[Federal Register Volume 76, Number 55 (Tuesday, March 22, 2011)]
[Proposed Rules]
[Pages 16168-16197]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2011-5799]
[[Page 16167]]
Vol. 76
Tuesday,
No. 55
March 22, 2011
Part III
Environmental Protection Agency
-----------------------------------------------------------------------
40 CFR Part 52
Approval and Promulgation of Implementation Plans; Oklahoma; Regional
Haze State Implementation Plan; Federal Implementation Plan for
Interstate Transport of Pollution Affecting Visibility and Best
Available Retrofit Technology Determinations; Proposed Rule
Federal Register / Vol. 76 , No. 55 / Tuesday, March 22, 2011 /
Proposed Rules
[[Page 16168]]
-----------------------------------------------------------------------
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 52
[EPA-R06-OAR-2010-0190; FRL-9279-7]
Approval and Promulgation of Implementation Plans; Oklahoma;
Regional Haze State Implementation Plan; Federal Implementation Plan
for Interstate Transport of Pollution Affecting Visibility and Best
Available Retrofit Technology Determinations
AGENCY: Environmental Protection Agency (EPA).
ACTION: Proposed rule.
-----------------------------------------------------------------------
SUMMARY: EPA is proposing to partially approve and partially disapprove
a revision to the Oklahoma State Implementation Plan (SIP) submitted by
the State of Oklahoma through the Oklahoma Department of Environmental
Quality (ODEQ) on February 19, 2010 that addresses regional haze for
the first implementation period. This revision was submitted to address
the requirements of the Clean Air Act (CAA or Act) and our rules that
require states to prevent any future and remedy any existing man-made
impairment of visibility in mandatory Class I areas caused by emissions
of air pollutants from numerous sources located over a wide geographic
area (also referred to as the ``regional haze program''). States are
required to assure reasonable progress toward the national goal of
achieving natural visibility conditions in Class I areas. EPA is
proposing to approve a portion of this SIP revision as meeting certain
requirements of the regional haze program and to partially approve and
partially disapprove those portions addressing the requirements for
best available retrofit technology (BART) and the long-term strategy
(LTS). EPA is proposing a Federal Implementation Plan (FIP) to
implement sulfur dioxide (SO2) emission limits on six
sources to address these issues. EPA also is proposing to disapprove
the State's submitted alternative to BART; EPA is taking no action on
the submitted reasonable progress goals at this time. In addition, EPA
is proposing to partially approve and partially disapprove a portion of
a revision to the Oklahoma SIP submitted by the State of Oklahoma on
May 10, 2007 and supplemented on December 10, 2007. We are taking
action on that portion of the submittals addressing the requirements of
CAA as it applies to visibility for the 1997 8-hour ozone and 1997
particulate matter (PM2.5) National Ambient Air Quality
Standards (NAAQS). This portion of the submittals addresses the
requirement that Oklahoma's SIP contain adequate provisions to prohibit
emissions from interfering with measures required in another state to
protect visibility. In this action, we propose a FIP to address the
deficiencies in this portion of Oklahoma's SIP submittals. The proposed
FIP will prevent emissions from six Oklahoma sources from interfering
with other states' measures to protect visibility and to implement
sulfur dioxide emission limits on these six sources to prevent such
interference.
DATES: Comments: Comments must be received on or before May 23, 2011.
Public Hearing. An open house and public hearing for this proposal
is scheduled to be held on Wednesday April 13, 2011, at the Metro
Technology Centers, Springlake Campus, Business Conference Center,
Meeting Rooms H and I, 1900 Springlake Drive, Oklahoma City, OK 73111,
(405) 424-8324. The Metro Technology Centers Springlake Campus is
located at the intersection of Martin Luther King Ave. and Springlake
Dr. between NE. 36th and NE. 50th just south of the Oklahoma City Zoo
and Kirkpatrick Center. Parking for the Business Conference Center is
available at no charge. The open house will begin at 1 p.m. and end at
3 p.m. local time. The public hearing will be held from 4 p.m. until 6
p.m., and again from 7 p.m. until 9 p.m.
The public hearing will provide interested parties the opportunity
to present information and opinions to EPA concerning our proposal.
Interested parties may also submit written comments, as discussed in
the proposal. Written statements and supporting information submitted
during the comment period will be considered with the same weight as
any oral comments and supporting information presented at the public
hearing. We will not respond to comments during the public hearing.
When we publish our final action, we will provide written responses to
all oral and written comments received on our proposal. To provide
opportunities for questions and discussion, we will hold an open house
prior to the public hearing. During the open house, EPA staff will be
available to informally answer questions on our proposed action. Any
comments made to EPA staff during the open house must still be provided
formally in writing or orally during the public hearing in order to be
considered in the record.
At the public hearing, the hearing officer may limit the time
available for each commenter to address the proposal to 5 minutes or
less if the hearing officer determines it to be appropriate. We will
not be providing equipment for commenters to show overhead slides or
make computerized slide presentations. Any person may provide written
or oral comments and data pertaining to our proposal at the Public
Hearing. Verbatim transcripts, in English, of the hearing and written
statements will be included in the rulemaking docket.
Addresses: Submit your comments, identified by Docket No. EPA-R06-
OAR-2010-0190, by one of the following methods:
Federal e-Rulemaking Portal: http://www.regulations.gov.
Follow the online instructions for submitting comments.
E-mail: [email protected].
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 [email protected].
SUPPLEMENTARY INFORMATION: Throughout this document wherever ``we,''
``us,'' or ``our'' is used, we mean the EPA.
This action is being taken under section 110 and part C of the CAA.
Table of Contents
I. Overview of Proposed Actions
A. Regional Haze
B. Interstate Transport of Visibility
II. SIP and FIP Background
III. What is the background for our proposed actions?
A. Regional Haze
B. Roles of Agencies in Addressing Regional Haze
C. The 1997 NAAQS for Ozone and PM2.5 and CAA
110(a)(2)(D)(i)
IV. What are the requirements for regional haze SIPs?
A. The CAA and the Regional Haze Rule
B. Determination of Baseline, Natural, and Current Visibility
Conditions
C. Determination of Reasonable Progress Goals
D. Best Available Retrofit Technology
E. Long-Term Strategy
F. Coordinating Regional Haze and Reasonably Attributable
Visibility Impairment
G. Monitoring Strategy and Other SIP Requirements
H. Consultation With States and Federal Land Managers
V. Our Analysis of Oklahoma's Regional Haze SIP
A. Affected Class I Areas
B. Determination of Baseline, Natural and Current Visibility
Conditions
1. Estimating Natural Visibility Conditions
2. Estimating Baseline Visibility Conditions
3. Natural Visibility Impairment
4. Uniform Rate of Progress
C. Evaluation of Oklahoma's Reasonable Progress Goal
1. Establishment of the Reasonable Progress Goal
2. ODEQ's Reasonable Progress ``Four Factor'' Analysis
3. Reasonable Progress Consultation
D. Evaluation of Oklahoma's BART Determinations
1. Identification of BART-Eligible Sources
2. Identification of Sources Subject to BART
a. Modeling Methodology
b. Contribution Threshold
c. BART Sources Exempted Due to Permit Modifications
d. Sources Identified by ODEQ as Subject to BART
3. BART Determinations
a. OG&E Seminole Units 1, 2, and 3 BART Determinations
b. OG&E Sooner Units 1 and 2 BART Determinations
c. OG&E Muskogee Units 4 and 5 BART Determinations
d. AEP/PSO Comanche Units 1 and 2 BART Determinations
e. AEP/PSO Northeastern Unit 2, 3, and 4 BART Determination
f. AEP/PSO Southwestern Unit 3 BART Determination
g. ODEQ BART Results and Summary
E. Evaluation of ODEQ's SO2 BART Determinations for
the OG&E and AEP/PSO Coal Fired Power Plant Units
1. Cost Effectiveness
a. Dry Scrubbing Cost Analyses
b. Wet Scrubbing Cost Analyses
2. Visibility Benefit
3. Our Conclusion on Oklahoma's SO2 BART Evaluations
for the Six OG&E and AEP/PSO Units
4. Alternative BART Determination
F. Federal Implementation Plan To Address SO2 BART
for the Six Sources
1. Introduction
2. Appropriate Emission Limits
a. Dry Scrubber Emission Limit
b. Wet Scrubber Emission Limit
3. Visibility Benefit From Dry and Wet Scrubbing
4. EPA's SO2 BART Determination for the Six Units
G. Long-Term Strategy
1. Emissions Inventory
a. Oklahoma's 2002 Emission Inventory
b. Oklahoma's 2018 Emission Inventory
2. Visibility Projection Modeling
3. Consultation and Emissions Reductions for Other States' Class
I Areas
4. Mandatory Long Term Strategy Factors
H. Coordination of RAVI and Regional Haze Requirements
I. Monitoring Strategy and Other SIP Requirements
J. Federal Land Manager Coordination
K. Periodic SIP Revisions and Five-Year Progress Reports
VI. Our Analysis of Oklahoma's Interstate Visibility Transport SIP
Provisions
VII. Proposed Actions
A. Regional Haze
B. Interstate Transport and Visibility
VIII. Statutory and Executive Order Reviews
I. Overview of Proposed Actions
A. Regional Haze
We propose to partially approve and partially disapprove Oklahoma's
regional haze (RH) SIP revision submitted on February 19, 2010.
Specifically, we propose to disapprove the SO2 BART
determinations for Units 4 and 5 of the Oklahoma Gas and Electric
(OG&E) Muskogee plant; Units 1 and 2 of the OG&E Sooner plant; and
Units 3 and 4 of the American Electric Power/Public Service Company of
Oklahoma (AEP/PSO) Northeastern plant. We propose to disapprove these
SO2 BART determinations because they do not comply with our
regulations under 40 CFR 51.308(e).
We are also proposing to disapprove the long term strategy (LTS)
under section 51.308(d)(3) because Oklahoma has not shown that the
strategy is adequate to achieve the reasonable progress goals set by
Oklahoma and by other nearby States. The visibility modeling used by
Oklahoma in support of its SIP revision submittal assumed
SO2 reductions from the six sources \1\ as identified above
that Oklahoma did not secure when making its BART determinations for
these sources. As we discuss elsewhere, ODEQ participated in the
Central Regional Air Planning Association (CENRAP) visibility modeling
development that assumed certain SO2 reductions from these
six BART sources. ODEQ also performed its consultations with other
states with the understanding that these reductions would be secured.
We propose a FIP to cure these defects in BART and the LTS.
---------------------------------------------------------------------------
\1\ In this document, when we say ``six BART sources,'' or ``six
sources,'' we mean Units 4 and 5 of the Oklahoma Gas and Electric
Muskogee plant; Units 1 and 2 of the Oklahoma Gas and Electric
Sooner plant; and Units 3 and 4 of the American Electric Power/
Public Service Company of Oklahoma Northeastern plant.
---------------------------------------------------------------------------
[[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.
---------------------------------------------------------------------------
\2\ Visual range is the greatest distance, in kilometers or
miles, at which a dark object can be viewed against the sky.
---------------------------------------------------------------------------
In section 169A of the 1977 Amendments to the CAA, Congress created
a program for protecting visibility in the nation's national parks and
wilderness areas. This section of the CAA establishes as a national
goal the ``prevention of any future, and the remedying of any existing,
impairment of visibility in mandatory Class I Federal areas \3\ which
impairment results from manmade air pollution.'' CAA Sec. 169A(a)(1).
The terms ``impairment of visibility'' and ``visibility impairment''
are defined in the Act to include a reduction in visual range and
atmospheric discoloration. Id. section 169A(g)(6). In 1980, we
promulgated regulations to address visibility impairment in Class I
areas that is ``reasonably attributable'' to a single source or small
group of sources, i.e., ``reasonably attributable visibility
impairment'' (RAVI). 45 FR 80084 (December 2, 1980). These regulations
represented the first phase in addressing visibility impairment. We
deferred action on RH that emanates from a variety of sources until
monitoring, modeling and scientific knowledge about the relationships
between pollutants and visibility impairment were improved.
---------------------------------------------------------------------------
\3\ Areas designated as mandatory Class I Federal areas consist
of national parks exceeding 6000 acres, wilderness areas and
national memorial parks exceeding 5000 acres, and all international
parks that were in existence on August 7, 1977. See CAA section
162(a). In accordance with section 169A of the CAA, EPA, in
consultation with the Department of Interior, promulgated a list of
156 areas where visibility is identified as an important value. See
44 FR 69122, November 30, 1979. The extent of a mandatory Class I
area includes subsequent changes in boundaries, such as park
expansions. CAA section 162(a). Although states and tribes may
designate as Class I additional areas which they consider to have
visibility as an important value, the requirements of the visibility
program set forth in section 169A of the CAA apply only to
``mandatory Class I Federal areas.'' Each mandatory Class I Federal
area is the responsibility of a ``Federal Land Manager'' (FLM). See
CAA section 302(i). When we use the term ``Class I area'' in this
action, we mean a ``mandatory Class I Federal area.''
---------------------------------------------------------------------------
Congress added section 169B to the CAA in 1990 to address RH
issues, and we promulgated regulations addressing RH in 1999. 64 FR
35714 (July 1, 1999), codified at 40 CFR part 51, subpart P. The
Regional Haze Rule (RHR) revised the existing visibility regulations to
integrate into the regulations provisions addressing RH impairment and
established a comprehensive visibility protection program for Class I
areas. The requirements for RH, found at 40 CFR 51.308 and 51.309, are
included in our visibility protection regulations at 40 CFR 51.300-309.
Some of the main elements of the RH requirements are summarized in
section III. The requirement to submit a RH SIP applies to all 50
states, the District of Columbia and the Virgin Islands.\4\ States were
required to submit the first implementation plan addressing RH
visibility impairment no later than December 17, 2007. 40 CFR
51.308(b).
---------------------------------------------------------------------------
\4\ Albuquerque/Bernalillo County in New Mexico must also submit
a regional haze SIP to completely satisfy the requirements of
section 110(a)(2)(D) of the CAA for the entire State of New Mexico
under the New Mexico Air Quality Control Act (section 74-2-4).
---------------------------------------------------------------------------
B. Roles of Agencies in Addressing Regional Haze
Successful implementation of the RH program will require long-term
regional coordination among states, tribal governments and various
federal agencies. As noted above, pollution affecting the air quality
in Class I areas can be transported over long distances, even hundreds
of kilometers. Therefore, to address effectively the problem of
visibility impairment in Class I areas, states need to develop
strategies in coordination with one another, taking into account the
effect of emissions from one jurisdiction on the air quality in
another.
Because the pollutants that lead to RH can originate from sources
located across broad geographic areas, we have encouraged the states
and tribes across the United States to address visibility impairment
from a regional perspective. Five regional planning organizations
(RPOs) were developed to address RH and related issues. The RPOs first
evaluated technical information to better understand how their states
and tribes impact Class I areas across the country, and then pursued
the development of regional strategies to reduce emissions of
particulate matter (PM) and other pollutants leading to RH.
CENRAP is an organization of states, tribes, federal agencies and
other interested parties that identifies RH and visibility issues and
develops strategies to address them. CENRAP is one of the five Regional
Planning Organizations RPOs across the U.S. and includes the states and
tribal areas of Nebraska, Kansas, Oklahoma, Texas, Minnesota, Iowa,
Missouri, Arkansas, and Louisiana.
C. The 1997 NAAQS for Ozone and PM2.5 and CAA
110(a)(2)(D)(i)
On July 18, 1997, we promulgated new NAAQS for 8-hour ozone and for
PM2.5. 62 FR 38652. Section 110(a)(1) of the CAA requires
states to submit SIPs to address a new or revised NAAQS within 3 years
after promulgation of such standards, or within such shorter period as
we may prescribe. Section 110(a)(2) of the CAA lists the elements that
such new SIPs must address, as applicable, including section
110(a)(2)(D)(i), which pertains to the interstate transport of certain
emissions.
On April 25, 2005, we published a ``Finding of Failure to Submit
SIPs for Interstate Transport for the 8-hour Ozone and PM2.5
NAAQS.'' 70 FR 21147. This included a finding that Oklahoma and other
states had failed to submit SIPs for interstate transport of air
pollution affecting visibility, and started a 2-year clock for the
promulgation of a FIP by us, unless a state made a submission to meet
the requirements of section 110(a)(2)(D)(i) and we approved the
submission. Id.
On August 15, 2006, we issued our ``Guidance for State
Implementation Plan (SIP) Submission to Meet Current Outstanding
Obligations Under Section 110(a)(2)(D)(i) for the 8-Hour Ozone and
PM2.5 National Ambient Air Quality Standards'' (2006
Guidance). We developed the 2006 Guidance to make recommendations to
states for making submissions to meet the requirements of section
110(a)(2)(D)(i) for the 1997 8-hour ozone standards and the 1997
PM2.5 standards.
As identified in the 2006 Guidance, the ``good neighbor''
provisions in section 110(a)(2)(D)(i) of the CAA require each state to
submit a SIP that prohibits emissions that adversely affect another
state in the ways contemplated
[[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\
---------------------------------------------------------------------------
\5\ The preamble to the RHR provides additional details about
the deciview. 64 FR 35714, 35725 (July 1, 1999).
---------------------------------------------------------------------------
The deciview is used in expressing Reasonable Progress Goals (RPGs)
(which are interim visibility goals towards meeting the national
visibility goal), defining baseline, current, and natural conditions,
and tracking changes in visibility. The RH SIPs must contain measures
that ensure ``reasonable progress'' toward the national goal of
preventing and remedying visibility impairment in Class I areas caused
by manmade air pollution by reducing anthropogenic emissions that cause
RH. The national goal is a return to natural conditions, i.e., manmade
sources of air pollution would no longer impair visibility in Class I
areas.
To track changes in visibility over time at each of the 156 Class I
areas covered by the visibility program (40 CFR 81.401-437), and as
part of the process for determining reasonable progress, states must
calculate the degree of existing visibility impairment at each Class I
area at the time of each RH SIP submittal and periodically review
progress every five years midway through each 10-year implementation
period. To do this, the RHR requires states to determine the degree of
impairment (in deciviews) for the average of the 20 percent least
impaired (``best'') and 20 percent most impaired (``worst'') visibility
days over a specified time period at each of their Class I areas. In
addition, states must also develop an estimate of natural visibility
conditions for the purpose of comparing progress toward the national
goal. Natural visibility is determined by estimating the natural
concentrations of pollutants that cause visibility impairment and then
calculating total light extinction based on those estimates. We have
provided guidance to states regarding how to calculate baseline,
natural and current visibility conditions.\6\
---------------------------------------------------------------------------
\6\ Guidance for Estimating Natural Visibility Conditions Under
the Regional Haze Rule, September 2003, EPA-454/B-03-005, available
at http://www.epa.gov/ttncaaa1/t1/memoranda/rh_envcurhr_gd.pdf
(hereinafter referred to as ``our 2003 Natural Visibility
Guidance''); and Guidance for Tracking Progress Under the Regional
Haze Rule, EPA-454/B-03-004, September 2003, available at http://www.epa.gov/ttncaaa1/t1/memoranda/rh_tpurhr_gd.pdf (hereinafter
referred to as our ``2003 Tracking Progress Guidance'').
---------------------------------------------------------------------------
For the first RH SIPs that were due by December 17, 2007,
``baseline visibility conditions'' were the starting points for
assessing ``current'' visibility impairment. Baseline visibility
conditions represent the degree of visibility impairment for the 20
percent least impaired days and 20 percent most impaired days for each
calendar year from 2000 to 2004. Using monitoring data for 2000 through
2004, states are required to calculate the average degree of visibility
impairment for each Class I area, based on the average of annual values
over the five-year period. The comparison of initial baseline
visibility conditions to natural visibility conditions indicates the
amount of improvement necessary to attain natural visibility, while the
future comparison of baseline conditions to the then current conditions
will indicate the amount of progress made. In general, the 2000-2004
baseline period is considered the time from which improvement in
visibility is measured.
C. Determination of Reasonable Progress Goals
The vehicle for ensuring continuing progress towards achieving the
natural visibility goal is the submission of a series of RH SIPs from
the states that establish two RPGs (i.e., two distinct goals, one for
the ``best'' and one for the ``worst'' days) for every Class I area for
each (approximately) 10-year implementation period. See 70 FR 3915;
[[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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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