revise SIPs under certain
circumstances. See CAA section 110(a)(1). One such circumstance is our
promulgation of a new or revised NAAQS. Id. Each state must submit
these revisions to us for approval and incorporation into the federally
enforceable SIP.
    If a state fails to make a required SIP submittal or if we find
that, the state's submittal is incomplete or unapprovable, then we must
promulgate a FIP to fill this regulatory gap. CAA section 110(c)(1). As
discussed elsewhere in this notice, we have made findings related to
Oklahoma SIP revisions needed to address interstate transport and the
requirement that emissions from Oklahoma sources do not interfere with
measures required in the SIP of any other state to protect visibility,
pursuant to section 110(a)(2)(D)(i)(II) of the CAA. We propose a FIP to
address the deficiencies in the Oklahoma Interstate Transport SIP.

III. 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 that would exist
under estimated natural conditions. Id.
---------------------------------------------------------------------------

    \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 manmade 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 were 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).
---------------------------------------------------------------------------

    \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.
    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 Regional
Planning Organizations 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, as applicable, including section
110(a)(2)(D)(i), which pertains to the interstate transport of certain
emissions.
    On April 25, 2005, we published a ``Finding of Failure to Submit
SIPs for Interstate Transport for the 8-hour Ozone and PM2.5
NAAQS.'' 70 FR 21147. This included a finding that Oklahoma and other
states had failed to submit SIPs for interstate transport of air
pollution affecting visibility, and started a 2-year clock for the
promulgation of a FIP by us, unless a state made a submission to meet
the requirements of section 110(a)(2)(D)(i) and we approved the
submission. Id.
    On August 15, 2006, we issued our ``Guidance for State
Implementation Plan (SIP) Submission 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.
    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 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 May 10, 2007, we received a SIP revision from Oklahoma to
address the interstate transport provisions of CAA 110(a)(2)(D)(i) for
the 1997 ozone and PM2.5 NAAQS. We received a supplement to
this SIP revision on December 10, 2007. In a prior action we approved
the Oklahoma SIP submittal for the ``interfere with measures to prevent
significant deterioration'' prong of section 110(a)(2)(D)(i) of the
CAA. 75 FR 72695, November 26, 2010. On February 19, 2010, Oklahoma
submitted a RH SIP to address interstate transport of emissions that
could interfere with efforts to protect visibility in other states.
Because, for the reasons outlined below, we can only partially approve
this RH SIP, we propose to partially approve and partially disapprove
the Oklahoma Interstate Transport SIP revision submittals that address
the requirement that emissions from Oklahoma sources do 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 propose to
promulgate a FIP in order to cure this defect in the Oklahoma
Interstate Transport SIP revision submittals.

IV. 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\
---------------------------------------------------------------------------

    \5\ The preamble to the RHR provides additional details about
the deciview. 64 FR 35714, 35725 (July 1, 1999).
---------------------------------------------------------------------------

    The deciview is used in expressing Reasonable Progress Goals (RPGs)
(which are interim visibility goals towards meeting the national
visibility goal), defining baseline, current, and natural conditions,
and tracking changes in visibility. The RH SIPs must contain measures
that ensure ``reasonable progress'' toward the national goal of
preventing and remedying visibility impairment in Class I areas caused
by manmade air pollution by reducing anthropogenic emissions that cause
RH. The national goal is a return to natural conditions, i.e., manmade
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\
---------------------------------------------------------------------------

    \6\ Guidance for Estimating Natural Visibility Conditions Under
the Regional Haze Rule, September 2003, EPA-454/B-03-005, available
at http://www.epa.gov/ttncaaa1/t1/memoranda/rh_envcurhr_gd.pdf
(hereinafter referred to as ``our 2003 Natural Visibility
Guidance''); and Guidance for Tracking Progress Under the Regional
Haze Rule, EPA-454/B-03-004, September 2003, available at http://www.epa.gov/ttncaaa1/t1/memoranda/rh_tpurhr_gd.pdf (hereinafter
referred to as our ``2003 Tracking Progress Guidance'').
---------------------------------------------------------------------------

    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.

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

    \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).
---------------------------------------------------------------------------

D. Best Available Retrofit Technology

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

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

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

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

    On July 6, 2005, we published the Guidelines for BART
Determinations Under the Regional Haze Rule at Appendix Y to 40 CFR
Part 51 (``BART Guidelines'') to assist states in determining which of
their sources should be subject to the BART requirements and in
determining appropriate emission limits for each applicable source. 70
FR 39104. In making a BART determination for a fossil fuel-fired
electric generating plant with a total generating capacity in excess of
750 megawatts, 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.
---------------------------------------------------------------------------

    \10\ BART-eligible sources are those sources that have the
potential to emit 250 tons or more of a visibility-impairing air
pollutant, were put in place between August 7, 1962 and August 7,
1977, and whose operations fall within one or more of 26
specifically listed source categories.
---------------------------------------------------------------------------

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

V. Our Analysis of Oklahoma's Regional Haze SIP

    On February 19, 2010, we received a RH SIP revision from the State
of Oklahoma for approval into the Oklahoma SIP. The following is a
discussion of our evaluation of that submission. The parts of the
submittal 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 ODEQ's submission in the order in which the
regulations appear in 40 CFR 51.308, and a more comprehensive technical
analysis.

A. Affected Class I Areas

    In accordance with 40 CFR 51.308(d), ODEQ has identified one Class
I area within its borders, the Wichita Mountains National Wildlife
Refuge (Wichita Mountains). ODEQ has also determined that Oklahoma
emissions have a small potential to impact visibility at Class I areas
outside of Oklahoma. Based on projections of visibility in 2018 for the
20% worst visibility days, ODEQ has projected that Oklahoma emissions
are responsible for visibility degradation at the Hercules Glades in
Missouri of approximately 3.61%, the Salt Creek in New Mexico of
approximately 2.53%, and the Guadalupe Mountains in Texas of
approximately 2.0%.\11\ We note that these projections are based on
modeling done by CENRAP that assumed a certain level of reductions of
SO2 emissions from six sources that Oklahoma did not
actually require in its submitted RH SIP revision. We expect that
Oklahoma's projected impacts on visibility at Class I areas outside of
Oklahoma would be greater had these controls and the associated
SO2 emission reductions not been included in CENRAP's
visibility modeling.
---------------------------------------------------------------------------

    \11\ Unless otherwise noted, when we refer to visibility
impacts, we mean the impacts due solely to the source or state
named, which do not include natural conditions.
---------------------------------------------------------------------------

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,\12\ ODEQ calculated
baseline/current and natural visibility conditions for its Class I
area, the Wichita Mountains, on the most impaired and least impaired
days, as summarized below (and further described in the TSD).
---------------------------------------------------------------------------

    \12\ Guidance for Estimating Natural Visibility Conditions Under
the Regional Haze Rule, EPA-454/B-03-005, September 2003.
---------------------------------------------------------------------------

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.\13\ 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.
---------------------------------------------------------------------------

    \13\ 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.
---------------------------------------------------------------------------

    ODEQ opted to use the default estimates for the natural conditions
combined with the ``new Improve equation,'' for Wichita Mountains. This
is an acceptable approach under our 2003 Natural Visibility Guidance.
For the Wichita Mountains, the default natural visibility value for the
20 percent worst days is 11.07 deciviews and for the 20 percent best
days it is 3.39 dv. For the Wichita Mountains, ODEQ also used the new
IMPROVE equation to calculate the ``refined'' natural visibility value
for the 20 percent worst days to be 7.53 deciviews and for the 20
percent best days to be 4.2 deciviews. We have reviewed ODEQ's estimate
of the natural visibility conditions and propose to find it acceptable
using the new IMPROVE equation.
    The new IMPROVE equation takes into account the most recent review
of the science \14\ and it accounts for the effect of particle size
distribution on light extinction efficiency of sulfate, nitrate, 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.
---------------------------------------------------------------------------

    \14\ The science behind the revised IMPROVE equation is
summarized in Appendix B.2 of the Tennessee Regional Haze submittal
and in numerous published papers. See for example: Hand, J.L., and
Malm, W.C., 2006, Review of the IMPROVE Equation for Estimating
Ambient Light Extinction Coefficients--Final Report. March 2006.
Prepared for Interagency Monitoring of Protected Visual Environments
(IMPROVE), Colorado State University, Cooperative Institute for
Research in the Atmosphere, Fort Collins, Colorado, available at
http://vista.cira.colostate.edu/improve/publications/GrayLit/016_IMPROVEeqReview/IMPROVEeqReview.htm and Pitchford, Marc., 2006,
Natural Haze Levels II: Application of the New IMPROVE Algorithm to
Natural Species Concentrations Estimates. Final Report of the
Natural Haze Levels II Committee to the RPO Monitoring/Data Analysis
Workgroup. September 2006, available at http://vista.cira.colostate.edu/improve/Publications/GrayLit/029_NaturalCondII/naturalhazelevelsIIreport.ppt.
---------------------------------------------------------------------------

2. Estimating Baseline Visibility Conditions
    As required by section 51.308(d)(2)(i) of the RHR and in accordance
with EPA's 2003 Natural Visibility Guidance,\15\ ODEQ calculated
baseline visibility conditions for the Wichita Mountains. The baseline
condition calculation begins with the calculation of light extinction,
using the IMPROVE equation. The IMPROVE equation sums the light
extinction \16\ resulting from individual pollutants, such as sulfates
and nitrates. As with the natural visibility conditions calculation,
ODEQ chose to use the new IMPROVE equation.
---------------------------------------------------------------------------

    \15\ Guidance for Estimating Natural Visibility Conditions Under
the Regional Haze Rule, EPA-454/B-03-005, September 2003.
    \16\ The amount of light lost as it travels over one million
meters. The haze index, in units of deciviews (dv), is calculated
directly from the total light extinction, bext expressed
in inverse megameters (Mm-1), as follows: HI = 10
ln(bext/10).
---------------------------------------------------------------------------

    The period for establishing baseline visibility conditions is 2000-
2004, and baseline conditions must be calculated using available
monitoring data. 40 CFR 51.308(d)(2). Although visibility monitoring
only began at the Wichita Mountains in March 2001, ODEQ concluded that
no other monitor provided a reasonable substitute that met our
completeness criteria.\17\ As a consequence, the Oklahoma RH SIP
employed the incomplete visibility data for 2001, complete data for
2002-2004, and provisional data for 2005 and 2006. The resulting
baseline conditions represent an average for 2002-2004. ODEQ calculated
the baseline conditions at the Wichita Mountains as 23.81 deciviews on
the 20 percent worst days, and 9.78 deciviews on the 20 percent best
days. We have reviewed ODEQ's estimation of baseline visibility
conditions at Wichita Mountains and propose to find it acceptable.
---------------------------------------------------------------------------

    \17\ Guidance for Tracking Progress Under the Regional Haze
Rule, EPA-454/B-03-004, September 2003, pages 2-8.
---------------------------------------------------------------------------

3. Natural Visibility Impairment
    To address 40 CFR 51.308(d)(2)(iv)(A), ODEQ also calculated the
number of deciviews by which baseline conditions exceed natural
visibility conditions at the Wichita Mountains for the 20 percent worst
days to be 16.28 dv (23.81-7.53). ODEQ calculated the baseline and
natural visibility conditions on the 20 percent best days to be 9.78
and 4.2 dv, respectively. This results in a calculation in which
baseline conditions exceed natural visibility conditions at the Wichita
Mountains for the 20 percent best days to be 5.6 dv (9.78-4.2). We have
reviewed ODEQ's estimate of the natural visibility impairment and
propose to find it acceptable.
4. Uniform Rate of Progress
    In setting the RPGs, ODEQ analyzed and determined the Uniform Rate
of Progress (URP) needed to reach natural visibility conditions by the
year 2064. In so doing, ODEQ compared the baseline visibility
conditions in the Wichita Mountains to the natural visibility
conditions in the Wichita Mountains (as described above) and determined
the uniform rate of progress needed in order to attain natural
visibility conditions by 2064. ODEQ constructed the URP consistent with
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 the Wichita Mountains. Using a baseline
visibility value of 23.81 dv and a ``refined'' natural visibility value
of 7.53 dv for the 20 percent worst days, ODEQ calculated the URP to be
approximately 0.27 dv per year. This results in a total reduction of
16.28 dv that are necessary to reach the natural visibility condition
of 7.53 dv in 2064. The URP results in a visibility improvement of 3.80
dv for the period covered by this SIP revision submittal (up to and
including 2018).

              Table 1--Summary of Uniform Rate of Progress
------------------------------------------------------------------------

------------------------------------------------------------------------
Baseline Conditions......................  23.81 dv.
Natural Visibility.......................  7.53 dv.
Total Improvement by 2064................  16.28 dv.
Improvement for this SIP by 2018.........  3.80 dv.
Uniform Rate of Progress.................  0.27 dv/year.
------------------------------------------------------------------------

    We propose to find that ODEQ has appropriately calculated the URP.

C. Evaluation of Oklahoma's Reasonable Progress Goal

    We are not taking action on Oklahoma's submitted RPGs because, as
described more fully below, we must first evaluate and act upon the RH
SIP revision submitted by the State of Texas. We provide a short
summary of the Oklahoma submittal for informational purposes only.
1. Establishment of the Reasonable Progress Goal
    ODEQ calculated the RPG for the Wichita Mountains for 2018 for the
20% best days to be 9.23 dv, which is a 0.54 dv improvement over a
baseline of 9.78 dv. ODEQ calculated the reasonable progress goal for
2018 for the 20% worst days to be 21.47 dv, which is a 2.3 deciview
improvement over a baseline of 23.81 dv. ODEQ's RPG establishes a
slower rate of progress than the URP. ODEQ has calculated that under
its reasonable progress goal, it would attain natural visibility
conditions in 2102. As we discuss elsewhere, ODEQ indicated that
emissions from other states, especially Texas, impeded Oklahoma's
ability to meet the URP.
2. ODEQ's Reasonable Progress ``Four Factor'' Analysis
    ODEQ analyzed the largest sources of visibility impairing
pollutants within the state, including sources of sulfur, nitrates,
ammonia, VOCs, and directly emitted coarse and fine particles. ODEQ
calculated (1) that sulfurous pollutants contribute approximately 44%
and nitrate bearing pollutants contribute approximately 21% of the
total light extinction (or visibility impairment) to the Wichita
Mountains, and (2) sources within Oklahoma contribute only
approximately 13% of the total pollutants that contribute to light
extinction.
    ODEQ initially relied on CENRAP modeling, based on an Alpine
Geophysics evaluation of possible additional point-source controls for
CENRAP states for 2018. That study relied on AirControlNet, an EPA
cost-benefit tool for emissions of NOX and SO2.
CENRAP used a maximum estimated cost of $5,000 per ton of emissions of
NOX or SO2 reduced for sources over 100 tons of
SO2 or NOX in the year 2018. CENRAP further
refined the analysis, considering controls only for those sources with
emissions of NOX or SO2 greater than or equal to
five tons per year per kilometer of distance to the Wichita Mountains
or the nearest other Class I area. This analysis resulted in the
conclusion by ODEQ that visibility at the Wichita Mountains would be
improved by an additional 0.5 dv, over what ODEQ projects as its
reasonable progress goal of 21.47 deciview for 2018 if controls were
implemented at the sources that met this combination of baseline
emissions, potential for cost-effective reductions, and visibility
impact.

    Following this analysis, ODEQ examined sources within Oklahoma that
were not already being controlled via BART or consent decrees or other
regulatory mechanisms. See the TSD for a listing of the sources
considered. In so doing, ODEQ analyzed the cost of compliance by
weighing the cost of potential pollution control equipment versus the
visibility benefit. Based on this analysis, ODEQ concluded that no
additional controls were required. ODEQ reasoned that most of the
largest sources of SO2 and NOX were already being
controlled through BART, already had adequate controls in place, or
were too far from the Wichita Mountains (too little visibility impact)
to justify the cost of additional controls.
3. Reasonable Progress Consultation
    ODEQ used CENRAP as its main vehicle for facilitating collaboration
with FLMs and other states in developing its RH SIP. ODEQ 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 the Wichita Mountains.
    ODEQ invited those states projected through visibility modeling to
contribute greater than 1 Mm-1 of light extinction at the
Wichita Mountains in 2018 to consultations. ODEQ conducted four
consultations. ODEQ directed its first consultation, to the tribal
leaders in Oklahoma and their environmental managers, on 14 August
2007. ODEQ held the next three consultations as conference calls and
invited CENRAP member clean air agencies, EPA, and the tribes to
participate.
    ODEQ received responses from the Arkansas Department of
Environmental Quality, the Iowa Department of Natural Resources, and
the Missouri Department of Natural Resources. These states concluded
that emissions from within their borders do not significantly impact
visibility at the Wichita Mountains, and they did not offer any
additional reductions from their anthropogenic sources.
    ODEQ has indicated and we agree that sources in Texas significantly
affect the visibility at the Wichita Mountains. We note ODEQ
communicated this to Texas in the correspondence included in Appendix
10-1, and Texas agreed with that assertion. However, ODEQ did not
request any emission reductions from Texas. As a result of its
correspondence with Texas, Texas agreed to provide ODEQ the opportunity
to comment on Best Available Control Technology determinations for
Prevention of Significant Deterioration sources that have significant
impact on the Wichita Mountains. Specifically, ODEQ will be afforded
the opportunity to review applications for sources if modeling predicts
a five percent or higher impact on light extinction in a given year and
provide comments to Texas during its public review and comment period.
Texas also agreed to notify ODEQ whenever modeling indicates that a
proposed source may significantly impact the Wichita Mountains. ODEQ
also requested that Class I impact reviews be required for all proposed
PSD sources within 300 kilometers of a Class I area. However, this
request was not agreed to by Texas, who cited the need for EPA to adopt
significant impact levels for Class I reviews so that there is a
consistent approach to requiring Class I reviews.
    In establishing its RPG, ODEQ is required by 40 CFR
51.308(d)(1)(i)(B) to consider the emission reduction measures needed
to achieve the URP for the period covered by this SIP. Our 1999 RHR
\18\ further illuminates this requirement:
---------------------------------------------------------------------------

    \18\ 64 FR 35732.

    [T]he State must identify the amount of progress that would result
if this uniform rate of progress were achieved during the period of the
---------------------------------------------------------------------------
first regional haze implementation plan.

    [T]he State must identify and analyze the emissions measures that
would be needed to achieve this amount of progress during the period
covered by the first long-term strategy, and to determine whether those
measures are reasonable based on the statutory factors. These factors
are the costs of compliance with the measures, the time necessary for
compliance with the measures, the energy and nonair quality
environmental impacts of the compliance with the measures, and the
remaining useful life of any existing source subject to the measures.
In doing this analysis, the State must consult with other States which
are anticipated to contribute to visibility impairment in the Class I
area under consideration. Because haze is a regional problem, States
are encouraged to work together to develop acceptable approaches for
addressing visibility problems to which they jointly contribute. If a
contributing State cannot agree with the State establishing the
reasonable progress goal, the State setting the goal must describe the
actions taken to resolve the disagreement.

    As further explained by the RHR,\19\ Oklahoma was under an
additional obligation to consider these controls as part of its
reasonable progress analysis requirement:
---------------------------------------------------------------------------

    \19\ Id.

    If the State determines that the amount of progress identified
through the 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.

    We note that as part of its RH SIP submittal, Texas did consider
the impact its sources have on the visibility of the Wichita Mountains.
Therefore, we believe that to properly assess whether Oklahoma has
satisfied the reasonable progress requirements of section 51.308(d)(1),
we must review and evaluate Texas' submittal. We will do this in the
course of processing the Texas RH SIP.

D. Evaluation of Oklahoma's BART Determinations

    Oklahoma's submitted BART rule, OAC 252:100-8, Part 11, became
effective on June 15, 2007. Definitions related to the BART rule were
added in the Air Quality Rules general definitions section in OAC
252:100-8.1.1, and became effective as a permanent rule on June 15,
2006. These submitted rules also incorporate by reference 40 CFR part
51, appendix Y (our BART Guidelines). The rules further provide that
the resulting source-specific requirements be incorporated into that
source's air quality permit.
    BART is an element of Oklahoma's LTS for the first implementation
period. As discussed in more detail in section IV.D. of this preamble,
the BART evaluation process consists of three components: (1) An
identification of all the BART-eligible sources, (2) an assessment of
whether those BART-eligible sources are in fact subject to BART and (3)
a determination of any BART controls. ODEQ 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. ODEQ identified the
BART-eligible sources in Oklahoma 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) was constructed on or after August
6, 1962, and was in existence prior to August 6, 1977; and (3)
potential emissions of any visibility-impairing pollutant from subject
units are 250 tons or more per year. ODEQ initially screened its
emissions inventory and permitting database to identify major
facilities with emission units in one or more of the 26 BART
categories. Following this, ODEQ used its databases and records to
identify facilities in these source categories with potential emissions
of 250 tons per year or more for any visibility-impairing pollutant
from any unit that was in existence on August 7, 1977 and began
operation after August 7, 1962. ODEQ contacted the sources, when
necessary, to obtain or confirm this information.
    The BART Guidelines direct states to address SO2,
NOX and direct PM (including both PM10 and
PM2.5) emissions as visibility-impairment 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 the Wichita Mountains. Ammonia emissions in
Oklahoma are primarily due to area sources, such as livestock and
fertilizer application. Because these are not point sources, they are
not subject to BART.\20\ ODEQ did consider ammonia from point sources.
The emissions inventory prepared for the CENRAP modeling demonstrates
that ammonia from point sources are not significant visibility-
impairing pollutants in Oklahoma. ODEQ further argued that because of
the limiting role of NOX and SO2 on
PM2.5 formation and the uncertainties in assessing the
effect of an individual source's ammonia emissions reductions on
visibility, it did not consider ammonia among visibility-impairing
pollutants. We have reviewed this information and propose to agree with
this decision.
---------------------------------------------------------------------------

    \20\ ODEQ took the position, and we agree, that it is not
practical at this time to control ammonia from these types of
sources, for the purpose of improving visibility under the
reasonable progress requirements of section 51.308(d)(1).
---------------------------------------------------------------------------

    Table 2 lists Oklahoma's BART-eligible sources:

                            Table 2: Facilities With BART-Eligible Units in Oklahoma
----------------------------------------------------------------------------------------------------------------
                                                                                Number of
          BART source category                  Facility name                   County                 units
----------------------------------------------------------------------------------------------------------------
Fossil fuel-fired boilers of more than   Georgia Pacific Consumer    Muskogee...................               2
 250 MMBTU/hr heat input.                 Products (formerly Fort
                                          James Operating) Muskogee
                                          Mill.
Kraft pulp mill........................  International Paper         McCurtain..................               4
                                          (formerly Weyerhaeuser)
                                          Valliant Paper Mill.
Hydrofluoric, sulfuric, and nitric acid  Koch Nitrogen Enid Plant..  Garfield...................               7
 plants.
                                         Terra International         Woodward...................              11
                                          Oklahoma Woodward Complex.
                                         Terra Nitrogen Partnership  Rogers.....................              12
                                          Verdigris Plant.
Petroleum refineries...................  Sinclair Oil Tulsa          Tulsa......................               7
                                          Refinery.
                                         Holly Refining and          Tulsa......................              25
                                          Marketing (formerly
                                          Sunoco) Tulsa Refinery.
                                         Wynnewood Refining........  Garvin.....................              14
                                         Valero Refinery (formerly   Carter.....................              24
                                          TPI Petroleum Inc)
                                          Ardmore Refinery.
Portland cement plants.................  Lafarge Building Materials  Rogers.....................              10
                                          Tulsa Rogers City Line.
Fossil fuel-fired steam electric plants  OG&E Horseshoe Lake         Oklahoma...................               2
 of more than 250 MMBTU/hr heat input.    Generating Station.
                                         OG&E Muskogee Generating    Muskogee...................               2
                                          Station.
                                         OG&E Seminole Generating    Seminole...................               3
                                          Station.
                                         OG&E Sooner Generating      Noble......................               2
                                          Station.
                                         PSO Comanche Power Station  Comanche...................               2
                                         PSO Northeastern Power      Rogers.....................               3
                                          Station.
                                         PSO Riverside Jenks Power   Tulsa......................               2
                                          Station.
                                         PSO Southwestern Power      Caddo......................               1
                                          Station.
                                         Western Farmers Electric    Caddo......................               3
                                          Coop Anadarko Plant.
                                         Western Farmers Electric    Woodward...................               3
                                          Coop Mooreland Station.
----------------------------------------------------------------------------------------------------------------

2. Identification of Sources Subject to BART
    The second step of the BART evaluation is to identify those BART-
eligible sources that may reasonably be anticipated to cause or
contribute to visibility impairment at any Class I area, i.e. those
sources that are subject to BART. The BART Guidelines allow states to
consider exempting some BART-eligible sources from further BART review
because they may not reasonably be anticipated to cause or contribute
to any visibility impairment in a Class I area. Consistent with the
BART Guidelines, ODEQ 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.
a. Modeling Methodology
    The BART Guidelines provide that states may choose to use the
CALPUFF \21\ 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).
ODEQ, in coordination with CENRAP, used the CALPUFF modeling system to
determine whether individual sources in Oklahoma were subject to or
exempt from BART.
---------------------------------------------------------------------------

    \21\ Note that our reference to CALPUFF encompasses the entire
CALPUFF modeling system, which includes the CALMET, CALPUFF, and
CALPOST models and other pre and post processors. The different
versions of CALPUFF have corresponding versions of CALMET, CALPOST,
etc. which may not be compatible with previous versions (e.g., the
output from a newer version of CALMET may not be compatible with an
older version of CALPUFF). The different versions of the CALPUFF
modeling system are available from the model developer at http://www.src.com/verio/download/download.htm.
---------------------------------------------------------------------------

    The BART Guidelines also recommend that states develop a modeling
protocol for making individual source attributions, and suggest that
states may want to consult with us and their RPO to address any issues
prior to modeling. The CENRAP states, including Oklahoma, developed the
``CENRAP BART Modeling Guidelines''. \22\ Stakeholders, including 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 indicates, therefore sources were
evaluated using the 1st High values instead of the 8th High values. The
use of the 1st High was agreed to by EPA, representatives of the
Federal Land Managers, and CENRAP stakeholders. Some sources that did
not screen out did later conduct refined CALPUFF modeling that
incorporated meteorological data with observations and which allowed to
them to compare 8th High modeling values with the 0.5 deciview
threshold. We propose to find the chosen model and the general modeling
methodology acceptable. However, we note a few additional deviations
from modeling guidance that are discussed in the TSD and addressed in
our remodeling of visibility impacts in support of the FIP for these
six sources.
---------------------------------------------------------------------------

    \22\ CENRAP BART Modeling Guidelines, T. W. Tesche, D. E.
McNally, and G. J. Schewe (Alpine Geophysics LLC), December 15,
2005, available at http://www.deq.state.ok.us/aqdnew/RulesAndPlanning/Regional_Haze/SIP/Appendices/index.htm.
---------------------------------------------------------------------------

b. Contribution Threshold
    For states using modeling to determine the applicability of BART to
single sources, the BART Guidelines note that the first step is to set
a contribution threshold to assess whether the impact of a single
source is sufficient to cause or contribute to visibility impairment at
a Class I area. The BART Guidelines state that, ``[a] single source
that is responsible for a 1.0 deciview change or more should be
considered to `cause' visibility impairment.'' 70 FR 39104, 39161. The
BART Guidelines also state that ``the appropriate threshold for
determining whether a source contributes to visibility impairment' may
reasonably differ across states,'' but, ``[a]s a general matter, any
threshold that you use for determining whether a source `contributes'
to visibility impairment should not be higher than 0.5 deciviews.'' Id.
Further, in setting a contribution threshold, states should ``consider
the number of emissions sources affecting the Class I areas at issue
and the magnitude of the individual sources' impacts. The Guidelines
affirm that states are free to use a lower threshold if they conclude
that the location of a large number of BART-eligible sources in
proximity of a Class I area justifies this approach. ODEQ used a
contribution threshold of 0.5 dv for determining which sources are
subject to BART. There are a limited number of BART-eligible sources in
close proximity to the State's Class I area and surrounding Class I
areas, and the results of the visibility impacts modeling demonstrated
that the majority of the individual BART-eligible sources had
visibility impacts well below 0.5 dv. We agree with the State's
rationale for choosing this threshold value.
c. BART Sources Exempted Due to Permit Modifications
    When performing its initial BART screening modeling, ODEQ
identified three sources with a contribution of greater than 0.5
deciviews in visibility impairment that desired to limit their
emissions in order to avoid a BART determination. These sources were
(1) the Georgia Pacific Consumer Products LP, Muskogee Mill; (2) the
International Paper, Valliant Paper Mill; and (3) the Western Farmers
Electric Coop, Anadarko Plant. An updated BART modeling analysis,
assuming those controls were in place, demonstrated a contribution of
less than 0.5 deciview of visibility impairment for each of these
facilities. They are individually discussed below. ODEQ issued a Title
V operating permit to each of the sources that imposed an emission
limitation requiring the modeled controls. Since these three sources
are voluntarily taking limits to avoid a full BART analysis, any future
changes or relaxation of these limits at these specific BART-eligible
units or in their permits that would allow for increases in
SO2, NOX, or PM emissions would subject those
sources to BART review, pursuant to the submitted ODEQ rules that we
propose to approve as part of the Oklahoma RH SIP.
i. Georgia Pacific Consumer Products LP, Muskogee Mill
    The Georgia Pacific, Muskogee Mill had two BART eligible boilers,
Boiler B-1 and Boiler B-2. Georgia Pacific requested of ODEQ that an
enforceable emission limit be imposed on Boiler B-1 to maintain
emissions below the BART contribution threshold of 0.5 deciviews. Where
previously Boiler B-1 was permitted to burn either No. 2 fuel oil or
natural gas, Boiler B-1 is now restricted to burning natural gas, which
will reduce its NOX emissions. ODEQ has determined that
under the Title V operating permit modification, this facility will
have a visibility impairment contribution of less than 0.5 deciviews at
any Class I area, which is below the contribution threshold used by
ODEQ in their BART analyses. This emission reduction is housed in a
modification to the facility's Oklahoma Department of Environmental
Quality, Air Quality Division operating Permit, No. 99-113-TV (M-5),
issued January 5, 2011. This permit requires that this fuel switch be
operational no more than five years following our final action on the
Oklahoma RH SIP.
ii. International Paper, Valliant Paper Mill
    The International Paper, Valliant Paper Mill has three BART
eligible boilers: EUG D1, Bark Boiler; EUG D2, Power Boiler; and EUG
D3, Package Boiler. It also has a BART eligible Lime Kiln, EUG E7a. The
Valiant Paper Mill has accepted limits on the sulfur content of fuel to
the Bark and Power boilers in order to reduce its visibility impact.
ODEQ has determined that under this Title V operating permit
modification, this facility will have a visibility impairment
contribution of less than 0.5 deciviews at any Class I area, which is
below the contribution threshold used by ODEQ in their BART analyses.
This emission reduction is housed in a modification to the facility's
Oklahoma Department of Environmental Quality, Air Quality Division
operating Permit No. 97-057-TV (M-10), issued March 24, 2010. This
permit requires these controls be operational no more than five years
following our final action on the Oklahoma RH SIP.
iii. Western Farmers Electric Coop, Anadarko Plant
    The Western Farmers Electric Coop (WFEC), Anadarko facility had
three

BART eligible combine cycle gas turbines, AN-Unit 4, AN-Unit 5, and AN-
Unit 6. WFEC agreed to NOX, SO2, and PM-10
emission limits on the combined cycle gas turbines in order to reduce
their visibility impact. ODEQ has determined that under this Title V
operating permit modification, this facility will have a visibility
impairment contribution of less than 0.5 deciviews at any Class I area,
which is below the contribution threshold used by ODEQ in their BART
analyses. This emission reduction is housed in a modification to the
facility's Oklahoma Department of Environmental Quality, Air Quality
Division operating Permit, No. 2005-037-TVR (M-1), issued July 9, 2010.
This permit will require these controls be operational no more than
five years following our final action on the Oklahoma RH SIP.
d. Sources Identified by ODEQ as Subject to BART
    Following the elimination of those sources that were found to have
visibility impacts below the 0.5 deciview threshold, or the three
discussed in the previous section that received Title V permits
limiting their visibility impact below the 0.5 deciview threshold, ODEQ
identified the sources contained in Table 3 as being subject to BART.

                                  Table 3--Sources in Oklahoma Subject to BART
----------------------------------------------------------------------------------------------------------------
           Facility name               BART emission units         Source category         Pollutants evaluated
----------------------------------------------------------------------------------------------------------------
OG&E Seminole......................  Units 1, 2, and 3.....  fossil fuel-fired steam      NOX
                                                              electric plants.
OG&E Sooner........................  Units 1 and 2.........  fossil fuel-fired steam      SO2
                                                              electric plants.            NOX
                                                                                PM10
OG&E Muskogee......................  Units 4 and 5.........  fossil fuel-fired steam      SO2
                                                              electric plants.            NOX
                                                                                PM10
AEP/PSO Comanche...................  Units 1 and 2.........  fossil fuel-fired steam      NOX
                                                              electric plants.
AEP/PSO Northeastern...............  Unit 2................  fossil fuel-fired steam      NOX
                                                              electric plants.
AEP/PSO Northeastern...............  Units 3 and 4.........  fossil fuel-fired steam      SO2
                                                              electric plants.            NOX
                                                                                PM10
AEP/PSO Southwestern...............  Unit 3................  fossil fuel-fired steam      NOX
                                                              electric plants.
----------------------------------------------------------------------------------------------------------------

3. BART Determinations
    The third step of a BART evaluation is to perform the BART
analysis. The BART Guidelines \23\ describe the BART analysis as
consisting of the following five basic steps:
---------------------------------------------------------------------------

    \23\ 70 FR 39164.
---------------------------------------------------------------------------

     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.
    All of the sources that are subject to BART presented in Table 3
are fossil fuel fired electricity generating units. ODEQ performed BART
determinations for all of these sources for NOX,
SO2, and PM. For each BART determination, we find that ODEQ
adequately considered Steps 1 through 5, above, except for the
SO2 BART determinations for Units 4 and 5 of the OG&E
Muskogee plant, Units 1 and 2 of the OG&E Sooner plant, and Units 3 and
4 of the AEP/PSO Northeastern plants. The SO2 BART
determinations for these six units are the subject of our FIP and are
treated separately in Section V.E. of this proposal. We agree with
ODEQ's BART determinations for all remaining cases and summarize them
below. For more details, please see the TSD.
a. OG&E Seminole Units 1, 2, and 3 BART Determinations
    The OG&E Seminole Units 1, 2 and 3 are BART-eligible sources. These
units are gas fired boilers with gross outputs of 567 MW each. ODEQ
considered all NOX control technologies, including
combustion controls such as Low NOX Burners (LNB) and Flue
Gas Recirculation (FGR); and post combustion controls, such as
Selective Catalytic Reduction (SCR), and Selective Noncatalytic
Reduction (SNCR). ODEQ concluded that LNB/OFA +SCR, LNB/OFA +FGR, and
LNB/OFA were technically feasible. ODEQ then evaluated the economic,
environmental, and energy impacts associated with the three proposed
control options. This included CALPUFF visibility modeling, based on a
modeling protocol we find acceptable. ODEQ determined that the
installation of new LNB with OFA and FGR was cost effective, with a
capital cost of $16,977,200 per unit for units 1 and 2 and $9,468,600
for unit 3 and an average cost effectiveness of $1,554-$2,120 per ton
of NOx removed for each unit over a twenty year operational life. ODEQ
determined that NOX BART emission limits should be 30-day
rolling averages of 0.203 lb/MMBtu for Unit 1, 0.212 lb/MMBtu for Unit
2 and 0.164 lb/MMBtu for Unit 3. The BART Guidelines do not specify a
presumptive NOX BART limit for gas fired power plants. As
Units 1, 2, and 3 are gas fired, ODEQ determined that SO2
and PM BART for them are no additional control. We propose to approve
ODEQ's determination of BART for the OG&E Seminole Units 1, 2, and 3.
b. OG&E Sooner Units 1 and 2 BART Determinations
    The OG&E Sooner Units 1 and 2 are BART-eligible sources. Both units
are coal fired with a gross output of 570 MW. We evaluate ODEQ's
SO2 BART determinations for Units 1 and 2 in section V.E.
Here we discuss our review of ODEQ's NOX and PM BART
determination for these units.
    ODEQ considered all NOx control technologies, including combustion
controls such as LNB and FGR; and post combustion controls, such as
SCR, and SNCR. ODEQ concluded that LNB/OFA +SCR, and LNB/OFA were
technically feasible. ODEQ noted that FGR control systems have been
used as a retrofit NOX control strategy on natural gas-fired
boilers, but have not generally been considered as a retrofit control
technology on coal-fired units. ODEQ then evaluated the economic,
environmental, and energy impacts associated with the two proposed
control options. This included CALPUFF visibility modeling, based on a
modeling protocol we find acceptable.

For Units 1 and 2, ODEQ determined the installation of new LNB with OFA
was cost effective, with a capital cost of $14,055,900 per unit for
units 1 and 2 and an average cost effectiveness of $493-785 per ton of
NOX removed for each unit over a twenty-five year
operational life. ODEQ determined that NOX BART emission
limits should be 30-day rolling averages of 0.15 lbs/MMBtu, which meets
the BART presumptive limit.
    For PM, ODEQ noted there are two generally recognized PM control
devices that are used to control PM emission from coal fired boilers,
which are Electrostatic Precipators (ESPs) and fabric filters (or
baghouses). Sooner Units 1 & 2 are currently equipped with ESP control
systems. ODEQ determined that although fabric filters offer a slight
improvement in PM control (99.7 versus 99.3 percent control), their
additional cost did not justify the modest improvement in PM control.
ODEQ determined PM BART is the existing ESPs with an emission rate of
0.1 lbs/MMBtu on a 3-hour average. ODEQ specified additional BART
emission limitations in lbs/hour and tons/year. We propose to approve
ODEQ's PM and NOX BART determinations for the OG&E Sooner
Units 1 and 2.
c. OG&E Muskogee Units 4 and 5 BART Determinations
    The OG&E Muskogee Units 4 and 5 are BART-eligible sources. Both
units are coal fired with a gross output of 572 MW. We evaluate ODEQ's
SO2 BART determinations for Units 4 and 5 in section V.E.
Here we discuss our review of ODEQ's NOX and PM BART
determination for these units.
    ODEQ considered all NOX control technologies, including
combustion controls such as LNB and FGR; and post combustion controls,
such as SCR, and SNCR. ODEQ concluded that LNB/OFA +SCR, and LNB/OFA
were technically feasible. ODEQ noted that FGR control systems have
been used as a retrofit NOX control strategy on natural gas-
fired boilers, but have not generally been considered as a retrofit
control technology on coal-fired units. ODEQ then evaluated the
economic, environmental, and energy impacts associated with the two
proposed control options. This included CALPUFF visibility modeling,
based on a modeling protocol we find acceptable. For Units 4 and 5,
ODEQ determined the installation of new LNB with OFA was cost
effective, with a capital cost of $14,113,700 per unit for units 4 and
5 and an average cost effectiveness of $260-$281 per ton of
NOX removed for each unit over a twenty-five year
operational life. ODEQ determined that NOX BART emission
limits should be 30-day rolling averages of 0.15 lbs/MMBtu, which meets
the BART presumptive limit.
    For PM, ODEQ noted there are two generally recognized PM control
devices that are used to control PM emission from coal fired boilers,
which are Electrostatic Precipators ESPs and fabric filters (or
baghouses). Muskogee Units 4 & 5 are currently equipped with ESP
control systems. ODEQ determined that although fabric filters offer a
slight improvement in PM control (99.7 versus 99.3 percent control),
their additional cost did not justify the modest improvement in PM
control. ODEQ determined PM BART is the existing ESPs with an emission
rate of 0.1 lbs/MMBtu on a 3-hour average. ODEQ specified additional
BART emission limitations in lbs/hour and tons/year. We propose to
approve ODEQ's PM and NOX BART determinations for the OG&E
Muskogee Units 4 and 5.
d. AEP/PSO Comanche Units 1 and 2 BART Determinations
    The AEP/PSO Comanche Units 1 and 2 are BART-eligible sources. These
units are gas fired turbines with duct burners and heat recovery steam
generators with a gross output of 94 MW each.
    For Units 1 and 2, ODEQ considered dry LNBs and SCR as being
possibly applicable to gas fired turbines. ODEQ concluded that due to
specific design considerations, only dry LNBs were technically
feasible. ODEQ then evaluated the economic, environmental, and energy
impacts associated with that proposed control option. This included
CALPUFF visibility modeling, based on a modeling protocol we find
acceptable. ODEQ determined that the installation of dry LNBs was cost
effective, with a capital cost of $34,660,000 an average cost
effectiveness of $2,600 per ton of NOX removed for each unit
over a twenty year operational life. ODEQ determined that
NOX BART emission limits should be 30-day rolling averages
of 0.15 lbs/MMBtu. The BART Guidelines do not specify a presumptive
NOX BART limit for gas fired power plants. As Units 1 and 2
are gas fired, ODEQ determined that SO2 and PM BART for them
are no additional control. We propose to approve ODEQ's determination
of BART for the AEP/PSO Comanche Units 1 and 2.
e. AEP/PSO Northeastern Unit 2, 3, and 4 BART Determination
    The AEP/PSO Northeastern Units 2, 3, and 4 are BART-eligible
sources. Unit 2 is a gas fired boiler with a gross output of 495 MW.
Units 3 and 4 are coal fired with gross outputs of 490 MW each. We
evaluate ODEQ's SO2 BART determinations for Units 3 and 4 in
section V.E. Here we discuss our review of ODEQ's NOX and PM
BART determination for these units.
    For Unit 2, ODEQ considered all NOX control
technologies, including combustion controls such as LNB and FGR; and
post combustion controls, such as SCR, and SNCR. ODEQ concluded that
LNB/OFA +SCR, LNB/OFA +FGR, and LNB/OFA were technically feasible. ODEQ
then evaluated the economic, environmental, and energy impacts
associated with the three proposed control options. This included
CALPUFF visibility modeling, based on a modeling protocol we find
acceptable. ODEQ determined that the installation of new LNB with OFA
was cost effective, with a capital cost of $3,450,000 and an average
cost effectiveness of $303 per ton of NOX removed over a
twenty year operational life. ODEQ determined that NOX BART
emission limits should be 30-day rolling averages of 0.28 lbs/MMBtu.
ODEQ specified additional BART emission limitations in lbs/hour and
tons/year. The BART Guidelines do not specify a presumptive
NOX BART limit for gas fired power plants. As Unit 2 is gas
fired, ODEQ determined that SO2 and PM BART for it are no
additional control. We propose to approve ODEQ's determination of BART
for the AEP/PSO Northeastern Unit 2.
    For Units 3 and 4, ODEQ considered all NOX control
technologies, including combustion controls such as LNB and FGR; and
post combustion controls, such as SCR, and SNCR. ODEQ concluded that
LNB/OFA +SCR, LNB/OFA, were technically feasible. ODEQ noted
difficulties posed by the installation of SNCR on Units 3 and 4 but did
evaluate SNCR. ODEQ noted that FGR control systems have been used as a
retrofit NOX control strategy on natural gas-fired boilers,
but have not generally been considered as a retrofit control technology
on coal-fired units. ODEQ then evaluated the economic, environmental,
and energy impacts associated with the two proposed control options.
This included CALPUFF visibility modeling, based on a modeling protocol
we find acceptable. For Units 3 and 4, ODEQ determined the installation
of new LNB with OFA was cost effective, with a capital cost of
$17,000,000 and an average cost effectiveness of $313 per ton of
NOX removed over a twenty-five year operational life. ODEQ
determined that NOX BART emission limits should be 30-day
rolling averages of 0.15 lbs/

MMBtu, which meets the BART presumptive limit.
    For PM, ODEQ noted there are two generally recognized PM control
devices that are used to control PM emission from coal fired boilers,
which are ESPs and fabric filters (or baghouses). Northeastern Units 3
& 4 are currently equipped with ESP control systems. ODEQ determined
that although fabric filters offer a slight improvement in PM control
(99.7 versus 99.3 percent control), their additional cost did not
justify the modest improvement in PM control. ODEQ determined PM BART
is the existing ESPs with an emission rate of 0.1 lbs/MMBtu on a 3-hour
average. ODEQ specified additional BART emission limitations in lbs/
hour and tons/year. We propose to approve ODEQ's determination of BART
for the AEP/PSO Northeastern Units 3 and 4.
f. AEP/PSO Southwestern Unit 3 BART Determination
    The AEP/PSO Southwestern Unit 3 is a BART-eligible source. This
unit is a gas fired boiler with a gross output of 332 MW. ODEQ
considered all NOX control technologies, including
combustion controls such as LNB and FGR; and post combustion controls,
such as SCR, and SNCR. ODEQ concluded that LNB/OFA +SCR, and LNB/OFA
were technically feasible. ODEQ then evaluated the economic,
environmental, and energy impacts associated with the three proposed
control options. This included CALPUFF visibility modeling, based on a
modeling protocol we find acceptable. ODEQ determined that the
installation of new LNB with OFA was cost effective, with a capital
cost of $3,000,000 and an average cost effectiveness of $947 per ton of
NOX removed over a twenty-year operational life. ODEQ
determined that NOX BART emission limits should be 30-day
rolling averages of 0.45 lbs/MMBtu on a 30-day average. ODEQ specified
additional BART emission limitations in lbs/hour and tons/year.
    The BART Guidelines do not specify a presumptive NOX
BART limit for gas fired power plants. However, due to the relatively
high NOX emission rate that ODEQ determined was BART, and
the fact that it appeared the annual average emissions rates recorded
with the Clean Air Markets Division indicates that the boiler can
currently comply with the standard on an annual average basis, we asked
for additional information. ODEQ responded with data detailing 9 years
of emissions versus load, that indicate that the boiler operates
through a range where emissions can reach as much as 1.4 lb/MMBtu at
full load. This unit has historically operated as a ``peaking unit''
responding to increased demand for electricity. While technically
feasible, LNB/OFA may not be as effective under all boiler operating
conditions, especially during load changes and at low and high
operating loads. After having examined the data, attached in our TSD,
we accept ODEQ's explanation. As Unit 3 is gas fired, ODEQ determined
that SO2 and PM BART for it are no additional control. We
propose to approve ODEQ's determination of BART for the AEP/PSO
Southwestern Unit 3.
g. ODEQ BART Results and Summary
    We have reviewed ODEQ's BART determinations for the sources listed
in Table 3, above. We note that these BART determinations result in
significant reductions in the amount of NOX that will be
emitted by these sources, totaling 27,043 tons per year. This results
in significant visibility benefits at the Wichita Mountains, Caney
Creek, Upper Buffalo, and Hercules Glades Class I areas. Calculated as
the 3-year average of the modeled visibility improvement at the 98th
percentile, these NOX BART reductions result in a visibility
improvement of 5.46 dv at the Wichita Mountains, 2.65 deciviews at
Caney Creek, 1.79 dv at the Upper Buffalo, and 1.37 dv at Hercules
Glades. This results in an 11.27 dv improvement over all these Class I
areas. See the TSD for more details.
    Oklahoma's BART rule requires each source subject to BART to
install and operate BART no later than 5 years after we approve this RH
SIP. OAC 252-100-8-75(e). Therefore, we believe this satisfies ODEQ's
obligation under section 51.308(e)(1)(iv), that ``each source subject
to BART be required to install and operate BART as expeditiously as
practicable, but in no event later than 5 years after approval of the
implementation plan revision.''
    For the reasons discussed above, we propose to find that with the
exception of the SO2 BART determinations for Units 4 and 5
of the OG&E Muskogee plant, Units 1 and 2 of the OG&E Sooner plant, and
Units 3 and 4 of the AEP/PSO Northeastern plants, ODEQ has satisfied
the BART requirement of section 51.308(e).

E. Evaluation of ODEQ's SO2 BART Determinations for the OG&E
and AEP/PSO Coal Fired Power Plant Units

    The discussion below is limited to the SO2 BART
assessments for Units 4 and 5 of the Oklahoma Gas and Electric Muskogee
plant, Units 1 and 2 of the Oklahoma Gas and Electric Sooner plant (the
``OG&E units''), and Units 3 and 4 of the American Electric Power/
Public Service Company of Oklahoma Northeastern plant (the ``AEP/PSO
units''). ODEQ's other BART assessments are covered in Section V.D.,
above.
    In the Oklahoma RH SIP submittal, ODEQ concluded that dry flue gas
desulfurization with spray dryer absorbers (``dry scrubbers'') and wet
flue gas desulfurization (``wet scrubbers'') were not cost effective
for these units. ODEQ came to this decision after comparing the cost
effectiveness in annualized dollars per ton of SO2 removed
($/ton) to the visibility improvement at the nearest Class I areas.
ODEQ determined that SO2 BART for these units was no control
and specified an SO2 limit of 0.65 lbs/MMBtu on a 30-day
rolling average. The OG&E units currently burn a low sulfur coal from
the Powder River Basin (PRB) of Wyoming, and already have historical
annual emission rates significantly below this limit. Therefore, it is
possible the OG&E units would be able to actually increase their
emissions slightly, and still be in compliance with ODEQ's
SO2 BART assessment. The AEP/PSO units have historical
annual emission rates that have been steadily decreasing to a point
where the imposition of ODEQ's proposed BART SO2 emission
rate of 0.65 lbs/MMBtu would result in very little reduction in
emissions. Below we discuss ODEQ's BART evaluation and our assessment
of that evaluation.
1. Cost Effectiveness
    We propose to find that ODEQ properly identified these sources as
BART eligible, in compliance with section 51.308(e)(1)(i). However, we
propose to find that ODEQ did not properly follow the requirements of
section 51.308(e)(1)(ii)(A) in determining BART. Specifically, we
propose that ODEQ did not properly ``take into consideration the costs
of compliance'' when it relied on cost estimates that greatly
overestimated the costs of dry and wet scrubbing to conclude these
controls were not cost effective. Given that scrubbers are typically
considered to be highly cost-effective controls for power plants such
as those at issue, we retained a consultant to independently assess the
suitability and costs of installing these controls. We have thoroughly
reviewed and evaluated the consultant's report and agree with its
findings regarding the cost-effectiveness of dry and wet scrubbing at
the BART units. Our

consultant's detailed report has been incorporated into the TSD.\24\
---------------------------------------------------------------------------

    \24\ Dr. Phyllis Fox, Revised BART Cost-Effectiveness Analysis
for Flue Gas Desulfurization at Coal-Fired Electric Generating Units
in Oklahoma: Sooner Units 1 & 2 Muskogee Units 4 & 5 Northeastern
Units 3 & 4. Report Prepared for U.S. EPA, RTI Project Number
0209897.004.085.
---------------------------------------------------------------------------

a. Dry Scrubbing Cost Analyses
    Table 4, below, summarizes and contrasts the cost effectiveness of
dry scrubbers estimated by ODEQ \25\ versus our estimate. Both ODEQ and
we used BART evaluations performed by OG&E and AEP/PSO as the starting
points for the assessments.\26\
---------------------------------------------------------------------------

    \25\ ODEQ BART analyses housed in Appendix 6-4 of the OK RH SIP.
    \26\ Sargent & Lundy, Sooner Units 1 & 2, Muskogee Units 4 & 5
Dry FGD BART Analysis Follow-Up Report, Prepared for Oklahoma Gas &
Electric, December 28, 2009.
     Trinity Consultants, Best Available Retrofit Technology (BART)
Determination, American Electric Power, Northeastern Power Plant,
May 30, 2008.

                              Table 4--Contrast of Dry Scrubber Cost Effectiveness
----------------------------------------------------------------------------------------------------------------
                                                                ODEQ projected cost ($/  EPA's projected cost ($/
                             Plant                                  ton SO2 removed)         ton SO2 removed)
----------------------------------------------------------------------------------------------------------------
Sooner 1......................................................                   $6,348                   $1,291
Sooner 2......................................................                    7,147                    1,291
Muskogee 4....................................................                    7,378                    1,317
Muskogee 5....................................................                    7,493                    1,317
Northeastern 3................................................                    3,294                    1,544
Northeastern 4................................................                    3,294                    1,544
----------------------------------------------------------------------------------------------------------------

    Although our TSD provides a detailed comparison between the costing
methodologies, a few general points can be made that explain why our
costs differ with those from ODEQ. First, in the case of the OG&E
analyses, a coal with a significantly higher sulfur content than is
currently burned was assumed by OG&E's contractor in determining the
design of the scrubber. This increased the capital cost of the scrubber
over what would minimally be needed to scrub the coal currently being
burned. However, the increased tonnage of SO2 that would
have been removed from the emissions resulting from the burning of that
coal, and the high efficiency of the scrubber was not used in
calculating the cost effectiveness ($/ton). Our cost analysis, assumed
the same higher sulfur coal, but adjusted the cost effectiveness to
account for the increased scrubber efficiency and the increased tonnage
of sulfur that would be removed. Second, the companies did not follow
the Air Pollution Control Cost Manual \27\ when possible, as specified
in the BART guidelines.\28\ Our cost analysis does follow the Air
Pollution Control Cost Manual. Third, some costs were significantly
outside of the range of the actual costs. In our analysis these costs
are adjusted accordingly. Fourth, the cost estimates contained double
counting. In our analysis, the double counted costs are removed.
Lastly, the cost estimates failed to evaluate the most cost effective
options. Our analysis accounts for the more cost effective options and
is referred to as ``Option 1'' in our consultant's report.
---------------------------------------------------------------------------

    \27\ U.S. EPA, EPA Air Pollution Control Cost Manual, EPA/452/B-
02-001, 6th Ed., January 2002. The EPA Air Pollution Control Cost
Manual was formerly known as the OAQPS Control Cost Manual.
    \28\ As stated in the BART guidelines, ``[i]n order to maintain
and improve consistency, cost estimates should be based on the OAQPS
Control Cost Manual, where possible.'' 70 FR 39104, 39166.
---------------------------------------------------------------------------

    However, even though it appeared that costing the larger scrubber
was OG&E's preferred option, we did not wish to propose our decision
solely on that basis. We also considered whether it would be cost
effective to scrub the type of coal currently burned at the units.
Therefore, we also analyzed the cost of a dry scrubber for the OG&E
units, assuming the scrubber would be sized to scrub the coal being
currently burned. This approach, referred to as ``Option 2'' in our
consultant's report, is summarized in Table 5, below. The estimates in
Table 5 are not refined estimates and did not consider all of the
issues considered in option 1.

 Table 5--Unrefined Minimally-Sized OG&E Dry Scrubber Cost Effectiveness
------------------------------------------------------------------------
                                                        EPA's Projected
                                                        Cost (Unrefined)
                        Plant                              ($/ton SO2
                                                            removed)
------------------------------------------------------------------------
Sooner 1.............................................             $4,594
Sooner 2.............................................              4,594
Muskogee 4...........................................              5,102
Muskogee 5...........................................              5,102
------------------------------------------------------------------------

    We further refined the cost of the smaller scrubber to account for
the issues discussed above that were rectified in Option 1: not
following the Air Pollution Control Cost Manual, adjusting costs that
were outside of the range of the actual costs, eliminating double
counted costs, and failing to evaluate the most cost effective options.
Additional details concerning this refinement are covered in our TSD.

  Table 6--Refined Minimally-Sized OG&E Dry Scrubber Cost Effectiveness
------------------------------------------------------------------------
                                                        EPA's Projected
                        Plant                          Cost (Refined) ($/
                                                       ton SO2  removed)
------------------------------------------------------------------------
Sooner 1.............................................             $2,048
Sooner 2.............................................              2,048
Muskogee 4...........................................              2,366
Muskogee 5...........................................              2,366
------------------------------------------------------------------------

    In contrasting the results displayed in Tables 4 and 6, we conclude
that based on a controlled emission limit of 0.06 lbs/MMBtu, a dry
scrubber is cost effective at Units 4 and 5 of the OG&E Muskogee plant,
Units 1 and 2 of the OG&E Sooner plant, and Units 3 and 4 of the AEP/
PSO Northeastern plant. In OG&E's case, this is true regardless of
whether the scrubber is sized to control the coal presently burned, or
a significantly dirtier coal. Therefore, we propose to find that we
cannot accept the cost estimates for dry scrubbers provided in the
Oklahoma RH submission.
b. Wet Scrubbing Cost Analyses
    Table 7, below summarizes and contrasts the cost effectiveness of
wet scrubbers estimated by ODEQ versus our estimates:

                              Table 7--Contrast of Wet Scrubber Cost Effectiveness
----------------------------------------------------------------------------------------------------------------
                                                                ODEQ projected cost ($/  EPA's projected cost ($/
                             Plant                                  ton SO2 removed)         ton SO2 removed)
----------------------------------------------------------------------------------------------------------------
Sooner 1......................................................                   $6,998                   $1,555
Sooner 2......................................................                    7,827                    1,555
Muskogee 4....................................................                    8,724                    1,417
Muskogee 5....................................................                    8,852                    1,417
Northeastern 3................................................                    3,625                    1,699
Northeastern 4................................................                    3,625                    1,699
----------------------------------------------------------------------------------------------------------------

    The ODEQ's BART analyses eliminated wet scrubbing, in part, because
the dollars per ton cost effectiveness was calculated to be higher than
for dry scrubbing; the incremental cost to go from dry to wet scrubbing
was judged unacceptable; and wet scrubbing was alleged to have certain
adverse impacts that dry scrubbing did not have. ODEQ determined that
wet scrubbing was not BART for SO2 for any of the subject
units. This determination was based in part, on several alleged adverse
collateral impacts including: (1) Increased sulfuric acid mist (SAM) in
the flue gas; (2) excess particulate emitted due to the location of a
scrubber downstream of the particulate control device; (3) the need for
more reactant, which would generate more fugitive dust; (4) the need
for significantly more water; (5) the generation of a wastewater stream
that must be treated; and (6) the creation of a higher visibility
impairment due to lower exit velocity, lower stack temperature, and