81728 Federal Register / Vol. 76, No. 249 / Wednesday, December 28, 2011 / Rules and Regulations 

1When 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. 

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. 

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


srobinson on DSK4SPTVN1PROD with RULES4
81730 Federal Register / Vol. 76, No. 249 / Wednesday, December 28, 2011 / Rules and Regulations 

2The 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. 

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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Federal Register / Vol. 76, No. 249 / Wednesday, December 28, 2011 / Rules and Regulations 81731 

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. 

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 costeffective, 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 


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3The 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. 

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. 

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 ‘‘rubberstamping’’ 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 


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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 


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4See,’’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’’). 

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. 

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 


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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 


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5States 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. 

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 


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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. 

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 threeyear 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 designspecific 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 


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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 nonspeculative, 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 costeffective 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 


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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. 

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). 

TABLE 1—AVERAGE NUMBER OF DAYS PER YEAR EACH FACILITY’S VISIBILITY IMPACTS EXCEED 1.0 AND 0.5 DECIVIEWS

Class I area 

Distance to 

unit 

(km) 

Average # of days/yr > 1.0 dv Average # of days/yr > 0.5 dv 

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 


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7 ‘‘Estimating Total Sulfuric Acid Emissions from 

Stationary Power Plants: Version 2010a. EPRI, Palo 

Alto, CA: 2010. 1020636.’’ 

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. 

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 pollutantspecific modeling were based on the 

erroneous PM speciation discussed 

above. 

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 


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10See, ‘‘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. 

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. 

13Revised 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). 

14U.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%22

New%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. 

to fully assess the total visibility benefit 

anticipated from emission reductions. 

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 sitespecific 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. 

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. 

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

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. 

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 


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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 precontrol 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 precontrol 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 


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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 startup, 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 


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81744 Federal Register / Vol. 76, No. 249 / Wednesday, December 28, 2011 / Rules and Regulations 

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. 

16A 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. 

17See Control Cost Manual, Section 2.3 to 2.4. 18EIA, ‘‘Updated Capital Cost Estimates for 

Electricity Generation Plants,’’ November 2010, 

footnote. 2, available at: http://www.eia.gov/oiaf/ 

beck_plantcosts/?src=email. 19Steven Stoft, Power Economics: Designing 

Markets for Electricity, 2002. 20 Id., page 2–18. 

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 sitespecific 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. 

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. 

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 


srobinson on DSK4SPTVN1PROD with RULES4
Federal Register / Vol. 76, No. 249 / Wednesday, December 28, 2011 / Rules and Regulations 81745 

21 70 FR 39104, at 39166, footnote 15. 

22Sargent & Lundy, IPM Model—Revisions to 

Cost and Performance for APC Technologies, SDA 

FGD Cost Development Methodology, Final, August 

2010, Table 1. 

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. 

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 resized 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%. 

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 


srobinson on DSK4SPTVN1PROD with RULES4
81746 Federal Register / Vol. 76, No. 249 / Wednesday, December 28, 2011 / Rules and Regulations 

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). 

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. 

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/Muskogee) 

Final 

(Sooner/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 


srobinson on DSK4SPTVN1PROD with RULES4
Federal Register / Vol. 76, No. 249 / Wednesday, December 28, 2011 / Rules and Regulations 81747 

24TSD, Appendix C, page 43. 25 70 FR 39104, at 39172. 

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

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. 

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. 


srobinson on DSK4SPTVN1PROD with RULES4
81748 Federal Register / Vol. 76, No. 249 / Wednesday, December 28, 2011 / Rules and Regulations 

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 coalfired 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 gasfired 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. 


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26See, WildEarth Guardians v. Jackson, Case No. 

4:09–cv–02453–CW (N. Dist. Cal.). 

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. 

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 coalfired 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 


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27 76 FR 16168, at 16194. 

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.’’ 

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 reanalyzed 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 BARTsubject 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 hazecausing 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 hazecausing 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 fiftyseven 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 coalfired 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: 

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 


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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. 

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 costeffective 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 


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81752 Federal Register / Vol. 76, No. 249 / Wednesday, December 28, 2011 / Rules and Regulations 

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 


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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 preindustrial 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 


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29 76 FR 52388, at 52407. 

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 


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need to control or monitor sulfuric acid 

or ammonia emissions. 

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, coalfired 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 


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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 


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

■ 1. The authority citation for part 52 

continues to read as follows: 

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

Subpart LL—[Amended] 

■ 2. Section 52.1920 is amended as 

follows: 

■ 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)’’. 

■ 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’’. ‘‘ 

■ 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: 

§ 52.1920 Identification of plan. 

* * * * * 

(c) * * * 

EPA APPROVED OKLAHOMA REGULATIONS

State citation Title/subject State effective 

date EPA approval date Explanation 

*******

PART 11. Visibility Protection Standards 

(252:100:8–70 to 252:100:8–77) ..................... Visibility Protection Standards.6/15/2007 12/28/11 [Insert FR page 

number where document 

begins] 

(e) * * * 

EPA APPROVED NON-REGULATORY PROVISIONS AND QUASI-REGULATORY MEASURES IN THE OKLAHOMA SIP 

Name of SIP provision 

Applicable geographic or nonattainment area State submittal/effective 

date 

EPA approval date Explanation 

*******

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).

Statewide .......... 5/1/2007 11/26/2010, 75 FR 72701 

12/28/11 [Insert citation of 

publication].

Noninterference with measures required to prevent 

significant deterioration of 

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. 


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81758 Federal Register / Vol. 76, No. 249 / Wednesday, December 28, 2011 / Rules and Regulations 

EPA APPROVED NON-REGULATORY PROVISIONS AND QUASI-REGULATORY MEASURES IN THE OKLAHOMA SIP—Continued 

Name of SIP provision 

Applicable geographic or nonattainment area State submittal/effective 

date 

EPA approval date Explanation 

Regional haze SIP: ..........................................

(a) Determination of baseline and natural 

visibility 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.

Statewide .......... 2/17/2010 12/28/11 [Insert citation of 

publication].

Core requirements of 40 

CFR 51.308 

■ 3. Section 52.1923 is added to read as 

follows: 

§ 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 boileroperating-day shall be determined by 

adding together all hourly heat inputs, 

in millions of BTU. Each boileroperating-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 boileroperating-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-operatingday 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 


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

■ 4. Section 52.1928 is added to read as 

follows: 

§ 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 

§ 52.1923. 

[FR Doc. 2011–32572 Filed 12–27–11; 8:45 am] 

BILLING CODE 6560–50–P 


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