Document ID: EPA-R06-OAR-2010-0190-0056
Agency: epa
Document Type: Rule
Title: OK011.0165 Approvals and Promulgations of Implementation Plans: Oklahoma; Federal Implementation Plan for Interstate Transport of Pollution Affecting Visibility and Best Available Retrofit Technology Determinations. 32 pages rzu
Posted Date: 2011-12-28T05:00Z

[Federal Register Volume 76, Number 249 (Wednesday, December 28, 2011)]
[Rules and Regulations]
[Pages 81728-81759]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2011-32572]

[[Page 81727]]

Vol. 76

Wednesday,

No. 249

December 28, 2011

Part IV

Environmental Protection Agency

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40 CFR Part 52

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

  Federal Register / Vol. 76 , No. 249 / Wednesday, December 28, 2011 / 
Rules and Regulations  

[[Page 81728]]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 52

[EPA-R06-OAR-2010-0190; FRL-9608-4]

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

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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SUMMARY: EPA is partially approving and partially disapproving a 
revision to the Oklahoma State Implementation Plan (SIP) submitted by 
the State of Oklahoma through the Oklahoma Department of Environmental 
Quality on February 19, 2010, intended to address the regional haze 
requirements of the Clean Air Act (CAA). In addition, EPA is partially 
approving and partially disapproving 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 to address the requirements of CAA 
section 110(a)(2)(D)(i)(II) as it applies to visibility for the 1997 8-
hour ozone and 1997 fine particulate matter National Ambient Air 
Quality Standards. This CAA requirement is intended to prevent 
emissions from one state from interfering with the visibility programs 
in another state. EPA is approving certain core elements of the SIP 
including Oklahoma's: determination of baseline and natural visibility 
conditions; coordinating regional haze and reasonably attributable 
visibility impairment; monitoring strategy and other implementation 
requirements; coordination with states and Federal Land Managers; and a 
number of NOX, SO2, and PM BART determinations. 
EPA is finding that Oklahoma's regional haze SIP did not address the 
sulfur dioxide Best Available Retrofit Technology requirements for six 
units in Oklahoma in accordance with the Regional Haze requirements, or 
the requirement to prevent interference with other states' visibility 
programs. EPA is promulgating a Federal Implementation Plan to address 
these deficiencies by requiring emissions to be reduced at these six 
units. This action is being taken under section 110 and part C of the 
CAA.

DATES: This final rule is effective on: January 27, 2012.

ADDRESSES: EPA has established a docket for this action under Docket ID 
No. EPA-R06-OAR-2010-0190. All documents in the docket are listed in 
the Federal eRulemaking portal index at http://www.regulations.gov and 
are available either electronically at http://www.regulations.gov or in 
hard copy at EPA Region 6, 1445 Ross Ave., Dallas, TX, 75202-2733. To 
inspect the hard copy materials, please schedule an appointment during 
normal business hours with the contact listed in the FOR FURTHER 
INFORMATION CONTACT section. A reasonable fee may be charged for 
copies.

FOR FURTHER INFORMATION CONTACT: Joe Kordzi, EPA Region 6, (214) 665-
7186, kordzi.joe@epa.gov.

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

Overview

    The CAA requires that states develop and implement SIPs to reduce 
the pollution that causes visibility impairment over a wide geographic 
area, known as Regional Haze (RH). CAA sections 110(a) and 169A. 
Oklahoma submitted a RH plan to us on February 19, 2010. On March 22, 
2011, we proposed to partially approve and partially disapprove certain 
elements of Oklahoma's SIP. 76 FR 16168. Today, we are taking final 
action by partially approving and partially disapproving the elements 
of Oklahoma's RH SIP addressed in our proposed rule. As discussed in 
the proposal for this rule, the CAA requires us to promulgate a Federal 
Implementation Plan (FIP) if a state fails to make a required SIP 
submittal or we find that the state's submittal is incomplete or 
unapprovable. CAA section 110(c)(1). Therefore, we are promulgating a 
FIP to address the deficiencies in Oklahoma's RH plan.
    One important element of the RH requirements of the CAA is that the 
Best Available Retrofit Technology (BART) must be selected and 
implemented for certain 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. Second, states 
determine whether such sources ``emit 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''). Third, for each source subject to BART, states 
then identify the appropriate type and the level of control for 
reducing emissions,'' by conducting a five-step analysis: Step 1: 
Identify All Available Retrofit Control Technologies, Step 2: Eliminate 
Technically Infeasible Options, Step 3: Evaluate Control Effectiveness 
of Remaining Control Technologies, Step 4: Evaluate Impacts and 
Document the Results, and Step 5: Evaluate Visibility Impacts.
    We agree with Oklahoma's identification of sources that are BART 
eligible and subject to BART. In addition, we are approving a number of 
BART determinations from Oklahoma's RH SIP. We are not able to approve 
Oklahoma's sulfur dioxide (SO2) BART determinations for the 
OG&E's Sooner Units 1 and 2, the OG&E Muskogee Units 4 and 5, and the 
AEP/PSO Northeastern Units 3 and 4. In reviewing the SO2 
BART determinations for these six units,\1\ we noted the state's cost 
estimates for SO2 scrubbers were high in comparison to other 
similar units, and we therefore separately assessed the costs of 
installation of controls for these units using well established costing 
methodologies for BART determinations. As a result of this review, we 
proposed disapproval of the Oklahoma's SO2 BART 
determinations for these six units because the Oklahoma's costing 
methodology was not in accordance with RH requirements. Consistent with 
the disparity in cost estimations we identified in our proposed 
disapproval, our revised cost estimate indicates that dry scrubber 
control technology is about \1/2\ to \3/4\ less expensive than was 
calculated by Oklahoma. We have therefore determined it is appropriate 
to finalize our proposed disapproval of the Oklahoma's SO2 
BART determinations for the six units, because we conclude that the 
flaws in the state's cost estimations were significant, and that the 
state therefore lacked adequate record support and a reasoned basis for 
its determinations regarding the cost effectiveness of controls as 
needed for the final steps of the BART analysis and as required by the 
RH Rule (RHR). We are also disapproving the state's submitted Long Term 
Strategy because it relies on these BART limits which we are 
disapproving. We will of course consider, and would prefer, approving a 
SIP if the state submits a revised plan for these units that we can 
approve.
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    \1\ When we say ``six BART sources,'' or ``six units,'' we mean 
Units 4 and 5 of the Oklahoma Gas and Electric Muskogee plant in 
Muskogee County; Units 1 and 2 of the Oklahoma Gas and Electric 
Sooner plant in Noble County; and Units 3 and 4 of the American 
Electric Power/Public Service Company of Oklahoma Northeastern plant 
in Rogers County.

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[[Page 81729]]

    We are approving the remaining sections of the RH SIP submission. 
This includes certain core elements of the SIP including Oklahoma's (1) 
determination of baseline and natural visibility conditions, (2) 
coordinating regional haze and reasonably attributable visibility 
impairment, (3) monitoring strategy and other implementation 
requirements, (4) coordination with states and Federal Land Managers, 
and (5) the following BART determinations from Oklahoma's RH SIP:
     The SO2, nitrogen oxides (NOX), and 
particulate matter (PM) BART determinations for the Oklahoma Gas and 
Electric (OG&E) Seminole Units 1, 2, and 3.
     The NOX and PM BART determinations for OG&E's 
Sooner Units 1 and 2.
     The NOX and PM BART determinations for the OG&E 
Muskogee Units 4 and 5.
     The SO2, NOX, and PM BART 
determinations for the American Electric Power/Public Service Company 
of Oklahoma (AEP/PSO) Comanche Units 1 and 2.
     The SO2, NOX, and PM BART 
determinations for the AEP/PSO Northeastern Unit 2.
     The NOX and PM BART determination for the AEP/
PSO Northeastern Units 3 and 4.
     The SO2, NOX, and PM BART 
determination for the AEP/PSO Southwestern Unit 3.
    In addition to the Regional Haze Requirements, CAA section 
110(a)(2)(D)(i)(II) requires that the Oklahoma SIP ensure that 
emissions from sources within Oklahoma do not interfere with measures 
required in the SIP of any other state under part C of the CAA to 
protect visibility. This requirement is commonly referred to as the 
visibility prong of ``interstate transport,'' which is also called the 
``good neighbor'' provision of the CAA. Oklahoma submitted a SIP to 
meet the requirements of interstate transport for the 1997 8-hour ozone 
National Ambient Air Quality Standards (NAAQS) and the fine particulate 
matter (PM2.5) NAAQS on May 10, 2007, and supplemented it on 
December 10, 2007. In the May 10, 2007, submittal, Oklahoma stated that 
it intended for its RH submittal to satisfy the requirements of the 
visibility prong. We proposed to partially approve and partially 
disapprove this submission as it relied upon the Regional Haze SIP that 
we were proposing to partially approve and partially disapprove. In 
evaluating whether Oklahoma's SIP ensures that emissions from sources 
within Oklahoma do not interfere with the visibility programs of other 
states, we found that the regional modeling conducted by the Central 
Regional Air Programs (CENRAP), participated in by Oklahoma, included 
reductions at the six units that were not required by the Oklahoma SIP. 
Since this modeling was used by other states and Oklahoma in 
establishing their Reasonable Progress Goals, we find that the Oklahoma 
SIP does not ensure that emissions from sources within Oklahoma do not 
interfere with measures required in the SIP of any other state under 
Part C of the CAA to protect visibility.
    To address the deficiencies identified in our disapproval of these 
SO2 BART determinations and the disapproval of the SIP 
submission as it pertains to the visibility prong of interstate 
transport, we are finalizing a FIP to control emissions from the six 
units. Our FIP requires that these six units reduce emissions of 
SO2 to improve the scenic views at four national parks and 
wilderness areas: the Caney Creek and Upper Buffalo Wilderness Areas in 
Arkansas, the Wichita Mountains National Wildlife Refuge in Oklahoma, 
and the Hercules Glades Wilderness Area in Missouri. Improved air 
quality also results in public health benefits. This FIP can be 
replaced by a future state plan that meets the applicable CAA 
requirements.
    All six units are coal-fired electricity generating units. Our FIP 
requires the six units to reduce their SO2 pollution to an 
emission rate of 0.06 pounds per million BTU, calculated on the basis 
of a rolling 30 boiler operating day average. This can be accomplished 
by retrofitting the six units with dry flue gas desulfurization 
technology, commonly known as ``SO2 scrubbers.'' In 
addition, any technology that can meet this SO2 emission 
limit may be implemented at the six subject units. For example, EPA 
believes that these limits can also be met by wet scrubbing technology 
or switching to natural gas.
    We held a 60 day public comment period on this action, and an open 
house and a public hearing in both Tulsa and Oklahoma City. Many public 
commenters disagreed with aspects of our cost analysis for 
SO2 BART for the six affected units. After careful review of 
information provided during the public comment period, we revised our 
calculation of the total project cost for the four OG&E units from our 
proposed range of approximately $312,423,000 to $605,685,000, to our 
final range of approximately $589,237,000 to $607,461,000. We made no 
changes to the cost basis for the two AEP/PSO units from our proposal. 
As such, the associated cost investment for AEP/PSO is $274,100,000. 
Even with these changes to our cost analysis we conclude that we cannot 
approve the SIP's SO2 emission limits and instead must adopt 
the proposed emission limits for the six units. However, in 
consideration of comments about the time needed to comply with our FIP, 
we have extended the time for compliance with the SO2 
emission limit from the proposed three years to five years.
    This investment will reduce the visibility impacts due to these 
facilities by over 60 to 80% at each one of the four national parks and 
wilderness areas in the area, and promote local tourism by decreasing 
the number of days when pollution impairs scenic views. Although 
today's action is taken to address visibility impairments, we believe 
it will also reduce public health impacts by decreasing SO2 
pollution by approximately 95%.
    This action is being taken under section 110 and part C of the CAA.

Table of Contents

I. Summary of Our Proposal
    A. Regional Haze
    B. Interstate Transport of Pollutants and Visibility Protection
II. Final Decision
    A. Regional Haze
    B. Interstate Transport of Pollutants and Visibility Protection
    C. Compliance Timeframe
III. Analysis of Major Issues Raised by Commenters
    A. Comments Generally Favoring Our Proposal
    B. Comments Generally Against Our Proposal
    C. Comments on Legal Issues
    1. General Legal Comments
    2. Comments Asking EPA To Consider All Rules
    3. Comments on Interstate Transport
    D. Comments on Modeling
    E. Summary of Responses to Comments on the SO2 BART 
Cost Calculation
    1. Control Cost Manual Methodology
    2. Revised Cost Calculations for the OG&E Units
    3. Cost Calculations for the AEP/PSO Units
    4. Conclusion
    F. Summary of Responses to Visibility Improvement Analysis 
Comments
    G. Summary of Responses to Comments Received on the 
SO2 BART Emission Limit
    H. Summary of Responses to Comments Received on the 
SO2 BART Compliance Timeframe
    I. Comments Supporting Conversion to Natural Gas and/or 
Renewable Energy Sources
    J. Comments Arguing Our Proposal Would Hurt the Economy and/or 
Raise Electricity Rates
    K. Comments Arguing Our Proposal Would Help the Economy
    L. Comments on Health and Ecosystem Benefits and Other 
Pollutants

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    M. Miscellaneous Comments
IV. Statutory and Executive Order Reviews

I. Summary of Our Proposal

    On March 22, 2011, we published the proposal on which we are now 
taking final action. 76 FR 16168. We proposed to partially approve and 
partially disapprove Oklahoma's RH SIP revision submitted on February 
19, 2010. We also proposed 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)(II) with respect to visibility for the 1997 8-
hour ozone NAAQS and the PM2.5 NAAQS.

A. Regional Haze

    We proposed to approve Oklahoma's determination 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). However, we proposed to disapprove 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 plant because they do not comply with our 
regulations under 40 CFR 51.308(e). We also proposed 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 Oklahoma used to support its SIP revision submittal 
assumed SO2 reductions from the six sources identified above 
that Oklahoma did not secure when making its BART determinations for 
these sources. The Oklahoma Department of Environmental Quality (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 consulted with other 
states with the understanding that these reductions would be secured. 
We proposed a FIP to address these defects in BART and the LTS.
    We proposed a FIP that included SO2 BART emission limits 
on these sources. We proposed 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 
individually to each of these units on a rolling 30 day calendar 
average. Additionally, we proposed monitoring, recordkeeping, and 
reporting requirements to ensure compliance with these emission 
limitations. We proposed that compliance with the emission limits be 
within three years of the effective date of our final rule. We 
solicited comments on alternative timeframes, of from two years up to 
five years from the effective date of our final rule. We also proposed 
that, 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), conversion should be completed within the same 
time frame. We solicited comments as to, considering the engineering 
and/or management challenges of such a fuel switch, whether the full 
five years allowed under section 51.308(e)(1)(iv) following our final 
approval would be appropriate.
    We proposed to disapprove section VI.E of the Oklahoma RH SIP 
entitled, ``Greater Reasonable Progress Alternative Determination.'' We 
also proposed 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 proposed 
that these portions of the submittal are severable from the BART 
determinations and the LTS. These alternative determinations are not 
fundamental requirements of a RH program, so disapproval of them does 
not create a regulatory gap in the SIP. Therefore, no FIP is required.
    We proposed 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).
    We also proposed to approve the remaining sections of the RH SIP 
submission.

B. Interstate Transport of Pollutants and Visibility Protection

    We proposed 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) with respect to visibility for the 1997 8-hour ozone 
NAAQS and the PM2.5 NAAQS. This proposal addressed 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.
    Having proposed to disapprove these provisions of the Oklahoma SIP, 
we proposed a FIP to address the requirements of section 
110(a)(2)(D)(i)(II) with respect to visibility to ensure that emissions 
from sources in Oklahoma do not interfere with the visibility programs 
of other states. We proposed to find that the controls proposed under 
the proposed FIP, in combination with the controls required by the 
portion of the Oklahoma RH submittal that we proposed to approve, will 
serve to prevent sources in Oklahoma from emitting pollutants in 
amounts that will interfere with efforts to protect visibility in other 
states.

II. Final Decision

A. Regional Haze

    We are partially approving, partially disapproving, and taking no 
action on various portions of Oklahoma's RH SIP revision submitted on 
February 19, 2010. We are finalizing a FIP to address the defects in 
those portions of this SIP that are mandatory requirements that we are 
disapproving.
    We are disapproving the SO2 BART determinations for 
Units 4 and 5 of the Oklahoma 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. 
We are disapproving the LTS under section 51.308(d)(3).
    We are finalizing a FIP that specifically imposes SO2 
BART emission limits on these sources. We find 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 
individually to each of these units. As we discuss elsewhere in this 
action and in a supplemental response to comments document 
(Supplemental RTC),\2\ we find there is ample support for this 
decision. However, in response to a comment we received, we are 
changing our proposed averaging period for these emission limits from a 
straight

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rolling 30 day calendar average to one calculated on the basis of a 
boiler operating day (BOD). We also received a comment requesting that 
we revise our proposed unit-by-unit SO2 limit, and replace 
it with a plant wide average SO2 limit. As we note in our 
response to this comment, although we are open to combining the BOD and 
plant wide averaging techniques, this presents a significant technical 
challenge in having a verifiable, workable, and enforceable algorithm 
for calculating such an average. Due to our obligation to ensure the 
enforceability of the emission limits we are imposing in our FIP and 
the technical challenges of meeting that obligation through a plant 
wide limit, we are not including a plant wide average SO2 
limit in our final FIP. We leave it to Oklahoma to take up this matter 
in a future SIP revision, should it decide to do so. We are confident 
that this issue can be addressed prior to the installation of the 
emission controls required to satisfy our FIP.
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    \2\ The full title of the Supplemental RTC document is the 
``Response to Technical Comments for Sections E through H of the 
Federal Register Notice for the Oklahoma Regional Haze and 
Visibility Transport FIP,'' and it is available in the docket for 
this rulemaking. This document is referred to as the ``Supplemental 
RTC'' throughout this rulemaking. We received many lengthy, and 
highly technical, comments concerning our SO2 BART cost 
analysis, the visibility improvement analysis, the emission limit, 
and the compliance timeframe. While this notice generally addresses 
all of the issues commenters raised, the Supplemental RTC is 
intended to address comments on these four categories in greater 
detail.
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    We are promulgating monitoring, recordkeeping, and reporting 
requirements to ensure compliance with these emission limitations.
    We are disapproving section VI.E of the Oklahoma RH SIP entitled, 
``Greater Reasonable Progress Alternative Determination.'' We are also 
disapproving 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 find that these portions of the 
submittal are severable from the BART determinations and the LTS. These 
alternative determinations are not fundamental requirements of a RH 
program, so disapproval of them does not create a gap in the SIP. For 
these reasons, no FIP is required.
    We are taking no action on whether Oklahoma has satisfied the 
reasonable progress requirements of EPA's RH SIP requirements found at 
section 51.308(d)(1).
    We are approving the remaining sections of the RH SIP submission. 
This includes certain core elements of the SIP including Oklahoma's (1) 
determination of baseline and natural visibility conditions, (2) 
coordinating regional haze and reasonably attributable visibility 
impairment, (3) monitoring strategy and other implementation 
requirements, (4) coordination with states and Federal Land Managers, 
and (5) the following BART determinations from Oklahoma's RH SIP:
     The SO2,, nitrogen oxides (NOX), and 
particulate matter (PM) BART determinations for the Oklahoma Gas and 
Electric (OG&E) Seminole Units 1, 2, and 3.
     The NOX and PM BART determinations for OG&E's 
Sooner Units 1 and 2.
     The NOX and PM BART determinations for the OG&E 
Muskogee Units 4 and 5.
     The SO2, NOX, and PM BART 
determinations for the American Electric Power/Public Service Company 
of Oklahoma (AEP/PSO) Comanche Units 1 and 2.
     The SO2, NOX, and PM BART 
determinations for the AEP/PSO Northeastern Unit 2.
     The NOX and PM BART determination for the AEP/
PSO Northeastern Units 3 and 4.
     The SO2, NOX, and PM BART 
determination for the AEP/PSO Southwestern Unit 3.

B. Interstate Transport of Pollutants and Visibility Protection

    We are partially approving and partially disapproving 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) with 
respect to visibility for the 1997 8-hour ozone NAAQS and the 
PM2.5 NAAQS.
    We are finalizing a FIP to address the requirements of section 
110(a)(2)(D)(i)(II) with respect to visibility to ensure that emissions 
from sources in Oklahoma do not interfere with the visibility programs 
of other states. We find that the controls under this FIP, in 
combination with the controls required by the portion of the Oklahoma 
RH submittal that we are approving, will serve to prevent sources in 
Oklahoma from emitting pollutants in amounts that will interfere with 
efforts to protect visibility in other states.

C. Compliance Timeframe

    In response to comments we received, we find that compliance with 
the emission limits of our FIP must be within five years of the 
effective date of this rule. This compliance timeframe includes the 
election to reconfigure the six units to burn natural gas.

III. Analysis of Major Issues Raised by Commenters

    We received both written comments and oral comments at the Public 
Hearings in Oklahoma City and Tulsa. We also received comments by the 
Internet and the mail. The comments are summarized and discussed below. 
The full text received from these commenters is included in the docket 
associated with this action.

A. Comments Generally Favoring Our Proposal

    Comment: We received many letters in support of our rulemaking from 
members representing various organizations that were similar in content 
and format, and are represented by two types of positive comment 
letters in the docket for this rulemaking. Each of these comment 
letters supports our proposed decision for the six coal units 
identified above. More than 500 of these letters specifically urge us 
to require emissions reductions from these six units in our final 
decision.
    We received two letters from Federal Land Managers in support of 
this rulemaking. These comments include support for our proposed 
disapproval of the Long Term Strategy under Section 51.308(d)(3) and 
our proposed disapproval of the Greater Reasonable Progress Alternative 
Determination (section 51.308), as well as support for our proposed FIP 
requiring an emissions limitation of 0.06 lb of SO2/MMBtu 
for each of the six units identified above. These comments also include 
agreement that EPA's proposed controls are cost-effective, reasonable 
and attainable, and that they constitute BART. These letters also 
included support for requiring compliance with the proposed emission 
limitations within three years from the effective date of the final 
rule, but could accept compliance within five years.
    At the Public Hearing in Oklahoma City, positive comments were 
received from representatives of a natural gas producer and from public 
citizens. Some comments included support for our proposed disapproval 
of the Oklahoma SIP submittal, as well as for finalizing our proposed 
FIP. Included with these comments was the belief expressed that not 
controlling these sources will not make electricity cheap. Another idea 
presented at this hearing was that, whereas cheap electricity does not 
make an economy healthy, renewable energy does. Data for eight states 
was presented, including Washington State in which 75 percent of the 
electricity comes from renewable resources. Other comments were that 
clean air is a basic necessity of life and not a luxury, and that clean 
air is not something that should be traded or bargained away in the 
name of profit. Further, these comments included encouragement for the 
shortest possible timeline for compliance.
    Comments were also received in support of our proposal at the 
Public

[[Page 81732]]

Hearing in Tulsa. One commenter noted that in the background for the 
proposed FIP, we accepted almost all of the methodologies and 
conclusions put forth by the ODEQ, with the exception of BART for 
SO2 removal. Another commenter mentioned that the concept of 
being a good neighbor and reducing air pollution is a critical 
component of the CAA.
    Response: We acknowledge these commenters for their support of this 
action. We also note that several of the specific emissions and 
timeframe limitations supported by these commenters in the proposal 
have been modified in this final action based on all of the information 
received during the comment period. Please see the docket associated 
with this action for additional detail. Additionally, some of the 
specific issues that these commenters raised are addressed elsewhere in 
this notice.

B. Comments Generally Against Our Proposal

    We received written comments, as well as oral comments at the 
Public Hearings in Oklahoma City and Tulsa, that generally did not 
support our proposed rulemaking. Most of these commenters expressed 
concerns about the economic impact of this rulemaking. Due to the 
specific nature of these comments, we address them more fully in the 
remainder of this notice and in the Supplemental RTC. The full text of 
these comments is included in the docket associated with this action.
    We also received one unspecific negative comment from an 
individual, which did not include documentation, rationale, or data for 
us to respond to beyond our responses provided elsewhere in this 
notice.

C. Comments on Legal Issues

1. General Legal Comments
    Comment: We received several comment letters questioning whether we 
have CAA authority to disapprove Oklahoma's BART determination and 
determine BART through a FIP. These commenters included the Oklahoma 
Attorney General, OG&E, several industry trade organizations, and AEP/
PSO. We also received a comment letter signed by multiple attorneys 
general from throughout the United States.\3\ The commenters generally 
contend that our proposal would ``usurp'' or encroach on the state's 
authority and that EPA lacks the authority to substitute its own 
judgment or policy preferences for the state's determinations. The 
Oklahoma Attorney General comments that our role is ``simply one of 
support'' and that state determinations are entitled to ``special 
deference.'' Similarly, one commenter states that we cannot ``second-
guess'' the state and redo a BART analysis with no deference to the 
state's findings. That commenter also states that we have not 
articulated any standard under which we may judge the validity of a 
state's BART determination.
---------------------------------------------------------------------------

    \3\ The signatories of this May 2011 comment letter were the 
attorney generals of Oklahoma, Alabama, Kentucky, Maine, the N. 
Mariana Islands, South Carolina, Texas, and Utah.
---------------------------------------------------------------------------

    Response: Congress crafted the CAA to provide for states to take 
the lead in developing implementation plans, but balanced that decision 
by requiring EPA to review the plans to determine whether a SIP meets 
the requirements of the CAA. EPA's review of SIPs is not limited to a 
ministerial type of ``rubber-stamping'' of a state's decisions. EPA 
must consider not only whether the state considered the appropriate 
factors but acted reasonably in doing so. In undertaking such a review, 
EPA does not ``usurp'' the state's authority but ensures that such 
authority is reasonably exercised. EPA has the authority to issue a FIP 
either when EPA has made a finding that the state has failed to timely 
submit a SIP or where EPA has found a SIP deficient. Here, EPA has 
authority and we have chosen to approve as much of the Oklahoma SIP as 
possible and to adopt a FIP only to fill the remaining gap. Our action 
today is consistent with the statute. In finalizing our proposed 
determinations, we are approving the state's determinations in 
identifying BART eligible sources and largely approving the state's 
BART determinations for thirteen different emission units subject to 
BART. We are, however, disapproving the state's SO2 BART 
determinations for six of those units. As explained in the proposal, 
the state's SO2 BART determinations for the six OG&E and 
AEP/PSO units are not approvable because ODEQ ``did not properly follow 
the requirements of section 51.308(e)(1)(ii)(A).'' 76 FR 16168, at 
16182. Specifically, ODEQ did not properly ``take into consideration 
the costs of compliance,'' when it relied on cost estimates that 
greatly overestimated the costs of controls. We have determined that 
the faults in ODEQ's cost methodology were significant enough that they 
resulted in BART determinations for SO2 that were both 
unreasoned and unjustified. Accordingly, those determinations that 
relied on significantly flawed cost estimations are not approvable.
    In the absence of approvable BART determinations in the SIP for 
SO2 for BART eligible sources in Oklahoma, we are obliged to 
promulgate a FIP to satisfy the CAA requirements. Likewise, in the 
absence of an approvable SIP that addresses the requirement that 
emissions from Oklahoma sources do not interfere with measures required 
in the SIP of any other state to protect visibility, we are obliged to 
promulgate a FIP to address the defect. This authority and 
responsibility exists under CAA section 110(c)(1). We also are required 
by the terms of a consent decree with WildEarth Guardians, lodged with 
the U.S. District Court for the Northern District of California to 
ensure that Oklahoma's CAA requirements for 110(a)(2)(D)(i)(II) are 
finalized by December 13, 2011. Because we have found the state's SIP 
submissions do not adequately satisfy either requirement in full and 
because we have previously found that Oklahoma failed to timely submit 
these SIP submissions, we have not only the authority but a duty to 
promulgate a FIP that meets those requirements. Our action in large 
part approves the RH SIP submitted by Oklahoma; the disapproval of the 
SO2 BART determinations and imposition of the FIP is not 
intended to encroach on state authority. This action is only intended 
to ensure that CAA requirements are satisfied using our authority under 
the CAA. We note that Oklahoma may submit a new SIP revision addressing 
the issue of SO2 controls for these six units, in which case 
we will assess it against Clean Air Act and Regional Haze Rule 
requirements as a possible replacement for the FIP.
    Comment: Multiple commenters have cited to various CAA statutory 
provisions to support their contention that the State of Oklahoma has 
authority or ``primary authority,'' where EPA has no authority or 
lesser authority. On this point, commenters have cited CAA Sections 
169A(b)(2)(A) and 169A(g)(2). Specifically, Section 169A(b)(2)(A) reads 
in part that regulations to protect visibility shall require the 
installation and operation of BART ``as determined by the State (or the 
Administrator in the case of a plan promulgated under section 7410(c) 
of the this title).'' Section 169A(g)(2) begins, ``in determining 
[BART] the State (or the Administrator in determining emissions 
limitations which reflect such technology) shall'' take into 
consideration several requisite statutory factors. The commenters place 
special emphasis on the references to the ``the State'' in these 
provisions and contend that the plain language of the statute

[[Page 81733]]

provides that states, and not EPA, have authority to determine BART.
    Response: We agree that states have authority to determine BART, 
but we disagree with commenters' assertions that EPA has no authority 
or lesser authority to determine BART when promulgating a FIP. As the 
parenthetical in section 169A(b)(2)(A) indicates, the Administrator has 
the authority to determine BART ``in the case of a plan promulgated 
under section 7510(c).'' In other words, the Administrator has explicit 
authority to determine BART when promulgating a FIP. In our proposal, 
we stated that we must consider the same factors as states when 
proposing a FIP to address BART. 76 FR 16168, at 16187. Our BART 
determination follows the factors prescribed by CAA Section 169A(g)(2). 
We disagree that the language of the CAA limits our authority to 
determine BART in the case of a FIP.
    Comment: Commenters who have argued that the plain language of the 
CAA requires that states are the primary or only BART determining 
authorities have also cited our preamble language from past Federal 
Register publications that they believe reinforces their contention. 
For example, several commenters cited 70 FR 39104, at 39107, which 
reads in part, ``the State must determine the appropriate level of BART 
control for each source subject to BART.'' Commenters have also cited 
the preamble to our proposal, where we wrote, ``States are free to 
determine the weight and significance to be assigned to each factor'' 
when making BART determinations. 76 FR 16168, at 16174. Finally, some 
commenters have stated the preamble of the RHR supports their 
contentions when it states: ``In some cases, the State may determine 
that a source has already installed sufficiently stringent emission 
controls for compliance with other programs (e.g., the acid rain 
program) such that no additional controls would be needed for 
compliance with the BART requirement.'' 64 FR 35714, at 35740.
    Response: We agree that states are assigned statutory and 
regulatory authority to determine BART and that many past EPA 
statements have confirmed state authority in this regard. Although the 
states have the freedom to determine the weight and significance of the 
statutory factors, they have an overriding obligation to come to a 
reasoned determination. As detailed in our proposal and the supporting 
Technical Support Document (TSD), the state's SO2 BART 
determinations for the six OG&E and AEP/PSO units were premised on 
flawed cost assumptions. Since these SO2 BART determinations 
of the state are not approvable, we are obliged to step into the shoes 
of the state and arrive at our BART determinations.
    Comment: Commenters have also cited other CAA provisions. One 
commenter states that 169A(b) only allows for EPA to issue guidelines 
with technical and procedural guidance for determining BART, not to 
issue rules that dictate the outcome (except for fossil-fueled power 
plants with capacity that exceeds 750 MW). That commenter also contends 
that our lack of authority relative to the states is shown through CAA 
Section 169A(f), which provides that the meeting of the national 
visibility goal is not a ``nondiscretionary duty'' of the 
Administrator. AEP/PSO comments that the provisions of CAA Section 169B 
shows that states have special authority to act together through 
visibility transport commissions. The Oklahoma Attorney General cites 
CAA Section 101(a)(3), which provides that air pollution control at its 
source ``is the primary responsibility of States and local 
governments.''
    Response: States shoulder significant responsibilities in CAA 
implementation and in effectuating the requirements of the RHR. EPA has 
the responsibility of ensuring that state plans, including RH SIPs, 
conform to CAA requirements. None of the CAA provisions cited by 
commenters change our conclusion that we have authority to issue a FIP 
to satisfy BART requirements given that Oklahoma's RH SIP is not fully 
approvable. We cannot approve a RH SIP that fails to address BART with 
a reasoned consideration of the costs of compliance. Our inability to 
approve the state's BART determinations for SO2 means we 
must follow through on our non-discretionary duty to promulgate a FIP. 
Under the CAA, we were required to do this by January 2011, two years 
after EPA found that Oklahoma failed to submit a RH SIP. 74 FR 2392. 
The language of CAA Section 169A(f), which concerns the meeting of the 
national goal, is not related to the review of a state's BART 
determinations or our determinations on their adequacy or the timing of 
our action.
    Comment: Many commenters expressed the view that their statutory 
arguments are reinforced by legislative history of the 1977 CAA 
amendments. Several commenters refer to statements of Senator Edmund 
Muskie regarding the conference agreement on the provisions for 
visibility protection in those amendments. Senator Muskie had stated 
that under the conference agreement the state, ``not the 
Administrator,'' identifies BART eligible sources and determines BART. 
123 Cong. Rec. 26854 (August 4, 1977). Commenters have also noted that 
Am. Corn Growers Ass'n v. EPA, 291 F.3d 1 (D.C. Cir. 2002) used 
legislative history, including the Conference Report on the 1977 
amendments, when the Court had invalidated past regulatory provisions 
regarding BART for constraining state authority. The Court stated that 
the Conference report confirmed that Congress ``intended the states to 
decide which sources impair visibility and what BART controls apply to 
those sources.''
    Response: We agree that the CAA places the requirements for 
determining BART for BART-eligible sources on states. As discussed 
above, the CAA also requires the Administrator to determine BART in the 
absence of an approvable determination from the state. Because we have 
determined that Oklahoma's BART determinations for SO2 for 
the six OG&E and AEP/PSO units do not conform with section 51.308(e) 
and are not approvable, we are authorized and at this time required to 
promulgate a FIP.
    Comment: Several commenters have asserted our proposal is 
inconsistent with the decision of the DC Circuit in Am. Corn Growers 
Ass'n v. EPA, 291 F.3d 1 (D.C. Cir. 2002). They contend that language 
in the decision affirms their views regarding state authority and EPA's 
lack of authority in regulating the problem of regional haze. In 
particular, the American Corn Growers decision had described states as 
playing ``the lead role'' in designing and implementing regional haze 
programs, Id. at 3, and described the CAA as ``giving the states broad 
authority over BART determinations.'' Id. at 8.
    Response: We disagree that our proposal is inconsistent with the 
American Corn Growers decision. We have determined that Oklahoma 
utilized flawed cost assessments and incorrectly estimated the 
visibility impacts of controls. We have determined these issues 
resulted in non-approvable SO2 BART determinations for the 
six OG&E and AEP/PSO units. We recognize the state's broad authority 
over BART determinations, and recognize the state's authority to 
attribute weight and significance to the statutory factors in making 
BART determinations. As a separate matter, however, a state's BART 
determination must be reasoned and based on an adequate record. 
Although we have largely approved the state's RH SIP, we cannot agree 
that CAA requirements are satisfied with respect to these 
SO2 BART determinations.
    Comment: One commenter contends that states have broader authority 
for regional haze, because it is not a human

[[Page 81734]]

health-based regulation. Another commenter similarly suggests that 
states are the ``appropriate decision makers'' because regional haze is 
about haze, not health.
    Response: We do not agree that the CAA or RHR prescribes a 
different degree of authority to states based on the program having the 
goal of improving visibility as opposed to preventing adverse human 
health effects. Among other things, the CAA requires states to submit 
plans that satisfy NAAQS standards set to protect both public health 
and welfare. Nothing in the terms of the CAA or its implementation 
history directs that SIP submittals addressing visibility are subject 
to a different standard of evaluation than SIP submittals that directly 
address public health issues associated with air pollutants. The 
distinction is not pertinent to state authority to develop RH SIPs and 
does not diminish our responsibility and authority to require that they 
conform to the RHR.
    Comment: Several commenters have more generally asserted that we 
lack authority to disapprove the RH SIP, because of past cases where we 
have lacked authority in particular SIP disapproval actions. These 
commenters have cited, in particular to Florida Power & Light Co. v. 
Costle, 650 F.2d 579, 581 (5th Cir. 1981) (EPA must approve a SIP that 
``meets statutory criteria''), Train v. NRDC, 421 U.S. 60, 79 (1975), 
and Commonwealth of Vir. v. EPA, 108 F.3d 1397 (D.C. Cir. 1997). Under 
these cases, the commenters assert that we cannot question the wisdom 
of a state's choices or require particular control measures if plan 
provisions satisfy CAA standards.
    Response: States are required by the CAA to address the BART 
requirements in their SIP. Our disapproval of the SO2 BART 
determinations in the Oklahoma RH SIP is authorized under the CAA 
because the state's SO2 BART determinations for the six OG&E 
and AEP/PSO units do not satisfy the statutory criteria. The state's 
analysis of the cost effectiveness of controls was flawed due to 
reasons discussed elsewhere in this notice. While states have authority 
to exercise different choices in determining BART, the determinations 
must be reasonably supported. Oklahoma's errors in taking into 
consideration the costs of compliance were significant enough that we 
cannot conclude the state determined BART according to CAA standards. 
The cases cited by the commenters stress important limits on EPA 
authority in reviewing SIP submissions, but our disapproval of these 
SO2 BART determinations for the six units has an appropriate 
basis in our CAA authority.
    Comment: A citizen commenter asserts that our proposal is 
indicative of ``raw unconstitutional power.''
    Response: The commenter has cited no specific provisions of the 
Constitution. In any case, we regard neither the RHR, which has 
previously been subject to review by the D.C. Circuit, nor our 
underlying statutory authority for this action to be unconstitutional. 
We are acting under statutory responsibilities established in the 1977 
and 1990 amendments to the CAA. As is the case for any executive agency 
under the authority of the President, the Constitution has charged us 
with the implementation and enforcement of laws written by Congress. 
The administration of the CAA and implementation of the RHR is 
accordingly not unconstitutional.
    Comment: AEP/PSO and another commenter have commented that our 
proposed action improperly combines matters under Oklahoma's RH SIP 
with unrelated matters addressed in the 2007 Interstate Transport SIP. 
Both commenters have stated that our disapproval of the Interstate 
Transport SIP would be inconsistent with our guidance in 2006. They 
contend our 2006 guidance had suggested conclusions regarding whether 
emissions from any one state could interfere with measures of 
neighboring states to protect visibility could only be reached when a 
neighboring state's RH SIP had been approved. These commenters believe 
Oklahoma's Interstate Transport SIP obligations under CAA Section 
110(a)(2)(D)(i)(II) can be approved because there were no EPA-approved 
regional haze SIPs at the time of submittal or when we reviewed the 
Oklahoma submission.
    Response: We disagree with contention of the commenters that RH SIP 
requirements and the visibility requirements of section 
110(a)(2)(D)(i)(II) are unrelated. We are addressing them 
simultaneously because the purposes and requirements of the interstate 
transport provisions of the CAA with respect to visibility and the RH 
program are intertwined. Section 110(a)(2)(D)(i)(II) does not 
explicitly define what is required in SIPs to prevent the prohibited 
impact on visibility in other states. However, because the RH program 
requires measures that must be included in SIPs specifically to protect 
visibility, EPA's 2006 Guidance \4\ recommended that RH SIP submissions 
meeting the requirements of the visibility program could satisfy the 
requirements of CAA section 110(a)(2)(D)(i)(II) with respect to 
visibility. Subsequently, in instances in which some states did not 
make the RH SIP submission, in whole or in part, or did not make an 
approvable RH SIP submission, we evaluated whether those states could 
comply with section 110(a)(2)(D)(i)(II) by other means. Thus, we have 
elsewhere determined that states may also be able to satisfy the 
requirements of CAA section 110(a)(2)(D)(i)(II) with something less 
than an approved RH SIP, see, for example, our determinations regarding 
Colorado (76 FR 22036) and Idaho (76 FR 36329). In other words, an 
approved RH SIP is not the only possible means to satisfy the 
requirements of CAA section 110(a)(2)(D)(i)(II) with respect to 
visibility; however, such a SIP could be sufficient. Given this 
reasoning, we do not agree with commenters' contentions that our action 
improperly combines two unrelated programs.
---------------------------------------------------------------------------

    \4\ See,''Guidance for State Implementation Plan (SIP) 
Submissions to Meet Current Outstanding Obligations Under Section 
110(a)(2)(D)(i) for the 8-Hour Ozone and PM2.5 National 
Ambient Air Quality Standards,'' from William T. Harnett, Director 
Air Quality Policy Division, OAQPS, to Regional Air Division 
Director, Regions I-X, dated August 15, 2006 (the ``2006 
Guidance'').
---------------------------------------------------------------------------

    Regarding our guidance on submissions in August of 2006, we 
explicitly stated that ``at this point in time,'' it was not possible 
to assess whether emissions from sources in the state would interfere 
with measures in the SIPs of other states. As subsequent events have 
demonstrated, we were mistaken as to the assumption that all states 
would submit RH SIPs in December of 2007, as required by the RHR, and 
mistaken as to the assumption that all such submissions would meet 
applicable RH program requirements and therefore be approved shortly 
thereafter. Thus the premise of the 2006 Guidance that it would be 
appropriate to await submission and approval of such RH SIPs before 
evaluating SIPs for compliance with section 110(a)(2)(D)(i)(II) was in 
error. Our 2006 Guidance was clearly intended to make recommendations 
that were relevant at that point in time, and subsequent events have 
rendered it inappropriate in this specific action. We must therefore 
act upon Oklahoma's submission in light of the actual facts, and in 
light of the statutory requirements of section 110(a)(2)(D)(i). In 
order to evaluate whether the state's SIP currently in fact contains 
provisions sufficient to prevent the prohibited impacts on the required 
programs of other states, we are obligated to consider the current 
circumstances and investigate the level

[[Page 81735]]

of controls at Oklahoma sources and whether those controls are or are 
not sufficient to prevent such impacts.
    We reject the argument that Oklahoma's submittal should be 
approvable because surrounding states have yet to submit RH SIPs that 
have been approved. The argument fails to address what would happen if 
a downwind state were never to submit the required RH SIP, or were 
never to submit a RH SIP that was approvable. On its face, the 
commenter's argument is simply inconsistent with the objectives of the 
statute to protect visibility programs in other states if a state never 
submits an approvable RH SIP. Second, this approach is flatly 
inconsistent with the timing requirements of section 110(a)(1) which 
specifies that SIP submissions to address section 110(a)(2)(D)(i), 
including the visibility prong of that section, must be made within 
three years after the promulgation of a new or revised NAAQS. We 
acknowledge that there have been delays with both RH SIP submissions by 
states and our actions on those RH SIP submissions, but that fact does 
not support a reading of the statute that overrides the timing 
requirements of the statute. At this point in time, states are required 
to have submitted regional haze plans to EPA that establish reasonable 
progress goals for Class I areas. This requirement applies whether or 
not states have in fact submitted such plans. We believe that there are 
means available now to evaluate whether a state's section 
110(a)(2)(d)(i)(II) SIP submission meets the substantive requirement 
that it contain provisions to prohibit interference with the visibility 
programs of other states, and therefore that further delay, until all 
RH SIPs are submitted and fully approved, is unwarranted and 
inconsistent with the key objective to protect visibility.
    As detailed in our proposal, we believe based on the information 
currently before us that an implementation plan that provides for 
emissions reductions consistent with the assumptions used in the 
modeling of other CENRAP states will ensure that emissions from 
Oklahoma sources do not interfere with the measures designed to protect 
visibility in other states. 76 FR 16168, at 16193. The Oklahoma 
SO2 BART determinations for the six OG&E and AEP/PSO units 
did not require these sources to meet the level of control assumed in 
the CENRAP modeling. As we discuss elsewhere in our response to 
comments, Oklahoma engaged in a regional planning process. This 
regional planning process included a forum in which state 
representatives built emission inventories that assumed that specific 
pollution sources would be controlled to specific levels. This included 
assumptions that the six OG&E and AEP/PSO units would be controlled to 
presumptive BART emission levels for SO2. Visibility 
modeling projections subsequently assumed those emission reductions, 
and other states relied on those reductions as part of their reasonable 
progress demonstrations. Accordingly and consistent with our proposal, 
we are partially disapproving the Oklahoma SIP revision submitted to 
address the requirements of CAA section 110(a)(2)(D)(i)(II). The FIP 
remedies the inadequacy in the Oklahoma SIP by requiring controls for 
the six units that at least achieve the level of control assumed in the 
CENRAP modeling.
    Comment: AEP/PSO and another commenter have asserted that the 
promulgation of revised NAAQS for ozone and PM2.5 in 1997 
did not trigger any additional SIP obligations with respect to section 
110(a)(2)(D)(i)(II). A commenter believes that these revised NAAQS are 
not meaningfully related to visibility requirements in Title I Part C, 
of the CAA. The commenters ask EPA to determine that no obligation to 
address Part C visibility components of a SIP arose from those NAAQS 
revisions.
    Response: Reduced visibility is an effect of air pollution, and the 
emissions of PM2.5 and ozone and its precursors can 
contribute to visibility impairment. SIP planning for the control of 
these pollutants on the promulgation of a new NAAQS will therefore 
implicate control measures and issues relating to visibility. CAA 
section 110(a)(1) therefore requires implementation plans submitted in 
the wake of a newly promulgated NAAQS to address whether the state has 
adequate provisions to prevent interference with the efforts of other 
states to protect visibility. The obligation to address Part C 
visibility components expressly follows from the language of 110(a) 
concerning when plans must be submitted and what each implementation 
plan must contain.
    Comment: OG&E contends that EPA's proposal to disapprove the 
state's BART determination is faulty, because the agency relied 
``without critical review'' on what the commenter describes as the 
``opinion'' of a contracted consultant. The commenter contends EPA's 
our consultant is unqualified to evaluate costs of installing and 
operating scrubbers at the OG&E Units, because our consultant ``has no 
experience designing scrubbers or estimating their costs.'' 
Additionally, OG&E states our consultant lacked relevant knowledge 
about the OG&E Units and the facilities at which these units are 
located, and did not attempt to communicate with OG&E or its contractor 
about the particular design parameters, engineering specifications, or 
other intricacies associated with the OG&E units. The commenter 
believes the consultant's report contains opinions that ``lack adequate 
foundation.'' On this basis, OG&E states that EPA cannot lawfully rely 
on the consultant's report.
    Response: As an initial matter, we do not agree that our regulatory 
actions are subject to evidentiary rules regarding expert testimony, as 
this comment suggests. Our consultant's detailed report was 
incorporated as technical support for our regulatory determinations and 
is not properly characterized as an opinion. The contention that we 
accepted the consultant's report without critical review is false. As 
was stated in our proposal, only after we thoroughly reviewed and 
evaluated the report was it made a part of our TSD. 76 FR 16168, at 
16182-16183. Furthermore, we met with OG&E and its consultant 
concerning the development of our proposal and had extensive 
communications clarifying particular technical points. This information 
was coordinated with our consultant and was incorporated into her 
report. Thus, we worked closely with our consultant in the development 
of her report.
    Comment: A commenter states that EPA's proposed BART determination 
would violate Executive Order 13132, Federalism.
    Response: We do not agree that our proposal or this final action 
violates Executive Order 13132. EPA is taking actions specified under 
the CAA in partially approving and partially disapproving the Oklahoma 
RH SIP. The CAA also specifies the responsibility of EPA to issue a FIP 
when states have not met their requirements under the CAA. EPA is 
promulgating this FIP to fill the regulatory gap created by the partial 
disapproval. Under the FIP, the state retains its authority to submit 
future RH SIPs consistent with CAA and RHR requirements; we do not 
discount the possibility of a future, approvable RH SIP submission that 
results in the modification or withdrawal of the FIP. This rulemaking 
does not change the distribution of power between the states and EPA. 
Consistent with this, in the Executive Orders section of this 
rulemaking, we have determined that Executive Order 13132 does not 
apply to this action.
    Comment: A commenter states that EPA cannot propose a FIP until 
after it

[[Page 81736]]

has taken final action to disapprove a state implementation plan. The 
commenter cites to part of CAA section 110(c)(1) which states that the 
Administrator shall promulgate a FIP ``at any time within 2 years 
after'' the Administrator ``disapproves a State implementation plan 
submission.'' The commenter states that EPA should withdraw the 
proposed FIP, take final action only on the SIP, and only then propose 
a FIP, if one is necessary.
    Response: We have the authority to promulgate a FIP concurrently 
with a disapproval action. This timing for FIP promulgation is 
authorized under CAA section 110(c)(1). As has been noted in past FIP 
promulgation actions, the language of CAA section 110(c)(1), by its 
terms, establishes a two-year period within which we must promulgate 
the FIP, and provides no further constraints on timing. See, e.g., 76 
FR 25178, at 25202. Oklahoma failed to submit its regional haze SIP to 
us by December 2007, as required by Congress. Two years later, Oklahoma 
had still not submitted its regional haze SIP. When we made a finding 
in 2009 that Oklahoma had failed to submit its regional haze SIP, (see 
74 FR 2392), that created an obligation for us to promulgate a FIP by 
January 2011. We are exercising our discretion to promulgate the FIP 
concurrently with our disapproval action because of the applicable 
statutory deadlines requiring us at this time to promulgate RH BART 
determinations to the extent Oklahoma's BART determinations are not 
approvable.
    Comment: OG&E expresses the view that we have improperly combined a 
proposed disapproval of the Oklahoma SIP with our own BART 
determination. The commenter contends that the fact we would reach a 
different BART determination is not ``itself sufficient grounds to 
disapprove the SIP.'' The commenter believes EPA desired to have 
scrubbers installed on the OG&E units and is only proposing to 
substitute its own BART determination ``to mask the fact that it lacks 
any meritorious grounds to disapprove ODEQ's BART determination.''
    Response: Our grounds for disapproving ODEQ's SO2 BART 
determination were articulated in our proposal, and we have not claimed 
that having arrived at a different SO2 BART determination 
constitutes a basis for disapproval. Instead, as was clear in our 
proposal, we were obliged to develop an SO2 BART 
determination because Oklahoma's SO2 BART determination was 
flawed and not approvable. The fact that Oklahoma's SO2 BART 
determination was not approvable caused us to develop a BART 
determination that adheres to the requirements of section 
51.308(e)(1)(ii)(A).
    Comment: OG&E comments that we cannot justify our disapproval based 
on aggregate visibility improvements. The commenter asserts that when 
we review a SIP or propose a FIP, the agency is required to consider 
the visibility improvement associated with scrubbers on a facility-by-
facility basis. The commenter points to a portion of our proposal where 
we stated that modeling demonstrates a ``2.89 deciview improvement in 
visibility,'' 76 FR 16168, at 16186, and notes the statement is based 
on combining impacts from scrubbers at multiple units. The commenter 
asserts this approach violates the individual facility approach 
dictated by CAA as outlined in the American Corn Growers case and 
violates the RHR and the guidelines that responded to that case 
outcome. In particular, the commenter cites to the preamble language at 
70 FR 39104, at 39106 which describes how the RHR was amended ``to 
require the States to consider the degree of visibility improvement 
resulting from a source's installation and operation of retrofit 
technology, along with the other statutory factors.'' The commenter 
attributes significance to EPA's phrasing, which had stated in part, 
``* * * States will be required to consider all five factors, including 
visibility impacts, on an individual source basis when making each 
individual source BART determination.''
    Another commenter also contends we based our SO2 BART 
proposal for the six OG&E and AEP/PSO units on a visibility estimate of 
an 8.20 dv cumulative improvement over multiple Class I areas. Further, 
this commenter contends we have claimed this visibility improvement 
will result from emission reductions at all three facilities combined, 
which the commenter characterizes as a form of aggregation that is 
impermissible, as BART must be determined on a source-by-source basis. 
The commenter also stated that analysis should be focused on the 
visibility impacts at the most impacted area, not all areas. The 
commenter claims our rules indicate that it is appropriate to model 
impacts at the nearest Class I area as well as impacts at other nearby 
Class I areas. However, in the case of the latter category of areas, 
merely for the purpose of ``determin[ing] whether effects at those 
[other] areas may be greater than at the nearest Class I area.'' 70 FR 
39104, at 39170. Further, continues the commenter, the rules state that 
``[i]f the highest modeled effects are observed at the nearest Class I 
area, you may choose not to analyze the other Class I areas any further 
* * *.'' Id. Based on this, the commenter states that that the BART 
rules contemplate a visibility improvement analysis that only is 
focused on visibility impacts in the most impacted area, not all areas.
    Response: We proposed disapproval of the Oklahoma SO2 
BART determination for the six OG&E and AEP/PSO units in part because 
we disagreed with ODEQ's cost analysis, and our own visibility modeling 
indicated SO2 controls would result in significant 
visibility improvement. In so doing, we adhered to the requirements of 
section 51.308(e). Oklahoma's SO2 BART determinations for 
the six units were based on flawed costing methodologies. Our 
determinations regarding visibility improvement are not inconsistent 
with the CAA or the court's interpretation in American Corn Growers of 
the individual facility approach that must be utilized when making BART 
determinations. Although we noted in the proposal the combined 
visibility improvement at four Class I areas due to the installation of 
SO2 controls at the six OG&E and AEP/PSO units, our FIP is 
not based on an analysis of visibility improvements that are aggregated 
across multiple facilities. Rather, we assessed the visibility 
improvement of each facility separately.
    Our visibility modeling shows that the six OG&E and AEP/PSO units 
``causes or contributes'' to visibility impairment--as the phrase is 
defined in the RHR \5\--at four Class I areas. As Table 1 indicates, 
the number of days per year each Class I area is impacted at this level 
by each facility's emissions are expected to decrease drastically at 
each Class I area as the result of installation of SO2 BART 
emission controls at the six units. Clearly, the visibility benefits 
from SO2 BART emission reductions will be spread among all 
affected Class I areas, not only the most affected area, and should be 
considered in evaluation of benefits from proposed reductions. The 
portion of the BART Guidelines (40 CFR 51 Appendix Y, IV.D.5) that the 
commenter referenced states: ``If the highest modeled effects are 
observed at the nearest Class I area, you may choose not to analyze the 
other Class I areas any further as additional analyses might be 
unwarranted.'' This section of the BART Guidelines addresses how to 
determine

[[Page 81737]]

visibility impacts as part of the BART determination and is intended to 
make clear that if certain controls would be justified based on the 
impacts at the nearest Class I area, the state is not required to 
undertake an exhaustive analysis of impacts across multiple Class I 
areas. Several paragraphs later in the BART Guidelines is the 
following: ``You have flexibility to assess visibility improvements due 
to BART controls by one or more methods. You may consider the 
frequency, magnitude, and duration components of impairment,'' 
emphasizing the flexibility in method and metrics that exists in 
assessing the net visibility improvement.
---------------------------------------------------------------------------

    \5\ States should consider a 1.0 deciview change or more from an 
individual source to ``cause'' visibility impairment, and a change 
of 0.5 deciviews to ``contribute'' to impairment. 70 FR 39120.
---------------------------------------------------------------------------

    Comment: OG&E comments that we had improperly analyzed the 
``contingent BART determination that applies if EPA rejects ODEQ's 
determination that low sulfur coal is BART and all appeals are 
exhausted.'' The commenter says the contingent BART determination 
should not have been analyzed as a BART alternative under 40 CFR 
51.308, because it is ``not a BART alternative.'' If the contingent 
determination were to be effectuated, the commenter asserts that 
scrubbers would then constitute BART itself, not an alternative to BART 
scrutinized under separate rules. The commenter also asserts that the 
contingent BART finding would be consistent with the statutory 
timeframe for installation of BART (viz., ``in no event later than five 
years'' under CAA section 169A(g)(4)), because the contingent BART 
finding would not be triggered until the appellate process had 
concluded and because a final appellate ruling might be made before 
2013, which could result in a time for compliance that is shorter than 
five years.
    Response: The RHR does not afford the option of submitting 
contingent BART determinations that would apply and become effective 
when EPA disapproves and successfully defends its disapproval of a 
state's BART determination. This item in the RH SIP could not be 
evaluated as a BART determination, because it is not on its face a BART 
finding. This component of the RH SIP submission inherently speculates 
on the actions and outcomes of review by EPA and the courts, and is 
contrary to the SIP planning and review expected under the RHR and the 
CAA, more generally. Accordingly, we properly evaluated these 
provisions as an alternative to BART and determined that the contingent 
BART determination was not approvable under 40 CFR 51.308. We disagree 
that it could be reviewed under any other provision and found to be 
consistent with the RHR.
    Comment: OG&E comments that we had improperly analyzed the ``2026 
compliance option'' as failing to meet the standards of a BART 
alternative. In the commenter's view, the 2026 compliance is not a BART 
alternative but only a measure ``to implement a long-term strategy in 
the name of reasonable progress.'' OG&E asserts that ODEQ has authority 
for this under 51.308(d)(3), and that implementation of the compliance 
option could reduce emissions more than would be possible with dry 
scrubbers, and that our evaluation of the 2026 compliance option loses 
sight of the long-term national goal.
    Response: We disagree that the contingent SIP provision can be 
recognized as implementing a long-term strategy. As discussed in our 
response regarding the ``contingent BART determination,'' this 
component of the RH SIP is not on its face reviewable as a BART 
determination and fails to satisfy the requirements of Section 51.308. 
The contingent SIP is predicated on speculative actions and outcomes of 
review by EPA and courts, and does not comport with established SIP 
planning and approval processes under the CAA.
    Comment: A commenter expressed concern that EPA has ignored the 
regional haze plan supported by ODEQ and local utilities, and states, 
``EPA has assumed the State's role under the Clean Air Act and has 
simply chosen not to exercise its discretion to approve the Greater 
Reasonable Progress Alternative Determination.'' Another commenter also 
submitted a comment requesting that EPA use the Oklahoma RH SIP as a 
guideline in the decision making process. Another commenter from the 
office of Oklahoma's Attorney General states that we ``should defer to 
the state plan,'' because Oklahoma is in a superior position to make 
decisions regarding energy policy.
    Response: We note that our action today largely approves the 
regional haze plan submitted by Oklahoma. We are, however, finalizing 
disapprovals of the state's SO2 BART determinations and the 
``Greater Reasonable Progress Alternative Determination'' referenced by 
the commenter. We have determined that neither of these components of 
the RH SIP submission conforms to CAA and RHR requirements. Because 
Oklahoma's SO2 BART determinations are not being approved, 
we have promulgated a FIP that determines SO2 BART for the 
six OG&E and AEP/PSO units in a manner consistent with RHR 
requirements. We agree that this action, as with any FIP, may be said 
to assume a planning role ordinarily belonging to the state. Even with 
the finalization of the FIP, the state nevertheless retains its 
authority to submit future RH SIPs consistent with CAA and RHR 
requirements; we do not discount the possibility of a future, 
approvable RH SIP submission that results in the modification or 
withdrawal of the FIP. In the meantime, sources must comply with the 
requirements of the FIP and the approved components of Oklahoma's RH 
SIP.
2. Comments Asking EPA To Consider All Rules
    Comment: OG&E comments that installation of scrubbers will consume 
a significant amount of additional power that would need to be 
generated by burning additional fuel. The commenter suggests that 
increased GHG emissions from the additional fuel combustion could 
trigger the requirement to obtain a prevention of significant 
deterioration (PSD) permit for greenhouse gas emissions (GHGs). The 
commenter asserts that a PSD permit application process ``can take 18-
24 months'' and, if the process is necessary, it might be impossible to 
accommodate any PSD permit application process in a three-year 
compliance period. The commenter further contends the permitting 
process will impose costs and the terms of the PSD permit might impose 
costs if changes to the method of operation or additional control 
technologies are required. The commenter says we failed to account for 
these costs in our cost evaluation.
    Response: We agree that the installation of SO2 dry 
scrubbers at the six OG&E and AEP/PSO units could conceivably increase 
the emissions of other regulated new source review pollutants, 
including GHGs, to the point where PSD review is triggered. Any PSD 
permit that is necessary would have to be obtained from ODEQ, which is 
the permitting authority in Oklahoma. Whether or not PSD permitting is 
required would be based on design-specific considerations and 
applicability determinations that will vary with each unit. OG&E has 
not provided underlying data or facts to substantiate first, that PSD 
permitting could not be avoided through controls designed to consume 
less power, and second that a PSD permit, if needed, would impose 
additional or collateral costs that would materially change our cost 
evaluation. We also disagree with the assertion that PSD permitting 
will require 18-24 months; Oklahoma's SIP for PSD permitting, 
consistent with CAA section 165(c), establishes a one year objective 
for granting or denying PSD permit applications. As we discuss 
elsewhere in this notice and in our Supplemental

[[Page 81738]]

RTC, we find that compliance with SO2 BART for the six units 
is extended to five years, which should provide ample opportunity to 
satisfy PSD permitting requirements, if any.
    Comment: A commenter states that the proposed three-year compliance 
period is not justified. The commenter contends that we should consider 
other regulations that we are formulating for the power sector that 
will affect the six units covered by the FIP. The commenter mentions 
the Clean Air Transport Rule, the proposed Air Toxics rule, the 
projected NSPS, and rules for GHGs, coal combustion waste, and 
implementation of 316(b) of the Clean Water Act. The commenter states 
the compliance period is inadequate because utilities would not have 
sufficient time to develop a plan that addresses all of the regulations 
we are considering, including BART, because those rules may affect how 
they choose to comply with any given BART limitations. The commenter 
also thinks we should be required to analyze whether the compliance 
timeframe is appropriate by examining whether the other regulations 
will cause delays because of simultaneous demands for materials, 
equipment, supplies, and labor.
    In related comments, OG&E and another commenter state that other 
regulatory developments that impact coal burning power plants in the 
period since Oklahoma submitted its SIP should be considered in our 
BART analysis, including the utility MACT proposal, the cooling water 
intake proposal, and the coal ash disposal proposal. OG&E further cites 
additional possible regulations through revision of the NAAQS, and the 
clean air transport proposal. OG&E states the control requirements and 
costs of these other rules should be considered in establishing the 
remaining useful life of the OG&E units for the BART analysis. OG&E is 
concerned that depending on the outcome of these rulemaking processes, 
some or all of the units in question may not continue to be 
economically viable. The Governor of Oklahoma also submitted a comment 
requesting EPA to consider the impact that subsequent rulemakings may 
have on the issue of regional haze.
    Response: We agree that multiple regulatory actions are pending 
that will affect the power sector and agree that regulatory development 
should be coordinated when possible. We also recognize the importance 
of long-term and coordinated planning on the part of owners of 
industrial sources that are subject to BART. The visibility 
requirements of the CAA were put in place in 1977 and 1990, and our 
implementing regulations adopted in 1999, and the regional haze 
requirement for installation and operation of BART, in particular, must 
be carried out expeditiously. We have no basis and no supporting 
evidence from the commenter or any other source to conclude that 
significant market constraints for materials, equipment, supplies and 
labor would arise to make a three-year compliance period unachievable, 
but we do recognize the importance of planning within any compliance 
period. As we discuss elsewhere in this notice and in the Supplemental 
RTC, we have extended the compliance timeframe from the three years we 
proposed. Compliance with the SO2 BART emission limits in 
our FIP must be within five years of the effective date of our final 
rule, which is the maximum time permitted by statute.
    With regard to the BART analysis, the BART guidelines do allow for 
consideration of the remaining useful life of facilities when 
considering the costs of potential BART controls. Such a claim would 
have to be secured by an enforceable requirement. Neither OG&E nor AEP/
PSO claimed any such restrictions on the operation of these six units. 
Consequently, we assumed a remaining useful life of 30 years in our 
BART analysis. If OG&E and/or AEP/PSO decide the units in question have 
a shorter useful life such that installing scrubbers is no longer cost 
effective, and are willing to accept an enforceable requirement to that 
effect, a revised BART analysis could be submitted by the plant(s) in 
question and our FIP could be re-analyzed accordingly. Similarly, we 
could also review a revised SIP submitted by ODEQ.
    The RHR follows from statutory requirements of the CAA that are 
separate and independent from the regulatory requirements mandated by 
other components of the CAA and by other federal statutory schemes 
cited by the commenters. Even assuming the cited regulations were 
finalized and costs of these regulations were non-speculative, they 
have no bearing on the cost effectiveness analysis used to determine 
BART. Whether or not SO2 BART is cost effective in 
conjunction with possibly unrelated environmental controls that may be 
separately required by other statutes such as the Clean Water Act is 
not part of the statutory formulation that Congress prescribed to 
address regional haze.
3. Comments on Interstate Transport
    Comment: We received two comments emphasizing that regional haze is 
a problem that is not always contained by state boundaries. One of the 
commenters states that a ``regional approach is critical'' and notes 
that CAA Section 169B(c)(1) authorizes the establishment of visibility 
transport regions. The commenter states that visibility issues for the 
Wichita Mountains Wilderness Area (WMWA) make it a ``candidate for 
consideration of the establishment of a transport region.'' The 
commenter believes that a regional examination or study of all the 
issues will allow development of the long range strategies and lead to 
cost-effective management of all pollution sources that impair 
visibility in the region's Class I areas.
    Response: We agree that pollutants from one or more states can 
significantly contribute to visibility impairment in the Class I areas 
of different states. CAA section 110(a)(2)(D)(i)(II) explicitly 
provides that states must have SIPs with adequate provisions to prevent 
interference with the efforts of other states to protect visibility. 
Our FIP action ensures that sources in Oklahoma meet the RH 
requirements for BART and the visibility requirements of section 
110(a)(2)(D)(i)(II). We also agree that a regional approach to 
addressing visibility transport is important, which is why EPA funded 
Regional Planning Organizations (RPOs), such as the Central Regional 
Air Planning Organization (CENRAP), in which Oklahoma participated. 
States such as Oklahoma engaged in the RPO process for years in order 
to co-develop strategies for mitigating regional haze. At this time, we 
do not believe that delaying or setting aside these strategies in order 
to further study regional haze through the formation of a transport 
region is appropriate. However, we note the Administrator has statutory 
discretion to establish a transport region in the future and may do so 
on the Administrator's own motion or on consideration of a ``petition 
from the Governors of at least two affected States.'' CAA Section 
169B(c)(1).

D. Comments on Modeling

    Comment: AEP/PSO stated that visibility improvements expected by 
installing controls under our FIP are nearly identical to the 
improvements from the actions included in the ODEQ SIP submission, and 
that the FIP controls will not provide a noticeable improvement in 
visibility. The commenter concludes that the actions included in the 
ODEQ SIP submission are just as effective in reducing visibility 
impairment as the FIP. We received additional comments that 
installation of controls proposed in the FIP would result in 
imperceptible or nearly

[[Page 81739]]

imperceptible improvements in visibility. Information is provided in 
the comments that claims to support the statement that there is 
``virtually no distinguishable'' difference between the controlled and 
uncontrolled cases.
    Response: We performed visibility modeling as part of the 
SO2 BART determination analysis. A change of approximately 
one deciview (dv) is generally regarded as a perceptible change in 
visibility. 70 FR 39104, at 39118. ``For purposes of determining which 
sources are subject to BART, states should consider a 1.0 deciview 
change or more from an individual source to `cause' visibility 
impairment, and a change of 0.5 deciviews to `contribute' to 
impairment.'' \6\ 70 FR 39104, at 39120. Our modeling indicates that 
visibility improvements anticipated from the installation of dry 
scrubbers at each facility will result in reducing modeled impacts 
(maximum of 98th percentile daily maximum dv) from each facility at all 
nearby Class I areas to levels below 0.5 dv, with improvements greater 
than 1.0 dv at some Class I areas. We also evaluated the amount of 
improvement in the number of days that each facility would either cause 
or contribute to visibility impairment. As detailed in Table 1 below, 
the reductions resulting from our FIP would almost completely eliminate 
days when any of the three facilities' BART units have a perceptible 
impact (greater than 1.0 dv). These reductions would also significantly 
decrease the number of days that have a 0.5 deciview impact (or 
greater).
---------------------------------------------------------------------------

    \6\ ``If `causing' visibility impairment means causing a humanly 
perceptible change in visibility in virtually all situations (i.e. a 
1.0 deciview change), then `contributing' to visibility impairment 
must mean having some lesser impact on the conditions affecting 
visibility that need not rise to the level of human perception.'' 70 
FR 39104, at 39120.

                        Table 1--Average Number of Days per Year Each Facility's Visibility Impacts Exceed 1.0 and 0.5 Deciviews
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                            Average  of days/yr > 1.0 dv  Average  of days/yr > 0.5 dv
                       Class I area                           Distance to  -----------------------------------------------------------------------------
                                                              unit  (km)      Baseline       LNB       LNB & DFGD    Baseline       LNB       LNB & DFGD
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                   Sooner Units 1 & 2
--------------------------------------------------------------------------------------------------------------------------------------------------------
Caney Creek...............................................             345            3            1            0           14            5            0
Hercules-Glades...........................................             363            2            0            0            9            3            0
Upper Buffalo.............................................             327            2            1            0           11            5            0
Wichita Mountains.........................................             234           18           10            1           38           25            3
                                                           ---------------------------------------------------------------------------------------------
    TOTAL Average # of days/yr............................  ..............           25           12            1           72           38            3
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                  Muskogee Units 4 & 5
--------------------------------------------------------------------------------------------------------------------------------------------------------
Caney Creek...............................................             180           17            7            0           46           28            3
Hercules-Glades...........................................             230            7            5            0           22           14            1
Upper Buffalo.............................................             164           15            8            0           34           25            2
Wichita Mountains.........................................             324           12            7            0           26           20            2
                                                           ---------------------------------------------------------------------------------------------
    TOTAL Average # of days/yr............................  ..............           51           27            0          128           86            8
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                Northeastern Units 3 & 4
--------------------------------------------------------------------------------------------------------------------------------------------------------
Caney Creek...............................................             263           10            6            0           30           17            1
Hercules-Glades...........................................             244            6            4            0           17           11            0
Upper Buffalo.............................................             211            8            4            0           21           12            1
Wichita Mountains.........................................             323           11            7            0           24           16            2
                                                           ---------------------------------------------------------------------------------------------
    TOTAL Average # of days/yr............................  ..............           35           21            0           93           55            4
--------------------------------------------------------------------------------------------------------------------------------------------------------

    In addition, in a situation where the installation of BART may not 
result in a perceptible improvement in visibility, the visibility 
benefit may still be significant, as explained by the preamble of the 
RHR: ``Failing to consider less-than-perceptible contributions to 
visibility impairment would ignore the CAA's intent to have BART 
requirements apply to sources that contribute to, as well as cause, 
such impairment.'' 70 FR 39104, at 39129. Given that sources are 
subject to BART based on a contribution threshold of no greater than 
0.5 deciviews, it would be inconsistent to automatically rule out 
additional controls where the improvement in visibility may be less 
than 1.0 deciview or even 0.5 deciviews. A perceptible visibility 
improvement is not a requirement of the BART determination because 
visibility improvements that are not perceptible may still be 
determined to be significant. We considered the reduction in visibility 
impairment at Wichita Mountains, Caney Creek, Upper Buffalo, and 
Hercules-Glades to be significant. Installation of dry scrubbers at 
each facility will result in significant visibility improvements, 
reducing the number of days with impaired visibility due to each of 
these sources at all impacted Class I areas (Table 1).
    Comment: AEP/PSO stated that we should accept the visibility 
analysis results provided in ODEQ's SIP for determining BART for 
SO2 because the results of both our and ODEQ's visibility 
modeling are not significantly different.
    Response: We disagree that ODEQ's modeling was sufficient for 
evaluating the visibility impacts to inform our BART determination. 
Given that the emission rates that we proposed as SO2 BART 
differed from those assumed in ODEQ's BART visibility modeling, it was 
necessary to perform our own CALPUFF visibility modeling. In doing so, 
we followed EPA/FLM guidance and practices to assess the anticipated 
visibility improvements from the use of dry and wet scrubbers with 
emission rates of 0.06 and 0.04 lb of SO2/MMBtu, 
respectively. ODEQ, in contrast, used emission rates of 0.10 and 0.08 
lb of SO2/MMBtu for dry and wet scrubbers, respectively, in 
its modeling. As a result, ODEQ underestimated the visibility 
improvements associated with

[[Page 81740]]

the use of dry and wet scrubbers. Furthermore, ODEQ's BART visibility 
analyses relied on pollutant-specific modeling to evaluate the 
visibility benefits from the use of available SO2 emission 
controls. As discussed in the TSD that accompanied the proposed action 
and elsewhere in our response to comments, due to the complexity of 
atmospheric chemistry and chemical transformation among pollutants, we 
modeled all visibility impairing pollutants together to fully assess 
the visibility improvement anticipated from the use of controls. As 
detailed in the TSD, we also had updated emission estimates for 
sulfuric acid emissions based on the latest information, and corrected 
PM speciation that was included in our modeling. We therefore disagree 
with the commenter and have explained why we needed to do our own BART 
CALPUFF visibility analysis. We modeled the emission rates determined 
to be achievable by the available and technologically feasible controls 
in accordance with the appropriate procedures, utilizing current 
practices and model versions that were acceptable to us at the time 
they were conducted in the latter half of 2010, and we are confident in 
using our results as one of the five factors in making a BART 
determination.
    Comment: A commenter stated that in our visibility analysis, we 
updated the PM speciation analysis for both Sooner and Muskogee to use 
National Park Service (NPS) speciation profiles for dry bottom boilers 
rather than wet bottom boilers calculated in ODEQ's SIP submission and 
used updated coal properties. The commenter concludes that the 
difference between ODEQ's PM speciation and EPA's should not impact the 
BART analysis because primary PM species emitted directly from the 
stack generally have little overall impact on visibility impairment, 
and PM specific controls are not being considered for BART. In 
addition, the commenter states that we used different estimates for 
sulfuric acid emissions used to represent emissions of sulfate 
particles. The commenter states that this sulfate emission rate is not 
likely to be a significant factor in the overall visibility impairment 
and therefore the differences between ODEQ's modeling and EPA's 
modeling is not significant. Because the results are not significantly 
different between EPA's and ODEQ's visibility modeling, the commenter 
asserts that we have no basis for not accepting the visibility modeling 
provided in the SIP.
    Response: As discussed in the TSD, it was necessary for us to 
perform CALPUFF visibility modeling to assess the anticipated 
visibility improvements from the use of dry and wet scrubbers at the 
achievable SO2 emission rates of 0.06 and 0.04 lbs/MMBtu, 
respectively. Because revised modeling was necessary to support our 
proposed BART determination, we performed modeling following EPA/FLM 
guidance and practices, and corrected errors noted during our review of 
ODEQ's modeling. Our modeling included revised PM speciation to correct 
errors in PM speciation that was included in ODEQ's modeling. As 
detailed in the TSD, ODEQ used incorrect coal properties and emission 
factors in calculating the PM speciation used in their modeling. In 
addition, we estimated sulfuric acid emissions using the best current 
information available from the Electric Power Research Institute (EPRI) 
\7\ and the correct coal properties. ODEQ estimates of sulfuric acid 
emissions for Sooner and Muskogee failed to account for removal in the 
existing air heater or ESP. ODEQ's estimates of sulfuric acid emissions 
from the Northeastern units were based on an assumption of 3 ppm sulfur 
content conversion in the flue gas. Furthermore, sulfuric acid emission 
estimates used in ODEQ's PM pollutant-specific modeling were based on 
the erroneous PM speciation discussed above.
---------------------------------------------------------------------------

    \7\ ``Estimating Total Sulfuric Acid Emissions from Stationary 
Power Plants: Version 2010a. EPRI, Palo Alto, CA: 2010. 1020636.''
---------------------------------------------------------------------------

    We agree with the commenter that primary PM and sulfuric acid 
emissions from the sources modeled may not significantly impact 
visibility. However, in performing our own modeling analysis to support 
our BART determination, we saw no reason to not make corrections and 
estimate emissions based on accepted methodology using the best current 
information, correct emission factors and coal properties. Because 
emissions of PM and sulfuric acid vary between wet and dry scrubbers 
and do have some impact on visibility conditions, we utilized the best 
estimates for the emissions of these species to fully account for the 
difference in visibility impacts between the base case and the two 
control cases modeled.
    Comment: AEP/PSO asserted that we incorrectly rejected the ODEQ 
visibility improvement evaluation because ODEQ applied various controls 
using pollutant-specific baseline and control model runs, as opposed to 
using all visibility impairing pollutants in the calculation of the 
baseline and control model runs. The commenter states that our BART 
guidelines are not specific as to how to evaluate visibility 
improvement for the application of BART controls. The commenter asserts 
that the pollutant specific CALPUFF modeling approach is a reasonable 
but simplistic method to look at the improvement in visibility 
impairment attributable to NOX, SO2, or PM and is 
consistent with our guidance contained in a BART Q&A document that 
states that the control technology visibility analysis can be conducted 
for single units and individual pollutants.
    Response: The referenced BART Q&A document \8\ states that it may 
be appropriate to conduct a unit by unit, pollutant by pollutant 
analysis, depending on the types of units and control measures under 
consideration. As discussed in the TSD, due to the nonlinear nature and 
complexity of atmospheric chemistry and chemical transformation among 
pollutants, all relevant pollutants should be modeled together to 
predict the total visibility impact at each Class I area receptor.\9\ 
The referenced Q&A document provides clarification and guidance on 
performing visibility analyses for BART. The emissions of 
NOX and SO2, should be modeled together to 
determine the visibility impacts, and in evaluation of controls and 
combinations of controls in determining BART for a source. As seen in 
our modeling results for wet and dry scrubbers included in our proposal 
and TSD, the chemical interaction between pollutants and background 
species can lead to situations where the reduction of emissions of a 
pollutant can actually lead to an increase in visibility impairment. 
Therefore, to fully assess the visibility benefit anticipated from the 
use of controls, all pollutants should be modeled together. As 
discussed elsewhere in this response to comments, it was necessary for 
us to perform CALPUFF visibility modeling to assess the anticipated 
visibility improvements from the use of dry and wet scrubbers at the 
achievable SO2 emission rates of 0.06 and 0.04 lb/MMBtu, 
respectively. Because revised modeling was necessary to support our 
proposed BART determination, we performed modeling following EPA/FLM 
guidance and practices, including modeling all visibility impairing 
pollutants together

[[Page 81741]]

to fully assess the total visibility benefit anticipated from emission 
reductions.
---------------------------------------------------------------------------

    \8\ ``Q&A's for Source by Source BART rule,'' dated July 6, 
2005. This document is not available on EPA's Web site and is a 
draft document reflecting the preliminary views of EPA staff on a 
number of questions submitted by stakeholders.
    \9\ ``Regional Haze Regulations and Guidelines for Best 
Available Retrofit Technology (BART) Determinations,'' from Joseph 
Paisie, Geographic Strategies Group, OAQPS, to Kay Prince, Branch 
Chief, EPA Region 4, dated July 19, 2006.
---------------------------------------------------------------------------

    Comment: AEP/PSO stated that when we calculated visibility 
improvement during our BART analysis, we used the monthly average 
humidity adjustment factors provided in Table A-2 of our 2003 Guidance 
document for the assessment of natural background visibility, whereas, 
ODEQ used Table A-3 in its visibility calculations. The commenter 
states that there is no guidance that requires the use of humidity 
factors from Table A-2 as opposed to Table A-3. In addition, the 
commenter states that the use of humidity factors from Table A-2 
instead of A-3 should not make a significant difference in the overall 
visibility impairment and does not provide a basis for our rejection of 
the visibility modeling provided in the SIP submittal.
    Response: EPA guidance for estimating natural visibility conditions 
under the RHR provides monthly site-specific relative humidity factors 
for use in calculating visibility impairment.\10\ Table A-2 of the 
guidance contains the ``recommended'' values based on the 
representative IMPROVE site location. Table A-3 provides data based on 
the centroid of the area as ``supplemental information.'' Relative 
humidity factors are used with the original IMPROVE equation to 
calculate extinction from measured or predicted pollutant 
concentrations. The factors used by ODEQ are not the recommended values 
and are given in the guidance document only as supplemental 
information. Furthermore, EPA guidance for tracking progress under the 
RHR contains that same information also labeled Table A-2 and A-3 and 
is consistent with the above guidance material.\11\ This guidance 
states that the site specific values provided in Table A-2 for each 
mandatory federal Class I area are recommended to be used for all 
visibility and tracking progress calculations for that Class I area. 
Table A-3 is supplemental data provided for informational purposes. We 
used the recommended values from Table A-2 of these guidance documents 
to calculate visibility using the original IMPROVE equation.
---------------------------------------------------------------------------

    \10\ See, ``Guidance for Estimating Natural Visibility 
Conditions Under the Regional Haze Rule,'' EPA-454/B-03-005, 
September 2003.
    \11\ ``Guidance for Tracking Progress Under the Regional Haze 
Rule,'' EPA-454/B-03-004, September 2003.
---------------------------------------------------------------------------

    As discussed elsewhere in this response to comments, we find that 
our CALPUFF visibility modeling was necessary to assess the anticipated 
visibility improvements from the use of dry and wet scrubbers at the 
achievable emission rates that were determined during our analysis of 
the available control technology. We performed our CALPUFF visibility 
modeling following EPA/FLM guidance and practices. As detailed in the 
following response to comment, we used the revised IMPROVE equation to 
estimate visibility impacts. The revised IMPROVE equation utilizes a 
separate set of relative humidity adjustment factors available from the 
Federal Land Managers' Air Quality Related Values Work Group (FLAG) 
Phase I Report.\12\ We also evaluated modeling results using the 
original IMPROVE equation to quantify the sensitivity of our results to 
the choice in visibility impairment algorithm. In applying the original 
IMPROVE equation for this sensitivity analysis, we utilized the 
recommended relative humidity factors provided in the guidance.
---------------------------------------------------------------------------

    \12\ ``Federal Land Managers' Air Quality Related Values Work 
Group (FLAG) Phase I Report--Revised (2010) Natural Resource Report 
NPS/NRPC/NRR--2010/232,'' National Park Service, U.S. Department of 
the Interior, available at http://www.nature.nps.gov/air/Pubs/pdf/flag/FLAG_2010.pdf.
---------------------------------------------------------------------------

    Comment: AEP/PSO stated that ODEQ used the most up-to-date version 
of the visibility model available and utilized the original IMPROVE 
equation that was approved for use at the time the SIP was prepared. 
The commenter stated that when we performed our modeling we used the 
revised IMPROVE equation. The commenter states that the use of this 
different equation is the largest variable causing the ODEQ modeling 
results to be different from our modeling results. The commenter 
concludes that because ODEQ used the most up-to-date version of the 
equation at the time the SIP was prepared, the subsequent release of 
new methods should not be the basis for overriding the results provided 
in the SIP.
    Response: The original IMPROVE equation and the revised IMPROVE 
equation refer to two different versions of algorithms used to estimate 
visibility impairment from pollutant concentrations. The revised 
equation is a more recently available, refined version of the original 
equation and is now considered by EPA and FLM representatives to be the 
better approach to estimating visibility impairment. Compared to the 
original IMPROVE equation, this revised IMPROVE equation has less bias, 
accounts for more pollutants, incorporates more recent data, and is 
based on considerations of relevance for the calculations needed for 
assessing progress under the RHR.\13\
---------------------------------------------------------------------------

    \13\ Revised IMPROVE algorithm for Estimating Light Extinction 
from Particle Speciation Data, IMPROVE, January 2006 (http://vista.cira.colostate.edu/improve/Publications/GrayLit/gray_literature.htm); Hand, J.L., Douglas, S.G., 2006, Review of the 
IMPROVE Equation for Estimating Ambient Light Extinction 
Coefficients--Final Report (http://vista.cira.colostate.edu/improve/Publications/GrayLit/016_IMPROVEEeqReview/IMPROVEeqReview.htm).
---------------------------------------------------------------------------

    As discussed elsewhere in this response to comments, it was 
necessary for us to perform CALPUFF visibility modeling to assess the 
anticipated visibility improvements from the use of dry and wet 
scrubbers at the achievable SO2 emission rates of 0.06 and 
0.04 lb/MMBtu, respectively for Step 5 of the BART analysis. As part of 
our BART analysis, we performed CALPUFF modeling to assess the impacts 
of the SO2 BART proposed controls on the sources at issue on 
visibility impairment. Because the revised IMPROVE equation is the 
preferred method for analyses being conducted at this time,\14\ we 
estimated the CALPUFF visibility impacts using this peer reviewed 
algorithm. We also evaluated modeling results using the original 
IMPROVE equation to quantify the sensitivity of our results to the 
choice in visibility impairment algorithm. Visibility benefits 
estimated using the original IMPROVE equation were larger than those 
estimated with the revised IMPROVE equation at all four Class I areas 
included in the modeling. We note that, using either equation, 
visibility benefits were projected for the installation of scrubbers 
and support the conclusion that dry scrubbers are the appropriate BART 
control for each facility.
---------------------------------------------------------------------------

    \14\ U.S. EPA. Additional Regional Haze Questions. U.S. 
Environmental Protections Agency. August 3, 2006, available at 
http://www.wrapair.org/forums/iwg/documents/Q_and_A_for_Regional_Haze_8-03-06.pdf#search=%22%22New%20IMPROVE%20equation%22%22; WRAP 
presentation, ``Update on IMPROVE Light Extinction Equation and 
Natural Conditions Estimates'' Tom Moore, May 23, 2006; U.S. Forest 
Service, National Park Service, and U.S. Fish and Wildlife Service. 
2010. Federal land managers' air quality related values work group 
(FLAG): phase I report--revised (2010). Natural Resource Report NPS/
NRPC/NRR--2010/232. National Park Service, Denver, Colorado.
---------------------------------------------------------------------------

    Comment: AEP/PSO states that we incorrectly compared baseline 
visibility impairment with visibility improvement for controlled cases. 
The commenter states that both the Oklahoma SIP and the proposed FIP 
compared an inherently higher 24-hour average for the baseline with an 
inherently lower 30-day average for the controlled case. The commenter 
states that the same averaging period should be used so

[[Page 81742]]

decisions are not biased toward greater SO2 emission 
reductions. The commenter also states that our analysis is consistent 
with many other BART analyses and determinations prepared by EPA, 
states and industry, but inconsistent with the proposed BART 
determination for the Four Corners Power Plant in New Mexico and BART 
guidance from the State of Colorado.
    Response: The approach that we have taken for estimating the 
visibility impacts of wet and dry scrubbing is appropriate based on the 
approach set out in the BART Guidelines. The BART guidelines state that 
in estimating visibility impacts:

    Use the 24-hour average actual emission rate from the highest 
emitting day of the meteorological period modeled (for the pre-
control scenario). Calculate the model results for each receptor as 
the change in deciviews compared against natural visibility 
conditions. Post-control emission rates are calculated as a 
percentage of pre-control emission rates. For example, if the 24-hr 
pre-control emission rate is 100 lb/hr of SO2, then the 
post control rate is 5 lb/hr if the control efficiency being 
evaluated is 95 percent.

The BART guidelines also state:

    The emissions estimates used in the models are intended to 
reflect steady-state operating conditions during periods of high 
capacity utilization. We do not generally recommend that emissions 
reflecting periods of start-up, shutdown, and malfunction be used, 
as such emission rates could produce higher than normal effects than 
would be typical of most facilities.

    The BART guidelines provide a consistent approach to assess the 
visibility improvement due to the installation of controls allowing 
comparison between BART assessments. Setting the baseline using the 
highest emitting day during the period being assessed provides a 
consistent approach for sources to assess their baseline impacts and 
gives an assessment of the maximum impact the source will have on 
visibility. ODEQ, EPA and AEP agreed on how to model the baseline 
emissions, including the baseline emission rates, in a previous 
modeling protocol and subsequent modeling reports. ODEQ's RH SIP, and 
EPA's proposed FIP incorporated this same baseline emission rate 
approach that is consistent with previous agreements and analyses that 
AEP had conducted.
    In modeling the post-control emission rates, we considered the 
reasonably anticipated control efficiency of the available control 
technology taking into account that the BART modeling should reflect 
steady-state operating conditions and should not generally reflect 
periods of start-up, shutdown and malfunction. As discussed previously 
in our TSD and elsewhere in this notice and the Supplemental RTC, 
control efficiencies reasonably achievable by dry scrubbing and wet 
scrubbing were determined to be 95% and 98% respectively. We also note 
that OG&E directed its vendors to provide bids on a dry SO2 
scrubber system that was designed to remove 95% of the SO2. 
The two AEP sources were modeled with baseline SO2 emission 
rates of 5230.8 and 5034.6 lb/hr for Units 3 and 4 
respectively. These rates for the two AEP sources were modeled using 
the firing rate of each unit with baseline SO2 emission 
rates of 0.9 lb/MMBtu which, as discussed above, are the same rates, 
previously provided by AEP and utilized by ODEQ in the Oklahoma RH SIP 
for the baseline emission rates. Applying the expected 95% reduction in 
emission rates for a dry scrubber, in accordance with the example given 
in the BART guidelines, would result in an emission rate of 0.045 lb/
MMBtu. This value is lower than our proposed BART SO2 
emission limit of 0.06 lb/MMBtu. The 0.06 lb/MMBtu emission limit we 
chose was based on a thorough review of achievable emission rates of 
current Dry Flue Gas Desulfurization (DFGD) scrubbers and the example 
method for the BART guidelines that yields 0.045 lb/MMBtu is not 
appropriate in this case for estimating future emission rate for 
modeling. We chose to model the future SO2 emission rate of 
0.06 lb/MMBtu rather than 0.045 lb/MMBtu because this is consistent 
with our proposed BART emission limit and is a reasonable estimate of 
future emissions in order to estimate the future visibility improvement 
from baseline levels. Our approach of modeling the proposed emission 
limit is consistent with the approach taken by ODEQ in their SIP and in 
our action on the BART FIP for the State of New Mexico and is not as 
conservative as using the emission rate based on percentage reduction 
as outlined in the BART guideline.
    As discussed elsewhere, the BART determination is based on 
consideration of five factors, including the degree of improvement in 
visibility which may reasonably be anticipated to result from the use 
of such technology. The visibility modeling is intended to give a 
reasonable best estimate of the visibility impacts from an evaluation 
of emission reductions. The visibility analysis is only one of the 
factors in a BART determination. In this final action, we are setting a 
SO2 limit of 0.06 lb/MMBtu to be calculated on a 30-day 
rolling average Boiler Operating Day. We modeled the 0.06 lb/MMBtu in 
our proposal, which equates to a 93 percent reduction in emissions, 
because we have determined this emission rate to be achievable. This 
percentage reduction is less than would be expected from the 
installation of a DFGD that has been optimally designed (refer to 
Figure 7 and 8 of the Supplemental RTC and the associated responses to 
comments).
    We recognize that sources complying with a 30 day average may at 
times operate above the 30 day average emission limit but they will 
have to balance those times by operating below the limit at other 
times. This variability is difficult to assess, though a prudent source 
will strive to remain below the 30-day emission limit as much as 
possible. In some instances, it may be appropriate to model a slightly 
higher emission rate when limiting the emissions using a 30-day average 
to account for potential variability, when the amount of variability is 
well understood. In this case, we believe using the 30 day average 
emission limit is a reasonable approach to project future emissions 
that would reasonably be anticipated in accordance with BART guidelines 
because we have no reason to think the variability in the future case 
will be large enough to impact our evaluation of the five factors.
    We did not believe it was appropriate to assess variability based 
on past history of emissions at the facilities because there is 
inherently more variability in historic data when facilities are not 
specifically controlling to achieve low SO2 emissions and 
the facility emissions instead can vary due to the range of types of 
coal purchased. As the limits are reduced to a level in the range that 
was proposed in our action, the amount of variability that would exist 
is expected to decrease, as the source must demonstrate compliance on a 
30-day BOD compliance level with a much tighter limit than it had 
previously. We have seen this in evaluation of some sources in 
comparing their pre-control emission variability with their post-
control emission variability.
    As discussed in a later response to comment, we note the TS Power 
Plant near Dunphy, Nevada, which has a similar permitted SO2 
emission limit to our BART FIP, maintained a 30-day BOD emission rate 
below 0.06 lb/MMBtu for an approximately 20-month period of time in 
2010-2011. This plant burns a similar Powder River Basin (PRB) coal as 
the six AEP/PSO and OG&E units. In addition, the Wygen II facility, 
located outside Gillette, Wyoming, and the Weston 4 facility, near 
Wausua, Wisconsin, also burn coal similar to the OG&E and AEP/PSO's

[[Page 81743]]

units and have been able to maintain 30-day BOD SO2 emission 
rates below 0.06 lb/MMBtu for significant periods of time during the 
years of 2009-2011. CEM data for the TS Plant (Figure 7 of the 
Supplemental RTC) shows limited variability in 24-hr emissions. We note 
that this data includes periods of start-up, shutdown, and malfunction 
that would normally be considered when evaluating the emission rate to 
be modeled to represent steady-state operating conditions for BART 
modeling. In evaluation of other facilities we did find where they had 
operated for months at a significantly lower emission rate than 0.06 
lb/MMBtu, with limited variability under steady-state conditions.
    The commenter pointed to other actions and guidance concerning 
emission rate estimates and indicated that we were not consistent with 
those approaches. The commenter pointed to the EPA Region 9 proposal 
for the Four Corners power plant, which used the percent reduction 
approach and the 24-hour maximum actual baseline emission rate to 
estimate a future controlled emission rate. We note that we evaluated 
this technique (see discussion earlier in this response) that is 
outlined in the BART guideline as one acceptable technique and it 
resulted in a value (0.045 lb/MMBtu) that was not reasonable compared 
to the 30-day emission limit (0.06 lb/MMBtu) that we proposed and 
determined to be technically feasible. The commenter also pointed to 
guidance that Colorado has developed for their BART sources that 
indicates a maximum 24-hour future controlled emission rate should be 
used in conjunction with using the maximum actual 24-hour baseline 
emission rate.
    The BART guidelines state:

    Make the net visibility improvement determination.
    Assess the visibility improvement based on the modeled change in 
visibility impacts for the pre-control and post-control emission 
scenarios.
    You have flexibility to assess visibility improvements due to 
BART controls by one or more methods. You may consider the 
frequency, magnitude, and duration components of impairment.

    The BART guidelines allow for some flexibility in how to assess 
visibility improvements due to BART controls. As we discuss elsewhere 
in this response, we consider issues related to frequency, magnitude 
and duration of emission levels that may occur in comparison to our 
proposed 0.06 lb/MMBtu 30-day limit and the potential for impacting the 
visibility projections. We concluded that the amount of times the 
variability of emissions would exceed 0.06 lb/MMBtu on a maximum daily 
process would not be expected to be of sufficient magnitude to have a 
large impact on our visibility improvement estimates. We agree that the 
BART guidelines allow for some flexibility in how visibility 
improvement determinations are conducted. We considered processes 
similar to Colorado's approach, including the methodology given as an 
example in the BART guidelines, but determined we did not have 
sufficient information to accurately estimate the future maximum 24-
hour emission rate and furthermore concluded that existing modeling 
indicated that small changes would not significantly impact our 
visibility improvement estimates. Overall, the BART guidelines give 
some flexibility to how the visibility improvements can be calculated 
and the approach that we have used is reasonable based on the 
information available and is not inconsistent with the BART guidelines.
    We conducted modeling for future emission rates of 0.04 and 0.06 
lb/MMBtu of SO2 in our proposal. We note that at these low 
SO2 emission rates, the most impacted days were more nitrate 
driven days because the SO2 rates were low. Therefore, a 
slight increase in emission rates on the order of 10% or so for a 
maximum 24-hour emission rate would not be expected to result in much 
change in visibility estimates. We do note that other modeling 
conducted by the source's consultants and the state indicates that a 
significant increase in the controlled SO2 emission rate 
would decrease the visibility impairment improvements from installation 
of controls and result in much lower relative visibility improvement. 
As further discussed elsewhere in this response we find our future 
emission rate to be a reasonable assessment of the visibility 
improvement due to the setting of a 0.06 lb/MMBtu on a 30-day BOD 
limit.
    In summary, we find our approach to modeling the baseline and 
control case emissions was a reasonable estimate of reduction in 
impairment and not inconsistent with the BART guideline. We recognize 
that it is possible that the facility will operate at slightly higher 
emission rates at times, but it is also true that to remain in 
compliance over a 30-day rolling average, it will also have to operate 
at lower emission rates than 0.06 lbs/MMBtu. Furthermore, we have shown 
that other facilities have demonstrated that it is feasible to operate 
below 0.06 lbs/MMBtu for extended periods of time. Finally, we have 
noted that even if emissions are slightly higher than 0.06 lbs/MMBtu, 
at times, it would not be expected to increase the visibility 
impairment significantly because at these low concentrations, 
visibility impairment due to AEP/PSO sources is primarily due to 
nitrates. We find the approach for estimating improvements in 
visibility due to our proposed emission level that we have used is 
appropriate based on the information available and is not inconsistent 
with the BART guidelines. For these reasons, we believe the proposal 
was based on a reasonable assessment of visibility improvements for 
consideration as one of the five factors of the BART decision.
    Comment: A commenter submitted a review of our modeling results for 
controlling SO2 emissions, noting a 2.89 deciview 
improvement in visibility at the Wichita Mountains and a cumulative 
improvement in visibility total of 8.20 deciviews. The commenter 
believes our CALPUFF modeling is appropriate and concurs with our 
emission calculations and speciation. They do, however, note several 
``possibly incorrect input values'' regarding base elevations of 
several units and the stack gas exit velocity of one unit. The 
commenter expressed the view that corrected values would not 
substantially change results and conclusions. The commenter also 
contends that EPA's proposed SO2 BART may benefit Oklahoma 
and the facilities, because the commenter believes that based on 
results of their dispersion modeling, the units are currently 
contributing to violations of the one-hour SO2 NAAQS.
    Response: We agree with the commenter that our modeling 
calculations and speciations are appropriate. We further agree with the 
commenter's noted visibility improvement resulting from the 
SO2 controls that we are requiring in the FIP. It is true 
that states will be required to submit plans demonstrating attainment 
or maintenance of the new one-hour SO2 NAAQS. However, this 
is not a consideration for our action, which is directed solely to 
ensuring the state has met the BART requirements of the RHR and the 
requirements of CAA section 110(a)(2)(D)(i)(II). With respect to the 
noted ``possibly incorrect input values,'' we agree that correcting 
these values would not substantially change our results and 
conclusions.

E. Summary of Responses to Comments on the SO2 BART Cost 
Calculation

    We received many comments on issues concerning our cost 
calculations for our proposed SO2 BART determinations on the 
six OG&E and AEP/PSO units. The full text received

[[Page 81744]]

from these commenters is included in the docket associated with this 
action. Additionally, our summary and response for these comments is 
provided in the ``Response to Technical Comments for Sections E through 
H of the Federal Register Notice for the Oklahoma Regional Haze and 
Visibility Transport FIP,'' (or Supplemental RTC), and it is available 
in the docket. Although we summarize them here, please see the 
Supplemental RTC for a full accounting of the issues and how they 
influenced our final decision. We deviate in sections E., F., G., and 
H., from the comment-response format of the rest of the notice, as many 
of the comments summarized herein were drawn from multiple, lengthy, 
and highly technical comments.
    The significant aspects of our approach to cost estimations in 
consideration of all comments are summarized in this section. Overall, 
our final rulemaking retains the basis for the cost effectiveness 
evaluation and cost estimates we employed in our proposal. However, as 
discussed in more detail below, we are changing several factors in the 
cost calculations for the four OG&E units as a result of the comments 
we received. We are making no changes to the cost calculations for the 
two AEP/PSO units.
1. Control Cost Manual Methodology
    The Control Cost Manual must be followed to the extent possible 
when calculating the cost of BART controls.\15\ This is necessary to 
ensure that a consistent methodology is used when comparing cost 
effectiveness determinations. The Control Cost Manual allows site-
specific conditions to be incorporated in certain circumstances. Site-
specific conditions can include vendor quotes, space constraints, a 
design feature that could complicate installing a control, or unusual 
circumstances that introduce a cost not contemplated by the Control 
Cost Manual. OG&E incorporated many of these into its cost evaluation. 
However, the RHR specifically requires that the analyst document any 
such site-specific conditions.\16\ Thus, the RHR places the burden on 
the analyst to make this demonstration, and on EPA to approve it, 
disapprove it, or document it when promulgating a FIP. Nevertheless, 
with the exceptions noted herein and in our Supplemental RTC, we 
approved many of those site-specific cost modifications.
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    \15\ Very limited situations exist under which an analyst can 
depart from the Control Cost Manual methodology under the RH rule. 
``The basis for equipment cost estimates also should be documented, 
either with data supplied by an equipment vendor (i.e., budget 
estimates or bids) or by a referenced source (such as the OAQPS 
Control Cost Manual, Fifth Edition, February 1996, EPA 453/B-96-
001). In order to maintain and improve consistency, cost estimates 
should be based on the OAQPS Control Cost Manual, where possible. 
The Control Cost Manual addresses most control technologies in 
sufficient detail for a BART analysis.'' 70 FR 39104, at 39166.
    \16\ A cost determination can deviate from the Control Cost 
Manual methodology if you ``include documentation for any additional 
information you used for the cost calculations, including any 
information supplied by vendors that affects your assumptions 
regarding purchased equipment costs, equipment life, replacement of 
major components, and any other element of the calculation that 
differs from the Control Cost Manual.'' Id.
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    The Control Cost Manual uses the overnight method of cost 
estimation, widely used in the utility industry.\17\ The U.S. Energy 
Information Administration (EIA) defines ``overnight cost'' as ``an 
estimate of the cost at which a plant could be constructed assuming 
that the entire process from planning through completion could be 
accomplished in a single day. This concept is useful to avoid any 
impact of financing issues and assumptions on estimated costs.'' \18\ 
EIA presents all of its projected plant costs in terms of overnight 
costs. The overnight cost is the present value cost that would have to 
be paid as a lump sum up front to completely pay for a construction 
project.\19\ The overnight method is appropriate for BART 
determinations because it allows different pollution control equipment 
to be compared in a meaningful manner. Because ``different controls 
have different expected useful lives and will result in different cash 
flows, the first step in comparing alternatives is to normalize their 
returns using the principle of the time value of money * * * . The 
process through which future cash flows are translated into current 
dollars is called present value analysis. When the cash flows involve 
income and expenses, it is also commonly referred to as net present 
value analysis. In either case, the calculation is the same: Adjust the 
value of future money to values based on the same point in time 
(generally year zero of the project), employing an appropriate interest 
(discount) rate and then add them together.'' \20\ This is the 
overnight method, in which costs are calculated based on current 
dollars. Therefore, consistent with our proposal, we find that the 
overnight method is appropriate for calculating costs for all six 
units.
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    \17\ See Control Cost Manual, Section 2.3 to 2.4.
    \18\ EIA, ``Updated Capital Cost Estimates for Electricity 
Generation Plants,'' November 2010, footnote. 2, available at: 
http://www.eia.gov/oiaf/beck_plantcosts/?src=email.
    \19\ Steven Stoft, Power Economics: Designing Markets for 
Electricity, 2002.
    \20\ Id., page 2-18.
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    OG&E and others incorrectly assume that BART cost effectiveness 
should be based on the ``all-in'' cost method, which includes all of 
the costs of a financial transaction, including interest, commissions, 
and any other fees from a financial transaction up to the date that the 
project goes into operation, as of the assumed commercial operating 
dates of the scrubbers, 2014 and 2015. This is an entirely different 
method than that prescribed in the Control Cost Manual. OG&E and others 
conclude that dry scrubbers are not cost effective for the six units, 
based on all-in costs reported in 2014 to 2015 dollars, compared to 
costs estimated at other similar facilities based on overnight costs 
and 2009 and earlier dollars. This comparison is an invalid because 
OG&E's 2014 and 2015 all-in costs are much higher than the 
corresponding overnight costs, as prescribed by the Control Cost 
Manual. This makes the estimated cost of scrubbers at the six units 
appear to be higher than scrubbers required at other similar facilities 
costed using the overnight method. Many of the corrections we make to 
ODEQ's cost estimates for the six OG&E and AEP/PSO units are due to the 
fact that ODEQ did not follow this provision of the Control Cost Manual 
in its SIP submittal. Please refer to our Supplemental RTC in the 
docket for more information about how the overnight costing methodology 
is employed by the Control Cost Manual.
2. Revised Cost Calculations for the OG&E Units
    OG&E's cost estimates deviate from the Control Cost Manual, which 
is based on the overnight cost approach. In its cost estimates, OG&E 
has improperly included allowances for excessive contingencies 
allowances for funds during construction (AFUDC), double counted 
certain expenses, and improperly relied on the Electric Power Research 
Institute (EPRI) cost model, CUECost. These deviations from the Control 
Cost Manual, occurring because of the reliance upon the all-in cost 
methodology, artificially increase the cost of scrubbing at Sooner and 
Muskogee, compared to the cost at other similar facilities using the 
overnight cost methodology.
    OG&E's cost estimates relied on vendor quotes and site specific 
estimates for certain additional costs. We support the use of vendor 
quotes and site specific estimates but only as used within the 
parameters of the overnight cost methodology. The Guidelines, cited in 
this comment, are

[[Page 81745]]

clear that ``[y]ou should include documentation for any additional 
information you used for the cost calculations, including any 
information supplied by vendors that affects your assumptions regarding 
purchased equipment costs, equipment life, replacement of major 
components, and any other element of the calculation that differs from 
the Control Cost Manual.'' \21\ However, much of the documentation OG&E 
and others cite to support deviations from the Control Cost Manual was 
not provided to us. Thus, we were unable to analyze their contents and 
determine whether these deviations were appropriate. Also, although 
OG&E provided two spreadsheets that listed its cost line items, these 
spreadsheets, each over 600 lines in length, were stripped of all 
formulas for cell calculations, preventing any meaningful review, 
despite our request for that material.
---------------------------------------------------------------------------

    \21\ 70 FR 39104, at 39166, footnote 15.
---------------------------------------------------------------------------

Capital Recovery Factor
    We are changing one input to the cost calculations for the four 
OG&E units based on a comment we received from OG&E concerning the 
Capital Recovery Factor (CRF). OG&E states that, while the Control Cost 
Manual includes a default rate of 7% for the social discount interest 
rate, we should use a site-specific social discount interest rate for 
the four OG&E units. This rate includes several site-specific 
variables, including income tax. The commenter states that the CRF 
includes not only recovery of principal but also a return on the 
principal, with the rate of return equal to the discount rate. OG&E 
states that for an investor owned utility, such as itself, which is 
financed by a mix of debt and equity, the discount rate is equal to the 
weighted average of the equity return and debt return.
    We agree that a site-specific social discount interest rate is 
appropriate based on the documentation provided by the commenter. 
However, we disagree that such a rate can include income tax. The 
Control Cost Manual states ``this Manual methodology does not consider 
income taxes.'' Control Cost Manual, page 2-9. The site-specific social 
discount interest rate, excluding income tax, is 6.01%, which is less 
than the default rate of 7%. Thus, we have revised our cost 
effectiveness analysis in Exhibits 1 and 2 for Options 1 and 2, to use 
the levelized interest rate of 6.01%, as reported by OG&E, adjusted to 
remove income taxes. This rate is consistent with OG&E's real average 
cost of capital and falls within the range of 3% to 7% recommended by 
OMB for regulatory cost analyses. This correction moderately improved 
the cost effectiveness, thus lowering the calculation of $/ton 
SO2 removed. For detailed information on our calculation, 
please see the Supplemental RTC.
Construction Management
    In our proposal, we revised the cost estimate to remove what we 
took to be double counting of the Balance of Plant (BOP) construction 
management costs. OG&E explained in a comment that crew wage rates do 
not include contractor general and administrative (G&A) costs and that 
construction management is the cost of third-party construction 
management, different from the BOP profits contractor and different 
from the owner. Based on this explanation, we have restored the 
construction management costs in our revised Options 1 and 2 cost 
estimates in Exhibits 1 and 2. This correction slightly diminished the 
cost effectiveness, thus raising the calculation of $/ton 
SO2 removed.
Scrubber Design and Emission Baseline Mismatch
    We retain both our Option 1 and Option 2 cost effectiveness 
approaches to the mismatch between the design of OG&E's SO2 
scrubbers and the coal they currently burn. OG&E specified to its 
vendors that they provide cost estimates for SO2 scrubber 
systems designed to treat the exhaust gases from a coal that contains 
much higher amounts of sulfur than coals that were typically burned in 
the baseline period (2004-2006). However, in calculating the cost 
effectiveness, OG&E used its historical baseline emissions, which 
resulted from the burning of those lower sulfur coals. Thus, OG&E 
costed scrubbers that were overdesigned based on the coal that was, and 
is, typically burned. This resulted in two errors that both combined to 
make the control technology appear less cost effective.
    First, the BART Guidelines require that we calculate cost 
effectiveness on the basis of annualized cost divided by tons of 
pollutant removed from the emissions baseline ($/ton). Therefore, use 
of a baseline that is lower than would result from burning the higher 
sulfur coal the scrubber was designed to treat, lowers the denominator 
in the $/ton equation, and skews the cost effectiveness calculation to 
appear less cost effective. We account for this mismatch in Option 1 by 
raising the baseline to match the higher sulfur coal the scrubber 
system was designed to treat.
    Second, although we have adjusted our calculation in response to 
OG&E's comments, we conclude that the over designed scrubber system was 
more expensive than necessary to treat the coal OG&E historically 
burned and continues to burn. We account for this mismatch in Option 2 
by slightly decreasing the capital costs to reflect a scrubber designed 
to treat the exhaust gases from the coal OG&E has historically burned, 
while retaining the historical emission baseline.
    We find that, whether OG&E chooses to burn its current coal, or 
burn a coal that its scrubber system was designed to treat, the 
resulting cost effectiveness lies in the range defined by Options 1 and 
2 (below). We find that both options are cost effective in light of the 
five-step BART analysis.
Cost Adjustment of Scrubber in Option 2
    As we describe above, in calculating cost effectiveness under 
Option 2 in our proposal, we also analyzed the cost of a dry scrubber 
for the OG&E units, assuming the scrubber would be re-sized to scrub 
the coal being currently burned. We did this using a cost scaling 
equation based on the differences between the sulfur content of the 
coal OG&E typically burns versus the coal their scrubber system was 
designed to treat. OG&E responded in a comment to us that the exhaust 
gas flow rate, rather than the sulfur content, is the primary variable 
that affects scrubber sizing. Thus, the use of a higher sulfur coal 
would not significantly affect the size, and hence the cost of a 
scrubber. Based on the information OG&E supplied, we re-adjusted the 
cost of Option 2 based on certain design algorithms in the dry scrubber 
absorber (SDA) cost model developed by OG&E's contractor, Sargent & 
Lundy for EPA.\22\ The results of this analysis indicate that the use 
of the lower sulfur coal alone would reduce the capital cost of the 
scrubber by about $7 million or 3%.
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    \22\ Sargent & Lundy, IPM Model--Revisions to Cost and 
Performance for APC Technologies, SDA FGD Cost Development 
Methodology, Final, August 2010, Table 1.
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Other Issues Concerning Site-Specific Costs
    In addition to those comments that resulted in a modification to 
our cost basis, two others merit particular emphasis. These comments 
led us to investigate two other line item costs to determine whether we 
underestimated the costs of the scrubbers for the four OG&E units by 
not using site-specific values. We determined that, even if we made 
changes to the cost calculations to account for these site-specific 
cost line items, the cost of controls would be

[[Page 81746]]

even more cost-effective than our proposed range. These line items 
costs are: (1) Auxiliary power; and (2) capacity factor for Option 2. 
These issues were uncovered during the course of preparing our response 
to comments, but did not directly follow from information provided by 
the comments. Thus, we did not further modify our cost basis, but 
discuss these issues as they serve to further illustrate why we believe 
our cost basis likely overestimates the costs of control and that our 
conclusions that dry scrubbers for the six OG&E and AEP/PSO units are 
cost effective and are reasonable.
a. Auxiliary Power
    We received a comment that EPA incorrectly lowered OG&E's auxiliary 
power costs for the DFGD/FF control systems on the premise that the 
unit cost of electricity used in the cost estimate was higher than the 
cost to OG&E to produce electricity. Auxiliary power is the sum of the 
demand by the scrubber, baghouse, and booster fans (the latter required 
to overcome the increase in backpressure from adding these controls) 
and is accounted for in a BART cost effectiveness analysis. OG&E used 
average year-round market retail rates of $85.93/MWh (2015 dollars) for 
Sooner and $83.83/MWh (2014 dollars) for Muskogee as the best long-run 
measure of auxiliary power costs. The cost of auxiliary power affects 
the cost effectiveness calculation in both Option 1 and Option 2.
    We have concluded that our proposed cost of $50/MWh is an 
appropriate estimate of the cost of auxiliary power for the four OG&E 
units. We arrived at this number because OG&E's summary of auxiliary 
power costs indicates the range used for other similar facilities is 
$30/MWh to $50/MWh.\23\ We took the most conservative view based on 
this report and adopted the highest value in this range. However, even 
if we were to take OG&E's view that a site-specific auxiliary power 
cost is more appropriate, we disagree that we could use the market-
value of power for purposes of the BART determination because the 
utility would not pay market price. We estimate that the actual site-
specific cost of auxiliary power for the four OG&E units is no more 
than $36/MWh. However, because we arrived at this figure due to 
independent research that we do not view as being a logical outgrowth 
of the comment we received, we have not revised our cost effectiveness 
analysis to use $36/MWh. Instead, we retain the $50/MWh figure we 
proposed. We view this example as further evidence that OG&E's scrubber 
costs are artificially inflated, and that the cost of controls under 
both options in our FIP is reasonable.
---------------------------------------------------------------------------

    \23\ December 28, 2009 S&L FollowUp Report, Attach. C, pdf 109 
(Gerald Gentleman--$45.65/MWh; White Bluff--$47/MWh; Boardman/
Northeastern/Naughton--$50/MWh; Nebraska City--$30/MWh).
---------------------------------------------------------------------------

b. Capacity Factor in Option 2
    ODEQ calculated future annual emissions assuming a 90% capacity 
factor. In comparison, during the years that established the emission 
baseline (2004-2006), the units operated only 78.5% of the time, on 
average. Thus, ODEQ's calculation of emission reductions from scrubbers 
compares uncontrolled 2004-2006 baseline emissions, when the units 
operated at 78.5% of capacity, to controlled emissions when burning a 
higher sulfur coal, with the units operating at 90% capacity. This 
mismatch results in two errors in estimating the cost of Option 2: The 
future emissions were overestimated, but certain operating costs were 
underestimated. Correcting these errors in the cost calculations would 
make Option 2 even more cost effective than our proposed calculations, 
as the resulting decrease in the operating costs would offset the 
increase in the capacity factor in the $/ton calculation. However, 
because we arrived at these errors due to independent research that we 
do not view as being a logical outgrowth of the comment we received, we 
have not revised our cost effectiveness analysis in Option 2. We view 
this example as further evidence that OG&E's scrubber costs are 
artificially inflated, and that the cost of controls under both options 
in our FIP is reasonable.
    We made no additional changes to our cost evaluation as a result of 
the comments we received. As summary of our final $/ton cost 
effectiveness calculations are provided below:

------------------------------------------------------------------------
                                   Proposal (Sooner/    Final (Sooner/
                                       Muskogee)           Muskogee)
------------------------------------------------------------------------
Option 1........................       $1,291/$1,317       $1,239/$1,276
Option 2........................       $2,048/$2,366       $2,747/$3,032
------------------------------------------------------------------------

3. Cost Calculations for the AEP/PSO Units
    We received a number of comments from AEP/PSO concerning our 
SO2 BART cost estimate for the two Northeastern units. Some 
of these comments objected to our incorporation of OG&E's site specific 
information in AEP/PSO's scrubber cost estimate. Other comments 
objected to specific line item costs in our cost estimates for both wet 
and dry scrubbers. We proposed the cost effectiveness of dry scrubbing 
to be $1,544/ton, and the cost effectiveness of wet scrubbers to be 
approximately 9% more. As we note in more detail in our separate 
Supplemental RTC, the ODEQ SO2 BART evaluation of AEP/PSO 
Northeastern units 3 and 4 does not provide any support for its 
assumption that the cost of dry scrubbers is $555/kW to $582/kW, 
figures we consider to be high in comparison to other BART scrubber 
determinations. However, the Northeastern units are very similar to the 
Sooner and Muskogee units, for which vendor quotes were available for 
dry scrubbers. We used these vendor quotes to support our cost analysis 
for the Northeastern units. After having reviewed all comments 
concerning our SO2 BART cost estimates for the AEP/PSO 
units, we have determined that no changes were warranted to our 
proposed cost estimates. Thus, absent any supporting information from 
AEP/PSO for any of the capital costs it presents, we find our BART 
SO2 cost evaluation to be well founded, representative of 
the AEP/PSO units in question, and based on the best information 
available to us.
4. Conclusion
    We find that under Option 1, the costs to comply with the FIP will 
be $1,239/ton for Units 1 and 2 of the OG&E Sooner plant and $1,276/ton 
for Units 4 and 5 of the OG&E Muskogee plant. Under Option 2, the cost 
to comply with the FIP will be $2,747/ton for Units 1 and 2 of the OG&E 
Sooner plant and $3,032/ton for Units 4 and 5 of the OG&E Muskogee 
plant. For Units 3 and 4 of the AEP/PSO Northeastern plant, we find 
that the costs to comply with the FIP remain at $1,544/ton, as we

[[Page 81747]]

proposed. We find these ranges to be cost effective for these six units 
under the five-step analysis for BART under the RHR. As previously 
stated, our complete, technical responses to comments received on the 
issue of costs are in the Supplemental RTC in the docket.

F. Summary of Responses to Visibility Improvement Analysis Comments

    We received comments on Step 5 of BART: Degree of improvement in 
visibility which may reasonably be anticipated to result from the use 
of scrubber technology. Commenters contested our determination that 
OG&E and AEP/PSO's facilities significantly contribute to visibility 
impairment. We explain that we find that dry scrubbers are cost 
effective for the six OG&E and AEP/PSO units, in light of the 
visibility improvement these controls are predicted to achieve. 
Commenters also disputed our determination not to use the $/deciview 
metric in the Step 5 BART analysis when this approach was used by ODEQ. 
OG&E provided a $/deciview analysis for its units and comparable BART 
determination performed by us. In our analysis for our BART FIP for 
OG&E and AEP/PSO, we did not evaluate $/deciview. We explain that the 
BART Guidelines list the $/deciview metric as an optional cost 
effectiveness measure that can be employed along with the required $/
ton metric for use in a BART evaluation. The metric can be useful in 
comparing control strategies or as additional information in the BART 
determination process; however, due to the complexity of the technical 
issues surrounding regional haze, we have never recommended the use of 
this metric as a cutpoint in making BART determinations. We note that 
to use the $/deciview metric as the main determining factor would most 
likely require the development of thresholds of acceptable costs per 
deciview of improvement for BART determinations for both single and 
multiple Class I analyses. We have not developed such thresholds for 
use in BART determination made by us. As OG&E acknowledges, EPA did not 
use this metric as part of its proposed BART determinations for either 
the Four Corners Power Plant FIP in AZ, or the San Juan Generating 
Station FIP in NM. Generally speaking, while the metric can be useful 
if thoughtfully applied, we view the use of the $/deciview metric as 
suggesting a level of precision in the calculation of visibility 
impacts that is not justified in many cases. While we did not use a $/
deciview metric, we did, however, consider the visibility benefits and 
costs of control together, as noted above by weighing the costs in 
light of the predicted visibility improvement.

G. Summary of Responses to Comments Received on the SO2 BART 
Emission Limit

    We received comments stating we did not adequately support our 
SO2 BART emission limit of 0.06 lbs/MMBtu for the six OG&E 
and AEP/PSO units. In analyzing the control technology, the RHR 
mandates that we take into account the most stringent emission control 
level that the technology is capable of achieving. 70 FR 39104, at 
39166. In accordance with the RHR, when identifying an emissions 
performance level to evaluate under BART, consideration of recent 
regulatory decisions and performance data (e.g. manufacturer's data, 
engineering estimates, and the experience of other sources) is 
required. Id. In determining our SO2 BART emission limit of 
0.06 lbs/MMBtu, we drew on a number of sources of information. These 
include industry reports, vendor quotes, the engineering analysis 
contained in the TSD, and the historical emissions data for other 
similar coal fired power plants. As we state in the TSD and affirm, a 
dry scrubber at Sooner or Muskogee, designed as costed, could meet an 
SO2 emission limit of 0.06 lb/MMBtu based on 30-day BOD 
average, when burning coal containing 0.51 to 1.18 lb/MMBtu 
SO2. We conclude the same is true for the AEP/PSO 
Northeastern units because they have historically burned coal with a 
sulfur content within this range.\24\
---------------------------------------------------------------------------

    \24\ TSD, Appendix C, page 43.
---------------------------------------------------------------------------

    Among other objections, OG&E states we cannot rely on the 
SO2 emission performance of new facilities as an indicator 
of the performance potential of retrofit scrubbers. OG&E presents data 
on what it states are the best performing scrubber installations in the 
United States, and contends that the lowest emission rate achieved by a 
retrofit on an annual basis is 0.088 lbs/MMBtu. We explain that a 
scrubber, regardless of type, is not influenced by whether the flue gas 
comes from a new boiler or an old boiler located in an existing plant. 
The scrubber merely reacts to physical and chemical characteristics of 
the gas stream. Therefore, although we use other sources of information 
to justify our SO2 BART emission limit, we find that 
considering emission data from new scrubber installations to support 
our decision is appropriate. In so doing, we analyzed the historical 
emissions data of several units that we discuss above in response to 
another comment, which OG&E included in its comment. We reviewed the 
performance of three units that are of similar size and burn similar 
coal. One unit, TS Power Plant, has an emission limit that requires 
emissions to be significantly controlled and has been able to maintain 
its emissions below 0.06 lbs/MMBtu on a 30 day BOD basis continuously. 
We also reviewed the performance of two other units that demonstrate 
the ability to maintain emissions below the 0.06 lbs/MMBtu limit for 
long periods of time. We note that these units do not have as 
constraining emission limits so they do not have to control their 
emissions as closely. This and other sources of information we outline 
above and in our Supplemental RTC cause us to conclude our proposed 
SO2 BART emission limit of 0.06 lbs/MMBtu, calculated on the 
basis of a 30 day BOD, for the six OG&E and AEP/PSO units is 
technically feasible and therefore the correct SO2 limit for 
BART.
    OG&E also states that we should include in our proposed 
SO2 BART emission limit a compliance margin. OG&E suggests 
that a SO2 emission of 0.10 is required to provide a 
``reasonable margin for operating fluctuations and compliance.'' We 
reply that we are modifying the compliance averaging period from a 30 
calendar period to a 30 day Boiler Operating Day (BOD) period. As the 
BART Guidelines direct, ``[y]ou should consider a boiler operating day 
to be any 24-hour period between 12:00 midnight and the following 
midnight during which any fuel is combusted at any time at the steam 
generating unit.'' \25\ To calculate a 30 day rolling average based on 
boiler operating day, the average of the last 30 ``boiler operating 
days'' is used. In other words, days are skipped when the unit is down, 
as for maintenance. This, in effect, provides a margin by eliminating 
spikes that occur at the beginning and end of outages, and is 
consistent with the BART Guidelines.
---------------------------------------------------------------------------

    \25\ 70 FR 39104, at 39172.
---------------------------------------------------------------------------

    In our separate Supplemental RTC, we also discuss several other 
objections OG&E raises in its comments. These include objections to our 
reliance on a National Lime Association scrubber performance chart, 
OG&E's contention that our proposed SO2 BART emission is 
more representative of a LAER limit, and the technical capability of 
dry scrubbing. After addressing these issues, we find that our proposed 
SO2 BART emission for the six OG&E and AEP/PSO units remains 
at rate of 0.06 lbs/MMBtu.

[[Page 81748]]

H. Summary of Responses to Comments Received on the SO2 BART 
Compliance Timeframe

    We proposed that compliance with our SO2 BART emission 
limits be within three years of the effective date of our final rule. 
We solicited comments on alternative timeframes, from as few as two (2) 
years to up to five (5) years from the effective date of our final 
rule. We received comments that retrofitting of scrubbers is now 
routine in the United States and that approximately 290 coal-fired 
units totaling about 116,000 MW nationwide have been retrofit with 
scrubbers since 1990. The commenter cites to many examples of 
SO2 scrubbers being installed at coal-fired power plants 
within a three year timeframe. OG&E and others state that our proposed 
three year schedule focuses on actual construction timelines, but fails 
to acknowledge or allow sufficient time for the engineering, design, 
and permit processes that must be completed prior to the commencement 
of construction. They state a compliance schedule of from 52-54 months 
would be required.
    Although we do not specify what technology the six OG&E and AEP/PSO 
units must use to satisfy the SO2 BART emission limit, we 
expect that either dry or wet SO2 scrubbers will be used, or 
that the SO2 limit will be met by switching one or more of 
the units to natural gas. We agree that SO2 scrubbers have 
been installed at other facilities with construction timeframes of 
three years or less. However, we also agree with OG&E and AEP/PSO that 
there may be issues such as PSD permitting, and the construction/
expansion of a landfill that may not be reflected in the example 
compliance times reported by the commenter. Therefore, we find that 
compliance with the emission limits be within five years of the 
effective date of our final rule.

I. Comments Supporting Conversion to Natural Gas and/or Renewable 
Energy Sources

    Comment: Several parties submitted comments noting that switching 
to natural gas-fired electricity is feasible and demonstrated in 
practice. One of the commenters points out that, of the three subject 
sites, two have existing major natural gas supplies (OG&E Muskogee and 
AEP/PSO Northeastern) and that fuel switching will require construction 
of new or expanded natural gas supply and electric interconnection 
facilities. The commenter states that expanding along existing gas 
supply lines would cost less and take less time than constructing a new 
line. The commenters have stressed that natural gas produces 
comparatively low emissions of many pollutants, including haze-causing 
pollutants, air toxics, and greenhouse gases. Commenters also noted use 
of natural gas as a fuel source would eliminate the need to manage coal 
combustion waste and scrubber waste. Several commenters who support the 
switch from coal combustion to natural gas combustion cited the 
availability and abundance of natural gas as a natural resource, 
particularly in Oklahoma.
    Response: We agree that switching of existing coal-fired power 
generating units to natural gas, either through conversion of existing 
boilers or installation of new power generating units, is technically 
feasible and demonstrated in practice. As stated in our proposal, the 
owners of the units subject to the FIP may elect to reconfigure the 
units to burn natural gas as means of satisfying their BART obligations 
under section 51.308(e). Switching to natural gas would be an 
acceptable method of complying with the limits proposed in the FIP, 
because natural gas combustion inherently results in much lower 
SO2 emissions. We agree that natural gas may result in lower 
emissions of other pollutants and offer other environmental advantages. 
The owners of each subject unit may take these advantages, as well as 
the availability and pricing information, into consideration as they 
evaluate this option for complying with SO2 BART emission 
limits.
    Comment: Eight commenters responded to our request for comments on 
the compliance deadline for the six BART-subject units and whether it 
would be appropriate to extend that deadline for those utilities that 
elected to switch from coal to natural gas in order to comply with the 
BART emission limits. Several of these commenters note that switching 
to natural gas can be accomplished in less than three years if 
utilities enter into long-term power purchase agreements with existing 
natural gas-fired power generators but utilities that choose to 
construct new gas-fired units or convert existing units will likely 
require more time. They indicate that the requirements to engage in 
competitive bidding, complete engineering designs, prepare budgets, 
obtain necessary permits, and equipment installation will likely 
require up to five years to complete. One of these commenters points 
out that OG&E has already studied fuel-switching at the system and 
plant levels and that the typical lead time of construction of new 
natural gas-fired combined cycle combustion turbines is four years.
    Numerous commenters express their support for extending the 
compliance deadline to five years for units that will be converted to, 
or replaced with, natural gas-fired power generating units. These 
commenters cite the broad collateral benefits and overall superiority 
of switching to a cleaner fuel source over installing additional 
controls on the existing units and continuing to burn coal.
    Multiple other commenters, however, expressed the opinion that the 
utilities have had ample time already to transition away from coal to 
cleaner or renewable power generation and that the affected utilities 
should phase out the BART-subject coal-fired units as quickly as 
possible. These commenters feel that the proposed compliance deadline 
of three years is adequate.
    ODEQ submitted comments supporting a fourteen and one-half month 
extension (to four years and two and one-half months total) on the 
installation of scrubbers and a seven and one-half year extension (to 
ten and one-half years total) for switching to natural gas.
    Response: We thank the commenters for their responses to our 
request for comments on the proposed compliance deadline. As we have 
discussed elsewhere in our response to comments we find that a 
compliance deadline of five years is appropriate for the six OG&E and 
AEP/PSO units to comply with our FIP SO2 emission limit. 
After reviewing the information provided by the commenters, we find 
that the same compliance deadline of five years is appropriate for any 
of the six OG&E and AEP/PSO units that elect to comply with the FIP 
SO2 emission limit by converting an existing unit to natural 
gas or replacing it with a new, natural gas-fired unit.
    Comment: Several commenters provided information concerning 
underutilized electrical generation capacity through natural gas 
combustion in Oklahoma. One commenter further suggested that fuel 
switching could be achieved by imposition of annual emissions caps on 
the BART-subject, coal-fired units. According to the commenter, such a 
scheme would provide the affected utilities with the flexibility to 
shift power generation to existing gas-fired generating units or 
purchase power from merchant generators. The commenter states that 
there is an exception provision in the RH regulations at 40 CFR 
51.308(e)(2) that allows for imposition of operating limits on BART-
eligible units in lieu of conventional BART reductions if the 
regulating authority implements an emission trading program.

[[Page 81749]]

    Another commenter noted that switching to natural gas-fired 
generation, either through conversion of existing units or replacement 
with new units, would result in power plants better suited to integrate 
with variable wind power generation.
    Response: Section 51.308(e)(2) allows Oklahoma to implement an 
emissions trading program or other alternative measure in lieu of BART. 
Among other requirements, such an alternative to BART must achieve 
greater reasonable progress than would be achieved through the 
installation and operation of BART. However, Oklahoma did not include 
such a program as part of its RH SIP, and we cannot require Oklahoma to 
establish an emission trading program that would support annual 
emission caps or operational limits on the six BART-subject units. We 
also note that as a practical matter, there is no longer adequate time 
to develop and implement such an emissions trading program and meet our 
consent decree deadline with WildEarth Guardians of December 13, 2011 
if we attempted to develop and implement such an emission trading 
program as part of our action.\26\ Whether or not existing natural gas-
fired power generation capacity in Oklahoma and other parts of the 
Southwest Power Pool is underutilized has no direct bearing on our 
SO2 BART determinations.
---------------------------------------------------------------------------

    \26\ See, WildEarth Guardians v. Jackson, Case No. 4:09-cv-
02453-CW (N. Dist. Cal.).
---------------------------------------------------------------------------

    Comment: We received multiple comments from numerous parties 
concerning the economics of switching from coal-fired to natural gas-
fired power generation. These comments focused on a wide range of 
economic issues, including cost-benefit analysis of one BART compliance 
alternative over another, future risk to ratepayers due to future 
maintenance and compliance costs, economic impact of increasing 
reliance on renewable energy sources, and ancillary benefits to the 
economy of switching from coal to natural gas or renewable energy 
sources.
    Many of the comments we received pertain to the additional economic 
burden of addressing coal combustion and scrubber waste that would 
continue to be generated by the six BART-subject coal-fired units if 
the utilities elect to comply with the BART requirements of the 
proposed FIP by installing scrubber units, rather than fuel switching. 
One commenter provided an economic analysis indicating that containment 
of the coal ash and scrubber waste would cost $180 million in capital 
investment and $2-$5 million annually for disposal of residuals if the 
utilities can sell the fly ash, or up to $9 million annually if the fly 
ash cannot be sold. The commenter further asserts that scrubbing all 
six of the BART-subject coal-fired units could generate up to 600,000 
tons per year of flue gas desulfurization waste byproducts, the 
disposal of which could cost an additional $22 million annually. Two 
commenters have asserted that the power generation capacity of the six 
OG&E and AEP/PSO units can be replaced with the construction of new, 
modern natural gas-fired combined cycle turbines for less money than 
would be required to install scrubbers on the coal-fired units to meet 
BART emission limits.
    Other comments focused on the likely imposition of future, 
additional environmental regulatory compliance costs associated with 
continued firing of coal, such as requirements for new baghouses to 
control emissions of particulate matter and metals, construction of 
improved and expanded containment of coal combustion residuals, and 
carbon emission reductions or sequestration. These commenters noted 
that attempting to further extend the lives of the six OG&E and AEP/PSO 
units is a bad investment when such additional controls for other 
pollutants are foreseeable, and that switching to natural gas power 
generation would reduce the risk to ratepayers of the eventual cost 
increases associated with these additional regulatory requirements.
    Several commenters noted that the six OG&E and AEP/PSO units are 
approaching the end of their useful lives and that switching to natural 
gas and renewable energy sources will decrease the risk to ratepayers 
of increased maintenance costs due to the advanced age of the units.
    Other commenters, some of whom identified themselves as ratepayers 
at the affected utilities, indicated that they would be willing to pay 
an increase in power rates in exchange for power that was generated by 
cleaner fuels or renewable energy sources. These commenters cited the 
overall health and environmental benefits that would result from a 
transition away from coal-fired power and expressed their belief that 
such benefits would outweigh any potential increase in electricity 
rates.
    Finally, two commenters suggested that switching to natural gas 
and/or renewable energy sources would have collateral economic benefits 
by creating new jobs and providing general economic stimulus in the 
region.
    Response: We affirm that each of the sources subject to BART under 
the FIP can acceptably meet the emission limits in the FIP by switching 
to natural gas. As the companies evaluate how to satisfy their BART 
obligations, we encourage them to consider switching from coal to 
natural gas at the six affected units as this may offer numerous, 
significant long-term financial and environmental benefits over the 
option of continued use of coal with additional controls. As was stated 
in our proposal, we do not wish to dissuade companies from exercising 
this option. As we discuss elsewhere in our response to comments and 
Supplemental RTC, we find that a compliance deadline of five years is 
appropriate for any of the six OG&E and AEP/PSO units that elect to 
comply with the FIP SO2 emission limit by converting an 
existing unit to natural gas or replacing it with a new, natural gas-
fired unit.
    Comment: Several commenters expressed concern over the potential 
rate increases that might result from a switch to natural gas or some 
form of renewable energy sources and the impact of those rate increases 
on households with low or fixed incomes.
    Response: The companies owning each of the sources subject to BART 
are only required to satisfy the SO2 BART emission limits at 
those sources. Our action only contemplates the reconfiguration of 
existing units. We have determined that reconfiguration would be cost 
effective with application of dry and wet scrubbing technology. Though 
the SO2 BART emission limits may also be met with 
reconfiguration of the units to burn natural gas, the companies 
themselves are free to determine whether this option best responds to 
future customer needs and preferences, including any potential impact 
on rates. As we state elsewhere in this response to comments and the 
Supplemental RTC, although we based our BART determination of the use 
of SO2 dry scrubbers, the owners of the six units in 
question are free to consider any technology to meet their 
SO2 BART obligations, including switching to natural gas. We 
acknowledge the potential benefits that the commenters suggest of 
switching the units in question to burn natural gas. Renewable energy 
technology is not a retrofit option for the sources subject to BART and 
is accordingly outside the scope of our action.
    Comment: Several commenters have expressed the view that it does 
not make good economic sense to invest heavily in new control equipment 
in order to meet BART on units that are so close to retirement. Some of 
these commenters point out that it makes more sense to invest in new 
natural gas-fired units

[[Page 81750]]

instead of converting the existing boilers to burn natural gas, given 
the size of the investments being considered and the advanced age of 
the existing coal-fired units.
    Several of the comments focused on the long-term economic benefits 
of construction of new natural gas-fired units over conversion of the 
existing boilers at the six coal-fired units to meet the BART emission 
limits.
    Response The BART guidelines do allow for consideration of the 
remaining useful life of facilities when considering the costs of 
potential BART controls. Such a claim would have to be secured by an 
enforceable requirement. Neither OG&E nor AEP/PSO claimed any such 
restriction on the operation of these six units and Oklahoma did not 
submit any enforceable document for action by us. Consequently, we 
assumed a remaining useful life of 30 years in our BART analysis.
    If OG&E and/or AEP/PSO decide the units in question have a shorter 
useful life such that installing scrubbers is no longer cost effective, 
and are willing to accept an enforceable requirement to that effect, a 
revised BART analysis could be submitted by the plant(s) in question 
and our FIP could be re-analyzed accordingly. Similarly, we could also 
review a revised SIP submitted by ODEQ.
    Comment: Numerous commenters expressed broad support for 
transitioning away from coal and other fossil fuels to sources of 
energy that are completely renewable, such as wind and solar-generated 
power. These commenters recommend that the BART-subject units should be 
replaced with wind-powered units where possible and that natural gas 
should be used for power generation during periods of low wind yield. 
One of the commenters notes that Oklahoma and other parts of the 
Southwest Power Pool (SPP) have enormous potential for wind farm 
development and that as of July 2010 the SPP transmission 
interconnection queue had 111 wind generation projects totaling over 
20,000 MW and an additional 7,470 MW of incremental wind development. 
Comments received on this subject also noted that wind power can be 
developed at relatively low costs and that the money the utilities 
currently spend on the importation of coal and handling the byproducts 
of its combustion would be better spent on construction of additional 
wind generating capacity.
    Response: Renewable energy technology is not a retrofit option for 
the sources subject to BART and is therefore outside the scope of our 
SO2 BART determination. We do generally acknowledge that 
many kinds of renewable energy do not produce haze-causing pollutants, 
and transitioning to those sources of energy could lead to visibility 
improvements.
    Comment: We received opinions and data from four commenters 
expressing support for increased energy efficiency efforts as a 
technique for lowering power demand and therefore reducing the 
combustion of fossil fuels and its impact on the environment. One of 
these commenters noted that the affected utilities have begun some 
energy efficiency programs and that with increased effort they should 
be able to realize the successes of other programs elsewhere in the 
country that have seen cumulative reductions in annual power 
consumption of 5-8 percent since 2004. The commenter notes that OG&E, 
in particular, should be able to reduce power demand by up to 1,200 
GWh/year and 2,100 GWh/year after five and ten years, respectively, at 
an annual reduction goal of one percent, or as much as 1,800 GWh/year 
and 3,100 GWh/year after five and ten years, respectively, at an annual 
reduction goal of one and a half percent.
    Response: While not specifically within the scope by our 
SO2 BART determination or our approval of other aspects of 
the state's RH SIP, we acknowledge that efficiency programs that reduce 
reliance on sources of haze-causing pollutants may promote visibility 
improvements.
    Comment: OG&E states that if it is required to decide whether to 
install scrubbers or retire and replace electric generating units with 
natural gas on roughly the same time frame, the economic analysis 
suggests that rate increases to customers will be lower with scrubbers. 
Installation of scrubbers is projected to cost more than $1.5 billion. 
OG&E is concerned that with this type of capital investment, it would 
be locked economically into maximizing the use of its coal-fired units 
for the foreseeable future. OG&E states the agreement outlined by ODEQ 
in the SIP (and rejected by EPA) would reduce ``the cumulative 
SO2 emissions from Sooner Units 1 and 2 and Muskogee Units 4 
and 5 [to] approximately fifty-seven percent (57%) less than would be 
achieved through the installation and operation of Dry FGD with SDA at 
all four (4) units.'' OG&E states it should have the flexibility to 
take advantage of evolving technologies and to utilize these local 
clean energy sources at its plants in the future, while achieving the 
same (or better) reduction in impact on visibility. OG&E states EPA's 
failure to consider these issues in the proposal is short-sighted, and 
arbitrary, capricious and contrary to applicable law.
    Response: We find the approximately $1.2 billion cost claimed by 
OG&E in its BART analysis (referenced above as $1.5 billion) for the 
installation of SO2 dry scrubbers is in error. As discussed 
elsewhere in our response to comments and Supplemental RTC, based on 
our Option 1 and Option 2 analyses, we find the total project costs to 
range between $290,418,007 to $299,400,007 for Sooner Units 1 and 2, 
and from $298,818,917 to 289,791,940 for Muskogee. Further, as we also 
discuss in our proposal, although we based our SO2 BART 
determination on the basis of dry SO2 scrubbers, OG&E is 
free to employ other technologies to meet this limit, including 
switching to natural gas, as long as that switch is completed in the 
same BART timeframe. We discuss the BART compliance deadline in the 
response to another comment.
    Comment: A commenter stated we failed to consider ``the costs of 
compliance'' of converting the six coal-fired generating units to 
natural gas. Without any explanation, contends OIEC, we proposed that 
these generating units could be converted to natural gas ``as a means 
of satisfying their BART obligations.* * *'' 76 FR 16168, at 16194. The 
commenter states we failed to consider the costs of compliance of 
conversion to natural gas, as required by the CAA section 169A(g)(2), 
and the BART Guidelines, Part 51, Appendix. Y(IV)(D)(4)(a). The 
commenter states the FIP should therefore be withdrawn.
    Response: The commenter's reference to our proposal \27\ is fully 
reproduced as follows:
---------------------------------------------------------------------------

    \27\ 76 FR 16168, at 16194.

    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 timeframe. 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.

    Under the RHR,\28\ we cannot, and did not, evaluate the costs 
associated with switching the six OG&E and AEP/PSO units over to 
natural gas for BART. However, after conducting the BART analysis and 
adopting of emissions limits, alternatives to installing control 
technologies may achieve the same emission limits. We are open to 
alternative mechanisms to achieve the BART emissions limits we adopted. 
As

[[Page 81751]]

stated in our proposal, we merely afforded OG&E and/or AEP/PSO the 
opportunity to switch to natural gas as a means of satisfying BART. We 
also indicated we were willing to consider comments to extend the BART 
compliance timeframe to the full amount of time allowed under the RHR 
to accommodate that conversion. Although we based our BART 
determination of the use of SO2 scrubbers, the six units in 
question are free to consider any technology or alternative mechanism 
to meet their SO2 BART obligations.
---------------------------------------------------------------------------

    \28\ 70 FR 39104, at 39164: ``note that it is not our intent to 
direct States to switch fuel forms, e.g. from coal to gas.''
---------------------------------------------------------------------------

J. Comments Arguing Our Proposal Would Hurt the Economy and/or Raise 
Electricity Rates

    Comment: Several commenters expressed concern about adverse effects 
of electrical bill increases, stating that analyses prepared by the 
state's utilities, business groups and the Oklahoma Corporation 
Commission estimate our proposal could increase utility bills in 
Oklahoma significantly, with some estimates as high as 30 percent. Some 
commenters stated that the rate increase would result in decreased 
business investment in Oklahoma; while others stated that it will hurt 
existing businesses, local governments, and families already struggling 
from the recession. Several commenters noted that the rate increase 
will have a disproportionate adverse impact on senior citizens and the 
disadvantaged, especially individuals living on fixed incomes. 
Commenters urged us to consider the cost implications of our proposal 
as we balance the goals of the CAA with the economic impact on 
consumers, communities, and businesses. Specifically, one commenter 
stated that installation of scrubber technologies on aging coal-fired 
facilities may not be the most cost-effective or environmental 
approach. Several commenters ask EPA to consider all of the 
alternatives available, including switching to natural gas over a 
longer timeframe. One commenter further stated that EPA's proposal is 
not cost effective and does not significantly improve visibility. 
Commenters urged EPA to adopt the Oklahoma State plan. A commenter that 
supported the proposal stated that while the FIP could cause rates to 
increase somewhat, Oklahoma has the eighth lowest average electricity 
rates in the country, rates are higher in neighboring states, and the 
difference in rates may result from the fact that other states have 
emission controls on a higher percentage of their coal plants.
    Response: The federal regulations implementing the CAA's BART 
provisions require that we evaluate (1) cost 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) 
remaining useful life of source, and (5) degree of improvement in 
visibility which may reasonably be anticipated to result from the use 
of such technology. 40 CFR 51.308(e)(1)(ii)(A). After a careful cost 
review, we have determined that benefits in visibility from 
implementing our proposal outweigh the increase in costs for the 
facilities. As discussed in our proposal, we disagree with OG&E's and 
AEP/PSO's cost estimate for installing scrubbers on the six units 
addressed by our FIP. After careful review of information provided 
during the public comment period, we revised our calculation of the 
total project cost for the four OG&E units from our proposed range of 
approximately $312,423,000 to $605,685,000, to our final range of 
approximately $589,237,000 to $607,461,000. We made no changes to the 
cost basis for the two AEP/PSO units from our proposal. As such, the 
associated cost investment for AEP/PSO is $274,100,000. In light of the 
visibility benefits we predict will occur, we consider this to be cost 
effective. We take our duty to estimate the cost of controls very 
seriously, and make every attempt to make a thoughtful and well 
informed determination. We note that our cost estimate, being about 
half that of OG&E's will result in significantly less costs being 
passed on to rate payers. We also note that our FIP allows for any of 
the six units to switch to natural gas within five years of this final 
action instead of installing the control technology.

K. Comments Arguing Our Proposal Would Help the Economy

    Comments: We also received comments that the proposed FIP would 
help the economy in a variety of ways. One commenter stated that 
environmental regulations like the RHR improve the economy and create 
jobs; and industry always finds a way to manage the cost of 
implementation. One commenter states that cleaner air will boost 
Oklahoma's productivity and job creation.
    Response: Although, we did not consider the potential positive 
benefits to local economics in making our decision today, we do 
acknowledge that improved visibility may have a positive impact on 
tourism. Also, installing the controls required by the BART 
determination on the six units will take three years or longer to 
complete. These projects will require well-paid, skilled labor that can 
potentially be drawn from the local area, which would seem to benefit 
the economy.
    Finally, as we have noted elsewhere in our response to comments, 
although our action concerns visibility impairment, this action may 
also result in significant improvements in human health. Improved human 
health will reduce the healthcare costs and reduce the number of missed 
school and work days in the community.

L. Comments on Health and Ecosystem Benefits and Other Pollutants

    Comments: Several commenters state that pollutants that cause 
visibility impairment also harm public health. Specifically, commenters 
assert the following:
    RH pollutants include NOX, SO2, PM, 
ammonia, and sulfuric acid. NOX is a precursor to ground 
level ozone, which is associated with respiratory diseases, asthma 
attacks, and decreased lung function. NOX also reacts 
with ammonia, moisture, and other compounds to form particulates 
that can cause and worsen respiratory disease, aggravate heart 
disease, and lead to premature death. Similarly, SO2 
increases asthma symptoms, leads to increased hospital visits, and 
can form particulates that aggravate respiratory and heart diseases 
and cause premature death. Both NOX and SO2 
cause acid rain. PM can penetrate into the lungs and cause health 
problems, such as premature mortality, lung disease, aggravated 
asthma, chronic bronchitis, and heart attacks.

    Commenters cite to EPA's estimates that in 2015, full 
implementation of the RHR nationally will prevent 1,600 premature 
deaths, 2,200 non-fatal heart attacks, 960 hospital admissions, and 
over 1 million lost school and work days. The RHR will result in health 
benefits valued at $8.4 to $9.8 billion annually. More than 100,000 
children and 365,000 adults are diagnosed with asthma in Oklahoma, and 
hospitalizations in Oklahoma due to asthma cost roughly $57.9 million 
in 2007 alone. Commenters also cite to a Clean Air Task Force finding 
that the six units at issue in the proposed rule annually cause 
approximately 118 deaths, 181 heart attacks, 2,037 asthma attacks, 86 
hospital admissions, 74 cases of chronic bronchitis, and 129 emergency 
room visits.
    Some commenters also relay personal stories of the health impacts 
on themselves and their families from the emissions at issue. One 
commenter is disappointed that the air quality in Oklahoma is so poor 
that the ODEQ often warns active adults to avoid prolonged outdoor 
exposure. She notes that ozone action days prevent children from 
playing outside in the summer. Several children have been hospitalized

[[Page 81752]]

due to asthma and other illnesses that the commenters attribute to the 
emissions at issue. One commenter contends that many people who are 
impacted by this rulemaking are not aware of the rulemaking process, or 
their rights under that process. Commenters further state that it is 
EPA's responsibility to protect the air quality and prevent these 
negative health effects.
    Several commenters also assert that NOX and 
SO2 emissions from coal plants harms crops like pecans, 
barley, and oats, which puts the livelihoods of local farmers at risk, 
impacts the health of those who consume the contaminated food, and 
increases the cost of food.
    Some commenters want this rulemaking to address health issues. One 
commenter states that, while the RHR was designed to provide redress 
for visibility impairment, the BART Guidelines expressly provide for 
the consideration of non-air quality environmental impacts in step four 
of the five-step BART process. This consideration includes the 
environmental impact on human health.
    One commenter states that the power plants have had plenty of time 
to change operations to comply, but they have failed to do so. Several 
commenters assert that Oklahoma is unable to properly manage water and 
air pollution because special interest groups trump science. Another 
commenter states that coal pollution is devastating tourism and 
wildlife in Oklahoma. One commenter states that cleaner air will 
improve the health of its citizens. Some commenters assert that 
customers are subsidizing the cost of electricity with their health, 
lives, and livelihoods. One commenter stated that the increase in 
electricity costs is offset by reducing the healthcare costs to the 
community to treat illnesses and deaths caused by air pollution from 
the plants. Another commenter points out that power plants are also 
built near the most vulnerable and underserved populations in the 
state, based on the argument that the plants will bring needed jobs. 
One commenter concludes that it is unfair and unethical to hold 
citizens hostage to the idea that they must choose between electricity 
and good health. Several commenters feel that it is appropriate for 
industry to bear the burden of the cost, rather than pass it on to 
citizens of the state in the form of healthcare costs. These commenters 
are amenable to paying higher electricity rates in exchange for 
healthier air and water. Several commenters request that EPA impose the 
strongest possible regulation of emissions and enforcement of the CAA.
    Another commenter notes that President Nixon created EPA to protect 
the environment and the CAA was passed to protect air quality in our 
national parks and wilderness areas. President Reagan's acid rain 
program cost less than industry or EPA estimated; and hopefully, 
installing scrubbers on these coal plants will also cost less than 
estimated. Further, the CAA allows EPA to limit sulfur oxides, nitrogen 
dioxides, organic compounds, and particulates to ensure the quality of 
the air in the region. Several commenters state that coal pollutes 
throughout the process during extraction, burning, and disposal. One 
commenter states that the true cost of coal is the cost of its 
transportation, remediation of coal pollution, and lost tourism and bad 
public relations in states where coal production occurs through 
mountaintop removal. Many commenters recommend that Oklahoma convert to 
more efficient sources of energy such as natural gas, wind, and solar 
power.
    One commenter asserts that he suffered from severe childhood asthma 
caused by allergies before the coal-fired power plants were built. He 
states that affordable electricity from the plants allows him to keep 
his windows closed, thereby preventing allergens from entering his 
home.
    Response: We appreciate the commenters' concerns regarding the 
negative health impacts of emissions from the six units at issue. We 
agree that the same NOX emissions that cause visibility 
impairment also contribute to the formation of ground-level ozone, 
which has been linked with respiratory problems, aggravated asthma, and 
even permanent lung damage. We also agree that SO2 emissions 
that cause visibility impairment also contribute to increased asthma 
symptoms, lead to increased hospital visits, and can form particulates 
that aggravate respiratory and heart diseases and cause premature 
death; and that both NOX and SO2 cause acid rain. 
We agree that the same PM emissions that cause visibility impairment 
can be inhaled deep into lungs, which can cause respiratory problems, 
decreased lung function, aggravated asthma, bronchitis, and premature 
death. We agree that these pollutants can have negative impacts on 
plants and ecosystems, damaging plants, trees, and other vegetation, 
and reducing forest growth and crop yields, which could have a negative 
effect on species diversity in ecosystems. Therefore, although our 
action concerns visibility impairment, we note the potential for 
significant improvements in human health and the ecosystem.
    The CAA states that the non-air quality environmental impacts of 
compliance are a consideration in determining BART. See CAA Section 
169A(g)(2). The BART Guidelines allow for the consideration of non-air 
quality environmental impacts under 40 CFR 51, Appendix Y(IV)(D)(j). 
See also, 70 FR 39104, at 39169. However, this BART factor generally is 
considered in order to determine if a control option that is otherwise 
technically feasible should be eliminated due to adverse environmental 
impacts. Such impacts could include solid or hazardous waste generation 
and discharges of polluted water as a result of the control device. 
Although we may note potential health benefits from the reduction of 
air pollutants due to the installation of a BART control, we do not 
consider them as part of the BART determination. While we received many 
comments concerning health impacts from the ongoing operations of BART-
eligible sources, we received no comments asserting that dry and wet 
scrubbers should be differentiated or eliminated as compliance options 
based on non-air quality environmental impacts.
    Although we appreciate the commenters' encouragement that we adopt 
even stricter standards, after considering all the comments we 
received, as we have stated elsewhere in this notice, we believe that 
the standards proposed in our proposal establish BART and will prevent 
visibility impairment from the six units.
    Issues that the commenters raise about the effect of EPA's action 
on the cost of electricity are addressed elsewhere in this notice. 
Additionally, comments that recommend that the six units switch to 
natural gas or other sources of renewable energy are addressed 
elsewhere in this notice.
    Comments: Several commenters note that coal-plant emissions contain 
other toxins including mercury, lead, cadmium, chromium, dioxins, 
formaldehyde, arsenic, radioactive isotopes, oxide, and radon gas. 
Another commenter is concerned that the toxicity of the pollutants in 
regional haze is higher in close proximity to the source of emissions.
    Specifically, several commenters state that poor reclamation of 
coal ash from AEP's Shady Point power plant causes negative health 
impacts in Bokoshe, Oklahoma. These commenters are concerned about the 
health effects of fly ash because they state it contains arsenic, 
mercury, lead, cadmium, and other toxins. They describe the project as 
consisting of transporting coal ash from the plant to an abandoned lead 
mine in Bokoshe. Commenters claim

[[Page 81753]]

that the result is a fifty foot wall of toxic coal ash at the 
reclamation site in Bokoshe. Commenters state that pollution from the 
reclamation project has damaged property and people's health. They 
state that fugitive emissions from the trucks and the reclamation site 
run off into the ground water, polluting drinking water supplies. One 
commenter also states that fly ash has been used in Oklahoma as repair 
material for county roads. Commenters state that sixteen to twenty 
families living nearby have cancer, children have asthma, and calves in 
the area are stillborn. One commenter states that EPA's proposal to put 
scrubbers on the units at issue will help address asthma, but these 
scrubbers will cause emissions of toxic fly ash.
    Several commenters are concerned that the mercury, chromium, and 
arsenic from the coal-fired power plants are contaminating food, 
primarily fish. One commenter contends that these chemicals are 
carcinogenic and bioaccumulate. As a result, they state, some fish in 
Oklahoma have high levels of toxic materials and cannot be consumed. 
Commenters note that mercury contamination is so extreme that larger 
fish species are unsafe for pregnant women to eat. One commenter states 
that mercury is a neurotoxin that negatively affects a child's ability 
to talk, walk, read, and learn. Several commenters point out that ODEQ 
has issued advisories that prohibit eating fish from certain lakes 
because the mercury content is dangerously high. One commenter further 
states that sixteen out of fifty of the lakes in Oklahoma have elevated 
levels of mercury.
    Response: Although we appreciate the commenters' concerns regarding 
the potential negative health impacts from toxic emissions from the six 
units at issue, we note that we are not quantifying any toxic emissions 
that may be emitted, and such emissions are not considered to be 
visibility impairing pollutants. Therefore, consideration of the toxic 
emissions is outside the scope of this rulemaking under the RHR. 
However, please note that other provisions of the CAA, as well as other 
environmental statutes and regulations address toxic emissions, such as 
the ones noted here. EPA implements such programs to protect human 
health and the environment from the negative impacts of these 
pollutants, and Oklahoma's SIP is required to include provisions 
consistent with these Federal requirements to the extent that they are 
applicable.
    Comment: One commenter mentions the impacts of the transport of 
emissions from existing and planned coal plants in Texas, stating that 
sixty percent of mercury pollution in Oklahoma comes from Texas. He 
requests that EPA accelerates mercury testing in Oklahoma's land and 
lakes.
    Response: While we understand the commenter's concern with the 
impacts of transport emission from Texas on water bodies in Oklahoma, 
mercury testing of water bodies is outside the scope of our action. 
Mercury is not considered a visibility impairing pollutant; it is an 
air toxic regulated under CAA requirements that are distinct from the 
RHR and CAA section 110(a)(2)(D)(i)(II).
    Comments: Several commenters discuss the impact of coal power on 
climate change. One commenter also notes that we should regulate 
CO2 because ninety-seven percent of scientists agree that it 
is causing climate change. He contends that coal fired power plants are 
contributing to climate change, stating that the CO2 level 
has risen from 280 ppm during the pre-industrial age to 380 ppm today. 
He cites the IPCC and others who state that the CO2 level 
should not exceed 350 ppm. He also discusses the increasing 
temperatures and potential for sea level rise in the near future. The 
commenter states that we need to address climate change now.
    Response: While we understand the commenters' concerns with respect 
to climate change, consideration of climate change is outside the scope 
of our action on the RHR. While CO2 is a greenhouse gas 
(GHG), it is not considered a visibility impairing pollutant. However, 
EPA implements regulations that address GHGs in order to protect the 
public and the environment from the negative impacts of climate change. 
Additionally, Oklahoma's SIP is required to include provisions 
consistent with those Federal requirements.

M. Miscellaneous Comments

    Comment: OG&E states that we found a defect in Oklahoma's Long Term 
Strategy (LTS) because CENRAP modeling assumed the presumptive 
SO2 BART limit (0.15 lb/mmBtu) for OG&E's Sooner and 
Muskogee facilities, which was not secured by Oklahoma in its SIP. OG&E 
states we reasoned that the proposed FIP was necessary to cure these 
defects. OG&E asserts we may not pre-determine the BART SO2 
emissions limit based on assumptions made during regional modeling, but 
the emissions limit should be determined based on the five statutory 
factors as applied to an individual facility.
    Further, OG&E states our reasoning with respect to the Oklahoma LTS 
is in error. When setting reasonable progress goals for their own Class 
I areas, OG&E states, the states are authorized to consider the same 
five statutory factors that are used in determining BART, including the 
costs of additional controls. OG&E states that Oklahoma did not specify 
additional SO2 controls for the Sooner and Muskogee units as 
part of Oklahoma's LTS for the Wichita Mountains. OG&E notes that for 
Class I areas in other states, a state must ensure that it has included 
in its LTS all measures needed to achieve its apportionment of emission 
reduction obligations agreed upon through the regional planning 
process. 40 CFR 51.308(d)(2)(ii). OG&E states that ODEQ found that its 
LTS required no further controls for Oklahoma sources because emissions 
from Oklahoma were found (through the regional planning process) to 
impair visibility at all relevant Class I areas other than Wichita 
Mountains only insignificantly. Thus, OG&E reasons, the Oklahoma LTS is 
consistent with the agreements reached during regional planning. OG&E 
states we failed to justify, or explain, our basis for assuming that 
the regional planning process would have come to a different conclusion 
concerning Oklahoma's impact on other states' Class I areas if a 
different SO2 emission rate had been assumed for the Sooner 
and Muskogee units in question.
    Response: We disagree with OG&E's assertion that Oklahoma's 
decision not to require controls for the six OG&E and AEP/PSO units is 
consistent with the RH requirements for the LTS, section 
51.308(d)(3)(ii), which requires:

    Where other States cause or contribute to impairment in a 
mandatory Class I Federal area, the State must demonstrate that it 
has included in its implementation plan all measures necessary to 
obtain its share of the emission reductions needed to meet the 
progress goal for the area. If the State has participated in a 
regional planning process, the State must ensure it has included all 
measures needed to achieve its apportionment of emission reduction 
obligations agreed upon through that process.

    Oklahoma did engage in a regional planning process. This regional 
planning process included a forum in which state representatives built 
emission inventories that assumed that specific pollution sources would 
be controlled to specific levels. This included assumptions that the 
six OG&E and AEP/PSO units would be controlled to presumptive BART 
emission levels for SO2. Visibility modeling projections 
subsequently assumed those emission reductions. However, Oklahoma, in 
its

[[Page 81754]]

subsequent RH SIP, did not include these promised reductions on which 
the other states are presently relying.
    We note the CENRAP RPO process was open and representatives from 
industry occasionally attended CENRAP meetings and had an opportunity 
to engage in this process. ODEQ engaged in consultations under 
51.308(d)(3)(i), which requires that where the State has emissions that 
are reasonably anticipated to contribute to visibility impairment in 
any mandatory Class I Federal area located in another State or States, 
the State must consult with the other State(s) in order to develop 
coordinated emission management strategies. The State must consult with 
any other State having emissions that are reasonably anticipated to 
contribute to visibility impairment in any mandatory Class I Federal 
area within the State.
    All states that engaged in these consultations were involved in the 
discussions leading up to, and the actual construction of the emission 
inventories and the modeling strategy. These LTS consultations 
therefore assumed OG&E's Sooner and Muskogee sources would be 
controlled to the presumptive limit levels and made decisions regarding 
whether additional controls to address LTS were needed on that basis. 
Thus, we are disapproving Oklahoma's LTS.
    Furthermore, and notwithstanding the above LTS discussion, we 
disagree with OG&E's assertion that our BART analysis of the six OG&E 
and AEP/PSO units is due to the CENRAP modeling. As we discussed in our 
proposal, we arrived at our proposed BART determination for the six 
units in question after performing the BART analysis required under the 
RHR.
    Comment: AEP/PSO commented that we should clarify that new 
monitoring systems proposed under section 52.1923(e) do not need to be 
installed for both Unit 3 and Unit 4 of the Northeastern plant if the 
same fuel is used for both units. Instead, they reason, stack emissions 
should be apportioned to the units based on unit to stack load ratios. 
AEP/PSO claims the equipment necessary to report emissions for each 
unit individually will add approximately $250,000 to the cost to 
comply, and provides no better data on emissions to the atmosphere.
    Response: We are affirming that we are in fact requiring that the 
monitoring described in section 52.1923(e) must be installed separately 
for each of Units 3 and 4 of the AEP/PSO Northeastern plant even though 
the same fuel is used for both units. We do not find that it is proper 
to calculate the emissions of each unit based on its load ratio, as 
individual SO2 scrubbers will likely have slightly different 
performance characteristics and we need to ensure that both units' 
scrubbers are working properly by monitoring the emissions unit by 
unit.
    Comment: AEP/PSO believes there is a conflict between the language 
in section 52.1923(d) and (e). Section 52.1923(d) states that 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.
    Section 52.1923(e) states that 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.
    Response: We do not see a conflict between the language in sections 
52.1923(d) and (e). Paragraph (d) refers to short term, discrete data 
acquisition problems and paragraph (e) refers to more serious problems 
that may arise due to fundamental underlying problems with the 
monitoring system.
    Comment: One commenter called for an integrated and comprehensive 
strategy for EGUs to meet CAA requirements, noting that EGU emissions 
are subject to the RHR, the PM2.5 NAAQS, and the National 
Emissions Standards for Hazardous Air Pollutants. The commenter stated 
that to effectively address impacts to human health and RH caused by 
EGU emissions, the FIP or SIP should require (1) SCR to control 
NOX, (2) wet scrubbers to control SO2, and (3) 
wet electrostatic precipitators to control condensable particulate 
matter and acid mists. The commenter also asked us to reconsider our 
proposal to accept ODEQ's NOX BART determination, because 
(1) according to our proposal additional NOX reductions 
would achieve significant improvement in visibility over baseline, (2) 
Nitrate particulates from EGUs are primarily responsible for the 
majority of visibility impairment during winter days, and (3) the full 
benefit of wet scrubber controls may not be achieved unless BART 
controls on NOX is also required. Concerning SO2, 
the commenter expressed concern that the proposal would ``approve'' a 
dry scrubber system, along with an older electrostatic precipitator at 
the OG&E Sooner facility that would achieve poor control of 
PM2.5 emissions. The commenter added that the proposed rule 
does not provided adequate information to allow the public to 
understand and compare control measures or to comprehend the extent of 
underperformance of PM2.5 controls.
    Another commenter requested additional controls and monitoring for 
ammonia and sulfuric acid. Specifically the commenter (1) requested 
that we set emission limits for ammonia and sulfuric acid mist, similar 
to those proposed for the San Juan Generating Station in New Mexico (76 
FR 491), (2) stated their support for requiring continuous emissions 
monitors to monitor ammonia, and (3) urged us to require stack testing 
for sulfuric acid on a more frequent basis than annual monitoring.
    Response: The purpose of our plan is to address the CAA BART 
requirements. Our evaluation found that:
     The NOX controls adopted by the state meet the 
CAA BART requirements;
     The SO2 BART controls we proposed in our FIP, 
in addition to the state adopted NOX controls, would lead to 
significant improvement in visibility and meet the CAA BART 
requirements;
     Additional NOX controls would not be cost 
effective; and
     Additional pollutant controls are not needed to meet the 
CAA BART requirements.
    Regarding the request for ammonia and sulfuric acid mist emission 
limits and monitoring, we did propose ammonia and sulfuric acid limits 
and monitoring, as part of our New Mexico RH FIP for the San Juan 
Generating Station. 76 FR 491. We did this because we were concerned 
about the potential for ammonia slip, as a result of the operation of 
Selective Catalytic Reduction (SCR), and the potential for the growth 
in sulfuric acid emissions if they were not limited in an enforceable 
manner. As explained in our response to comments in that action, we 
ultimately determined that neither an ammonia limit, nor ammonia 
monitoring was warranted.\29\ We did, however, limit sulfuric acid 
emissions, verified by annual stack testing due to the potential for 
visibility impairment from increased sulfuric acid emissions associated 
with operation of SCR. These issues are not applicable here, as our 
BART FIP is concerned with the reduction of SO2, which is 
not controlled by SCR, and our visibility modeling does not indicate 
the

[[Page 81755]]

need to control or monitor sulfuric acid or ammonia emissions.
---------------------------------------------------------------------------

    \29\ 76 FR 52388, at 52407.
---------------------------------------------------------------------------

    Comment: One commenter stated that by mandating scrubbers on coal 
plants that we are trying to phase out does not make sense. Another 
commenter asked why switching to low sulfur coal is not considered a 
viable alternative instead of mandating installation of expensive wet 
gas scrubbers. A third commenter stated that the EPA continues to bog 
down electricity producers with burdensome paperwork and legal 
uncertainty and that the EPA RHR is a perfect example of the EPA's lack 
of economic reality.
    Response: We are not attempting to phase out the Oklahoma coal 
plants that are subject to our FIP. The purpose of our FIP is to 
control SO2 emissions from six Oklahoma EGUs that contribute 
to RH in order to meet the CAA BART requirements. To that end we are 
setting emissions limits for SO2. We are not requiring 
certain control technologies or fuel sources. As discussed earlier, we 
used the CAA's BART evaluation criteria for our plan and found that it 
is reasonable and realistic. The paperwork required will ensure 
compliance with the BART FIP.
    Comment: One commenter expressed his view that citizens should ask 
EPA to set and enforce regulations for haze because the state 
regulations were inadequate. Another commenter stated that we should 
reject lower standards suggested by others.
    Response: We agree with the commenter that Oklahoma's RH SIP was 
inadequate in its control of SO2 from the six OG&E and AEP/
PSO units. We find that our FIP will require the proper amount of 
SO2 control in order to comply with the RHR.
    Comment: A request was submitted that we hold a public hearing on 
our proposal in Tulsa, Oklahoma.
    Response: Originally we scheduled one public hearing in Oklahoma 
City. In response to the request we added a second hearing in Tulsa on 
April 14, 2011. The transcripts of both public hearings are available 
in the docket.
    Comment: One commenter asked us to work with ODEQ and the 
electrical power providers to develop a cost effective plan.
    Response: We find that the SO2 controls required by our 
FIP are, for the reasons discussed elsewhere in our response to 
comments and Supplemental RTC, cost effective. We are, however, willing 
to work with ODEQ and others to develop a SIP that could replace our 
FIP. Such a SIP will need to meet the CAA and EPA's RH regulations and 
be consistent with EPA's guidance.
    Comment: One commenter supported our proposal's (1) determination 
that Oklahoma's SO2 BART limits do not meet the RH 
regulations, (2) analysis of the visibility improvement resulting from 
BART controls, (3) determination that low NOX burners are 
appropriate as BART, and (4) determination that existing electrostatic 
precipitators and a 0.1 lbs/MMBtu emissions limit is appropriate as 
BART for particulate matter.
    Response: We appreciate the comments.
    Comment: Comments were received expressing concern over other 
sources of air pollution, such as landfills, coal-fired power plants, 
the Tar Creek superfund site and sources in Texas.
    Response: While we understand the commenter's concern with the 
impacts of other sources of pollution, the scope of this action is 
limited to assessing whether certain elements of the Oklahoma RH SIP 
meet the RH requirements of the CAA, including BART, and addressing any 
deficiencies identified. We note also that other state and federal 
statutes and regulations address other sources of air pollution, such 
as those referenced by the commenters, to protect human health and the 
environment from the negative impacts of these pollutants.
    Comment: Two commenters provided questions at the Oklahoma City 
public hearing. Several questions relate to Class 1 areas, such as: 
designation of Class 1 areas; location of Class 1 areas in relation to 
the six units and other coal-fired units; frequency, degree, and season 
of visibility impact in Class 1 areas; and tourism at the Class 1 
areas. Other questions concern cost of compliance by the six units, 
such as: annual and total cost; cost and benefit analysis of comparing 
the cost of compliance to ``visitor impact days''; economic impacts to 
the region; and EPA's authority to implement the FIP. Finally, some 
questions concern the Wichita Wildlife Refuge specifically and 
contemplate sources of haze impacting that Class 1 area, other than the 
six units.
    Response: In general, answers to these questions are: (1) Found in 
our proposal or in supporting documents for our proposal, (2) furnished 
in response to other comments, or (3) not a necessary or relevant 
consideration for our action. For responses to these comments, please 
see the ``Addendum Responding to Questions Received'' available in the 
electronic docket for this rulemaking.
    Comment: We received comments not related to the proposal. These 
included comments on:
     Enforcement by EPA and ODEQ;
     A RH educational plan;
     Emissions from the LaFarge cement company; and
     Eliminating coal as a source of energy.
    Response: While these and other comments may be important topics 
for discussion, we are not addressing these topics as they are outside 
the scope of our rulemaking.

IV. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review and Executive 
Order 13563: Improving Regulation and Regulatory Review

    This action finalizes a source-specific FIP for six units at coal-
fired power plants in Oklahoma (OG&E Sooner Plant Units 1 and 2, OG&E 
Muskogee Plant Units 4 and 5, and AEP/PSO Northeastern Plant Units 3 
and 4). This type of action is exempt from Executive Orders 12866 (58 
FR 51735, October 4, 1993) and 13563 (76 FR 3821, January 21, 2011).

B. Paperwork Reduction Act

    This action does not impose an information collection burden under 
the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. 
Burden is defined at 5 CFR 1320.3(b). 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 FIP only applies to six units at three power plants (OG&E Sooner 
Plant, OG&E Muskogee Plant, and AEP/PSO Northeastern Plant) the 
Paperwork Reduction Act does not apply. See 5 CFR 1320(c).

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 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

[[Page 81756]]

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 action on small 
entities, I certify that this action will not have a significant 
economic impact on a substantial number of small entities. The FIP for 
the OG&E Sooner Plant, the Muskogee Plant, and the AEP/PSO Northeastern 
Plant being finalized today does not impose any new requirements on 
small entities. See Mid-Tex Electric Cooperative, Inc. v. FERC, 773 
F.2d 327 (D.C. Cir. 1985).

D. Unfunded Mandates Reform Act

    Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2 
U.S.C. 1531-1538, requires Federal agencies, unless otherwise 
prohibited by law, to assess the effects of their regulatory actions on 
state, local, and tribal governments and the private sector. This rule 
does not contain a Federal mandate that may result in expenditures of 
$100 million or more, adjusted for inflation, for state, local, and 
tribal governments, in the aggregate, or the private sector in any one 
year. Our cost estimate indicates that the total annual cost of 
compliance with this rule is below this threshold. Thus, this rule is 
not subject to the requirements of sections 202 or 205 of UMRA.
    This rule is also not subject to the requirements of section 203 of 
UMRA because it contains no regulatory requirements that might 
significantly or uniquely affect small governments. This rule contains 
regulatory requirements that apply only to six units at coal-fired 
power plants in Oklahoma (OG&E Sooner Plant Units 1 and 2, OG&E 
Muskogee Plant Units 4 and 5, and AEP/PSO Northeastern Plant Units 3 
and 4).

E. Executive Order 13132: Federalism

    This action does not have federalism implications. It 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. This action merely prescribes EPA's 
action to address the state not fully meeting its obligation to 
prohibit emissions from interfering with other states measures to 
protect visibility. 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 solicited comment on the proposed rule 
from state and local officials.

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

    This final action does not have tribal implications, as specified 
in Executive Order 13175 (65 FR 67249, November 6, 2000), because the 
action EPA is taking neither imposes substantial direct compliance 
costs on tribal governments, nor preempts tribal law. Therefore, the 
requirements of section 5(b) and 5(c) of the Executive Order do not 
apply to this rule. Consistent with EPA policy, EPA nonetheless 
provided outreach to Oklahoma Tribes on several occasions in March and 
April 2011, and offered consultation regarding this action. EPA did not 
receive any requests for consultation on this rule.

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

    EPA interprets EO 13045 (62 FR 19885, April 23, 1997) as applying 
only to those regulatory actions that concern health or safety risks, 
such that the analysis required under section 5-501 of the EO has the 
potential to influence the regulation. This action is not subject to EO 
13045 because it implements specific standards established by Congress 
in statutes.

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(d) of the National Technology Transfer and Advancement 
Act of 1995 (``NTTAA''), Public Law 104-113, 12(d) (15 U.S.C. 272 note) 
directs EPA to use voluntary consensus standards in its regulatory 
activities unless to do so would be inconsistent with applicable law or 
otherwise impractical. Voluntary consensus standards are technical 
standards (e.g., materials specifications, test methods, sampling 
procedures, and business practices) that are developed or adopted by 
voluntary consensus standards bodies. NTTAA directs EPA to provide 
Congress, through OMB, explanations when the Agency decides not to use 
available and applicable voluntary consensus standards. This rule would 
require the affected units at the OG&E Sooner Plant, the Muskogee 
Plant, and the AEP/PSO Northeastern Plant to meet the applicable 
monitoring requirements of 40 CFR part 75. Part 75 already incorporates 
a number of voluntary consensus standards. Consistent with the Agency's 
Performance Based Measurement System (PBMS), Part 75 sets forth 
performance criteria that allow the use of alternative methods to the 
ones set forth in Part 75. The PBMS approach is intended to be more 
flexible and cost effective for the regulated community; it is also 
intended to encourage innovation in analytical technology and improved 
data quality. At this time, EPA is not recommending any revisions to 
Part 75; however, EPA periodically revises the test procedures set 
forth in Part 75. When EPA revises the test procedures set forth in 
Part 75 in the future, EPA will address the use of any new voluntary 
consensus standards that are equivalent. Currently, even if a test 
procedure is not set forth in Part 75, EPA is not precluding the use of 
any method, whether it constitutes a voluntary consensus standard or 
not, as long as it meets the performance criteria specified; however, 
any alternative methods must be approved through the petition process 
under 40 CFR 75.66 before they are used.

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.
    EPA has determined that this rule 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 minority or low-income 
population. Our FIP limits emissions of SO2 from six units 
at coal-fired power plants in Oklahoma (OG&E Sooner Plant Units 1 and 
2, OG&E Muskogee Plant Units 4

[[Page 81757]]

and 5, and AEP/PSO Northeastern Plant Units 3 and 4). In addition to 
our FIP, we also approve SIP elements that also limit the emission of 
other pollutants, including PM and NOX.

K. Congressional Review Act

    The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the 
Small Business Regulatory Enforcement Fairness Act of 1996, generally 
provides that before a rule may take effect, the agency promulgating 
the rule must submit a rule report, which includes a copy of the rule, 
to each House of the Congress and to the Comptroller General of the 
United States. EPA will submit a report containing this action and 
other required information to the U.S. Senate, the U.S. House of 
Representatives, and the Comptroller General of the United States prior 
to publication of the rule in the Federal Register. A major rule cannot 
take effect until 60 days after it is published in the Federal 
Register. This action is not a ``major rule'' as defined by 5 U.S.C. 
804(2). This rule will be effective on January 27, 2012.

L. Judicial Review

    Under section 307(b)(1) of the CAA, petitions for judicial review 
of this action must be filed in the United States Court of Appeals for 
the appropriate circuit by February 27, 2012. Pursuant to CAA section 
307(d)(1)(B), this action is subject to the requirements of CAA section 
307(d) as it promulgates a FIP under CAA section 110(c). Filing a 
petition for reconsideration by the Administrator of this final rule 
does not affect the finality of this action for the purposes of 
judicial review nor does it extend the time within which a petition for 
judicial review may be filed, and shall not postpone the effectiveness 
of such rule or action. This action may not be challenged later in 
proceedings to enforce its requirements. See CAA section 307(b)(2).

List of Subjects in 40 CFR Part 52

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

    Dated: December 13, 2011.
Lisa P. Jackson,
Administrator.

    For the reasons set out in the preamble, title 40, chapter I, of 
the Code of Federal Regulations is amended as follows:

PART 52--[AMENDED]

0
1. The authority citation for part 52 continues to read as follows:

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

Subpart LL--[Amended]

0
2. Section 52.1920 is amended as follows:
0
a. The table in paragraph (c) is amended by adding in sequential order 
under ``Subchapter 8. Permits for Part 70 Sources'' a new heading for 
part 11 and a new entry for ``(252:100:8-70 to 252:100:8-77)''.
0
b. The first table in paragraph (e) is amended by adding at the end a 
new entry for ``Interstate transport for the 1997 ozone and 
PM2.5 NAAQS (Noninterference with measures required to 
prevent significant deterioration of air quality or to protect 
visibility in any other State)'', immediately followed by an entry for 
``Regional haze SIP''. ``
0
c. The second table in paragraph (e) entitled ``EPA Approved Statutes 
in the Oklahoma SIP'' is amended by removing the entry for ``Interstate 
transport for the 1997 ozone and PM2.5 NAAQS.''
    The amendments read as follows:

Sec.  52.1920  Identification of plan.

* * * * *
    (c) * * *

                                        EPA Approved Oklahoma Regulations
----------------------------------------------------------------------------------------------------------------
                                                       State effective
         State citation              Title/subject           date        EPA approval date       Explanation
----------------------------------------------------------------------------------------------------------------
 
                                                  * * * * * * *
                                    PART 11. Visibility Protection Standards
----------------------------------------------------------------------------------------------------------------
(252:100:8-70 to 252:100:8-77)..  Visibility                6/15/2007   12/28/11 [Insert FR  ...................
                                   Protection                            page number where
                                   Standards.                            document begins]
----------------------------------------------------------------------------------------------------------------

     (e) * * *

            EPA Approved Non-Regulatory Provisions and Quasi-Regulatory Measures in the Oklahoma SIP
----------------------------------------------------------------------------------------------------------------
                                       Applicable
      Name of SIP provision          geographic or     State submittal/  EPA approval date       Explanation
                                   nonattainment area   effective date
----------------------------------------------------------------------------------------------------------------
 
                                                  * * * * * * *
Interstate transport for the      Statewide..........        5/1/2007   11/26/2010, 75 FR    Noninterference
 1997 ozone and PM2.5 NAAQS                                              72701 12/28/11       with measures
 (Noninterference with measures                                          [Insert citation     required to
 required to prevent significant                                         of publication].     prevent
 deterioration of air quality or                                                              significant
 to protect visibility in any                                                                 deterioration of
 other State).                                                                                air quality in any
                                                                                              other State
                                                                                              approved 11/26/
                                                                                              2010.
                                                                                              Noninterference
                                                                                              with measures
                                                                                              required to
                                                                                              protect visibility
                                                                                              in any other State
                                                                                              partially approved
                                                                                              12/28/11.

[[Page 81758]]

 
Regional haze SIP:..............  Statewide..........       2/17/2010   12/28/11 [Insert     Core requirements
(a) Determination of baseline                                            citation of          of 40 CFR 51.308
 and natural visibility                                                  publication].
 conditions.
(b) Coordinating regional haze
 and reasonably attributable
 visibility impairment.
(c) Monitoring strategy and
 other implementation
 requirements.
(d) Coordination with States and
 Federal Land Managers.
(e) BART determinations except
 for the following SO2 BART
 determinations: 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.
----------------------------------------------------------------------------------------------------------------

0
3. Section 52.1923 is added to read as follows:

Sec.  52.1923  Best Available Retrofit Requirements (BART) for 
SO2 and 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 five 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 CAA 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 that would be emitted to the atmosphere.
    Boiler-operating-day means any 24-hour period between 12:00 
midnight and the following midnight during which any fuel is combusted 
at any time at the steam generating unit.
    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:

Unit 4 of the Oklahoma Gas and Electric Muskogee plant; or
Unit 5 of the Oklahoma Gas and Electric Muskogee plant; or
Unit 1 of the Oklahoma Gas and Electric Sooner plant; or
Unit 2 of the Oklahoma Gas and Electric Sooner plant; or
Unit 3 of the American Electric Power/Public Service Company of 
Oklahoma Northeastern plant; or
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), above.
    (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 boiler-
operating-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 boiler-operating-day shall be determined by adding together all 
hourly heat inputs, in millions of BTU. Each boiler-operating-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 boiler-operating-days and dividing the total pounds of 
SO2 by the sum of the heat input during the same 30 boiler-
operating-day period. The result shall be the 30 boiler-operating-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 boiler-operating-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

[[Page 81759]]

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 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.
0
4. Section 52.1928 is added to read as follows:

Sec.  52.1928  Visibility protection.

    (a) The following portions of the Oklahoma Regional Haze (RH) State 
Implementation Plan submitted on February 19, 2010 are disapproved:
    (1) 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;
    (2) The long-term strategy for regional haze;
    (3) ``Greater Reasonable Progress Alternative Determination'' 
(section VI.E), and
    (4) 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.
    (b) The portion of the State Implementation Plan pertaining to 
adequate provisions to prohibit emissions from interfering with 
measures required in another state to protect visibility, submitted on 
May 10, 2007 and supplemented on December 10, 2007 is disapproved.
    (c) The SO2 BART requirements 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, the 
deficiencies in the long-term strategy for regional haze, and the 
requirement for a plan to contain adequate provisions to prohibit 
emissions from interfering with measures required in another state to 
protect visibility are satisfied by Sec.  52.1923.

[FR Doc. 2011-32572 Filed 12-27-11; 8:45 am]
BILLING CODE 6560-50-P