16168 Federal Register / Vol. 76, No. 55 / Tuesday, March 22, 2011 / Proposed Rules 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 52 

[EPA–R06–OAR–2010–0190; FRL–9279–7] 

Approval and Promulgation of 

Implementation Plans; Oklahoma; 

Regional Haze State Implementation 

Plan; Federal Implementation Plan for 

Interstate Transport of Pollution 

Affecting Visibility and Best Available 

Retrofit Technology Determinations 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Proposed rule. 

SUMMARY: EPA is proposing to partially 

approve and partially disapprove a 

revision to the Oklahoma State 

Implementation Plan (SIP) submitted by 

the State of Oklahoma through the 

Oklahoma Department of Environmental 

Quality (ODEQ) on February 19, 2010 

that addresses regional haze for the first 

implementation period. This revision 

was submitted to address the 

requirements of the Clean Air Act (CAA 

or Act) and our rules that require states 

to prevent any future and remedy any 

existing man-made impairment of 

visibility in mandatory Class I areas 

caused by emissions of air pollutants 

from numerous sources located over a 

wide geographic area (also referred to as 

the ‘‘regional haze program’’). States are 

required to assure reasonable progress 

toward the national goal of achieving 

natural visibility conditions in Class I 

areas. EPA is proposing to approve a 

portion of this SIP revision as meeting 

certain requirements of the regional 

haze program and to partially approve 

and partially disapprove those portions 

addressing the requirements for best 

available retrofit technology (BART) and 

the long-term strategy (LTS). EPA is 

proposing a Federal Implementation 

Plan (FIP) to implement sulfur dioxide 

(SO2) emission limits on six sources to 

address these issues. EPA also is 

proposing to disapprove the State’s 

submitted alternative to BART; EPA is 

taking no action on the submitted 

reasonable progress goals at this time. In 

addition, EPA is proposing to partially 

approve and partially disapprove a 

portion of a revision to the Oklahoma 

SIP submitted by the State of Oklahoma 

on May 10, 2007 and supplemented on 

December 10, 2007. We are taking action 

on that portion of the submittals 

addressing the requirements of CAA as 

it applies to visibility for the 1997 

8-hour ozone and 1997 particulate 

matter (PM2.5) National Ambient Air 

Quality Standards (NAAQS). This 

portion of the submittals addresses the 

requirement that Oklahoma’s SIP 

contain adequate provisions to prohibit 

emissions from interfering with 

measures required in another state to 

protect visibility. In this action, we 

propose a FIP to address the 

deficiencies in this portion of 

Oklahoma’s SIP submittals. The 

proposed FIP will prevent emissions 

from six Oklahoma sources from 

interfering with other states’ measures 

to protect visibility and to implement 

sulfur dioxide emission limits on these 

six sources to prevent such interference. 

DATES: Comments: Comments must be 

received on or before May 23, 2011. 

Public Hearing. An open house and 

public hearing for this proposal is 

scheduled to be held on Wednesday 

April 13, 2011, at the Metro Technology 

Centers, Springlake Campus, Business 

Conference Center, Meeting Rooms H 

and I, 1900 Springlake Drive, Oklahoma 

City, OK 73111, (405) 424–8324. The 

Metro Technology Centers Springlake 

Campus is located at the intersection of 

Martin Luther King Ave. and Springlake 

Dr. between NE. 36th and NE. 50th just 

south of the Oklahoma City Zoo and 

Kirkpatrick Center. Parking for the 

Business Conference Center is available 

at no charge. The open house will begin 

at 1 p.m. and end at 3 p.m. local time. 

The public hearing will be held from 4 

p.m. until 6 p.m., and again from 7 p.m. 

until 9 p.m. 

The public hearing will provide 

interested parties the opportunity to 

present information and opinions to 

EPA concerning our proposal. Interested 

parties may also submit written 

comments, as discussed in the proposal. 

Written statements and supporting 

information submitted during the 

comment period will be considered 

with the same weight as any oral 

comments and supporting information 

presented at the public hearing. We will 

not respond to comments during the 

public hearing. When we publish our 

final action, we will provide written 

responses to all oral and written 

comments received on our proposal. To 

provide opportunities for questions and 

discussion, we will hold an open house 

prior to the public hearing. During the 

open house, EPA staff will be available 

to informally answer questions on our 

proposed action. Any comments made 

to EPA staff during the open house must 

still be provided formally in writing or 

orally during the public hearing in order 

to be considered in the record. 

At the public hearing, the hearing 

officer may limit the time available for 

each commenter to address the proposal 

to 5 minutes or less if the hearing officer 

determines it to be appropriate. We will 

not be providing equipment for 

commenters to show overhead slides or 

make computerized slide presentations. 

Any person may provide written or oral 

comments and data pertaining to our 

proposal at the Public Hearing. 

Verbatim transcripts, in English, of the 

hearing and written statements will be 

included in the rulemaking docket. 

Addresses: Submit your comments, 

identified by Docket No. EPA–R06– 

OAR–2010–0190, by one of the 

following methods: 

• Federal e-Rulemaking Portal: 

http://www.regulations.gov. Follow the 

online instructions for submitting 

comments. 

• E-mail: r6air_okhaze@epa.gov. 

• Mail: Mr. Joe Kordzi, Air Planning 

Section (6PD–L), Environmental 

Protection Agency, 1445 Ross Avenue, 

Suite 1200, Dallas, Texas 75202–2733. 

• Hand or Courier Delivery: Mr. Joe 

Kordzi, Air Planning Section (6PD–L), 

Environmental Protection Agency, 1445 

Ross Avenue, Suite 700, Dallas, Texas 

75202–2733. Such deliveries are 

accepted only between the hours of 8 

a.m. and 4 p.m. weekdays, and not on 

legal holidays. Special arrangements 

should be made for deliveries of boxed 

information. 

• Fax: Mr. Joe Kordzi, Air Planning 

Section (6PD–L), at fax number 214– 

665–7263. 

Instructions: Direct your comments to 

Docket No. EPA–R06–OAR–2010–0190. 

Our policy is that all comments received 

will be included in the public docket 

without change and may be made 

available online at http:// 

www.regulations.gov, including any 

personal information provided, unless 

the comment includes information 

claimed to be Confidential Business 

Information (CBI) or other information 

whose disclosure is restricted by statute. 

Do not submit information that you 

consider to be CBI or otherwise 

protected through www.regulations.gov 

or e-mail. The http:// 

www.regulations.gov Web site is an 

‘‘anonymous access’’ system, which 

means we will not know your identity 

or contact information unless you 

provide it in the body of your comment. 

If you send an e-mail comment directly 

to us without going through 

www.regulations.gov your e-mail 

address will be automatically captured 

and included as part of the comment 

that is placed in the public docket and 

made available on the Internet. If you 

submit an electronic comment, we 

recommend that you include your name 

and other contact information in the 

body of your comment and with any 

disk or CD–ROM you submit. If we 

cannot read your comment due to 


srobinson on DSKHWCL6B1PROD with PROPOSALS3
Federal Register / Vol. 76, No. 55 / Tuesday, March 22, 2011 / Proposed Rules 16169 

1 In this document, when we say ‘‘six BART 

sources,’’ or ‘‘six sources,’’ we mean Units 4 and 5 

of the Oklahoma Gas and Electric Muskogee plant; 

Units 1 and 2 of the Oklahoma Gas and Electric 

Sooner plant; and Units 3 and 4 of the American 

Electric Power/Public Service Company of 

Oklahoma Northeastern plant. 

technical difficulties and cannot contact 

you for clarification, we may not be able 

to consider your comment. Electronic 

files should avoid the use of special 

characters, any form of encryption, and 

be free of any defects or viruses. 

Docket: All documents in the docket 

are listed in the http:// 

www.regulations.gov index. Although 

listed in the index, some information is 

not publicly available, e.g., CBI or other 

information whose disclosure is 

restricted by statute. Certain other 

material, such as copyrighted material, 

will be publicly available only in hard 

copy. Publicly available docket 

materials are available either 

electronically in www.regulations.gov 

or in hard copy at the Air Planning 

Section (6PD–L), Environmental 

Protection Agency, 1445 Ross Avenue, 

Suite 700, Dallas, Texas 75202–2733. 

The file will be made available by 

appointment for public inspection in 

the Region 6 FOIA Review Room 

between the hours of 8:30 a.m. and 4:30 

p.m. weekdays except for legal holidays. 

Contact the person listed in the FOR

FURTHER INFORMATION CONTACT

paragraph below or Mr. Bill Deese at 

214–665–7253 to make an appointment. 

If possible, please make the 

appointment at least two working days 

in advance of your visit. There will be 

a 15 cent per page fee for making 

photocopies of documents. On the day 

of the visit, please check in at the our 

Region 6 reception area at 1445 Ross 

Avenue, Suite 700, Dallas, Texas. 

The state submittal is also available 

for public inspection during official 

business hours, by appointment, at the 

Oklahoma Department of Environmental 

Quality, 707 N Robinson, Oklahoma 

City, OK 73102. 

FOR FURTHER INFORMATION CONTACT: Joe 

Kordzi, EPA Region 6 Air Planning 

Section, telephone 214–665–7186, email address r6air_okhaze@epa.gov. 

SUPPLEMENTARY INFORMATION: 

Throughout this document wherever 

‘‘we,’’ ‘‘us,’’ or ‘‘our’’ is used, we mean the 

EPA. 

This action is being taken under 

section 110 and part C of the CAA. 

Table of Contents 

I. Overview of Proposed Actions 

A. Regional Haze 

B. Interstate Transport of Visibility 

II. SIP and FIP Background 

III. What is the background for our proposed 

actions? 

A. Regional Haze 

B. Roles of Agencies in Addressing 

Regional Haze 

C. The 1997 NAAQS for Ozone and PM2.5

and CAA 110(a)(2)(D)(i) 

IV. What are the requirements for regional 

haze SIPs? 

A. The CAA and the Regional Haze Rule 

B. Determination of Baseline, Natural, and 

Current Visibility Conditions 

C. Determination of Reasonable Progress 

Goals 

D. Best Available Retrofit Technology 

E. Long-Term Strategy 

F. Coordinating Regional Haze and 

Reasonably Attributable Visibility 

Impairment 

G. Monitoring Strategy and Other SIP 

Requirements 

H. Consultation With States and Federal 

Land Managers 

V. Our Analysis of Oklahoma’s Regional 

Haze SIP 

A. Affected Class I Areas 

B. Determination of Baseline, Natural and 

Current Visibility Conditions 

1. Estimating Natural Visibility Conditions 

2. Estimating Baseline Visibility 

Conditions 

3. Natural Visibility Impairment 

4. Uniform Rate of Progress 

C. Evaluation of Oklahoma’s Reasonable 

Progress Goal 

1. Establishment of the Reasonable 

Progress Goal 

2. ODEQ’s Reasonable Progress ‘‘Four 

Factor’’ Analysis 

3. Reasonable Progress Consultation 

D. Evaluation of Oklahoma’s BART 

Determinations 

1. Identification of BART-Eligible Sources 

2. Identification of Sources Subject to 

BART 

a. Modeling Methodology 

b. Contribution Threshold 

c. BART Sources Exempted Due to Permit 

Modifications 

d. Sources Identified by ODEQ as Subject 

to BART 

3. BART Determinations 

a. OG&E Seminole Units 1, 2, and 3 BART 

Determinations 

b. OG&E Sooner Units 1 and 2 BART 

Determinations 

c. OG&E Muskogee Units 4 and 5 BART 

Determinations 

d. AEP/PSO Comanche Units 1 and 2 

BART Determinations 

e. AEP/PSO Northeastern Unit 2, 3, and 4 

BART Determination 

f. AEP/PSO Southwestern Unit 3 BART 

Determination 

g. ODEQ BART Results and Summary 

E. Evaluation of ODEQ’s SO2 BART 

Determinations for the OG&E and AEP/ 

PSO Coal Fired Power Plant Units 

1. Cost Effectiveness 

a. Dry Scrubbing Cost Analyses 

b. Wet Scrubbing Cost Analyses 

2. Visibility Benefit 

3. Our Conclusion on Oklahoma’s SO2

BART Evaluations for the Six OG&E and 

AEP/PSO Units 

4. Alternative BART Determination 

F. Federal Implementation Plan To 

Address SO2 BART for the Six Sources 

1. Introduction 

2. Appropriate Emission Limits 

a. Dry Scrubber Emission Limit 

b. Wet Scrubber Emission Limit 

3. Visibility Benefit From Dry and Wet 

Scrubbing 

4. EPA’s SO2 BART Determination for the 

Six Units 

G. Long-Term Strategy 

1. Emissions Inventory 

a. Oklahoma’s 2002 Emission Inventory 

b. Oklahoma’s 2018 Emission Inventory 

2. Visibility Projection Modeling 

3. Consultation and Emissions Reductions 

for Other States’ Class I Areas 

4. Mandatory Long Term Strategy Factors 

H. Coordination of RAVI and Regional 

Haze Requirements 

I. Monitoring Strategy and Other SIP 

Requirements 

J. Federal Land Manager Coordination 

K. Periodic SIP Revisions and Five-Year 

Progress Reports 

VI. Our Analysis of Oklahoma’s Interstate 

Visibility Transport SIP Provisions 

VII. Proposed Actions 

A. Regional Haze 

B. Interstate Transport and Visibility 

VIII. Statutory and Executive Order Reviews 

I. Overview of Proposed Actions 

A. Regional Haze 

We propose to partially approve and 

partially disapprove Oklahoma’s 

regional haze (RH) SIP revision 

submitted on February 19, 2010. 

Specifically, we propose to disapprove 

the SO2 BART determinations for Units 

4 and 5 of the Oklahoma Gas and 

Electric (OG&E) Muskogee plant; Units 

1 and 2 of the OG&E Sooner plant; and 

Units 3 and 4 of the American Electric 

Power/Public Service Company of 

Oklahoma (AEP/PSO) Northeastern 

plant. We propose to disapprove these 

SO2 BART determinations because they 

do not comply with our regulations 

under 40 CFR 51.308(e). 

We are also proposing to disapprove 

the long term strategy (LTS) under 

section 51.308(d)(3) because Oklahoma 

has not shown that the strategy is 

adequate to achieve the reasonable 

progress goals set by Oklahoma and by 

other nearby States. The visibility 

modeling used by Oklahoma in support 

of its SIP revision submittal assumed 

SO2 reductions from the six sources 1 as 

identified above that Oklahoma did not 

secure when making its BART 

determinations for these sources. As we 

discuss elsewhere, ODEQ participated 

in the Central Regional Air Planning 

Association (CENRAP) visibility 

modeling development that assumed 

certain SO2 reductions from these six 

BART sources. ODEQ also performed its 

consultations with other states with the 

understanding that these reductions 

would be secured. We propose a FIP to 

cure these defects in BART and the LTS. 


srobinson on DSKHWCL6B1PROD with PROPOSALS3
16170 Federal Register / Vol. 76, No. 55 / Tuesday, March 22, 2011 / Proposed Rules 

We are also proposing to approve the 

remaining sections of the RH SIP 

submission, except as discussed below. 

We propose to find that Units 4 and 

5 of the OG&E Muskogee plant, Units 1 

and 2 of the OG&E Sooner plant, and 

Units 3 and 4 of the AEP/PSO 

Northeastern plant are subject to BART 

under 40 CFR 51.308(e). Further, we 

propose a FIP that specifically imposes 

SO2 BART emission limits on these 

sources. We propose that SO2 BART for 

Units 4 and 5 of the OG&E Muskogee 

plant, Units 1 and 2 of the OG&E Sooner 

plant, and Units 3 and 4 of the AEP/PSO 

Northeastern plant is an SO2 emission 

limit of 0.06 lbs/MMBtu that applies 

singly to each of these units on a 30 day 

rolling average. Additionally, we 

propose monitoring, recordkeeping, and 

reporting requirements to ensure 

compliance with these emission 

limitations. 

We propose that compliance with the 

emission limits be within three (3) years 

of the effective date of our final rule. We 

solicit comments on alternative 

timeframes, of from two (2) years up to 

five (5) years from the effective date our 

final rule. 

Should OG&E and/or AEP/PSO elect 

to reconfigure the above units to burn 

natural gas, as a means of satisfying 

their BART obligations under section 

51.308(e), that conversion should be 

completed within the same time frame. 

We invite comments as to, considering 

the engineering and/or management 

challenges of such a fuel switch, 

whether the full 5 years allowed under 

section 308(e)(1)(iv) following our final 

approval would be appropriate. 

We propose to disapprove section 

VI.E of the Oklahoma RH SIP entitled, 

‘‘Greater Reasonable Progress 

Alternative Determination.’’ We also 

propose to disapprove the separate 

executed agreements between ODEQ 

and OG&E, and ODEQ and AEP/PSO 

entitled ‘‘OG&E Regional Haze 

Agreement, Case No. 10–024, and ‘‘PSO 

Regional Haze Agreement, Case No. 10– 

025,’’ housed within Appendix 6–5 of 

the RH SIP. We propose that these 

portions of the submittal are severable 

from the BART determinations and the 

LTS; therefore, no FIP is required. 

We are taking no action on whether 

Oklahoma has satisfied the reasonable 

progress requirements of EPA’s regional 

haze SIP requirements found at section 

51.308(d)(1). 

B. Interstate Transport of Visibility 

We also propose to partially approve 

and partially disapprove a portion of a 

SIP revision we received from the State 

of Oklahoma on May 10, 2007, as 

supplemented on December 10, 2007, 

for the purpose of addressing the ‘‘good 

neighbor’’ provisions of the CAA section 

110(a)(2)(D)(i) for the 1997 8-hour ozone 

NAAQS and the PM2.5 NAAQS. Section 

110(a)(2)(D)(i)(II) of the Act requires that 

states have a SIP, or submit a SIP 

revision, containing provisions 

‘‘prohibiting any source or other type of 

emission activity within the state from 

emitting any air pollutant in amounts 

which will * * * interfere with 

measures required to be included in the 

applicable implementation plan for any 

other State under part C [of the CAA] to 

protect visibility.’’ Because of the 

impacts on visibility from the interstate 

transport of pollutants, we interpret the 

‘‘good neighbor’’ provisions of section 

110 of the Act described above as 

requiring states to include in their SIPs 

measures to prohibit emissions that 

would interfere with the reasonable 

progress goals set to protect Class I areas 

in other states. 

These SIP revisions were submitted to 

address the requirement that 

Oklahoma’s SIP must have adequate 

provisions to prohibit emissions from 

adversely affecting another state’s air 

quality through interstate transport. 

Oklahoma indicates in its May 10, 2007 

submittal that it intended that its RH 

SIP be used to satisfy the requirements 

of section 110(a)(2)(D)(i)(II) that 

emissions from Oklahoma sources do 

not interfere with measures required in 

the SIP of any other state under part C 

of the CAA to protect visibility. 

Consistent with our proposed actions 

with regard to Oklahoma’s RH SIP 

revision submittal, we also propose a 

partial approval and partial disapproval 

of the Oklahoma Interstate Transport 

SIP revision submittals that address the 

requirement of section 110(a)(2)(D)(i)(II). 

Specifically, we propose a partial 

approval and partial disapproval of the 

Oklahoma Interstate Transport SIP 

revision submittals that address the 

requirement of section 110(a)(2)(D)(i)(II) 

that emissions from Oklahoma sources 

do not interfere with measures required 

in the SIP of any other state under part 

C of the CAA to protect visibility. We 

believe that the controls proposed under 

the proposed FIP, in combination with 

the controls required by the portion of 

the Oklahoma RH submittal that we 

propose to approve, will serve to 

prevent sources in Oklahoma from 

emitting pollutants in amounts which 

will interfere with efforts to protect 

visibility in other states. 

II. SIP and FIP Background 

The CAA requires each state to 

develop a plan that provides for the 

implementation, maintenance, and 

enforcement of the NAAQS. CAA 

section 110(a). We establish NAAQS 

under section 109 of the CAA. 

Currently, the NAAQS address six 

criteria pollutants: Carbon monoxide; 

nitrogen dioxide; ozone; lead; 

particulate matter; and sulfur dioxide. 

The plan developed by a state is referred 

to as the SIP. The content of the SIP is 

specified in section 110 of the CAA, 

other provisions of the CAA, and 

applicable regulations. A primary 

purpose of the SIP is to provide the air 

pollution regulations, control strategies, 

and other means or techniques 

developed by the state to ensure that the 

ambient air within that state meets the 

NAAQS. However, another important 

aspect of the SIP is to ensure that 

emissions from within the state do not 

have certain prohibited impacts upon 

the ambient air in other states through 

the interstate transport of pollutants. 

CAA section 110(a)(2)(D). States are 

required to update or revise SIPs under 

certain circumstances. See CAA section 

110(a)(1). One such circumstance is our 

promulgation of a new or revised 

NAAQS. Id. Each state must submit 

these revisions to us for approval and 

incorporation into the federally 

enforceable SIP. 

If a state fails to make a required SIP 

submittal or if we find that, the state’s 

submittal is incomplete or 

unapprovable, then we must promulgate 

a FIP to fill this regulatory gap. CAA 

section 110(c)(1). As discussed 

elsewhere in this notice, we have made 

findings related to Oklahoma SIP 

revisions needed to address interstate 

transport and the requirement that 

emissions from Oklahoma sources do 

not interfere with measures required in 

the SIP of any other state to protect 

visibility, pursuant to section 

110(a)(2)(D)(i)(II) of the CAA. We 

propose a FIP to address the 

deficiencies in the Oklahoma Interstate 

Transport SIP. 

III. What is the background for our 

proposed actions? 

A. Regional Haze 

RH is visibility impairment that is 

produced by a multitude of sources and 

activities which are located across a 

broad geographic area and emit fine 

particles (PM2.5) (e.g., sulfates, nitrates, 

organic carbon, elemental carbon, and 

soil dust) and their precursors (e.g., SO2, 

nitrogen oxides (NOX), and in some 

cases, ammonia (NH3) and volatile 

organic compounds (VOCs)). Fine 

particle precursors react in the 

atmosphere to form PM2.5 (e.g., sulfates, 

nitrates, organic carbon, elemental 

carbon, and soil dust), which also 

impair visibility by scattering and 


srobinson on DSKHWCL6B1PROD with PROPOSALS3
Federal Register / Vol. 76, No. 55 / Tuesday, March 22, 2011 / Proposed Rules 16171 

2 Visual range is the greatest distance, in 

kilometers or miles, at which a dark object can be 

viewed against the sky. 

3Areas designated as mandatory Class I Federal 

areas consist of national parks exceeding 6000 

acres, wilderness areas and national memorial parks 

exceeding 5000 acres, and all international parks 

that were in existence on August 7, 1977. See CAA 

section 162(a). In accordance with section 169A of 

the CAA, EPA, in consultation with the Department 

of Interior, promulgated a list of 156 areas where 

visibility is identified as an important value. See 44 

FR 69122, November 30, 1979. The extent of a 

mandatory Class I area includes subsequent changes 

in boundaries, such as park expansions. CAA 

section 162(a). Although states and tribes may 

designate as Class I additional areas which they 

consider to have visibility as an important value, 

the requirements of the visibility program set forth 

in section 169A of the CAA apply only to 

‘‘mandatory Class I Federal areas.’’ Each mandatory 

Class I Federal area is the responsibility of a 

‘‘Federal Land Manager’’ (FLM). See CAA section 

302(i). When we use the term ‘‘Class I area’’ in this 

action, we mean a ‘‘mandatory Class I Federal area.’’ 

4Albuquerque/Bernalillo County in New Mexico 

must also submit a regional haze SIP to completely 

satisfy the requirements of section 110(a)(2)(D) of 

the CAA for the entire State of New Mexico under 

the New Mexico Air Quality Control Act (section 

74–2–4). 

absorbing light. Visibility impairment 

reduces the clarity, color, and visible 

distance that one can see. PM2.5 also can 

cause serious health effects and 

mortality in humans and contributes to 

environmental effects such as acid 

deposition and eutrophication. 

Data from the existing visibility 

monitoring network, the ‘‘Interagency 

Monitoring of Protected Visual 

Environments’’ (IMPROVE) monitoring 

network, show that visibility 

impairment caused by air pollution 

occurs virtually all the time at most 

national park and wilderness areas. The 

average visual range 2 in many Class I 

areas (i.e., national parks and memorial 

parks, wilderness areas, and 

international parks meeting certain size 

criteria) in the western United States is 

100–150 kilometers, or about one-half to 

two-thirds of the visual range that 

would exist without anthropogenic air 

pollution. 64 FR 35714, 35715 (July 1, 

1999). In most of the eastern Class I 

areas of the United States, the average 

visual range is less than 30 kilometers, 

or about one-fifth of the visual range 

that would exist under estimated 

natural conditions. Id. 

In section 169A of the 1977 

Amendments to the CAA, Congress 

created a program for protecting 

visibility in the nation’s national parks 

and wilderness areas. This section of the 

CAA establishes as a national goal the 

‘‘prevention of any future, and the 

remedying of any existing, impairment 

of visibility in mandatory Class I 

Federal areas 3 which impairment 

results from manmade air pollution.’’ 

CAA § 169A(a)(1). The terms 

‘‘impairment of visibility’’ and ‘‘visibility 

impairment’’ are defined in the Act to 

include a reduction in visual range and 

atmospheric discoloration. Id. section 

169A(g)(6). In 1980, we promulgated 

regulations to address visibility 

impairment in Class I areas that is 

‘‘reasonably attributable’’ to a single 

source or small group of sources, i.e., 

‘‘reasonably attributable visibility 

impairment’’ (RAVI). 45 FR 80084 

(December 2, 1980). These regulations 

represented the first phase in addressing 

visibility impairment. We deferred 

action on RH that emanates from a 

variety of sources until monitoring, 

modeling and scientific knowledge 

about the relationships between 

pollutants and visibility impairment 

were improved. 

Congress added section 169B to the 

CAA in 1990 to address RH issues, and 

we promulgated regulations addressing 

RH in 1999. 64 FR 35714 (July 1, 1999), 

codified at 40 CFR part 51, subpart P. 

The Regional Haze Rule (RHR) revised 

the existing visibility regulations to 

integrate into the regulations provisions 

addressing RH impairment and 

established a comprehensive visibility 

protection program for Class I areas. The 

requirements for RH, found at 40 CFR 

51.308 and 51.309, are included in our 

visibility protection regulations at 40 

CFR 51.300–309. Some of the main 

elements of the RH requirements are 

summarized in section III. The 

requirement to submit a RH SIP applies 

to all 50 states, the District of Columbia 

and the Virgin Islands.4 States were 

required to submit the first 

implementation plan addressing RH 

visibility impairment no later than 

December 17, 2007. 40 CFR 51.308(b). 

B. Roles of Agencies in Addressing 

Regional Haze 

Successful implementation of the RH 

program will require long-term regional 

coordination among states, tribal 

governments and various federal 

agencies. As noted above, pollution 

affecting the air quality in Class I areas 

can be transported over long distances, 

even hundreds of kilometers. Therefore, 

to address effectively the problem of 

visibility impairment in Class I areas, 

states need to develop strategies in 

coordination with one another, taking 

into account the effect of emissions from 

one jurisdiction on the air quality in 

another. 

Because the pollutants that lead to RH 

can originate from sources located 

across broad geographic areas, we have 

encouraged the states and tribes across 

the United States to address visibility 

impairment from a regional perspective. 

Five regional planning organizations 

(RPOs) were developed to address RH 

and related issues. The RPOs first 

evaluated technical information to 

better understand how their states and 

tribes impact Class I areas across the 

country, and then pursued the 

development of regional strategies to 

reduce emissions of particulate matter 

(PM) and other pollutants leading to RH. 

CENRAP is an organization of states, 

tribes, federal agencies and other 

interested parties that identifies RH and 

visibility issues and develops strategies 

to address them. CENRAP is one of the 

five Regional Planning Organizations 

RPOs across the U.S. and includes the 

states and tribal areas of Nebraska, 

Kansas, Oklahoma, Texas, Minnesota, 

Iowa, Missouri, Arkansas, and 

Louisiana. 

C. The 1997 NAAQS for Ozone and 

PM2.5 and CAA 110(a)(2)(D)(i) 

On July 18, 1997, we promulgated 

new NAAQS for 8-hour ozone and for 

PM2.5. 62 FR 38652. Section 110(a)(1) of 

the CAA requires states to submit SIPs 

to address a new or revised NAAQS 

within 3 years after promulgation of 

such standards, or within such shorter 

period as we may prescribe. Section 

110(a)(2) of the CAA lists the elements 

that such new SIPs must address, as 

applicable, including section 

110(a)(2)(D)(i), which pertains to the 

interstate transport of certain emissions. 

On April 25, 2005, we published a 

‘‘Finding of Failure to Submit SIPs for 

Interstate Transport for the 8-hour 

Ozone and PM2.5 NAAQS.’’ 70 FR 

21147. This included a finding that 

Oklahoma and other states had failed to 

submit SIPs for interstate transport of air 

pollution affecting visibility, and started 

a 2-year clock for the promulgation of a 

FIP by us, unless a state made a 

submission to meet the requirements of 

section 110(a)(2)(D)(i) and we approved 

the submission. Id. 

On August 15, 2006, we issued our 

‘‘Guidance for State Implementation 

Plan (SIP) Submission to Meet Current 

Outstanding Obligations Under Section 

110(a)(2)(D)(i) for the 8-Hour Ozone and 

PM2.5 National Ambient Air Quality 

Standards’’ (2006 Guidance). We 

developed the 2006 Guidance to make 

recommendations to states for making 

submissions to meet the requirements of 

section 110(a)(2)(D)(i) for the 1997 8- 

hour ozone standards and the 1997 

PM2.5 standards. 

As identified in the 2006 Guidance, 

the ‘‘good neighbor’’ provisions in 

section 110(a)(2)(D)(i) of the CAA 

require each state to submit a SIP that 

prohibits emissions that adversely affect 

another state in the ways contemplated 


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5The preamble to the RHR provides additional 

details about the deciview. 64 FR 35714, 35725 

(July 1, 1999). 

6 Guidance for Estimating Natural Visibility 

Conditions Under the Regional Haze Rule, 

September 2003, EPA–454/B–03–005, available at 

http://www.epa.gov/ttncaaa1/t1/memoranda/ 

rh_envcurhr_gd.pdf (hereinafter referred to as ‘‘our 

2003 Natural Visibility Guidance’’); and Guidance 

for Tracking Progress Under the Regional Haze 

Rule, EPA–454/B–03–004, September 2003, 

available at http://www.epa.gov/ttncaaa1/t1/ 

memoranda/rh_tpurhr_gd.pdf (hereinafter referred 

to as our ‘‘2003 Tracking Progress Guidance’’). 

in the statute. Section 110(a)(2)(D)(i) 

contains four distinct requirements 

related to the impacts of interstate 

transport. The SIP must prevent sources 

in the state from emitting pollutants in 

amounts which will: (1) Contribute 

significantly to nonattainment of the 

NAAQS in other states; (2) interfere 

with maintenance of the NAAQS in 

other states; (3) interfere with provisions 

to prevent significant deterioration of air 

quality in other states; or (4) interfere 

with efforts to protect visibility in other 

states. 

The 2006 Guidance stated that states 

may make a simple SIP submission 

confirming that it is not possible at that 

time to assess whether there is any 

interference with measures in the 

applicable SIP for another state 

designed to ‘‘protect visibility’’ for the 8- 

hour ozone and PM2.5 NAAQS until RH 

SIPs are submitted and approved. RH 

SIPs were required to be submitted by 

December 17, 2007. See 74 FR 2392 

(January 15, 2009). 

On May 10, 2007, we received a SIP 

revision from Oklahoma to address the 

interstate transport provisions of CAA 

110(a)(2)(D)(i) for the 1997 ozone and 

PM2.5 NAAQS. We received a 

supplement to this SIP revision on 

December 10, 2007. In a prior action we 

approved the Oklahoma SIP submittal 

for the ‘‘interfere with measures to 

prevent significant deterioration’’ prong 

of section 110(a)(2)(D)(i) of the CAA. 75 

FR 72695, November 26, 2010. On 

February 19, 2010, Oklahoma submitted 

a RH SIP to address interstate transport 

of emissions that could interfere with 

efforts to protect visibility in other 

states. Because, for the reasons outlined 

below, we can only partially approve 

this RH SIP, we propose to partially 

approve and partially disapprove the 

Oklahoma Interstate Transport SIP 

revision submittals that address the 

requirement that emissions from 

Oklahoma sources do not interfere with 

measures required in the SIP of any 

other state to protect visibility. See CAA 

section 110(a)(2)(D)(i)(II). We propose to 

promulgate a FIP in order to cure this 

defect in the Oklahoma Interstate 

Transport SIP revision submittals. 

IV. What are the requirements for 

regional haze SIPs? 

The following is a summary and basic 

explanation of the regulations covered 

under the RHR. See 40 CFR 51.308 for 

a complete listing of the regulations 

under which this SIP was evaluated. 

A. The CAA and the Regional Haze Rule 

RH SIPs must assure reasonable 

progress towards the national goal of 

achieving natural visibility conditions 

in Class I areas. Section 169A of the 

CAA and our implementing regulations 

require states to establish long-term 

strategies for making reasonable 

progress toward meeting this goal. 

Implementation plans must also give 

specific attention to certain stationary 

sources that were in existence on 

August 7, 1977, but were not in 

operation before August 7, 1962, and 

require these sources, where 

appropriate, to install BART controls for 

the purpose of eliminating or reducing 

visibility impairment. The specific RH 

SIP requirements are discussed in 

further detail below. 

B. Determination of Baseline, Natural, 

and Current Visibility Conditions 

The RHR establishes the deciview 

(dv) as the principal metric for 

measuring visibility. See 70 FR 39104. 

This visibility metric expresses uniform 

changes in the degree of haze in terms 

of common increments across the entire 

range of visibility conditions, from 

pristine to extremely hazy conditions. 

Visibility is sometimes expressed in 

terms of the visual range, which is the 

greatest distance, in kilometers or miles, 

at which a dark object can just be 

distinguished against the sky. The 

deciview is a useful measure for 

tracking progress in improving 

visibility, because each deciview change 

is an equal incremental change in 

visibility perceived by the human eye. 

Most people can detect a change in 

visibility of one deciview.5

The deciview is used in expressing 

Reasonable Progress Goals (RPGs) 

(which are interim visibility goals 

towards meeting the national visibility 

goal), defining baseline, current, and 

natural conditions, and tracking changes 

in visibility. The RH SIPs must contain 

measures that ensure ‘‘reasonable 

progress’’ toward the national goal of 

preventing and remedying visibility 

impairment in Class I areas caused by 

manmade air pollution by reducing 

anthropogenic emissions that cause RH. 

The national goal is a return to natural 

conditions, i.e., manmade sources of air 

pollution would no longer impair 

visibility in Class I areas. 

To track changes in visibility over 

time at each of the 156 Class I areas 

covered by the visibility program (40 

CFR 81.401–437), and as part of the 

process for determining reasonable 

progress, states must calculate the 

degree of existing visibility impairment 

at each Class I area at the time of each 

RH SIP submittal and periodically 

review progress every five years midway 

through each 10-year implementation 

period. To do this, the RHR requires 

states to determine the degree of 

impairment (in deciviews) for the 

average of the 20 percent least impaired 

(‘‘best’’) and 20 percent most impaired 

(‘‘worst’’) visibility days over a specified 

time period at each of their Class I areas. 

In addition, states must also develop an 

estimate of natural visibility conditions 

for the purpose of comparing progress 

toward the national goal. Natural 

visibility is determined by estimating 

the natural concentrations of pollutants 

that cause visibility impairment and 

then calculating total light extinction 

based on those estimates. We have 

provided guidance to states regarding 

how to calculate baseline, natural and 

current visibility conditions.6

For the first RH SIPs that were due by 

December 17, 2007, ‘‘baseline visibility 

conditions’’ were the starting points for 

assessing ‘‘current’’ visibility 

impairment. Baseline visibility 

conditions represent the degree of 

visibility impairment for the 20 percent 

least impaired days and 20 percent most 

impaired days for each calendar year 

from 2000 to 2004. Using monitoring 

data for 2000 through 2004, states are 

required to calculate the average degree 

of visibility impairment for each Class I 

area, based on the average of annual 

values over the five-year period. The 

comparison of initial baseline visibility 

conditions to natural visibility 

conditions indicates the amount of 

improvement necessary to attain natural 

visibility, while the future comparison 

of baseline conditions to the then 

current conditions will indicate the 

amount of progress made. In general, the 

2000–2004 baseline period is 

considered the time from which 

improvement in visibility is measured. 

C. Determination of Reasonable Progress 

Goals 

The vehicle for ensuring continuing 

progress towards achieving the natural 

visibility goal is the submission of a 

series of RH SIPs from the states that 

establish two RPGs (i.e., two distinct 

goals, one for the ‘‘best’’ and one for the 

‘‘worst’’ days) for every Class I area for 

each (approximately) 10-year 

implementation period. See 70 FR 3915; 


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7 Guidance for Setting Reasonable Progress Goals 

under the Regional Haze Program, June 1, 2007, 

memorandum from William L. Wehrum, Acting 

Assistant Administrator for Air and Radiation, to 

EPA Regional Administrators, EPA Regions 1–10 

(pp. 4–2, 5–1). 

8The set of ‘‘major stationary sources’’ potentially 

subject to BART are listed in CAA section 

169A(g)(7). 

9 In American Corn Growers Ass’n v. EPA, 291 

F.3d 1 (DC Cir. 2002), the U.S Court of Appeals for 

the District of Columbia Circuit issued a ruling 

vacating and remanding the BART provisions of the 

regional haze rule. In 2005, we issued BART 

guidelines to address the court’s ruling in that case. 

See 70 FR 39104 (July 6, 2005). 

10BART-eligible sources are those sources that 

have the potential to emit 250 tons or more of a 

visibility-impairing air pollutant, were put in place 

between August 7, 1962 and August 7, 1977, and 

whose operations fall within one or more of 26 

specifically listed source categories. 

see also 64 FR 35714. The RHR does not 

mandate specific milestones or rates of 

progress, but instead calls for states to 

establish goals that provide for 

‘‘reasonable progress’’ toward achieving 

natural (i.e., ‘‘background’’) visibility 

conditions. In setting RPGs, states must 

provide for an improvement in visibility 

for the most impaired days over the 

(approximately) 10-year period of the 

SIP, and ensure no degradation in 

visibility for the least impaired days 

over the same period. Id. 

States have significant discretion in 

establishing RPGs, but are required to 

consider the following factors 

established in section 169A of the CAA 

and in our RHR at 40 CFR 

51.308(d)(1)(i)(A): (1) The costs of 

compliance; (2) the time necessary for 

compliance; (3) the energy and non-air 

quality environmental impacts of 

compliance; and (4) the remaining 

useful life of any potentially affected 

sources. States must demonstrate in 

their SIPs how these factors are 

considered when selecting the RPGs for 

the best and worst days for each 

applicable Class I area. States have 

considerable flexibility in how they take 

these factors into consideration, as 

noted in our Reasonable Progress 

Guidance.7 In setting the RPGs, states 

must also consider the rate of progress 

needed to reach natural visibility 

conditions by 2064 (referred to hereafter 

as the ‘‘Uniform Rate of Progress (URP)’’) 

and the emission reduction measures 

needed to achieve that rate of progress 

over the 10-year period of the SIP. 

Uniform progress towards achievement 

of natural conditions by the year 2064 

represents a rate of progress, which 

states are to use for analytical 

comparison to the amount of progress 

they expect to achieve. In setting RPGs, 

each state with one or more Class I areas 

(‘‘Class I State’’) must also consult with 

potentially ‘‘contributing states,’’ i.e., 

other nearby states with emission 

sources that may be affecting visibility 

impairment at the Class I State’s areas. 

40 CFR 51.308(d)(1)(iv). 

D. Best Available Retrofit Technology 

Section 169A of the CAA directs 

states to evaluate the use of retrofit 

controls at certain larger, often 

uncontrolled, older stationary sources 

with the potential to emit greater than 

250 tons or more of any pollutant in 

order to address visibility impacts from 

these sources. Specifically, section 

169A(b)(2)(A) of the Act requires states 

to revise their SIPs to contain such 

measures as may be necessary to make 

reasonable progress towards the natural 

visibility goal, including a requirement 

that certain categories of existing major 

stationary sources 8 built between 1962 

and 1977 procure, install, and operate 

the ‘‘Best Available Retrofit Technology’’ 

(BART), as determined by the state or us 

in the case of a plan promulgated under 

section 110(c) of the CAA. Under the 

RHR, States are directed to conduct 

BART determinations for such ‘‘BARTeligible’’ sources that may be anticipated 

to cause or contribute to any visibility 

impairment in a Class I area. Rather 

than requiring source-specific BART 

controls, states also have the flexibility 

to adopt an emissions trading program 

or other alternative program as long as 

the alternative provides greater 

reasonable progress towards improving 

visibility than BART. 

We promulgated regulations 

addressing RH in 1999, 64 FR 35714 

(July 1, 1999), codified at 40 CFR part 

51, subpart P.9 These regulations require 

all states to submit implementation 

plans that, among other measures, 

contain either emission limits 

representing BART for certain sources 

constructed between 1962 and 1977, or 

alternative measures that provide for 

greater reasonable progress than BART. 

40 CFR 51.308(e). 

On July 6, 2005, we published the 

Guidelines for BART Determinations 

Under the Regional Haze Rule at 

Appendix Y to 40 CFR Part 51 (‘‘BART 

Guidelines’’) to assist states in 

determining which of their sources 

should be subject to the BART 

requirements and in determining 

appropriate emission limits for each 

applicable source. 70 FR 39104. In 

making a BART determination for a 

fossil fuel-fired electric generating plant 

with a total generating capacity in 

excess of 750 megawatts, a state must 

use the approach set forth in the BART 

Guidelines. A state is encouraged, but 

not required, to follow the BART 

Guidelines in making BART 

determinations for other types of 

sources. 

The process of establishing BART 

emission limitations can be logically 

broken down into three steps: first, 

states identify those sources which meet 

the definition of ‘‘BART-eligible source’’ 

set forth in 40 CFR 51.301; 10 second, 

states determine whether such sources 

‘‘emits any air pollutant which may 

reasonably be anticipated to cause or 

contribute to any impairment of 

visibility in any such area’’ (a source 

which fits this description is ‘‘subject to 

BART’’) and; third, for each source 

subject to BART, states then identify the 

appropriate type and the level of control 

for reducing emissions. 

States must address all visibilityimpairing pollutants emitted by a source 

in the BART determination process. The 

most significant visibility impairing 

pollutants are SO2, NOX, and PM. We 

have stated that states should use their 

best judgment in determining whether 

VOC or ammonia compounds impair 

visibility in Class I areas. 

Under the BART Guidelines, states 

may select an exemption threshold 

value for their BART modeling, below 

which a BART-eligible source would 

not be expected to cause or contribute 

to visibility impairment in any Class I 

area. The state must document this 

exemption threshold value in the SIP 

and must state the basis for its selection 

of that value. Any source with 

emissions that model above the 

threshold value would be subject to a 

BART determination review. The BART 

Guidelines acknowledge varying 

circumstances affecting different Class I 

areas. States should consider the 

number of emission sources affecting 

the Class I areas at issue and the 

magnitude of the individual sources’ 

impacts. Any exemption threshold set 

by the state should not be higher than 

0.5 dv. 

In their SIPs, states must identify 

potential BART sources, described as 

‘‘BART-eligible sources’’ in the RHR, and 

document their BART control 

determination analyses. The term 

‘‘BART-eligible source’’ used in the 

BART Guidelines means the collection 

of individual emission units at a facility 

that together comprises the BARTeligible source. In making BART 

determinations, section 169A(g)(2) of 

the CAA requires that states consider 

the following factors: (1) The costs of 

compliance; (2) the energy and non-air 

quality environmental impacts of 

compliance; (3) any existing pollution 

control technology in use at the source; 

(4) the remaining useful life of the 

source; and (5) the degree of 


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improvement in visibility which may 

reasonably be anticipated to result from 

the use of such technology. States are 

free to determine the weight and 

significance to be assigned to each 

factor. See 40 CFR 51.308(e)(1)(ii). 

A RH SIP must include sourcespecific BART emission limits and 

compliance schedules for each source 

subject to BART. Once a state has made 

its BART determination, the BART 

controls must be installed and in 

operation as expeditiously as 

practicable, but no later than five years 

after the date of our approval of the RH 

SIP. CAA section 169(g)(4) and 40 CFR 

51.308(e)(1)(iv). In addition to what is 

required by the RHR, general SIP 

requirements mandate that the SIP must 

also include all regulatory requirements 

related to monitoring, recordkeeping, 

and reporting for the BART controls on 

the source. See CAA section 110(a). As 

noted above, the RHR allows states to 

implement an alternative program in 

lieu of BART so long as the alternative 

program can be demonstrated to achieve 

greater reasonable progress toward the 

national visibility goal than would 

BART. 

E. Long-Term Strategy (LTS) 

Consistent with the requirement in 

section 169A(b) of the CAA that states 

include in their regional haze SIP a 10 

to 15 year strategy for making 

reasonable progress, Section 

51.308(d)(3) of the RHR requires that 

states include a LTS in their RH SIPs. 

The LTS is the compilation of all 

control measures a state will use during 

the implementation period of the 

specific SIP submittal to meet any 

applicable RPGs. The LTS must include 

‘‘enforceable emissions limitations, 

compliance schedules, and other 

measures as necessary to achieve the 

reasonable progress goals’’ for all Class 

I areas within, or affected by emissions 

from, the state. 40 CFR 51.308(d)(3). 

When a state’s emissions are 

reasonably anticipated to cause or 

contribute to visibility impairment in a 

Class I area located in another state, the 

RHR requires the impacted state to 

coordinate with the contributing states 

in order to develop coordinated 

emissions management strategies. 40 

CFR 51.308(d)(3)(i). In such cases, the 

contributing state must demonstrate that 

it has included, in its SIP, all measures 

necessary to obtain its share of the 

emission reductions needed to meet the 

RPGs for the Class I area. The RPOs 

have provided forums for significant 

interstate consultation, but additional 

consultations between states may be 

required to sufficiently address 

interstate visibility issues. This is 

especially true where two states belong 

to different RPOs. 

States should consider all types of 

anthropogenic sources of visibility 

impairment in developing their LTS, 

including stationary, minor, mobile, and 

area sources. At a minimum, states must 

describe how each of the following 

seven factors listed below are taken into 

account in developing their LTS: (1) 

Emission reductions due to ongoing air 

pollution control programs, including 

measures to address RAVI; (2) measures 

to mitigate the impacts of construction 

activities; (3) emissions limitations and 

schedules for compliance to achieve the 

RPG; (4) source retirement and 

replacement schedules; (5) smoke 

management techniques for agricultural 

and forestry management purposes 

including plans as currently exist 

within the state for these purposes; (6) 

enforceability of emissions limitations 

and control measures; (7) the 

anticipated net effect on visibility due to 

projected changes in point, area, and 

mobile source emissions over the period 

addressed by the LTS. 40 CFR 

51.308(d)(3)(v). 

F. Coordinating Regional Haze and 

Reasonably Attributable Visibility 

Impairment 

As part of the RHR, we revised 40 

CFR 51.306(c) regarding the LTS for 

RAVI to require that the RAVI plan must 

provide for a periodic review and SIP 

revision not less frequently than every 

three years until the date of submission 

of the state’s first plan addressing RH 

visibility impairment, which was due 

December 17, 2007, in accordance with 

40 CFR 51.308(b) and (c). On or before 

this date, the state must revise its plan 

to provide for review and revision of a 

coordinated LTS for addressing RAVI 

and RH, and the state must submit the 

first such coordinated LTS with its first 

RH SIP. Future coordinated LTS and 

periodic progress reports evaluating 

progress towards RPGs, must be 

submitted consistent with the schedule 

for SIP submission and periodic 

progress reports set forth in 40 CFR 

51.308(f) and 51.308(g), respectively. 

The periodic review of a state’s LTS 

must report on both RH and RAVI 

impairment and must be submitted to us 

as a SIP revision. 

G. Monitoring Strategy and Other SIP 

Requirements 

Section 51.308(d)(4) of the RHR 

includes the requirement for a 

monitoring strategy for measuring, 

characterizing, and reporting of RH 

visibility impairment that is 

representative of all mandatory Class I 

Federal areas within the state. The 

strategy must be coordinated with the 

monitoring strategy required in section 

51.305 for RAVI. Compliance with this 

requirement may be met through 

‘‘participation’’ in the Interagency 

Monitoring of Protected Visual 

Environments (IMPROVE) network, i.e., 

review and use of monitoring data from 

the network. The monitoring strategy is 

due with the first RH SIP, and it must 

be reviewed every five (5) years. The 

monitoring strategy must also provide 

for additional monitoring sites if the 

IMPROVE network is not sufficient to 

determine whether RPGs will be met. 

The SIP must also provide for the 

following: 

• Procedures for using monitoring 

data and other information in a state 

with mandatory Class I areas to 

determine the contribution of emissions 

from within the state to RH visibility 

impairment at Class I areas both within 

and outside the state; 

• Procedures for using monitoring 

data and other information in a state 

with no mandatory Class I areas to 

determine the contribution of emissions 

from within the state to RH visibility 

impairment at Class I areas in other 

states; 

• Reporting of all visibility 

monitoring data to the Administrator at 

least annually for each Class I area in 

the state, and where possible, in 

electronic format; 

• Developing a statewide inventory of 

emissions of pollutants that are 

reasonably anticipated to cause or 

contribute to visibility impairment in 

any Class I area. The inventory must 

include emissions for a baseline year, 

emissions for the most recent year for 

which data are available, and estimates 

of future projected emissions. A state 

must also make a commitment to update 

the inventory periodically; and 

• Other elements, including 

reporting, recordkeeping, and other 

measures necessary to assess and report 

on visibility. 

The RHR requires control strategies to 

cover an initial implementation period 

extending to the year 2018, with a 

comprehensive reassessment and 

revision of those strategies, as 

appropriate, every 10 years thereafter. 

Periodic SIP revisions must meet the 

core requirements of section 51.308(d) 

with the exception of BART. The 

requirement to evaluate sources for 

BART applies only to the first RH SIP. 

Facilities subject to BART must 

continue to comply with the BART 

provisions of section 51.308(e), as noted 

above. Periodic SIP revisions will assure 

that the statutory requirement of 

reasonable progress will continue to be 

met. 


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11Unless otherwise noted, when we refer to 

visibility impacts, we mean the impacts due solely 

to the source or state named, which do not include 

natural conditions. 

12 Guidance for Estimating Natural Visibility 

Conditions Under the Regional Haze Rule, EPA– 

454/B–03–005, September 2003. 

13The IMPROVE program is a cooperative 

measurement effort governed by a steering 

committee composed of representatives from 

Federal agencies (including representatives from 

EPA and the FLMs) and RPOs. The IMPROVE 

monitoring program was established in 1985 to aid 

the creation of Federal and State implementation 

plans for the protection of visibility in Class I areas. 

One of the objectives of IMPROVE is to identify 

chemical species and emission sources responsible 

for existing anthropogenic visibility impairment. 

The IMPROVE program has also been a key 

participant in visibility-related research, including 

the advancement of monitoring instrumentation, 

analysis techniques, visibility modeling, policy 

formulation and source attribution field studies. 

14The science behind the revised IMPROVE 

equation is summarized in Appendix B.2 of the 

Tennessee Regional Haze submittal and in 

numerous published papers. See for example: 

Hand, J.L., and Malm, W.C., 2006, Review of the 

IMPROVE Equation for Estimating Ambient Light 

Extinction Coefficients—Final Report. March 2006. 

Prepared for Interagency Monitoring of Protected 

Visual Environments (IMPROVE), Colorado State 

University, Cooperative Institute for Research in the 

Atmosphere, Fort Collins, Colorado, available at 

http://vista.cira.colostate.edu/improve/ 

publications/GrayLit/016_IMPROVEeqReview/ 

IMPROVEeqReview.htm and Pitchford, Marc., 2006, 

Natural Haze Levels II: Application of the New 

IMPROVE Algorithm to Natural Species 

Concentrations Estimates. Final Report of the 

Natural Haze Levels II Committee to the RPO 

Monitoring/Data Analysis Workgroup. September 

2006, available at http://vista.cira.colostate.edu/ 

improve/Publications/GrayLit/029_NaturalCondII/ 

naturalhazelevelsIIreport.ppt. 

H. Consultation With States and Federal 

Land Managers 

The RHR requires that states consult 

with Federal Land Managers (FLMs) 

before adopting and submitting their 

SIPs. 40 CFR 51.308(i). States must 

provide FLMs an opportunity for 

consultation, in person and at least 60 

days prior to holding any public hearing 

on the SIP. This consultation must 

include the opportunity for the FLMs to 

discuss their assessment of impairment 

of visibility in any Class I area and to 

offer recommendations on the 

development of the RPGs and on the 

development and implementation of 

strategies to address visibility 

impairment. Further, a state must 

include in its SIP a description of how 

it addressed any comments provided by 

the FLMs. Finally, a SIP must provide 

procedures for continuing consultation 

between the state and FLMs regarding 

the state’s visibility protection program, 

including development and review of 

SIP revisions, five-year progress reports, 

and the implementation of other 

programs having the potential to 

contribute to impairment of visibility in 

Class I areas. 

V. Our Analysis of Oklahoma’s 

Regional Haze SIP 

On February 19, 2010, we received a 

RH SIP revision from the State of 

Oklahoma for approval into the 

Oklahoma SIP. The following is a 

discussion of our evaluation of that 

submission. The parts of the submittal 

that are interrelated are discussed 

together, in order to provide the reader 

with a more ready understanding of our 

evaluation. See the Technical Support 

Document (TSD) for this proposal for a 

step-wise evaluation of ODEQ’s 

submission in the order in which the 

regulations appear in 40 CFR 51.308, 

and a more comprehensive technical 

analysis. 

A. Affected Class I Areas 

In accordance with 40 CFR 51.308(d), 

ODEQ has identified one Class I area 

within its borders, the Wichita 

Mountains National Wildlife Refuge 

(Wichita Mountains). ODEQ has also 

determined that Oklahoma emissions 

have a small potential to impact 

visibility at Class I areas outside of 

Oklahoma. Based on projections of 

visibility in 2018 for the 20% worst 

visibility days, ODEQ has projected that 

Oklahoma emissions are responsible for 

visibility degradation at the Hercules 

Glades in Missouri of approximately 

3.61%, the Salt Creek in New Mexico of 

approximately 2.53%, and the 

Guadalupe Mountains in Texas of 

approximately 2.0%.11 We note that 

these projections are based on modeling 

done by CENRAP that assumed a certain 

level of reductions of SO2 emissions 

from six sources that Oklahoma did not 

actually require in its submitted RH SIP 

revision. We expect that Oklahoma’s 

projected impacts on visibility at Class 

I areas outside of Oklahoma would be 

greater had these controls and the 

associated SO2 emission reductions not 

been included in CENRAP’s visibility 

modeling. 

B. Determination of Baseline, Natural 

and Current Visibility Conditions 

As required by section 51.308(d)(2)(i) 

of the RHR and in accordance with 

EPA’s 2003 Natural Visibility 

Guidance,12 ODEQ calculated baseline/ 

current and natural visibility conditions 

for its Class I area, the Wichita 

Mountains, on the most impaired and 

least impaired days, as summarized 

below (and further described in the 

TSD). 

1. Estimating Natural Visibility 

Conditions 

Natural background visibility, as 

defined in EPA’s 2003 Natural Visibility 

Guidance, is estimated by calculating 

the expected light extinction using 

default estimates of natural 

concentrations of fine particle 

components adjusted by site-specific 

estimates of humidity. This calculation 

uses the IMPROVE equation, which is a 

formula for estimating light extinction 

from the estimated natural 

concentrations of fine particle 

components (or from components 

measured by the IMPROVE monitors). 

As documented in EPA’s 2003 Natural 

Visibility Guidance, EPA allows states 

to use ‘‘refined’’ or alternative 

approaches to 2003 EPA guidance to 

estimate the values that characterize the 

natural visibility conditions of Class I 

areas. One alternative approach is to 

develop and justify the use of 

alternative estimates of natural 

concentrations of fine particle 

components. Another alternative is to 

use the ‘‘new IMPROVE equation’’ that 

was adopted for use by the IMPROVE 

Steering Committee in December 

2005.13 The purpose of this refinement 

to the ‘‘old IMPROVE equation’’ is to 

provide more accurate estimates of the 

various factors that affect the calculation 

of light extinction. 

ODEQ opted to use the default 

estimates for the natural conditions 

combined with the ‘‘new Improve 

equation,’’ for Wichita Mountains. This 

is an acceptable approach under our 

2003 Natural Visibility Guidance. For 

the Wichita Mountains, the default 

natural visibility value for the 20 

percent worst days is 11.07 deciviews 

and for the 20 percent best days it is 

3.39 dv. For the Wichita Mountains, 

ODEQ also used the new IMPROVE 

equation to calculate the ‘‘refined’’ 

natural visibility value for the 20 

percent worst days to be 7.53 deciviews 

and for the 20 percent best days to be 

4.2 deciviews. We have reviewed 

ODEQ’s estimate of the natural visibility 

conditions and propose to find it 

acceptable using the new IMPROVE 

equation. 

The new IMPROVE equation takes 

into account the most recent review of 

the science 14 and it accounts for the 

effect of particle size distribution on 

light extinction efficiency of sulfate, 

nitrate, and organic carbon. It also 

adjusts the mass multiplier for organic 

carbon (particulate organic matter) by 

increasing it from 1.4 to 1.8. New terms 

are added to the equation to account for 

light extinction by sea salt and light 

absorption by gaseous nitrogen dioxide. 

Site-specific values are used for 

Rayleigh scattering (scattering of light 

due to atmospheric gases) to account for 

the site-specific effects of elevation and 


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16176 Federal Register / Vol. 76, No. 55 / Tuesday, March 22, 2011 / Proposed Rules 

15 Guidance for Estimating Natural Visibility 

Conditions Under the Regional Haze Rule, EPA– 

454/B–03–005, September 2003. 

16The amount of light lost as it travels over one 

million meters. The haze index, in units of 

deciviews (dv), is calculated directly from the total 

light extinction, bext expressed in inverse 

megameters (Mm¥1), as follows: HI = 10 ln(bext/10). 

17 Guidance for Tracking Progress Under the 

Regional Haze Rule, EPA–454/B–03–004, 

September 2003, pages 2–8. 

temperature. Separate relative humidity 

enhancement factors are used for small 

and large size distributions of 

ammonium sulfate and ammonium 

nitrate and for sea salt. The terms for the 

remaining contributors, elemental 

carbon (light-absorbing carbon), fine 

soil, and coarse mass terms, do not 

change between the original and new 

IMPROVE equations. 

2. Estimating Baseline Visibility 

Conditions 

As required by section 51.308(d)(2)(i) 

of the RHR and in accordance with 

EPA’s 2003 Natural Visibility 

Guidance,15 ODEQ calculated baseline 

visibility conditions for the Wichita 

Mountains. The baseline condition 

calculation begins with the calculation 

of light extinction, using the IMPROVE 

equation. The IMPROVE equation sums 

the light extinction 16 resulting from 

individual pollutants, such as sulfates 

and nitrates. As with the natural 

visibility conditions calculation, ODEQ 

chose to use the new IMPROVE 

equation. 

The period for establishing baseline 

visibility conditions is 2000–2004, and 

baseline conditions must be calculated 

using available monitoring data. 40 CFR 

51.308(d)(2). Although visibility 

monitoring only began at the Wichita 

Mountains in March 2001, ODEQ 

concluded that no other monitor 

provided a reasonable substitute that 

met our completeness criteria.17 As a 

consequence, the Oklahoma RH SIP 

employed the incomplete visibility data 

for 2001, complete data for 2002–2004, 

and provisional data for 2005 and 2006. 

The resulting baseline conditions 

represent an average for 2002–2004. 

ODEQ calculated the baseline 

conditions at the Wichita Mountains as 

23.81 deciviews on the 20 percent worst 

days, and 9.78 deciviews on the 20 

percent best days. We have reviewed 

ODEQ’s estimation of baseline visibility 

conditions at Wichita Mountains and 

propose to find it acceptable. 

3. Natural Visibility Impairment 

To address 40 CFR 

51.308(d)(2)(iv)(A), ODEQ also 

calculated the number of deciviews by 

which baseline conditions exceed 

natural visibility conditions at the 

Wichita Mountains for the 20 percent 

worst days to be 16.28 dv (23.81¥7.53). 

ODEQ calculated the baseline and 

natural visibility conditions on the 20 

percent best days to be 9.78 and 4.2 dv, 

respectively. This results in a 

calculation in which baseline 

conditions exceed natural visibility 

conditions at the Wichita Mountains for 

the 20 percent best days to be 5.6 dv 

(9.78¥4.2). We have reviewed ODEQ’s 

estimate of the natural visibility 

impairment and propose to find it 

acceptable. 

4. Uniform Rate of Progress 

In setting the RPGs, ODEQ analyzed 

and determined the Uniform Rate of 

Progress (URP) needed to reach natural 

visibility conditions by the year 2064. In 

so doing, ODEQ compared the baseline 

visibility conditions in the Wichita 

Mountains to the natural visibility 

conditions in the Wichita Mountains (as 

described above) and determined the 

uniform rate of progress needed in order 

to attain natural visibility conditions by 

2064. ODEQ constructed the URP 

consistent with our 2003 Tracking 

Progress Guidance by plotting a straight 

graphical line from the baseline level of 

visibility impairment for 2000–2004 to 

the level of visibility conditions 

representing no anthropogenic 

impairment in 2064 for the Wichita 

Mountains. Using a baseline visibility 

value of 23.81 dv and a ‘‘refined’’ natural 

visibility value of 7.53 dv for the 20 

percent worst days, ODEQ calculated 

the URP to be approximately 0.27 dv per 

year. This results in a total reduction of 

16.28 dv that are necessary to reach the 

natural visibility condition of 7.53 dv in 

2064. The URP results in a visibility 

improvement of 3.80 dv for the period 

covered by this SIP revision submittal 

(up to and including 2018). 

TABLE 1—SUMMARY OF UNIFORM

RATE OF PROGRESS

Baseline Conditions .............. 23.81 dv. 

Natural Visibility ..................... 7.53 dv. 

Total Improvement by 2064 .. 16.28 dv. 

Improvement for this SIP by 

2018.

3.80 dv. 

Uniform Rate of Progress ..... 0.27 dv/year. 

We propose to find that ODEQ has 

appropriately calculated the URP. 

C. Evaluation of Oklahoma’s 

Reasonable Progress Goal 

We are not taking action on 

Oklahoma’s submitted RPGs because, as 

described more fully below, we must 

first evaluate and act upon the RH SIP 

revision submitted by the State of Texas. 

We provide a short summary of the 

Oklahoma submittal for informational 

purposes only. 

1. Establishment of the Reasonable 

Progress Goal 

ODEQ calculated the RPG for the 

Wichita Mountains for 2018 for the 20% 

best days to be 9.23 dv, which is a 0.54 

dv improvement over a baseline of 9.78 

dv. ODEQ calculated the reasonable 

progress goal for 2018 for the 20% worst 

days to be 21.47 dv, which is a 2.3 

deciview improvement over a baseline 

of 23.81 dv. ODEQ’s RPG establishes a 

slower rate of progress than the URP. 

ODEQ has calculated that under its 

reasonable progress goal, it would attain 

natural visibility conditions in 2102. As 

we discuss elsewhere, ODEQ indicated 

that emissions from other states, 

especially Texas, impeded Oklahoma’s 

ability to meet the URP. 

2. ODEQ’s Reasonable Progress ‘‘Four 

Factor’’ Analysis 

ODEQ analyzed the largest sources of 

visibility impairing pollutants within 

the state, including sources of sulfur, 

nitrates, ammonia, VOCs, and directly 

emitted coarse and fine particles. ODEQ 

calculated (1) that sulfurous pollutants 

contribute approximately 44% and 

nitrate bearing pollutants contribute 

approximately 21% of the total light 

extinction (or visibility impairment) to 

the Wichita Mountains, and (2) sources 

within Oklahoma contribute only 

approximately 13% of the total 

pollutants that contribute to light 

extinction. 

ODEQ initially relied on CENRAP 

modeling, based on an Alpine 

Geophysics evaluation of possible 

additional point-source controls for 

CENRAP states for 2018. That study 

relied on AirControlNet, an EPA costbenefit tool for emissions of NOX and 

SO2. CENRAP used a maximum 

estimated cost of $5,000 per ton of 

emissions of NOX or SO2 reduced for 

sources over 100 tons of SO2 or NOX in 

the year 2018. CENRAP further refined 

the analysis, considering controls only 

for those sources with emissions of NOX

or SO2 greater than or equal to five tons 

per year per kilometer of distance to the 

Wichita Mountains or the nearest other 

Class I area. This analysis resulted in 

the conclusion by ODEQ that visibility 

at the Wichita Mountains would be 

improved by an additional 0.5 dv, over 

what ODEQ projects as its reasonable 

progress goal of 21.47 deciview for 2018 

if controls were implemented at the 

sources that met this combination of 

baseline emissions, potential for costeffective reductions, and visibility 

impact. 


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18 64 FR 35732. 19 Id. 

Following this analysis, ODEQ 

examined sources within Oklahoma that 

were not already being controlled via 

BART or consent decrees or other 

regulatory mechanisms. See the TSD for 

a listing of the sources considered. In so 

doing, ODEQ analyzed the cost of 

compliance by weighing the cost of 

potential pollution control equipment 

versus the visibility benefit. Based on 

this analysis, ODEQ concluded that no 

additional controls were required. 

ODEQ reasoned that most of the largest 

sources of SO2 and NOX were already 

being controlled through BART, already 

had adequate controls in place, or were 

too far from the Wichita Mountains (too 

little visibility impact) to justify the cost 

of additional controls. 

3. Reasonable Progress Consultation 

ODEQ used CENRAP as its main 

vehicle for facilitating collaboration 

with FLMs and other states in 

developing its RH SIP. ODEQ was able 

to use CENRAP generated products, 

such as regional photochemical 

modeling results and visibility 

projections, and source apportionment 

modeling to assist in identifying 

neighboring states’ contributions to the 

visibility impairment at the Wichita 

Mountains. 

ODEQ invited those states projected 

through visibility modeling to 

contribute greater than 1 Mm¥1 of light 

extinction at the Wichita Mountains in 

2018 to consultations. ODEQ conducted 

four consultations. ODEQ directed its 

first consultation, to the tribal leaders in 

Oklahoma and their environmental 

managers, on 14 August 2007. ODEQ 

held the next three consultations as 

conference calls and invited CENRAP 

member clean air agencies, EPA, and the 

tribes to participate. 

ODEQ received responses from the 

Arkansas Department of Environmental 

Quality, the Iowa Department of Natural 

Resources, and the Missouri Department 

of Natural Resources. These states 

concluded that emissions from within 

their borders do not significantly impact 

visibility at the Wichita Mountains, and 

they did not offer any additional 

reductions from their anthropogenic 

sources. 

ODEQ has indicated and we agree that 

sources in Texas significantly affect the 

visibility at the Wichita Mountains. We 

note ODEQ communicated this to Texas 

in the correspondence included in 

Appendix 10–1, and Texas agreed with 

that assertion. However, ODEQ did not 

request any emission reductions from 

Texas. As a result of its correspondence 

with Texas, Texas agreed to provide 

ODEQ the opportunity to comment on 

Best Available Control Technology 

determinations for Prevention of 

Significant Deterioration sources that 

have significant impact on the Wichita 

Mountains. Specifically, ODEQ will be 

afforded the opportunity to review 

applications for sources if modeling 

predicts a five percent or higher impact 

on light extinction in a given year and 

provide comments to Texas during its 

public review and comment period. 

Texas also agreed to notify ODEQ 

whenever modeling indicates that a 

proposed source may significantly 

impact the Wichita Mountains. ODEQ 

also requested that Class I impact 

reviews be required for all proposed 

PSD sources within 300 kilometers of a 

Class I area. However, this request was 

not agreed to by Texas, who cited the 

need for EPA to adopt significant impact 

levels for Class I reviews so that there 

is a consistent approach to requiring 

Class I reviews. 

In establishing its RPG, ODEQ is 

required by 40 CFR 51.308(d)(1)(i)(B) to 

consider the emission reduction 

measures needed to achieve the URP for 

the period covered by this SIP. Our 1999 

RHR18 further illuminates this 

requirement: 

[T]he State must identify the amount 

of progress that would result if this 

uniform rate of progress were achieved 

during the period of the first regional 

haze implementation plan. 

[T]he State must identify and analyze 

the emissions measures that would be 

needed to achieve this amount of 

progress during the period covered by 

the first long-term strategy, and to 

determine whether those measures are 

reasonable based on the statutory 

factors. These factors are the costs of 

compliance with the measures, the time 

necessary for compliance with the 

measures, the energy and nonair quality 

environmental impacts of the 

compliance with the measures, and the 

remaining useful life of any existing 

source subject to the measures. In doing 

this analysis, the State must consult 

with other States which are anticipated 

to contribute to visibility impairment in 

the Class I area under consideration. 

Because haze is a regional problem, 

States are encouraged to work together 

to develop acceptable approaches for 

addressing visibility problems to which 

they jointly contribute. If a contributing 

State cannot agree with the State 

establishing the reasonable progress 

goal, the State setting the goal must 

describe the actions taken to resolve the 

disagreement. 

As further explained by the RHR,19

Oklahoma was under an additional 

obligation to consider these controls as 

part of its reasonable progress analysis 

requirement: 

If the State determines that the amount of 

progress identified through the analysis is 

reasonable based upon the statutory factors, 

the State should identify this amount of 

progress as its reasonable progress goal for 

the first long-term strategy, unless it 

determines that additional progress beyond 

this amount is also reasonable. If the State 

determines that additional progress is 

reasonable based on the statutory factors, the 

State should adopt that amount of progress 

as its goal for the first long-term strategy. 

We note that as part of its RH SIP 

submittal, Texas did consider the 

impact its sources have on the visibility 

of the Wichita Mountains. Therefore, we 

believe that to properly assess whether 

Oklahoma has satisfied the reasonable 

progress requirements of section 

51.308(d)(1), we must review and 

evaluate Texas’ submittal. We will do 

this in the course of processing the 

Texas RH SIP. 

D. Evaluation of Oklahoma’s BART 

Determinations 

Oklahoma’s submitted BART rule, 

OAC 252:100–8, Part 11, became 

effective on June 15, 2007. Definitions 

related to the BART rule were added in 

the Air Quality Rules general definitions 

section in OAC 252:100–8.1.1, and 

became effective as a permanent rule on 

June 15, 2006. These submitted rules 

also incorporate by reference 40 CFR 

part 51, appendix Y (our BART 

Guidelines). The rules further provide 

that the resulting source-specific 

requirements be incorporated into that 

source’s air quality permit. 

BART is an element of Oklahoma’s 

LTS for the first implementation period. 

As discussed in more detail in section 

IV.D. of this preamble, the BART 

evaluation process consists of three 

components: (1) An identification of all 

the BART-eligible sources, (2) an 

assessment of whether those BARTeligible sources are in fact subject to 

BART and (3) a determination of any 

BART controls. ODEQ addressed these 

steps as follows: 

1. Identification of BART-Eligible 

Sources 

The first step of a BART evaluation is 

to identify all the BART-eligible sources 

within the state’s boundaries. ODEQ 

identified the BART-eligible sources in 

Oklahoma by utilizing the three 

eligibility criteria in the BART 

Guidelines (70 FR 39158) and our 


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16178 Federal Register / Vol. 76, No. 55 / Tuesday, March 22, 2011 / Proposed Rules 

20ODEQ took the position, and we agree, that it 

is not practical at this time to control ammonia from 

these types of sources, for the purpose of improving 

visibility under the reasonable progress 

requirements of section 51.308(d)(1). 

21Note that our reference to CALPUFF 

encompasses the entire CALPUFF modeling system, 

which includes the CALMET, CALPUFF, and 

CALPOST models and other pre and post 

processors. The different versions of CALPUFF 

have corresponding versions of CALMET, 

CALPOST, etc. which may not be compatible with 

previous versions (e.g., the output from a newer 

version of CALMET may not be compatible with an 

older version of CALPUFF). The different versions 

of the CALPUFF modeling system are available 

from the model developer at http://www.src.com/ 

verio/download/download.htm. 

regulations (40 CFR 51.301): (1) One or 

more emission units at the facility fit 

within one of the 26 categories listed in 

the BART Guidelines; (2) the emission 

unit(s) was constructed on or after 

August 6, 1962, and was in existence 

prior to August 6, 1977; and (3) 

potential emissions of any visibilityimpairing pollutant from subject units 

are 250 tons or more per year. ODEQ 

initially screened its emissions 

inventory and permitting database to 

identify major facilities with emission 

units in one or more of the 26 BART 

categories. Following this, ODEQ used 

its databases and records to identify 

facilities in these source categories with 

potential emissions of 250 tons per year 

or more for any visibility-impairing 

pollutant from any unit that was in 

existence on August 7, 1977 and began 

operation after August 7, 1962. ODEQ 

contacted the sources, when necessary, 

to obtain or confirm this information. 

The BART Guidelines direct states to 

address SO2, NOX and direct PM 

(including both PM10 and PM2.5) 

emissions as visibility-impairment 

pollutants, and States must exercise 

their ‘‘best judgment to determine 

whether VOC or ammonia emissions 

from a source are likely to have an 

impact on visibility in an area.’’ See 70 

FR 39162. CENRAP modeling 

demonstrated that VOCs from 

anthropogenic sources are not 

significant visibility-impairing 

pollutants at the Wichita Mountains. 

Ammonia emissions in Oklahoma are 

primarily due to area sources, such as 

livestock and fertilizer application. 

Because these are not point sources, 

they are not subject to BART.20 ODEQ 

did consider ammonia from point 

sources. The emissions inventory 

prepared for the CENRAP modeling 

demonstrates that ammonia from point 

sources are not significant visibilityimpairing pollutants in Oklahoma. 

ODEQ further argued that because of the 

limiting role of NOX and SO2 on PM2.5

formation and the uncertainties in 

assessing the effect of an individual 

source’s ammonia emissions reductions 

on visibility, it did not consider 

ammonia among visibility-impairing 

pollutants. We have reviewed this 

information and propose to agree with 

this decision. 

Table 2 lists Oklahoma’s BARTeligible sources: 

TABLE 2: FACILITIES WITH BART-ELIGIBLE UNITS IN OKLAHOMA

BART source category Facility name County Number of 

units 

Fossil fuel-fired boilers of more than 250 MMBTU/hr 

heat input.

Georgia Pacific Consumer Products (formerly Fort 

James Operating) Muskogee Mill.

Muskogee .... 2 

Kraft pulp mill ................................................................. International Paper (formerly Weyerhaeuser) Valliant 

Paper Mill.

McCurtain .... 4 

Hydrofluoric, sulfuric, and nitric acid plants ................... Koch Nitrogen Enid Plant .............................................. Garfield ........ 7 

Terra International Oklahoma Woodward Complex ...... Woodward ... 11 

Terra Nitrogen Partnership Verdigris Plant ................... Rogers ........ 12 

Petroleum refineries ....................................................... Sinclair Oil Tulsa Refinery ............................................. Tulsa ........... 7 

Holly Refining and Marketing (formerly Sunoco) Tulsa 

Refinery.

Tulsa ........... 25 

Wynnewood Refining .................................................... Garvin .......... 14 

Valero Refinery (formerly TPI Petroleum Inc) Ardmore 

Refinery.

Carter .......... 24 

Portland cement plants .................................................. Lafarge Building Materials Tulsa Rogers City Line ...... Rogers ......... 10 

Fossil fuel-fired steam electric plants of more than 250 

MMBTU/hr heat input.

OG&E Horseshoe Lake Generating Station ................. Oklahoma .... 2 

OG&E Muskogee Generating Station ........................... Muskogee ... 2 

OG&E Seminole Generating Station ............................. Seminole ..... 3 

OG&E Sooner Generating Station ................................ Noble ........... 2 

PSO Comanche Power Station ..................................... Comanche ... 2 

PSO Northeastern Power Station ................................. Rogers ......... 3 

PSO Riverside Jenks Power Station ............................ Tulsa ........... 2 

PSO Southwestern Power Station ................................ Caddo ......... 1 

Western Farmers Electric Coop Anadarko Plant .......... Caddo ......... 3 

Western Farmers Electric Coop Mooreland Station ..... Woodward ... 3 

2. Identification of Sources Subject to 

BART 

The second step of the BART 

evaluation is to identify those BARTeligible sources that may reasonably be 

anticipated to cause or contribute to 

visibility impairment at any Class I area, 

i.e. those sources that are subject to 

BART. The BART Guidelines allow 

states to consider exempting some 

BART-eligible sources from further 

BART review because they may not 

reasonably be anticipated to cause or 

contribute to any visibility impairment 

in a Class I area. Consistent with the 

BART Guidelines, ODEQ required each 

of its BART-eligible sources to develop 

and submit dispersion modeling to 

assess the extent of their contribution to 

visibility impairment at surrounding 

Class I areas. 

a. Modeling Methodology 

The BART Guidelines provide that 

states may choose to use the 

CALPUFF 21 modeling system or 

another appropriate model to predict 

the visibility impacts from a single 

source on a Class I area and to therefore, 


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22CENRAP BART Modeling Guidelines, T. W. 

Tesche, D. E. McNally, and G. J. Schewe (Alpine 

Geophysics LLC), December 15, 2005, available at 

http://www.deq.state.ok.us/aqdnew/ 

RulesAndPlanning/Regional_Haze/SIP/ 

Appendices/index.htm. 

determine whether an individual source 

is anticipated to cause or contribute to 

impairment of visibility in Class I areas, 

i.e., ‘‘is subject to BART’’. The 

Guidelines state that we believe 

CALPUFF is the best regulatory 

modeling application currently 

available for predicting a single source’s 

contribution to visibility impairment (70 

FR 39162). ODEQ, in coordination with 

CENRAP, used the CALPUFF modeling 

system to determine whether individual 

sources in Oklahoma were subject to or 

exempt from BART. 

The BART Guidelines also 

recommend that states develop a 

modeling protocol for making 

individual source attributions, and 

suggest that states may want to consult 

with us and their RPO to address any 

issues prior to modeling. The CENRAP 

states, including Oklahoma, developed 

the ‘‘CENRAP BART Modeling 

Guidelines’’. 22 Stakeholders, including 

EPA, FLMs, industrial sources, trade 

groups, and other interested parties, 

actively participated in the development 

and review of the CENRAP protocol. 

CENRAP provided readily available 

modeling data bases for use by states to 

conduct their analyses. We note that the 

original meteorological databases 

generated by CENRAP did not include 

observations as EPA guidance indicates, 

therefore sources were evaluated using 

the 1st High values instead of the 8th 

High values. The use of the 1st High was 

agreed to by EPA, representatives of the 

Federal Land Managers, and CENRAP 

stakeholders. Some sources that did not 

screen out did later conduct refined 

CALPUFF modeling that incorporated 

meteorological data with observations 

and which allowed to them to compare 

8th High modeling values with the 0.5 

deciview threshold. We propose to find 

the chosen model and the general 

modeling methodology acceptable. 

However, we note a few additional 

deviations from modeling guidance that 

are discussed in the TSD and addressed 

in our remodeling of visibility impacts 

in support of the FIP for these six 

sources. 

b. Contribution Threshold 

For states using modeling to 

determine the applicability of BART to 

single sources, the BART Guidelines 

note that the first step is to set a 

contribution threshold to assess whether 

the impact of a single source is 

sufficient to cause or contribute to 

visibility impairment at a Class I area. 

The BART Guidelines state that, ‘‘[a] 

single source that is responsible for a 1.0 

deciview change or more should be 

considered to ‘cause’ visibility 

impairment.’’ 70 FR 39104, 39161. The 

BART Guidelines also state that ‘‘the 

appropriate threshold for determining 

whether a source contributes to 

visibility impairment’ may reasonably 

differ across states,’’ but, ‘‘[a]s a general 

matter, any threshold that you use for 

determining whether a source 

‘contributes’ to visibility impairment 

should not be higher than 0.5 

deciviews.’’ Id. Further, in setting a 

contribution threshold, states should 

‘‘consider the number of emissions 

sources affecting the Class I areas at 

issue and the magnitude of the 

individual sources’ impacts. The 

Guidelines affirm that states are free to 

use a lower threshold if they conclude 

that the location of a large number of 

BART-eligible sources in proximity of a 

Class I area justifies this approach. 

ODEQ used a contribution threshold of 

0.5 dv for determining which sources 

are subject to BART. There are a limited 

number of BART-eligible sources in 

close proximity to the State’s Class I 

area and surrounding Class I areas, and 

the results of the visibility impacts 

modeling demonstrated that the 

majority of the individual BART-eligible 

sources had visibility impacts well 

below 0.5 dv. We agree with the State’s 

rationale for choosing this threshold 

value. 

c. BART Sources Exempted Due to 

Permit Modifications 

When performing its initial BART 

screening modeling, ODEQ identified 

three sources with a contribution of 

greater than 0.5 deciviews in visibility 

impairment that desired to limit their 

emissions in order to avoid a BART 

determination. These sources were (1) 

the Georgia Pacific Consumer Products 

LP, Muskogee Mill; (2) the International 

Paper, Valliant Paper Mill; and (3) the 

Western Farmers Electric Coop, 

Anadarko Plant. An updated BART 

modeling analysis, assuming those 

controls were in place, demonstrated a 

contribution of less than 0.5 deciview of 

visibility impairment for each of these 

facilities. They are individually 

discussed below. ODEQ issued a Title V 

operating permit to each of the sources 

that imposed an emission limitation 

requiring the modeled controls. Since 

these three sources are voluntarily 

taking limits to avoid a full BART 

analysis, any future changes or 

relaxation of these limits at these 

specific BART-eligible units or in their 

permits that would allow for increases 

in SO2, NOX, or PM emissions would 

subject those sources to BART review, 

pursuant to the submitted ODEQ rules 

that we propose to approve as part of 

the Oklahoma RH SIP. 

i. Georgia Pacific Consumer Products 

LP, Muskogee Mill 

The Georgia Pacific, Muskogee Mill 

had two BART eligible boilers, Boiler B– 

1 and Boiler B–2. Georgia Pacific 

requested of ODEQ that an enforceable 

emission limit be imposed on Boiler B– 

1 to maintain emissions below the 

BART contribution threshold of 0.5 

deciviews. Where previously Boiler B– 

1 was permitted to burn either No. 2 

fuel oil or natural gas, Boiler B–1 is now 

restricted to burning natural gas, which 

will reduce its NOX emissions. ODEQ 

has determined that under the Title V 

operating permit modification, this 

facility will have a visibility impairment 

contribution of less than 0.5 deciviews 

at any Class I area, which is below the 

contribution threshold used by ODEQ in 

their BART analyses. This emission 

reduction is housed in a modification to 

the facility’s Oklahoma Department of 

Environmental Quality, Air Quality 

Division operating Permit, No. 99–113– 

TV (M–5), issued January 5, 2011. This 

permit requires that this fuel switch be 

operational no more than five years 

following our final action on the 

Oklahoma RH SIP. 

ii. International Paper, Valliant Paper 

Mill 

The International Paper, Valliant 

Paper Mill has three BART eligible 

boilers: EUG D1, Bark Boiler; EUG D2, 

Power Boiler; and EUG D3, Package 

Boiler. It also has a BART eligible Lime 

Kiln, EUG E7a. The Valiant Paper Mill 

has accepted limits on the sulfur 

content of fuel to the Bark and Power 

boilers in order to reduce its visibility 

impact. ODEQ has determined that 

under this Title V operating permit 

modification, this facility will have a 

visibility impairment contribution of 

less than 0.5 deciviews at any Class I 

area, which is below the contribution 

threshold used by ODEQ in their BART 

analyses. This emission reduction is 

housed in a modification to the facility’s 

Oklahoma Department of Environmental 

Quality, Air Quality Division operating 

Permit No. 97–057–TV (M–10), issued 

March 24, 2010. This permit requires 

these controls be operational no more 

than five years following our final 

action on the Oklahoma RH SIP. 

iii. Western Farmers Electric Coop, 

Anadarko Plant 

The Western Farmers Electric Coop 

(WFEC), Anadarko facility had three 


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23 70 FR 39164. 

BART eligible combine cycle gas 

turbines, AN–Unit 4, AN–Unit 5, and 

AN–Unit 6. WFEC agreed to NOX, SO2, 

and PM–10 emission limits on the 

combined cycle gas turbines in order to 

reduce their visibility impact. ODEQ has 

determined that under this Title V 

operating permit modification, this 

facility will have a visibility impairment 

contribution of less than 0.5 deciviews 

at any Class I area, which is below the 

contribution threshold used by ODEQ in 

their BART analyses. This emission 

reduction is housed in a modification to 

the facility’s Oklahoma Department of 

Environmental Quality, Air Quality 

Division operating Permit, No. 2005– 

037–TVR (M–1), issued July 9, 2010. 

This permit will require these controls 

be operational no more than five years 

following our final action on the 

Oklahoma RH SIP. 

d. Sources Identified by ODEQ as 

Subject to BART 

Following the elimination of those 

sources that were found to have 

visibility impacts below the 0.5 

deciview threshold, or the three 

discussed in the previous section that 

received Title V permits limiting their 

visibility impact below the 0.5 deciview 

threshold, ODEQ identified the sources 

contained in Table 3 as being subject to 

BART. 

TABLE 3—SOURCES IN OKLAHOMA SUBJECT TO BART 

Facility name BART emission units Source category Pollutants 

evaluated 

OG&E Seminole ....................... Units 1, 2, and 3 ..................... fossil fuel-fired steam electric plants ......................................... NOX

OG&E Sooner .......................... Units 1 and 2 ........................... fossil fuel-fired steam electric plants ......................................... SO2

NOX

PM10

OG&E Muskogee ..................... Units 4 and 5 ........................... fossil fuel-fired steam electric plants ......................................... SO2

NOX

PM10

AEP/PSO Comanche ............... Units 1 and 2 ........................... fossil fuel-fired steam electric plants ......................................... NOX

AEP/PSO Northeastern ............ Unit 2 ....................................... fossil fuel-fired steam electric plants ......................................... NOX

AEP/PSO Northeastern ............ Units 3 and 4 ........................... fossil fuel-fired steam electric plants ......................................... SO2

NOX

PM10

AEP/PSO Southwestern ........... Unit 3 ....................................... fossil fuel-fired steam electric plants ......................................... NOX

3. BART Determinations 

The third step of a BART evaluation 

is to perform the BART analysis. The 

BART Guidelines 23 describe the BART 

analysis as consisting of the following 

five basic steps: 

• Step 1: Identify All Available 

Retrofit Control Technologies, 

• Step 2: Eliminate Technically 

Infeasible Options, 

• Step 3: Evaluate Control 

Effectiveness of Remaining Control 

Technologies, 

• Step 4: Evaluate Impacts and 

Document the Results, and 

• Step 5: Evaluate Visibility Impacts. 

All of the sources that are subject to 

BART presented in Table 3 are fossil 

fuel fired electricity generating units. 

ODEQ performed BART determinations 

for all of these sources for NOX, SO2, 

and PM. For each BART determination, 

we find that ODEQ adequately 

considered Steps 1 through 5, above, 

except for the SO2 BART determinations 

for Units 4 and 5 of the OG&E Muskogee 

plant, Units 1 and 2 of the OG&E Sooner 

plant, and Units 3 and 4 of the AEP/PSO 

Northeastern plants. The SO2 BART 

determinations for these six units are 

the subject of our FIP and are treated 

separately in Section V.E. of this 

proposal. We agree with ODEQ’s BART 

determinations for all remaining cases 

and summarize them below. For more 

details, please see the TSD. 

a. OG&E Seminole Units 1, 2, and 3 

BART Determinations 

The OG&E Seminole Units 1, 2 and 3 

are BART-eligible sources. These units 

are gas fired boilers with gross outputs 

of 567 MW each. ODEQ considered all 

NOX control technologies, including 

combustion controls such as Low NOX

Burners (LNB) and Flue Gas 

Recirculation (FGR); and post 

combustion controls, such as Selective 

Catalytic Reduction (SCR), and Selective 

Noncatalytic Reduction (SNCR). ODEQ 

concluded that LNB/OFA +SCR, LNB/ 

OFA +FGR, and LNB/OFA were 

technically feasible. ODEQ then 

evaluated the economic, environmental, 

and energy impacts associated with the 

three proposed control options. This 

included CALPUFF visibility modeling, 

based on a modeling protocol we find 

acceptable. ODEQ determined that the 

installation of new LNB with OFA and 

FGR was cost effective, with a capital 

cost of $16,977,200 per unit for units 1 

and 2 and $9,468,600 for unit 3 and an 

average cost effectiveness of $1,554– 

$2,120 per ton of NOx removed for each 

unit over a twenty year operational life. 

ODEQ determined that NOX BART 

emission limits should be 30-day rolling 

averages of 0.203 lb/MMBtu for Unit 1, 

0.212 lb/MMBtu for Unit 2 and 0.164 lb/ 

MMBtu for Unit 3. The BART 

Guidelines do not specify a presumptive 

NOX BART limit for gas fired power 

plants. As Units 1, 2, and 3 are gas fired, 

ODEQ determined that SO2 and PM 

BART for them are no additional 

control. We propose to approve ODEQ’s 

determination of BART for the OG&E 

Seminole Units 1, 2, and 3. 

b. OG&E Sooner Units 1 and 2 BART 

Determinations 

The OG&E Sooner Units 1 and 2 are 

BART-eligible sources. Both units are 

coal fired with a gross output of 570 

MW. We evaluate ODEQ’s SO2 BART 

determinations for Units 1 and 2 in 

section V.E. Here we discuss our review 

of ODEQ’s NOX and PM BART 

determination for these units. 

ODEQ considered all NOx control 

technologies, including combustion 

controls such as LNB and FGR; and post 

combustion controls, such as SCR, and 

SNCR. ODEQ concluded that LNB/OFA 

+SCR, and LNB/OFA were technically 

feasible. ODEQ noted that FGR control 

systems have been used as a retrofit 

NOX control strategy on natural gasfired boilers, but have not generally 

been considered as a retrofit control 

technology on coal-fired units. ODEQ 

then evaluated the economic, 

environmental, and energy impacts 

associated with the two proposed 

control options. This included 

CALPUFF visibility modeling, based on 

a modeling protocol we find acceptable. 


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For Units 1 and 2, ODEQ determined 

the installation of new LNB with OFA 

was cost effective, with a capital cost of 

$14,055,900 per unit for units 1 and 2 

and an average cost effectiveness of 

$493–785 per ton of NOX removed for 

each unit over a twenty-five year 

operational life. ODEQ determined that 

NOX BART emission limits should be 

30-day rolling averages of 0.15 lbs/ 

MMBtu, which meets the BART 

presumptive limit. 

For PM, ODEQ noted there are two 

generally recognized PM control devices 

that are used to control PM emission 

from coal fired boilers, which are 

Electrostatic Precipators (ESPs) and 

fabric filters (or baghouses). Sooner 

Units 1 & 2 are currently equipped with 

ESP control systems. ODEQ determined 

that although fabric filters offer a slight 

improvement in PM control (99.7 versus 

99.3 percent control), their additional 

cost did not justify the modest 

improvement in PM control. ODEQ 

determined PM BART is the existing 

ESPs with an emission rate of 0.1 lbs/ 

MMBtu on a 3-hour average. ODEQ 

specified additional BART emission 

limitations in lbs/hour and tons/year. 

We propose to approve ODEQ’s PM and 

NOX BART determinations for the 

OG&E Sooner Units 1 and 2. 

c. OG&E Muskogee Units 4 and 5 BART 

Determinations 

The OG&E Muskogee Units 4 and 5 

are BART-eligible sources. Both units 

are coal fired with a gross output of 572 

MW. We evaluate ODEQ’s SO2 BART 

determinations for Units 4 and 5 in 

section V.E. Here we discuss our review 

of ODEQ’s NOX and PM BART 

determination for these units. 

ODEQ considered all NOX control 

technologies, including combustion 

controls such as LNB and FGR; and post 

combustion controls, such as SCR, and 

SNCR. ODEQ concluded that LNB/OFA 

+SCR, and LNB/OFA were technically 

feasible. ODEQ noted that FGR control 

systems have been used as a retrofit 

NOX control strategy on natural gasfired boilers, but have not generally 

been considered as a retrofit control 

technology on coal-fired units. ODEQ 

then evaluated the economic, 

environmental, and energy impacts 

associated with the two proposed 

control options. This included 

CALPUFF visibility modeling, based on 

a modeling protocol we find acceptable. 

For Units 4 and 5, ODEQ determined 

the installation of new LNB with OFA 

was cost effective, with a capital cost of 

$14,113,700 per unit for units 4 and 5 

and an average cost effectiveness of 

$260–$281 per ton of NOX removed for 

each unit over a twenty-five year 

operational life. ODEQ determined that 

NOX BART emission limits should be 

30-day rolling averages of 0.15 lbs/ 

MMBtu, which meets the BART 

presumptive limit. 

For PM, ODEQ noted there are two 

generally recognized PM control devices 

that are used to control PM emission 

from coal fired boilers, which are 

Electrostatic Precipators ESPs and fabric 

filters (or baghouses). Muskogee Units 4 

& 5 are currently equipped with ESP 

control systems. ODEQ determined that 

although fabric filters offer a slight 

improvement in PM control (99.7 versus 

99.3 percent control), their additional 

cost did not justify the modest 

improvement in PM control. ODEQ 

determined PM BART is the existing 

ESPs with an emission rate of 0.1 lbs/ 

MMBtu on a 3-hour average. ODEQ 

specified additional BART emission 

limitations in lbs/hour and tons/year. 

We propose to approve ODEQ’s PM and 

NOX BART determinations for the 

OG&E Muskogee Units 4 and 5. 

d. AEP/PSO Comanche Units 1 and 2 

BART Determinations 

The AEP/PSO Comanche Units 1 and 

2 are BART-eligible sources. These units 

are gas fired turbines with duct burners 

and heat recovery steam generators with 

a gross output of 94 MW each. 

For Units 1 and 2, ODEQ considered 

dry LNBs and SCR as being possibly 

applicable to gas fired turbines. ODEQ 

concluded that due to specific design 

considerations, only dry LNBs were 

technically feasible. ODEQ then 

evaluated the economic, environmental, 

and energy impacts associated with that 

proposed control option. This included 

CALPUFF visibility modeling, based on 

a modeling protocol we find acceptable. 

ODEQ determined that the installation 

of dry LNBs was cost effective, with a 

capital cost of $34,660,000 an average 

cost effectiveness of $2,600 per ton of 

NOX removed for each unit over a 

twenty year operational life. ODEQ 

determined that NOX BART emission 

limits should be 30-day rolling averages 

of 0.15 lbs/MMBtu. The BART 

Guidelines do not specify a presumptive 

NOX BART limit for gas fired power 

plants. As Units 1 and 2 are gas fired, 

ODEQ determined that SO2 and PM 

BART for them are no additional 

control. We propose to approve ODEQ’s 

determination of BART for the AEP/PSO 

Comanche Units 1 and 2. 

e. AEP/PSO Northeastern Unit 2, 3, and 

4 BART Determination 

The AEP/PSO Northeastern Units 2, 3, 

and 4 are BART-eligible sources. Unit 2 

is a gas fired boiler with a gross output 

of 495 MW. Units 3 and 4 are coal fired 

with gross outputs of 490 MW each. We 

evaluate ODEQ’s SO2 BART 

determinations for Units 3 and 4 in 

section V.E. Here we discuss our review 

of ODEQ’s NOX and PM BART 

determination for these units. 

For Unit 2, ODEQ considered all NOX

control technologies, including 

combustion controls such as LNB and 

FGR; and post combustion controls, 

such as SCR, and SNCR. ODEQ 

concluded that LNB/OFA +SCR, LNB/ 

OFA +FGR, and LNB/OFA were 

technically feasible. ODEQ then 

evaluated the economic, environmental, 

and energy impacts associated with the 

three proposed control options. This 

included CALPUFF visibility modeling, 

based on a modeling protocol we find 

acceptable. ODEQ determined that the 

installation of new LNB with OFA was 

cost effective, with a capital cost of 

$3,450,000 and an average cost 

effectiveness of $303 per ton of NOX

removed over a twenty year operational 

life. ODEQ determined that NOX BART 

emission limits should be 30-day rolling 

averages of 0.28 lbs/MMBtu. ODEQ 

specified additional BART emission 

limitations in lbs/hour and tons/year. 

The BART Guidelines do not specify a 

presumptive NOX BART limit for gas 

fired power plants. As Unit 2 is gas 

fired, ODEQ determined that SO2 and 

PM BART for it are no additional 

control. We propose to approve ODEQ’s 

determination of BART for the AEP/PSO 

Northeastern Unit 2. 

For Units 3 and 4, ODEQ considered 

all NOX control technologies, including 

combustion controls such as LNB and 

FGR; and post combustion controls, 

such as SCR, and SNCR. ODEQ 

concluded that LNB/OFA +SCR, LNB/ 

OFA, were technically feasible. ODEQ 

noted difficulties posed by the 

installation of SNCR on Units 3 and 4 

but did evaluate SNCR. ODEQ noted 

that FGR control systems have been 

used as a retrofit NOX control strategy 

on natural gas-fired boilers, but have not 

generally been considered as a retrofit 

control technology on coal-fired units. 

ODEQ then evaluated the economic, 

environmental, and energy impacts 

associated with the two proposed 

control options. This included 

CALPUFF visibility modeling, based on 

a modeling protocol we find acceptable. 

For Units 3 and 4, ODEQ determined 

the installation of new LNB with OFA 

was cost effective, with a capital cost of 

$17,000,000 and an average cost 

effectiveness of $313 per ton of NOX

removed over a twenty-five year 

operational life. ODEQ determined that 

NOX BART emission limits should be 

30-day rolling averages of 0.15 lbs/ 


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16182 Federal Register / Vol. 76, No. 55 / Tuesday, March 22, 2011 / Proposed Rules 

MMBtu, which meets the BART 

presumptive limit. 

For PM, ODEQ noted there are two 

generally recognized PM control devices 

that are used to control PM emission 

from coal fired boilers, which are ESPs 

and fabric filters (or baghouses). 

Northeastern Units 3 & 4 are currently 

equipped with ESP control systems. 

ODEQ determined that although fabric 

filters offer a slight improvement in PM 

control (99.7 versus 99.3 percent 

control), their additional cost did not 

justify the modest improvement in PM 

control. ODEQ determined PM BART is 

the existing ESPs with an emission rate 

of 0.1 lbs/MMBtu on a 3-hour average. 

ODEQ specified additional BART 

emission limitations in lbs/hour and 

tons/year. We propose to approve 

ODEQ’s determination of BART for the 

AEP/PSO Northeastern Units 3 and 4. 

f. AEP/PSO Southwestern Unit 3 BART 

Determination 

The AEP/PSO Southwestern Unit 3 is 

a BART-eligible source. This unit is a 

gas fired boiler with a gross output of 

332 MW. ODEQ considered all NOX

control technologies, including 

combustion controls such as LNB and 

FGR; and post combustion controls, 

such as SCR, and SNCR. ODEQ 

concluded that LNB/OFA +SCR, and 

LNB/OFA were technically feasible. 

ODEQ then evaluated the economic, 

environmental, and energy impacts 

associated with the three proposed 

control options. This included 

CALPUFF visibility modeling, based on 

a modeling protocol we find acceptable. 

ODEQ determined that the installation 

of new LNB with OFA was cost 

effective, with a capital cost of 

$3,000,000 and an average cost 

effectiveness of $947 per ton of NOX

removed over a twenty-year operational 

life. ODEQ determined that NOX BART 

emission limits should be 30-day rolling 

averages of 0.45 lbs/MMBtu on a 30-day 

average. ODEQ specified additional 

BART emission limitations in lbs/hour 

and tons/year. 

The BART Guidelines do not specify 

a presumptive NOX BART limit for gas 

fired power plants. However, due to the 

relatively high NOX emission rate that 

ODEQ determined was BART, and the 

fact that it appeared the annual average 

emissions rates recorded with the Clean 

Air Markets Division indicates that the 

boiler can currently comply with the 

standard on an annual average basis, we 

asked for additional information. ODEQ 

responded with data detailing 9 years of 

emissions versus load, that indicate that 

the boiler operates through a range 

where emissions can reach as much as 

1.4 lb/MMBtu at full load. This unit has 

historically operated as a ‘‘peaking unit’’ 

responding to increased demand for 

electricity. While technically feasible, 

LNB/OFA may not be as effective under 

all boiler operating conditions, 

especially during load changes and at 

low and high operating loads. After 

having examined the data, attached in 

our TSD, we accept ODEQ’s 

explanation. As Unit 3 is gas fired, 

ODEQ determined that SO2 and PM 

BART for it are no additional control. 

We propose to approve ODEQ’s 

determination of BART for the AEP/PSO 

Southwestern Unit 3. 

g. ODEQ BART Results and Summary 

We have reviewed ODEQ’s BART 

determinations for the sources listed in 

Table 3, above. We note that these 

BART determinations result in 

significant reductions in the amount of 

NOX that will be emitted by these 

sources, totaling 27,043 tons per year. 

This results in significant visibility 

benefits at the Wichita Mountains, 

Caney Creek, Upper Buffalo, and 

Hercules Glades Class I areas. 

Calculated as the 3-year average of the 

modeled visibility improvement at the 

98th percentile, these NOX BART 

reductions result in a visibility 

improvement of 5.46 dv at the Wichita 

Mountains, 2.65 deciviews at Caney 

Creek, 1.79 dv at the Upper Buffalo, and 

1.37 dv at Hercules Glades. This results 

in an 11.27 dv improvement over all 

these Class I areas. See the TSD for more 

details. 

Oklahoma’s BART rule requires each 

source subject to BART to install and 

operate BART no later than 5 years after 

we approve this RH SIP. OAC 252–100– 

8–75(e). Therefore, we believe this 

satisfies ODEQ’s obligation under 

section 51.308(e)(1)(iv), that ‘‘each 

source subject to BART be required to 

install and operate BART as 

expeditiously as practicable, but in no 

event later than 5 years after approval of 

the implementation plan revision.’’ 

For the reasons discussed above, we 

propose to find that with the exception 

of the SO2 BART determinations for 

Units 4 and 5 of the OG&E Muskogee 

plant, Units 1 and 2 of the OG&E Sooner 

plant, and Units 3 and 4 of the AEP/PSO 

Northeastern plants, ODEQ has satisfied 

the BART requirement of section 

51.308(e). 

E. Evaluation of ODEQ’s SO2 BART 

Determinations for the OG&E and AEP/ 

PSO Coal Fired Power Plant Units 

The discussion below is limited to the 

SO2 BART assessments for Units 4 and 

5 of the Oklahoma Gas and Electric 

Muskogee plant, Units 1 and 2 of the 

Oklahoma Gas and Electric Sooner plant 

(the ‘‘OG&E units’’), and Units 3 and 4 

of the American Electric Power/Public 

Service Company of Oklahoma 

Northeastern plant (the ‘‘AEP/PSO 

units’’). ODEQ’s other BART 

assessments are covered in Section V.D., 

above. 

In the Oklahoma RH SIP submittal, 

ODEQ concluded that dry flue gas 

desulfurization with spray dryer 

absorbers (‘‘dry scrubbers’’) and wet flue 

gas desulfurization (‘‘wet scrubbers’’) 

were not cost effective for these units. 

ODEQ came to this decision after 

comparing the cost effectiveness in 

annualized dollars per ton of SO2

removed ($/ton) to the visibility 

improvement at the nearest Class I 

areas. ODEQ determined that SO2 BART 

for these units was no control and 

specified an SO2 limit of 0.65 lbs/ 

MMBtu on a 30-day rolling average. The 

OG&E units currently burn a low sulfur 

coal from the Powder River Basin (PRB) 

of Wyoming, and already have historical 

annual emission rates significantly 

below this limit. Therefore, it is possible 

the OG&E units would be able to 

actually increase their emissions 

slightly, and still be in compliance with 

ODEQ’s SO2 BART assessment. The 

AEP/PSO units have historical annual 

emission rates that have been steadily 

decreasing to a point where the 

imposition of ODEQ’s proposed BART 

SO2 emission rate of 0.65 lbs/MMBtu 

would result in very little reduction in 

emissions. Below we discuss ODEQ’s 

BART evaluation and our assessment of 

that evaluation. 

1. Cost Effectiveness 

We propose to find that ODEQ 

properly identified these sources as 

BART eligible, in compliance with 

section 51.308(e)(1)(i). However, we 

propose to find that ODEQ did not 

properly follow the requirements of 

section 51.308(e)(1)(ii)(A) in 

determining BART. Specifically, we 

propose that ODEQ did not properly 

‘‘take into consideration the costs of 

compliance’’ when it relied on cost 

estimates that greatly overestimated the 

costs of dry and wet scrubbing to 

conclude these controls were not cost 

effective. Given that scrubbers are 

typically considered to be highly costeffective controls for power plants such 

as those at issue, we retained a 

consultant to independently assess the 

suitability and costs of installing these 

controls. We have thoroughly reviewed 

and evaluated the consultant’s report 

and agree with its findings regarding the 

cost-effectiveness of dry and wet 

scrubbing at the BART units. Our 


srobinson on DSKHWCL6B1PROD with PROPOSALS3
Federal Register / Vol. 76, No. 55 / Tuesday, March 22, 2011 / Proposed Rules 16183 

24 Dr. Phyllis Fox, Revised BART CostEffectiveness Analysis for Flue Gas Desulfurization 

at Coal-Fired Electric Generating Units in 

Oklahoma: Sooner Units 1 & 2 Muskogee Units 4 

& 5 Northeastern Units 3 & 4. Report Prepared for 

U.S. EPA, RTI Project Number 0209897.004.085. 

25ODEQ BART analyses housed in Appendix 6– 

4 of the OK RH SIP. 

26Sargent & Lundy, Sooner Units 1 & 2, Muskogee 

Units 4 & 5 Dry FGD BART Analysis Follow-Up 

Report, Prepared for Oklahoma Gas & Electric, 

December 28, 2009. 

Trinity Consultants, Best Available Retrofit 

Technology (BART) Determination, American 

Electric Power, Northeastern Power Plant, May 30, 

2008. 

27U.S. EPA, EPA Air Pollution Control Cost 

Manual, EPA/452/B–02–001, 6th Ed., January 2002. 

The EPA Air Pollution Control Cost Manual was 

formerly known as the OAQPS Control Cost 

Manual. 

28As stated in the BART guidelines, ‘‘[i]n order 

to maintain and improve consistency, cost estimates 

should be based on the OAQPS Control Cost 

Manual, where possible.’’ 70 FR 39104, 39166. 

consultant’s detailed report has been 

incorporated into the TSD.24

a. Dry Scrubbing Cost Analyses 

Table 4, below, summarizes and 

contrasts the cost effectiveness of dry 

scrubbers estimated by ODEQ 25 versus 

our estimate. Both ODEQ and we used 

BART evaluations performed by OG&E 

and AEP/PSO as the starting points for 

the assessments.26

TABLE 4—CONTRAST OF DRY SCRUBBER COST EFFECTIVENESS

Plant ODEQ projected cost 

($/ton SO2 removed) 

EPA’s projected cost 

($/ton SO2 removed) 

Sooner 1 .................................................................................................................................. $6,348 $1,291 

Sooner 2 .................................................................................................................................. 7,147 1,291 

Muskogee 4 ............................................................................................................................. 7,378 1,317 

Muskogee 5 ............................................................................................................................. 7,493 1,317 

Northeastern 3 ......................................................................................................................... 3,294 1,544 

Northeastern 4 ......................................................................................................................... 3,294 1,544 

Although our TSD provides a detailed 

comparison between the costing 

methodologies, a few general points can 

be made that explain why our costs 

differ with those from ODEQ. First, in 

the case of the OG&E analyses, a coal 

with a significantly higher sulfur 

content than is currently burned was 

assumed by OG&E’s contractor in 

determining the design of the scrubber. 

This increased the capital cost of the 

scrubber over what would minimally be 

needed to scrub the coal currently being 

burned. However, the increased tonnage 

of SO2 that would have been removed 

from the emissions resulting from the 

burning of that coal, and the high 

efficiency of the scrubber was not used 

in calculating the cost effectiveness ($/ 

ton). Our cost analysis, assumed the 

same higher sulfur coal, but adjusted the 

cost effectiveness to account for the 

increased scrubber efficiency and the 

increased tonnage of sulfur that would 

be removed. Second, the companies did 

not follow the Air Pollution Control 

Cost Manual 27 when possible, as 

specified in the BART guidelines.28 Our 

cost analysis does follow the Air 

Pollution Control Cost Manual. Third, 

some costs were significantly outside of 

the range of the actual costs. In our 

analysis these costs are adjusted 

accordingly. Fourth, the cost estimates 

contained double counting. In our 

analysis, the double counted costs are 

removed. Lastly, the cost estimates 

failed to evaluate the most cost effective 

options. Our analysis accounts for the 

more cost effective options and is 

referred to as ‘‘Option 1’’ in our 

consultant’s report. 

However, even though it appeared 

that costing the larger scrubber was 

OG&E’s preferred option, we did not 

wish to propose our decision solely on 

that basis. We also considered whether 

it would be cost effective to scrub the 

type of coal currently burned at the 

units. Therefore, we also analyzed the 

cost of a dry scrubber for the OG&E 

units, assuming the scrubber would be 

sized to scrub the coal being currently 

burned. This approach, referred to as 

‘‘Option 2’’ in our consultant’s report, is 

summarized in Table 5, below. The 

estimates in Table 5 are not refined 

estimates and did not consider all of the 

issues considered in option 1. 

TABLE 5—UNREFINED MINIMALLYSIZED OG&E DRY SCRUBBER COST

EFFECTIVENESS

Plant 

EPA’s Projected 

Cost 

(Unrefined) 

($/ton SO2

removed) 

Sooner 1 ......................... $4,594 

Sooner 2 ......................... 4,594 

Muskogee 4 .................... 5,102 

Muskogee 5 .................... 5,102 

We further refined the cost of the 

smaller scrubber to account for the 

issues discussed above that were 

rectified in Option 1: not following the 

Air Pollution Control Cost Manual, 

adjusting costs that were outside of the 

range of the actual costs, eliminating 

double counted costs, and failing to 

evaluate the most cost effective options. 

Additional details concerning this 

refinement are covered in our TSD. 

TABLE 6—REFINED MINIMALLY-SIZED

OG&E DRY SCRUBBER COST

EFFECTIVENESS

Plant 

EPA’s Projected 

Cost 

(Refined) 

($/ton SO2

removed) 

Sooner 1 ......................... $2,048 

Sooner 2 ......................... 2,048 

Muskogee 4 .................... 2,366 

Muskogee 5 .................... 2,366 

In contrasting the results displayed in 

Tables 4 and 6, we conclude that based 

on a controlled emission limit of 0.06 

lbs/MMBtu, a dry scrubber is cost 

effective at Units 4 and 5 of the OG&E 

Muskogee plant, Units 1 and 2 of the 

OG&E Sooner plant, and Units 3 and 4 

of the AEP/PSO Northeastern plant. In 

OG&E’s case, this is true regardless of 

whether the scrubber is sized to control 

the coal presently burned, or a 

significantly dirtier coal. Therefore, we 

propose to find that we cannot accept 

the cost estimates for dry scrubbers 

provided in the Oklahoma RH 

submission. 

b. Wet Scrubbing Cost Analyses 

Table 7, below summarizes and 

contrasts the cost effectiveness of wet 

scrubbers estimated by ODEQ versus 

our estimates: 


srobinson on DSKHWCL6B1PROD with PROPOSALS3
16184 Federal Register / Vol. 76, No. 55 / Tuesday, March 22, 2011 / Proposed Rules 

29Electric Power Research Institute (EPRI), A 

Review of Literature Related to the Use of Spray 

Dryer Absorber Material: Production, 

Characterization, Utilization Applications, Barriers, 

and Recommendations, December 6, 2006, Table 1– 

2. 

30These units are 620 MW pulverized coal fired 

boilers that burn similar low sulfur PRB coal (0.5– 

0.7 lb/MMBtu) that were placed into service in 1980 

and 1985, respectively. They were retrofitted with 

wet scrubbers in 2006 and 2007, respectively. 

31Throughout this document, any reference to 

‘‘ODEQ modeling’’ refers to modeling performed or 

reviewed by ODEQ. 

32CENRAP BART Modeling Guidelines, T. W. 

Tesche, D. E. McNally, and G. J. Schewe (Alpine 

Geophysics LLC), December 15, 2005, available at 

(http://www.deq.state.ok.us/aqdnew/ 

RulesAndPlanning/Regional_Haze/SIP/ 

Appendices/index.htm). 

TABLE 7—CONTRAST OF WET SCRUBBER COST EFFECTIVENESS

Plant ODEQ projected cost 

($/ton SO2 removed) 

EPA’s projected cost 

($/ton SO2 removed) 

Sooner 1 .................................................................................................................................. $6,998 $1,555 

Sooner 2 .................................................................................................................................. 7,827 1,555 

Muskogee 4 ............................................................................................................................. 8,724 1,417 

Muskogee 5 ............................................................................................................................. 8,852 1,417 

Northeastern 3 ......................................................................................................................... 3,625 1,699 

Northeastern 4 ......................................................................................................................... 3,625 1,699 

The ODEQ’s BART analyses 

eliminated wet scrubbing, in part, 

because the dollars per ton cost 

effectiveness was calculated to be higher 

than for dry scrubbing; the incremental 

cost to go from dry to wet scrubbing was 

judged unacceptable; and wet scrubbing 

was alleged to have certain adverse 

impacts that dry scrubbing did not have. 

ODEQ determined that wet scrubbing 

was not BART for SO2 for any of the 

subject units. This determination was 

based in part, on several alleged adverse 

collateral impacts including: (1) 

Increased sulfuric acid mist (SAM) in 

the flue gas; (2) excess particulate 

emitted due to the location of a scrubber 

downstream of the particulate control 

device; (3) the need for more reactant, 

which would generate more fugitive 

dust; (4) the need for significantly more 

water; (5) the generation of a wastewater 

stream that must be treated; and (6) the 

creation of a higher visibility 

impairment due to lower exit velocity, 

lower stack temperature, and higher 

SAM emissions. We have determined 

these claims are either wrong or 

overstated. Furthermore, we noted 

several benefits of wet scrubbing and 

some drawbacks to dry scrubbing, 

which were not evaluated by ODEQ. 

These issues are detailed in our 

consultant’s report. Please see the TSD 

for further discussion of our evaluation 

of ODEQ’s determination that wet 

scrubbing was not BART for SO2. 

Although OG&E’s contractor did not 

evaluate wet scrubbing in its final 

updated BART analyses, ODEQ 

modified an earlier OG&E wet scrubber 

cost estimate as the basis for estimating 

the cost of wet scrubbing. The total 

capital requirement for wet scrubbers 

was carried forward from the previous 

cost estimate. ODEQ then modified 

other costing parameters to be 

consistent with OG&E’s contractor’s 

current dry scrubber cost estimate. 

These modifications included the 

capital recovery factor, the annual 

operating costs, and administrative 

costs. AEP/PSO’s contractor did provide 

a wet scrubber cost analysis as part of 

its BART analyses, which was 

incorporated into ODEQ’s BART 

analysis. However, ODEQ’s wet 

scrubber BART analyses for the OG&E 

and AEP/PSO plants did not include the 

kind of detailed, line-by-line cost 

breakdown that is needed for a proper 

evaluation. 

We approached this problem by 

comparing the cost of wet to dry 

scrubbing for 13 cost effectiveness 

analyses (including the earlier OG&E 

analyses and the AEP/PSO analyses). 

The results of this analysis indicated 

that the average calculated cost 

effectiveness of a wet scrubber is 

typically about 9% higher than for a dry 

scrubber, except in those cases where an 

existing ESP can substitute for a new 

baghouse. Although that specific option 

was not evaluated or assumed in our 

cost analyses, we note that the OG&E 

and AEP/PSO units in question all have 

existing ESPs, and we expect they could 

be retained to reduce the cost. After 

increasing the cost of our calculated dry 

scrubbing estimate by 9%, we propose 

to find that the cost of wet scrubbing for 

the OG&E and AEP units fall within the 

range of values found to be cost effective 

in other similar wet scrubber cost 

determinations. As we stated in the 

BART Rule, ‘‘[a] reasonable range would 

be a range that is consistent with the 

range of cost effectiveness values used 

in other similar permit decisions over a 

period of time.’’ 70 FR 39104, 39168. 

Dry scrubbers are being successfully 

applied to many kinds of stationary 

sources worldwide, including many 

similar applications in the utility 

industry.29 As explained in the 

preamble to the BART Guidelines in 

explaining the decision to establish 

presumptive BART limits for SO2 based 

on the use of scrubbers, both wet and 

dry scrubbers are highly cost effective 

for power plants, with costs of $400 to 

$2000 per ton of SO2 removed typically. 

70 FR at 39132. Thus, dry scrubbing is 

clearly cost effective, barring an 

unusual, site specific condition. 

However, neither OG&E nor AEP/PSO 

identified any such conditions. 

Similarly, wet scrubbing has been 

employed in many coal fired power 

plants in the United States, and is in fact 

more widely used than dry scrubbing. 

This includes the Pleasant Prairie Units 

1 and 2 in Wisconsin, which are similar 

to the OG&E and AEP/PSO units in 

question.30 Therefore, because our cost 

effectiveness calculations for the BART 

units fall within the range for other 

similar scrubber installations, we 

propose to find that both dry and wet 

scrubbing are cost effective in terms of 

dollars per tons of SO2 removed. 

Consequently, we propose to disapprove 

ODEQ’s evaluation of the cost 

effectiveness of control. 

2. Visibility Benefit 

Having considered the cost 

effectiveness of wet and dry scrubbers 

for OG&E and AEP/PSO, we then 

considered the visibility improvement 

that would result from the installation 

of controls. As was done in assessing 

costs, OG&E and AEP assessed visibility 

on a facility basis. ODEQ 31 used the 

CALPUFF modeling system, which 

consists of a meteorological data preprocessor (CALMET), an air dispersion 

model (CALPUFF), and post-processor 

programs (POSTUTIL, CALSUM, 

CALPOST). The CALPUFF modeling 

system is the recommended model for 

conducting BART visibility analysis. 

The modeling analysis generally 

followed the BART protocol developed 

by CENRAP.32 In ODEQ’s modeling 

approach, CALPUFF visibility modeling 

for each pollutant was carried out 

separately so that only NOX emissions 

were modeled in support of the NOX


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Federal Register / Vol. 76, No. 55 / Tuesday, March 22, 2011 / Proposed Rules 16185 

33Memo from Joseph Paisie (Geographic 

Strategies Group, OAQPS) to Kay Prince (Branch 

Chief EPA Region 4) on Regional Haze Regulations 

and Guidelines for Best Available Retrofit 

Technology (BART) Determinations, July 19, 2006. 

34Electric Power Research Institute, Estimating 

Total Sulfuric Acid Emissions from Stationary 

Power Plants, 1016384, technical Update, March 

2008. 

BART determination or only SO2/H2SO4

emissions for SO2 BART 

determinations. Due to the nonlinear 

nature and complexity of atmospheric 

chemistry and chemical transformation 

among pollutants, CALPUFF modeling 

on a pollutant-specific basis is not 

recommended.33 Furthermore, this 

approach does not allow for predictions 

of total visibility impairment for 

different control scenarios at Class I area 

receptors and the determination of the 

98th percentile day for visibility 

impairment. In the case of NOX BART 

determinations for gas-fired units 

performed by ODEQ, modeling results 

from this approach are informative 

because SO2 and PM emissions are 

minimal. 

Although we generally regard the 

visibility modeling analyses performed 

by ODEQ in support of BART 

determinations to be of high quality, 

some deviations from our guidance and 

errors in emission calculations were 

noted. We performed our own modeling 

analysis of the three facilities, 

incorporating changes to meet our 

guidance and correct errors in emission 

calculations. We note that refined 

CALPUFF modeling included in 

ODEQ’s SIP used updated 

meteorological fields that included 

observations in accordance with EPA 

guidance (40 CFR Part 51, Appendix W) 

and we utilized this data in our own 

modeling analysis. In the ODEQ 

modeling, sulfuric acid emissions from 

the OG&E units were estimated based on 

an assumed 1% SO2 to SO3 conversion 

rate across the boiler. A control 

efficiency of 40% was assumed for the 

wet scrubbing control scenario and 90% 

for the dry scrubbing scenario. 

Emissions from the AEP/PSO units were 

calculated based on an assumed 3 ppm 

sulfur content conversion in the flue 

gas. As detailed in the TSD, we utilized 

a different approach based on the best 

current information from the Electric 

Power Research Institute (EPRI) 34 to 

estimate the sulfuric acid released from 

combustion in the boiler. ODEQ’s 

speciation of PM emissions, estimated 

for use in PM only modeling, contained 

errors in the parameters used in the 

calculation of speciation factors. As 

discussed in the above sections, we 

concluded that the dry scrubber and the 

wet scrubber could achieve emission 

limits of 0.06 lb/MMbtu SO2 and 0.04 

lb/MMbtu SO2, respectively, and these 

limits were used to calculate emissions 

for our visibility modeling. Our 

emission estimation methodology is 

detailed in the TSD. 

We remodeled the visibility impacts 

of the OG&E and AEP/PSO units to 

correct these errors and to provide 

consistency with modeling guidance we 

have provided to the states. First, the 

model was run using the pre-BART 

conditions to establish a baseline. For 

all modeling runs, all relevant visibilityimpairing pollutants were included. The 

model was then run to include the 

control technology selected as NOX

BART, LNB with OFA, in order to 

evaluate the visibility benefit expected 

from this control and separate the 

benefit of installation of NOX BART 

from that due to SO2 control 

technologies. Modeling results of the 

visibility impact due to installation of 

LNB show significant improvement in 

visibility over the baseline. These 

results in combination with review of 

the cost analysis and other factors 

considered in the ODEQ BART 

determination support the conclusion 

that LNB with OFA is NOX BART for 

these units. To evaluate the anticipated 

visibility improvement due to wet and 

dry scrubbers, these control 

technologies were modeled for each 

facility. These modeling control 

scenarios with scrubbers for SO2 also 

included NOX emissions controlled by 

LNB with OFA. The modeled visibility 

impacts were then compared to the 

impact achieved with only LNB with 

OFA and no additional controls on SO2

to evaluate the incremental visibility 

benefit of each SO2 control technology 

(wet or dry scrubber). 

The results of our visibility modeling 

analyses, for the maximum impacts of 

the 98th percentile delta-dv impacts 

from 2001–2003 are presented as Table 

8. These results employ our revised 

emission calculations and methodology, 

and the new IMPROVE equation 

(Method 8). As can be seen from these 

results, despite employing an SO2

emission limit of 0.04 lbs/MMBtu in the 

wet scrubber case (versus 0.06 lbs/ 

MMBtu in the dry scrubber case), the 

visibility modeling does not show a 

consistent, clear benefit for wet 

scrubbing. A possible explanation for 

this is that by reducing the SO2

emissions to the rate of 0.06 lb/MMbtu, 

the 98th percentile days are primarily 

winter days when nitrate particulates 

are responsible for the majority of 

visibility impairment. Additional 

controls of SO2 do not yield a reduction 

in sulfate large enough to provide 

significant visibility improvement for 

the 98th percentile value. In some cases, 

the further reduction in sulfate on these 

days results in a small increase in 

available ammonia for reaction with 

NOX and leads to a slight increase in 

visibility impairment due to additional 

nitrate particulate that can offset the 

benefit due to less sulfate particulate. 

TABLE 8—EPA MODELED MAXIMUM IMPACTS OF THE 98TH PERCENTILE DELTA-DV IMPACTS FROM 2001–2003 

Class I 

area 

Visibility impact (D dv) Improvement 

over baseline 

due to LNB 

Improvement 

over LNB 

due to DFGD 

Improvement 

over LNB 

Baseline LNB LNB & DFGD LNB & WFGD due to WFGD 

Sooner Units 1&2 

Caney Creek ................ 0.73 0.50 0.13 0.13 0.23 0.37 0.38 

Hercules-Glades .......... 0.71 0.43 0.13 0.12 0.28 0.30 0.31 

Upper Buffalo ............... 0.77 0.49 0.13 0.12 0.28 0.35 0.37 

Wichita Mountains ........ 2.08 1.46 0.41 0.35 0.62 1.05 1.11 

Total ...................... 4.28 2.88 0.80 0.71 1.41 2.08 2.16 

Muskogee Units 4&5 

Caney Creek ................ 1.48 1.19 0.45 0.51 0.29 0.74 0.69 

Hercules-Glades .......... 1.07 0.92 0.19 0.19 0.14 0.74 0.73 


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16186 Federal Register / Vol. 76, No. 55 / Tuesday, March 22, 2011 / Proposed Rules 

35These emission limits are a 30-day rolling 

average SO2 emission limit of 0.10 lbs/MMBtu. 

TABLE 8—EPA MODELED MAXIMUM IMPACTS OF THE 98TH PERCENTILE DELTA-DV IMPACTS FROM 2001–2003— 

Continued 

Class I 

area 

Visibility impact (D dv) Improvement 

over baseline 

due to LNB 

Improvement 

over LNB 

due to DFGD 

Improvement 

over LNB 

Baseline LNB LNB & DFGD LNB & WFGD due to WFGD 

Upper Buffalo ............... 1.52 1.20 0.37 0.33 0.31 0.84 0.87 

Wichita Mountains ........ 1.31 1.03 0.29 0.34 0.27 0.75 0.70 

Total ...................... 5.37 4.35 1.29 1.37 1.02 3.06 2.98 

Northeastern Units 3&4 

Caney Creek ................ 1.70 0.99 0.29 0.30 0.71 0.70 0.69 

Hercules-Glades .......... 0.92 0.88 0.18 0.20 0.04 0.70 0.68 

Upper Buffalo ............... 1.52 0.85 0.28 0.28 0.67 0.57 0.57 

Wichita Mountains ........ 1.66 1.39 0.30 0.31 0.27 1.09 1.08 

Total ...................... 5.80 4.11 1.05 1.09 1.69 3.06 3.02 

In Table 9, we extract the results of 

our visibility modeling from Table 8 for 

the dry scrubbing case, and total the 

results across the OG&E and AEP/PSO 

facilities, and across Class I areas. This 

is again based on the maximum impacts 

98th Percentile delta-dv impacts from 

2001–2003. 

TABLE 9—EPA MODELED MAXIMUM IMPACTS DUE TO DRY SCRUBBING OF THE 98TH PERCENTILE DELTA-DV IMPACTS

FROM 2001–2003 

Class I area 

Improvement over LNB + OFA due to dry scrubbing 

Sooner Muskogee Northeastern 

Total 

Sooner 

Muskogee 

Northeastern 

Caney Creek .................................................................................................... 0.37 0.74 0.70 1.81 

Hercules-Glades .............................................................................................. 0.30 0.74 0.70 1.74 

Upper Buffalo ................................................................................................... 0.35 0.84 0.57 1.76 

Wichita Mountains ........................................................................................... 1.05 0.75 1.09 2.89

Total All Class I Areas .............................................................................. 2.07 3.07 3.06 8.20 

The visibility improvements 

documented in Table 9 are significant 

and will result in marked steps toward 

reaching natural background conditions. 

3. Our Conclusion on Oklahoma’s SO2

BART Evaluations for the Six OG&E and 

AEP/PSO Units 

As discussed above, ODEQ concludes 

that it is too expensive to control the 

SO2 emissions from the OG&E and AEP/ 

PSO units in question and that the 

potential visibility benefits are not 

substantial enough to justify additional 

control. As we have shown above, we 

disagree with ODEQ’s conclusion on 

costs for SO2 controls and we find that 

cost effective SO2 controls are available 

and our modeling demonstrates that 

substantial visibility improvement is 

achievable based on the installation of 

these controls. In particular, our 

modeling indicates that dry scrubbing 

will result in a 2.89 deciview 

improvement in visibility at the Wichita 

Mountains. Furthermore, the addition of 

SO2 scrubbers (wet or dry) on each of 

the three facilities (2 units at each 

facility) will reduce visibility 

impairment at Class I areas (Wichita 

Mountains and/or other surrounding 

Class I areas) from values that are above 

the 1 deciview impact that is a direct 

causation of visibility impairment to 

levels that are below the 0.5 deciview 

threshold that ODEQ used for 

determining if a source contributed to 

visibility impairment. We consider the 

reduction in visibility impairment at 

Wichita Mountains, Caney Creek, Upper 

Buffalo, and Hercules-Glades to be 

significant both for the RH SIP and also 

for reduction of visibility impairment on 

other states in meeting the requirements 

of the 110 (a)(2)(D) SIP. Therefore, we 

propose to disapprove Oklahoma’s 

submitted SO2 BART determinations for 

the six BART sources in question. 

Consequently, we propose a FIP to 

address this deficiency. 

4. Alternative BART Determination 

The RH submittal includes an 

alternative to BART for the six BART 

sources entitled ‘‘Greater Reasonable 

Progress Alternative Determination’’ 

(Alternative Determination). This 

Alternative Determination submittal 

includes executed agreements between 

ODEQ and OG&E, and ODEQ and AEP/ 

PSO entitled, ‘‘OG&E Regional Haze 

Agreement, Case No. 10–024, and ‘‘PSO 

Regional Haze Agreement, Case No. 10– 

025.’’ The submitted Alternative 

Determination provides for alternative 

control scenarios that would apply were 

we to disapprove ODEQ’s SO2 BART 

determinations for the OG&E and AEP/ 

PSO units. Under the Alternative 

Determination, following the exhaustion 

of all administrative and judicial 

appeals of disapproval by us of the 

BART determinations for the six units, 

the BART determination would be 

superseded by a requirement that the 

OG&E and AEP/PSO units comply with 

either of the following requirements: 

By January 1, 2018, install dry scrubbers 

(and fabric filters for PM control at the OG&E 

units) or otherwise meet SO2 and PM 

emission limits specified by ODEQ.35


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Federal Register / Vol. 76, No. 55 / Tuesday, March 22, 2011 / Proposed Rules 16187 

36BART must be installed and operational as 

expeditiously as practicable, but in no event later 

than five years after approval of an implementation 

plan. CAA 169A(g)(4). 

By December 31, 2026, meet a combined 

annual SO2 emission limit that is equivalent 

to: (i) the SO2 emission limits specified by 

ODEQ on half of the OG&E units and half of 

the AEP/PSO units; and (ii) being at or below 

the SO2 emissions that would result from 

switching the remaining units to natural gas. 

In other words, after having exhausted 

any rights to challenge our disapproval 

of ODEQ’s BART determinations, OG&E 

and AEP/PSO could elect to either (1) 

install dry scrubbers at the beginning of 

2018; or (2) scrub half of their units 

(again at the higher rate) and switch the 

other half (not specified as to plant for 

OG&E) to natural gas by the end of 2026. 

We find that neither of these 

alternatives would comport with the 

requirements of section 51.308, as 

explained below. 

Our regulations do provide states with 

the flexibility to adopt alternatives to 

BART. Such alternatives, for example, 

could include fuel switching beyond the 

five-year window allowed for the 

installation of BART. Such alternatives, 

however, must be shown to provide for 

greater reasonable progress than BART 

does and must be fully implemented 

prior to the close of the planning period 

for the first regional haze SIP. 40 CFR 

51.308(e)(2)(i) and (iii). 

Even assuming that a contingent SIP 

provision triggered by the conclusion of 

all appeals regarding a related provision 

could be considered enforceable, we do 

not believe that the Alternative 

Determination is approvable. We 

propose to disapprove the Alternative 

Determination because neither of the set 

of contingent emission limitations meets 

the requirements of our RH regulations 

governing ‘‘better than BART’’ 

alternatives. As described above, ODEQ 

concluded that BART requires no 

additional controls at these units. The 

Alternative Determination would apply 

only where we have disagreed with this 

conclusion, disapproved the SIP, and 

prevailed in any ensuing litigation. It 

seems highly probable in such a 

situation that both the courts and we 

would have concluded that BART 

requires the use of scrubbers. Given this, 

the first potential requirement, that the 

BART units install scrubbers in January 

2018, does not provide for greater 

reasonable progress than does BART. 

Rather, it allows OG&E and AEP/PSO to 

delay the installation of scrubbers 

beyond the time period allowed by the 

CAA.36 In addition to the question of 

timing, the emission limits associated 

with the first potential requirement are 

substantially higher than what we have 

proposed as BART using the same 

controls, dry scrubbers. We have not 

seen any explanation from ODEQ as to 

how allowing OG&E and AEP/PSO 

additional time in which to meet less 

stringent emission limitations provides 

for greater reasonable progress. 

The second potential requirement 

does not require any reduction in 

emissions from the BART units until 

2026, near the end of the second longterm strategy period for RH. Again, we 

have seen no explanation of how such 

an extended compliance period would 

result in greater reasonable progress. 

More significantly, however, such an 

approach is not allowed by our 

regulations governing alternatives to 

BART, which require all necessary 

emission reductions to take place during 

the period of the first long-term strategy 

for RH, i.e. by 2018. 40 CFR 

51.308(e)(2)(iii). 

For the reasons discussed here, we 

propose to disapprove as part of the 

Oklahoma RH SIP, this submitted 

‘‘Alternative Determination.’’ If 

Oklahoma provides us with an 

alternative demonstration that complies 

with 40 CFR 51.308(e)(2)(i) and (iii), we 

will consider it under a future action. 

F. Federal Implementation Plan To 

Address SO2 BART for the Six Sources 

1. Introduction 

As discussed above, we propose to 

disapprove Oklahoma’s BART 

determination for the six sources in 

question. In addition, as discussed in 

Section VI, we have determined that 

additional controls are necessary on 

these units to prevent emissions from 

Oklahoma from interfering with other 

states’ plans to improve visibility, and 

we are partially disapproving the 

Oklahoma SIP as it pertains to that 

requirement. To correct the deficiencies 

identified in these proposed 

disapprovals, we are also proposing a 

FIP. 

In proposing a FIP to address BART, 

we must consider the same factors as 

states. As discussed above, we agree 

with ODEQ’s evaluation for pollutants 

other than SO2, but disagree for SO2 in 

two respects. First, we believe that dry 

scrubbing and wet scrubbing are both 

cost effective. Second, we have 

identified some concerns with ODEQ’s 

estimation of visibility impacts and 

accordingly have re-evaluated the 

visibility impacts of these controls. Our 

modeling shows that the use of these 

controls will result in greater 

improvement in visibility than 

estimated by ODEQ. 

We propose to find that both dry 

scrubbing and wet scrubbing provide 

cost effective reductions of SO2. We also 

believe that implementation of these 

controls will provide substantial 

visibility improvement at four Class I 

areas. 

2. Appropriate Emission Limits 

In our BART Guidelines, we 

established an SO2 presumptive limit 

that applies to Electricity Generating 

Units (EGUs) at power plants with a 

total generating capacity in excess of 

750 MW of either 0.15 lbs/MMBtu, or 

95% control. 70 FR 39104, 39131. We 

required that states, as a general matter, 

must require owners and operators of 

greater than 750 MW power plants to 

meet these BART emission limits. In 

addition, we noted that the presumption 

does not limit the states’ ability to 

consider whether a different level of 

control is appropriate in a particular 

case. We stated that ‘‘[i]f, upon 

examination of an individual EGU, a 

state determines that a different 

emission limit is appropriate based 

upon its analysis of the five factors, then 

the state may apply a more or less 

stringent limit.’’ Id. Because we are 

making the BART determinations under 

our FIP, we are obligated to determine 

the appropriate level of control. 

a. Dry Scrubber Emission Limit 

As is detailed in our TSD, dry 

scrubber performance varies with the 

sulfur content of the coal. Our analysis 

indicates that a dry scrubber on the 

OG&E units can remove approximately 

90% of the SO2 when burning coal with 

an uncontrolled emission rate of 

approximately 0.51 lb/MMBtu, 91.5% 

when burning coal corresponding to 

ODEQ’s proposed BART limit of 0.65 lb/ 

MMBtu, and 95% when burning the 

coal used to size the scrubber, 1.18 lb/ 

MMBtu. Similarly, our analysis 

indicates that a dry scrubber on the 

Northeastern units can remove 

approximately 93% of the SO2 when 

burning coal with an uncontrolled 

emission rate of 0.9 lb/MMBtu, and 

91.5% when burning coal 

corresponding to ODEQ’s proposed 

BART limit of 0.65 lb/MMBtu. This 

information is summarized in Table 10: 

TABLE 10—EXPECTED DRY SCRUBBER

PERFORMANCE VS. UNCONTROLLED

EMISSION RATES

Control 

(percent) 

Uncontrolled 

emission rate 

(lbs/MMBtu) 

Controlled 

emission rate 

(lbs/MMBtu) 

90.0 ........ 0.51 0.051 

91.5 ........ 0.65 0.055 

93.0 ........ 0.90 0.063 

95.0 ........ 1.18 0.059 


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16188 Federal Register / Vol. 76, No. 55 / Tuesday, March 22, 2011 / Proposed Rules 

37Sargent & Lundy, Flue Gas Desulfurization 

Technology, Dry Lime vs. Wet Limestone FGD, 

Prepared for National Lime Association, March 

2007. 

38Engineering and Economic Factors Affecting 

the Installation of Control Technologies for 

Multipollutant Strategies, EPA–600/R–02/073, 

October 2002, pdf pagination 5: ‘‘Conservatively 

high assumptions were made for the time, labor, 

reagents, and steel needed to install FGD systems. 

For LSFO installation timing, it is expected that one 

system requires about 27 months of total effort for 

planning, engineering, installation, and startup, 

with connections occurring during normally 

scheduled outages),’’ available at http:// 

www.epa.gov/clearskies/pdfs/multi102902.pdf. 

39We note that, as with the other fossil fuel fired 

power plant BART determinations contained within 

this proposal, separate NOx and PM BART 

determinations must also be made. 

Based on this information, our 

analysis indicates that an SO2 emission 

limit of 0.06 lbs/MMBtu can be met on 

the basis of a 30-day rolling average for 

the OG&E and AEP/PSO units, using dry 

scrubber technologies. As is noted in 

our TSD, there are already facilities 

operating below this emission rate, 

using dry scrubber technologies, and 

that burn similar coals. 

b. Wet Scrubber Emission Limit 

According to OG&E’s contractor, 

‘‘[w]et scrubbing is the predominant 

technology for large-scale utility 

applications in most parts of the world.’’ 

In addition, ‘‘SO2 removal guarantees of 

up to 99% (without additives) are 

available from the system suppliers and 

have been demonstrated in commercial 

applications, though there is a practical 

outlet limitation at 0.04 lb. SO2/MBtu, 

which represents a lower percentage 

removal for the lowest sulfur coals.’’ 37

However, as we note in our TSD, 

Pleasant Prairie Units 1 and 2, similar 

boilers that burn a similar low sulfur 

PRB coal, were retrofitted with wet 

scrubbers in 2006 and 2007. An 

examination of our Clean Air Markets 

Division SO2 emissions data for Unit 1 

for the period 2007 through June 2010 

indicates this unit easily meets a 365- 

day rolling average of less than 0.03 lb/ 

MMBtu. Similarly, the Minnesota Power 

Boswell 3 unit was recently retrofit with 

a wet scrubber (among other pollution 

control upgrades) and, based on our 

Clean Air Markets Division SO2

emissions data, it appears to be 

achieving a monthly average emission 

rate of less than 0.03 lbs/MMBtu. This, 

along with other similar examples 

discussed in our TSD, indicates that wet 

scrubbing at the OG&E and AEP/PSO 

units could consistently result in an SO2

removal efficiency of 98%, or meet an 

emission limit of 0.04 lbs/MMBtu on a 

30-day rolling average. 

3. Visibility Benefit From Dry and Wet 

Scrubbing 

As discussed in our evaluation of 

ODEQ’s BART evaluation, our modeling 

indicates substantial visibility benefit 

from the implementation of dry 

scrubbing. We did not find substantial 

additional visibility benefits on the 98th 

percentile value from the use of wet 

scrubbers even though we believe wet 

scrubbers would be expected to achieve 

lower emissions. As a result, we 

propose that the emission limit in the 

FIP be based on the emission levels that 

can be achieved by dry scrubbing. 

4. EPA’s SO2 BART Determination for 

the Six Units 

As described above, for the particular 

cases we are considering in this action, 

we have concluded there is a lack of a 

clear visibility advantage to wet 

scrubbing at the SO2 emission rates we 

have considered. Other details 

concerning the input values we have 

assumed in our visibility modeling are 

contained in the TSD. We invite 

comment on all aspects of our visibility 

modeling. Given that wet scrubbing is 

approximately 9% higher in cost on a 

$/tons of SO2 removed basis, we 

propose that SO2 BART for the Units 4 

and 5 of the OG&E Muskogee plant, 

Units 1 and 2 of the OG&E Sooner plant, 

and Units 3 and 4 of the AEP/PSO 

Northeastern plant should be based on 

dry scrubbing. We note there are 

significant advantages to wet scrubbing 

that OG&E and/or AEP/PSO may find 

attractive as a means of satisfying our 

proposed FIP. 

As we note above, under section 

51.308(e)(1)(iv), ‘‘each source subject to 

BART [is] required to install and operate 

BART as expeditiously as practicable, 

but in no event later than 5 years after 

approval of the implementation plan 

revision.’’ Based on the retrofit of other 

scrubber installations we have 

reviewed, we find that three (3) years 

from the date our final determination 

becomes effective is adequate time for 

the installation and operation of these 

controls.38 We solicit comments on 

alternative timeframes, of from two (2) 

years up to five (5) years from the 

effective date our final rule. 

We do not wish to dissuade 

companies from exercising the option of 

switching to natural gas as a means of 

satisfying their BART obligations under 

section 51.308(e). Such an approach, for 

example, would be acceptable for 

satisfying SO2 BART,39 if it satisfies the 

requirement under section 

51.308(e)(1)(iv) that, ‘‘each source 

subject to BART be required to install 

and operate BART as expeditiously as 

practicable, but in no event later than 5 

years after approval of the 

implementation plan revision.’’ 

Switching to natural gas would be an 

acceptable method of complying with 

the limits proposed in this FIP. In 

addition, we invite comments as to, 

considering the engineering and/or 

management challenges of such a fuel 

switch, whether the full 5 years allowed 

under section 308(e)(1)(iv) following our 

final action would be justified. 

G. Long-Term Strategy 

As described in section IV.E of this 

action, the LTS is a compilation of statespecific control measures relied on by 

the state for achieving its RPGs. 

Oklahoma’s LTS for the first 

implementation period addresses the 

emissions reductions from federal, state, 

and local controls that take effect in the 

state from the end of the baseline period 

starting in 2004 until 2018. The 

Oklahoma LTS was developed by 

ODEQ, in coordination with the 

CENRAP RPO, through an evaluation of 

the following components: (1) 

Construction of a CENRAP 2002 

baseline emission inventory; (2) 

construction of a CENRAP 2018 

emission inventory, including 

reductions from CENRAP member state 

controls required or expected under 

federal and state regulations, (including 

BART); (3) modeling to determine 

visibility improvement and apportion 

individual state contributions; (4) state 

consultation; and (5) application of the 

LTS factors. 

1. Emissions Inventory 

Section 51.308(d)(3)(iii) requires that 

Oklahoma document the technical basis, 

including modeling, monitoring and 

emissions information, on which it 

relied upon to determine its 

apportionment of emission reduction 

obligations necessary for achieving 

reasonable progress in each mandatory 

Class I Federal area it affects. Oklahoma 

must identify the baseline emissions 

inventory on which its strategies are 

based. Section 51.308(d)(3)(iv) requires 

that Oklahoma identify all 

anthropogenic sources of visibility 

impairment considered by the state in 

developing its long-term strategy. This 

includes major and minor stationary 

sources, mobile sources, and area 

sources. Oklahoma met these 

requirements by relying on technical 

analyses developed by its RPO, 

CENRAP and approved by all state 

participants, as described below. 

The emissions inventory used in the 

RH technical analyses was developed by 

CENRAP with assistance from 

Oklahoma. The 2018 emissions 


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40Note, our proposed FIP, discussed in section 

V.E, would require a stricter level of SO2 for six 

units in these facilities. 

41 Guidance on the Use of Models and Other 

Analyses for Demonstrating Attainment of Air 

Quality Goals for Ozone, PM2.5, and Regional Haze, 

(EPA–454/B–07–002), April 2007, located at 

http://www.epa.gov/scram001/guidance/guide/ 

final-03-pm-rh-guidance.pdf. Emissions Inventory 

Guidance for Implementation of Ozone and 

Particulate Matter National Ambient Air Quality 

Standards (NAAQS) and Regional Haze 

Regulations, August 2005, updated November 2005 

(‘‘our Modeling Guidance’’), located at http:// 

www.epa.gov/ttnchie1/eidocs/eiguid/index.html, 

EPA–454/R–05–001. 

inventory was developed by projecting 

2002 emissions and applying reductions 

expected from federal and state 

regulations affecting the emissions of 

the visibility-impairing pollutants NOX, 

PM, SO2,, and VOCs. 

a. Oklahoma’s 2002 Emission Inventory 

ODEQ and CENRAP developed an 

emission inventory for five inventory 

source classifications: Point, area, nonroad and on-road mobile sources, and 

biogenic sources for the baseline year of 

2002. Oklahoma’s 2002 emissions 

inventory is summarized in Table 11: 

TABLE 11—OKLAHOMA’S 2002 EMISSIONS INVENTORY

SO2 NH3 NOX VOCs PM10– 

PM2.5 PM2.5

Point ......................................................... 148,761 24,102 158,818 37,794 8,026 8,636 

Area .......................................................... 11,779 114,363 115,407 201,758 304,560 109,279 

Non-road mobile ...................................... 4,773 280 49,396 47,863 433 4,580 

On-road mobile ........................................ 4,708 4,434 142,592 99,924 879 2,459 

Biogenic ................................................... 0 0 35,909 988,314 0 0 

Total .................................................. 170,021 143,179 502,122 1,375,653 313,898 124,954 

See the TSD for details on how the 

2002 emissions inventory was 

constructed. We propose that 

Oklahoma’s 2002 emission inventory is 

acceptable. 

b. Oklahoma’s 2018 Emission Inventory 

In general, ODEQ used a combination 

of our Economic Growth Analysis 

System (EGAS 5), our mobile emissions 

factor model (MOBILE 6), our off-road 

emissions factor model (NONROAD), 

and the Integrated Planning Model 

(IPM) for electric generating units in 

constructing its 2018 emission 

inventory. ODEQ modified the projected 

emissions from the IPM modeling for 

OG&E Sooner and Muskogee electric 

power plants and the PSO Northeast 

electric power plants to reflect the 

application of presumptive BART 

controls.40 More specifically, CENRAP 

developed emissions for five inventory 

source classifications: point, area, nonroad and on-road mobile sources, and 

biogenic sources. CENRAP used its 2002 

emission inventory, described above, to 

estimate emissions in 2018. All control 

strategies expected to take effect prior to 

2018 are included in the projected 

emission inventory. Oklahoma’s 2018 

emissions inventory is summarized in 

Table 12: 

TABLE 12—OKLAHOMA’S 2018 EMISSIONS INVENTORY

SO2 NH3 NOX VOCs PM10– 

PM2.5 PM2.5

Point ......................................................... 106,701 35,215 140,298 125,648 8,935 13,989 

Area .......................................................... 12,374 141,532 128,257 400,056 275,844 127,018 

Non-road mobile ...................................... 156 40 25,387 28,489 2,914 292 

On-road mobile ........................................ 545 5,818 39,397 39,281 0 953 

Biogenic ................................................... 0 0 35,909 988,314 0 0 

Total .................................................. 119,776 182,605 369,248 1,581,788 287,693 142,252 

See the TSD for details on how the 

2018 emissions inventory was 

constructed. CENRAP and ODEQ used 

this and other state’s 2018 emission 

inventories to construct visibility 

projection modeling for 2018. We 

propose that Oklahoma’s 2018 emission 

inventory is acceptable but for its 

inclusion of reductions from the OG&E 

and AEP/PSO coal fired units that were 

not ultimately required by Oklahoma. 

As discussed above, we propose a FIP 

to address this deficiency. 

2. Visibility Projection Modeling 

CENRAP performed modeling for the 

RH LTS for its member states, including 

Oklahoma. The modeling analysis is a 

complex technical evaluation that began 

with selection of the modeling system. 

CENRAP used (1) the Mesoscale 

Meteorological Model (MM5) 

meteorological model, (2) the Sparse 

Matrix Operator Kernel Emissions 

(SMOKE) modeling system to generate 

hourly gridded speciated emission 

inputs, (3) the Community Multiscale 

Air Quality (CMAQ) photochemical grid 

model and (4) the Comprehensive Air 

Quality model with extensions (CAMx), 

as a secondary corroborative model. 

CAMx was also utilized with its 

Particulate Source Apportionment 

Technology (PSAT) tool to provide 

source apportionment for both the 

baseline and future case visibility 

modeling. 

The photochemical modeling of RH 

for the CENRAP states for 2002 and 

2018 was conducted on the 36-km 

resolution national regional planning 

organization domain that covered the 

continental United States, portions of 

Canada and Mexico, and portions of the 

Atlantic and Pacific Oceans along the 

east and west coasts. The CENRAP 

states’ modeling was developed 

consistent with our guidance.41

CENRAP examined the model 

performance of the regional modeling 

for the areas of interest before 

determining whether the CMAQ model 

results were suitable for use in the RH 


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42 64 FR 35735. 

assessment of the LTS and for use in the 

modeling assessment. The 2002 

modeling efforts were used to evaluate 

air quality/visibility modeling for a 

historical episode—in this case, for 

calendar year 2002—to demonstrate the 

suitability of the modeling systems for 

subsequent planning, sensitivity, and 

emissions control strategy modeling. 

Model performance evaluation is 

performed by comparing output from 

model simulations with ambient air 

quality data for the same time period to 

determine whether the model’s 

performance is sufficiently accurate to 

justify using the model for simulating 

future conditions. Once CENRAP 

determined the model performance to 

be acceptable, it used the model to 

determine the 2018 RPGs using the 

current and future year air quality 

modeling predictions, and compared the 

RPGs to the URP. Table 13, derived from 

Table VIII–9 of the Oklahoma RH SIP 

submittal, summarizes the projected 

contribution from Oklahoma emissions 

on visibility degradation at Class I areas 

for the 20 percent worst days in 2018. 

Note, this table only includes 

contributions of 0.15 deciviews or 

greater. 

TABLE 13—PROJECTED CONTRIBUTION FROM OKLAHOMA EMISSIONS ON VISIBILITY DEGRADATION FOR THE 20 PERCENT

WORST DAYS IN 2018 

Class I area State 

Contribution to 

light extinction 

(Mm-1) 

Total light 

extinction 

(Mm-1) 

Oklahoma 

contribution 

(percent) 

Deciview 

contribution 

Wichita Mountains ....................... Oklahoma .................................... 12.28 86 .56 14.19 1.53 

Hercules-Glades .......................... Missouri ....................................... 3.74 103 .49 3.61 0.37 

Salt Creek .................................... New Mexico ................................. 1.46 57 .67 2.53 0.26 

Caney Creek ................................ Arkansas ...................................... 2.23 96 .84 2.30 0.23 

Upper Buffalo ............................... Arkansas ...................................... 1.97 97 .16 2.03 0.21 

Guadalupe Mountains .................. Texas ........................................... 1.11 55 .43 2.00 0.20 

Seney ........................................... Michigan ...................................... 1.74 95 .27 1.83 0.18 

White Mountain ............................ New Mexico ................................. 0.69 40 .8 1.70 0.17 

Isle Royale ................................... Michigan ...................................... 1.08 73 .71 1.46 0.15 

3. Consultation and Emissions 

Reductions for Other States’ Class I 

Areas 

As in the development of Oklahoma’s 

reasonable progress goal for the Wichita 

Mountains, ODEQ used CENRAP as its 

main vehicle for facilitating 

collaboration with FLMs and other 

states in satisfying its LTS consultation 

requirement. This helped ODEQ and 

other state environmental agencies 

analyze emission apportionments at 

Class I areas and develop coordinated 

RH SIP strategies. 

Section 51.308(d)(3)(i) requires that 

Oklahoma consult with other states if its 

emissions are reasonably anticipated to 

contribute to visibility impairment at 

that state’s Class I area(s), and that 

Oklahoma consult with other states if 

their emissions are reasonably 

anticipated to contribute to visibility 

impairment at the Wichita Mountains. 

ODEQ’s consultations with other states 

are described in section V.C.3 above. 

After evaluating whether emissions 

from Oklahoma sources contribute to 

visibility impairment in other states’ 

Class I areas, ODEQ concluded there 

was no contribution sufficient to require 

consultation. ODEQ’s evaluation relied, 

however, upon SO2 BART reductions 

from the six units of the OG&E and 

AEP/PSO three coal fired power plants 

but these reductions are not required. 

Regardless of its conclusions regarding 

the impacts of Oklahoma emissions on 

other states’ Class I areas, however, 

Oklahoma did consult with other states 

and tribes, largely through the CENRAP 

process. We propose that those 

consultations adequately satisfy the 

requirement under Section 

51.308(d)(3)(i). 

Section 51.308(d)(3)(ii) requires that if 

Oklahoma emissions cause or contribute 

to impairment in another state’s Class I 

area, Oklahoma must demonstrate that it 

has included in its RH SIP all measures 

necessary to obtain its share of the 

emission reductions needed to meet the 

progress goal for that Class I area. 

Section 51.308(d)(3)(ii) also requires 

that since Oklahoma participated in a 

regional planning process, it must 

ensure it has included all measures 

needed to achieve its apportionment of 

emission reduction obligations agreed 

upon through that process. As we state 

in the RHR42, Oklahoma’s commitments 

to participate in CENRAP bind it to 

secure emission reductions agreed to as 

a result of that process, unless it 

proposes a separate process and 

performs its consultations on the basis 

of that process: 

While States are not bound by the 

results of a regional planning effort, nor 

can the content of their SIPs be dictated 

by a regional planning body, we expect 

that a coordinated regional effort will 

likely produce results the States will 

find beneficial in developing their 

regional haze implementation plans. 

Any State choosing not to follow the 

recommendations of a regional body 

would need to provide a specific 

technical basis that its strategy 

nonetheless provides for reasonable 

progress based on the statutory factors. 

At the same time, EPA cannot require 

States to participate in regional 

planning efforts if the State prefers to 

develop a long-term strategy on its own. 

We note that any State that acts alone 

in this regard must conduct the 

necessary technical support to justify 

their apportionment, which generally 

will require regional inventories and a 

regional modeling analysis. 

Additionally, any such State must 

consult with other States before 

submitting its long-term strategy to EPA. 

Consequently, because Oklahoma 

accepted and incorporated the CENRAPdeveloped visibility modeling into its 

RH SIP, which assumed controls for the 

six units discussed above that were not 

subsequently secured, we propose to 

disapprove Oklahoma’s long term 

strategy. 

However, our proposed FIP does 

include controls for the six units that at 

least achieve the level of control 

assumed in the CENRAP modeling. In 

addition, as described above, Oklahoma 

has required controls on additional 

sources as part of its BART evaluation. 

Therefore, we propose to find that with 

the addition of our proposed FIP, the 

requirements in section 51.308(d)(3)(ii) 

have been met. 

4. Mandatory Long Term Strategy 

Factors 

Section 51.308(d)(3)(v) requires that 

Oklahoma minimally consider certain 


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43Oklahoma’s Part 1 and Part II visibility SIP 

contained RAVI provisions and was previously 

approved by EPA (64 FR 60683). 

factors in developing its long-term 

strategy (the LTS factors). These 

include: (1) Emission reductions due to 

ongoing air pollution control programs, 

including measures to address RAVI; (2) 

measures to mitigate the impacts of 

construction activities; (3) emissions 

limitations and schedules for 

compliance to achieve the reasonable 

progress goal; (4) source retirement and 

replacement schedules; (5) smoke 

management techniques for agricultural 

and forestry management purposes 

including plans as currently exist 

within the state for these purposes; (6) 

enforceability of emissions limitations 

and control measures; and (7) the 

anticipated net effect on visibility due to 

projected changes in point, area, and 

mobile source emissions over the period 

addressed by the long-term strategy. For 

the reasons outlined below, we propose 

to find that Oklahoma has satisfied all 

the requirements of Section 

51.308(d)(3)(v). 

In addition to its BART 

determinations and by extension our 

proposed FIP, Oklahoma’s LTS 

incorporates emission reductions due to 

a number of ongoing air pollution 

control programs. This includes the 

issuance and enforcement of permits 

limiting emissions (based on our 

National Ambient Air Quality 

Standards) from all major sources in 

Oklahoma (the SIP also includes 

permits for minor sources), state rules 

which specifically limit targeted 

emissions sources and categories, and 

other air pollution control programs that 

ODEQ administers. We note that fine 

and coarse particulate, of which 

construction-related activities are 

thought to be a small contributor, are 

themselves minor contributors to 

visibility impairment at the Wichita 

Mountains. ODEQ relies on fugitive dust 

control rules to control and minimize 

dust from construction activities. ODEQ 

has adopted rules to ensure the 

enforceability of these emission 

limitations. This includes rules that 

govern ODEQ’s permitting process for 

major and minor sources, Prevention of 

Significant Deterioration (PSD) 

provisions, Best Available Control 

Technology (BACT), and BART 

requirements. These rules have 

corresponding compliance schedules 

and enforcement protocols and are 

summarized in the TSD. 

ODEQ issues permits to all major and 

minor point sources in Oklahoma, and 

each permit contains enforceable 

limitations on emissions of various 

pollutants, including those which cause 

or contribute to RH at the Wichita 

Mountains. Unless those permits specify 

a different schedule for compliance, 

ODEQ requires permitted sources to 

comply with their permits immediately 

upon issuance. ODEQ also enforces 

compliance schedules of relevant 

administrative and judicial orders, 

including consent decrees that result in 

significant SO2 and NOX reductions. 

We approved ODEQ’s SIP to address 

reasonably attributable visibility 

impairment at the Wichita Mountains 

on November 8, 1999. See 64 FR 60683. 

As we note in section V.H, the FLMs did 

not identify any integral vistas in 

Oklahoma. In addition, the Wichita 

Mountains is not experiencing RAVI, 

nor are any Oklahoma sources affected 

by the RAVI provisions. Therefore, the 

Oklahoma RH SIP does not incorporate 

any measures to specifically address 

RAVI. 

ODEQ considered source retirement 

and replacement schedules in 

developing its long-term strategy of 

emissions reductions. ODEQ stated it 

cannot reliably predict the retirement or 

replacement of sources and 

consequently does not rely on source 

retirement to achieve any reasonable 

progress goal. 

Fires are responsible for much of the 

directly emitted fine particulate matter 

in the Oklahoma emissions inventory. 

ODEQ considered smoke management 

techniques for the purposes of 

agricultural and forestry management in 

its LTS. As Tables IV–1 and IV–2 in the 

Oklahoma RH SIP revision submittal 

indicate, all types of fire sources 

(wildfire, agricultural burning, 

rangeland burning, etc.) are responsible 

for approximately 4.2% of the total SO2, 

4.1% of the total NH3, 3.9% of the total 

NOX, 2.1% of the total VOCs, and 3.6% 

of the total PM10 emissions. In contrast, 

fire is responsible for about 33.4% of the 

total PM2.5 emissions. However, Table 

VIII–3 of the Oklahoma RH SIP 

indicates that all Oklahoma area sources 

combined, of which fire is only a part, 

account for less than 1% of the total 

visibility impact at the Wichita 

Mountains. Nevertheless, ODEQ states 

that it and the Oklahoma Department of 

Agriculture, Food, and Forestry intend 

to create a basic, voluntary smoke 

management program based on our 

Interim Air Quality Policy on Wildland 

and Prescribed Fires. We commend this 

effort and offer our assistance in the 

development of this plan. 

Section 51.308(d)(3)(v)(F) requires 

that Oklahoma ensure the enforceability 

of emission limitations and control 

measures used to meet reasonable 

progress goals. ODEQ has issued 

enforceable Title V operating permits 

requiring BART-eligible sources subject 

to BART to install BART and achieve 

the associated BART emission limits. 

Similarly, any BART requirement in a 

FIP must be included by ODEQ in a Part 

70 air quality permit. See 70 FR at 

39172. 

ODEQ has demonstrated it has the 

statutory authority to regulate air 

emissions from all facilities and sources 

subject to operating permit requirements 

under Title V of the CAA. ODEQ also 

has the authority to administratively 

and judicially enforce any provision of 

an ODEQ issued air quality permits. See 

the TSD for more details on Oklahoma 

laws that provide for this authority. 

H. Coordination of RAVI and Regional 

Haze Requirements 

Our visibility regulations direct states 

to coordinate their RAVI LTS and 

monitoring provisions with those for 

RH, as explained in section IV, above. 

Under our RAVI regulations, the RAVI 

portion of a state SIP must address any 

integral vistas identified by the FLMs 

pursuant to 40 CFR 51.304. See 40 CFR 

51.302. An integral vista is defined in 40 

CFR 51.301 as a ‘‘view perceived from 

within the mandatory Class I Federal 

area of a specific landmark or panorama 

located outside the boundary of the 

mandatory Class I Federal area.’’ 

Visibility in any mandatory Class I 

Federal area includes any integral vista 

associated with that area. The FLMs did 

not identify any integral vistas in 

Oklahoma. In addition, the Wichita 

Mountains is not experiencing RAVI, 

nor are any Oklahoma sources affected 

by the RAVI provisions. Thus, the 

Oklahoma RH SIP submittal does not 

explicitly address the two requirements 

regarding coordination of RH with the 

RAVI LTS and monitoring provisions. 

However, Oklahoma previously made a 

commitment to address RAVI should 

the FLM certify visibility impairment 

from an individual source.43 We 

propose to find that this RH submittal 

appropriately supplements and 

augments Oklahoma’s RAVI visibility 

provisions to address RH by updating 

the monitoring and LTS provisions as 

summarized below in this section. 

I. Monitoring Strategy and Other SIP 

Requirements 

Section 51.308(d)(4) requires the SIP 

contain a monitoring strategy for 

measuring, characterizing, and reporting 

of RH visibility impairment that is 

representative of all mandatory Class I 

Federal areas within the state. This 

monitoring strategy must be coordinated 

with the monitoring strategy required in 

Section 51.305 for reasonably 


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attributable visibility impairment. As 

Section 51.308(d)(4) notes, compliance 

with this requirement may be met 

through participation in the IMPROVE 

network. Since the monitor at the 

Wichita Mountains is an IMPROVE 

monitor, we propose that ODEQ has 

satisfied this requirement. See the TSD 

for details concerning the IMPROVE 

network. 

Section 51.308(d)(4)(i) requires the 

establishment of any additional 

monitoring sites or equipment needed to 

assess whether reasonable progress 

goals to address RH for all mandatory 

Class I Federal areas within the state are 

being achieved. Shortly after the 

creation of CENRAP, its monitoring 

workgroup noted the lack of a 

representative monitor for the Wichita 

Mountains. At that time, an IMPROVE 

site for Upper Buffalo, Arkansas, in a 

wetter climate several hundred miles to 

the east-northeast, provided the closest 

available visibility monitoring data. 

Because this monitoring data was 

deemed unrepresentative, a particle 

sampler monitor was established at the 

Wichita Mountains and began operating 

in March, 2001. As described in section 

V.B., above, baseline visibility 

conditions were calculated using data 

representative of 2002–2004 due to lack 

of data from previous years. With the 

addition of the monitor at the Wichita 

Mountains, we propose to find that 

ODEQ has satisfied this requirement. 

Section 51.308(d)(4)(ii) requires that 

ODEQ establish procedures by which 

monitoring data and other information 

are used in determining the contribution 

of emissions from within Oklahoma to 

RH visibility impairment at mandatory 

Class I Federal areas both within and 

outside the state. The monitor at the 

Wichita Mountains is operated by 

Wichita Mountains personnel. The 

IMPROVE monitoring program is 

national in scope, and other states have 

similar monitoring and data reporting 

procedures, ensuring a consistent and 

robust monitoring data collection 

system. As section 51.308(d)(4) 

indicates, participation in the IMPROVE 

program constitutes compliance with 

this requirement. We therefore propose 

that ODEQ has satisfied this 

requirement. 

Section 51.308(d)(4)(iv) requires that 

the SIP must provide for the reporting 

of all visibility monitoring data to the 

Administrator at least annually for each 

mandatory Class I Federal area in the 

state. To the extent possible, Oklahoma 

should report visibility monitoring data 

electronically. Section 51.308(d)(4)(vi) 

also requires that ODEQ provide for 

other elements, including reporting, 

recordkeeping, and other measures, 

necessary to assess and report on 

visibility. We propose that Oklahoma’s 

participation in the IMPROVE network 

ensures the monitoring data is reported 

at least annually, is easily accessible, 

and therefore complies with this 

requirement. 

Section 51.308(d)(4)(iv) requires that 

ODEQ maintain a statewide inventory of 

emissions of pollutants that are 

reasonably anticipated to cause or 

contribute to visibility impairment in 

any mandatory Class I Federal area. The 

inventory must include emissions for a 

baseline year, emissions for the most 

recent year for which data are available, 

and estimates of future projected 

emissions. The state must also include 

a commitment to update the inventory 

periodically. Please refer to section V.G., 

above, where we discuss ODEQ’s 

emission inventory. ODEQ has stated 

that it intends to update the Oklahoma 

statewide emissions inventories 

periodically and review periodic 

emissions information from other states 

and future emissions projections. We 

propose that this satisfies the 

requirement. 

J. Federal Land Manager Coordination 

The Wichita Mountains is one of more 

than 546 refuges throughout the United 

States managed by the Fish and Wildlife 

Service, which is the Federal Land 

Manager (FLM) for this Class I area. 

Although the FLMs are very active in 

participating in the RPOs, the RH Rule 

grants the FLMs a special role in the 

review of the RH SIPs, summarized in 

section IV.H., above. We view both the 

FLMs and the state environmental 

agencies as our partners in the RH 

process. 

Section 51.308(i)(1) requires that by 

November 29, 1999, Oklahoma must 

have identified in writing to the FLMs 

the title of the official to which the FLM 

of the Wichita Mountains can submit 

any recommendations on the 

implementation of section 51.308. We 

acknowledge this section has been 

satisfied by all states via communication 

prior to this SIP. 

Under Section 51.308(i)(2), Oklahoma 

was obligated to provide the Fish and 

Wildlife Service with an opportunity for 

consultation, in person and at least 60 

days prior to holding a public hearing 

on it RH SIP. In practice, state 

environmental agencies have usually 

provided all FLMs—the Forest Service, 

the Park Service, and the Fish and 

Wildlife Service, copies of their RH SIP, 

as the FLMs collectively have reviewed 

these RH SIPs. ODEQ followed this 

practice and sent its draft of this 

implementation plan revision to the 

federal land manager staff on October 1, 

2009 and notified the federal land 

manager staff of the public hearing held 

on December 16, 2009. In its letter dated 

December 4, 2009, transmitting its 

comments, the Fish and Wildlife 

Service acknowledged having received 

Oklahoma’s draft RH SIP on October 5, 

2009. 

The FLMs have communicated to us 

their dissatisfaction with the fact that 

the draft RH SIP they were provided by 

ODEQ was markedly different than the 

version ODEQ submitted to us as their 

final RH SIP. Specifically, the FLMs 

note that in the version of the SIP they 

reviewed, SO2 BART for the six OG&E 

and AEP/PSO coal fired units that are 

the subject of our FIP was determined 

by ODEQ to be dry SO2 scrubbers with 

an emission limit of 0.10 lbs/MMBtu for 

the OG&E units, and 0.153 lbs/MMBtu 

for the AEP–PSO units. When ODEQ 

submitted their final RH SIP to us, those 

SO2 BART determinations were changed 

to replace the SO2 scrubber 

requirements with an SO2 limit of 0.65 

lbs/MMBtu on a 30 day rolling average 

that corresponds to uncontrolled low 

sulfur coal. We note the Fish and 

Wildlife Service has not requested that 

ODEQ re-open their 60 day comment 

period. We would like to address any 

question as to whether section 

51.308(i)(2) has been satisfied. We 

believe, however, that our proposed FIP, 

as described in section V.F., above, may 

alleviate these concerns. We invite the 

FLMs to provide comment on this or 

other aspects of our proposal. 

Section 51.308(i)(3) requires that 

ODEQ provide in its RH SIP a 

description of how it addressed any 

comments provided by the FLMs. ODEQ 

has provided that information in 

Appendix 10–2 of its RH SIP. 

Lastly, Section 51.308(i)(4) specifies 

the RH SIP must provide procedures for 

continuing consultation between the 

state and Federal Land Manager on the 

implementation of the visibility 

protection program required by section 

51.308, including development and 

review of implementation plan revisions 

and 5-year progress reports, and on the 

implementation of other programs 

having the potential to contribute to 

impairment of visibility in the 

mandatory Class I Federal areas. ODEQ 

has stipulated in its RH SIP it will 

continue to coordinate and consult with 

the FLMs as required by section 

51.308(i)(4). ODEQ states it intends to 

consult the FLMs in the development 

and review of implementation plan 

revisions; review of progress reports; 

and development and implementation 

of other programs that may contribute to 

impairment of visibility at the Wichita 

Mountains and other Class I areas. We 


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44See 40 CFR 51.308(b). 

propose that ODEQ has satisfied section 

51.308(i). 

K. Periodic SIP Revisions and Five-Year 

Progress Reports 

ODEQ affirmed its commitment to 

complete items required in the future 

under our RHR. ODEQ acknowledged its 

requirement under 40 CFR 51.308(f), to 

submit periodic progress reports and RH 

SIP revisions, with the first report due 

by July 31, 2018 and every ten years 

thereafter. 

ODEQ also acknowledged its 

requirement under 40 CFR 51.308(g), to 

submit a progress report in the form of 

a SIP revision every five years following 

this initial submittal of the Oklahoma 

RH SIP. The report will evaluate the 

progress made towards the RPGs for 

each mandatory Class I area located 

within Oklahoma and in each 

mandatory Class I area located outside 

Oklahoma which may be affected by 

emissions from within Oklahoma. 

If another state’s RH SIP identifies 

that Oklahoma’s SIP needs to be 

supplemented or modified, and if, after 

appropriate consultation Oklahoma 

agrees, today’s action may be revisited, 

or the additional information and/or 

changes will be addressed in the fiveyear progress report SIP revision. 

VI. Our Analysis of Oklahoma’s 

Interstate Visibility Transport SIP 

Provisions 

We received a SIP from Oklahoma to 

address the interstate transport 

requirements of CAA 110(a)(2)(D)(i) for 

the 1997 8-hour ozone and PM2.5

NAAQS on May 10, 2007, as 

supplemented on December 10, 2007. 

Concerning such CAA requirements 

preventing sources in the state from 

emitting pollutants in amounts which 

will interfere with efforts to protect 

visibility in other states, Oklahoma 

stated that it was on track for the 

submission of its RH SIP by the 

December, 17, 2007 deadline.44

Oklahoma states in its May 10, 2007 

submittal that it intended that its RH 

SIP be used to satisfy the requirements 

of section 110(a)(2)(D)(i)(II) that 

emissions from Oklahoma sources do 

not interfere with measures required in 

the SIP of any other state under part C 

of the CAA to protect visibility. 

However, it did not establish that 

emissions from its sources would not 

interfere with the visibility programs of 

other states, nor did it as part of its 

February 19, 2010 RH SIP submittal. In 

order to evaluate whether Oklahoma’s 

existing SIP adequately prevents 

interference with the visibility programs 

of other states, we propose to address 

this question using other available 

information. 

As an initial matter, we note that 

section 110(a)(2)(D)(i)(II) does not 

explicitly specify how we should 

ascertain whether a state’s SIP contains 

adequate provisions to prevent 

emissions from sources in that state 

from interfering with measures required 

in another state to protect visibility. 

Thus, the statute is ambiguous on its 

face, and we must interpret that 

provision. 

Our 2006 Guidance recommended 

that a state could meet the visibility 

prong of the transport requirements of 

section 110(a)(2)(D)(i)(II) of the CAA by 

submission of the RH SIP, due in 

December 2007. Our reasoning was that 

the development of the RH SIPs was 

intended to occur in a collaborative 

environment among the states. In fact, 

in developing their respective 

reasonable progress goals, CENRAP 

states consulted with each other through 

CENRAP’s work groups. As a result of 

this process, the common understanding 

was that each state would take action to 

achieve the emissions reductions relied 

upon by other states in their reasonable 

progress demonstrations under the RHR. 

CENRAP states consulted in the 

development of reasonable progress 

goals, using the products of this 

technical consultation process to codevelop their reasonable progress goals. 

In developing their visibility projections 

using photochemical grid modeling, 

CENRAP states assumed a certain level 

of emissions from sources within 

Oklahoma. As we discuss above in 

section V.G, this modeling assumed SO2

reductions from the six OG&E and AEP/ 

PSO coal fired units that are the subject 

of our FIP. Although we have not yet 

received all RH SIPs, we understand 

that the CENRAP states used the 

visibility projection modeling to 

establish their own respective 

reasonable progress goals. Thus, we 

believe that an implementation plan 

that provides for emissions reductions 

consistent with the assumptions used in 

those states’ modeling will ensure that 

emissions from Oklahoma sources do 

not interfere with the measures 

designed to protect visibility in other 

states. 

However, after the visibility 

projection modeling and all 

consultations were completed, 

Oklahoma revised its SO2 BART 

determinations for these six units, as 

submitted in the RH SIP submittal of 

February 19, 2010, removing the 

requirement that they be controlled to 

ensure these agreed upon emissions 

limits would be met. Consistent with 

our proposed conclusion that Oklahoma 

has not obtained its needed share of 

emission reductions, as we discuss 

above in section V.G.3, we propose to 

find that the Oklahoma SIP revision 

submittals do not ensure that emissions 

from sources in Oklahoma do not 

interfere with other State’s visibility 

programs as required by section 

110(a)(2)(D)(i)(II) of the CAA. 

Our proposed FIP does include 

controls for the six units that at least 

achieve the level of control assumed in 

the CENRAP modeling. In addition, as 

described in section V.D., above, 

Oklahoma has required controls on 

sources as part of its BART evaluation. 

Thus, we believe that the controls 

proposed under our FIP, plus the 

additional controls required by 

Oklahoma under its SIP that we propose 

to approve, constitute the assemblage of 

cost effective controls that are 

reasonable at this time, and serve to 

prevent sources in Oklahoma from 

emitting pollutants in amounts that will 

interfere with efforts to protect visibility 

in other states. In light of this, we 

propose to partially approve and 

partially disapprove the Oklahoma SIP 

revision submitted to address the 

requirements of section 

110(a)(2)(D)(i)(II) of the CAA. 

VII. Proposed Actions 

A. Regional Haze 

We propose to partially approve and 

partially disapprove Oklahoma’s RH SIP 

revision submitted on February 19, 

2010. Specifically, we propose to 

disapprove the SO2 BART 

determinations for Units 4 and 5 of the 

Oklahoma Gas and Electric Muskogee 

plant; Units 1 and 2 of the Oklahoma 

Gas and Electric Sooner plant; and Units 

3 and 4 of the American Electric Power/ 

Public Service Company of Oklahoma 

Northeastern plant. We propose to 

disapprove these SO2 BART 

determinations because they do not 

comply with our regulations under 40 

CFR 51.308(e). We are also proposing to 

disapprove Oklahoma’s long term 

strategy under section 51.308(d)(3) 

because it does not incorporate these 

emission reductions. ODEQ participated 

in the CENRAP visibility modeling 

development that assumed certain SO2

reductions from these six BART units. 

ODEQ also performed its consultations 

with other states with the understanding 

that these reductions would be secured. 

We propose a FIP to cure these defects 

in BART and the LTS. 

We propose to find that Units 4 and 

5 of the OG&E Muskogee plant, Units 1 

and 2 of the OG&E Sooner plant, and 

Units 3 and 4 of the AEP/PSO 


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Northeastern plant are subject to BART 

under 40 CFR 51.308(e). Further, we 

propose a FIP that specifically imposes 

SO2 BART on these six sources. We 

propose that SO2 BART for Units 4 and 

5 of the OG&E Muskogee plant, Units 1 

and 2 of the OG&E Sooner plant, and 

Units 3 and 4 of the AEP/PSO 

Northeastern plant is an SO2 emission 

limit of 0.06 lbs/MMBtu that applies 

singly to each of these units on a 30 day 

rolling average. Additionally, we 

propose monitoring, record-keeping, 

and reporting requirements to ensure 

compliance with these emission 

limitations. 

We propose that compliance with the 

emission limits be within three (3) years 

of the effective date of our final rule. We 

solicit comments on alternative 

timeframes, of from two (2) years up to 

five (5) years from the effective date of 

our final rule. 

Should OG&E and/or AEP/PSO elect 

to reconfigure the above units to burn 

natural gas, as a means of satisfying 

their BART obligations under section 

51.308(e), that conversion should be 

completed by the same time frame. We 

invite comments as to, considering the 

engineering and/or management 

challenges of such a fuel switch, 

whether the full 5 years allowed under 

section 308(e)(1)(iv) following the 

effective date of our final rule would be 

appropriate. 

We propose to disapprove section 

VI.E of the Oklahoma RH SIP entitled, 

‘‘Greater Reasonable Progress 

Alternative Determination.’’ We also 

propose to disapprove the separate 

executed agreements between ODEQ 

and OG&E, and ODEQ and AEP/PSO 

entitled ‘‘OG&E Regional Haze 

Agreement, Case No. 10–024,’’ and ‘‘PSO 

Regional Haze Agreement, Case No. 10– 

025,’’ housed within Appendix 6–5 of 

the RH SIP. We propose that these 

portions of the submittal are severable 

from the BART determinations and the 

LTS; therefore, no FIP is required. 

We are taking no action on whether 

Oklahoma has satisfied the reasonable 

progress requirements of section 

51.308(d)(1). 

We propose to approve all other 

portions of the Oklahoma RH SIP. We 

note that all controls required as part of 

Oklahoma’s BART determinations, not 

included as part of our proposed FIP, 

must be operational within five years 

from the effective date of our final rule. 

B. Interstate Transport of Visibility 

We are also proposing to partially 

approve and partially disapprove a 

portion of a SIP revision submitted by 

the State of Oklahoma for the purpose 

of addressing the ‘‘good neighbor’’ 

provisions of the CAA section 

110(a)(2)(D)(i) for the 1997 8-hour ozone 

NAAQS and the PM2.5 NAAQS. 

Specifically, we propose a partial 

approval and partial disapproval of the 

Oklahoma Interstate Transport SIP 

provisions that address the requirement 

of section 110(a)(2)(D)(i)(II) that 

emissions from Oklahoma sources do 

not interfere with measures required in 

the SIP of any other state under part C 

of the CAA to protect visibility. With 

regard to whether emissions from 

Oklahoma sources interfere with the 

visibility programs of other states, we 

are proposing to find that Oklahoma 

sources, except for Units 4 and 5 of the 

OG&E Muskogee plant, Units 1 and 2 of 

the OG&E Sooner plant, and Units 3 and 

4 of the AEP/PSO Northeastern plant, 

are sufficiently controlled to eliminate 

interference with the visibility programs 

of other states, and for the six units we 

are proposing specific SO2 emission 

limits that will eliminate such interstate 

interference. 

VIII. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review 

This proposed action is not a 

‘‘significant regulatory action’’ under the 

terms of Executive Order (EO) 12866 (58 

FR 51735, October 4, 1993), and is 

therefore not subject to review under the 

Executive Order. The proposed FIP 

applies to only three facilities and is not 

a rule of general applicability. 

B. Paperwork Reduction Act 

This proposed action does not impose 

an information collection burden under 

the provisions of the Paperwork 

Reduction Act, 44 U.S.C. 3501 et seq. 

Under the Paperwork Reduction Act, a 

‘‘collection of information’’ is defined as 

a requirement for ‘‘answers to * * * 

identical reporting or recordkeeping 

requirements imposed on ten or more 

persons * * *.’’ 44 U.S.C. 3502(3)(A). 

Because the proposed FIP applies to just 

three facilities, the Paperwork 

Reduction Act does not apply. See 5 

CFR 1320(c). 

Burden means the total time, effort, or 

financial resources expended by persons 

to generate, maintain, retain, or disclose 

or provide information to or for a 

Federal agency. This includes the time 

needed to review instructions; develop, 

acquire, install, and utilize technology 

and systems for the purposes of 

collecting, validating, and verifying 

information, processing and 

maintaining information, and disclosing 

and providing information; adjust the 

existing ways to comply with any 

previously applicable instructions and 

requirements; train personnel to be able 

to respond to a collection of 

information; search data sources; 

complete and review the collection of 

information; and transmit or otherwise 

disclose the information. 

An agency may not conduct or 

sponsor, and a person is not required to 

respond to a collection of information 

unless it displays a currently valid 

Office of Management and Budget 

(OMB) control number. The OMB 

control numbers for our regulations in 

40 CFR are listed in 40 CFR part 9. 

C. Regulatory Flexibility Act 

The Regulatory Flexibility Act (RFA) 

generally requires an agency to prepare 

a regulatory flexibility analysis of any 

rule subject to notice and comment 

rulemaking requirements under the 

Administrative Procedure Act or any 

other statute unless the agency certifies 

that the rule will not have a significant 

economic impact on a substantial 

number of small entities. Small entities 

include small businesses, small 

organizations, and small governmental 

jurisdictions. 

For purposes of assessing the impacts 

of today’s proposed rule on small 

entities, small entity is defined as: (1) A 

small business as defined by the Small 

Business Administration’s (SBA) 

regulations at 13 CFR 121.201; (2) a 

small governmental jurisdiction that is a 

government of a city, county, town, 

school district or special district with a 

population of less than 50,000; and (3) 

a small organization that is any not-forprofit enterprise which is independently 

owned and operated and is not 

dominant in its field. 

After considering the economic 

impacts of this proposed action on small 

entities, I certify that this proposed 

action will not have a significant 

economic impact on a substantial 

number of small entities. The FIP for the 

three Oklahoma facilities being 

proposed today does not impose any 

new requirements on small entities. The 

proposed partial approval of the SIP, if 

finalized, merely approves state law as 

meeting Federal requirements and 

imposes no additional requirements 

beyond those imposed by state law. See 

Mid-Tex Electric Cooperative, Inc. v. 

FERC, 773 F.2d 327 (D.C. Cir. 1985) 

D. Unfunded Mandates Reform Act 

(UMRA) 

Under sections 202 of the Unfunded 

Mandates Reform Act of 1995 

(‘‘Unfunded Mandates Act’’), signed into 

law on March 22, 1995, EPA must 

prepare a budgetary impact statement to 

accompany any proposed or final rule 


srobinson on DSKHWCL6B1PROD with PROPOSALS3
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that includes a Federal mandate that 

may result in estimated costs to State, 

local, or tribal governments in the 

aggregate; or to the private sector, of 

$100 million or more (adjusted to 

inflation). Under section 205, EPA must 

select the most cost-effective and least 

burdensome alternative that achieves 

the objectives of the rule and is 

consistent with statutory requirements. 

Section 203 requires EPA to establish a 

plan for informing and advising any 

small governments that may be 

significantly or uniquely impacted by 

the rule. 

EPA has determined that the approval 

action proposed does not include a 

Federal mandate that may result in 

estimated costs of $100 million or more 

to either State, local, or tribal 

governments in the aggregate, or to the 

private sector. This Federal action 

proposes to approve pre-existing 

requirements under State or local law, 

and imposes no new requirements. 

Accordingly, no additional costs to 

State, local, or tribal governments, or to 

the private sector, result from this 

action. 

E. Executive Order 13132: Federalism 

Federalism (64 FR 43255, August 10, 

1999) revokes and replaces Executive 

Orders 12612 (Federalism) and 12875 

(Enhancing the Intergovernmental 

Partnership). Executive Order 13132 

requires EPA to develop an accountable 

process to ensure ‘‘meaningful and 

timely input by State and local officials 

in the development of regulatory 

policies that have federalism 

implications.’’ ‘‘Policies that have 

federalism implications’’ is defined in 

the Executive Order to include 

regulations that have ‘‘substantial direct 

effects on the States, on the relationship 

between the national government and 

the States, or on the distribution of 

power and responsibilities among the 

various levels of government.’’ Under 

Executive Order 13132, EPA may not 

issue a regulation that has federalism 

implications, that imposes substantial 

direct compliance costs, and that is not 

required by statute, unless the Federal 

government provides the funds 

necessary to pay the direct compliance 

costs incurred by State and local 

governments, or EPA consults with 

State and local officials early in the 

process of developing the proposed 

regulation. EPA also may not issue a 

regulation that has federalism 

implications and that preempts State 

law unless the Agency consults with 

State and local officials early in the 

process of developing the proposed 

regulation. 

This rule will not have substantial 

direct effects on the States, on the 

relationship between the national 

government and the States, or on the 

distribution of power and 

responsibilities among the various 

levels of government, as specified in 

Executive Order 13132, because it 

merely addresses the State not fully 

meeting its obligation to prohibit 

emissions from interfering with other 

states measures to protect visibility 

established in the CAA. Thus, Executive 

Order 13132 does not apply to this 

action. In the spirit of Executive Order 

13132, and consistent with EPA policy 

to promote communications between 

EPA and State and local governments, 

EPA specifically solicits comment on 

this proposed rule from State and local 

officials. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

Executive Order 13175, entitled 

Consultation and Coordination with 

Indian Tribal Governments (65 FR 

67249, November 9, 2000), requires EPA 

to develop an accountable process to 

ensure ‘‘meaningful and timely input by 

tribal officials in the development of 

regulatory policies that have tribal 

implications.’’ This proposed rule does 

not have tribal implications, as specified 

in Executive Order 13175. It will not 

have substantial direct effects on tribal 

governments. Thus, Executive Order 

13175 does not apply to this rule. EPA 

specifically solicits additional comment 

on this proposed rule from tribal 

officials. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

Executive Order 13045: Protection of 

Children from Environmental Health 

Risks and Safety Risks (62 FR 19885, 

April 23, 1997), applies to any rule that: 

(1) is determined to be economically 

significant as defined under Executive 

Order 12866; and (2) concerns an 

environmental health or safety risk that 

we have reason to believe may have a 

disproportionate effect on children. If 

the regulatory action meets both criteria, 

the Agency must evaluate the 

environmental health or safety effects of 

the planned rule on children, and 

explain why the planned regulation is 

preferable to other potentially effective 

and reasonably feasible alternatives 

considered by the Agency. However, to 

the extent this proposed rule will limit 

emissions of SO2, the rule will have a 

beneficial effect on children’s health by 

reducing air pollution. 

This rule is not subject to Executive 

Order 13045 because it does not involve 

decisions intended to mitigate 

environmental health or safety risks. 

However, to the extent this proposed 

rule will limit emissions of SO2, the rule 

will have a beneficial effect on 

children’s health by reducing air 

pollution. 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This action is not subject to Executive 

Order 13211 (66 FR 28355 (May 22, 

2001)), because it is not a significant 

regulatory action under Executive Order 

12866. 

I. National Technology Transfer and 

Advancement Act 

Section 12 of the National Technology 

Transfer and Advancement Act 

(NTTAA) of 1995 requires Federal 

agencies to evaluate existing technical 

standards when developing a new 

regulation. To comply with NTTAA, 

EPA must consider and use ‘‘voluntary 

consensus standards’’ (VCS) if available 

and applicable when developing 

programs and policies unless doing so 

would be inconsistent with applicable 

law or otherwise impractical. 

The EPA believes that VCS are 

inapplicable to this action. Today’s 

action does not require the public to 

perform activities conducive to the use 

of VCS. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order 12898 (59 FR 7629, 

February 16, 1994), establishes federal 

executive policy on environmental 

justice. Its main provision directs 

federal agencies, to the greatest extent 

practicable and permitted by law, to 

make environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority 

populations and low-income 

populations in the United States. 

We have determined that this 

proposed rule, if finalized, will not have 

disproportionately high and adverse 

human health or environmental effects 

on minority or low-income populations 

because it increases the level of 

environmental protection for all affected 

populations without having any 

disproportionately high and adverse 

human health or environmental effects 

on any population, including any 


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minority or low-income population. 

This proposed rule limits emissions of 

SO2 from three facilities in Oklahoma. 

The partial approval of the SIP, if 

finalized, merely approves state law as 

meeting Federal requirements and 

imposes no additional requirements 

beyond those imposed by state law. 

List of Subjects in 40 CFR Part 52 

Environmental protection, Air 

pollution control, Intergovernmental 

relations, Nitrogen dioxide, Ozone, 

Particulate matter, Reporting and 

recordkeeping requirements, Sulfur 

dioxides, Visibility, Interstate transport 

of pollution, Regional haze, Best 

available control technology. 

Dated: March 4, 2011. 

Al Armendariz, 

Regional Administrator, Region 6. 

Title 40, chapter I, of the Code of 

Federal Regulations is proposed to be 

amended as follows: 

PART 52—[AMENDED] 

1. The authority citation for part 52 

continues to read as follows: 

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

2. Part 52 is proposed to be amended 

by adding § 52.1923 to read as follows: 

§ 52.1923 Interstate pollutant transport 

provisions; What are the FIP requirements 

for Units 4 and 5 of the Oklahoma Gas and 

Electric Muskogee plant; Units 1 and 2 of 

the Oklahoma Gas and Electric Sooner 

plant; and Units 3 and 4 of the American 

Electric Power/Public Service Company of 

Oklahoma Northeastern plant affecting 

visibility? 

(a) Applicability. The provisions of 

this section shall apply to each owner 

or operator, or successive owners or 

operators, of the coal burning 

equipment designated as: Units 4 or 5 of 

the Oklahoma Gas and Electric 

Muskogee plant; Units 1 or 2 of the 

Oklahoma Gas and Electric Sooner 

plant; and Units 3 or 4 of the American 

Electric Power/Public Service Company 

of Oklahoma Northeastern plant. 

(b) Compliance Dates. Compliance 

with the requirements of this section is 

required within 3 years of the effective 

date of this rule unless otherwise 

indicated by compliance dates 

contained in specific provisions. 

(c) Definitions. All terms used in this 

part but not defined herein shall have 

the meaning given them in the Clean Air 

Act and in parts 51 and 60 of this title. 

For the purposes of this section: 

24-hour period means the period of 

time between 12:01 a.m. and 12 

midnight. Air pollution control 

equipment includes selective catalytic 

control units, baghouses, particulate or 

gaseous scrubbers, and any other 

apparatus utilized to control emissions 

of regulated air contaminants which 

would be emitted to the atmosphere. 

Daily average means the arithmetic 

average of the hourly values measured 

in a 24-hour period. 

Heat input means heat derived from 

combustion of fuel in a unit and does 

not include the heat input from 

preheated combustion air, recirculated 

flue gases, or exhaust gases from other 

sources. Heat input shall be calculated 

in accordance with 40 CFR part 75. 

Owner or Operator means any person 

who owns, leases, operates, controls, or 

supervises any of the coal burning 

equipment designated as: 

(i) Unit 4 of the Oklahoma Gas and 

Electric Muskogee plant; or 

(ii) Unit 5 of the Oklahoma Gas and 

Electric Muskogee plant; or 

(ii) Unit 1 of the Oklahoma Gas and 

Electric Sooner plant; or 

(iv) Unit 2 of the Oklahoma Gas and 

Electric Sooner plant; or 

(v) Unit 3 of the American Electric 

Power/Public Service Company of 

Oklahoma Northeastern plant; or 

(vi) Unit 4 of the American Electric 

Power/Public Service Company of 

Oklahoma Northeastern plant. 

Regional Administrator means the 

Regional Administrator of EPA Region 6 

or his/her authorized representative. 

Unit means one of the coal fired 

boilers covered under paragraph (a) of 

this section. 

(d) Emissions Limitations. SO2

emission limit. The individual sulfur 

dioxide emission limit for a unit shall 

be 0.06 pounds per million British 

thermal units (lb/MMBtu) as averaged 

over a rolling 30 calendar day period. 

For each unit, SO2 emissions for each 

calendar day shall be determined by 

summing the hourly emissions 

measured in pounds of SO2. For each 

unit, heat input for each calendar day 

shall be determined by adding together 

all hourly heat inputs, in millions of 

BTU. Each day the thirty-day rolling 

average for a unit shall be determined 

by adding together the pounds of SO2

from that day and the preceding 29 days 

and dividing the total pounds of SO2 by 

the sum of the heat input during the 

same 30-day period. The result shall be 

the 30-day rolling average in terms of lb/ 

MMBtu emissions of SO2. If a valid SO2

pounds per hour or heat input is not 

available for any hour for a unit, that 

heat input and SO2 pounds per hour 

shall not be used in the calculation of 

the 30-day rolling average for SO2. 

(e) Testing and monitoring. (1) No 

later than the compliance date of this 

regulation, the owner or operator shall 

install, calibrate, maintain and operate 

Continuous Emissions Monitoring 

Systems (CEMS) for SO2 on Units 4 and 

5 of the Oklahoma Gas and Electric 

Muskogee plant; Units 1 and 2 of the 

Oklahoma Gas and Electric Sooner 

plant; and Units 3 and 4 of the 

American Electric Power/Public Service 

Company of Oklahoma Northeastern 

plant in accordance with 40 CFR 60.8 

and 60.13(e), (f), and (h), and Appendix 

B of Part 60. The owner or operator shall 

comply with the quality assurance 

procedures for CEMS found in 40 CFR 

part 75. Compliance with the emission 

limits for SO2 shall be determined by 

using data from a CEMS. 

(2) Continuous emissions monitoring 

shall apply during all periods of 

operation of the coal burning 

equipment, including periods of startup, 

shutdown, and malfunction, except for 

CEMS breakdowns, repairs, calibration 

checks, and zero and span adjustments. 

Continuous monitoring systems for 

measuring SO2 and diluent gas shall 

complete a minimum of one cycle of 

operation (sampling, analyzing, and 

data recording) for each successive 15- 

minute period. Hourly averages shall be 

computed using at least one data point 

in each fifteen minute quadrant of an 

hour. Notwithstanding this requirement, 

an hourly average may be computed 

from at least two data points separated 

by a minimum of 15 minutes (where the 

unit operates for more than one 

quadrant in an hour) if data are 

unavailable as a result of performance of 

calibration, quality assurance, 

preventive maintenance activities, or 

backups of data from data acquisition 

and handling system, and recertification 

events. When valid SO2 pounds per 

hour, or SO2 pounds per million Btu 

emission data are not obtained because 

of continuous monitoring system 

breakdowns, repairs, calibration checks, 

or zero and span adjustments, emission 

data must be obtained by using other 

monitoring systems approved by the 

EPA to provide emission data for a 

minimum of 18 hours in each 24 hour 

period and at least 22 out of 30 

successive boiler operating days. 

(f) Reporting and Recordkeeping 

Requirements. Unless otherwise stated 

all requests, reports, submittals, 

notifications, and other communications 

to the Regional Administrator required 

by this section shall be submitted, 

unless instructed otherwise, to the 

Director, Multimedia Planning and 

Permitting Division, U.S. Environmental 

Protection Agency, Region 6, to the 

attention of Mail Code: 6PD, at 1445 

Ross Avenue, Suite 1200, Dallas, Texas 

75202–2733. For each unit subject to the 

emissions limitation in this section and 

upon completion of the installation of 


srobinson on DSKHWCL6B1PROD with PROPOSALS3
Federal Register / Vol. 76, No. 55 / Tuesday, March 22, 2011 / Proposed Rules 16197 

CEMS as required in this section, the 

owner or operator shall comply with the 

following requirements: 

(1) For each emissions limit in this 

section, comply with the notification, 

reporting, and recordkeeping 

requirements for CEMS compliance 

monitoring in 40 CFR 60.7(c) and (d). 

(2) For each day, provide the total SO2

emitted that day by each emission unit. 

For any hours on any unit where data 

for hourly pounds or heat input is 

missing, identify the unit number and 

monitoring device that did not produce 

valid data that caused the missing hour. 

(g) Equipment Operations. At all 

times, including periods of startup, 

shutdown, and malfunction, the owner 

or operator shall, to the extent 

practicable, maintain and operate the 

unit including associated air pollution 

control equipment in a manner 

consistent with good air pollution 

control practices for minimizing 

emissions. Determination of whether 

acceptable operating and maintenance 

procedures are being used will be based 

on information available to the Regional 

Administrator which may include, but 

is not limited to, monitoring results, 

review of operating and maintenance 

procedures, and inspection of the unit. 

(h) Enforcement. (1) Notwithstanding 

any other provision in this 

implementation plan, any credible 

evidence or information relevant as to 

whether the unit would have been in 

compliance with applicable 

requirements if the appropriate 

performance or compliance test had 

been performed, can be used to establish 

whether or not the owner or operator 

has violated or is in violation of any 

standard or applicable emission limit in 

the plan. 

(2) Emissions in excess of the level of 

the applicable emission limit or 

requirement that occur due to a 

malfunction shall constitute a violation 

of the applicable emission limit. 

[FR Doc. 2011–5799 Filed 3–21–11; 8:45 am] 

BILLING CODE 6560–50–P 


srobinson on DSKHWCL6B1PROD with PROPOSALS3