64186 Federal Register / Vol. 76, No. 200 / Monday, October 17, 2011 / Proposed Rules 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 52 

[EPA–R06–OAR–2008–0727; FRL–9478–2] 

Approval and Promulgation of 

Implementation Plans; Arkansas; 

Regional Haze State Implementation 

Plan; Interstate Transport State 

Implementation Plan To Address 

Pollution Affecting Visibility and 

Regional Haze 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Proposed rule. 

SUMMARY: EPA is proposing to partially 

approve and partially disapprove a 

revision to the Arkansas State 

Implementation Plan (SIP) submitted by 

the State of Arkansas through the 

Arkansas Department of Environmental 

Quality (ADEQ) on September 23, 2008, 

August 3, 2010, and supplemented on 

September 27, 2011, that addresses 

regional haze (RH) for the first 

implementation period. These revisions 

were 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’’). EPA is 

also proposing to partially approve and 

partially disapprove a portion of a SIP 

revision submitted by the State of 

Arkansas on April 2, 2008, and 

supplemented on September 27, 2011, 

to address the interstate transport 

requirements of the CAA that the 

Arkansas SIP contain adequate 

provisions to prohibit emissions from 

interfering with measures required in 

another state to protect visibility. This 

action is being taken under section 110 

and part C of the CAA. 

DATES: Comments must be received on 

or before November 16, 2011. 

ADDRESSES: Submit your comments, 

identified by Docket No. EPA–R06– 

OAR–2008–0727, by one of the 

following methods: 

• Federal e-Rulemaking Portal: http:// 

www.regulations.gov. Follow the online 

instructions for submitting comments. 

• E-mail: Mr. Guy Donaldson at 

donaldson.guy@epa.gov. Please also 

send a copy by e-mail to the person 

listed in the FOR FURTHER INFORMATION

CONTACT section below. 

• Mail: Mr. Guy Donaldson, Chief, 

Air Planning Section (6PD–L), 

Environmental Protection Agency, 1445 

Ross Avenue, Suite 1200, Dallas, Texas 

75202–2733. 

• Hand or Courier Delivery: Mr. Guy 

Donaldson, Chief, Air Planning Section 

(6PD–L), Environmental Protection 

Agency, 1445 Ross Avenue, Suite 1200, 

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. Guy Donaldson, Chief, Air 

Planning Section (6PD–L), at fax 

number 214–665–7263. 

Instructions: Direct your comments to 

Docket No. EPA–R06–OAR–2008–0727. 

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 http:// 

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 http:// 

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 

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 http:// 

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 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 

Arkansas Department of Environmental 

Quality, 5301 Northshore Drive, North 

Little Rock, AR 72118–5317. 

FOR FURTHER INFORMATION CONTACT: Ms. 

Dayana Medina, Air Planning Section 

(6PD–L), Environmental Protection 

Agency, Region 6, 1445 Ross Avenue, 

Suite 700, Dallas, Texas 75202–2733, 

telephone 214–665–7241; fax number 

214–665–7263; e-mail address 

medina.dayana@epa.gov. 

SUPPLEMENTARY INFORMATION: 

Throughout this document wherever 

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

the EPA. 

Table of Contents 

I. Overview of Proposed Actions 

A. Regional Haze 

B. Interstate Transport and Visibility 

II. 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) 

III. 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 

IV. Our Analysis of Arkansas’ Regional Haze 

SIP 

A. Affected Class I Areas 

B. Determination of Baseline, Natural and 

Current Visibility Conditions 


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1. Estimating Natural Visibility Conditions 

2. Estimating Baseline Visibility 

Conditions 

3. Natural Visibility Impairment 

4. Uniform Rate of Progress 

C. Evaluation of Arkansas’ Reasonable 

Progress Goals 

1. Establishment of the Reasonable 

Progress Goals 

2. ADEQ’s Reasonable Progress ‘‘Four 

Factor’’ Analysis 

3. Reasonable Progress Consultation 

D. Evaluation of Arkansas’ BART 

Determinations 

1. Identification of BART-Eligible Sources 

2. Identification of Sources Subject to 

BART 

a. Modeling Methodology 

b. Contribution Threshold 

c. Sources Identified by ADEQ as Subject 

to BART 

3. BART Determinations 

a. AECC Bailey Unit 1 and AECC 

McClellan Unit 1 BART Determinations 

b. AEP Flint Creek Boiler No. 1 BART 

Determination 

c. Entergy Lake Catherine Unit 4 BART 

Determination 

d. Entergy White Bluff Units 1, 2, and 

Auxiliary Boiler BART Determinations 

e. Domtar Power Boilers No. 1 and 2 BART 

Determinations 

f. ADEQ BART Results and Summary 

4. Arkansas’ Regional Haze Rule 

E. Long-Term Strategy 

1. Emissions Inventories 

a. Arkansas’ 2002 Emission Inventory 

b. Arkansas’ 2018 Emission Inventory 

2. Visibility Projection Modeling 

3. Sources of Visibility Impairment 

a. Sources of Visibility Impairment in 

Caney Creek 

b. Sources of Visibility Impairment in 

Upper Buffalo 

c. Arkansas’ Contribution to Visibility 

Impairment in Class I Areas Outside the 

State 

4. Consultation and Emissions Reductions 

for Other States’ Class I Areas 

5. Mandatory Long-Term Strategy Factors 

a. Reductions Due to Ongoing Air Pollution 

Programs 

b. Measures To Mitigate the Impacts of 

Construction Activities 

c. Emissions Limitations and Schedules of 

Compliance 

d. Source Retirement and Replacement 

Schedules 

e. Agricultural and Forestry Smoke 

Management Techniques 

f. Enforceability of Emissions Limitations 

and Control Measures 

g. Anticipated Net Effect on Visibility Due 

to Projected Changes 

6. Our Conclusion on Arkansas’ Long-Term 

Strategy 

F. Coordination of RAVI and Regional Haze 

Requirements 

G. Monitoring Strategy and Other SIP 

Requirements 

H. Federal Land Manager Coordination 

I. Periodic SIP Revisions and Five-Year 

Progress Reports 

J. Determination of the Adequacy of 

Existing Implementation Plan 

V. Our Analysis of Arkansas’ Interstate 

Visibility Transport SIP Provisions 

VI. Proposed Action 

A. Regional Haze 

B. Interstate Transport and Visibility 

VII. Statutory and Executive Order Reviews 

I. Overview of Proposed Actions 

A. Regional Haze 

We are proposing to partially approve 

and partially disapprove Arkansas’ RH 

SIP revision submitted on September 

23, 2008, August 3, 2010, and 

supplemented on September 27, 2011, 

as discussed in sections IV and VI of 

this proposed rulemaking. Specifically, 

we are proposing to approve the 

following: the State’s identification of 

affected Class I areas; the establishment 

of baseline and natural visibility 

conditions; the Uniform Rate of Progress 

(URP); the State’s reasonable progress 

goal (RPG) consultation and the longterm strategy (LTS) consultation; the 

regional haze monitoring strategy and 

other SIP requirements under section 

51.308(d)(4); the State’s commitment to 

submit periodic regional haze SIP 

revisions and periodic progress reports 

describing progress towards the RPGs; 

the State’s commitment to make a 

determination of the adequacy of the 

existing SIP at the time a progress report 

is submitted; and the State’s 

consultation and coordination with 

Federal land managers (FLMs). 

We are proposing to partially approve 

and partially disapprove those portions 

addressing the State’s identification of 

BART-eligible sources and subject to 

BART sources; the requirements for best 

available retrofit technology (BART); the 

State’s RH Rule; and the LTS. 

Specifically, we are proposing to 

approve the State’s identification of 

BART-eligible sources, with the 

exception of the 6A Boiler at the 

Georgia-Pacific Crossett Mill, which we 

find to be BART-eligible. We are 

proposing to approve the State’s 

identification of subject to BART 

sources, with the exception of the 6A 

and 9A Boilers at the Georgia-Pacific 

Crossett Mill, which we find to be 

subject to BART. We are also proposing 

to approve the following BART 

determinations made by ADEQ: The PM 

BART determination for the No. 1 Boiler 

of the American Electric Power (AEP) 

Flint Creek plant; the SO2 and PM 

BART determinations for the natural gas 

firing scenario for Unit 4 of the Entergy 

Lake Catherine plant; the PM BART 

determinations for both the bituminous 

and sub-bituminous coal firing 

scenarios for Units 1 and 2 of the 

Entergy White Bluff plant; and the PM 

BART determination for the No. 1 

Power Boiler of the Domtar Ashdown 

Mill. We are proposing to disapprove 

the following BART determinations 

made by ADEQ: The SO2, NOX, and PM 

BART determinations for both Unit 1 of 

the Arkansas Electric Cooperative 

Corporation (AECC) Bailey plant and 

Unit 1 of the AECC McClellan plant; the 

SO2 and NOX BART determinations for 

the No. 1 Boiler of the AEP Flint Creek 

plant; the NOX BART determination for 

the natural gas firing scenario and the 

SO2, NOX, and PM BART 

determinations for the fuel oil firing 

scenario for Unit 4 of the Entergy Lake 

Catherine plant; the SO2 and NOX BART 

determinations for both the bituminous 

and sub-bituminous coal firing 

scenarios for Units 1 and 2 of the 

Entergy White Bluff plant; the BART 

determination for the Auxiliary Boiler of 

the Entergy White Bluff Plant; the SO2

and NOX BART determinations for the 

No. 1 Power Boiler of the Domtar 

Ashdown Mill; and the SO2, NOX and 

PM BART determinations for the No. 2 

Power Boiler of the Domtar Ashdown 

Mill. We are proposing to disapprove 

these BART determinations because 

they do not comply with our regulations 

under 40 CFR 51.308(e). The Arkansas 

RH Rule, the Arkansas Pollution Control 

and Ecology Commission (APC&E 

Commission) Regulation 19, Chapter 15, 

was submitted by ADEQ on September 

23, 2008, as part of the RH SIP. On 

August 3, 2010, we received a SIP 

submittal from ADEQ revising several 

chapters of APC&E Commission 

Regulation 19, including chapter 15. 

The revisions to Chapter 15 of APC&E 

Commission Regulation 19 that we 

received on August 3, 2010, are mostly 

non-substantive edits to the original rule 

we received on September 23, 2008. 

Therefore, in this proposed rulemaking 

we are proposing to take action on 

chapter 15 of APC&E Regulation 19 

contained in the submittal we received 

on September 23, 2008, and as revised 

by the submittal we received on August 

3, 2010. We are proposing to approve 

the portions of APC&E Commission 

Regulation 19, chapter 15, which we 

received on September 23, 2008, and as 

revised on August 3, 2010, that are 

consistent with the portions of the 

Arkansas RH SIP we are proposing to 

approve and we are proposing to 

disapprove the portions that are 

consistent with other portions of the 

Arkansas RH SIP we are proposing to 

disapprove. We are proposing to 

partially approve and partially 

disapprove the State’s LTS because the 

LTS only partially satisfies the 

requirements under section 

51.308(d)(3), and a portion of it relies on 

portions of the RH SIP we are proposing 

to disapprove. 


jlentini on DSK4TPTVN1PROD with PROPOSALS2
64188 Federal Register / Vol. 76, No. 200 / Monday, October 17, 2011 / Proposed Rules 

1CAA section 110(c)(1). 

2 Visual range is the greatest distance, in 

kilometers or miles, at which a dark object can be 

viewed against the sky. 

We are proposing to disapprove the 

reasonable progress goals (RPGs) under 

section 51.308(d)(1) because Arkansas 

did not consider the factors that states 

are required to consider in establishing 

RPGs under the CAA and section 

51.308(d)(1)(A). 

Under the CAA,1 we must, within 24 

months following a final disapproval, 

either approve a SIP or promulgate a 

Federal Implementation Plan (FIP). At 

this time, we are not proposing a FIP for 

the portions of the Arkansas RH SIP we 

are proposing to disapprove because 

ADEQ has expressed its intent to revise 

the Arkansas RH SIP by correcting the 

deficiencies we have identified in this 

proposal. We are electing to not propose 

a FIP at this time in order to provide 

Arkansas time to correct these 

deficiencies. 

B. Interstate Transport and Visibility 

We are proposing to partially approve 

and partially disapprove a portion of the 

SIP revision we received from the State 

of Arkansas on April 2, 2008, 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 

whichwill * * * 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 

either measures to prohibit emissions 

that would interfere with the reasonable 

progress goals set to protect Class I areas 

in other states, or a demonstration that 

emissions from Arkansas sources and 

activities will not have the prohibited 

impacts on other states’ existing SIPs. 

Arkansas stated in its April 2, 2008 

submittal that it is relying on the 

Arkansas RH Rule, the APC&E 

Commission Regulation 19, Chapter 15, 

to satisfy the requirements of section 

110(a)(2)(D)(i)(II) that emissions from 

Arkansas sources not interfere with 

measures required in the SIP of any 

other state under part C of the CAA to 

protect visibility. ADEQ also stated in 

its April 2, 2008 submittal that it is not 

possible to assess whether there is any 

interference with the measures in the 

applicable SIP for another state 

designed to protect visibility for the 8- 

hour ozone and PM2.5 NAAQS until 

ADEQ submits and EPA approves 

Arkansas’ RH SIP. 

In developing their Regional Haze SIP 

and RPGs, Arkansas and potentially 

impacted States collaborated through 

the Central Regional Air Planning 

(CENRAP) association. Each State 

developed its Regional Haze Plans and 

RPGs based on the CENRAP modeling. 

The CENRAP modeling was based in 

part on the emissions reductions each 

state intended to achieve by 2018. In the 

case of Arkansas, some of the emissions 

reductions included in the modeling, 

and thus relied upon by other States, 

were from BART controls on Arkansas 

subject to BART sources. In the State’s 

September 27, 2011 supplemental 

submission, ADEQ clarified that the 

base year modeling inventory used by 

CENRAP in the 2002 base case modeling 

was prepared by the CENRAP Modeling 

Workgroup and its consultants, and was 

derived primarily from the 2002 

National Emissions Inventory (NEI). 

ADEQ also clarified that it provided the 

CENRAP Modeling Workgroup with the 

controlled BART source emission limits 

contained in the State’s RH Rule, the 

APC&E Commission Regulation 19, 

Chapter 15, for inclusion in the 

CENRAP’s 2018 future case modeling. 

The State’s RH Rule became effective 

October 15, 2007, and incorporates 

BART requirements for Arkansas’ 

subject to BART sources. The current 

language of the regulation requires 

Arkansas’ subject to BART sources to 

comply with BART requirements no 

later than five years after EPA approval 

of the RH SIP or 6 years after the 

effective date of the regulation, 

whichever is first. However, on March 

26, 2010, the Arkansas Pollution Control 

and Ecology Commission, the 

environmental policy-making body for 

Arkansas, granted all Arkansas subject 

to BART sources a variance from the 

compliance deadline imposed by the 

State’s RH Rule, such that these sources 

are now required to comply with BART 

requirements no later than 5 years after 

EPA approval of the RH SIP. 

Compliance with these BART 

requirements will ensure that Arkansas 

obtains its share of the emission 

reductions relied upon by other states to 

meet the RPGs for their Class I areas. 

Since compliance of Arkansas’ subject 

to BART sources with BART 

requirements is dependent upon our 

approval of the RH SIP, and since we 

are proposing to disapprove the portion 

of the RH SIP which includes some of 

Arkansas’ BART determinations, a 

portion of the emission reductions 

committed to by Arkansas and relied 

upon by other states will not be realized 

and, as a consequence, Arkansas’ 

emissions will interfere with other 

states’ SIPs to protect visibility. 

Therefore, we are proposing to partially 

approve and partially disapprove the 

portion of the Arkansas Interstate 

Transport SIP submittal that addresses 

the visibility requirement of section 

110(a)(2)(D)(i)(II) that emissions from 

Arkansas sources not interfere with 

measures required in the SIP of any 

other state under part C of the CAA to 

protect visibility. 

II. 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 

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 


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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). 

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 man-made 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 

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). 

We received the Arkansas RH SIP on 

September 23, 2008. 

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. 

The 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 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, 

including section 110(a)(2)(D)(i), which 

pertains to the interstate transport of 

certain emissions. Thus, states were 

required to submit SIPs that satisfy the 

applicable requirements under sections 

110(a)(1) and (2), including the 

requirements of section 110(a)(2)(D)(i), 

by July 2000. States, including 

Arkansas, did not meet the statutory 

July 2000 deadline for submission of 

these SIPs. Accordingly, on April 25, 

2005, EPA made findings of failure to 

submit, notifying all states, including 

Arkansas, of their failure to make the 

required SIP submission to address 

interstate transport under section 

110(a)(2)(D)(i). 70 FR 21147. This 

finding started a 24-month FIP clock 

under section 110(c). Pursuant to 

section 110(c), we are required to 

promulgate a FIP to address the 

applicable interstate transport 

requirements, unless the State makes 

the required submission and we fully 

approve such submission, within the 

24-month period. 

On August 15, 2006, we issued our 

‘‘Guidance for State Implementation 

Plan (SIP) Submissions to Meet Current 

Outstanding Obligations Under Section 

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

PM2.5 National Ambient Air Quality 

Standards’’ (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 

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. In this action, we only address 

the fourth element regarding visibility. 

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 


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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’’). 

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 April 2, 2008, we received a SIP 

revision from Arkansas to address the 

interstate transport provisions of CAA 

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

PM2.5 NAAQS. For the reasons 

discussed in section V of this proposed 

rulemaking, a portion of the emission 

reductions committed to by Arkansas 

and relied upon by other states will not 

be realized and Arkansas’ emissions 

will interfere with other states’ SIPs to 

protect visibility. Therefore, we are 

proposing to partially approve and 

partially disapprove the portion of the 

Arkansas Interstate Transport SIP 

submittal that addresses the 

requirement that emissions from 

Arkansas sources 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 recognize that we have an 

outstanding obligation to promulgate a 

FIP for the portion of the Arkansas 

Interstate Transport SIP submittal we 

are proposing to disapprove. However, 

because we are not proposing a FIP for 

the portions of the Arkansas RH SIP we 

are proposing to disapprove at this time 

in order to provide Arkansas time to 

correct the deficiencies identified in this 

proposal, we are likewise not proposing 

a FIP at this time for the disapproved 

portion of the Arkansas Interstate 

Transport SIP. We believe it is 

appropriate to address the concerns 

with the Regional Haze SIP and the 

Interstate Transport SIP at the same time 

and it is appropriate, in this instance, to 

allow the state an opportunity to 

address the deficiencies we have 

identified in this proposed action before 

imposing a FIP. If we were to propose 

a FIP for the disapproved portion of the 

Arkansas Interstate Transport SIP 

without also proposing a FIP for the 

disapproved portions of the Arkansas 

RH SIP, this could potentially result in 

Arkansas’ subject to BART sources 

being required to install two successive 

levels of control measures, the first in 

order to meet the requirements of 

section 110(a)(2)(D)(i), and the second 

in order to meet the requirements of the 

RH program. This would result in an 

inefficient use of resources by both the 

affected sources and us. 

III. 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 

man-made air pollution by reducing 

anthropogenic emissions that cause RH. 

The national goal is a return to natural 

conditions, i.e., man-made 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. 


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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 (D.C. 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. 

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; 

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 (MW), 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. See also 40 CFR part 51, 

Appendix Y, section III.A.1. 

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 


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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 

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). Also, a state with a 

Class I area impacted by emissions from 

another state must consult with such 

contributing state, (id.) and must also 

demonstrate that it has included in its 

SIP all measures necessary to obtain its 

share of emission reductions needed to 

meet the reasonable progress goals for 

the Class I area. Id. at (d)(3)(ii). 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 


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11The TSD can be found in the docket for this 

proposal at http://www.regulations.gov. The docket 

number is EPA–R06–OAR–2008–0727. 12An inverse megameter is the direct 

measurement unit for visibility impairment data. It 

is the amount of light scattered and absorbed as it 

travels over a distance of one million meters. 

Deciviews (dv) can be calculated from extinction 

data as follows: dv = 10 × ln (bext(Mm¥1)/10), where 

dv stands for ‘‘deciviews;’’ ln stands for ‘‘natural 

logarithm;’’ and bext stands for ‘‘extinction value.’’ 13See Appendix E of the TSD for CENRAP 

Emissions and Air Quality Modeling to Support 

Regional Haze State Implementation, found in 

Appendix 8.1 of the Arkansas RH SIP. 

14 Guidance for Estimating Natural Visibility 

Conditions Under the Regional Haze Rule, EPA– 

454/B–03–005, September 2003. 

15Since this is the first RH SIP submittal, the 

calculated baseline visibility condition and the 

current visibility condition will be the same. It is 

expected that subsequent RH SIP submittals will 

reflect different calculated numbers for baseline and 

current visibility conditions due to the change in 

conditions. 

16The 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. 

• 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. 

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. 

IV. Our Analysis of Arkansas’ Regional 

Haze SIP 

On September 23, 2008, we received 

a RH SIP revision from the State of 

Arkansas for approval into the Arkansas 

SIP. We received a supplemental 

submission to the RH SIP revision on 

September 27, 2011. In addition, we 

received a submittal revising several 

chapters of APC&E Commission 

Regulation 19, including Chapter 15 

(Arkansas’ RH Rule), on August 3, 2010. 

In this proposed rulemaking, the only 

portions of the August 3, 2010, 

submittal we are proposing to take 

action on are those addressing Chapter 

15 of APC&E Commission Regulation 

19. The following is a discussion of our 

evaluation of these submissions. The 

parts of the submittals 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 ADEQ’s submissions in 

the order in which the regulations 

appear in 40 CFR 51.308, and a more 

comprehensive technical analysis.11

A. Affected Class I Areas 

In accordance with 40 CFR 51.308(d), 

ADEQ has identified two Class I areas 

within its borders, the Caney Creek 

Wilderness Area (Caney Creek) in 

Ouachita National Forest and the Upper 

Buffalo Wilderness Area (Upper Buffalo) 

in the Ozark National Forest. ADEQ is 

responsible for developing RPGs for 

these two Class I areas. ADEQ has also 

determined that Arkansas emissions 

cause and contribute to visibility 

impairment at the two Class I areas in 

Missouri: Hercules Glades Wilderness 

Area (Hercules Glades) and Mingo 

National Wildlife Refuge (Mingo). The 

TSD for the CENRAP Emissions and Air 

Quality Modeling to Support Regional 

Haze State Implementation (TSD for 

CENRAP modeling) demonstrates 

Arkansas sources are responsible for a 

visibility extinction of approximately 

7.1 inverse megameters 12 (Mm¥1) at 

Hercules Glades and for a visibility 

extinction of approximately 4.95 Mm¥1

at Mingo on the worst 20% days for 

2002.13 As discussed in section IV.C.3 of 

this proposed rulemaking, ADEQ 

consulted with the appropriate state air 

quality agency in Missouri to reach an 

agreement on whether it is necessary for 

Arkansas to commit to additional 

emission reductions that would help 

Missouri achieve its RPGs for Hercules 

Glades and Mingo. 

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,14 ADEQ calculated baseline/ 

current 15 and natural visibility 

conditions for its two Class I areas, 

Caney Creek and Upper Buffalo, 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 16. 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. 

ADEQ opted to use the new IMPROVE 

equation to calculate the ‘‘refined’’ 

natural visibility conditions. This is an 

acceptable approach under our 2003 


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17The science behind the revised IMPROVE 

equation is summarized in Appendix 5.1 of the 

Arkansas RH SIP 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. 

18 Guidance for Estimating Natural Visibility 

Conditions Under the Regional Haze Rule, EPA– 

454/B–03–005, September 2003. 

19The 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). 

Natural Visibility Guidance. For Caney 

Creek, ADEQ used the new IMPROVE 

equation to calculate the ‘‘refined’’ 

natural visibility value for the 20 

percent worst days to be 11.58 

deciviews and for the 20 percent best 

days to be 4.23 deciviews. For Upper 

Buffalo, ADEQ used the new IMPROVE 

equation to calculate the ‘‘refined’’ 

natural visibility value for the 20 

percent worst days to be 11.57 

deciviews and for the 20 percent best 

days to be 4.18 deciviews. We have 

reviewed ADEQ’s estimates of the 

natural visibility conditions for Caney 

Creek and Upper Buffalo and are 

proposing to find these acceptable using 

the new IMPROVE equation. 

The new IMPROVE equation takes 

into account the most recent review of 

the science 17 and it accounts for the 

effect of particle size distribution on 

light extinction efficiency of sulfate 

(SO4), nitrate (NO3), 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 

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 18, ADEQ calculated baseline 

visibility conditions for Caney Creek 

and Upper Buffalo. The baseline 

condition calculation begins with the 

calculation of light extinction, using the 

IMPROVE equation. The IMPROVE 

equation sums the light extinction 19

resulting from individual pollutants, 

such as sulfates and nitrates. As with 

the natural visibility conditions 

calculation, ADEQ 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). The IMPROVE monitor at 

Caney Creek was installed between 2000 

and 2002, and therefore ADEQ used 

visibility data for 2002–2004. The 

resulting baseline conditions represent 

an average for 2002–2004. ADEQ 

calculated the baseline conditions at 

Caney Creek as 26.36 deciviews on the 

20 percent worst days, and 11.24 

deciviews on the 20 percent best days. 

In calculating the baseline conditions at 

Upper Buffalo, ADEQ used visibility 

data for 2000–2004. ADEQ calculated 

the baseline conditions at Upper Buffalo 

as 26.27 deciviews on the 20 percent 

worst days, and 11.71 deciviews on the 

20 percent best days. We have reviewed 

ADEQ’s estimation of baseline visibility 

conditions at Caney Creek and Upper 

Buffalo and are proposing to find these 

estimates acceptable. 

3. Natural Visibility Impairment 

To address 40 CFR 

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

calculated the number of deciviews by 

which baseline conditions exceed 

natural visibility conditions for the best 

and worst days at Caney Creek and 

Upper Buffalo. At Caney Creek for the 

20 percent worst days, ADEQ calculated 

the number of deciviews by which 

baseline conditions exceed natural 

visibility conditions to be 14.78 dv 

(baseline of 26.36 dv¥natural 

conditions of 11.58 dv). For the 20 

percent best days at Caney Creek, the 

baseline conditions exceed natural 

visibility conditions by 7.01 dv 

(baseline of 11.24 dv¥natural 

conditions of 4.23 dv). At Upper Buffalo 

for the 20% worst days, ADEQ 

calculated the number of deciviews by 

which baseline conditions exceed 

natural visibility conditions to be 14.7 

dv (baseline of 26.27 dv¥natural 

conditions of 11.57 dv). For the 20 

percent best days at Upper Buffalo, the 

baseline conditions exceed natural 

visibility conditions by 7.53 dv 

(baseline of 11.71 dv¥natural 

conditions of 4.18 dv). We have 

reviewed ADEQ’s estimates of the 

natural visibility impairment at Caney 

Creek and Upper Buffalo and are 

proposing to find these estimates 

acceptable. 

4. Uniform Rate of Progress 

In setting the RPGs, ADEQ analyzed 

and determined the Uniform Rate of 

Progress (URP) needed to reach natural 

visibility conditions by the year 2064. In 

so doing, ADEQ compared the baseline 

visibility conditions to the natural 

visibility conditions in Caney Creek and 

compared the baseline visibility 

conditions to the natural visibility 

conditions in Upper Buffalo (as 

described above), and determined the 

uniform rate of progress needed in order 

to attain natural visibility conditions by 

2064. ADEQ constructed the URP 

consistent with the requirements of the 

RHR and 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 Caney Creek and 

for Upper Buffalo. 

Using a baseline visibility value of 

26.36 dv and a ‘‘refined’’ natural 

visibility value of 11.58 dv for the 20 

percent worst days for Caney Creek, 

ADEQ calculated the URP to be 

approximately 0.246 dv per year. This 

results in a total reduction of 14.78 dv 

that are necessary to reach the natural 

visibility condition of 11.58 dv in 2064 

for Caney Creek. The URP results in a 

visibility improvement of 3.45 dv for 

Caney Creek for the period covered by 

this SIP revision submittal (up to and 

including 2018). 

Using a baseline visibility value of 

26.27 dv and a ‘‘refined’’ natural 

visibility value of 11.57 dv for the 20 

percent worst days for Upper Buffalo, 

ADEQ calculated the URP to be 

approximately 0.245 dv per year. This 

results in a total reduction of 14.70 dv 

that are necessary to reach the natural 

visibility condition of 11.57 dv in 2064 

for Upper Buffalo. The URP results in a 

visibility improvement of 3.43 dv for 

Upper Buffalo for the period covered by 

this SIP revision submittal (up to and 

including 2018). 


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20The TSD for CENRAP Emissions and Air 

Quality Modeling to Support RH State 

Implementation is found in Appendix 8.1 of the 

Arkansas RH SIP. 

TABLE 1—SUMMARY OF UNIFORM RATE OF PROGRESS

Visibility metric Caney Creek Upper Buffalo 

Baseline Conditions ................................................................................................................................ 26.36 dv ................. 26.27 dv. 

Natural Visibility ...................................................................................................................................... 11.58 dv ................. 11.57 dv. 

Total Improvement by 2064 .................................................................................................................... 14.78 dv ................. 14.70 dv. 

Improvement for this SIP by 2018 .......................................................................................................... 3.45 dv ................... 3.43 dv. 

Uniform Rate of Progress ....................................................................................................................... 0.246 dv/year ......... 0.245 dv/year. 

We are proposing to find that ADEQ 

has appropriately calculated the URP 

and has satisfied the requirement in 

section 51.308(d)(1)(i)(B). 

C. Evaluation of Arkansas’ Reasonable 

Progress Goals 

We are proposing to disapprove 

Arkansas’s Reasonable Progress Goals 

because the State did not establish the 

RPGs for Caney Creek and Upper 

Buffalo in accordance with the 

requirements of the RHR. As a result, 

ADEQ’s RH SIP fails to ensure adequate 

reasonable progress toward meeting the 

national visibility goal. Section 

169A(g)(1) of the CAA and section 

51.308(d)(1)(i)(A) of the RHR require 

states to take into account certain factors 

in establishing its reasonable progress 

goals and to demonstrate how those 

factors were taken into consideration in 

selecting the goals. ADEQ did not do so. 

We do note that ADEQ did consult with 

other states regarding the development 

of RPGs in accordance with the RHR, 

but this is not enough for us to approve 

the RPGs. 

1. Establishment of the Reasonable 

Progress Goal 

ADEQ adopted the CENRAP modeled 

2018 visibility conditions as the RPGs 

for Caney Creek and Upper Buffalo 

Class I areas. ADEQ established a RPG 

of 22.48 dv for Caney Creek for 2018 for 

the 20% worst days. This represents a 

3.88 dv improvement over a baseline of 

26.36 dv. For Upper Buffalo, ADEQ 

established a RPG of 22.52 dv for 2018 

for the 20% worst days, which 

represents a 3.75 dv improvement over 

a baseline of 26.27 dv. ADEQ calculated 

that under its RPGs, it would attain 

natural visibility conditions in 2062 for 

Caney Creek and 2063 for Upper 

Buffalo. The CENRAP’s projections for 

2018 for the 20% best days for Caney 

Creek and Upper Buffalo, which 

represent ADEQ’s RPGs for the 20% best 

days, are shown in Figures 10.4 and 

10.6 of the RH SIP and in Appendix D 

to the TSD for CENRAP Emissions and 

Air Quality Modeling to Support RH 

State Implementation.20 A comparison 

of ADEQ’s RPGs to baseline conditions 

on the least impaired days shows that 

control of Arkansas sources will result 

in no degradation in visibility 

conditions in the first planning period. 

The CENRAP modeling shows that for 

the 20% best days, there would be a 

0.89 dv and a 0.91 dv improvement in 

visibility from the baseline for Caney 

Creek and Upper Buffalo, respectively. 

ADEQ established RPGs that ensure 

no degradation in visibility for the least 

impaired days. See 40 CFR 51.308(d)(1). 

However, in setting its RPGs for its Class 

I areas for the 20% worst days, the State 

relied on the fact that the emission 

reductions from BART and from the 

implementation of other requirements of 

the CAA would result in RPGs that 

provided for a slightly greater rate of 

improvement in visibility than would be 

needed to attain the URP. Based on this 

fact, ADEQ did not undertake any 

further analysis. As discussed below, we 

do not believe this provides sufficient 

analysis under section 169A of the CAA 

and our RHR, and discuss it further in 

the next section. 

2. ADEQ’s Reasonable Progress ‘‘Four 

Factor’’ Analysis 

In establishing a RPG for a Class I 

Federal area located within a state, the 

State is required by CAA § 169A(g)(1) 

and 40 CFR 51.308(d)(1)(i)(A) to 

‘‘[c]onsider the costs of compliance, the 

time necessary for compliance, the 

energy and non-air quality 

environmental impacts of compliance, 

and the remaining useful life of any 

potentially affected sources, and include 

a demonstration showing how these 

factors were taken into consideration in 

selecting the goal.’’ In addition to this 

explicit statutory requirement, the RHR 

also establishes an analytical 

requirement to ensure that each State 

considers carefully the suite of emission 

reduction measures necessary to attain 

the URP. The RHR provides that EPA 

will consider both the State’s 

consideration of the four factors in 

section 51.308(d)(1)(i)(A) and its 

analysis of the URP ‘‘[i]n determining 

whether the State’s goal for visibility 

improvement provides for reasonable 

progress.’’ 40 CFR 51.308(d)(1)(iii). As 

explained in the preamble to the RHR, 

the URP analysis was adopted to ensure 

that States use a common analytical 

framework and to ensure an informed 

and equitable decision making process 

to ensure a transparent process that 

would, among other things, ensure that 

the public would be provided with the 

information necessary to understand the 

emission reductions needed, the costs of 

such measures, and other factors 

associated with improvements in 

visibility. 64 FR at 35733. The preamble 

to the Rule (64 FR 35732) also makes 

clear that the URP does not establish a 

‘‘safe harbor’’ for the State in setting its 

progress goals: 

If the State determines that the amount of 

progress identified through the [URP] 

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. 

In establishing its RPGs for 2018 for 

the 20% worst days, ADEQ relied on the 

improvements in visibility that are 

anticipated to result from federal, State, 

and local control programs that are 

either currently in effect or with 

mandated future-year emission 

reduction schedules that predate 2018, 

including BART emission limitations 

established by ADEQ. Based on the 

emissions reductions from these 

measures, CENRAP modeled the 

projected visibility conditions 

anticipated at each Class I area in 2018 

and ADEQ used these results to 

establish RPGs. 

ADEQ argued that because this rate of 

progress, if sustained, will result in a 

return to natural visibility prior to 2064, 

no additional analysis was required and 

would be an unnecessary exercise. We 

consistently informed States, including 

Arkansas, throughout the regional haze 

development process that the above 

interpretation of the statute and our 

regulations is incorrect. ADEQ cannot 

rely solely on meeting the URP to justify 


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21See Appendix 2.1 of the Arkansas RH SIP 

the conclusion that its goals provide for 

reasonable progress. We provided 

comments to ADEQ on the draft 

Arkansas RH SIP to that effect.21

States do have discretion in setting 

RPGs, but are required to go beyond the 

URP analysis in establishing RPGs. 

ADEQ made no attempt to determine 

whether additional progress would be 

reasonable based on the statutory 

factors. It does not appear that such an 

analysis would have been an 

unnecessary exercise, as claimed by 

ADEQ. As discussed in section IV.D.2 of 

this proposed rulemaking, there are at 

least two point sources in Arkansas not 

subject to the BART requirements that 

contribute to visibility impairment at 

Arkansas’ Class I areas. This conclusion 

is based on the information in the RH 

SIP indicating that these sources have 

predicted impacts exceeding the 0.5 dv 

threshold ADEQ used to determine 

whether BART sources contribute to 

visibility impairment. Given their 

contribution to visibility impairment, 

these two sources are potential 

candidates for emissions controls under 

reasonable progress, as may be other 

Arkansas point sources whose visibility 

impact was not evaluated by ADEQ. 

Also, as discussed in section IV.E.3 of 

this proposed notice, Arkansas sources 

are projected to remain significant 

contributors to visibility impairment in 

2018 and thus providing further support 

that additional analysis should have 

been performed according to the 

statutory factors. 

Given that ADEQ did not provide an 

analysis that considered the four 

statutory factors under 40 CFR 

51.308(d)(1)(i)(A) to evaluate the 

potential of controlling certain sources 

or source categories for addressing 

visibility impacts from man-made 

sources, it is not possible to assess 

whether any additional control 

measures for improving visibility are 

reasonable. Section 51.308(d)(1)(iii) 

requires that in determining whether the 

State’s goal for visibility improvement 

provides for reasonable progress 

towards natural visibility conditions, 

the Administrator will evaluate the 

demonstrations developed by the State 

pursuant to paragraphs (d)(1)(i) and 

(d)(1)(ii) of this section. Consequently, 

for the reasons outlined above, we are 

proposing to find that Arkansas has not 

satisfied the requirements to establish 

reasonable progress goals under section 

51.308(d)(1)(i)(A). 

3. Reasonable Progress Consultation 

ADEQ worked with the Missouri 

Department of Natural Resources 

(MDNR) and CENRAP to jointly develop 

the consultation strategy. Consultations 

were held jointly by Arkansas and 

Missouri. ADEQ used CENRAP as the 

main vehicle for facilitating 

collaboration with FLMs and other 

states in developing its RH SIP. ADEQ 

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 Caney Creek and Upper 

Buffalo. 

ADEQ determined that in addition to 

Arkansas, the following states have a 

significant contribution to decreased 

visibility in one or both of Arkansas’ 

Class I areas: Illinois, Indiana, 

Kentucky, Missouri, Ohio, Oklahoma, 

Tennessee, and Texas. ADEQ sent a 

letter dated February 26, 2007, to these 

states, requesting that they participate in 

the consultation process for the 

Arkansas RH SIP. These states complied 

with ADEQ’s request and participated in 

the consultation process for the 

Arkansas RH SIP. ADEQ and MDNR 

jointly conducted three consultations in 

the form of conference calls on April 3, 

May 11, and June 7, 2007. Participants 

in the consultation process included 

states and tribes, CENRAP and other 

Regional Planning Organizations 

(RPOs), EPA, and FLMs. 

At the three consultations held by 

ADEQ and MDNR, a URP was 

developed for each Class I area in 

Arkansas and Missouri (Caney Creek 

and Upper Buffalo in Arkansas, and 

Hercules Glades and Mingo in 

Missouri). The participating states also 

determined that regional modeling and 

other findings based on existing and 

proposed controls arising from local, 

state, and federal requirements 

indicated that the two Class I areas in 

Arkansas and the two Class I areas in 

Missouri are on the glidepath and are 

expected to meet the rate of progress 

goals for the first implementation period 

ending in 2018. ADEQ determined that 

additional emissions reductions from 

other States are not necessary to address 

visibility impairment at Caney Creek 

and the Upper Buffalo for the first 

implementation period ending in 2018, 

and all states participating in its 

consultations agreed with this. 

Therefore, we are proposing to find that 

Arkansas has satisfied the requirement 

under section 308(d)(1)(iv) to consult 

with other States which may reasonably 

be anticipated to cause or contribute to 

visibility impairment at Arkansas’ two 

Class I areas. 

D. Evaluation of Arkansas’ BART 

Determinations 

Arkansas’ RH Rule, APC&E 

Commission Regulation 19, chapter 15, 

was included in the Arkansas RH SIP 

submittal, and became effective on 

October 15, 2007. On August 3, 2010, 

we received a SIP revision from ADEQ 

containing amendments to several 

chapters of APC&E Commission 

Regulation 19, including Chapter 15. 

The revisions to Chapter 15 of APC&E 

Commission Regulation 19, contained in 

the August 3, 2010 submittal, are mostly 

non-substantive amendments to the rule 

we received on September 23, 2008. 

Chapter 15 of Regulation 19 

incorporates by reference the definitions 

contained in section 40 CFR 51.301 of 

the Act, as in effect on June 22, 2007. 

Chapter 15 also identifies the Arkansas 

BART-eligible sources, the subject to 

BART sources and their BART 

requirements, and the BART 

compliance provisions. The rules 

further provide that the source’s air 

quality permit be revised to incorporate 

the resulting source-specific 

requirements. The State’s RH Rule and 

our proposed action on it are discussed 

in section IV.D.4 of this proposed 

rulemaking. 

BART is an element of Arkansas’ LTS 

for the first implementation period. As 

discussed in more detail in section III.D. 

of this preamble, the BART evaluation 

process consists of three components: 

(1) An identification of all the BARTeligible sources, (2) an assessment of 

whether those BART-eligible sources are 

in fact subject to BART and (3) a 

determination of any BART controls. 

ADEQ 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. ADEQ 

identified the BART-eligible sources in 

Arkansas by utilizing the three 

eligibility criteria in the BART 

Guidelines (70 FR 39158) and our 

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) began operation on or after 

August 6, 1962, and was in existence on 

August 6, 1977; and (3) potential 

emissions of any visibility-impairing 

pollutant from subject units are 250 tons 

or more per year. ADEQ initially 

screened its emissions inventory and 

permitting database to identify major 

facilities with emission units in one or 

more of the 26 BART source categories. 

Following this, ADEQ used its databases 


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22A copy of the boiler inspection report for the 

6A Boiler at the Georgia-Pacific Crossett Mill can 

be found in the docket for this proposed 

rulemaking. 

23The BART Guidelines define ‘‘in operation’’ as 

‘‘engaged in activity related to the primary design 

function of the source.’’ 

and records to identify facilities in these 

source categories with potential 

emissions of 250 tons per year (tpy) or 

more of the following visibility 

impairing pollutants: sulfur dioxide 

(SO2), nitrogen dioxide (NOX), 

particulate matter equal to or smaller 

than ten microns (PM10), volatile 

organic compounds (VOC) or ammonia 

(NH3). Using its databases and records, 

ADEQ then determined which of these 

facilities had units that were in 

existence on August 7, 1977 and began 

operation after August 7, 1962. ADEQ 

contacted the sources, when necessary, 

to obtain or confirm this information. 

From this, ADEQ determined there are 

18 facilities with BART-eligible units. 

Table 2 lists Arkansas’ BART-eligible 

sources, as identified by Arkansas in 

Table 9.1 of the RH SIP: 

TABLE 2—FACILITIES WITH BART-ELIGIBLE UNITS IN ARKANSAS

BART source category Facility name County Unit description 

Fossil fuel-fired steam electric plants of 

more than 250 MMBTU/hr heat input.

AEP Flint Creek Power Plant .................. Benton .................... Boiler 

AECC Carl E. Bailey Generating ............. Woodruff ................. Boiler 

AECC John L. McClellan Generating ...... Ouachita ................. Boiler 

Entergy Lake Catherine Plant ................. Hot Spring ............... Unit 4 Boiler 

Entergy Robert E. Ritchie Plant .............. Phillips .................... Unit 2 

Entergy White Bluff Plant ........................ Jefferson ................. Unit 1 

Unit 2 

Auxiliary Boiler 

Kraft pulp mills ............................................ Domtar Ashdown Mill ............................... Little River ............... No. 1 Power 

No. 2 Power 

Delta Natural Kraft ................................... Jefferson ................. Recovery Boiler 

Evergreen Packaging/International .......... Jefferson ................. No. 4 Recovery 

Georgia-Pacific Crossett Mill ................... Ashley ..................... 9A Boiler 

Green Bay Packaging .............................. Conway ................... Recovery Boiler 

Potlatch Forest Products/Clearwater ....... Desha ..................... Power Boiler 

Petroleum .................................................... Lion Oil Company .................................... Union ...................... No. 7 Catalyst 

Sulfur recovery ............................................ Albermarle Corporation South Plant ........ Columbia ................. Tail Gas 

Sintering plants ........................................... Big River Industries—Arkalite .................. Crittenden ............... Kiln A 

Chemical process plants ............................ Albermarle Corporation South Plant ........ Columbia ................. No. 1 Boiler 

No. 2 Boiler 

Future Fuels/Eastman Chemical ............. Independence ......... 3 Coal Boilers 

El Dorado Chemical Company ................ Union ...................... West Nitric Acid 

East Nitric Acid 

Nitric Acid 

We note that in chapter 15 of APC&E 

Regulation 19, contained in the RH SIP 

submittal we received on September 23, 

2008, and as revised by the submittal we 

received on August 3, 2010, ADEQ 

identified one more unit (not listed in 

Table 2), the 6A Boiler at the GeorgiaPacific Crossett Mill, as being BARTeligible. ADEQ did not identify the 6A 

Boiler as BART-eligible in the RH SIP 

narrative. Appendix 9.1A states the 6A 

Boiler began operation prior to August 

7, 1962, and that it falls out of the BART 

eligibility criteria because of its start of 

operations date. On September 27, 2011, 

ADEQ submitted supplemental 

information clarifying that the GeorgiaPacific Crossett Mill provided ADEQ a 

copy of a boiler inspection report for the 

6A Boiler, which states that the 

inspection of the new boiler took place 

on August 6, 1962, to determine if the 

boiler complied with the State and 

American Society of Mechanical 

Engineers (ASME) codes.22 However, 

ADEQ stated it cannot say with 

certainty whether the 6A boiler was in 

operation as of August 6, 1962, or at a 

later date.23 Since there is not sufficient 


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24On May 27, 1958, the Arkansas Department of 

Labor performed an annual inspection of the 

International Paper No. 1 and 2 Boilers. On June 26, 

1958, the Arkansas Department of Labor issued an 

inspection certificate to the International Paper 

Company for the No. 1 and 2 Boilers. Since the No. 

1 and 2 Boilers were in operation prior to August 

7, 1962, they fall out of the startup date criteria for 

BART eligibility. The inspection certificate for the 

can be viewed in the docket for this proposed 

rulemaking. 

25ADEQ Operating Air Permit for the Great Lakes 

Chemical Corporation—Central Plant (Permit No. 

1077–AOP–R1). This permit can be viewed at 

http://www.adeq.state.ar.us/ftproot/pub/

WebDatabases/PermitsOnline/Air/1077-AOPR1.pdf. 

26Note 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. 

27CENRAP 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. 

information to determine the date of 

start of operations of the 6A Boiler, we 

cannot make the determination that the 

boiler is not BART-eligible. Therefore, 

we are proposing to find that the 6A 

Boiler at the Georgia-Pacific Crossett 

Mill is BART-eligible. 

In the RH SIP, ADEQ identified one 

unit (the No. 4 recovery boiler) at 

International Paper/Evergreen Packaging 

as BART-eligible (shown in Table 2). 

ADEQ included two other units (the No. 

1 and 2 Power Boilers) at International 

Paper/Evergreen Packaging in its 

evaluation to determine what sources 

are subject to BART. The International 

Paper/Evergreen Packaging No. 1 and 

No. 2 Power Boilers are not BARTeligible because they were constructed 

and were in operation prior to August 

7, 1962.24 We agree that the No. 1 and 

2 Power Boilers at International Paper/ 

Evergreen Packaging are not BARTeligible. 

In the RH SIP, ADEQ did not identify 

Boilers SN–301A and SN–302A at the 

Great Lakes Chemical Plant as BARTeligible, but since these units were at 

one point believed to be BART-eligible, 

ADEQ included these units in its 

evaluation to determine what sources 

are subject to BART. EPA reviewed the 

federally enforceable operating permit 

for the Great Lakes Chemical Plant and 

determined that Boilers SN–301A and 

SN–302A are not BART-eligible because 

they are boilers with a heat input rating 

less than 250 MMBtu/hr and are not 

integral to the process, as the permit 

states they are used to supply heat to the 

process.25 The BART Guidelines 

provide that an individual fossil fuel 

boiler smaller than 250 MMBtu/hr that 

does not fall into source Category 1 (i.e., 

Fossil-fuel fired steam electric plants of 

more than 250 MMBtu/hr heat input), 

falls into one of the other source 

categories for BART eligibility only if it 

is an integral part of a process 

description at a plant. If the boiler is 

integral to the process description at a 

plant, it falls into the source category of 

the process which it serves. In general, 

if the boiler serves the process in any 

way beyond contributing heat, it is 

integral to the process. Based on 

information in the current operating air 

permit for the Great Lakes Chemical 

Plant, we agree that Boilers SN–301A 

and SN–302A are not BART-eligible. 

As discussed above, there is a 

discrepancy between the BART-eligible 

sources identified in the RH SIP 

narrative, and those identified in the 

State’s RH Rule. Because ADEQ 

submitted supplemental information on 

September 27, 2011, clarifying that it 

did not know with certainty the startup 

date of operations of the 6A Boiler at the 

Georgia-Pacific Crossett Mill, we are 

proposing to find that the 6A Boiler is 

BART-eligible. We are proposing to 

approve ADEQ’s identification of the 

remaining BART-eligible sources. 

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, ADEQ 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. 

The BART Guidelines direct states to 

address SO2, NOX and direct PM 

(including both PM10 and PM2.5) 

emissions as visibility-impairing 

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 Caney Creek and Upper 

Buffalo. Ammonia emissions in 

Arkansas are primarily due to area 

sources, such as livestock and fertilizer 

application. Because these are not point 

sources, they are not subject to BART. 

The emissions inventory prepared for 

the CENRAP modeling demonstrates 

that ammonia from point sources are not 

significant visibility-impairing 

pollutants in Arkansas. ADEQ further 

argued that only specific VOCs form 

secondary organic aerosols that affect 

visibility and that these compounds are 

a fraction of the total VOCs reported in 

Arkansas’ emissions inventory. ADEQ 

does not have the breakdown of VOC 

emissions necessary to model only those 

that impair visibility. Because 

CALPUFF, EPA’s prescribed screening 

model, cannot simulate formation of 

particles from anthropogenic VOCs, nor 

their visibility impacts, ADEQ did not 

evaluate emissions of VOCs in making 

BART determinations. We have 

reviewed this information and propose 

to agree with ADEQ’s decision to 

address only SO2, NOX, and PM as 

visibility impairing pollutants because 

VOC emissions from anthropogenic 

sources are not significant visibilityimpairing pollutants at Caney Creek and 

Upper Buffalo and ammonia emissions 

in Arkansas are primarily due to area 

sources. 

a. Modeling Methodology 

The BART Guidelines provide that 

states may choose to use the 

CALPUFF 26 modeling system or 

another appropriate model to predict 

the visibility impacts from a single 

source on a Class I area and to therefore, 

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). ADEQ used the CALPUFF 

modeling system to determine whether 

individual sources in Arkansas 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 Arkansas, developed 

the ‘‘CENRAP BART Modeling 

Guidelines’’.27 Stakeholders, including 


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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 

recommends, therefore sources were 

evaluated using the 1st High values 

instead of the 8th High values. The use 

of the 1st High modeling values was 

agreed to by EPA, representatives of the 

Federal Land Managers, and CENRAP 

stakeholders. We are proposing to find 

the chosen model and the general 

modeling methodology for screening 

modeling acceptable. 

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. 

Considering the number of sources 

affecting Arkansas’ Class I areas and the 

magnitude of each source’s impact, 

ADEQ used a contribution threshold of 

0.5 dv for determining which sources 

are subject to BART. We agree with the 

State’s selection of this threshold value. 

c. Sources Identified by ADEQ as 

Subject to BART 

Following the elimination of those 

sources that were found to have 

visibility impacts well below the 0.5 dv 

threshold, ADEQ identified the sources 

contained in Table 3 as being subject to 

BART. 

TABLE 3—SOURCES IN ARKANSAS SUBJECT TO BART 

Facility name BART emission units Source category Pollutants 

evaluated 

AECC Carl E. Bailey Generating Station ... Unit 1 ........................................................ fossil fuel-fired steam electric plants ........ SO2

NOX

PM10

AECC John L. McClellan Generating Station.Unit 1 ........................................................ fossil fuel-fired steam electric plants ........ SO2

NOX

PM10

AEP Flint Creek Power Plant ..................... Boiler No. 1 ............................................... fossil fuel-fired steam electric plants ........ SO2

NOX

PM10

Entergy Lake Catherine Plant ..................... Unit 4 ........................................................ fossil fuel-fired steam electric plants ........ SO2

NOX

PM10

Entergy White Bluff Plant ............................ Units 1, 2, and Auxiliary Boiler ................. fossil fuel-fired steam electric plants ........ SO2

NOX

PM10

Domtar Ashdown Mill .................................. Power Boilers No. 1 and 2 ....................... kraft pulp mill ............................................ SO2

NOX

PM10

In Appendix 9.2B of the RH SIP, 

ADEQ provided screening modeling 

results for all sources identified in the 

RH SIP as BART-eligible sources, as 

well as for the SN–301A and SN–302A 

Boilers at the Great Lakes Chemical 

plant, the No. 1 and No. 2 Power Boilers 

at International Paper/Evergreen 

Packaging, and the 6A and 9A Boilers at 

the Georgia-Pacific Crossett Mill (as 

discussed above). Our evaluation of 

these results showed that four facilities 

that ADEQ did not identify as subject to 

BART had modeled visibility impacts 

that exceed the 0.5 dv contribution 


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28Throughout this document, any reference to 

‘‘ADEQ modeling’’ refers to modeling performed or 

reviewed by ADEQ. 

29Memo from Joseph Paisie (Geographic 

Strategies Group, OAQPS) to Kay Prince (Branch 

Chief EPA Region 4) on Regional Haze Regulations 

threshold used by ADEQ to determine 

what sources are subject to BART. Our 

evaluation to determine whether these 

sources are subject to BART or not is 

discussed below: 

• As discussed in section V.D.1., 

ADEQ included the No. 1 and No. 2 

Power Boilers at International Paper/ 

Evergreen Packaging and the SN–301A 

and SN–302A Boilers at the Great Lakes 

Chemical plant in its modeling 

evaluation to determine what sources 

are subject to BART. As already 

discussed elsewhere in this proposed 

notice, we are proposing to approve 

ADEQ’s identification of these two 

sources as not BART-eligible and not 

subject to BART. 

• As discussed in section IV.D.2.a. of 

this proposed rulemaking, the original 

meteorological databases generated by 

CENRAP did not include observations 

as EPA guidance recommends. 

Therefore, in their evaluation to 

determine if a source exceeds the 0.5 dv 

contribution threshold at nearby Class I 

areas, states used the 1st high values 

(i.e., maximum value) of modeled 

visibility impacts instead of the 8th high 

values (i.e., 98th percentile value). The 

use of the 1st high modeled values was 

agreed to by EPA, representatives of the 

Federal Land Managers, and CENRAP 

stakeholders. ADEQ’s modeling shows 

that Future Fuels/Eastman Chemical has 

a modeled visibility impact of 0.711 dv 

at Hercules-Glade. Further examination 

of the modeling results reveals that only 

one day of the three years modeled 

exceeds the 0.5 dv contribution 

threshold value at any Class I area. 

Since only one day is projected above 

the threshold, we believe it is very 

unlikely that a refined modeling 

approach using updated meteorological 

data, which would allow for the use of 

the 98th percentile modeled visibility 

impact rather than the maximum 

impact, would show modeled impacts 

above the threshold. Therefore, we are 

proposing that this facility is not subject 

to BART. 

• The visibility modeling provided in 

Appendix 9.2B of the Arkansas RH SIP 

shows that the 9A Boiler of the GeorgiaPacific Crossett Mill has visibility 

impacts exceeding the 0.5 dv 

contribution threshold, with a visibility 

impact above 1 dv at Caney Creek and 

Hercules-Glade. EPA also reviewed 

ADEQ’s revised modeling for this 

source, which looked at the visibility 

impacts of both the 6A and 9A Boilers 

at the Georgia-Pacific Crossett Mill. 

Using updated emission rates, ADEQ’s 

revised modeling showed projected 

visibility impacts of the two boilers 

combined below the 0.5 dv threshold. 

The revised emission rates were based 

on stack test results and assumptions 

based on worst case monthly fuel usage, 

from the perspective of total emissions. 

However, from the data provided, it is 

unclear if the modeled emissions are 

representative of the actual maximum 

24 hour emissions from the highest 

emitting day over the modeled period. 

There is no supporting technical 

analysis discussing the assumptions 

made in the revised emission estimates 

and explaining how stack test data was 

used to estimate maximum emissions 

nor is fuel usage information provided 

for the modeled period. We are 

proposing to disapprove ADEQ’s 

determination that the Georgia-Pacific 

Crossett Mill’s 6A and 9A Boilers are 

not subject to BART because ADEQ has 

not modeled the visibility impact of the 

6A and 9A Boilers using acceptable 

estimates of maximum 24 hour 

emissions, and as a result we do not 

know if the boilers have a combined 

visibility impact below the 0.5 dv 

contribution threshold or not. Based on 

the permit allowables and available 

information, the two boilers are subject 

to BART and require a full BART 

analysis. 

We are proposing to approve ADEQ’s 

identification of subject to BART 

sources, except for ADEQ’s 

determination that the Georgia-Pacific 

Crossett Mill 6A and 9A Boilers are not 

subject to BART. 

3. BART Determinations 

The third step of a BART evaluation 

is to perform the BART analysis. BART 

is a source-specific control 

determination, based on consideration 

of several factors set out in section 

169A(g)(2) of the CAA. These factors 

include the costs of compliance and the 

degree of improvement in visibility 

associated with the use of possible 

control technologies. EPA issued BART 

Guidelines (Appendix Y to Part 51) in 

2005 to clarify the BART provisions 

based on the statutory and regulatory 

BART requirements (70 FR 39164). The 

BART Guidelines 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. 

We note the BART Guidelines 

(Appendix Y to part 51) provide that 

states must follow the guidelines in 

making BART determinations on a 

source-by-source basis for 750 MW 

power plants but are not required to use 

the process in the guidelines when 

making BART determinations for other 

types of sources. States with subject to 

BART units with a generating capacity 

less than 750 MW are strongly 

encouraged to follow the BART 

Guidelines in making BART 

determinations, but they are not 

required to do so. However, the 

requirement to perform a BART analysis 

that considers ‘‘the technology 

available, the costs of compliance, the 

energy and nonair quality 

environmental impacts of compliance, 

any pollution control equipment in use 

at the source, the remaining useful life 

of the source, and the degree of 

improvement in visibility which may 

reasonably be anticipated to result from 

the use of such technology,’’ is found in 

section 51.308(e)(1)(ii)(A) and the RHR, 

and applies to all subject to BART 

sources. 

All of the sources that are subject to 

BART presented in Table 3 are fossil 

fuel fired electricity generating units, 

with the exception of the Domtar 

Ashdown Mill, which is a kraft pulp 

mill. ADEQ performed BART 

determinations for these sources for 

NOx, SO2, and PM. 

We have found several problems in 

these BART determinations, which lead 

us to propose disapproval of some of 

ADEQ’s BART determinations. We 

discuss these problems in detail in the 

individual BART determination 

sections, and we summarize some 

general issues in the paragraphs that 

follow. 

For some sources, ADEQ did not 

adequately consider whether retrofit 

controls should be required based on a 

flawed analysis of the source’s potential 

visibility impacts. ADEQ assumed that 

if pre-control modeling 28 conducted on 

the basis of a single pollutant showed 

that the source’s emissions of the 

pollutant in question did not 

‘‘contribute’’ to visibility impairment, 

then further BART analysis for that 

pollutant was unnecessary. This 

approach is unacceptable. Due to the 

nonlinear nature and complexity of 

atmospheric chemistry and chemical 

transformation among pollutants, 

ideally all relevant pollutants should be 

modeled together to predict the total 

visibility impact at each Class I area 

receptor.29 At a minimum, NOX and SO2


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and Guidelines for Best Available Retrofit 

Technology (BART) Determinations, July 19, 2006. 

30 ‘‘States may choose to identify de minimis 

levels of pollutants at BART-eligible sources (but 

are not required to do so). De minimis values 

should be identified with the purpose of excluding 

only those emissions so minimal that they are 

unlikely to contribute to regional haze. Any de 

minimis values that you adopt must not be higher 

than the PSD applicability levels: 40 tons/yr for SO2

and NOX and 15 tons/yr for PM10. These de minimis 

levels may only be applied on a plant-wide basis.’’ 

40 CFR Appendix Y to part 51. 31 70 FR at 39131–39136. 

32The CALPUFF modeling system consists of a 

meteorological data pre-processor (CALMET), an air 

dispersion model (CALPUFF), and post-processor 

programs (POSTUTIL, CALSUM, CALPOST). The 

CALPUFF modeling system is the recommended 

model for conducting BART visibility analysis. 

33Arkansas Electric Cooperative Corporation Best 

Available Retrofit Technology Engineering Analysis 

prepared by Stephen Cain, October 20, 2006. 

emissions should be modeled together 

to determine the visibility impacts 

attributable to these pollutants when 

evaluating controls and combinations of 

controls in determining BART for a 

source. Predicting the impacts of PM on 

visibility is relatively straight-forward, 

unlike predicting the impacts of SO2

and NOX. Using CALPUFF on a 

pollutant specific basis to model only 

the impact of PM emissions on visibility 

is an acceptable approach to determine 

whether a source should be subject to 

review for PM controls, or alternatively, 

that the source is not subject to BART 

for PM. ADEQ applied a threshold of 0.5 

dv for determining whether a source 

‘‘contributes’’ to visibility impairment 

on a per-pollutant basis. As discussed 

above, the State selected a threshold of 

0.5 dv for the initial screening modeling 

that included all pollutants. Clearly, a 

lower threshold value is needed in 

evaluating pollutant-specific modeling 

for sources that emit more than one 

visibility impairing pollutant. 

Furthermore, this approach is only 

acceptable for PM-specific modeling. 

We note that a State may establish de 

minimis levels of emissions (applicable 

on a plant-wide basis) of visibility 

impairing pollutants to exclude some 

sources from further evaluation when 

the emissions are so minimal that they 

are unlikely to contribute to regional 

haze.30

For some BART determinations, 

ADEQ did not properly determine 

BART, but instead concluded that the 

presumptive limits in the BART 

Guidelines could be adopted in place of 

a careful source-specific analysis of the 

appropriate level of controls. As noted 

above, EPA issued BART Guidelines in 

2005 that address the BART 

determination process by laying out a 

step by step process for taking into 

consideration the factors relevant to a 

BART determination. In that 

rulemaking, EPA also established 

presumptive BART limits for certain 

electric generating units (EGUs) located 

at power plants 750 MW or greater in 

size based variously on the size of the 

unit, the type of unit, the type of fuel 

used, and the presence or absence of 

controls.31 Having identified controls 

that the Agency considered to be 

generally cost-effective across all 

affected units, the EPA took into 

account the substantial degree of 

visibility improvement anticipated to 

result from the use of such controls on 

these EGUs and concluded that such 

BART-eligible sources should at least 

meet the presumptive limits. The 

presumptive limits accordingly are the 

starting point in a BART determination 

for these units—unless the State 

determines that the general assumptions 

underlying EPA’s analysis are not 

applicable in a particular case. EPA did 

not provide that States could avoid a 

source-specific BART determination by 

adopting the presumptive limits. In fact, 

nothing on the record would support 

the conclusion that the presumptive 

limits represent the ‘‘best available 

retrofit controls’’ for all EGUs at these 

large power plants. EPA did not address 

the question of whether in specific cases 

more stringent controls would be called 

for but rather simply concluded that it 

could not reach a generalized 

conclusion as to the appropriateness of 

more stringent controls for categories of 

EGUs. As a result, the BART Rule does 

not establishing a ‘‘safe harbor’’ from 

more stringent regulation under the 

BART provisions. We have consistently 

informed ADEQ in comments to its draft 

SIP and in conversations that foregoing 

a BART analysis is not acceptable. 

For the BART determinations for 

which ADEQ did perform a full BART 

analysis that considered the statutory 

factors under section 51.308(e)(1)(ii)(A), 

we are proposing to find that ADEQ did 

not adequately consider one or more of 

the factors it is required to consider in 

determining whether retrofit controls 

should be required. 

For more details, please see our 

evaluation of the BART determination 

for each subject to BART unit, below, 

and the TSD. 

a. AECC Bailey Unit 1 and AECC 

McClellan Unit 1 BART Determinations 

The AECC Bailey Unit 1 and the 

AECC McClellan Unit 1 are BARTeligible sources. The AECC Bailey Unit 

1 is a boiler with a gross output of 122 

MW and a maximum heat input rate of 

1350 MMBtu/hr, and is currently 

permitted to burn both natural gas and 

fuel oil. The fuel oil burned at the plant 

is subject to an operating air permit 

sulfur content limit of 2.3% by weight. 

The AECC McClellan Unit 1 is a boiler 

with a gross output of 134 MW and a 

maximum heat input rate of 1436 

MMBtu/hr, and is currently permitted to 

burn both natural gas and fuel oil. The 

fuel oil burned at the plant is subject to 

an operating air permit sulfur content 

limit of 2.8% by weight. 

Regarding BART for NOX and PM, 

ADEQ conducted pollutant specific precontrol CALPUFF 32 modeling for the 

AECC Bailey Unit 1 and the AECC 

McClellan Unit 1. AECC stated that the 

results of the NOX modeling show that 

NOX does not cause or contribute to 

visibility impacts.33 Based on this, 

AECC determined and ADEQ agreed it 

was not necessary to make a BART 

determination for NOX for either the 

AECC Bailey Unit 1 or AECC McClellan 

Unit 1. However, the ADEQ’s modeling 

results presented indicate that the 

predicted visibility impacts from NOX

are as high as 0.347 dv at Mingo due to 

emissions from the AECC Bailey Unit 1, 

and 0.421 dv at Caney Creek due to 

emissions from the AECC McClellan 

Unit 1. As stated above, NOX and SO2

emissions should be modeled together 

due to the nonlinear nature and 

complexity of atmospheric chemistry 

and chemical transformation among 

pollutants. Evaluation of the screening 

modeling results for these units reveals 

that on some of the most impacted days, 

NOX is a significant contributor to the 

visibility impairment due to these units. 

Post-control modeling performed by 

ADEQ, applying the use of 1% sulfur 

fuel, show that these units would 

continue to cause or contribute to 

visibility impairment at a number of 

Class I areas, with NOX emissions 

responsible for over 50% of the 

impairment on some days under this 

control scenario. In light of the 

relatively high impacts due to NOX, a 

combination of NOX and SO2 controls 

may prove to be cost-effective and 

provide for substantial visibility 

improvement and should therefore be 

evaluated. 

For PM BART, AECC decided and 

ADEQ agreed that PM does not cause 

visibility impacts because the PM 

emissions are less than those of NOX at 

these units. This conclusion is not 

supported in the record by PM visibility 

modeling results, additional technical 

analysis, or reference to a permit limit 

for PM that restricts emissions below a 

level that will impact visibility. Neither 

the State nor AECC have completed a 

BART analysis that considers the 


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34Connecticut Department of Environmental 

Protection (DEP). ‘‘22a–174–19a: Control of Sulfur 

Dioxide Emissions from Power Plants and Other 

Large Stationary Sources of Air Pollution,’’ 

Regulations of Connecticut State Agencies, Title 

22a: Abatement of Air Pollution, December 28, 

2000. http://www.dep.state.ct.us/air2/regs/

mainregs/sec19a.pdf. 

35New York State Department of Environmental 

Conservation (DEC). ‘‘Subpart 225–1: Fuel 

Composition and Use-Sulfur Limitations,’’ 

Environmental Conservation Rules and Regulations, 

May 8, 2005. http://www.dec.state.ny.us/website/

regs/subpart225_1.html. 

36MANE–VU is an RPO that includes the 

following states: Maine, New Hampshire, Vermont, 

Massachusetts, Rhode Island, Connecticut, New 

York, New Jersey, Pennsylvania, Maryland, 

Delaware, and also the District of Columbia. 

37See 76 FR 27973. 

statutory factors under section 

51.308(e)(1)(ii)(A) that states are 

required to consider in determining 

what type and level of control is BART 

for a source for NOX and PM, or fully 

demonstrated that these units have 

sufficient pollution controls in place for 

these pollutants such that additional 

controls would likely achieve very low 

emissions reductions, have minimal 

visibility benefit, and not be costeffective. Therefore, we are proposing to 

disapprove the NOX and PM BART 

determinations for these two units. 

Regarding BART for SO2 for the two 

sources, AECC performed a BART 

analysis to determine what retrofit 

controls are BART for AECC Bailey Unit 

1 and AECC McClellan Unit 1. In Step 

1 of this BART analysis, AECC 

identified use of fuel oil with 1% sulfur 

content and installation of a scrubber as 

the only two control options available. 

This is a problem because 1% sulfur 

fuel oil is not the maximum level of 

control available when it comes to the 

use of low sulfur fuel as a control 

strategy for SO2 emissions. After 

completing the remaining steps of the 

BART analysis, AECC determined and 

ADEQ agreed that BART for the AECC 

Bailey Unit 1 and the AECC McClellan 

Unit 1 is use of fuel oil with 1% sulfur 

content. Our evaluation of AECC’s 

BART analysis beyond Step 1 can be 

found in the TSD. We are not discussing 

in this proposed notice our evaluation 

of AECC’s BART analysis for the AECC 

Bailey Unit 1 and the AECC McClellan 

Unit 1 beyond Step 1, as we are 

proposing that AECC did not properly 

complete the first step of the BART 

analysis and thus we find that AECC 

and ADEQ did not properly follow the 

requirements of section 

51.308(e)(1)(ii)(A) in determining BART. 

Specifically, we are proposing that 

AECC and ADEQ did not properly ‘‘take 

into consideration the technology 

available’’ by failing to consider the 

maximum level of control each control 

option is capable of achieving. The 

BART Guidelines (Appendix Y to Part 

41) provide that in identifying all 

options, you must identify the most 

stringent option (i.e., maximum level of 

control each technology is capable of 

achieving) as well a reasonable set of 

options for analysis. The requirement to 

consider the most stringent level of 

control when making BART 

determinations is also found in the RHR 

(64 FR 35740), which provides that in 

establishing source specific BART 

emission limits, the State should 

identify and consider in the BART 

analysis the maximum level of emission 

reduction that has been achieved in 

other recent retrofits at existing sources 

in the source category. The visibility 

regulations define BART as ‘‘an 

emission limitation based on the degree 

of reduction achievable through the 

application of the best system of 

continuous emission reduction.’’ Since 

recent retrofits at existing sources 

provide a good indication of the current 

‘‘best system’’ for controlling emissions, 

these controls must be considered in the 

BART analysis. In considering use of 

fuel oil with low sulfur content as a 

control option in the BART analysis, 

AECC did not identify and consider the 

maximum level of control achievable 

from the use of low sulfur fuel oil, and 

thus the BART analysis is flawed. 

Sulfur content in fuel oil currently 

can be found in industry to be 0.5% by 

weight or less. AECC should have 

considered the use of fuel oil with 0.5% 

sulfur content or less in the BART 

analysis for the two units in question. 

We are aware of several fossil-fuel fired 

steam electric plants throughout the 

country that are currently limited by 

permit to burn fuel oil with a sulfur 

content of 0.5% or less by weight. 

Connecticut limits the sulfur content of 

fuel oil to a maximum 0.3%34 and New 

York requires facilities to comply with 

the use of fuel oil with varying sulfur 

content limits, with facilities in New 

York City being required to use fuel oil 

with a maximum 0.3% sulfur content.35

Lowering the sulfur content in fuel oil 

is also a part of the long-term strategy 

recommended by the Mid-Atlantic/ 

Northeast Visibility Union (MANE–VU) 

states to reduce and prevent regional 

haze.36 The MANE–VU states in the 

inner zone (New Jersey, New York, 

Delaware, and Pennsylvania) plan to 

reduce the sulfur content of No. 6 

residual fuel oil to 0.3–0.5% sulfur by 

weight by no later than 2012.37

Therefore, the use of fuel oil with a 

0.5% sulfur content or lower is 

technically feasible and either AECC or 

ADEQ should have evaluated its cost 

effectiveness for the AECC Bailey Unit 

1 and the AECC McClellan Unit 1. In 

addition, an operating air permit 

restriction to use only natural gas as the 

fuel source for the two units would have 

also been acceptable. As part of the 

BART analysis, ADEQ and/or AECC 

must perform a cost analysis in which 

all cost estimates are properly 

documented and must evaluate the 

visibility impacts of all technically 

feasible control options considered 

before making a BART determination. 

Therefore, for the reasons expressed 

above, we are proposing to disapprove 

the SO2, NOX, and PM BART 

determinations for the AECC Bailey 

Unit 1 and the AECC McClellan Unit 1. 

b. AEP Flint Creek No. 1 Boiler BART 

Determination 

The AEP Flint Creek No. 1 Boiler is 

a BART-eligible source. The unit has a 

gross output of 558 MW and a 

maximum heat input rate of 6324 

MMBtu/hr, and burns primarily low 

sulfur western coal, but can also 

combust fuel oil and tire derived fuels 

(TDF). Fuel oil firing is only allowed 

during startup and shutdown of the 

boiler, startup and shutdown of the 

pulverizer mills, for flame stabilization 

when the coal is frozen, for fuel oil tank 

maintenance, to prevent boiler tube 

failure in extreme cold weather, and 

when the unit is offline for 

maintenance. 

Regarding BART for PM, ADEQ 

conducted pre-control CALPUFF 

modeling for the AEP Flint Creek No. 1 

Boiler showing that PM10 and PM2.5

emissions from the source have minimal 

visibility impacts at each Class I area 

within 300 km. Based on this, AEP 

decided and ADEQ agreed that the 

existing PM emission limit in the 

operating air permit, which is 

achievable through the use of the 

existing electrostatic precipitator (ESP), 

is BART for PM for AEP Flint Creek No. 

1 Boiler. We reviewed the CALPUFF 

visibility modeling submitted by ADEQ 

for AEP Flint Creek No. 1 Boiler, and 

agree that PM10 and PM2.5 emissions 

from the source have minimal visibility 

impacts at each Class I area within 300 

km. As explained in section IV.D.3 of 

this proposed rulemaking, using 

CALPUFF on a pollutant specific basis 

to model only the impact of PM 

emissions on visibility is an acceptable 

approach to determine whether a source 

should be subject to review for PM 

controls. In the case of the AEP Flint 

Creek No. 1 Boiler, we have found that 

the visibility impact due to PM 

emissions alone is so minimal such that 

the installation of any additional PM 

controls on the unit would likely 


jlentini on DSK4TPTVN1PROD with PROPOSALS2
Federal Register / Vol. 76, No. 200 / Monday, October 17, 2011 / Proposed Rules 64203 

38ADEQ Operating Air Permit for AEP-Flint 

Creek Power Plan (Permit No. 0276–AOP–R5). This 

permit can be viewed at http:// 

www.adeq.state.ar.us/ftproot/pub/WebDatabases/ 

PermitsOnline/Air/0276-AOP-R5.pdf. 

39The ‘‘presumptive limits’’ are the rebuttable 

specific limits established in the BART Rule for SO2

and NOX for certain EGUs based on fuel type, unit 

size, cost effectiveness, and the presence or absence 

of pre-existing controls. 

40ADEQ’s CALPUFF visibility modeling 

indicates the highest modeled visibility impact of 

AEP Flint Creek No. 1 Boiler on nearby Class I areas 

is: 3.970 Ddv at Caney Creek; 3.781 Ddv at Upper 

Buffalo; 3.983 Ddv at Hercules Glade; 2.596 Ddv at 

Mingo; 1.420 Ddv at Sipsey. ADEQ’s post-control 

visibility modeling shows that the State’s BART 

determinations would result in the source still 

causing visibility impairment at Caney Creek (1.573 

Ddv), Upper Buffalo (2.089 Ddv), and Hercules 

Glade (1.541 Ddv), and contributing to visibility 

impairment at Mingo (0.927) (Appendix 9.2B of the 

Arkansas Regional Haze SIP). 

41See, e.g., William J. Gretta and others, The SCR 

Retrofit Design for the Seminole Generating Station, 

PowerGen, 2008, Hitachi SCR at Seminole Electric 

Delivers 0.04 lb/MMBtu NOX (Preliminary Results), 

FGD and DeNOX Newsletter, December 2009, No. 

380, and NOX CEMS data reported to Clean Air 

Markets. 

42Clay Erickson, Robert Lisauskas, and Anthony 

Licata, What New in SCRs, DOE’s Environmental 

Control Conference, May 16, 2006, p. 28. Available 

here: http://www.netl.doe.gov/publications/

proceedings/06/ecc/pdfs/Licata.pdf; LG&E Energy, 

Selective Catalytic Reduction: From Planning to 

Operation, Competitive Power College, December 

2005, p. 75–77. 

43See also Sargent & Lundy, IPM Model— 

Revisions to Cost and Performance for APC 

Technologies, SDA FGD Cost Development 

Methodology, Final, August 2010, p. 1 (‘‘It should 

be noted that the lowest available SO2 emission 

guarantees, from the original equipment 

manufacturers of SDA FGD systems, are 0.06 lb/ 

MMBtu.’’). 

44 Georgia Environmental Protection Division, 

Longleaf Energy Station, Permit No. 4911–099– 

0033–P–01–0, April 9, 2010. Available at: http:// 

airpermit.dnr.state.ga.us/gaairpermits/Permit

PDF.aspx?id=PDF-PI-18499. 

45U.S. EPA, Region 9, Prevention of Significant 

Deterioration Permit, Desert Rock Energy Company, 

July 31, 2008. Available at: http://

www.regulations.gov/search/Regs/home.html

#docketDetail?R=EPA-R09-OAR-2007-1110. 

achieve very low emissions reductions, 

have minimal visibility benefit, and not 

be cost-effective. Therefore, we are 

proposing to approve ADEQ’s 

determination that PM BART for AEP 

Flint Creek No. 1 Boiler is the existing 

PM emission limit. The federally 

enforceable operating air permit for the 

source sets the PM emission limit for 

the unit at 0.1 lb/MMBtu.38

Regarding BART for SO2 and NOX, 

neither AEP nor ADEQ performed a 

BART analysis that considered the 

statutory factors states are required to 

consider in determining what retrofit 

controls are BART for the AEP Flint 

Creek No. 1 Boiler. Instead, AEP 

determined and ADEQ agreed that 

BART for SO2 is the presumptive limit 

of 0.15 lb/MMBtu and that BART for 

NOX is the presumptive limit of 0.23 lb/ 

MMBtu for AEP Flint Creek No. 1 

Boiler.39 We are aware that the AEP 

Flint Creek Power Plant has a 558 MW 

generating capacity, and is therefore not 

required to follow the BART Guidelines 

in making BART determinations for the 

No. 1 Boiler. However, this facility and/ 

or the State must still conduct a BART 

analysis as specified in 40 CFR 

51.308(e)(1)(ii)(A), which provides that: 

The determination of BART must be based 

on an analysis of the best system of 

continuous emission control technology 

available and associated emission reductions 

achievable for each BART-eligible source that 

is subject to BART within the State. In this 

analysis, the State must take into 

consideration the technology available, the 

costs of compliance, the energy and nonair 

quality environmental impacts of 

compliance, any pollution control equipment 

in use at the source, the remaining useful life 

of the source, and the degree of improvement 

in visibility which may reasonably be 

anticipated to result from the use of such 

technology. 

Therefore, we are proposing to 

disapprove ADEQ’s BART finding since 

neither AEP nor ADEQ conducted a 

BART analysis considering the best 

system of controls for BART for SO2 and 

NOX for AEP Flint Creek No. 1 Boiler. 

The source and/or ADEQ should have 

performed a BART analysis for SO2 and 

NOX. Controls achieving more than the 

SO2 and NOX presumptive limits are 

available and should be considered in 

the BART analysis, especially 

considering the magnitude of the 

visibility impact of the AEP Flint Creek 

No. 1 Boiler on the Class I areas within 

300 km.40 For instance, selective 

catalytic reduction (SCR) controls are 

routinely designed and have routinely 

achieved a NOX control efficiency of 

90% and a NOX emission rate as low as 

0.04 lb/MMBtu,41 based on a 30-day 

rolling average. Furthermore, SCR 

system designers analyzed EPA’s Clean 

Air Market’s CEMS data to determine 

the NOX levels that are currently being 

achieved by over 100 SCR-equipped 

coal-fired boilers, and found that 25 of 

these units are achieving NOX emissions 

less than 0.05 lb/MMBtu on an hourly 

average basis.42 Flue gas desulfurization 

(FGD) units (i.e., wet and dry scrubbers), 

are a type of post-combustion control for 

SO2 emissions. In a report for the 

National Lime Association, Sargent & 

Lundy stated that vendors guarantee 

SO2 reduction efficiencies of up to 95%, 

or as low as 0.06 lb/MMBtu SO2 for dry 

scrubbers.43 The Longleaf Energy 

Station in Georgia has two 600 MW 

boilers that burn coal and are equipped 

with a dry scrubber capable of achieving 

SO2 emissions of 0.065 lb/MMBtu on a 

30-day rolling average when the 

uncontrolled SO2 emission rate is less 

than or equal to 1 lb/MMBtu.44 The 

Desert Rock Energy Company, a 1500 

MW coal fired power plant in New 

Mexico, is equipped with a wet scrubber 

and has an SO2 emission limit of 0.060 

lb/MMBtu, averaged over a 24-hour 

period.45 We note that a 24-hour average 

is much more stringent than a 30-day 

rolling average. 

Therefore, for the reasons expressed 

above, we are proposing to disapprove 

ADEQ’s determination of SO2 and NOX

BART for the AEP Flint Creek No. 1 

Boiler. 

c. Entergy Lake Catherine Unit 4 BART 

Determination 

The Entergy Lake Catherine Unit 4 is 

a BART-eligible source. Unit 4 is a 

combustion engineering tilting 

tangential fired boiler powering a 552 

MW generator. The unit has a maximum 

heat input rate of 5850 MMBtu/hr and 

burns primarily natural gas with No. 6 

fuel oil as the secondary fuel. There is 

currently no emission control 

equipment connected to the boiler. 

Class I areas within 300 km of the 

facility include Caney Creek, Upper 

Buffalo, and Hercules Glades. 

Since Unit 4 is permitted to burn both 

natural gas and No. 6 fuel oil, ADEQ 

made BART determinations for both 

natural gas firing and fuel oil firing 

scenarios. The Arkansas RH SIP 

contains the CALPUFF pre-control 

modeling files for the natural gas firing 

scenario, and ADEQ also provided the 

modeling files for the fuel oil firing 

scenario. CALPUFF post-control 

modeling results for both gas and oil 

firing were also included in the 

Arkansas RH SIP. In the State’s 

September 27, 2011 supplemental 

submittal, ADEQ brought to our 

attention that per an inspection report 

dated July 28, 2011, Entergy Lake 

Catherine Unit 4 is no longer capable of 

burning fuel oil. ADEQ noted that the 

fuel tanks at the source have been 

emptied and the pipework necessary to 

burn fuel oil is in the process of being 

removed. ADEQ stated the source does 

maintain the ability to burn natural gas. 

We note that since the source has not 

modified its permit and ADEQ has not 

revised its RH SIP to reflect this change, 

we are not disregarding the BART 

emission limits for the source for fuel 

oil firing in this proposed rulemaking. 

Regarding BART for SO2 and PM for 

the natural gas firing scenario, Entergy 

stated that most of the visibility-causing 

emissions from Unit 4 are due to NOX

since SO2 and PM emissions from 

natural gas-fired boilers are generally 

very low. Therefore, for the natural gas 


jlentini on DSK4TPTVN1PROD with PROPOSALS2
64204 Federal Register / Vol. 76, No. 200 / Monday, October 17, 2011 / Proposed Rules 

46See ADEQ Operating Air Permit for Entergy 

Arkansas Inc.-Lake Catherine Plant (Permit No. 

1717–AOP–R4). This permit can be viewed at 

http://www.adeq.state.ar.us/ftproot/pub/

WebDatabases/PermitsOnline/Air/1717-AOPR4.pdf. 

47Our comments on this matter are documented 

in Appendix 9.3B of the Arkansas RH SIP. 

48 40 CFR 72.2 defines a peaking unit as ‘‘[a] unit 

that has (i) An average capacity factor of no more 

than 10.0 percent during the previous three 

calendar years and (ii) A capacity factor of no more 

than 20.0 percent in each of those calendar years.’’ 

49 40 CFR 72.2 defines capacity factor as either 

‘‘(1) The ratio of a unit’s actual annual electric 

output (expressed in MWe/hr) to the unit’s 

nameplate capacity (or maximum observed hourly 

gross load (in MWe/hr) if greater than the 

nameplate capacity) times 8760 hours; or (2) The 

ratio of a unit’s annual heat input (in million British 

thermal units or equivalent units of measure) to the 

unit’s maximum rated hourly heat input rate (in 

million British thermal units per hour or equivalent 

units of measure) times 8,760 hours. 

50Table 2–1 of the ‘‘BART Analysis for Lake 

Catherine Plant- Unit 4,’’ prepared by Robert Paine, 

December 2006 notes that Unit 4 was operated 

6,988 hours in 2001 (79.7% utilization); 5,651 hours 

in 2002 (64.5% utilization); 3,972 hours in 2003 

(45.3% utilization); 1,534 hours in 2004 (17.5% 

utilization); and 2,059 hours in 2005 (23.5% 

utilization). 

firing scenario for Unit 4, Entergy made 

no BART determination for SO2, and 

determined that BART for PM is the 

existing PM emission limit in the 

operating air permit. ADEQ agreed with 

the Entergy’s determination. Revisions 

to the State’s RH Rule, Chapter 15 of 

APC&E Commission Regulation 19, 

which were submitted to us on August 

3, 2010, state the existing PM emission 

limit as of October 15, 2007 is PM BART 

for the natural gas firing scenario for 

Entergy Lake Catherine Unit 4. This 

corresponds to an emission limit of 45 

lb/hr PM.46 We agree that SO2 and PM 

emissions from natural gas-fired boilers 

are generally very low, and therefore we 

are proposing to approve ADEQ’s 

decision not to make a BART 

determination for SO2 for the natural gas 

firing scenario for Unit 4. Since we have 

found that the visibility impact of Unit 

4 due to PM emissions alone (from 

natural gas firing) is so minimal such 

that the installation of any additional 

PM controls on the unit would likely 

achieve very low emissions reductions, 

have minimal visibility benefits, and not 

be cost-effective, we are also proposing 

to approve ADEQ’s determination that 

BART for PM for Unit 4 for the natural 

gas firing scenario is the existing PM 

emission limit as of October 15, 2007, or 

45.0 lb/hr. 

Regarding BART for NOX for the 

natural gas firing and fuel oil firing 

scenarios, Entergy conducted a BART 

analysis to determine what retrofit 

controls are BART for Lake Catherine 

Unit 4. In Step 1 of the BART analysis 

for NOX, Entergy considered a 

combination of the following NOX

combustion controls for the natural gas 

firing scenario: boiler tuning, burners 

out of service (BOOS), induced flue gas 

recirculation (IFGR), overfire air (OFA), 

and low NOX burners (LNB). Entergy 

considered a combination of the 

following NOX combustion controls for 

the fuel oil firing scenario: boiler tuning, 

boiler modifications, BOOS, and forced 

flue gas recirculation (FFGR). However, 

Entergy did not consider postcombustion controls for NOX, such as 

selective catalytic reduction (SCR) and 

selective non-catalytic reduction 

(SNCR), even though these controls are 

technically feasible and available 

technologies for reducing NOX

emissions currently used by similar 

facilities. We provided comments to 

ADEQ to this effect on May 1, 2007.47

In response to our comments, Arkansas 

included in its RH SIP submittal the 

results of a computerized model it 

obtained from Entergy, which according 

to the source, evaluated Unit 4’s 

performance and the capital and 

operation and maintenance costs 

associated with each identified control 

technology. Entergy reported that the 

results of the computerized model 

showed that post-combustion controls, 

such as SCR and SNCR, had a cost that 

would be uneconomical to install. The 

results of this computer model are 

discussed further in our discussion of 

Step 4 of the BART analysis. 

For Step 3 of the NOX BART analysis, 

Entergy evaluated the control 

effectiveness of the control options 

considered in Step 1 for both the natural 

gas and fuel oil firing scenarios. We 

generally agree with Entergy’s 

evaluation of the control effectiveness of 

all control options considered. In Step 

4 of the BART analysis, Entergy 

considered the costs of compliance for 

each control option. In evaluating the 

costs of compliance, Entergy analyzed 

the cost-effectiveness in annualized 

dollars per ton of NOX removed ($/ton) 

of the control options identified in Step 

1 of the BART analysis for NOX for the 

natural gas and fuel oil firing scenarios. 

We note there are two flaws in Entergy’s 

cost-analysis. Entergy provided no 

documentation or detailed breakdown 

of the cost estimates. The results of the 

computer model the source used to 

determine the cost-effectiveness of postcombustion controls also did not 

provide documentation or a detailed 

breakdown of the cost estimates. We 

have no basis to verify the validity of 

neither the cost estimates nor Entergy’s 

determination based on the cost 

estimation analysis for BART. The basis 

for cost estimates should be 

documented either with data supplied 

by a vendor (i.e., budget estimates or 

bids) or by a referenced source. This 

was not done in the BART analysis. 

Furthermore, Unit 4 is a peaking unit,48

and Entergy attempted to account for 

this by assuming a 10% capacity 

factor 49 in the calculation of the metrics 

for tons removed and $/ton removed for 

all control options considered in Step 1 

of the BART analysis. The computer 

model Entergy used to estimate the cost 

effectiveness of post-combustion 

controls likewise assumed a 10% 

capacity factor in the calculation of the 

metrics for tons removed and $/ton 

removed. Given that there are no permit 

requirements in place that would limit 

the operation of this unit to 10% 

capacity, the facility can legally be 

operated well above the 10% capacity 

factor assumed by Entergy. Thus, any 

cost effectiveness analysis based on a 

10% capacity factor is likely to 

significantly inflate the cost per ton of 

controlling this unit. In support of the 

10% capacity utilization factor, Entergy 

stated that the unit has operated, on 

average, at a capacity of 6.9% for the 

past three years. However, past use of 

this unit was much higher— 

approximately 46% on average—over 

the 2001–2005 period.50 Given the 

variability in capacity utilization of this 

unit over the past ten years, the 

assumed 10% capacity utilization 

should be supported by an enforceable 

limit. Therefore, we are proposing to 

disapprove ADEQ’s NOX BART 

determination for both the natural gas 

and fuel oil firing scenarios for Lake 

Catherine Unit 4. 

For SO2 BART for the fuel oil-firing 

scenario, Entergy identified only one 

available control option in Step 1 of the 

BART analysis- use of fuel oil with low 

sulfur content. ADEQ agreed with the 

source’s decision. Entergy only 

considered the use of fuel oil with 1%, 

0.5%, and 0.2% sulfur content by 

weight. We note use of fuel oil with 1% 

sulfur content is the base case, as 

Entergy stated the source’s current Title 

V permit limits the sulfur content of fuel 

oil used to 1%. Entergy did not consider 

any post-combustion SO2 controls in the 

BART analysis, even though postcombustion control technologies, such 

as wet and dry scrubbers, are currently 

being used by comparable facilities to 

control SO2 emissions. As such, Entergy 

did not identify and consider control 

technologies that are capable of the 

maximum level of control that is 

achievable, as is required by the BART 

guidelines and the RHR. In Step 3 of the 


jlentini on DSK4TPTVN1PROD with PROPOSALS2
Federal Register / Vol. 76, No. 200 / Monday, October 17, 2011 / Proposed Rules 64205 

51ADEQ Operating Air Permit for Entergy 

Services Inc.—White Bluff Plant (Permit No. 0263– 

AOP–R6). This permit can be viewed at http:// 

www.adeq.state.ar.us/ftproot/pub/WebDatabases/

PermitsOnline/Air/0263-AOP-R6.pdf. 

BART analysis, Entergy considered the 

control effectiveness of all technically 

feasible control options identified in 

Step 1 by using AP–42 factors for 1%, 

0.5%, and 0.2% sulfur residual oil to 

determine the amount of sulfur dioxide 

emissions that would be eliminated by 

use of low sulfur fuel oil. Entergy found 

that based on a 10% capacity factor, use 

of 0.5% sulfur fuel oil would result in 

1,059 tpy SO2 removed from the 

baseline and use of 0.2% sulfur fuel oil 

would result in 1,802 tpy SO2 removed 

from the baseline. In Step 4 of the BART 

analysis, Entergy considered the costs of 

compliance for each control option. 

Entergy provided no documentation or 

detailed breakdown of the costs 

estimates for low sulfur fuel oil. 

Therefore, we have no basis to verify the 

validity of either the cost estimates or 

ADEQ’s BART determination based on 

the cost estimation. The basis for cost 

estimates should be documented, and 

should clearly indicate the amount of 

fuel oil that corresponds to the annual 

cost listed in the cost-analysis. After 

conducting post-control visibility 

modeling, Entergy determined and 

ADEQ agreed that SO2 BART for the fuel 

oil firing scenario is an SO2 emission 

limit of 0.562 lb/MMBtu on a 30 day 

rolling average. The RH SIP provides 

conflicting information on whether this 

emission limit corresponds to use of 1% 

or 0.5% sulfur fuel oil. On September 

27, 2011, ADEQ submitted a 

supplemental submittal clarifying that 

the 0.562 lb/MMBtu emission limit 

corresponds to use of 0.5% sulfur 

content fuel oil. However, for the 

reasons discussed above, we are 

proposing to find that the source and 

ADEQ did not properly follow the 

requirements of section 

51.308(e)(1)(ii)(A) in determining SO2

BART for the fuel oil firing scenario. 

Specifically, we are proposing that 

ADEQ did not properly take into 

consideration ‘‘the technology 

available’’ and ‘‘the costs of 

compliance.’’ 

Regarding BART for PM for the fuel 

oil firing scenario, Entergy identified the 

PM10 emission rates associated with use 

of 1%, 0.5%, and 0.2% sulfur fuel oil. 

Entergy determined PM BART for Unit 

4 for the fuel oil firing scenario is 0.037 

lb/MMBtu on a 30 day rolling average. 

ADEQ’s September 27, 2011 

supplemental submittal clarified that 

this PM emission limit corresponds to 

use of 0.5% sulfur content fuel oil. 

ADEQ and Entergy did not consider any 

post-combustion controls in the BART 

analysis for PM for the fuel oil firing 

scenario. We note the use of a wet 

scrubber system that controls both SO2

and PM emissions may prove to be costeffective and provide for substantial 

visibility improvement and should 

therefore be considered in Unit 4’s 

BART analysis. 

We are proposing to find that Entergy 

and ADEQ did not properly follow the 

requirements of section 

51.308(e)(1)(ii)(A) in determining BART 

for NOX for both the natural gas and fuel 

oil firing scenarios and BART for SO2

and PM for the fuel oil firing scenario 

for the Entergy Lake Catherine Unit 4. 

Specifically, we are proposing that 

ADEQ did not properly take into 

consideration ‘‘the technology 

available’’ and ‘‘the costs of 

compliance.’’ For the reasons identified 

above, we are proposing to disapprove 

ADEQ’s BART determinations for PM, 

NOX, and SO2 under oil firing 

conditions, and NOX under natural gas 

firing conditions. We are proposing to 

approve ADEQ’s BART determination 

for the Entergy Lake Catherine Unit 4 for 

PM under gas firing conditions and 

ADEQ’s decision to make no BART 

determination for SO2 under gas firing 

conditions. 

d. Entergy White Bluff Units 1, 2, and 

Auxiliary Boiler BART Determinations 

The White Bluff Units 1 and 2 and the 

Auxiliary Boiler are BART-eligible 

sources. Units 1 and 2 are coal fired 

boilers with a maximum power rating of 

850 MW each and a heat input rate of 

8700 MMBtu/hr each. Units 1 and 2 are 

permitted to burn both sub-bituminous 

and bituminous coal as the primary fuel 

and No. 2 fuel oil or bio-diesel as the 

start-up fuel. The Auxiliary Boiler is a 

183 MMBtu/hr boiler that is permitted 

to burn only No. 2 fuel oil or biodiesel. 

The Class I areas located within 300 km 

of the facility are Caney Creek, Upper 

Buffalo, and Hercules Glades. Since 

Units 1 and 2 are permitted to burn both 

bituminous and sub-bituminous coal, 

ADEQ made separate BART 

determinations for bituminous subbituminous coal firing. 

Regarding BART for PM for Units 1 

and 2, neither Entergy nor ADEQ 

performed a BART analysis to 

determine what retrofit controls are 

BART for Units 1 and 2. The source’s 

rationale for this, which ADEQ agreed 

with, was its belief that most of the 

visibility-causing emissions from Units 

1 and 2 are due to SO2 and NOX, and 

PM10 emissions are well-controlled with 

existing electrostatic precipitators 

(ESPs). We reviewed the CALPUFF 

visibility modeling submitted by ADEQ 

for Entergy White Bluff, and agree that 

PM emissions from the source have 

minimal visibility impacts at each Class 

I area within 300 km. Revisions to the 

Arkansas RH Rule (APC&E Commission 

Regulation 19, chapter 15) that were 

submitted to us by ADEQ on August 3, 

2010, state the PM BART emission limit 

for White Bluff Units 1 and 2 is the 

existing PM emission limit in the air 

permit as of October 15, 2007. The 

federally enforceable operating air 

permit states the PM emissions from the 

two units are controlled with ESPs and 

requires that the two units comply with 

a PM emission standard of 0.10 lb/ 

MMBtu.51 Since we have found that the 

visibility impact of the source due to 

PM emissions alone is so minimal such 

that the installation of any additional 

PM controls on the units would likely 

achieve very low emissions reductions, 

have minimal visibility benefits, and not 

be cost-effective, we are proposing to 

approve ADEQ’s determination that PM 

BART for both the bituminous and subbituminous coal firing scenarios is the 

existing PM emission limit for Units 1 

and 2. 

Regarding SO2 BART for White Bluff 

Units 1 and 2, Entergy performed a 

BART analysis and determined that the 

presumptive limits of 0.15 lb/MMBtu 

for both the sub-bituminous and 

bituminous coal firing scenarios for SO2

for Units 1 and 2 apply to the two units 

because they are greater than 200 MW 

each. Although Entergy performed a 

BART analysis for BART for SO2, it 

considered only those control options 

that meet the presumptive limit of 0.15 

lb/MMBtu, without considering whether 

a more stringent SO2 emission limit is 

BART for Units 1 and 2. As stated 

elsewhere in this proposed rulemaking, 

the BART guidelines and the RHR 

require consideration of the most 

stringent control technology in the 

BART analysis. Because the control 

technology options considered in the 

BART analysis are capable of achieving 

a lower emission limit than the 

presumptive limit for this facility, and 

these controls are being currently used 

by similar facilities to control SO2

emissions to an emission limit lower 

than the presumptive limit, 

consideration of these technologies and 

the lowest emission limit achievable 

must be included in the BART analysis. 

In Step 1 of the SO2 BART analysis for 

Units 1 and 2, Entergy identified two 

available options to control the units to 

the presumptive SO2 limit: limestone 

forced oxidation (wet scrubbing) and 

lime spray dryer (dry scrubbing). 

Entergy did not identify either control 

option as technically infeasible. In Step 


jlentini on DSK4TPTVN1PROD with PROPOSALS2
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52See Table 9.3a of the Arkansas RH SIP. 

53Based on operating hours provided by Entergy 

for Units 1 and 2, Unit 1 was operated 92.5% of 

the time in 2003, and Unit 2 was operated 92.7% 

of the time in 2004. See Table 2–1, under Section 

2.2 of the BART analysis for Entergy White Bluff 

Units 1 and 2 (found in Appendix 9.3A of the RH 

SIP). 

3 of the BART analysis, Entergy 

evaluated the control effectiveness of 

the two control options, stating the wet 

scrubber can achieve up to 95% control 

efficiency while the dry scrubber can 

achieve up to 92% control efficiency. In 

Step 4 of the BART analysis, Entergy 

evaluated the costs of compliance for 

the two control options. Entergy 

determined the installation of a wet 

scrubber would have an annualized cost 

of $17,023,735 with a cost effectiveness 

of $620/ton SO2 removed at Unit 1 and 

an annualized cost of $17,159,021 with 

a cost-effectiveness of $620/ton SO2

removed at Unit 2. Entergy also 

determined the installation of a dry 

scrubber would have an annualized cost 

of $34,035,909 with a cost effectiveness 

of $1280/ton SO2 removed at Unit 1 and 

an annualized cost of $34,306,388 with 

a cost-effectiveness of $1280/ton SO2

removed at Unit 2. In Step 5 of the 

BART analysis, Entergy evaluated the 

visibility impacts of the two control 

options. However, Entergy’s modeling 

underestimated the visibility benefit 

anticipated from the use of wet or dry 

scrubbers because it modeled both 

control options at the same SO2

emission rate of 0.15 lb/MMBtu, rather 

than at the achievable control 

effectiveness of 92% removal for dry 

scrubbing and 95% for wet scrubbing. 

We also note that Entergy deviated from 

the modeling protocol and used the 98th 

percentile (8th highest modeled day) in 

this analysis instead of the maximum 

modeled visibility impact. Entergy’s 

post-control modeling showed that the 

visibility benefits for dry scrubbers and 

wet scrubbers is nearly the same (with 

dry scrubbing being slightly better due 

to a hotter plume and lower sulfuric 

acid emissions), while the annualized 

cost of a dry scrubber is nearly twice 

that of a wet scrubber. Entergy 

determined and ADEQ agreed that 

BART for SO2 for Units 1 and 2 is 

installation and operation of a wet 

scrubber at each unit to achieve the 

presumptive BART limit of 0.15 lb/ 

MMBtu for both the sub-bituminous and 

the bituminous coal firing scenarios. 

Entergy considered a wet scrubber 

achieving 0.15 lb/MMBtu to be the most 

stringent technology available. But as 

discussed elsewhere, wet scrubbers and 

dry scrubbers have been documented to 

achieve much lower emissions, 

including emissions as low as .065 lbs/ 

MMBtu for dry scrubbers. Therefore, the 

evaluation is not acceptable. In 

addition, we note that the 0.15 lb/ 

MMBtu presumptive BART limit 

established by ADEQ corresponds to 

82% control removal of the wet 

scrubber at Unit 1 and 80% control 

removal at Unit 2, as indicated by ADEQ 

in the Arkansas RH SIP narrative.52

Table A–1 in Appendix A of the BART 

analysis indicates the cost-effectiveness 

of installing and operating a wet 

scrubber is $620/ton SO2 removed. 

Although Table A–1 indicates such costeffectiveness value corresponds to 

operation of the wet scrubber at 95% 

control efficiency, neither ADEQ nor 

Entergy provided a breakdown of the 

cost estimates and we were therefore 

unable to verify whether it in fact 

corresponds to 95% control efficiency 

or if it corresponds to 80% control 

efficiency at Unit 2 and 82% control 

efficiency at Unit 1. Even if the $620/ton 

SO2 removed cost-effectiveness value 

corresponds to only 82% control 

efficiency for Unit 1 and 80% control 

efficiency for Unit 2, we believe that the 

incremental cost of operating the wet 

scrubber at 95% vs. 80% and 82% 

control efficiency is relatively minimal, 

and is likely cost-effective. Since 

Entergy and ADEQ considered only the 

0.15 lb/MMBtu SO2 presumptive limit 

in the BART analysis for Units 1 and 2, 

even though a lower limit is technically 

achievable and more than likely costeffective, we are proposing to 

disapprove ADEQ’s determination that 

BART for SO2 for Units 1 and 2 is the 

presumptive limit of 0.15 lb/MMBtu on 

a 30-day rolling average for both the 

sub-bituminous and bituminous coal 

firing scenarios. 

Regarding NOX BART for White Bluff 

Units 1 and 2, Entergy performed a 

BART analysis in which available 

combustion control technologies to 

control NOX to the presumptive limit of 

0.15 lb/MMBtu for the sub-bituminous 

coal-firing scenario and 0.28 lb/MMBtu 

for the bituminous coal-firing scenario 

were considered. As in the SO2 BART 

analysis for Units 1 and 2, Entergy did 

not consider establishing NOX BART 

emission limits more stringent than the 

NOX presumptive limits. In Step 1 of the 

NOX BART analysis, Entergy considered 

the following control options: boiler 

tuning, OFA, and LNB. Entergy did not 

evaluate post-combustion controls such 

as SCR and SNCR or any other NOX

control options capable of emission 

limits more stringent than the 

presumptive limits, when these are 

technically feasible and available and 

are currently being used by comparable 

facilities to control NOX emissions at 

rates more stringent than the 

presumptive limit. Since Entergy did 

not identify the maximum control 

technology available as a control option 

in Step 1 of the BART analysis, the 

subsequent analysis in the remaining 

steps was incomplete. However, for the 

sake of providing a fuller picture of our 

evaluation of Entergy’s BART analysis 

for NOX for White Bluff Units 1 and 2, 

we discuss the remaining steps of the 

BART analysis. 

Entergy did not identify any of the 

NOX controls it listed in Step 1 of the 

BART analysis as being technically 

infeasible. In Step 3 of the BART 

analysis, Entergy evaluated the control 

effectiveness of the control options. 

Entergy determined boiler tuning will 

result in 37% control removal; a 

combination of boiler tuning and OFA 

will result in 53.6% control removal; 

and a combination of boiler tuning, 

OFA, and LNB will result in 69% 

control efficiency at each unit. In Step 

4 of the BART analysis, Entergy 

evaluated the costs of compliance for 

the control options considered and 

determined that a combination of boiler 

tuning, OFA, and LNB has a control 

effectiveness of $463/ton NOX removed 

for Unit 1 and $437/ton NOX removed 

for Unit 2. We note Entergy’s cost 

analysis of the NOX control options 

included no documentation or detailed 

breakdown of the costs. We have no 

basis to verify the validity of neither the 

cost estimates nor Entergy and ADEQ’s 

determination based on the analysis of 

cost estimation for BART. The basis for 

cost estimates must be documented 

either with data supplied by an 

equipment vendor (i.e., budget estimates 

or bids) or by a referenced source. This 

was not done. Without either ADEQ or 

Entergy providing a breakdown of costs 

of material, labor, operation and 

maintenance, etc, we cannot verify the 

accuracy of Entergy’s cost effectiveness 

determination. Furthermore, the costeffectiveness analysis is problematic 

because Entergy assumed, and ADEQ 

agreed with, an 85% utilization of the 

two units when the units are capable of 

100% utilization and there is no 

federally enforceable limit of 85% 

utilization in place.53 Since the two 

units are technically and legally capable 

of operating at 100% utilization, a cost 

estimate assuming 85% utilization may 

underestimate the amount of emission 

reductions achieved by the controls and 

therefore under-represent the potential 

cost-effectiveness of such controls. In 

Step 5 of the BART analysis, Entergy 

evaluated the visibility impacts of the 

control options and subsequently 

determined that a combination of boiler 


jlentini on DSK4TPTVN1PROD with PROPOSALS2
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54The maximum modeled pre-control Ddv values 

at surrounding Class I areas due to the three subjectto-BART units at White Bluff are: Caney Creek= 

8.816 Ddv; Upper Buffalo= 7.750 Ddv; Hercules 

Glade=6.314 Ddv; Mingo=5.617; and Sipsey=5.843. 

See Appendix 9.2C of the Arkansas RH SIP. 

tuning, OFA, and LNB is BART for NOX

for Units 1 and 2, achieving an emission 

limit of 0.15 lb/MMBtu for the subbituminous coal firing scenario and 0.28 

lb/MMBtu for the bituminous coal firing 

scenario. ADEQ agreed with the 

Entergy’s determination. 

As already explained in our 

evaluation of BART for SO2 for Units 1 

and 2, we disagree with Entergy and 

ADEQ’s approach of not considering an 

emission limit more stringent than the 

presumptive limit when comparable 

facilities have used control technologies 

to reduce emissions below the 

presumptive limit. Also, as explained 

elsewhere in this notice, the BART Rule 

does not suggest the presumptive limits 

should be viewed as establishing a safe 

harbor from more stringent regulation 

under the BART provisions. ADEQ’s 

CALPUFF pre-control modeling 

indicates the three subject to BART 

units at White Bluff together cause 

visibility impairment at Caney Creek, 

Upper Buffalo, Hercules Glade, Mingo, 

and Sipsey.54 A considerable portion of 

this visibility impairment is due to NOX

emissions. ADEQ’s post-control 

modeling indicates the three subject to 

BART units at White Bluff combined 

would still cause visibility impairment 

at all five Class I areas modeled (Caney 

Creek, Upper Buffalo, Hercules Glade, 

Mingo and Sipsey), and that a 

considerable portion of the post-control 

modeled visibility impairment is due to 

NOX emissions. In light of the postcontrol modeling results, ADEQ and/or 

Entergy should have considered 

additional post-combustion controls, 

such as SNCR and SCR, that are capable 

of achieving NOX emission limits well 

below the NOX presumptive limits, and 

have been widely used by similar 

facilities to achieve emissions at rates 

below the presumptive limit. Therefore, 

we are proposing to disapprove ADEQ’s 

determination that BART for NOX for 

White Bluff Units 1 and 2 is 0.15 lb/ 

MMBtu for the sub-bituminous coal 

firing scenario and 0.28 lb/MMBtu for 

the bituminous coal firing scenario. 

With regard to the Auxiliary Boiler, 

neither ADEQ nor Entergy conducted a 

BART analysis that considered the 

statutory factors states are required to 

consider in determining what level of 

control is BART for a source, whether 

this be an emission limit or a work 

practice standard. The Arkansas RH SIP 

narrative states ADEQ decided to 

establish work practice standards for 

this source pursuant to 40 CFR 

51.308(e)(1)(iii), rather than establish 

BART emission limits for SO2, NOX, and 

PM. APC&E Commission Regulation 19, 

Chapter 15, established that BART for 

the Auxiliary Boiler is a restriction to 

operate no more than 4360 hours 

annually. Since ADEQ’s pre and postcontrol visibility modeling shows the 

visibility impact on surrounding Class I 

areas of all three units at the facility 

combined, we are not able to assess the 

visibility impact on Class I areas of the 

Auxiliary Boiler alone. The operating 

permit indicates the Auxiliary Boiler 

combusts No. 2 fuel oil or biodiesel to 

provide steam for Unit 1 and 2 start-up 

activities. The restriction established by 

ADEQ as BART would allow the 

Auxiliary Boiler to operate 50% of the 

time on an annual basis. In practice, an 

auxiliary boiler that is only needed for 

start-up is typically operated much less 

than that. We are proposing to find that 

ADEQ did not properly follow the 

requirements of section 

51.308(e)(1)(ii)(A) because neither 

ADEQ nor Entergy performed a BART 

analysis for the Auxiliary Boiler for 

their chosen work practice standard. We 

are proposing to disapprove ADEQ’s 

determination that BART for the White 

Bluff Auxiliary Boiler is a restriction to 

operate no more than 4360 hours 

annually. 

e. Domtar Power Boilers No. 1 and 2 

BART Determinations 

The Domtar Power Boilers No. 1 and 

2 are BART-eligible sources. The Power 

Boilers generate steam and electricity 

for the other processes within the 

Domtar kraft pulp mill. The No. 1 Power 

Boiler has a heat input rating of 580 

MMBtu/hr and is permitted to burn 

bark, wood waste, municipal yard 

waste, recycled sanitary products 

composed of cellulose and 

polypropylene, pelletized paper fuel 

(PPF), No. 6 fuel oil, used oil generated 

on site, reprocessed fuel oil, tire derived 

fuel (TDF), and natural gas. The No. 1 

Power Boiler is equipped with a 

traveling grate, a combustion air system, 

and a wet ESP for removal of PM 

emissions. According to the operating 

air permit, the No. 1 Power Boiler’s 

permitted emission rate for PM/PM10 is 

0.07 lb/MMBtu. The operating air 

permit provides that the sulfur content 

of the fuel oil used at the No.1 Power 

Boiler shall not exceed 3.0% by weight 

and that the No. 1 Power Boiler shall 

not use more than 2,700,000 gallons of 

fuel oil for any consecutive 12-month 

period. The permit also limits the total 

amount of TDF used at the Power 

Boilers No. 1, 2, and 3 combined to 220 

tons in any 24-hour period. 

The No. 2 Power Boiler has a heat 

input rating of 820 MMBtu/hr and burns 

primarily pulverized bituminous coal, 

but is also permitted to burn noncondensable gases (NCGs), bark and 

wood chips used to absorb oil spills, 

wood waste, municipal yard waste, 

natural gas, used oil generated on site, 

recycled sanitary products based on 

cellulose and polypropylene, No. 6 fuel 

oil, reprocessed fuel oil, TDF, and 

petroleum coke. The No. 2 Power Boiler 

is equipped with a traveling grate, 

combustion air system including OFA, 

multiclones for removal of PM 

emissions, and two venturi scrubbers in 

parallel for removal of remaining PM 

emissions and SO2. According to the 

operating air permit, the No. 2 Power 

Boiler’s permitted emission rate for PM/ 

PM10 is 0.1 lb/MMBtu. 

Regarding BART for PM, Domtar 

stated the No. 1 and 2 Power Boilers 

were at the time subject to the Boiler 

Maximum Achievable Control 

Technology (MACT) PM emission 

standard of 0.07 lb/MMBtu. A wet ESP 

was installed at the No. 1 Power Boiler 

to meet the 0.07 lb/MMBtu Boiler 

MACT PM emission standard. Domtar 

also stated that the No. 2 Power Boiler’s 

existing wet scrubber is capable of 

meeting the Boiler MACT PM emission 

standard. Domtar noted that in the 

BART Guidelines, EPA encourages the 

use of streamlined approaches for BART 

determinations and elected to forego a 

BART analysis and to presumptively 

rely on the 0.07 lb/MMBtu Boiler MACT 

PM emission standard in existence at 

the time to meet the BART PM 

requirements for both the No. 1 and No. 

2 Power Boilers. We note the BART 

Guidelines (Appendix Y to Part 51) 

provide that for VOC and PM sources 

subject to MACT standards, States may 

streamline the BART analysis by 

including a discussion of the MACT 

controls and whether any major new 

technologies have been developed 

subsequent to the MACT standards. The 

guidelines provide that unless there are 

new technologies subsequent to the 

MACT standards which would lead to 

cost-effective increases in the level of 

control, sources may rely on the MACT 

standards for purposes of BART. 

Concerning Power Boiler No. 1, 

Domtar provided a discussion of other 

PM control technologies available at the 

time, and determined that a wet ESP 

with a PM emission limit of 0.07 lb/ 

MMBtu on a 30-day rolling average is 

BART for Power Boiler No. 1. ADEQ 

agreed with Domtar’s determination. We 

agree that ADEQ’s determination for 

BART for PM for Power Boiler No. 1 is 

consistent with the BART Guidelines 

and are proposing to approve it. 


jlentini on DSK4TPTVN1PROD with PROPOSALS2
64208 Federal Register / Vol. 76, No. 200 / Monday, October 17, 2011 / Proposed Rules 

55The MACT standards are part of the National 

Emission Standards for Hazardous Air Pollutants 

for Source Categories (NESHAP), provided under 40 

CFR 63. 56ADEQ’s pre-control modeling files are found in 

Appendix 9.2B of the Arkansas RH SIP. Since 

ADEQ’s visibility modeling shows the visibility 

impact of No. 1 and 2 Power Boilers combined, we 

were unable to assess the visibility impact of No. 

2 Power Boiler individually on surrounding Class 

I areas. 

57Compilation of Air Pollutant Emission Factors, 

Volume I: Stationary Point and Area Sources, AP– 

42, 5th Edition, January 1995. 

58See EPA’s Air Pollution Control Fact Sheet on 

FGD control technology, available at http:// 

www.epa.gov/ttn/catc/dir1/ffdg.pdf. 

Concerning Power Boiler No. 2, Domtar 

stated that the unit was subject to the 

Boiler MACT55 PM emission standard 

in existence at the time (0.07 lb/ 

MMBtu), and indicated its intent to 

presumptively rely on such standard to 

meet BART PM requirements for Power 

Boiler No. 2. However, instead of 

adopting 0.07 lb/MMBtu as the BART 

PM emission limit for Power Boiler No. 

2, ADEQ adopted 0.10 lb/MMBtu as the 

BART PM emission limit. Since ADEQ 

did not select the Boiler MACT PM 

emission standard current at the time 

the BART determination was made as 

the BART PM emission limit for Power 

Boiler No. 2, ADEQ cannot elect to take 

the streamlined approach provided in 

the BART Guidelines. If ADEQ chooses 

to take the streamlined approach 

provided in the BART Guidelines, 

ADEQ must select the Boiler MACT PM 

standard if it determines there are no 

new and cost-effective technologies or 

available upgrades developed 

subsequent to the MACT standard. 

Otherwise, ADEQ and/or Domtar must 

perform a complete BART analysis that 

considers the statutory factors under 

section 51.308(e)(ii)(A) to determine 

BART for PM for Power Boiler No. 2. 

Furthermore, ADEQ’s pre-control 

visibility modeling indicates a 

considerable portion of the combined 

visibility impact of No. 1 and 2 Power 

Boilers at Caney Creek is due to PM 

emissions.56 Therefore, we are 

proposing to disapprove ADEQ’s 

determination that BART for PM10 for 

Power Boiler No. 2 is 0.10 lb/MMBtu on 

a 30-day rolling average, and we are 

proposing to approve ADEQ’s 

determination that BART for PM10 for 

Power Boiler No. 1 is 0.07 lb/MMBtu on 

a 30-day rolling average. 

Regarding BART for SO2 for Power 

Boiler No. 1, Domtar noted precombustion controls such as fuel 

switching/blending and fuel cleaning 

are ineffective, as wood has low sulfur 

content. Domtar also noted postcombustion controls such as flue gas 

desulfurization (FGD) and (i.e., wet and 

dry scrubbers) have not been installed 

on wood-fired boilers because of the 

relatively low SO2 emissions from wood 

combustion. Domtar determined that 

due to the low sulfur content of wood, 

SO2 emissions from wood combustion 

are inherently low and ‘‘have a 

negligible impact on visibility 

impairment.’’ Domtar determined SO2

BART for Power Boiler No. 1 is no 

additional SO2 controls beyond the 

existing fuel restrictions (fuel oil with a 

maximum 3.0% sulfur content and a 

usage limitation of 2,700,000 gallons of 

fuel oil per consecutive 12-month 

period) are necessary. ADEQ agreed 

with Domtar’s determination and 

decided that an emission limit of 1.12 

lb/MMBtu on a 30-day rolling average is 

BART for SO2 for Power Boiler No. 1. 

We note that ADEQ’s CALPUFF precontrol modeling demonstrates the No. 

1 Power Boiler emits more than onethird of the total modeled emissions of 

SO2 from the two sources. 

We agree that due to the low sulfur 

content of wood, SO2 emissions from 

wood-fired boilers are generally 

relatively low. Table 1.6–2 of EPA’s 

Compilation of Air Pollutant Emission 

Factors indicates the combustion of 

wood waste has a typical SO2 emission 

rate of 0.025 lb/MMBtu.57 In light of 

this, we question the appropriateness of 

an SO2 emission limit of 1.12 lb/MMBtu 

for Power Boiler No. 1. Neither ADEQ 

nor Domtar provided any support for 

this emission limit. Domtar stated that 

approximately 75 percent of the heat 

input for Power Boiler No. 1 is supplied 

by bark. A unit combusting primarily 

bark should be capable of achieving an 

SO2 emission rate much lower than 1.12 

lb/MMBtu. The facility’s current permit 

for this unit limits its annual SO2

emissions to 214 tons per year (tons/ 

year), which is a low figure. Therefore, 

there appears to be a mismatch between 

ADEQ’s relatively high BART SO2

emission limit and what the facility 

actually needs, based on its current 

permit. As part of its BART analysis, 

ADEQ and/or Domtar should have 

conducted a fuel inventory of this boiler 

in order to explore this issue. Other 

sources of potential sulfur emissions 

should have been investigated, 

including emissions resulting from 

burning fuel oil and TDF. ADEQ should 

also have considered lowering the sulfur 

content of fuel oil burned at the source, 

and/or lowering the limit on fuel oil 

usage. If Power Boiler No. 1 truly needs 

such a high SO2 emission limit, then 

ADEQ and/or the Domtar should have 

investigated the feasibility, 

effectiveness, and cost of SO2 controls. 

Therefore, we are proposing to find that 

ADEQ did not properly follow the 

requirements of section 

51.308(e)(1)(ii)(A) in determining BART. 

We are proposing to disapprove ADEQ’s 

determination that BART for SO2 for 

Power Boiler No. 1 is 1.12 lb/MMBtu on 

a 30-day rolling average. 

Regarding BART for SO2 for Power 

Boiler No. 2, neither ADEQ nor Domtar 

performed a BART analysis that 

considered the statutory factors under 

section 51.308(e)(ii)(A). Domtar stated 

the unit is equipped with a wet scrubber 

for control of SO2 and PM emissions. 

According to Domtar, the existing wet 

scrubber currently achieves an SO2

control efficiency of approximately 

90%. Domtar indicated that the BART 

Guidelines provide an option to skip the 

comprehensive BART analysis for 

subject to BART units already equipped 

with the most stringent controls 

available, including all possible 

improvements to control devices, as 

long as these are made federally 

enforceable for the purpose of 

implementing BART for the source. 

Domtar stated that since wet scrubbing 

is the most effective method of 

controlling SO2 emissions and it has not 

identified any feasible upgrades to the 

existing wet scrubber, no BART analysis 

is necessary. ADEQ agreed with Domtar, 

and determined that no additional SO2

removal is needed for the No. 2 Power 

Boiler, and BART for SO2 is 1.20 lb/ 

MMBtu on a 30-day rolling average 

using the existing wet scrubber. 

We agree that the BART Guidelines 

allow sources to forego the BART 

analysis when the source already has 

the most stringent controls available in 

place and all possible improvements to 

control devices have been made. 

However, we disagree that a 1.20 lb/ 

MMBtu SO2 emissions rate corresponds 

to the most stringent control available. 

We note FGD systems are capable of SO2

reduction efficiencies up to 98%.58

Therefore, the 90% reduction efficiency 

claimed by Domtar does not correspond 

to the highest SO2 control efficiency wet 

scrubbers are capable of achieving. The 

highest SO2 control efficiency issue 

aside, although Domtar stated it did not 

identify any feasible upgrades to the 

existing wet scrubber, it provided no 

documentation of what upgrades were 

considered and why they were found to 

be technical infeasible. In considering 

all possible improvements to the 

scrubber, Domtar should have evaluated 

options that not only improve the 

design removal efficiency of the 

scrubber vessel itself, but also 

considered upgrades that can improve 

the overall SO2 removal efficiency of the 

scrubber system. For example, the 


jlentini on DSK4TPTVN1PROD with PROPOSALS2
Federal Register / Vol. 76, No. 200 / Monday, October 17, 2011 / Proposed Rules 64209 

59See the docket for this rulemaking to view the 

Title V permit for the Temple Inland Kraft 

Linerboard Mill. 

60ADEQ’s post-control modeling, showing the 

visibility improvement resulting from BART 

controls, demonstrates that the visibility impact of 

Continued 

BART Guidelines state that improving 

maintenance practices, adjusting 

scrubber chemistry, and increasing 

auxiliary equipment redundancy are 

some ways to improve average SO2

removal efficiencies. For the reasons 

discussed above, we are proposing to 

find that ADEQ did not properly follow 

the requirements of section 

51.308(e)(1)(ii)(A) in determining BART 

for SO2 for Power Boiler No. 2. We are 

proposing to disapprove ADEQ’s 

determination that BART for SO2 for the 

No. 2 Power Boiler is 1.20 lb/MMBtu on 

a 30-day rolling average using the 

existing wet scrubber. 

Regarding BART for NOX for Power 

Boilers No. 1 and 2, Domtar performed 

a BART analysis to determine what 

controls are BART for the two boilers. 

In Step 1 of the NOX BART analysis, 

Domtar identified the following control 

technologies: boiler tuning/ 

optimization, fuel blending, FGR, LNB, 

OFA, SCR, SNCR, and reburning/ 

methane de-NOX. Domtar stated the 

source has employed and intends to 

continue to employ the latest boiler 

optimization and tuning techniques, 

and that such control technologies are 

considered part of the base case for 

Power Boilers No. 1 and 2. Similarly, 

Domtar explained it historically mixes 

10–15% (heat input basis) wood with 

coal in the No. 2 Power Boiler and 

therefore fuel blending is considered 

part of the base case for the No. 2 Power 

Boiler. In Step 3 of the BART analysis, 

Domtar evaluated the technical 

feasibility of each control option. 

Domtar explained that since wood is 

inherently low in nitrogen content, fuel 

blending is not technically feasible for 

wood-fired boilers, and therefore 

eliminated this as a control option for 

Power Boiler No. 1. Regarding FGR, 

Domtar asserted that only thermal NOX

can be controlled by FGR. As most NOX

emissions from the No. 1 and No. 2 

Power Boilers are due to fuel NOX rather 

than thermal NOX, Domtar determined 

FGR is technically infeasible for both 

power boilers. Domtar stated that 

combustion modification with LNB is 

used in both gas/oil-fired and coal fired 

units, but is not used for wood-fired 

boilers. Therefore, Domtar determined 

use of LNB is technically infeasible for 

Power Boiler No. 1. Regarding use of 

OFA, Domtar stated the source was 

informed by one OFA vendor that while 

OFA results in decreased NOX

emissions, the primary purpose is 

combustion optimization, and 

implementation of OFA can actually 

increase NOX emissions in certain 

circumstances. Based on this, Domtar 

determined an OFA system upgrade at 

Power Boilers No. 1 and 2 is technically 

infeasible and eliminated this as a 

control option for both units in 

question. Domtar determined that 

methane de-NOX is the only technically 

feasible NOX control option for Power 

Boiler No. 1 and methane de-NOX and 

LNB are the only two technically 

feasible NOX control options for Power 

Boiler No. 2. In so doing, Domtar 

determined that SCR and SNCR are 

technically infeasible control options for 

No. 1 and 2 Power Boilers because they 

are not suited for power boilers that 

experience wide temperature variances 

and high load swings. We note a review 

of the RACT/BACT/LAER 

Clearinghouse (Process types 11.120 and 

11.190) indicates there are several 

wood-fired utility boilers that employ 

SNCR. In particular, a similar source, 

the bark boiler at Temple Inland Kraft 

Linerboard Mill in Orange, Texas, 

employs SNCR, Low Excess Air (LEA), 

and low NOX gas burners.59 The Temple 

Inland Kraft boiler has a NOX emission 

limit of 0.166 lb/MMBtu on a 30 day 

rolling average. Like the Domtar Power 

Boilers No. 1 and 2, the Temple Inland 

Kraft boiler exhibits load swing. We also 

note there are other similarities in the 

operating parameters of the bark boiler 

at Temple Inland Kraft and Power Boiler 

No. 1 (the bark boiler) at Domtar. Like 

Power Boiler No. 1 at Domtar, the bark 

boiler at Temple Inland Kraft is 

permitted to burn, among other fuel 

sources, bark/wood biomass, natural 

gas, and tire-derived fuel. The Temple 

Inland Kraft bark boiler has a maximum 

heat input rating of 656 MMBtu/hr, 

while Domtar Power Boiler No. 1 has a 

maximum heat input rating of 580 

MMBtu/hr. In conducting its BART 

analysis, ADEQ and/or Domtar should 

have more carefully considered the use 

of post-combustion control 

technologies, such as SNCR, for both 

power boilers at Domtar, since SNCR is 

a control technology that has been used 

at similar facilities to control NOX

emissions. Because ADEQ eliminated 

some of the control options as being 

technically infeasible in Step 2 of the 

BART analysis, the subsequent analysis 

in remaining steps was incomplete. 

However, for the sake of providing a 

fuller picture of our evaluation of 

Domtar’s BART analysis for NOX for 

Domtar Power Boilers No. 1 and 2, we 

discuss the remaining steps of the BART 

analysis. 

In Step 3 of the BART analysis, 

Domtar evaluated the control 

effectiveness of the control options it 

considered technically feasible. Domtar 

determined that methane de-NOX has a 

potential control efficiency of 50%, 

whereas LNB has a potential control 

efficiency of 30%. In Step 4 of the BART 

analysis, Domtar evaluated the cost of 

compliance for each control option. 

Domtar determined the costeffectiveness of methane de-NOX is 

$7,262/ton NOX removed at Power 

Boiler No. 1 and $4,259/ton NOX

removed at Power Boiler No. 2, while 

the cost-effectiveness of LNB is $1,465/ 

ton NOX removed at Power Boiler No. 

1. Domtar eliminated consideration of 

methane de-NOX at Power Boilers No. 1 

and 2 due to its high cost. Since Domtar 

eliminated the only control option 

considered for Power Boiler No. 1 

prematurely (before evaluating visibility 

impacts), it determined, and ADEQ 

agreed, that there are no NOX controls 

available for Power Boiler No. 1 and 

ADEQ established a BART NOX

emission limit of 0.46 lb/MMBtu on a 

30-day rolling average for Power Boiler 

No. 1. This would result in no 

additional NOX emission reductions at 

Power Boiler No. 1 beyond baseline 

conditions. 

Also based on the cost-effectiveness 

analysis, Domtar determined that BART 

for Power Boiler No. 2 is LNB and 

ADEQ established a BART NOX

emission limit of 0.45 lb/MMBtu on a 

30-day rolling average for Power Boiler 

No. 2. After making BART 

determinations for the No. 1 and 2 

Power Boilers, ADEQ modeled the 

visibility impacts of the controls it 

selected as BART. We note Domtar and 

ADEQ’s approach for making NOX

BART determinations for the No. 1 and 

2 Power Boilers is flawed, as the RHR 

and the BART Guidelines provide that 

the visibility impacts of all technically 

feasible control options, which 

corresponds to Step 5 of the BART 

analysis, must be considered before a 

BART determination is made. ADEQ 

and Domtar eliminated methane de-NOX

in the BART analysis for Power Boilers 

No. 1 and 2 due to high cost before 

evaluating the visibility impacts of this 

control option. Thereby, ADEQ modeled 

only the visibility impacts of LNB for 

Power Boiler No. 2. 

ADEQ stated its post-control visibility 

modeling demonstrates the BART 

determinations for PM, SO2, and NOX

for Power Boilers No. 1 and 2 will result 

in a combined visibility improvement of 

9.9% at Caney Creek and 12.9% at 

Upper Buffalo.60 We note this is very 


jlentini on DSK4TPTVN1PROD with PROPOSALS2
64210 Federal Register / Vol. 76, No. 200 / Monday, October 17, 2011 / Proposed Rules 

Power Boilers No. 1 and 2 combined will be 2.038 Ddv at Caney Creek and 1.029 Ddv at Upper Buffalo 

after ADEQ’s BART controls are put in place. 

61Emission limits are based on a 30-day rolling 

average. 

minimal visibility improvement and 

that there is ample room for the 

additional visibility improvement that 

would result from BART controls more 

stringent than those selected by ADEQ 

and Domtar. 

We are proposing to find that ADEQ 

did not properly follow the 

requirements of section 

51.308(e)(1)(ii)(A) in determining NOX

BART for Power Boilers No.1 and 2. 

Specifically, we are proposing that 

ADEQ did not properly take into 

consideration ‘‘the technology 

available’’ and ‘‘the degree of 

improvement in visibility which may 

reasonably be anticipated to result from 

the use of such technology.’’ We 

disagree with Domtar and ADEQ’s 

assessment that use of SNCR at the two 

power boilers is technically infeasible. 

In addition, ADEQ did not model the 

visibility impacts of all technically 

feasible control options before making 

NOX BART determinations. For these 

reasons, we are proposing to disapprove 

ADEQ’s determination that BART for 

NOX for Power Boiler No. 1 is a NOX

emission limit of 0.46 lb/MMBtu (which 

would achieve no NOX emission 

reductions beyond the baseline) and 

that BART for NOX for Power Boiler No. 

2 is a NOX emission limit of 0.45 lb/ 

MMBtu (achieved by use of LNB). 

f. ADEQ BART Results and Summary 

We have reviewed ADEQ’s BART 

determinations for the sources listed in 

Table 3, above. For the reasons 

discussed above, and as discussed in 

more detail in the TSD, we are 

proposing to find that ADEQ has 

partially satisfied the BART requirement 

of section 51.308(e). We are proposing 

to find that the BART determinations 

listed in Table 4 satisfy the BART 

requirement of section 51.308(e). We are 

proposing to find that the BART 

determinations listed in Table 5 do not 

satisfy the BART requirement of section 

51.308(e). We are also proposing to find 

that the 6A and 9A Boilers at the 

Georgia-Pacific Crossett Mill are subject 

to BART and require a full BART 

analysis to satisfy the BART 

requirement of section 51.308(e). 

TABLE 4—BART DETERMINATIONS SATISFYING SECTION 51.308(e) 

Facility name BART 

emission unit Pollutant BART emission limit 61

American Electric Power Flint Creek Power Plant .............. Boiler No. 1 ............. PM10 ....................................... existing PM emission limit 

(0.1 lb/MMBtu). 

Entergy Lake Catherine Plant .............................................. Unit 4 ....................... natural gas 

firing.

SO2 .............. No BART Determination. 

PM10 ............. existing PM emission limit 

(45 lb/hr). 

Entergy White Bluff Plant ..................................................... Unit 1 ....................... bituminous 

coal firing.

PM10 ............. existing PM emission limit 

(0.1 lb/MMBtu). 

sub-bituminous 

coal firing.

PM10 ............. existing PM emission limit 

(0.1 lb/MMBtu). 

Unit 2 ....................... bituminous 

coal firing.

PM10 ............. existing PM emission limit 

(0.1 lb/MMBtu). 

sub-bituminous 

coal firing.

PM10 ............. existing PM emission limit 

(0.1 lb/MMBtu). 

Domtar Ashdown Mill ........................................................... No. 1 Power Boiler .. PM10 ....................................... 0.07 lb/MMBtu. 

TABLE 5—BART DETERMINATIONS NOT SATISFYING SECTION 51.308(e) 

Facility name BART 

emission unit Pollutant BART emission limit 62

Arkansas Electric Cooperative Corporation Carl E. Bailey 

Generating Station.

Unit 1 ....................... SO2 ......................................... Use of fuel oil with 1% sulfur content. 

NOX ........................................ No BART Determination. 

PM .......................................... No BART Determination. 

Arkansas Electric Cooperative Corporation John L. 

McClellan Generating Station.

Unit 1 ....................... SO2 ......................................... Use of fuel oil with 1% sulfur content. 

NOX ........................................ No BART Determination. 

PM .......................................... No BART Determination. 

American Electric Power Flint Creek Power Plant .............. Boiler No. 1 ............. SO2 ......................................... 0.15 lb/MMBtu. 


jlentini on DSK4TPTVN1PROD with PROPOSALS2
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62 Emission limits are based on a 30-day rolling 

average. 

63 See Arkansas Pollution Control and Ecology 

Commission Reg. 19.1504(B). 

TABLE 5—BART DETERMINATIONS NOT SATISFYING SECTION 51.308(e)—Continued 

Facility name BART 

emission unit Pollutant BART emission limit 62

NOX ........................................ 0.23 lb/MMBtu. 

Entergy Lake Catherine Plant .............................................. Unit 4 ....................... natural gas 

firing.

NOX .............. 0.15 lb/MMBtu. 

fuel oil firing SO2 .............. 0.562 lb/MMBtu. 

NOX .............. 0.25 lb/MMBtu. 

PM ................ 0.037 lb/MMBtu. 

Entergy White Bluff Plant ..................................................... Unit 1 ....................... bituminous 

coal firing.

SO2 .............. 0.15 lb/MMBtu. 

NOX .............. 0.28 lb/MMBtu. 

sub-bituminous 

coal firing.

SO2 .............. 0.15 lb/MMBtu. 

NOX .............. 0.15 lb/MMBtu. 

Unit 2 ....................... bituminous 

coal firing.

SO2 .............. 0.15 lb/MMBtu. 

NOX .............. 0.28 lb/MMBtu. 

sub-bituminous 

coal firing.

SO2 .............. 0.15 lb/MMBtu. 

NOX .............. 0.15 lb/MMBtu. 

Auxiliary Boiler ........ All ............................................ Boiler to be operated no 

more than 4360 hrs annually. 

Domtar Ashdown Mill ........................................................... No. 1 Power Boiler .. SO2 ......................................... 1.12 lb/MMBtu. 

NOX ........................................ 0.46 lb/MMBtu. 

No. 2 Power Boiler .. SO2 ......................................... 1.2 lb/MMBtu. 

NOX ........................................ 0.45 lb/MMBtu. 

PM10 ....................................... 0.1 lb/MMBtu. 

4. Arkansas’ Regional Haze Rule 

APC&E Commission Regulation 19, 

Chapter 15 requires each source subject 

to BART to install and operate BART no 

later than 6 years after the effective date 

of ADEQ’s regulation or 5 years after we 

approve this RH SIP, which ever comes 

first.63

ADEQ originally submitted Arkansas’ 

RH Rule, the APC&E Commission 

Regulation 19, Chapter 15, along with 

the Arkansas RH SIP, which we 

received on September 23, 2008. On 

August 3, 2010, we received a SIP 

revision submittal from ADEQ revising 

several chapters of APC&E Commission 

Regulation 19, including chapter 15. 

The revisions to Chapter 15 of APC&E 

Commission Regulation 19 that we 

received on August 3, 2010 are mostly 

non-substantive amendments that revise 

the original version of the rule we 

received on September 23, 2008. 

Therefore, in this proposed rulemaking 

we are proposing to take action on the 

version of Chapter 15 of APC&E 

Regulation 19 contained in the 

submittal we received on September 23, 

2008, as revised by the submittal 

received on August 3, 2010. The only 

portion of the August 3, 2010 SIP 

submittal we are proposing to take 

action on in this rulemaking is that 

portion revising chapter 15 of APC&E 

Regulation 19. In this proposed 

rulemaking, we are not proposing to 

take action on the portions of the 

August 3, 2010 SIP submittal that revise 

other chapters of APC&E Commission 

Regulation 19, as those chapters are not 

related to regional haze. We will take 

action on the revisions to other chapters 

of APC&E Commission Regulation 19 at 

a later time. 

We are proposing to partially approve 

and partially disapprove chapter 15 of 

APC&E Commission Regulation 19. We 

are proposing to approve those portions 

of chapter 15 of APC&E Commission 

Regulation 19 that incorporate the 

BART determinations we are proposing 

to approve and those portions that are 

consistent with our overall action on the 

Arkansas RH SIP. Specifically, we are 

proposing to approve the following 

sections of chapter 15 of APC&E 

Commission Regulation 19: Reg. 

19.1501, which establishes the purpose 


jlentini on DSK4TPTVN1PROD with PROPOSALS2
64212 Federal Register / Vol. 76, No. 200 / Monday, October 17, 2011 / Proposed Rules 

64On March 26, 2010, the Arkansas Pollution 

Control & Ecology Commission, Arkansas’ 

rulemaking body, granted all Arkansas subject-toBART sources a variance from the compliance 

deadline imposed by the State’s RH Rule, such that 

these sources are now required to comply with 

BART requirements no later than 5 years after EPA 

approval of the RH SIP. 

of the rule; Reg. 19.1502, which 

incorporates by reference the definitions 

contained in 40 CFR 51.301, as in effect 

on June 22, 2007; Reg. 19.1503, which 

identifies the State’s BART-eligible 

sources; the portion of Reg. 19.1504(A) 

that identifies AECC Bailey Generating 

Station (Unit 1), AECC McClellan 

Generating Station (Unit 1), Domtar 

Ashdown Mill (Power Boilers No. 1 and 

2), Lake Catherine (Unit 4), White Bluff 

(Units 1, 2, and the Auxiliary Boiler), 

and AEP Flint Creek (Boiler No. 1) as 

subject to BART sources; Reg. 

19.1504(B), which requires each source 

subject to BART to install and operate 

BART as expeditiously as possible, but 

no later than 6 years after the effective 

date of the State’s regulation or 5 years 

after EPA approval of the RH SIP 

(whichever comes first); 64 Reg. 

19.1504(C), which requires each source 

subject to BART to maintain the control 

equipment required by chapter 15, and 

establish procedures to ensure such 

equipment is properly operated and 

maintained; Reg. 19.1505(A)(3), which 

establishes PM BART for AEP Flint 

Creek Power Plant, Boiler 1; Reg. 

19.1505(D)(3), which establishes PM 

BART for Domtar Ashdown Mill, Power 

Boiler No. 1; Reg. 19.1505(F)(3), which 

establishes PM BART (bituminous coal) 

for Entergy White Bluff, Unit 1; Reg. 

19.1505(G)(3), which establishes PM 

BART (sub-bituminous coal) for Entergy 

White Bluff, Unit 1; Reg. 19.1505(I)(3), 

which establishes PM BART 

(bituminous coal) for Entergy White 

Bluff, Unit 2; Reg. 19.1505(J)(3), which 

establishes PM BART (sub-bituminous 

coal) for Entergy White Bluff, Unit 2; 

Reg. 19.1505(M)(2), which establishes 

PM BART (natural gas) for Entergy Lake 

Catherine Unit 4; Reg.19.1506, which 

provides the compliance provisions for 

the subject to BART sources; and Reg. 

19.1507, which provides that the Part 70 

permit of each facility subject to BART 

shall be subject to re-opening. 

We are proposing to disapprove the 

portion of Chapter 15 of APC&E 

Commission Regulation 19 that fails to 

identify the 6A and 9A Boilers at the 

Georgia-Pacific Mill as subject to BART 

sources, and the portions that 

incorporate the State’s BART 

determinations we are proposing to 

disapprove. Specifically, we are 

proposing to disapprove the following 

sections of Chapter 15 of the Arkansas 

Pollution Control and Ecology 

Commission Regulation 19: the portion 

of Reg. 19.1504(A) that fails to identify 

the 6A and 9A Boilers at the GeorgiaPacific Crossett Mill as subject to BART 

sources; Reg. 19.1505(A)(1), which 

establishes SO2 BART for AEP Flint 

Creek Power Plant, Boiler 1; Reg. 

19.1505(A)(2), which establishes NOX

BART for AEP Flint Creek Power Plant, 

Boiler 1; Reg. 19.1505(B), which 

establishes SO2 BART for AECC Bailey 

Generating Station, Unit 1; Reg. 

19.1505(C), which establishes SO2

BART for AECC McClellan Generating 

Station, Unit 1; Reg 19.1505(D)(1), 

which establishes SO2 BART for Domtar 

Ashdown Mill, Power Boiler No. 1; Reg. 

19.1505(D)(2), which establishes NOX

BART for Domtar Ashdown Mill, Power 

Boiler No. 1; Reg. 19.1505(E)(1), which 

establishes SO2 BART for Domtar 

Ashdown Mill, Power Boiler No. 2; Reg. 

19.1505(E)(2), which establishes NOX

BART for Domtar Ashdown Mill, Power 

Boiler No. 2; Reg. 19.1505(E)(3), which 

establishes PM BART for Domtar 

Ashdown Mill, Power Boiler No. 2; Reg. 

19.1505(F)(1), which establishes SO2

BART (bituminous coal) for Entergy 

White Bluff, Unit 1; Reg. 19.1505(F)(2), 

which establishes NOX BART 

(bituminous coal) for Entergy White 

Bluff, Unit 1; Reg. 19.1505(G)(1), which 

establishes SO2 BART (sub-bituminous 

coal) for Entergy White Bluff, Unit 1; 

Reg. 19.1505(G)(2), which establishes 

NOX BART (sub-bituminous coal) for 

Entergy White Bluff, Unit 1; Reg. 

19.1505(H), which provides that when 

burning a mix of bituminous and subbituminous coal at White Bluff Unit 1, 

the NOX BART limits shall be prorated 

using the percentage of each coal being 

used; Reg. 19.1505(I)(1), which 

establishes SO2 BART (bituminous coal) 

for Entergy White Bluff, Unit 2; Reg. 

19.1505(I)(2), which establishes NOX

BART (bituminous coal) for Entergy 

White Bluff, Unit 2; Reg. 19.1505(J)(1), 

which establishes SO2 BART (subbituminous coal) for Entergy White 

Bluff, Unit 2; Reg. 19.1505(J)(2), which 

establishes NOX BART (sub-bituminous 

coal) for Entergy White Bluff, Unit 2; 

Reg. 19.1505(K), which provides that 

when burning a mix of bituminous and 

sub-bituminous coal at White Bluff Unit 

2, the NOX BART limits shall be 

prorated using the percentage of each 

coal being used; Reg. 19.1505(L), which 

establishes BART for Entergy White 

Bluff, Auxiliary Boiler; Reg. 

19.1505(M)(1), which establishes NOX

BART (natural gas) for Entergy Lake 

Catherine Unit 4; Reg. 19.1505(N)(1), 

which establishes SO2 BART (fuel oil) 

for Entergy Lake Catherine Unit 4; Reg. 

19.1505(N)(2), which establishes NOX

BART (fuel oil) for Entergy Lake 

Catherine Unit 4; and Reg. 

19.1505(N)(3), which establishes PM 

BART (fuel oil) for Entergy Lake 

Catherine Unit 4. 

E. 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. 

Arkansas’ 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 

Arkansas LTS was developed by ADEQ, 

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 Inventories 

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

Arkansas 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. Arkansas 

must identify the baseline emissions 

inventory on which its strategies are 

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

that Arkansas 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. Arkansas 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 Arkansas. 

ADEQ provided a statewide emissions 

inventory for 2002- representing the 

mid-point of the 2000–2004 baseline 

period, and a projected emissions 

inventory for 2018, the end of the first 

10-year planning period. The 2018 

inventory is based on visibility 

modeling conducted by CENRAP. The 

2018 emissions inventory was 


jlentini on DSK4TPTVN1PROD with PROPOSALS2
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65 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 

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. Arkansas’ 2002 Emission Inventory 

ADEQ 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. Arkansas’ 2002 emissions 

inventory provides estimates of annual 

emissions for haze producing pollutants 

by source category as summarized in 

Table 6, based on information in section 

7.0 of Arkansas’ RH SIP. 

TABLE 6—ARKANSAS’ 2002 EMISSIONS INVENTORY

[Tons/year] 

SO2 NH3 NOX VOCs PM10 PM2.5

Point ......................................................... 92,205 1 72,419 44,329 12,406 7,837 

Area .......................................................... 29,889 152,436 27,450 93,548 148,433 68,000 

Non-road mobile ...................................... 5,490 49 62,472 54,785 5,673 5,220 

On-road mobile ........................................ 3,902 2,480 141,894 48,599 3,784 3,021 

Biogenic ................................................... 0 0 18,960 1,385,666 0 0 

Total .................................................. 131,485 154,967 323,195 1,626,927 170,296 84,078 

See the TSD for details on how the 

2002 emissions inventory was 

constructed. We are proposing that 

Arkansas’ 2002 emission inventory is 

acceptable. 

b. Arkansas’ 2018 Emission Inventory 

In constructing Arkansas’ 2018 

emission inventory, ADEQ used a 

combination of our Economic Growth 

Analysis System (EGAS 6), our mobile 

emissions factor model (MOBILE 6), our 

off-road emissions factor model 

(NONROAD), and the Integrated 

Planning Model (IPM) for electric 

generating units. CENRAP developed 

emissions for five inventory source 

classifications: point, area, non-road and 

on-road mobile sources, and biogenic 

sources. CENRAP used the 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. Arkansas’ 2018 

emissions inventory provides estimates 

of annual emissions for haze producing 

pollutants by source category as 

summarized in Table 7, based on 

information in section 7.0 of the 

Arkansas RH SIP. 

TABLE 7—ARKANSAS’ 2018 EMISSIONS INVENTORY

SO2 NH3 NOX VOCs PM10 PM2.5

Point ......................................................... 106,461 2,575 71,107 55,603 19,799 13,775 

Area .......................................................... 31,169 201,722 31,531 107,387 148,592 69,585 

Non-road mobile ...................................... 211 49 34,305 31,475 3,678 3,387 

On-road mobile ........................................ 442 3,412 33,640 19,924 949 949 

Biogenic ................................................... 0 0 18,960 1,385,666 0 0 

Total .................................................. 138,283 207,758 189,542 1,600,055 173,019 87,695 

See the TSD for details on how the 

2018 emissions inventory was 

constructed. CENRAP and ADEQ used 

this and other state’s 2018 emission 

inventories to construct visibility 

projection modeling for 2018. We are 

proposing that Arkansas’ 2018 emission 

inventory is acceptable. 

2. Visibility Projection Modeling 

CENRAP performed modeling for the 

RH LTS for its member states, including 

Arkansas. 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.65

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 

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 


jlentini on DSK4TPTVN1PROD with PROPOSALS2
64214 Federal Register / Vol. 76, No. 200 / Monday, October 17, 2011 / Proposed Rules 

66The species contributing to visibility extinction 

at Caney Creek and Upper Buffalo, shown on Tables 

8–11, are the following: sulfate (SO4), nitrate (NO3), 

primary organic aerosols (POA), elemental carbon 

(EC), soil dust, and coarse mass (CM). These 

species’ precursors are SO2, NOX, and in some 

cases, NH3 and VOCs. 

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. The results of 

CENRAP’s visibility projection 

modeling are discussed in the section 

that follows. 

3. Sources of Visibility Impairment 

Visibility impairment in Class I areas 

is the result of local air pollution as well 

as transport of regional pollution across 

long distances. CENRAP used CAMx 

with its Particulate Source 

Apportionment Technology (PSAT) tool 

to provide source apportionment by 

geographic region and major source 

category. The pollutants causing the 

highest levels of light extinction are 

associated with the sources causing the 

most visibility impairment. 

a. Sources of Visibility Impairment in 

Caney Creek 

Tables 8 and 9 show the modeled 

contributions to total extinction at 

Caney Creek for each source category 

and species for 2002 and 2018, 

respectively.66 Visibility impairment at 

Caney Creek in 2002 on the worst 20% 

days is largely due to SO4 from point 

sources that contributes over half (75.1 

Mm¥1) of the total extinction of 133.93 

Mm¥1. The largest contributions of SO4

come from Texas (11.55 Mm¥1 from all 

source categories) and the eastern 

United States (17.98 Mm¥1). Overall, 

the largest source region contributions 

to visibility impairment in 2002 are 

from the eastern United States (19.16 

Mm¥1), Texas (14.89 Mm¥1), and 

Arkansas (13.57 Mm¥1). 

In 2018, Arkansas sources will 

contribute the most to visibility 

impairment at Caney Creek, as large 

reductions in impairment from point 

sources in East Texas and the eastern 

U.S. will occur while SO4 emissions, 

particularly from point sources, are 

expected to increase in Arkansas. The 

2018 projection shows the total 

extinction at Caney Creek for the worst 

20% days is estimated to be 85.84 

Mm¥1, a reduction of approximately 

36% from 2002 levels. Anticipated 

reductions of SO4 emissions from point 

sources in Texas, the eastern United 

States, Indiana, and Ohio will account 

for a decrease of 24.41 Mm¥1 in total 

light extinction, which is approximately 

half of the total expected reduction 

between 2002 and 2018. Even with such 

large expected reductions in SO4

emissions from point sources in 2018, 

extinction due to point sources will still 

be the highest contributor to visibility 

impairment on the worst 20% days, 

accounting for over half of the total 

extinction. Visibility impairment from 

all Arkansas sources will decrease by 

2.32 Mm¥1, almost entirely due to 

expected reductions from mobile 

sources. Total reductions in NO3

emissions from mobile sources will 

contribute a decrease in total extinction 

of approximately 9 Mm¥1. There is an 

under-prediction bias in the model that 

must be considered when examining 

source apportionment results for SO4. 

Use of a 12 km resolution modeling grid 

in CAMX reduced the summertime SO4

bias but required large computational 

expense. The use of higher resolution 

modeling should be reconsidered in 

future modeling efforts. 

TABLE 8—PROJECTED LIGHT EXTINCTION FOR 20% WORST DAYS AT CANEY CREEK WILDERNESS AREA IN 2002 

[Mm¥1] 

Total 1 Point Natural On-road Non-road Area 

SO4 .......................................................... 87.05 75.10 0.09 1.19 1.70 5.66 

NO3 .......................................................... 13.78 4.06 0.64 4.70 2.45 1.37 

POA .......................................................... 10.50 1.29 1.33 0.46 1.34 5.32 

EC ............................................................ 4.80 0.19 0.33 0.86 1.79 1.40 

SOIL ......................................................... 1.12 0.19 0.01 0.01 0.01 0.87 

CM ............................................................ 3.73 0.21 0.04 0.03 0.02 3.19 

Sum ................................................... 133.93 81.04 2.45 7.26 7.31 17.81 

1Totals include contributions from boundary conditions and secondary organic matter. 

TABLE 9—PROJECTED LIGHT EXTINCTION FOR 20% WORST DAYS AT CANEY CREEK WILDERNESS AREA IN 2018 

[Mm¥1] 

Total 1 Point Natural On-road Non-road Area 

SO4 .......................................................... 48.95 39.83 0.07 0.12 0.44 5.31 

NO3 .......................................................... 7.57 2.84 0.53 0.97 1.33 1.37 

POA .......................................................... 9.93 1.76 1.18 0.14 1.03 5.09 

EC ............................................................ 3.17 0.24 0.30 0.16 0.94 1.31 

SOIL ......................................................... 1.29 0.35 0.01 0.01 0.01 0.87 

CM ............................................................ 3.58 0.24 0.04 0.03 0.01 3.02 

Sum ................................................... 85.84 45.27 2.12 1.44 3.76 16.96 

1Totals include contributions from boundary conditions and secondary organic matter. 


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67See Appendix E of the TSD for CENRAP 

Emissions and Air Quality Modeling To Support 

Regional Haze State Implementation, found in 

Appendix 8.1 of the Arkansas RH SIP. 

b. Sources of Visibility Impairment in 

Upper Buffalo 

Tables 10 and 11 show the 

contributions to total extinction at 

Upper Buffalo for each source category 

and species for 2002 and 2018, 

respectively. Visibility impairment at 

Upper Buffalo in 2002 on the worst 20% 

days is largely due to SO4 from point 

sources that contributes over half (72.17 

Mm¥1) of the total extinction of 131.79 

Mm¥1. The largest contributions of 

visibility impairment due to SO4 come 

from the eastern United States (18.56 

Mm¥1), Indiana (9.79 Mm¥1), Illinois 

(8.06 Mm¥1), and Kentucky (6.93 

Mm¥1). Overall, the largest source 

region contributions to visibility 

impairment in 2002 are from the eastern 

United States (20.00 Mm¥1), Arkansas 

(13.47 Mm¥1), Indiana (10.20 Mm¥1), 

Illinois (9.64 Mm¥1), and Missouri (9.60 

Mm¥1). 

In 2018, Arkansas sources will 

contribute the most to visibility 

impairment at Upper Buffalo, as large 

reductions in impairment from point 

sources in Indiana, Illinois, Ohio and 

the eastern U.S. will occur while SO4

emissions, particularly from point 

sources, are expected to increase in 

Arkansas. The 2018 projection shows 

the total extinction at Upper Buffalo for 

the worst 20% days is estimated to be 

86.16 Mm¥1, a reduction of 

approximately 35% from 2002 levels. 

Anticipated reductions of SO4 emissions 

from point sources in the eastern United 

States, Indiana, Illinois, Kentucky and 

Ohio will account for a decrease of 

28.43 Mm¥1 in total light extinction, 

more than 60% of the total expected 

reduction in impairment between 2002 

and 2018. Even with such large 

expected reductions in SO4 emissions 

from point sources in 2018, extinction 

due to point sources will still be the 

highest contributor to visibility 

impairment on the worst 20% days, 

accounting for approximately half of the 

total extinction. Visibility impairment 

from all Arkansas sources will decrease 

by 1.45 Mm¥1, due to expected 

reductions from mobile sources. Total 

reductions in NO3 emissions from 

mobile sources will contribute a 

decrease in total extinction of 

approximately 8.5 Mm¥1. There is an 

under-prediction bias in the model that 

must be considered when examining 

source apportionment results forSO4. 

Use of a 12 km resolution modeling grid 

in CAMX reduced the summertime 

sulfate bias but required large 

computational expense. The use of 

higher resolution modeling should be 

reconsidered in future modeling efforts. 

TABLE 10—PROJECTED LIGHT EXTINCTION FOR 20% WORST DAYS AT UPPER BUFFALO WILDERNESS AREA IN 2002 

[Mm¥1] 

Total 1 Point Natural On-road Non-road Area 

SO4 ........................................................... 83.18 72.17 0.08 1.15 1.67 5.24 

NO3 .......................................................... 13.30 3.93 0.61 4.14 2.71 1.23 

POA .......................................................... 10.85 1.06 1.33 0.47 1.38 5.75 

EC ............................................................ 4.72 0.16 0.31 0.80 1.93 1.30 

SOIL ......................................................... 1.21 0.20 0.02 0.01 0.01 0.93 

CM ............................................................ 6.85 0.29 0.05 0.05 0.02 6.02 

Sum ................................................... 131.79 77.80 2.39 6.62 7.72 20.46 

1Totals include contributions from boundary conditions and secondary organic matter. 

TABLE 11—PROJECTED LIGHT EXTINCTION FOR 20% WORST DAYS AT UPPER BUFFALO WILDERNESS AREA IN 2018 

[Mm¥1] 

Total 1 Point Natural On-road Non-road Area 

SO4 ........................................................... 45.38 37.09 0.06 0.12 0.42 4.95 

NO3 .......................................................... 9.22 3.48 0.63 1.10 1.81 1.48 

POA .......................................................... 10.17 1.48 1.20 0.14 1.01 5.49 

EC ............................................................ 3.07 0.21 0.28 0.15 0.99 1.21 

SOIL ......................................................... 1.40 0.40 0.01 0.01 0.01 0.93 

CM ............................................................ 6.53 0.36 0.05 0.04 0.02 5.65 

Sum ................................................... 86.16 43.02 2.24 1.57 4.25 19.71 

1Totals include contributions from boundary conditions and secondary organic matter. 

c. Arkansas’ Contribution to Visibility 

Impairment in Class I Areas Outside the 

State 

CAMx PSAT results were also utilized 

to evaluate the impact of Arkansas 

emission sources in 2002 and 2018 on 

visibility impairment at Class I areas 

outside of the state. Arkansas sources 

are modeled to have contributions to the 

Class I areas in Missouri (HerculesGlades and Mingo). Outside of Arkansas 

and Missouri, the largest contribution 

from Arkansas sources is at the Wichita 

Mountains Class I area in Oklahoma, 

amounting to 2.0% of the visibility 

impairment at Wichita Mountains in 

2002 and 2.3% in 2018. Arkansas is also 

projected to contribute a small amount 

of visibility degradation at Class I areas 

in other states listed in Table 12. We 

agree that additional emission 

reductions in Arkansas, beyond those 

controlled through BART requirements, 

are not necessary to protect visibility at 

Class I areas outside of the state at this 

time. Table 12 summarizes the projected 

contribution from Arkansas emissions 

on visibility degradation at 9 Class I 

areas for the 20 percent worst days in 

2002 and 2018, as modeled by 

CENRAP.67


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68Contributions less than 1% were excluded from 

Table 12. 

69An inverse megameter is the direct 

measurement unit for visibility impairment data. It 

is the amount of light scattered and absorbed as it 

travels over a distance of one million meters. 

Deciviews (dv) can be calculated from extinction 

data as follows: dv = 10 × ln (bext(Mm¥1)/10). 

70See Appendix E of the TSD for CENRAP 

Emissions and Air Quality Modeling To Support 

Regional Haze State Implementation, found in 

Appendix 8.1 of the Arkansas RH SIP. 

TABLE 12—PERCENT CONTRIBUTION FROM ARKANSAS EMISSIONS TO TOTAL VISIBILITY IMPAIRMENT AT CLASS I AREAS

ON 20% WORST DAYS 68

Class I area State 2002 

(percent) 

2018 

(percent) 

Upper Buffalo ............................................................ Arkansas ................................................................... 10.2 14.0 

Caney Creek ............................................................. Arkansas ................................................................... 10.1 13.1 

Hercules Glades ....................................................... Missouri .................................................................... 5.9 7.6 

Mingo ........................................................................ Missouri .................................................................... 3.3 4.4 

Wichita Mountains .................................................... Oklahoma ................................................................. 2.0 2.3 

Mammoth Cave ........................................................ Kentucky ................................................................... 1.0 1.8 

Bondville ................................................................... Illinois ........................................................................ 1.2 1.5 

Breton Island ............................................................ Louisiana .................................................................. 1.1 1.3 

Cadiz ......................................................................... Kentucky ................................................................... 0.9 1.2 

4. Consultation and Emissions 

Reductions for Other States’ Class I 

Areas 

As in the development of Arkansas’ 

RPGs for Caney Creek and Upper 

Buffalo, ADEQ used CENRAP as its 

main vehicle for facilitating 

collaboration with FLMs and other 

states in satisfying its LTS consultation 

requirement. This helped ADEQ 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 

Arkansas 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 

Arkansas consult with other states if 

those states’ emissions are reasonably 

anticipated to contribute to visibility 

impairment at Caney Creek and Upper 

Buffalo. ADEQ’s consultations with 

other states are described in section 

V.C.3 above. The CENRAP visibility 

modeling demonstrates Arkansas 

sources are responsible for a visibility 

extinction of approximately 7.1 inverse 

megameters 69 (Mm¥1) at Hercules 

Glades and for a visibility extinction of 

approximately 4.95 Mm¥1 at Mingo on 

the worst 20% days for 2002.70 ADEQ 

consulted with Missouri, as well as with 

several other states whose emissions 

have a potential visibility impact at 

Caney Creek and Upper Buffalo. As 

already discussed elsewhere in this 

proposed notice, ADEQ neither 

requested additional emission 

reductions from other states, nor made 

a commitment to other states for 

additional emission reductions beyond 

those already factored in to the 

CENRAP’s photochemical modeling for 

the 2018 visibility projections. All states 

participating in ADEQ’s consultation 

process agreed with this decision. 

We are proposing to find that ADEQ’s 

consultations satisfy the requirements 

under section 51.308(d)(3)(i) and (ii). 

5. Mandatory Long Term Strategy 

Factors 

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

Arkansas consider certain 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 are proposing to 

find that Arkansas has not satisfied all 

the requirements of Section 

51.308(d)(3)(v). 

a. Reductions Due to Ongoing Air 

Pollution Programs 

In addition to its BART 

determinations, Arkansas’ LTS 

incorporates emission reductions due to 

a number of ongoing air pollution 

control programs. This includes EPA’s 

Clean Air Interstate Rule (CAIR), which 

was expected to cap Arkansas’ ozone 

season trading budget for annual NOx 

allocations at 9,596 tons by 2015. 

Consistent with EPA guidance and 

regulations (see 70 FR 39104, 39106 

(July 6, 2005)), many states relied on 

EPA’s Clean Air Interstate Rule (CAIR) 

to satisfy key elements of Regional Haze 

SIPs. The D.C. Circuit, however, found 

CAIR to be inconsistent with the 

requirements of the Act and remanded 

the rule to the Agency. North Carolina 

v. EPA, 531 F.3d 896, 929–30 (D.C. Cir. 

2008); modified on rehearing, North 

Carolina v. EPA, 550 F.3d 1176, 1178 

(D.C. Cir. 2008). In response to the 

remand of the CAIR rule, on July 6, 

2011, EPA finalized the Transport Rule, 

also known as the Cross-State Air 

Pollution Rule (CSAPR), a rule intended 

to reduce the interstate transport of fine 

particulate matter and ozone (see 76 FR 

48208). Since Arkansas was subject to 

CAIR only for ozone season NOx, its 

Regional Haze SIP did not rely on CAIR 

to meet the requirements for BART or 

for attaining the in-state emissions 

reductions necessary to ensure 

reasonable progress. Instead, Arkansas 

evaluated controls for its potential 

BART sources. Arkansas made BART 

determinations for its subject to BART 

sources, including Electric Generating 

Units (EGUs) that might have been 

controlled under CAIR. Controls on 

these sources are an element of 

Arkansas’ LTS for attaining the RPGs at 

Caney Creek and Upper Buffalo. In 

terms of the LTS, EPA anticipates that 

the Transport Rule will result in similar 

or better improvements in visibility than 

those predicted from CAIR at Class I 

areas in Arkansas. As a result, we do not 

expect the remand of CAIR to have a 

significant negative effect on the ability 

of Arkansas’ LTS to ensure that Caney 

Creek and Upper Buffalo meet the RPGs 

in the State’s RH SIP. We note that to 

assess whether a state’s current 

strategies will be sufficient to meet its 

RPGs, the RHR requires a midcourse 

review by each state and, if necessary, 

a correction of the state’s regional haze 

plan. See 40 CFR 52.308(g). If for a 

particular Class I area, the emissions 

reductions resulting from the Transport 


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71See ‘‘Arkansas Pollution Control and Ecology 

Commission Regulation No. 19—Regulations of the 

Arkansas Plan of Implementation for Air Pollution 

Control,’’ found in Appendix 9.3C of the Arkansas 

RH SIP. 

Rule do not provide similar or greater 

benefits than CAIR and if meeting the 

RPGs at one of its Class I areas is in 

jeopardy, the State will be required to 

address this circumstance in its five 

year review. 

ADEQ also considered the Tier 2 

Vehicle Emission Standards in 

developing its LTS. Federal Tier 2 

Vehicle Emission Standards for 

passenger cars and light trucks were 

fully implemented in 2007 and similar 

rules for heavy trucks were scheduled to 

be implemented by 2009. These federal 

standards will result in reductions of 

emissions of PM, ozone precursors, and 

non-methane organic compounds. In 

developing its LTS, ADEQ also 

considered the Highway Diesel and 

Nonroad Diesel Rules, which mandated 

the use of lower sulfur fuels in diesel 

engines beginning in 2006 for highway 

diesel fuel, and 2007 for nonroad diesel 

fuel. These federal rules have resulted 

in more effective control of PM 

emissions from diesel engines by 

allowing the installation of control 

devices that were technically infeasible 

for fuels with higher sulfur content. 

We approved Arkansas’ Visibility 

Protection SIP on February 10, 1986 (51 

FR 4910). We approved Arkansas’ Part 

II Visibility Protection SIP, which 

addresses reasonably attributable 

visibility impairment (RAVI) at Caney 

Creek and Upper Buffalo, on July 21, 

1988 (53 FR 27514). As we note in 

section IV.H of this proposed notice, the 

FLMs did not identify any integral 

vistas in Arkansas. In addition, Caney 

Creek and Upper Buffalo are not 

experiencing RAVI, nor are any 

Arkansas sources affected by the RAVI 

provisions. For this reason, the 

Arkansas RH SIP does not incorporate 

any measures to specifically address 

RAVI. 

b. Measures To Mitigate the Impacts of 

Construction Activities 

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

that Arkansas consider measures to 

mitigate the impacts of construction 

activities in developing its LTS. 

Construction-related activities are 

believed to be a small contributor to fine 

and coarse particulates. ADEQ notes 

that since the Arkansas Water and Air 

Pollution Control Act does not apply to 

land clearing, land grading, or road 

construction operations, ADEQ has 

limited opportunities to mitigate air 

emissions resulting from construction 

activities. However, ADEQ notes the 

federal General Conformity program 

requires assessment of the potential 

impacts of any construction-related 

emissions of criteria pollutants from 

federal projects in areas that have been 

designated as not attaining the National 

Ambient Air Quality Standards 

(NAAQS) for that pollutant. ADEQ also 

participates in the Blue Skyways 

Collaborative, a regional group that 

works collaboratively on the 

introduction of innovative, regionalscale, transportation-related programs 

and projects. The State has directed 

grant funds to fleet managers and 

equipment suppliers as a means of 

subsidizing diesel retrofits and the 

biodiesel market. 

c. Emissions Limitations and Schedules 

of Compliance 

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

that in developing its LTS, Arkansas 

consider emissions limitations and 

schedules of compliance to achieve the 

RPGs. The SIP contains emission limits 

and schedules of compliance for those 

sources subject to BART: the AECC 

Bailey Unit 1; the AECC McClellan Unit 

1; the AEP Flint Creek Boiler No. 1; the 

Entergy Lake Catherine Unit 4; the 

Entergy White Bluff Units 1, 2, and the 

Auxiliary Boiler; and the Domtar Power 

Boilers No. 1 and 2. The schedules for 

implementation of BART for these 

sources are identified in Section 9.3 of 

the RH SIP and in the State’s RH Rule 

included in Appendix 9.3C of the SIP. 

The BART emission limits established 

by ADEQ are an element of the LTS, and 

since we are proposing to disapprove a 

portion of ADEQ’s BART 

determinations, we cannot propose to 

approve this element of the LTS. 

d. Source Retirement and Replacement 

Schedules 

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

that Arkansas consider source 

retirement and replacement schedules 

in developing its LTS. ADEQ stated 

retirement and replacement will be 

managed in conformance with existing 

SIP requirements pertaining to the 

Prevention of Significant Deterioration 

(PSD) and the New Source Review 

(NSR) programs. ADEQ notes source 

retirement and replacement will be 

tracked through on-going point source 

inventories. 

e. Agricultural and Forestry Smoke 

Management Techniques 

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

that Arkansas consider smoke 

management techniques for agricultural 

and forestry management purposes in 

developing its LTS. ADEQ considered 

smoke management techniques for the 

purposes of agricultural and forestry 

management in its LTS. Regulation 18 of 

the Arkansas Pollution Control and 

Ecology Commission contains a general 

prohibition on ‘‘open burning of refuse, 

garbage, trade waste, or other waste 

material,’’ but exempts controlled fires 

used for forest and wildlife management 

and certain agricultural activities 

(ADEQ Reg. 18.602–18.603). In 2007, 

the Arkansas Forestry Commission 

approved revisions to the Arkansas 

Smoke Management Program (SMP). 

The Arkansas SMP is designed to assure 

that prescribed fires are planned and 

executed in a manner designed to 

minimize impacts associated with the 

smoke produced by prescribed fires. 

The Arkansas SMP recommends a 

written fire plan that includes measures 

that can be taken to reduce residual 

smoke from burning activities. The 

Arkansas SMP also includes a process to 

evaluate potential smoke impacts at 

sensitive receptors and guidelines for 

scheduling fires such that exposure of 

sensitive populations is minimized and 

visibility impacts in Class I areas are 

avoided. 

f. Enforceability of Emissions 

Limitations and Control Measures 

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

that Arkansas ensure the enforceability 

of emission limitations and control 

measures used to meet reasonable 

progress goals. ADEQ has ensured that 

all emission limitations and control 

measures used to meet RPGs are 

enforceable by incorporating these into 

State regulations.71 The State’s RH Rule, 

Chapter 15 of the APC&E Commission 

Regulation 19, contains the BART 

requirements for all subject to BART 

sources in Arkansas. ADEQ has also 

committed to issuing enforceable Part 

70 air quality permits requiring BARTeligible sources subject to BART to 

install BART and achieve the associated 

BART emission limits. Subject sources 

must achieve the BART emission limits 

referenced above within five years of 

our approval of the SIP, as required by 

section 51.308(e)(1)(iv). ADEQ 

determined that emission limitations or 

control measures other than BART are 

not currently required in order to meet 

the established RPGs. As discussed 

previously, we disagree with this 

position and are proposing to 

disapprove the RPGs. 

g. Anticipated Net Effect on Visibility 

Due to Projected Changes 

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

that in developing its LTS, Arkansas 

consider the anticipated net effect on 

visibility due to projected changes in 

point, area, and mobile source 


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72Arkansas’ part II Visibility Protection SIP 

contained RAVI provisions and was approved by 

EPA on July 21, 1988 (53 FR 27514). 

emissions over the period addressed by 

the long-term strategy. In developing its 

RH SIP, ADEQ relied on the CENRAP’s 

2018 modeling projections, which show 

that net visibility is expected to improve 

by 3.88 dv at Caney Creek and 3.75 dv 

at Upper Buffalo. CENRAP’s 2018 

modeling projections account for 

changes in point, area, and on-road and 

non-road mobile emissions. The results 

of CENRAP’s 2018 modeling projections 

are discussed in sections IV.E.2 and 

IV.E.3 of this proposed rulemaking. 

6. Our Conclusion on Arkansas’ Long 

Term Strategy 

We are proposing to partially approve 

and partially disapprove Arkansas’ LTS. 

Because we are proposing to disapprove 

some of ADEQ’s BART determinations, 

we are also proposing to disapprove the 

corresponding emission limits and 

schedules of compliance that Arkansas 

relied on as part of its LTS. With the 

exception of this element, the LTS 

satisfies the requirements of 40 CFR 

51.308(d)(3), and we are proposing to 

approve these remaining elements. 

F. 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 

Arkansas. In addition, Caney Creek and 

Upper Buffalo are not experiencing 

RAVI, nor are any Arkansas sources 

affected by the RAVI provisions. Thus, 

the Arkansas RH SIP submittal does not 

explicitly address the two requirements 

regarding coordination of RH with the 

RAVI LTS and monitoring provisions. 

However, Arkansas previously made a 

commitment to address RAVI should 

the FLM certify visibility impairment 

from an individual source.72 We are 

proposing to find that this RH submittal 

appropriately supplements and 

augments Arkansas’ RAVI visibility 

provisions to address RH by updating 

the monitoring and LTS provisions. We 

discuss the relevant monitoring 

provisions in the section that follows. 

G. 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 

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 monitors at Caney 

Creek and Upper Buffalo are IMPROVE 

monitors, we are proposing that ADEQ 

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. The IMPROVE monitor 

at Upper Buffalo was installed in 1991. 

Shortly after the creation of CENRAP, its 

monitoring workgroup noted there was 

a visibility void in Southern Arkansas. 

In 2001, the Caney Creek Wilderness 

area IMPROVE monitor was added to 

help fill that void. ADEQ also commits 

in the Arkansas RH SIP to evaluate the 

monitoring network periodically and 

consider evaluation technology changes 

and the need for new monitors. With the 

addition of the monitor at Caney Creek, 

we are proposing to find that ADEQ has 

satisfied this requirement. 

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

ADEQ establish procedures by which 

monitoring data and other information 

are used in determining the contribution 

of emissions from within Arkansas to 

RH visibility impairment at mandatory 

Class I Federal areas both within and 

outside the state. The monitor at Caney 

Creek is operated by Caney Creek 

Wilderness Area personnel, while the 

monitor at Upper Buffalo is operated by 

Upper Buffalo Wilderness Area 

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 

are therefore proposing that ADEQ 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, Arkansas 

should report visibility monitoring data 

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

also requires that ADEQ provide for 

other elements, including reporting, 

recordkeeping, and other measures, 

necessary to assess and report on 

visibility. We are proposing that 

Arkansas’ 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)(v) requires that 

ADEQ 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 ADEQ’s 

emission inventory. ADEQ has stated 

that it intends to update the Arkansas 

statewide emissions inventories 

periodically. We are proposing that this 

satisfies the requirement in section 

51.308(d)(4)(v). 

H. Federal Land Manager Coordination 

Both Caney Creek and Upper Buffalo 

are federally protected wilderness areas 

for which the United States Department 

of Agriculture (USDA) Forest Service is 

the FLM. Although the FLMs are very 

active in participating in the RPOs, the 

RHR grants the FLMs a special role in 

the review of the RH SIPs, summarized 

in section III.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, Arkansas must have 

identified in writing to the FLMs the 

title of the official to which the FLM of 

Caney Creek and Upper Buffalo 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), Arkansas 

was obligated to provide the Forest 

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 


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73A copy of the Arkansas Pollution Control and 

Ecology Commission’s Minute Order can be viewed 

at http://www.adeq.state.ar.us/ftproot/Pub/ 

commission/minute_orders/10-08_Petition_from_

Variance_Entergy_Swepco_AECC.pdf. 

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. ADEQ followed this 

practice and sent its draft of this 

implementation plan revision to the 

federal land manager staff on February 

22, 2008 and notified the federal land 

manager staff of the public hearing held 

on July 7, 2008. 

Section 51.308(i)(3) requires that 

ADEQ provide in its RH SIP a 

description of how it addressed any 

comments provided by the FLMs. ADEQ 

has provided that information in 

Appendix 2.1 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. ADEQ 

has stipulated in its RH SIP it will 

continue to coordinate and consult with 

the FLMs as required by section 

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

consult the FLMs in the development of 

future progress reports and plan 

revisions, as well as during the 

implementation of programs having the 

potential to contribute to visibility 

impairment at Caney Creek and Upper 

Buffalo. We are proposing that ADEQ 

has satisfied section 51.308(i). 

I. Periodic SIP Revisions and Five-year 

Progress Reports 

ADEQ affirmed its commitment to 

complete items required in the future 

under our RHR. ADEQ 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. 

ADEQ also acknowledged its 

requirement under 40 CFR 51.308(g), to 

submit a progress report in the form of 

a SIP revision to the us every five years 

following this initial submittal of the 

Arkansas RH SIP. The report will 

evaluate the progress made towards the 

RPGs for each mandatory Class I area 

located within Arkansas and in each 

mandatory Class I area located outside 

Arkansas which may be affected by 

emissions from within Arkansas. We are 

proposing that ADEQ has satisfied 

section 51.308(f) and (g). 

J. Determination of the Adequacy of 

Existing Implementation Plan 

Section 51.308(h) requires that 

Arkansas take one of the listed actions, 

as appropriate, at the same time the 

State is required to submit any 5-year 

progress report to EPA in accordance 

with section 51.308(g). ADEQ has 

committed in its SIP to take one of the 

actions listed under 51.308(h), 

depending on the findings of the fiveyear progress report. We are proposing 

that ADEQ has satisfied section 

51.308(h). 

V. Our Analysis of Arkansas’ Interstate 

Visibility Transport SIP Provisions 

We received a SIP from Arkansas to 

address the interstate transport 

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

the 1997 8-hour ozone and PM2.5

NAAQS on April 2, 2008. 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, Arkansas stated that the 

State’s RH Rule, the APC&E 

Commission Regulation 19, chapter 15, 

satisfies the requirement of section 

110(a)(2)(D)(i) regarding the protection 

of visibility. Arkansas indicated in the 

April 2, 2008 submittal that at the time, 

it was not possible 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 in other 

states, until such time as Arkansas 

submits and EPA approves the Arkansas 

RH SIP. 

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 

Arkansas, consistent with the BART 

determinations made by ADEQ. In the 

State’s September 27, 2011 

supplemental submittal, ADEQ clarified 

that the base year modeling inventory 

used by CENRAP in the 2002 base case 

modeling was prepared by the CENRAP 

Modeling Workgroup and its 

consultants, and was derived primarily 

from the 2002 National Emissions 

Inventory (NEI). ADEQ also clarified 

that it provided the CENRAP Modeling 

Workgroup with the controlled BART 

source emission limits contained in the 

State’s RH Rule, the APC&E 

Commission Regulation 19, Chapter 15, 

for inclusion in the CENRAP’s 2018 

future case modeling. ADEQ stated in its 

Interstate Transport SIP that it is relying 

on the State RH Rule to meet the 

visibility prong of the transport 

requirements of section 

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

State’s RH Rule became effective 

October 15, 2007. The current language 

of the regulation requires Arkansas’ 

subject to BART sources to comply with 

BART requirements no later than five 

years after EPA approval of the RH SIP 

or 6 years after the effective date of the 

regulation, whichever is first. However, 

on March 26, 2010, the Arkansas 

Pollution Control & Ecology 

Commission, Arkansas’ rulemaking 

body, granted all Arkansas subject to 

BART sources a variance from the 

compliance deadline imposed by the 

State’s RH Rule, such that these sources 

are now required to comply with BART 

requirements no later than 5 years after 

EPA approval of the RH SIP.73

Compliance with these BART 

requirements will ensure that Arkansas 

obtains its share of the emission 

reductions relied upon by other states to 

meet the RPGs for their Class I areas. 

Since compliance of Arkansas’ subject 

to BART sources with BART 

requirements is dependent upon our 

approval of the RH SIP, and since we 

are proposing to disapprove a portion of 

the RH SIP, including some of Arkansas’ 


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BART determinations, a portion of the 

emission reductions committed to by 

Arkansas and relied upon by other 

states will not be realized. 

As we are proposing to disapprove a 

majority of the BART determinations 

made by ADEQ for its subject to BART 

sources, we are proposing to find that 

the Arkansas SIP revision submittal 

does not fully ensure that emissions 

from sources in Arkansas do not 

interfere with other State’s visibility 

programs as required by section 

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

Specifically, the BART determinations 

we are proposing to disapprove, will not 

result in the corresponding emission 

reductions other states relied on to 

achieve the RPGs in their Class I areas. 

Therefore, we are proposing to partially 

approve and partially disapprove the 

portion of the Arkansas Interstate 

Transport SIP submittal that addresses 

the visibility requirement of section 

110(a)(2)(D)(i)(II) that emissions from 

Arkansas sources not interfere with 

measures required in the SIP of any 

other state under part C of the CAA to 

protect visibility. 

VI. Proposed Action 

A. Regional Haze 

We are proposing to partially approve 

and partially disapprove Arkansas’ RH 

SIP revision submitted on September 

23, 2008, August 3, 2010, and 

supplemented on September 27, 2011. 

Specifically, we are proposing to 

approve the following: 

• The State’s identification of affected 

Class I areas; 

• The establishment of baseline and 

natural visibility conditions; 

• The Uniform Rate of Progress 

(URP); 

• The State’s reasonable progress goal 

(RPG) consultation and the long-term 

strategy (LTS) consultation; 

• The regional haze monitoring 

strategy and other SIP requirements 

under section 51.308(d)(4); 

• The State’s commitment to submit 

periodic regional haze SIP revisions and 

periodic progress reports describing 

progress towards the RPGs; 

• The State’s commitment to make a 

determination of the adequacy of the 

existing SIP at the time a progress report 

is submitted; 

• And the State’s consultation and 

coordination with Federal land 

managers (FLMs) 

We are proposing to disapprove the 

State’s RPGs because Arkansas did not 

consider the four statutory factors that 

states are required to consider in 

establishing RPGs under the CAA and 

section 51.308(d)(1)(A). 

We are proposing to partially approve 

and partially disapprove the portions of 

these submittals addressing the State’s 

identification of subject to BART 

sources; the requirements for best 

available retrofit technology (BART); the 

State’s RH Rule; and the LTS. 

Specifically, we are proposing to 

approve the following: 

• The State’s identification of BARTeligible sources, with the exception of 

the 6A Boiler at the Georgia-Pacific 

Crossett Mill, which we are proposing to 

find is BART-eligible; 

• The State’s identification of subject 

to BART sources, with the exception of 

its determination that the 6A and 9A 

Boilers at the Georgia-Pacific Crossett 

Mill are not subject to BART; 

• The following BART 

determinations made by ADEQ: the PM 

BART determination for the No. 1 Boiler 

of the AEP Flint Creek plant; the SO2

and PM BART determinations for the 

natural gas firing scenario for Unit 4 of 

the Entergy Lake Catherine plant; the 

PM BART determinations for both the 

bituminous and sub-bituminous coal 

firing scenarios for Units 1 and 2 of the 

Entergy White Bluff plant; and the PM 

BART determination for the No. 1 

Power Boiler of the Domtar Ashdown 

Mill; 

• The portion of the submittal we 

received on September 23, 2008, and as 

revised by the submittal received on 

August 3, 2010, that contains those 

portions of Chapter 15 of APC&E 

Commission Regulation 19 which 

correspond to the portions of the 

Arkansas RH SIP we are proposing to 

approve. Specifically, we are proposing 

to approve the following sections of 

Chapter 15 of APC&E Commission 

Regulation 19: Reg. 19.1501; Reg. 

19.1502; Reg. 19.1503; the portion of 

Reg. 19.1504(A) that identifies AECC 

Bailey Generating Station (Unit 1), 

AECC McClellan Generating Station 

(Unit 1), Domtar Ashdown Mill (Power 

Boilers No. 1 and 2), Lake Catherine 

(Unit 4), White Bluff (Units 1, 2, and the 

Auxiliary Boiler), and AEP Flint Creek 

(Boiler No. 1) as subject to BART 

sources; Reg. 19.1504(B); Reg. 

19.1504(C); Reg. 19.1505(A)(3); Reg. 

19.1505(D)(3); Reg. 19.1505(F)(3); Reg. 

19.1505(G)(3); Reg. 19.1505(I)(3); Reg. 

19.1505(J)(3); Reg. 19.1505(M)(2); Reg. 

19.1506; and Reg. 19.1507; and 

• The State’s LTS, with the exception 

of the portion of the LTS that relied on 

the BART emission limits and schedules 

of compliance we are proposing to 

disapprove. 

We are proposing to disapprove the 

following: 

• ADEQ’s determination that the 6A 

and 9A Boilers of the Georgia-Pacific 

Crossett Mill are not subject to BART; 

• The following BART 

determinations made by ADEQ: the 

NOX, PM, and SO2 BART 

determinations for both Unit 1 of the 

Arkansas Electric Cooperative 

Corporation (AECC) Bailey plant and 

Unit 1 of the AECC McClellan plant; the 

SO2 and NOX BART determinations for 

the No. 1 Boiler of the American Electric 

Power (AEP) Flint Creek plant; the NOx 

BART determination for the natural gas 

firing scenario and the PM, SO2, and 

NOX BART determinations for the fuel 

oil firing scenario for Unit 4 of the 

Entergy Lake Catherine plant; the SO2

and NOX BART determinations for both 

the bituminous and sub-bituminous coal 

firing scenarios for Units 1 and 2 of the 

Entergy White Bluff plant; the BART 

determination for the Auxiliary Boiler of 

the Entergy White Bluff Plant; the SO2

and NOX BART determinations for the 

No. 1 Power Boiler of the Domtar 

Ashdown Mill; and the SO2, NOX, and 

PM BART determinations for the No. 2 

Power Boiler of the Domtar Ashdown 

Mill; 

• A portion of Arkansas’ Regional 

Haze Rule, APC&E Commission 

Regulation 19, chapter 15, which we 

received on September 23, 2008, and as 

revised by the submittal received on 

August 3, 2010. Specifically, we are 

proposing to disapprove the following 

sections of Chapter 15 of APC&E 

Commission Regulation 19: The portion 

of Reg. 19.1504(A) that fails to identify 

the 6A and 9A Boilers at the GeorgiaPacific Crossett Mill as subject to BART 

sources; Reg. 19.1505(A)(1); Reg. 

19.1505(A)(2); Reg. 19.1505(B); Reg. 

19.1505(C); Reg. 19.1505(D)(1); Reg. 

19.1505(D)(2); Reg. 19.1505(E)(1); Reg. 

19.1505(E)(2); Reg. 19.1505(E)(3); Reg. 

19.1505(F)(1); Reg. 19.1505(F)(2); Reg. 

19.1505(G)(1); Reg. 19.1505(G)(2); Reg. 

19.1505(H); Reg. 19.1505(I)(1); Reg. 

19.1505(I)(2); Reg. 19.1505(J)(1); Reg. 

19.1505(J)(2); Reg. 19.1505(K); Reg. 

19.1505(L); Reg. 19.1505(M)(1); Reg. 

19.1505(N)(1); Reg. 19.1505(N)(2); and 

Reg. 19.1505(N)(3); and 

• The portion of the State’s LTS that 

relied on the BART emission limits and 

schedules of compliance we are 

proposing to disapprove. 

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 Arkansas 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. 


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Specifically, we are proposing a partial 

approval and partial disapproval of the 

Arkansas Interstate Transport SIP 

provisions that address the requirement 

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

emissions from Arkansas sources not 

interfere with measures required in the 

SIP of any other state under part C of the 

CAA to protect visibility. Although the 

BART emission limits we are proposing 

to approve will result in the 

corresponding emission reductions 

other states relied on to achieve the 

RPGs in their Class I areas, the BART 

emission limits we are proposing to 

disapprove will not result in the 

corresponding emission reductions 

other states relied on to achieve the 

RPGs in their Class I areas. Therefore, 

ADEQ will obtain only a portion of its 

share of the emission reductions relied 

upon by other states to meet the RPGs 

for their Class I areas. 

VII. Statutory and Executive Order 

Reviews 

Under the Clean Air Act, the 

Administrator is required to approve a 

SIP submission that complies with the 

provisions of the Act and applicable 

Federal regulations. 42 U.S.C. 7410(k); 

40 CFR 52.02(a). Thus, in reviewing SIP 

submissions, EPA’s role is to approve 

state choices, provided that they meet 

the criteria of the Clean Air Act. 

Accordingly, this action merely 

proposes to approve state law as 

meeting Federal requirements and does 

not impose additional requirements 

beyond those imposed by state law. For 

that reason, this action: 

• Is not a ‘‘significant regulatory 

action’’ subject to review by the Office 

of Management and Budget under 

Executive Order 12866 (58 FR 51735, 

October 4, 1993); 

• Does not impose an information 

collection burden under the provisions 

of the Paperwork Reduction Act (44 

U.S.C. 3501 et seq.); 

• Is certified as not having a 

significant economic impact on a 

substantial number of small entities 

under the Regulatory Flexibility Act 

(5 U.S.C. 601 et seq.); 

• Does not contain any unfunded 

mandate or significantly or uniquely 

affect small governments, as described 

in the Unfunded Mandates Reform Act 

of 1995 (Pub. L. 104–4); 

• Does not have Federalism 

implications as specified in Executive 

Order 13132 (64 FR 43255, August 10, 

1999); 

• Is not an economically significant 

regulatory action based on health or 

safety risks subject to Executive Order 

13045 (62 FR 19885, April 23, 1997); 

• Is not a significant regulatory action 

subject to Executive Order 13211 (66 FR 

28355, May 22, 2001); 

• Is not subject to requirements of 

section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (15 U.S.C. 272 note) because 

application of those requirements would 

be inconsistent with the Clean Air Act; 

and 

• Does not provide EPA with the 

discretionary authority to address, as 

appropriate, disproportionate human 

health or environmental effects, using 

practicable and legally permissible 

methods, under Executive Order 12898 

(59 FR 7629, February 16, 1994). 

In addition, this rule does not have 

tribal implications as specified by 

Executive Order 13175 (65 FR 67249, 

November 9, 2000), because the SIP is 

not approved to apply in Indian country 

located in the state, and EPA notes that 

it will not impose substantial direct 

costs on tribal governments or preempt 

tribal 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. 

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

Dated: October 3, 2011. 

Al Armendariz, 

Regional Administrator, Region 6. 

[FR Doc. 2011–26336 Filed 10–14–11; 8:45 am] 

BILLING CODE 6560–50–P 


jlentini on DSK4TPTVN1PROD with PROPOSALS2