```

[Federal Register Volume 76, Number 55 (Tuesday, March 22, 2011)]
[Proposed Rules]
[Pages 16168-16197]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2011-5799]

[[Page 16167]]

Vol. 76

Tuesday,

No. 55

March 22, 2011

Part III

Environmental Protection Agency

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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

[[Page 16168]]

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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.

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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: r6air_okhaze@epa.gov.
     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 214-665-7263.
    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

[[Page 16169]]

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 214-665-7253 to make an 
appointment. If possible, please make the appointment at least two 
working days in advance of your visit. There will be a 15 cent per page 
fee for making photocopies of documents. On the day of the visit, 
please check in at 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 214-665-7186, e-mail address r6air_okhaze@epa.gov.

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.
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    \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.

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[[Page 16170]]

    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

[[Page 16171]]

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.
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    \2\ Visual range is the greatest distance, in kilometers or 
miles, at which a dark object can be viewed against the sky.
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    In section 169A of the 1977 Amendments to the CAA, Congress created 
a program for protecting visibility in the nation's national parks and 
wilderness areas. This section of the CAA establishes as a national 
goal the ``prevention of any future, and the remedying of any existing, 
impairment of visibility in mandatory Class I Federal areas \3\ which 
impairment results from 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.
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    \3\ Areas designated as mandatory Class I Federal areas consist 
of national parks exceeding 6000 acres, wilderness areas and 
national memorial parks exceeding 5000 acres, and all international 
parks that were in existence on August 7, 1977. See CAA section 
162(a). In accordance with section 169A of the CAA, EPA, in 
consultation with the Department of Interior, promulgated a list of 
156 areas where visibility is identified as an important value. See 
44 FR 69122, November 30, 1979. The extent of a mandatory Class I 
area includes subsequent changes in boundaries, such as park 
expansions. CAA section 162(a). Although states and tribes may 
designate as Class I additional areas which they consider to have 
visibility as an important value, the requirements of the visibility 
program set forth in section 169A of the CAA apply only to 
``mandatory Class I Federal areas.'' Each mandatory Class I Federal 
area is the responsibility of a ``Federal Land Manager'' (FLM). See 
CAA section 302(i). When we use the term ``Class I area'' in this 
action, we mean a ``mandatory Class I Federal area.''
---------------------------------------------------------------------------

    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).
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    \4\ Albuquerque/Bernalillo County in New Mexico must also submit 
a regional haze SIP to completely satisfy the requirements of 
section 110(a)(2)(D) of the CAA for the entire State of New Mexico 
under the New Mexico Air Quality Control Act (section 74-2-4).
---------------------------------------------------------------------------

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

[[Page 16172]]

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

    The deciview is used in expressing Reasonable Progress Goals (RPGs) 
(which are interim visibility goals towards meeting the national 
visibility goal), defining baseline, current, and natural conditions, 
and tracking changes in visibility. The RH SIPs must contain measures 
that ensure ``reasonable progress'' toward the national goal of 
preventing and remedying visibility impairment in Class I areas caused 
by 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\
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    \6\ Guidance for Estimating Natural Visibility Conditions Under 
the Regional Haze Rule, September 2003, EPA-454/B-03-005, available 
at http://www.epa.gov/ttncaaa1/t1/memoranda/rh_envcurhr_gd.pdf 
(hereinafter referred to as ``our 2003 Natural Visibility 
Guidance''); and Guidance for Tracking Progress Under the Regional 
Haze Rule, EPA-454/B-03-004, September 2003, available at http://www.epa.gov/ttncaaa1/t1/memoranda/rh_tpurhr_gd.pdf (hereinafter 
referred to as our ``2003 Tracking Progress Guidance'').
---------------------------------------------------------------------------

    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;

[[Page 16173]]

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

[[Page 16174]]

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.

[[Page 16175]]

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.
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    \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

[[Page 16176]]

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.

[[Page 16177]]

    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

[[Page 16178]]

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,

[[Page 16179]]

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

[[Page 16180]]

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.

[[Page 16181]]

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/

[[Page 16182]]

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

[[Page 16183]]

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:

[[Page 16184]]

                              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 
higher SAM emissions. We have determined these claims are either wrong 
or overstated. Furthermore, we noted several benefits of wet scrubbing 
and some drawbacks to dry scrubbing, which were not evaluated by ODEQ. 
These issues are detailed in our consultant's report. Please see the 
TSD for further discussion of our evaluation of ODEQ's determination 
that wet scrubbing was not BART for SO2.
    Although OG&E's contractor did not evaluate wet scrubbing in its 
final updated BART analyses, ODEQ modified an earlier OG&E wet scrubber 
cost estimate as the basis for estimating the cost of wet scrubbing. 
The total capital requirement for wet scrubbers was carried forward 
from the previous cost estimate. ODEQ then modified other costing 
parameters to be consistent with OG&E's contractor's current dry 
scrubber cost estimate. These modifications included the capital 
recovery factor, the annual operating costs, and administrative costs. 
AEP/PSO's contractor did provide a wet scrubber cost analysis as part 
of its BART analyses, which was incorporated into ODEQ's BART analysis. 
However, ODEQ's wet scrubber BART analyses for the OG&E and AEP/PSO 
plants did not include the kind of detailed, line-by-line cost 
breakdown that is needed for a proper evaluation.
    We approached this problem by comparing the cost of wet to dry 
scrubbing for 13 cost effectiveness analyses (including the earlier 
OG&E analyses and the AEP/PSO analyses). The results of this analysis 
indicated that the average calculated cost effectiveness of a wet 
scrubber is typically about 9% higher than for a dry scrubber, except 
in those cases where an existing ESP can substitute for a new baghouse. 
Although that specific option was not evaluated or assumed in our cost 
analyses, we note that the OG&E and AEP/PSO units in question all have 
existing ESPs, and we expect they could be retained to reduce the cost. 
After increasing the cost of our calculated dry scrubbing estimate by 
9%, we propose to find that the cost of wet scrubbing for the OG&E and 
AEP units fall within the range of values found to be cost effective in 
other similar wet scrubber cost determinations. As we stated in the 
BART Rule, ``[a] reasonable range would be a range that is consistent 
with the range of cost effectiveness values used in other similar 
permit decisions over a period of time.'' 70 FR 39104, 39168. Dry 
scrubbers are being successfully applied to many kinds of stationary 
sources worldwide, including many similar applications in the utility 
industry.\29\ As explained in the preamble to the BART Guidelines in 
explaining the decision to establish presumptive BART limits for 
SO2 based on the use of scrubbers, both wet and dry 
scrubbers are highly cost effective for power plants, with costs of 
$400 to $2000 per ton of SO2 removed typically. 70 FR at 
39132. Thus, dry scrubbing is clearly cost effective, barring an 
unusual, site specific condition. However, neither OG&E nor AEP/PSO 
identified any such conditions. Similarly, wet scrubbing has been 
employed in many coal fired power plants in the United States, and is 
in fact more widely used than dry scrubbing. This includes the Pleasant 
Prairie Units 1 and 2 in Wisconsin, which are similar to the OG&E and 
AEP/PSO units in question.\30\ Therefore, because our cost 
effectiveness calculations for the BART units fall within the range for 
other similar scrubber installations, we propose to find that both dry 
and wet scrubbing are cost effective in terms of dollars per tons of 
SO2 removed. Consequently, we propose to disapprove ODEQ's 
evaluation of the cost effectiveness of control.
---------------------------------------------------------------------------

    \29\ Electric Power Research Institute (EPRI), A Review of 
Literature Related to the Use of Spray Dryer Absorber Material: 
Production, Characterization, Utilization Applications, Barriers, 
and Recommendations, December 6, 2006, Table 1-2.
    \30\ These units are 620 MW pulverized coal fired boilers that 
burn similar low sulfur PRB coal (0.5-0.7 lb/MMBtu) that were placed 
into service in 1980 and 1985, respectively. They were retrofitted 
with wet scrubbers in 2006 and 2007, respectively.
---------------------------------------------------------------------------

2. Visibility Benefit
    Having considered the cost effectiveness of wet and dry scrubbers 
for OG&E and AEP/PSO, we then considered the visibility improvement 
that would result from the installation of controls. As was done in 
assessing costs, OG&E and AEP assessed visibility on a facility basis. 
ODEQ \31\ used the CALPUFF modeling system, which consists of a 
meteorological data pre-processor (CALMET), an air dispersion model 
(CALPUFF), and post-processor programs (POSTUTIL, CALSUM, CALPOST). The 
CALPUFF modeling system is the recommended model for conducting BART 
visibility analysis. The modeling analysis generally followed the BART 
protocol developed by CENRAP.\32\ In ODEQ's modeling approach, CALPUFF 
visibility modeling for each pollutant was carried out separately so 
that only NOX emissions were modeled in support of the 
NOX

[[Page 16185]]

BART determination or only SO2/H2SO4 
emissions for SO2 BART determinations. Due to the nonlinear 
nature and complexity of atmospheric chemistry and chemical 
transformation among pollutants, CALPUFF modeling on a pollutant-
specific basis is not recommended.\33\ Furthermore, this approach does 
not allow for predictions of total visibility impairment for different 
control scenarios at Class I area receptors and the determination of 
the 98th percentile day for visibility impairment. In the case of 
NOX BART determinations for gas-fired units performed by 
ODEQ, modeling results from this approach are informative because 
SO2 and PM emissions are minimal.
---------------------------------------------------------------------------

    \31\ Throughout this document, any reference to ``ODEQ 
modeling'' refers to modeling performed or reviewed by ODEQ.
    \32\ 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).
    \33\ Memo from Joseph Paisie (Geographic Strategies Group, 
OAQPS) to Kay Prince (Branch Chief EPA Region 4) on Regional Haze 
Regulations and Guidelines for Best Available Retrofit Technology 
(BART) Determinations, July 19, 2006.
---------------------------------------------------------------------------

    Although we generally regard the visibility modeling analyses 
performed by ODEQ in support of BART determinations to be of high 
quality, some deviations from our guidance and errors in emission 
calculations were noted. We performed our own modeling analysis of the 
three facilities, incorporating changes to meet our guidance and 
correct errors in emission calculations. We note that refined CALPUFF 
modeling included in ODEQ's SIP used updated meteorological fields that 
included observations in accordance with EPA guidance (40 CFR Part 51, 
Appendix W) and we utilized this data in our own modeling analysis. In 
the ODEQ modeling, sulfuric acid emissions from the OG&E units were 
estimated based on an assumed 1% SO2 to SO3 
conversion rate across the boiler. A control efficiency of 40% was 
assumed for the wet scrubbing control scenario and 90% for the dry 
scrubbing scenario. Emissions from the AEP/PSO units were calculated 
based on an assumed 3 ppm sulfur content conversion in the flue gas. As 
detailed in the TSD, we utilized a different approach based on the best 
current information from the Electric Power Research Institute (EPRI) 
\34\ to estimate the sulfuric acid released from combustion in the 
boiler. ODEQ's speciation of PM emissions, estimated for use in PM only 
modeling, contained errors in the parameters used in the calculation of 
speciation factors. As discussed in the above sections, we concluded 
that the dry scrubber and the wet scrubber could achieve emission 
limits of 0.06 lb/MMbtu SO2 and 0.04 lb/MMbtu 
SO2, respectively, and these limits were used to calculate 
emissions for our visibility modeling. Our emission estimation 
methodology is detailed in the TSD.
---------------------------------------------------------------------------

    \34\ Electric Power Research Institute, Estimating Total 
Sulfuric Acid Emissions from Stationary Power Plants, 1016384, 
technical Update, March 2008.
---------------------------------------------------------------------------

    We remodeled the visibility impacts of the OG&E and AEP/PSO units 
to correct these errors and to provide consistency with modeling 
guidance we have provided to the states. First, the model was run using 
the pre-BART conditions to establish a baseline. For all modeling runs, 
all relevant visibility-impairing pollutants were included. The model 
was then run to include the control technology selected as 
NOX BART, LNB with OFA, in order to evaluate the visibility 
benefit expected from this control and separate the benefit of 
installation of NOX BART from that due to SO2 
control technologies. Modeling results of the visibility impact due to 
installation of LNB show significant improvement in visibility over the 
baseline. These results in combination with review of the cost analysis 
and other factors considered in the ODEQ BART determination support the 
conclusion that LNB with OFA is NOX BART for these units. To 
evaluate the anticipated visibility improvement due to wet and dry 
scrubbers, these control technologies were modeled for each facility. 
These modeling control scenarios with scrubbers for SO2 also 
included NOX emissions controlled by LNB with OFA. The 
modeled visibility impacts were then compared to the impact achieved 
with only LNB with OFA and no additional controls on SO2 to 
evaluate the incremental visibility benefit of each SO2 
control technology (wet or dry scrubber).
    The results of our visibility modeling analyses, for the maximum 
impacts of the 98th percentile delta-dv impacts from 2001-2003 are 
presented as Table 8. These results employ our revised emission 
calculations and methodology, and the new IMPROVE equation (Method 8). 
As can be seen from these results, despite employing an SO2 
emission limit of 0.04 lbs/MMBtu in the wet scrubber case (versus 0.06 
lbs/MMBtu in the dry scrubber case), the visibility modeling does not 
show a consistent, clear benefit for wet scrubbing. A possible 
explanation for this is that by reducing the SO2 emissions 
to the rate of 0.06 lb/MMbtu, the 98th percentile days are primarily 
winter days when nitrate particulates are responsible for the majority 
of visibility impairment. Additional controls of SO2 do not 
yield a reduction in sulfate large enough to provide significant 
visibility improvement for the 98th percentile value. In some cases, 
the further reduction in sulfate on these days results in a small 
increase in available ammonia for reaction with NOX and 
leads to a slight increase in visibility impairment due to additional 
nitrate particulate that can offset the benefit due to less sulfate 
particulate.

                               Table 8--EPA Modeled Maximum Impacts of the 98th Percentile Delta-dv Impacts From 2001-2003
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                          Visibility impact ([Delta] dv)                    Improvement     Improvement     Improvement
              Class I area               ----------------------------------------------------------------  over baseline   over LNB due    over LNB due
                                             Baseline           LNB         LNB & DFGD      LNB & WFGD      due to LNB        to DFGD         to WFGD
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                    Sooner Units 1&2
--------------------------------------------------------------------------------------------------------------------------------------------------------
Caney Creek.............................            0.73            0.50            0.13            0.13            0.23            0.37            0.38
Hercules-Glades.........................            0.71            0.43            0.13            0.12            0.28            0.30            0.31
Upper Buffalo...........................            0.77            0.49            0.13            0.12            0.28            0.35            0.37
Wichita Mountains.......................            2.08            1.46            0.41            0.35            0.62            1.05            1.11
                                         ---------------------------------------------------------------------------------------------------------------
    Total...............................            4.28            2.88            0.80            0.71            1.41            2.08            2.16
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                   Muskogee Units 4&5
--------------------------------------------------------------------------------------------------------------------------------------------------------
Caney Creek.............................            1.48            1.19            0.45            0.51            0.29            0.74            0.69
Hercules-Glades.........................            1.07            0.92            0.19            0.19            0.14            0.74            0.73

[[Page 16186]]

 
Upper Buffalo...........................            1.52            1.20            0.37            0.33            0.31            0.84            0.87
Wichita Mountains.......................            1.31            1.03            0.29            0.34            0.27            0.75            0.70
                                         ---------------------------------------------------------------------------------------------------------------
    Total...............................            5.37            4.35            1.29            1.37            1.02            3.06            2.98
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                 Northeastern Units 3&4
--------------------------------------------------------------------------------------------------------------------------------------------------------
Caney Creek.............................            1.70            0.99            0.29            0.30            0.71            0.70            0.69
Hercules-Glades.........................            0.92            0.88            0.18            0.20            0.04            0.70            0.68
Upper Buffalo...........................            1.52            0.85            0.28            0.28            0.67            0.57            0.57
Wichita Mountains.......................            1.66            1.39            0.30            0.31            0.27            1.09            1.08
                                         ---------------------------------------------------------------------------------------------------------------
    Total...............................            5.80            4.11            1.05            1.09            1.69            3.06            3.02
--------------------------------------------------------------------------------------------------------------------------------------------------------

    In Table 9, we extract the results of our visibility modeling from 
Table 8 for the dry scrubbing case, and total the results across the 
OG&E and AEP/PSO facilities, and across Class I areas. This is again 
based on the maximum impacts 98th Percentile delta-dv impacts from 
2001-2003.

Table 9--EPA Modeled Maximum Impacts Due to Dry Scrubbing of the 98th Percentile Delta-dv Impacts From 2001-2003
----------------------------------------------------------------------------------------------------------------
                                                          Improvement over LNB + OFA due to dry scrubbing
                                                 ---------------------------------------------------------------
                  Class I area                                                                     Total Sooner
                                                      Sooner         Muskogee      Northeastern      Muskogee
                                                                                                   Northeastern
----------------------------------------------------------------------------------------------------------------
Caney Creek.....................................            0.37            0.74            0.70            1.81
Hercules-Glades.................................            0.30            0.74            0.70            1.74
Upper Buffalo...................................            0.35            0.84            0.57            1.76
Wichita Mountains...............................            1.05            0.75            1.09            2.89
                                                 ---------------------------------------------------------------
    Total All Class I Areas.....................            2.07            3.07            3.06            8.20
----------------------------------------------------------------------------------------------------------------

    The visibility improvements documented in Table 9 are significant 
and will result in marked steps toward reaching natural background 
conditions.
3. Our Conclusion on Oklahoma's SO2 BART Evaluations for the 
Six OG&E and AEP/PSO Units
    As discussed above, ODEQ concludes that it is too expensive to 
control the SO2 emissions from the OG&E and AEP/PSO units in 
question and that the potential visibility benefits are not substantial 
enough to justify additional control. As we have shown above, we 
disagree with ODEQ's conclusion on costs for SO2 controls 
and we find that cost effective SO2 controls are available 
and our modeling demonstrates that substantial visibility improvement 
is achievable based on the installation of these controls. In 
particular, our modeling indicates that dry scrubbing will result in a 
2.89 deciview improvement in visibility at the Wichita Mountains. 
Furthermore, the addition of SO2 scrubbers (wet or dry) on 
each of the three facilities (2 units at each facility) will reduce 
visibility impairment at Class I areas (Wichita Mountains and/or other 
surrounding Class I areas) from values that are above the 1 deciview 
impact that is a direct causation of visibility impairment to levels 
that are below the 0.5 deciview threshold that ODEQ used for 
determining if a source contributed to visibility impairment. We 
consider the reduction in visibility impairment at Wichita Mountains, 
Caney Creek, Upper Buffalo, and Hercules-Glades to be significant both 
for the RH SIP and also for reduction of visibility impairment on other 
states in meeting the requirements of the 110 (a)(2)(D) SIP. Therefore, 
we propose to disapprove Oklahoma's submitted SO2 BART 
determinations for the six BART sources in question. Consequently, we 
propose a FIP to address this deficiency.
4. Alternative BART Determination
    The RH submittal includes an alternative to BART for the six BART 
sources entitled ``Greater Reasonable Progress Alternative 
Determination'' (Alternative Determination). This Alternative 
Determination submittal includes 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.'' 
The submitted Alternative Determination provides for alternative 
control scenarios that would apply were we to disapprove ODEQ's 
SO2 BART determinations for the OG&E and AEP/PSO units. 
Under the Alternative Determination, following the exhaustion of all 
administrative and judicial appeals of disapproval by us of the BART 
determinations for the six units, the BART determination would be 
superseded by a requirement that the OG&E and AEP/PSO units comply with 
either of the following requirements:

    By January 1, 2018, install dry scrubbers (and fabric filters 
for PM control at the OG&E units) or otherwise meet SO2 
and PM emission limits specified by ODEQ.\35\
---------------------------------------------------------------------------

    \35\ These emission limits are a 30-day rolling average 
SO2 emission limit of 0.10 lbs/MMBtu.

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

[[Page 16187]]

    By December 31, 2026, meet a combined annual SO2 
emission limit that is equivalent to: (i) the SO2 
emission limits specified by ODEQ on half of the OG&E units and half 
of the AEP/PSO units; and (ii) being at or below the SO2 
emissions that would result from switching the remaining units to 
---------------------------------------------------------------------------
natural gas.

    In other words, after having exhausted any rights to challenge our 
disapproval of ODEQ's BART determinations, OG&E and AEP/PSO could elect 
to either (1) install dry scrubbers at the beginning of 2018; or (2) 
scrub half of their units (again at the higher rate) and switch the 
other half (not specified as to plant for OG&E) to natural gas by the 
end of 2026. We find that neither of these alternatives would comport 
with the requirements of section 51.308, as explained below.
    Our regulations do provide states with the flexibility to adopt 
alternatives to BART. Such alternatives, for example, could include 
fuel switching beyond the five-year window allowed for the installation 
of BART. Such alternatives, however, must be shown to provide for 
greater reasonable progress than BART does and must be fully 
implemented prior to the close of the planning period for the first 
regional haze SIP. 40 CFR 51.308(e)(2)(i) and (iii).
    Even assuming that a contingent SIP provision triggered by the 
conclusion of all appeals regarding a related provision could be 
considered enforceable, we do not believe that the Alternative 
Determination is approvable. We propose to disapprove the Alternative 
Determination because neither of the set of contingent emission 
limitations meets the requirements of our RH regulations governing 
``better than BART'' alternatives. As described above, ODEQ concluded 
that BART requires no additional controls at these units. The 
Alternative Determination would apply only where we have disagreed with 
this conclusion, disapproved the SIP, and prevailed in any ensuing 
litigation. It seems highly probable in such a situation that both the 
courts and we would have concluded that BART requires the use of 
scrubbers. Given this, the first potential requirement, that the BART 
units install scrubbers in January 2018, does not provide for greater 
reasonable progress than does BART. Rather, it allows OG&E and AEP/PSO 
to delay the installation of scrubbers beyond the time period allowed 
by the CAA.\36\ In addition to the question of timing, the emission 
limits associated with the first potential requirement are 
substantially higher than what we have proposed as BART using the same 
controls, dry scrubbers. We have not seen any explanation from ODEQ as 
to how allowing OG&E and AEP/PSO additional time in which to meet less 
stringent emission limitations provides for greater reasonable 
progress.
---------------------------------------------------------------------------

    \36\ BART must be installed and operational as expeditiously as 
practicable, but in no event later than five years after approval of 
an implementation plan. CAA 169A(g)(4).
---------------------------------------------------------------------------

    The second potential requirement does not require any reduction in 
emissions from the BART units until 2026, near the end of the second 
long-term strategy period for RH. Again, we have seen no explanation of 
how such an extended compliance period would result in greater 
reasonable progress. More significantly, however, such an approach is 
not allowed by our regulations governing alternatives to BART, which 
require all necessary emission reductions to take place during the 
period of the first long-term strategy for RH, i.e. by 2018. 40 CFR 
51.308(e)(2)(iii).
    For the reasons discussed here, we propose to disapprove as part of 
the Oklahoma RH SIP, this submitted ``Alternative Determination.'' If 
Oklahoma provides us with an alternative demonstration that complies 
with 40 CFR 51.308(e)(2)(i) and (iii), we will consider it under a 
future action.

F. Federal Implementation Plan To Address SO2 BART for the 
Six Sources

1. Introduction
    As discussed above, we propose to disapprove Oklahoma's BART 
determination for the six sources in question. In addition, as 
discussed in Section VI, we have determined that additional controls 
are necessary on these units to prevent emissions from Oklahoma from 
interfering with other states' plans to improve visibility, and we are 
partially disapproving the Oklahoma SIP as it pertains to that 
requirement. To correct the deficiencies identified in these proposed 
disapprovals, we are also proposing a FIP.
    In proposing a FIP to address BART, we must consider the same 
factors as states. As discussed above, we agree with ODEQ's evaluation 
for pollutants other than SO2, but disagree for 
SO2 in two respects. First, we believe that dry scrubbing 
and wet scrubbing are both cost effective. Second, we have identified 
some concerns with ODEQ's estimation of visibility impacts and 
accordingly have re-evaluated the visibility impacts of these controls. 
Our modeling shows that the use of these controls will result in 
greater improvement in visibility than estimated by ODEQ.
    We propose to find that both dry scrubbing and wet scrubbing 
provide cost effective reductions of SO2. We also believe 
that implementation of these controls will provide substantial 
visibility improvement at four Class I areas.
2. Appropriate Emission Limits
    In our BART Guidelines, we established an SO2 
presumptive limit that applies to Electricity Generating Units (EGUs) 
at power plants with a total generating capacity in excess of 750 MW of 
either 0.15 lbs/MMBtu, or 95% control. 70 FR 39104, 39131. We required 
that states, as a general matter, must require owners and operators of 
greater than 750 MW power plants to meet these BART emission limits. In 
addition, we noted that the presumption does not limit the states' 
ability to consider whether a different level of control is appropriate 
in a particular case. We stated that ``[i]f, upon examination of an 
individual EGU, a state determines that a different emission limit is 
appropriate based upon its analysis of the five factors, then the state 
may apply a more or less stringent limit.'' Id. Because we are making 
the BART determinations under our FIP, we are obligated to determine 
the appropriate level of control.
a. Dry Scrubber Emission Limit
    As is detailed in our TSD, dry scrubber performance varies with the 
sulfur content of the coal. Our analysis indicates that a dry scrubber 
on the OG&E units can remove approximately 90% of the SO2 
when burning coal with an uncontrolled emission rate of approximately 
0.51 lb/MMBtu, 91.5% when burning coal corresponding to ODEQ's proposed 
BART limit of 0.65 lb/MMBtu, and 95% when burning the coal used to size 
the scrubber, 1.18 lb/MMBtu. Similarly, our analysis indicates that a 
dry scrubber on the Northeastern units can remove approximately 93% of 
the SO2 when burning coal with an uncontrolled emission rate 
of 0.9 lb/MMBtu, and 91.5% when burning coal corresponding to ODEQ's 
proposed BART limit of 0.65 lb/MMBtu. This information is summarized in 
Table 10:

  Table 10--Expected Dry Scrubber Performance vs. Uncontrolled Emission
                                  Rates
------------------------------------------------------------------------
                                           Uncontrolled     Controlled
            Control (percent)              emission rate   emission rate
                                            (lbs/MMBtu)     (lbs/MMBtu)
------------------------------------------------------------------------
90.0....................................            0.51           0.051
91.5....................................            0.65           0.055
93.0....................................            0.90           0.063
95.0....................................            1.18           0.059
------------------------------------------------------------------------

[[Page 16188]]

    Based on this information, our analysis indicates that an 
SO2 emission limit of 0.06 lbs/MMBtu can be met on the basis 
of a 30-day rolling average for the OG&E and AEP/PSO units, using dry 
scrubber technologies. As is noted in our TSD, there are already 
facilities operating below this emission rate, using dry scrubber 
technologies, and that burn similar coals.
b. Wet Scrubber Emission Limit
    According to OG&E's contractor, ``[w]et scrubbing is the 
predominant technology for large-scale utility applications in most 
parts of the world.'' In addition, ``SO2 removal guarantees 
of up to 99% (without additives) are available from the system 
suppliers and have been demonstrated in commercial applications, though 
there is a practical outlet limitation at 0.04 lb. SO2/MBtu, 
which represents a lower percentage removal for the lowest sulfur 
coals.'' \37\ However, as we note in our TSD, Pleasant Prairie Units 1 
and 2, similar boilers that burn a similar low sulfur PRB coal, were 
retrofitted with wet scrubbers in 2006 and 2007. An examination of our 
Clean Air Markets Division SO2 emissions data for Unit 1 for 
the period 2007 through June 2010 indicates this unit easily meets a 
365-day rolling average of less than 0.03 lb/MMBtu. Similarly, the 
Minnesota Power Boswell 3 unit was recently retrofit with a wet 
scrubber (among other pollution control upgrades) and, based on our 
Clean Air Markets Division SO2 emissions data, it appears to 
be achieving a monthly average emission rate of less than 0.03 lbs/
MMBtu. This, along with other similar examples discussed in our TSD, 
indicates that wet scrubbing at the OG&E and AEP/PSO units could 
consistently result in an SO2 removal efficiency of 98%, or 
meet an emission limit of 0.04 lbs/MMBtu on a 30-day rolling average.
---------------------------------------------------------------------------

    \37\ Sargent & Lundy, Flue Gas Desulfurization Technology, Dry 
Lime vs. Wet Limestone FGD, Prepared for National Lime Association, 
March 2007.
---------------------------------------------------------------------------

3. Visibility Benefit From Dry and Wet Scrubbing
    As discussed in our evaluation of ODEQ's BART evaluation, our 
modeling indicates substantial visibility benefit from the 
implementation of dry scrubbing. We did not find substantial additional 
visibility benefits on the 98th percentile value from the use of wet 
scrubbers even though we believe wet scrubbers would be expected to 
achieve lower emissions. As a result, we propose that the emission 
limit in the FIP be based on the emission levels that can be achieved 
by dry scrubbing.
4. EPA's SO2 BART Determination for the Six Units
    As described above, for the particular cases we are considering in 
this action, we have concluded there is a lack of a clear visibility 
advantage to wet scrubbing at the SO2 emission rates we have 
considered. Other details concerning the input values we have assumed 
in our visibility modeling are contained in the TSD. We invite comment 
on all aspects of our visibility modeling. Given that wet scrubbing is 
approximately 9% higher in cost on a $[sol]tons of SO2 
removed basis, we propose that SO2 BART for the 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 should be based on 
dry scrubbing. We note there are significant advantages to wet 
scrubbing that OG&E and/or AEP/PSO may find attractive as a means of 
satisfying our proposed FIP.
    As we note above, under section 51.308(e)(1)(iv), ``each source 
subject to BART [is] 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.'' Based on the retrofit 
of other scrubber installations we have reviewed, we find that three 
(3) years from the date our final determination becomes effective is 
adequate time for the installation and operation of these controls.\38\ 
We solicit comments on alternative timeframes, of from two (2) years up 
to five (5) years from the effective date our final rule.
---------------------------------------------------------------------------

    \38\ Engineering and Economic Factors Affecting the Installation 
of Control Technologies for Multipollutant Strategies, EPA-600/R-02/
073, October 2002, pdf pagination 5: ``Conservatively high 
assumptions were made for the time, labor, reagents, and steel 
needed to install FGD systems. For LSFO installation timing, it is 
expected that one system requires about 27 months of total effort 
for planning, engineering, installation, and startup, with 
connections occurring during normally scheduled outages),'' 
available at http://www.epa.gov/clearskies/pdfs/multi102902.pdf.
---------------------------------------------------------------------------

    We do not wish to dissuade companies from exercising the option of 
switching to natural gas as a means of satisfying their BART 
obligations under section 51.308(e). Such an approach, for example, 
would be acceptable for satisfying SO2 BART,\39\ if it 
satisfies the requirement 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.'' Switching to natural 
gas would be an acceptable method of complying with the limits proposed 
in this FIP. In addition, 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 action would be justified.
---------------------------------------------------------------------------

    \39\ We note that, as with the other fossil fuel fired power 
plant BART determinations contained within this proposal, separate 
NOx and PM BART determinations must also be made.
---------------------------------------------------------------------------

G. Long-Term Strategy

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

[[Page 16189]]

inventory was developed by projecting 2002 emissions and applying 
reductions expected from federal and state regulations affecting the 
emissions of the visibility-impairing pollutants NOX, PM, 
SO2,, and VOCs.
a. Oklahoma's 2002 Emission Inventory
    ODEQ and CENRAP developed an emission inventory for five inventory 
source classifications: Point, area, non-road and on-road mobile 
sources, and biogenic sources for the baseline year of 2002. Oklahoma's 
2002 emissions inventory is summarized in Table 11:

                                                      Table 11--Oklahoma's 2002 Emissions Inventory
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                SO2             NH3             NOX            VOCs        PM10-  PM2.5        PM2.5
--------------------------------------------------------------------------------------------------------------------------------------------------------
Point...................................................         148,761          24,102         158,818          37,794           8,026           8,636
Area....................................................          11,779         114,363         115,407         201,758         304,560         109,279
Non-road mobile.........................................           4,773             280          49,396          47,863             433           4,580
On-road mobile..........................................           4,708           4,434         142,592          99,924             879           2,459
Biogenic................................................               0               0          35,909         988,314               0               0
                                                         -----------------------------------------------------------------------------------------------
    Total...............................................         170,021         143,179         502,122       1,375,653         313,898         124,954
--------------------------------------------------------------------------------------------------------------------------------------------------------

    See the TSD for details on how the 2002 emissions inventory was 
constructed. We propose that Oklahoma's 2002 emission inventory is 
acceptable.
b. Oklahoma's 2018 Emission Inventory
    In general, ODEQ used a combination of our Economic Growth Analysis 
System (EGAS 5), our mobile emissions factor model (MOBILE 6), our off-
road emissions factor model (NONROAD), and the Integrated Planning 
Model (IPM) for electric generating units in constructing its 2018 
emission inventory. ODEQ modified the projected emissions from the IPM 
modeling for OG&E Sooner and Muskogee electric power plants and the PSO 
Northeast electric power plants to reflect the application of 
presumptive BART controls.\40\ More specifically, CENRAP developed 
emissions for five inventory source classifications: point, area, non-
road and on-road mobile sources, and biogenic sources. CENRAP used its 
2002 emission inventory, described above, to estimate emissions in 
2018. All control strategies expected to take effect prior to 2018 are 
included in the projected emission inventory. Oklahoma's 2018 emissions 
inventory is summarized in Table 12:
---------------------------------------------------------------------------

    \40\ Note, our proposed FIP, discussed in section V.E, would 
require a stricter level of SO2 for six units in these 
facilities.

                                                      Table 12--Oklahoma's 2018 Emissions Inventory
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                SO2             NH3             NOX            VOCs        PM10-  PM2.5        PM2.5
--------------------------------------------------------------------------------------------------------------------------------------------------------
Point...................................................         106,701          35,215         140,298         125,648           8,935          13,989
Area....................................................          12,374         141,532         128,257         400,056         275,844         127,018
Non-road mobile.........................................             156              40          25,387          28,489           2,914             292
On-road mobile..........................................             545           5,818          39,397          39,281               0             953
Biogenic................................................               0               0          35,909         988,314               0               0
                                                         -----------------------------------------------------------------------------------------------
    Total...............................................         119,776         182,605         369,248       1,581,788         287,693         142,252
--------------------------------------------------------------------------------------------------------------------------------------------------------

    See the TSD for details on how the 2018 emissions inventory was 
constructed. CENRAP and ODEQ used this and other state's 2018 emission 
inventories to construct visibility projection modeling for 2018. We 
propose that Oklahoma's 2018 emission inventory is acceptable but for 
its inclusion of reductions from the OG&E and AEP/PSO coal fired units 
that were not ultimately required by Oklahoma. As discussed above, we 
propose a FIP to address this deficiency.
2. Visibility Projection Modeling
    CENRAP performed modeling for the RH LTS for its member states, 
including Oklahoma. The modeling analysis is a complex technical 
evaluation that began with selection of the modeling system. CENRAP 
used (1) the Mesoscale Meteorological Model (MM5) meteorological model, 
(2) the Sparse Matrix Operator Kernel Emissions (SMOKE) modeling system 
to generate hourly gridded speciated emission inputs, (3) the Community 
Multiscale Air Quality (CMAQ) photochemical grid model and (4) the 
Comprehensive Air Quality model with extensions (CAMx), as a secondary 
corroborative model. CAMx was also utilized with its Particulate Source 
Apportionment Technology (PSAT) tool to provide source apportionment 
for both the baseline and future case visibility modeling.
    The photochemical modeling of RH for the CENRAP states for 2002 and 
2018 was conducted on the 36-km resolution national regional planning 
organization domain that covered the continental United States, 
portions of Canada and Mexico, and portions of the Atlantic and Pacific 
Oceans along the east and west coasts. The CENRAP states' modeling was 
developed consistent with our guidance.\41\
---------------------------------------------------------------------------

    \41\ Guidance on the Use of Models and Other Analyses for 
Demonstrating Attainment of Air Quality Goals for Ozone, PM2.5, and 
Regional Haze, (EPA-454/B-07-002), April 2007, located at http://www.epa.gov/scram001/guidance/guide/final-03-pm-rh-guidance.pdf. 
Emissions Inventory Guidance for Implementation of Ozone and 
Particulate Matter National Ambient Air Quality Standards (NAAQS) 
and Regional Haze Regulations, August 2005, updated November 2005 
(``our Modeling Guidance''), located at http://www.epa.gov/ttnchie1/eidocs/eiguid/index.html, EPA-454/R-05-001.
---------------------------------------------------------------------------

    CENRAP examined the model performance of the regional modeling for 
the areas of interest before determining whether the CMAQ model results 
were suitable for use in the RH

[[Page 16190]]

assessment of the LTS and for use in the modeling assessment. The 2002 
modeling efforts were used to evaluate air quality/visibility modeling 
for a historical episode--in this case, for calendar year 2002--to 
demonstrate the suitability of the modeling systems for subsequent 
planning, sensitivity, and emissions control strategy modeling. Model 
performance evaluation is performed by comparing output from model 
simulations with ambient air quality data for the same time period to 
determine whether the model's performance is sufficiently accurate to 
justify using the model for simulating future conditions. Once CENRAP 
determined the model performance to be acceptable, it used the model to 
determine the 2018 RPGs using the current and future year air quality 
modeling predictions, and compared the RPGs to the URP. Table 13, 
derived from Table VIII-9 of the Oklahoma RH SIP submittal, summarizes 
the projected contribution from Oklahoma emissions on visibility 
degradation at Class I areas for the 20 percent worst days in 2018. 
Note, this table only includes contributions of 0.15 deciviews or 
greater.

                Table 13--Projected Contribution From Oklahoma Emissions on Visibility Degradation for the 20 Percent Worst Days in 2018
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                     Contribution to
                                                                                          light          Total light        Oklahoma         Deciview
                  Class I area                                  State                extinction (Mm-  extinction  (Mm-    contribution     contribution
                                                                                            1)               1)            (percent)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Wichita Mountains..............................  Oklahoma..........................            12.28             86.56            14.19             1.53
Hercules-Glades................................  Missouri..........................             3.74            103.49             3.61             0.37
Salt Creek.....................................  New Mexico........................             1.46             57.67             2.53             0.26
Caney Creek....................................  Arkansas..........................             2.23             96.84             2.30             0.23
Upper Buffalo..................................  Arkansas..........................             1.97             97.16             2.03             0.21
Guadalupe Mountains............................  Texas.............................             1.11             55.43             2.00             0.20
Seney..........................................  Michigan..........................             1.74             95.27             1.83             0.18
White Mountain.................................  New Mexico........................             0.69             40.8              1.70             0.17
Isle Royale....................................  Michigan..........................             1.08             73.71             1.46             0.15
--------------------------------------------------------------------------------------------------------------------------------------------------------

3. Consultation and Emissions Reductions for Other States' Class I 
Areas
    As in the development of Oklahoma's reasonable progress goal for 
the Wichita Mountains, ODEQ used CENRAP as its main vehicle for 
facilitating collaboration with FLMs and other states in satisfying its 
LTS consultation requirement. This helped ODEQ and other state 
environmental agencies analyze emission apportionments at Class I areas 
and develop coordinated RH SIP strategies.
    Section 51.308(d)(3)(i) requires that Oklahoma consult with other 
states if its emissions are reasonably anticipated to contribute to 
visibility impairment at that state's Class I area(s), and that 
Oklahoma consult with other states if their emissions are reasonably 
anticipated to contribute to visibility impairment at the Wichita 
Mountains. ODEQ's consultations with other states are described in 
section V.C.3 above. After evaluating whether emissions from Oklahoma 
sources contribute to visibility impairment in other states' Class I 
areas, ODEQ concluded there was no contribution sufficient to require 
consultation. ODEQ's evaluation relied, however, upon SO2 
BART reductions from the six units of the OG&E and AEP/PSO three coal 
fired power plants but these reductions are not required. Regardless of 
its conclusions regarding the impacts of Oklahoma emissions on other 
states' Class I areas, however, Oklahoma did consult with other states 
and tribes, largely through the CENRAP process. We propose that those 
consultations adequately satisfy the requirement under Section 
51.308(d)(3)(i).
    Section 51.308(d)(3)(ii) requires that if Oklahoma emissions cause 
or contribute to impairment in another state's Class I area, Oklahoma 
must demonstrate that it has included in its RH SIP all measures 
necessary to obtain its share of the emission reductions needed to meet 
the progress goal for that Class I area. Section 51.308(d)(3)(ii) also 
requires that since Oklahoma participated in a regional planning 
process, it must ensure it has included all measures needed to achieve 
its apportionment of emission reduction obligations agreed upon through 
that process. As we state in the RHR \42\, Oklahoma's commitments to 
participate in CENRAP bind it to secure emission reductions agreed to 
as a result of that process, unless it proposes a separate process and 
performs its consultations on the basis of that process:
---------------------------------------------------------------------------

    \42\ 64 FR 35735.
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    While States are not bound by the results of a regional planning 
effort, nor can the content of their SIPs be dictated by a regional 
planning body, we expect that a coordinated regional effort will likely 
produce results the States will find beneficial in developing their 
regional haze implementation plans. Any State choosing not to follow 
the recommendations of a regional body would need to provide a specific 
technical basis that its strategy nonetheless provides for reasonable 
progress based on the statutory factors. At the same time, EPA cannot 
require States to participate in regional planning efforts if the State 
prefers to develop a long-term strategy on its own. We note that any 
State that acts alone in this regard must conduct the necessary 
technical support to justify their apportionment, which generally will 
require regional inventories and a regional modeling analysis. 
Additionally, any such State must consult with other States before 
submitting its long-term strategy to EPA.
    Consequently, because Oklahoma accepted and incorporated the 
CENRAP-developed visibility modeling into its RH SIP, which assumed 
controls for the six units discussed above that were not subsequently 
secured, we propose to disapprove Oklahoma's long term strategy.
    However, our proposed FIP does include controls for the six units 
that at least achieve the level of control assumed in the CENRAP 
modeling. In addition, as described above, Oklahoma has required 
controls on additional sources as part of its BART evaluation. 
Therefore, we propose to find that with the addition of our proposed 
FIP, the requirements in section 51.308(d)(3)(ii) have been met.
4. Mandatory Long Term Strategy Factors
    Section 51.308(d)(3)(v) requires that Oklahoma minimally consider 
certain

[[Page 16191]]

factors in developing its long-term strategy (the LTS factors). These 
include: (1) Emission reductions due to ongoing air pollution control 
programs, including measures to address RAVI; (2) measures to mitigate 
the impacts of construction activities; (3) emissions limitations and 
schedules for compliance to achieve the reasonable progress goal; (4) 
source retirement and replacement schedules; (5) smoke management 
techniques for agricultural and forestry management purposes including 
plans as currently exist within the state for these purposes; (6) 
enforceability of emissions limitations and control measures; and (7) 
the anticipated net effect on visibility due to projected changes in 
point, area, and mobile source emissions over the period addressed by 
the long-term strategy. For the reasons outlined below, we propose to 
find that Oklahoma has satisfied all the requirements of Section 
51.308(d)(3)(v).
    In addition to its BART determinations and by extension our 
proposed FIP, Oklahoma's LTS incorporates emission reductions due to a 
number of ongoing air pollution control programs. This includes the 
issuance and enforcement of permits limiting emissions (based on our 
National Ambient Air Quality Standards) from all major sources in 
Oklahoma (the SIP also includes permits for minor sources), state rules 
which specifically limit targeted emissions sources and categories, and 
other air pollution control programs that ODEQ administers. We note 
that fine and coarse particulate, of which construction-related 
activities are thought to be a small contributor, are themselves minor 
contributors to visibility impairment at the Wichita Mountains. ODEQ 
relies on fugitive dust control rules to control and minimize dust from 
construction activities. ODEQ has adopted rules to ensure the 
enforceability of these emission limitations. This includes rules that 
govern ODEQ's permitting process for major and minor sources, 
Prevention of Significant Deterioration (PSD) provisions, Best 
Available Control Technology (BACT), and BART requirements. These rules 
have corresponding compliance schedules and enforcement protocols and 
are summarized in the TSD.
    ODEQ issues permits to all major and minor point sources in 
Oklahoma, and each permit contains enforceable limitations on emissions 
of various pollutants, including those which cause or contribute to RH 
at the Wichita Mountains. Unless those permits specify a different 
schedule for compliance, ODEQ requires permitted sources to comply with 
their permits immediately upon issuance. ODEQ also enforces compliance 
schedules of relevant administrative and judicial orders, including 
consent decrees that result in significant SO2 and 
NOX reductions.
    We approved ODEQ's SIP to address reasonably attributable 
visibility impairment at the Wichita Mountains on November 8, 1999. See 
64 FR 60683. As we note in section V.H, the FLMs did not identify any 
integral vistas in Oklahoma. In addition, the Wichita Mountains is not 
experiencing RAVI, nor are any Oklahoma sources affected by the RAVI 
provisions. Therefore, the Oklahoma RH SIP does not incorporate any 
measures to specifically address RAVI.
    ODEQ considered source retirement and replacement schedules in 
developing its long-term strategy of emissions reductions. ODEQ stated 
it cannot reliably predict the retirement or replacement of sources and 
consequently does not rely on source retirement to achieve any 
reasonable progress goal.
    Fires are responsible for much of the directly emitted fine 
particulate matter in the Oklahoma emissions inventory. ODEQ considered 
smoke management techniques for the purposes of agricultural and 
forestry management in its LTS. As Tables IV-1 and IV-2 in the Oklahoma 
RH SIP revision submittal indicate, all types of fire sources 
(wildfire, agricultural burning, rangeland burning, etc.) are 
responsible for approximately 4.2% of the total SO2, 4.1% of 
the total NH3, 3.9% of the total NOX, 2.1% of the 
total VOCs, and 3.6% of the total PM10 emissions. In contrast, fire is 
responsible for about 33.4% of the total PM2.5 emissions. 
However, Table VIII-3 of the Oklahoma RH SIP indicates that all 
Oklahoma area sources combined, of which fire is only a part, account 
for less than 1% of the total visibility impact at the Wichita 
Mountains. Nevertheless, ODEQ states that it and the Oklahoma 
Department of Agriculture, Food, and Forestry intend to create a basic, 
voluntary smoke management program based on our Interim Air Quality 
Policy on Wildland and Prescribed Fires. We commend this effort and 
offer our assistance in the development of this plan.
    Section 51.308(d)(3)(v)(F) requires that Oklahoma ensure the 
enforceability of emission limitations and control measures used to 
meet reasonable progress goals. ODEQ has issued enforceable Title V 
operating permits requiring BART-eligible sources subject to BART to 
install BART and achieve the associated BART emission limits. 
Similarly, any BART requirement in a FIP must be included by ODEQ in a 
Part 70 air quality permit. See 70 FR at 39172.
    ODEQ has demonstrated it has the statutory authority to regulate 
air emissions from all facilities and sources subject to operating 
permit requirements under Title V of the CAA. ODEQ also has the 
authority to administratively and judicially enforce any provision of 
an ODEQ issued air quality permits. See the TSD for more details on 
Oklahoma laws that provide for this authority.

H. Coordination of RAVI and Regional Haze Requirements

    Our visibility regulations direct states to coordinate their RAVI 
LTS and monitoring provisions with those for RH, as explained in 
section IV, above. Under our RAVI regulations, the RAVI portion of a 
state SIP must address any integral vistas identified by the FLMs 
pursuant to 40 CFR 51.304. See 40 CFR 51.302. An integral vista is 
defined in 40 CFR 51.301 as a ``view perceived from within the 
mandatory Class I Federal area of a specific landmark or panorama 
located outside the boundary of the mandatory Class I Federal area.'' 
Visibility in any mandatory Class I Federal area includes any integral 
vista associated with that area. The FLMs did not identify any integral 
vistas in Oklahoma. In addition, the Wichita Mountains is not 
experiencing RAVI, nor are any Oklahoma sources affected by the RAVI 
provisions. Thus, the Oklahoma RH SIP submittal does not explicitly 
address the two requirements regarding coordination of RH with the RAVI 
LTS and monitoring provisions. However, Oklahoma previously made a 
commitment to address RAVI should the FLM certify visibility impairment 
from an individual source.\43\ We propose to find that this RH 
submittal appropriately supplements and augments Oklahoma's RAVI 
visibility provisions to address RH by updating the monitoring and LTS 
provisions as summarized below in this section.
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    \43\ Oklahoma's Part 1 and Part II visibility SIP contained RAVI 
provisions and was previously approved by EPA (64 FR 60683).
---------------------------------------------------------------------------

I. Monitoring Strategy and Other SIP Requirements

    Section 51.308(d)(4) requires the SIP contain a monitoring strategy 
for measuring, characterizing, and reporting of RH visibility 
impairment that is representative of all mandatory Class I Federal 
areas within the state. This monitoring strategy must be coordinated 
with the monitoring strategy required in Section 51.305 for reasonably

[[Page 16192]]

attributable visibility impairment. As Section 51.308(d)(4) notes, 
compliance with this requirement may be met through participation in 
the IMPROVE network. Since the monitor at the Wichita Mountains is an 
IMPROVE monitor, we propose that ODEQ has satisfied this requirement. 
See the TSD for details concerning the IMPROVE network.
    Section 51.308(d)(4)(i) requires the establishment of any 
additional monitoring sites or equipment needed to assess whether 
reasonable progress goals to address RH for all mandatory Class I 
Federal areas within the state are being achieved. Shortly after the 
creation of CENRAP, its monitoring workgroup noted the lack of a 
representative monitor for the Wichita Mountains. At that time, an 
IMPROVE site for Upper Buffalo, Arkansas, in a wetter climate several 
hundred miles to the east-northeast, provided the closest available 
visibility monitoring data. Because this monitoring data was deemed 
unrepresentative, a particle sampler monitor was established at the 
Wichita Mountains and began operating in March, 2001. As described in 
section V.B., above, baseline visibility conditions were calculated 
using data representative of 2002-2004 due to lack of data from 
previous years. With the addition of the monitor at the Wichita 
Mountains, we propose to find that ODEQ has satisfied this requirement.
    Section 51.308(d)(4)(ii) requires that ODEQ establish procedures by 
which monitoring data and other information are used in determining the 
contribution of emissions from within Oklahoma to RH visibility 
impairment at mandatory Class I Federal areas both within and outside 
the state. The monitor at the Wichita Mountains is operated by Wichita 
Mountains personnel. The IMPROVE monitoring program is national in 
scope, and other states have similar monitoring and data reporting 
procedures, ensuring a consistent and robust monitoring data collection 
system. As section 51.308(d)(4) indicates, participation in the IMPROVE 
program constitutes compliance with this requirement. We therefore 
propose that ODEQ has satisfied this requirement.
    Section 51.308(d)(4)(iv) requires that the SIP must provide for the 
reporting of all visibility monitoring data to the Administrator at 
least annually for each mandatory Class I Federal area in the state. To 
the extent possible, Oklahoma should report visibility monitoring data 
electronically. Section 51.308(d)(4)(vi) also requires that ODEQ 
provide for other elements, including reporting, recordkeeping, and 
other measures, necessary to assess and report on visibility. We 
propose that Oklahoma's participation in the IMPROVE network ensures 
the monitoring data is reported at least annually, is easily 
accessible, and therefore complies with this requirement.
    Section 51.308(d)(4)(iv) requires that ODEQ maintain a statewide 
inventory of emissions of pollutants that are reasonably anticipated to 
cause or contribute to visibility impairment in any mandatory Class I 
Federal area. The inventory must include emissions for a baseline year, 
emissions for the most recent year for which data are available, and 
estimates of future projected emissions. The state must also include a 
commitment to update the inventory periodically. Please refer to 
section V.G., above, where we discuss ODEQ's emission inventory. ODEQ 
has stated that it intends to update the Oklahoma statewide emissions 
inventories periodically and review periodic emissions information from 
other states and future emissions projections. We propose that this 
satisfies the requirement.

J. Federal Land Manager Coordination

    The Wichita Mountains is one of more than 546 refuges throughout 
the United States managed by the Fish and Wildlife Service, which is 
the Federal Land Manager (FLM) for this Class I area. Although the FLMs 
are very active in participating in the RPOs, the RH Rule grants the 
FLMs a special role in the review of the RH SIPs, summarized in section 
IV.H., above. We view both the FLMs and the state environmental 
agencies as our partners in the RH process.
    Section 51.308(i)(1) requires that by November 29, 1999, Oklahoma 
must have identified in writing to the FLMs the title of the official 
to which the FLM of the Wichita Mountains can submit any 
recommendations on the implementation of section 51.308. We acknowledge 
this section has been satisfied by all states via communication prior 
to this SIP.
    Under Section 51.308(i)(2), Oklahoma was obligated to provide the 
Fish and Wildlife Service with an opportunity for consultation, in 
person and at least 60 days prior to holding a public hearing on it RH 
SIP. In practice, state environmental agencies have usually provided 
all FLMs--the Forest Service, the Park Service, and the Fish and 
Wildlife Service, copies of their RH SIP, as the FLMs collectively have 
reviewed these RH SIPs. ODEQ followed this practice and sent its draft 
of this implementation plan revision to the federal land manager staff 
on October 1, 2009 and notified the federal land manager staff of the 
public hearing held on December 16, 2009. In its letter dated December 
4, 2009, transmitting its comments, the Fish and Wildlife Service 
acknowledged having received Oklahoma's draft RH SIP on October 5, 
2009.
    The FLMs have communicated to us their dissatisfaction with the 
fact that the draft RH SIP they were provided by ODEQ was markedly 
different than the version ODEQ submitted to us as their final RH SIP. 
Specifically, the FLMs note that in the version of the SIP they 
reviewed, SO2 BART for the six OG&E and AEP/PSO coal fired 
units that are the subject of our FIP was determined by ODEQ to be dry 
SO2 scrubbers with an emission limit of 0.10 lbs/MMBtu for 
the OG&E units, and 0.153 lbs/MMBtu for the AEP-PSO units. When ODEQ 
submitted their final RH SIP to us, those SO2 BART 
determinations were changed to replace the SO2 scrubber 
requirements with an SO2 limit of 0.65 lbs/MMBtu on a 30 day 
rolling average that corresponds to uncontrolled low sulfur coal. We 
note the Fish and Wildlife Service has not requested that ODEQ re-open 
their 60 day comment period. We would like to address any question as 
to whether section 51.308(i)(2) has been satisfied. We believe, 
however, that our proposed FIP, as described in section V.F., above, 
may alleviate these concerns. We invite the FLMs to provide comment on 
this or other aspects of our proposal.
    Section 51.308(i)(3) requires that ODEQ provide in its RH SIP a 
description of how it addressed any comments provided by the FLMs. ODEQ 
has provided that information in Appendix 10-2 of its RH SIP.
    Lastly, Section 51.308(i)(4) specifies the RH SIP must provide 
procedures for continuing consultation between the state and Federal 
Land Manager on the implementation of the visibility protection program 
required by section 51.308, including development and review of 
implementation plan revisions and 5-year progress reports, and on the 
implementation of other programs having the potential to contribute to 
impairment of visibility in the mandatory Class I Federal areas. ODEQ 
has stipulated in its RH SIP it will continue to coordinate and consult 
with the FLMs as required by section 51.308(i)(4). ODEQ states it 
intends to consult the FLMs in the development and review of 
implementation plan revisions; review of progress reports; and 
development and implementation of other programs that may contribute to 
impairment of visibility at the Wichita Mountains and other Class I 
areas. We

[[Page 16193]]

propose that ODEQ has satisfied section 51.308(i).

K. Periodic SIP Revisions and Five-Year Progress Reports

    ODEQ affirmed its commitment to complete items required in the 
future under our RHR. ODEQ acknowledged its requirement under 40 CFR 
51.308(f), to submit periodic progress reports and RH SIP revisions, 
with the first report due by July 31, 2018 and every ten years 
thereafter.
    ODEQ also acknowledged its requirement under 40 CFR 51.308(g), to 
submit a progress report in the form of a SIP revision every five years 
following this initial submittal of the Oklahoma RH SIP. The report 
will evaluate the progress made towards the RPGs for each mandatory 
Class I area located within Oklahoma and in each mandatory Class I area 
located outside Oklahoma which may be affected by emissions from within 
Oklahoma.
    If another state's RH SIP identifies that Oklahoma's SIP needs to 
be supplemented or modified, and if, after appropriate consultation 
Oklahoma agrees, today's action may be revisited, or the additional 
information and/or changes will be addressed in the five-year progress 
report SIP revision.

VI. Our Analysis of Oklahoma's Interstate Visibility Transport SIP 
Provisions

    We received a SIP from Oklahoma to address the interstate transport 
requirements of CAA 110(a)(2)(D)(i) for the 1997 8-hour ozone and 
PM2.5 NAAQS on May 10, 2007, as supplemented on December 10, 
2007. Concerning such CAA requirements preventing sources in the state 
from emitting pollutants in amounts which will interfere with efforts 
to protect visibility in other states, Oklahoma stated that it was on 
track for the submission of its RH SIP by the December, 17, 2007 
deadline.\44\ Oklahoma states 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. However, it did not establish 
that emissions from its sources would not interfere with the visibility 
programs of other states, nor did it as part of its February 19, 2010 
RH SIP submittal. In order to evaluate whether Oklahoma's existing SIP 
adequately prevents interference with the visibility programs of other 
states, we propose to address this question using other available 
information.
---------------------------------------------------------------------------

    \44\ See 40 CFR 51.308(b).
---------------------------------------------------------------------------

    As an initial matter, we note that section 110(a)(2)(D)(i)(II) does 
not explicitly specify how we should ascertain whether a state's SIP 
contains adequate provisions to prevent emissions from sources in that 
state from interfering with measures required in another state to 
protect visibility. Thus, the statute is ambiguous on its face, and we 
must interpret that provision.
    Our 2006 Guidance recommended that a state could meet the 
visibility prong of the transport requirements of section 
110(a)(2)(D)(i)(II) of the CAA by submission of the RH SIP, due in 
December 2007. Our reasoning was that the development of the RH SIPs 
was intended to occur in a collaborative environment among the states. 
In fact, in developing their respective reasonable progress goals, 
CENRAP states consulted with each other through CENRAP's work groups. 
As a result of this process, the common understanding was that each 
state would take action to achieve the emissions reductions relied upon 
by other states in their reasonable progress demonstrations under the 
RHR. CENRAP states consulted in the development of reasonable progress 
goals, using the products of this technical consultation process to co-
develop their reasonable progress goals. In developing their visibility 
projections using photochemical grid modeling, CENRAP states assumed a 
certain level of emissions from sources within Oklahoma. As we discuss 
above in section V.G, this modeling assumed SO2 reductions 
from the six OG&E and AEP/PSO coal fired units that are the subject of 
our FIP. Although we have not yet received all RH SIPs, we understand 
that the CENRAP states used the visibility projection modeling to 
establish their own respective reasonable progress goals. Thus, we 
believe that an implementation plan that provides for emissions 
reductions consistent with the assumptions used in those states' 
modeling will ensure that emissions from Oklahoma sources do not 
interfere with the measures designed to protect visibility in other 
states.
    However, after the visibility projection modeling and all 
consultations were completed, Oklahoma revised its SO2 BART 
determinations for these six units, as submitted in the RH SIP 
submittal of February 19, 2010, removing the requirement that they be 
controlled to ensure these agreed upon emissions limits would be met. 
Consistent with our proposed conclusion that Oklahoma has not obtained 
its needed share of emission reductions, as we discuss above in section 
V.G.3, we propose to find that the Oklahoma SIP revision submittals do 
not ensure that emissions from sources in Oklahoma do not interfere 
with other State's visibility programs as required by section 
110(a)(2)(D)(i)(II) of the CAA.
    Our proposed FIP does include controls for the six units that at 
least achieve the level of control assumed in the CENRAP modeling. In 
addition, as described in section V.D., above, Oklahoma has required 
controls on sources as part of its BART evaluation. Thus, we believe 
that the controls proposed under our FIP, plus the additional controls 
required by Oklahoma under its SIP that we propose to approve, 
constitute the assemblage of cost effective controls that are 
reasonable at this time, and serve to prevent sources in Oklahoma from 
emitting pollutants in amounts that will interfere with efforts to 
protect visibility in other states. In light of this, we propose to 
partially approve and partially disapprove the Oklahoma SIP revision 
submitted to address the requirements of section 110(a)(2)(D)(i)(II) of 
the CAA.

VII. Proposed Actions

A. Regional Haze

    We propose to partially approve and partially disapprove Oklahoma's 
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 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 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 Oklahoma's long term 
strategy under section 51.308(d)(3) because it does not incorporate 
these emission reductions. ODEQ participated in the CENRAP visibility 
modeling development that assumed certain SO2 reductions 
from these six BART units. 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.
    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

[[Page 16194]]

Northeastern plant are subject to BART under 40 CFR 51.308(e). Further, 
we propose a FIP that specifically imposes SO2 BART on these 
six 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, 
record-keeping, 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 of 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 by 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 the effective date of our 
final rule 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 section 51.308(d)(1).
    We propose to approve all other portions of the Oklahoma RH SIP. We 
note that all controls required as part of Oklahoma's BART 
determinations, not included as part of our proposed FIP, must be 
operational within five years from the effective date of our final 
rule.

B. Interstate Transport of Visibility

    We are also proposing to partially approve and partially disapprove 
a portion of a SIP revision submitted by the State of Oklahoma 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. Specifically, we propose a partial approval and 
partial disapproval of the Oklahoma Interstate Transport SIP provisions 
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. With regard to whether emissions from Oklahoma sources 
interfere with the visibility programs of other states, we are 
proposing to find that Oklahoma sources, except 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, are sufficiently 
controlled to eliminate interference with the visibility programs of 
other states, and for the six units we are proposing specific 
SO2 emission limits that will eliminate such interstate 
interference.

VIII. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

    This proposed action is not a ``significant regulatory action'' 
under the terms of Executive Order (EO) 12866 (58 FR 51735, October 4, 
1993), and is therefore not subject to review under the Executive 
Order. The proposed FIP applies to only three facilities and is not a 
rule of general applicability.

B. Paperwork Reduction Act

    This proposed action does not impose an information collection 
burden under the provisions of the Paperwork Reduction Act, 44 U.S.C. 
3501 et seq. Under the Paperwork Reduction Act, a ``collection of 
information'' is defined as a requirement for ``answers to * * * 
identical reporting or recordkeeping requirements imposed on ten or 
more persons * * *.'' 44 U.S.C. 3502(3)(A). Because the proposed FIP 
applies to just three facilities, the Paperwork Reduction Act does not 
apply. See 5 CFR 1320(c).
    Burden means the total time, effort, or financial resources 
expended by persons to generate, maintain, retain, or disclose or 
provide information to or for a Federal agency. This includes the time 
needed to review instructions; develop, acquire, install, and utilize 
technology and systems for the purposes of collecting, validating, and 
verifying information, processing and maintaining information, and 
disclosing and providing information; adjust the existing ways to 
comply with any previously applicable instructions and requirements; 
train personnel to be able to respond to a collection of information; 
search data sources; complete and review the collection of information; 
and transmit or otherwise disclose the information.
    An agency may not conduct or sponsor, and a person is not required 
to respond to a collection of information unless it displays a 
currently valid Office of Management and Budget (OMB) control number. 
The OMB control numbers for our regulations in 40 CFR are listed in 40 
CFR part 9.

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA) generally requires an agency 
to prepare a regulatory flexibility analysis of any rule subject to 
notice and comment rulemaking requirements under the Administrative 
Procedure Act or any other statute unless the agency certifies that the 
rule will not have a significant economic impact on a substantial 
number of small entities. Small entities include small businesses, 
small organizations, and small governmental jurisdictions.
    For purposes of assessing the impacts of today's proposed rule on 
small entities, small entity is defined as: (1) A small business as 
defined by the Small Business Administration's (SBA) regulations at 13 
CFR 121.201; (2) a small governmental jurisdiction that is a government 
of a city, county, town, school district or special district with a 
population of less than 50,000; and (3) a small organization that is 
any not-for-profit enterprise which is independently owned and operated 
and is not dominant in its field.
    After considering the economic impacts of this proposed action on 
small entities, I certify that this proposed action will not have a 
significant economic impact on a substantial number of small entities. 
The FIP for the three Oklahoma facilities being proposed today does not 
impose any new requirements on small entities. The proposed partial 
approval of the SIP, if finalized, merely approves state law as meeting 
Federal requirements and imposes no additional requirements beyond 
those imposed by state law. See Mid-Tex Electric Cooperative, Inc. v. 
FERC, 773 F.2d 327 (D.C. Cir. 1985)

D. Unfunded Mandates Reform Act (UMRA)

    Under sections 202 of the Unfunded Mandates Reform Act of 1995 
(``Unfunded Mandates Act''), signed into law on March 22, 1995, EPA 
must prepare a budgetary impact statement to accompany any proposed or 
final rule

[[Page 16195]]

that includes a Federal mandate that may result in estimated costs to 
State, local, or tribal governments in the aggregate; or to the private 
sector, of $100 million or more (adjusted to inflation). Under section 
205, EPA must select the most cost-effective and least burdensome 
alternative that achieves the objectives of the rule and is consistent 
with statutory requirements. Section 203 requires EPA to establish a 
plan for informing and advising any small governments that may be 
significantly or uniquely impacted by the rule.
    EPA has determined that the approval action proposed does not 
include a Federal mandate that may result in estimated costs of $100 
million or more to either State, local, or tribal governments in the 
aggregate, or to the private sector. This Federal action proposes to 
approve pre-existing requirements under State or local law, and imposes 
no new requirements. Accordingly, no additional costs to State, local, 
or tribal governments, or to the private sector, result from this 
action.

E. Executive Order 13132: Federalism

    Federalism (64 FR 43255, August 10, 1999) revokes and replaces 
Executive Orders 12612 (Federalism) and 12875 (Enhancing the 
Intergovernmental Partnership). Executive Order 13132 requires EPA to 
develop an accountable process to ensure ``meaningful and timely input 
by State and local officials in the development of regulatory policies 
that have federalism implications.'' ``Policies that have federalism 
implications'' is defined in the Executive Order to include regulations 
that have ``substantial direct effects on the States, on the 
relationship between the national government and the States, or on the 
distribution of power and responsibilities among the various levels of 
government.'' Under Executive Order 13132, EPA may not issue a 
regulation that has federalism implications, that imposes substantial 
direct compliance costs, and that is not required by statute, unless 
the Federal government provides the funds necessary to pay the direct 
compliance costs incurred by State and local governments, or EPA 
consults with State and local officials early in the process of 
developing the proposed regulation. EPA also may not issue a regulation 
that has federalism implications and that preempts State law unless the 
Agency consults with State and local officials early in the process of 
developing the proposed regulation.
    This rule will not have substantial direct effects on the States, 
on the relationship between the national government and the States, or 
on the distribution of power and responsibilities among the various 
levels of government, as specified in Executive Order 13132, because it 
merely addresses the State not fully meeting its obligation to prohibit 
emissions from interfering with other states measures to protect 
visibility established in the CAA. Thus, Executive Order 13132 does not 
apply to this action. In the spirit of Executive Order 13132, and 
consistent with EPA policy to promote communications between EPA and 
State and local governments, EPA specifically solicits comment on this 
proposed rule from State and local officials.

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

    Executive Order 13175, entitled Consultation and Coordination with 
Indian Tribal Governments (65 FR 67249, November 9, 2000), requires EPA 
to develop an accountable process to ensure ``meaningful and timely 
input by tribal officials in the development of regulatory policies 
that have tribal implications.'' This proposed rule does not have 
tribal implications, as specified in Executive Order 13175. It will not 
have substantial direct effects on tribal governments. Thus, Executive 
Order 13175 does not apply to this rule. EPA specifically solicits 
additional comment on this proposed rule from tribal officials.

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

    Executive Order 13045: Protection of Children from Environmental 
Health Risks and Safety Risks (62 FR 19885, April 23, 1997), applies to 
any rule that: (1) is determined to be economically significant as 
defined under Executive Order 12866; and (2) concerns an environmental 
health or safety risk that we have reason to believe may have a 
disproportionate effect on children. If the regulatory action meets 
both criteria, the Agency must evaluate the environmental health or 
safety effects of the planned rule on children, and explain why the 
planned regulation is preferable to other potentially effective and 
reasonably feasible alternatives considered by the Agency. However, to 
the extent this proposed rule will limit emissions of SO2, 
the rule will have a beneficial effect on children's health by reducing 
air pollution.
    This rule is not subject to Executive Order 13045 because it does 
not involve decisions intended to mitigate environmental health or 
safety risks. However, to the extent this proposed rule will limit 
emissions of SO2, the rule will have a beneficial effect on 
children's health by reducing air pollution.

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

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

I. National Technology Transfer and Advancement Act

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

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

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

[[Page 16196]]

minority or low-income population. This proposed rule limits emissions 
of SO2 from three facilities in Oklahoma. The partial 
approval of the SIP, if finalized, merely approves state law as meeting 
Federal requirements and imposes no additional requirements beyond 
those imposed by state law.

List of Subjects in 40 CFR Part 52

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

    Dated: March 4, 2011.
Al Armendariz,
Regional Administrator, Region 6.

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

PART 52--[AMENDED]

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

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

    2. Part 52 is proposed to be amended by adding Sec.  52.1923 to 
read as follows:

Sec.  52.1923  Interstate pollutant transport provisions; What are the 
FIP requirements 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; and Units 3 and 4 of the American Electric Power/Public Service 
Company of Oklahoma Northeastern plant affecting visibility?

    (a) Applicability. The provisions of this section shall apply to 
each owner or operator, or successive owners or operators, of the coal 
burning equipment designated as: Units 4 or 5 of the Oklahoma Gas and 
Electric Muskogee plant; Units 1 or 2 of the Oklahoma Gas and Electric 
Sooner plant; and Units 3 or 4 of the American Electric Power/Public 
Service Company of Oklahoma Northeastern plant.
    (b) Compliance Dates. Compliance with the requirements of this 
section is required within 3 years of the effective date of this rule 
unless otherwise indicated by compliance dates contained in specific 
provisions.
    (c) Definitions. All terms used in this part but not defined herein 
shall have the meaning given them in the Clean Air Act and in parts 51 
and 60 of this title. For the purposes of this section:
    24-hour period means the period of time between 12:01 a.m. and 12 
midnight. Air pollution control equipment includes selective catalytic 
control units, baghouses, particulate or gaseous scrubbers, and any 
other apparatus utilized to control emissions of regulated air 
contaminants which would be emitted to the atmosphere.
    Daily average means the arithmetic average of the hourly values 
measured in a 24-hour period.
    Heat input means heat derived from combustion of fuel in a unit and 
does not include the heat input from preheated combustion air, 
recirculated flue gases, or exhaust gases from other sources. Heat 
input shall be calculated in accordance with 40 CFR part 75.
    Owner or Operator means any person who owns, leases, operates, 
controls, or supervises any of the coal burning equipment designated 
as:
    (i) Unit 4 of the Oklahoma Gas and Electric Muskogee plant; or
    (ii) Unit 5 of the Oklahoma Gas and Electric Muskogee plant; or
    (ii) Unit 1 of the Oklahoma Gas and Electric Sooner plant; or
    (iv) Unit 2 of the Oklahoma Gas and Electric Sooner plant; or
    (v) Unit 3 of the American Electric Power/Public Service Company of 
Oklahoma Northeastern plant; or
    (vi) Unit 4 of the American Electric Power/Public Service Company 
of Oklahoma Northeastern plant.
    Regional Administrator means the Regional Administrator of EPA 
Region 6 or his/her authorized representative.
    Unit means one of the coal fired boilers covered under paragraph 
(a) of this section.
    (d) Emissions Limitations. SO2  emission limit. The 
individual sulfur dioxide emission limit for a unit shall be 0.06 
pounds per million British thermal units (lb/MMBtu) as averaged over a 
rolling 30 calendar day period. For each unit, SO2 emissions 
for each calendar day shall be determined by summing the hourly 
emissions measured in pounds of SO2. For each unit, heat 
input for each calendar day shall be determined by adding together all 
hourly heat inputs, in millions of BTU. Each day the thirty-day rolling 
average for a unit shall be determined by adding together the pounds of 
SO2 from that day and the preceding 29 days and dividing the 
total pounds of SO2 by the sum of the heat input during the 
same 30-day period. The result shall be the 30-day rolling average in 
terms of lb/MMBtu emissions of SO2. If a valid 
SO2 pounds per hour or heat input is not available for any 
hour for a unit, that heat input and SO2 pounds per hour 
shall not be used in the calculation of the 30-day rolling average for 
SO2.
    (e) Testing and monitoring. (1) No later than the compliance date 
of this regulation, the owner or operator shall install, calibrate, 
maintain and operate Continuous Emissions Monitoring Systems (CEMS) for 
SO2 on 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 in accordance with 40 CFR 60.8 
and 60.13(e), (f), and (h), and Appendix B of Part 60. The owner or 
operator shall comply with the quality assurance procedures for CEMS 
found in 40 CFR part 75. Compliance with the emission limits for 
SO2 shall be determined by using data from a CEMS.
    (2) Continuous emissions monitoring shall apply during all periods 
of operation of the coal burning equipment, including periods of 
startup, shutdown, and malfunction, except for CEMS breakdowns, 
repairs, calibration checks, and zero and span adjustments. Continuous 
monitoring systems for measuring SO2 and diluent gas shall 
complete a minimum of one cycle of operation (sampling, analyzing, and 
data recording) for each successive 15-minute period. Hourly averages 
shall be computed using at least one data point in each fifteen minute 
quadrant of an hour. Notwithstanding this requirement, an hourly 
average may be computed from at least two data points separated by a 
minimum of 15 minutes (where the unit operates for more than one 
quadrant in an hour) if data are unavailable as a result of performance 
of calibration, quality assurance, preventive maintenance activities, 
or backups of data from data acquisition and handling system, and 
recertification events. When valid SO2 pounds per hour, or 
SO2 pounds per million Btu emission data are not obtained 
because of continuous monitoring system breakdowns, repairs, 
calibration checks, or zero and span adjustments, emission data must be 
obtained by using other monitoring systems approved by the EPA to 
provide emission data for a minimum of 18 hours in each 24 hour period 
and at least 22 out of 30 successive boiler operating days.
    (f) Reporting and Recordkeeping Requirements. Unless otherwise 
stated all requests, reports, submittals, notifications, and other 
communications to the Regional Administrator required by this section 
shall be submitted, unless instructed otherwise, to the Director, 
Multimedia Planning and Permitting Division, U.S. Environmental 
Protection Agency, Region 6, to the attention of Mail Code: 6PD, at 
1445 Ross Avenue, Suite 1200, Dallas, Texas 75202-2733. For each unit 
subject to the emissions limitation in this section and upon completion 
of the installation of

[[Page 16197]]

CEMS as required in this section, the owner or operator shall comply 
with the following requirements:
    (1) For each emissions limit in this section, comply with the 
notification, reporting, and recordkeeping requirements for CEMS 
compliance monitoring in 40 CFR 60.7(c) and (d).
    (2) For each day, provide the total SO2 emitted that day 
by each emission unit. For any hours on any unit where data for hourly 
pounds or heat input is missing, identify the unit number and 
monitoring device that did not produce valid data that caused the 
missing hour.
    (g) Equipment Operations. At all times, including periods of 
startup, shutdown, and malfunction, the owner or operator shall, to the 
extent practicable, maintain and operate the unit including associated 
air pollution control equipment in a manner consistent with good air 
pollution control practices for minimizing emissions. Determination of 
whether acceptable operating and maintenance procedures are being used 
will be based on information available to the Regional Administrator 
which may include, but is not limited to, monitoring results, review of 
operating and maintenance procedures, and inspection of the unit.
    (h) Enforcement. (1) Notwithstanding any other provision in this 
implementation plan, any credible evidence or information relevant as 
to whether the unit would have been in compliance with applicable 
requirements if the appropriate performance or compliance test had been 
performed, can be used to establish whether or not the owner or 
operator has violated or is in violation of any standard or applicable 
emission limit in the plan.
    (2) Emissions in excess of the level of the applicable emission 
limit or requirement that occur due to a malfunction shall constitute a 
violation of the applicable emission limit.

[FR Doc. 2011-5799 Filed 3-21-11; 8:45 am]
BILLING CODE 6560-50-P
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