18944 Federal Register / Vol. 80, No. 67 / Wednesday, April 8, 2015 / Proposed Rules 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 52 

[EPA–R06–OAR–2015–0189; FRL–9924–85– 

Region 6] 

Promulgation of Air Quality 

Implementation Plans; State of 

Arkansas; Regional Haze and 

Interstate Visibility Transport Federal 

Implementation Plan 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Proposed rule. 

SUMMARY: The Environmental Protection 

Agency (EPA) is proposing to 

promulgate a Federal Implementation 

Plan (FIP) to address certain regional 

haze and visibility transport 

requirements for the State of Arkansas. 

This FIP would address the 

requirements of the Regional Haze Rule 

(RHR) and interstate visibility transport 

for those portions of Arkansas’ State 

Implementation Plan (SIP) we 

disapproved in our final action 

published on March 12, 2012. 

Specifically, the proposed FIP addresses 

the requirements for Best Available 

Retrofit Technology (BART) for those 

sources for which we did not approve 

Arkansas’ BART determinations, 

Reasonable Progress Goals (RPGs), 

reasonable progress controls and a longterm strategy, as well as the interstate 

visibility transport requirements for 

pollutants that affect visibility in Class 

I areas in nearby states. Specific to the 

reasonable progress controls 

requirement, we are proposing in the 

alternative two options for controlling 

the emissions from the Entergy 

Independence Plant that is not subject 

to BART. Under Option 1, we are 

proposing controls for emissions of SO2, 

and NOX. If we take final action on this 

finding, the source will be subject to 

controls for both pollutants. 

Alternatively, under Option 2, we are 

proposing controls for only emissions of 

SO2 for this planning period. In 

particular, we are soliciting comments 

on the alternate proposed Options 1 and 

2. 

DATES: Comments: Comments must be 

received on or before May 16, 2015. 

Public Hearing: We are holding 

information sessions—for the purpose of 

providing additional information and 

informal discussion for our proposal, 

and public hearings—to accept oral 

comments into the record, as follows: 

Date: Thursday, April 16, 2015. 

Time: Information Session: 9 a.m.– 

9:45 a.m. (break from 9:45 a.m.–10 a.m.) 

Public hearing: 10 a.m.–11:30 a.m. 

(break from 11:30 a.m.–1 p.m.) 

Information Session: 1 p.m.–1:45 p.m. 

(break from 1:45 p.m.–2 p.m.) 

Public hearing: 2 p.m.–7:30 p.m. 

(including break from 4 p.m.–4:30 p.m.). 

Please see the ADDRESSES section for 

the location of the hearing in North 

Little Rock, AR. 

ADDRESSES: Submit your comments, 

identified by Docket No. EPA–R06– 

OAR–2015–0189, by one of the 

following methods: 

• Federal e-Rulemaking Portal: http:// 

www.regulations.gov. Follow the online 

instructions for submitting comments. 

• Email: R6AIR_ARHaze@epa.gov. 

• 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 700, 

Dallas, Texas 75202–2733. Such 

deliveries are accepted only between the 

hours of 8 a.m. and 4 p.m. weekdays, 

and not on legal holidays. Special 

arrangements should be made for 

deliveries of boxed information. 

• Fax: Mr. Guy Donaldson, Chief, Air 

Planning Section (6PD–L), at fax 

number 214–665–7263. 

Instructions: Direct your comments to 

Docket No. EPA–R06–OAR–2015–0189. 

Our policy is that all comments received 

will be included in the public docket 

without change and may be made 

available online at www.regulations.gov, 

including any personal information 

provided, unless the comment includes 

information claimed to be Confidential 

Business Information (CBI) or other 

information whose disclosure is 

restricted by statute. Do not submit 

information that you consider to be CBI 

or otherwise protected through 

www.regulations.gov or email. The 

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 email comment directly 

to us without going through 

www.regulations.gov your email 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 and any 

form of encryption, and be free of any 

defects or viruses. 

Docket: All documents in the docket 

are listed in the 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. SIP 

materials which are incorporated by 

reference into 40 Code of Federal 

Regulations (CFR) part 52 are available 

for inspection at the following location: 

Environmental Protection Agency, 

Region 6, 1445 Ross Avenue, Suite 700, 

Dallas, TX 75202. Publicly available 

materials are available either 

electronically in www.regulations.gov or 

in hard copy at the Region 6 office. The 

Regional Office hours are Monday 

through Friday, 8:30 to 4:30, excluding 

Federal holidays. 

Hearing location: Arkansas 

Department of Environmental Quality, 

Commission Room, 1st floor, 5301 

Northshore Drive, North Little Rock, AR 

72118. 

The public hearing will provide 

interested parties the opportunity to 

present information and opinions to us 

concerning our proposal. Interested 

parties may also submit written 

comments, as discussed in the proposal. 

Written statements and supporting 

information submitted during the 

comment period will be considered 

with the same weight as any oral 

comments and supporting information 

presented at the public hearing. We will 

not respond to comments during the 

public hearings. When we publish our 

final action, we will provide written 

responses to all significant oral and 

written comments received on our 

proposal. To provide opportunities for 

questions and discussion, we will hold 

an information session prior to the 

public hearing. During the information 

session, EPA staff will be available to 

informally answer questions on our 

proposed action. Any comments made 

to EPA staff during an information 

session must still be provided orally 

during the public hearing, or formally in 

writing within 30 days after completion 

of the hearings, in order to be 

considered in the record. At the public 

hearings, the hearing officer may limit 

the time available for each commenter 

to address the proposal to three minutes 

or less if the hearing officer determines 

it to be appropriate. We will not be 

providing equipment for commenters to 

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Federal Register / Vol. 80, No. 67 / Wednesday, April 8, 2015 / Proposed Rules 18945 

1 Visual range is the greatest distance, in 

kilometers or miles, at which a dark object can be 

viewed against the sky. 

2Areas 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. 42 U.S.C. 

7472(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. 44 FR 

69122 (November 30, 1979). The extent of a 

mandatory Class I area includes subsequent changes 

in boundaries, such as park expansions. 42 U.S.C. 

7472(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.’’ 42 U.S.C. 7602(i). When we use the term 

‘‘Class I area’’ in this action, we mean a ‘‘mandatory 

Class I Federal area.’’ 

3 45 FR 80084 (December 2, 1980). 

4 64 FR 35714 (July 1, 1999), codified at 40 CFR 

part 51, subpart P (Regional Haze Rule). 

5See 40 CFR 51.308(b). EPA’s regional haze 

regulations require subsequent updates to the 

regional haze SIPs. 40 CFR 51.308(g)–(i). 

6 77 FR 14604, March 12, 2012. 

show overhead slides or make 

computerized slide presentations. Any 

person may provide written or oral 

comments and data pertaining to our 

proposal at the public hearings. 

Verbatim English language transcripts of 

the hearing and written statements will 

be included in the rulemaking docket. 

FOR FURTHER INFORMATION CONTACT: To 

schedule your inspection, contact Ms. 

Dayana Medina at (214) 665–7241 or via 

electronic mail at medina.dayana@

epa.gov. 

SUPPLEMENTARY INFORMATION: 

Throughout this document wherever 

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

the EPA. 

Table of Contents 

I. Background 

II. Overview of Proposed Actions 

A. Regional Haze 

B. Interstate Transport of Pollutants That 

Affect Visibility 

C. History of State Submittals and Our 

Actions 

D. Our Authority To Promulgate a FIP 

III. Our Proposed BART Analyses and 

Determinations 

A. Identification of BART-Eligible Sources 

and Subject to BART Sources 

1. Georgia Pacific-Crossett Mill 6A and 9A 

Power Boilers 

2. AECC Carl E. Bailey Generating Station 

Unit 1 

B. BART Factors 

C. BART Determinations and Proposed 

Federally Enforceable Limits 

1. AECC Carl E. Bailey Generating Station 

2. AECC John L. McClellan Generating 

Station 

3. AEP Flint Creek Power Plant 

4. Entergy White Bluff Plant 

5. Entergy Lake Catherine Plant 

6. Domtar Ashdown Paper Mill 

IV. Our Proposed Reasonable Progress 

Analysis and Determinations 

A. Reasonable Progress Analysis of Point 

Sources 

1. Entergy Independence Plant Units 1 and 

2 

B. Reasonable Progress Goals 

V. Our Proposed Long-Term Strategy 

VI. Our Proposal for Interstate Visibility 

Transport 

VII. Summary of Proposed Actions 

A. Regional Haze 

B. Interstate Visibility Transport 

VIII. Statutory and Executive Order Reviews 

I. Background 

Regional haze is visibility impairment 

that is produced by a multitude of 

sources and activities that are located 

across a broad geographic area and emit 

fine particulates (PM2.5) (e.g., sulfates, 

nitrates, organic carbon (OC), elemental 

carbon (EC), and soil dust), and their 

precursors (e.g., sulfur dioxide (SO2), 

nitrogen oxides (NOX), and in some 

cases, ammonia (NH3) and volatile 

organic compounds (VOC)). Fine 

particle precursors react in the 

atmosphere to form PM2.5, which 

impairs visibility by scattering and 

absorbing light. Visibility impairment 

reduces the clarity, color, and visible 

distance that one can see. PM2.5 can also 

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 parks and wilderness areas. 

The average visual range 1 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. In most of the eastern Class 

I areas of the United States, the average 

visual range is less than 30 kilometers, 

or about one-fifth of the visual range 

that would exist under estimated 

natural conditions. 64 FR 35715 (July 1, 

1999). 

In section 169A of the 1977 

Amendments to the Clean Air Act 

(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 man-made impairment of 

visibility in 156 national parks and 

wilderness areas designated as 

mandatory Class I Federal areas.2 On 

December 2, 1980, EPA 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.’’ 3 These regulations 

represented the first phase in addressing 

visibility impairment. EPA deferred 

action on regional haze that emanates 

from a variety of sources until 

monitoring, modeling, and scientific 

knowledge about the relationships 

between pollutants and visibility 

impairment were improved. 

Congress added section 169B to the 

CAA in 1990 to address regional haze 

issues, and we promulgated regulations 

addressing regional haze in 1999.4 The 

Regional Haze Rule (RHR) revised the 

existing visibility regulations to 

integrate into the regulations provisions 

addressing regional haze impairment 

and established a comprehensive 

visibility protection program for Class I 

areas. The requirements for regional 

haze, found at 40 CFR 51.308 and 

51.309, are included in our visibility 

protection regulations at 40 CFR 

51.300–309. The requirement to submit 

a regional haze SIP applies to all 50 

states, the District of Columbia, and the 

Virgin Islands. States were required to 

submit the first implementation plan 

addressing regional haze visibility 

impairment no later than December 17, 

2007.5

II. Overview of Proposed Actions 

A. Regional Haze 

We are proposing to promulgate a FIP 

as described in this notice and 

summarized in this section to address 

those portions of Arkansas’ regional 

haze SIP that we disapproved on March 

12, 2012.6 In our March 12, 2012 final 

action, we disapproved Arkansas’ BART 

control analyses and determinations for 

nine units at six facilities and the 

Reasonable Progress Goals (RPGs) 

analysis and RPGs set by Arkansas, and 

partially disapproved the long-term 

strategy for making reasonable progress. 

We are proposing this FIP because 

Arkansas has not provided a revision to 

its SIP to address the deficiencies 

identified in our March 12, 2012 partial 

disapproval. We believe, however, it is 

preferable for states to take the lead in 

implementing the Regional Haze 

requirements as envisioned by the Clean 

Air Act. We will work with the State of 

Arkansas if it chooses to develop a SIP 

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18946 Federal Register / Vol. 80, No. 67 / Wednesday, April 8, 2015 / Proposed Rules 

7 77 FR 14604, March 12, 2012. 8 Id. 

to meet the Regional Haze requirements 

to replace this proposed FIP. 

The FIP we are proposing includes 

BART control determinations for 

sources in Arkansas without previously 

approved BART determinations and 

associated compliance schedules and 

requirements for equipment 

maintenance, monitoring, testing, 

recordkeeping, and reporting for all 

affected sources and units. The BART 

sources addressed in this FIP cause or 

contribute to visibility impairment at 

one or more Class I areas in Arkansas 

and Missouri. The two Class I areas in 

Arkansas are the Caney Creek 

Wilderness Area and the Upper Buffalo 

Wilderness Area. The two Class I areas 

in Missouri are the Hercules-Glades 

Wilderness Area and the Mingo 

National Wildlife Refuge. In this FIP, we 

are proposing SO2, NOX, and PM BART 

control determinations for nine units at 

six facilities in Arkansas. We are 

proposing SO2, NOX, and PM BART 

determinations for Unit 1 of the 

Arkansas Electric Cooperative 

Corporation (AECC) Carl E. Bailey 

Generating Station; SO2, NOX, and PM 

BART determinations for Unit 1 of the 

AECC John L. McClellan Generating 

Station; SO2 and NOX BART 

determinations for Boiler No. 1 of the 

American Electric Power (AEP) Flint 

Creek Power Plant; SO2 and NOX BART 

determinations for Units 1 and 2 and 

SO2, NOX, and PM BART 

determinations for the Auxiliary Boiler 

of the Entergy White Bluff Plant; NOX

BART determination for Unit 4 of the 

Entergy Lake Catherine Plant; SO2 and 

NOX BART determinations for Power 

Boiler No. 1 and SO2, NOX and PM 

BART determinations for Power Boiler 

No. 2 of the Domtar Ashdown Mill. 

Additionally, for the reasonable 

progress requirements, we are proposing 

in the alternative two options for 

controlling the emissions from the 

Entergy Independence Plant that is not 

subject to BART. Under Option 1, under 

the reasonable progress requirements, 

we are proposing controls for emissions 

of SO2 and NOX for Units 1 and 2 of the 

Entergy Independence Plant. 

Alternatively, under Option 2, we are 

proposing controls for only emissions of 

SO2 for the first planning period. We 

solicit comments on this proposed 

alternative approach. We are also 

soliciting public comment on any 

alternative control measures for Entergy 

White Bluff Units 1 and 2 and 

Independence Units 1 and 2 that would 

address the BART and reasonable 

progress requirements for these four 

units for this regional haze planning 

period. The measures in the FIP that we 

are proposing will reduce emissions that 

contribute to regional haze in Arkansas’ 

Class I areas and other nearby Class I 

areas. RPGs are interim visibility goals 

towards meeting the CAA’s national 

visibility goal of preventing any future, 

and remedying any existing, impairment 

of visibility resulting from manmade air 

pollution in Class I areas. This proposed 

FIP and the portion of the Arkansas 

regional haze SIP that we approved on 

March 12, 2012, together would ensure 

that progress is made toward natural 

visibility conditions at these Class I 

areas. This proposed action and the 

accompanying documents that are 

available in the Docket explain the basis 

for our proposed Arkansas Regional 

Haze FIP. Please refer to our previous 

rulemaking on the Arkansas regional 

haze SIP for additional background 

regarding the CAA, regional haze, and 

our RHR.7

B. Interstate Transport of Pollutants 

That Affect Visibility 

We propose that a combination of 

those portions of the Arkansas regional 

haze SIP that we previously approved 

and the measures in the FIP will satisfy 

the visibility requirement of CAA 

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

hour ozone and 1997 PM2.5 national 

ambient air quality standards (NAAQS). 

CAA section 110(a)(2)(D)(i)(II) requires 

that states have a SIP, or submit a SIP 

revision, containing provisions 

‘‘prohibiting any source or other type of 

emission activity within the state from 

emitting any air pollutant in amounts 

which will . . . interfere with measures 

required to be included in the 

applicable implementation plan for any 

other State under part C [of the CAA] to 

protect visibility.’’ Because of the 

impacts on visibility from the interstate 

transport of pollutants, we interpret 

these ‘‘good neighbor’’ provisions of 

section 110 of the Act as requiring states 

to include in their SIPs measures to 

prohibit emissions that would interfere 

with the reasonable progress goals set to 

protect Class I areas in other states. For 

Arkansas, we interpret this to mean that 

the State must include in its SIP a 

demonstration that emissions from 

Arkansas sources and activities will not 

have the prohibited impacts on other 

states’ existing SIPs. We refer herein to 

this requirement as the interstate 

transport visibility requirement. The 

Arkansas Department of Environmental 

Quality (ADEQ) submitted a SIP 

revision to address this requirement on 

April 2, 2008, and submitted 

supplemental information on September 

27, 2011. The April 2, 2008 submittal 

stated that Arkansas is relying on the 

Air Pollution Control and Ecology 

Commission (APCEC) Regulation 19, 

Chapter 15, also known as the State 

BART rulemaking, to satisfy the 

requirements of section 

110(a)(2)(D)(i)(II) with respect to 

visibility transport. The April 2, 2008 

SIP submittal, which was submitted 

prior to Arkansas’ submission of the 

Arkansas regional haze SIP, also stated 

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 1997 8-hour ozone and 

PM2.5 NAAQS until Arkansas submits 

and we approve the Arkansas regional 

haze SIP. In our final rule published on 

March 12, 2012, we partially approved 

and partially disapproved the SIP 

submittal with respect to the interstate 

transport visibility requirement under 

CAA section 110(a)(2)(D)(i)(II), 

triggering the obligation for us to 

promulgate a FIP or to fully approve a 

revised SIP submission from Arkansas 

to ensure that the requirement is fully 

addressed.8 Today’s notice describes 

our proposed FIP, which we propose to 

find will fully address the deficiencies 

we identified in our prior partial 

disapproval action of Arkansas’ SIP 

submittal with respect to the interstate 

visibility transport requirement under 

CAA section 110(a)(2)(D)(i)(II) for the 

1997 8-hour ozone and 1997 PM2.5

NAAQS. 

C. History of State Submittals and Our 

Actions 

As discussed above, Arkansas 

submitted a SIP revision on April 2, 

2008, to address the interstate transport 

visibility requirement of CAA section 

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

ozone and 1997 PM2.5 NAAQS. To 

address the first regional haze 

implementation period, Arkansas 

submitted a regional haze SIP on 

September 23, 2008. On August 3, 2010, 

Arkansas submitted a SIP revision with 

non-substantive revisions to the APCEC 

Regulation 19, Chapter 15, which 

identified the BART-eligible and 

subject-to-BART sources in Arkansas 

and established the BART emission 

limits that subject-to-BART sources are 

required to comply with. On September 

27, 2011, the State submitted 

supplemental information on the 

Arkansas regional haze SIP. We are 

hereafter referring to these regional haze 

submittals collectively as the ‘‘2008 

Arkansas RH SIP.’’ On March 12, 2012, 

we partially approved and partially 

disapproved the 2008 Arkansas RH SIP 

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Federal Register / Vol. 80, No. 67 / Wednesday, April 8, 2015 / Proposed Rules 18947 

9 Id. 

10 76 FR 64186 and 77 FR 14604. 

11May 18, 2012 letter from James W. Cutbirth, 

Environmental Services Superintendent at GeorgiaPacific Crossett Paper Operations, to Mary 

Pettyjohn, ADEQ. A copy of this letter can be found 

in the docket for this proposed rulemaking. 

12See ADEQ Operating Air Permit No. 0597– 

AOP–R14, issued on May 23, 2012. A copy of the 

air permit can be found in the docket for this 

proposed rulemaking. 

and the April 2, 2008 SIP submittal 

concerning the interstate transport 

visibility requirements for the 1997 8- 

hour ozone and 1997 PM2.5 NAAQS.9

Our partial disapproval of the 2008 

Arkansas RH SIP included a disapproval 

of the following BART determinations 

made by Arkansas: 

• SO2, NOX, and PM BART for the 

AECC Carl E. Bailey Generating Station 

Unit 1; 

• SO2, NOX, and PM BART for the 

AECC John L. McClellan Generating 

Station Unit 1; 

• SO2 and NOX BART for the AEP 

Flint Creek Power Plant No. 1 Boiler; 

• SO2 and NOX BART for the 

bituminous and sub-bituminous coal 

firing scenarios for the Entergy White 

Bluff Plant Units 1 and 2; 

• SO2, NOX, and PM BART for the 

Entergy White Bluff Plant Auxiliary 

Boiler; 

• NOX BART for the natural gas firing 

scenario for the Entergy Lake Catherine 

Plant Unit 4; 

• SO2, NOX, and PM BART for the 

fuel oil firing scenario for the Entergy 

Lake Catherine Plant Unit 4; 

• SO2 and NOX BART for the Domtar 

Ashdown Mill No. 1 Power Boiler; and 

• SO2, NOX, and PM BART for the 

Domtar Ashdown Mill No. 2 Power 

Boiler. 

In our final action, we also 

disapproved Arkansas’ determinations 

that the Georgia Pacific-Crossett Mill 6A 

Boiler is not BART-eligible, and that the 

6A and 9A Boilers are not subject to 

BART. By partially disapproving 

Arkansas’ BART determinations, we 

also partially disapproved the 

corresponding provisions of APCEC 

Regulation 19, Chapter 15. We also 

disapproved Arkansas’ RPGs for its two 

Class I areas, the Caney Creek 

Wilderness Area and the Upper Buffalo 

Wilderness Area, because Arkansas did 

not meet the requirement under section 

169A(g)(1) of the CAA and 40 CFR 

51.308(d)(1)(i)(A) to consider the four 

statutory factors when establishing its 

RPGs. Additionally, we partially 

disapproved Arkansas’ long-term 

strategy because it relied on other 

disapproved portions of the SIP. 

D. Our Authority To Promulgate a FIP 

Under section 110(c) of the Act, 

whenever we disapprove a mandatory 

SIP submission in whole or in part, we 

are required to promulgate a FIP within 

2 years unless we approve a SIP revision 

correcting the deficiencies before 

promulgating a FIP. Specifically, CAA 

section 110(c) provides that the 

Administrator shall promulgate a FIP 

within 2 years after the Administrator 

disapproves a state implementation plan 

submission ‘‘unless the State corrects 

the deficiency, and the Administrator 

approves the plan or plan revision, 

before the Administrator promulgates 

such Federal implementation plan.’’ 

The term ‘‘Federal implementation 

plan’’ is defined in section 302(y) of the 

CAA in pertinent part as a plan 

promulgated by the Administrator to 

correct an inadequacy in a SIP. 

Thus, because we partially 

disapproved the 2008 Arkansas RH SIP 

and the SIP submittal addressing the 

interstate transport visibility 

requirement, we are required to 

promulgate a FIP for Arkansas, unless 

we first approve a SIP revision that 

corrects the disapproved portions of 

these SIP submittals. As Arkansas has 

not as yet submitted a revised SIP 

following our partial disapproval, we 

are proposing a FIP to address those 

portions of the SIP that we disapproved. 

III. Our Proposed BART Analyses and 

Determinations 

Following our 2012 disapproval of the 

2008 Arkansas RH SIP, Arkansas began 

the process of generating additional 

technical information and analysis for 

the BART determinations. Arkansas 

gathered technical documentation from 

the companies whose BART 

determinations we disapproved. These 

documents were provided to us and are 

the basis for our evaluation of BART 

determinations for the facilities with 

prior disapproved BART 

determinations. 

A. Identification of BART-Eligible 

Sources and Subject to BART Sources 

States are required to identify all the 

BART-eligible sources within their 

boundaries by utilizing the three 

eligibility criteria in the BART 

Guidelines (70 FR 39158) and the RHR 

(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 the unit was in 

existence on August 6, 1977; and (3) the 

potential emissions of any visibilityimpairing pollutant from subject units 

are 250 tons or more per year. Sources 

that meet these three criteria are 

considered BART-eligible. Once a list of 

the BART-eligible sources within a state 

has been compiled, states must 

determine whether to make BART 

determinations for all of them or to 

consider exempting some of them from 

BART because they may not reasonably 

be anticipated to cause or contribute to 

any visibility impairment in a Class I 

area. The BART Guidelines present 

several options that rely on modeling 

and/or emissions analyses to determine 

if a source may reasonably be 

anticipated to cause or contribute to 

visibility impairment in a Class I area. 

A source that may not be reasonably 

anticipated to cause or contribute to any 

visibility impairment in a Class I area is 

not ‘‘subject to BART,’’ and for such 

sources, a state need not apply the five 

statutory factors to make a BART 

determination. 

1. Georgia Pacific-Crossett Mill 6A and 

9A Power Boilers 

In our March 12, 2012 final action, we 

approved Arkansas’ identification of 

BART-eligible sources except for the 

Georgia-Pacific Crossett Mill 6A Boiler. 

We also approved Arkansas’ 

determination of which sources are 

subject to BART, with the exception of 

its determination that the GeorgiaPacific Crossett Mill 6A and 9A Boilers 

are not subject to BART. Our basis and 

analyses for our disapproval of 

Arkansas’ determinations that the 6A 

Boiler is not BART-eligible and that the 

6A and 9A Boilers are not subject to 

BART is found in our October 17, 2011 

proposed rulemaking, March 12, 2012 

final rulemaking, and the associated 

TSDs.10

A revised Title V permit for the 

Georgia-Pacific Crossett Mill was issued 

on August 4, 2011, and again on May 

23, 2012. Although no pollution 

controls were installed, the permitted 

emission limits for SO2 and PM10 for the 

6A Boiler and SO2, NOX, and PM10 for 

the 9A Boiler were revised to be more 

stringent. In a letter dated May 18, 

2012,11 Georgia-Pacific explained to 

ADEQ that it had conducted additional 

dispersion modeling in 2011 based on 

the currently enforceable Title V permit 

limits for the 6A and 9A Boilers.12 The 

results of the 2011 modeling analysis 

are summarized in the table below. 

Based on modeling of the current permit 

limits, the boilers’ maximum visibility 

impact was modeled to be 0.359 dv at 

Caney Creek (assuming 2002 

meteorology). In the letter to ADEQ, 

Georgia-Pacific stated its belief that the 

2011 dispersion modeling analysis and 

the current Title V permit that enforces 

the modeled limits are sufficient to 

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18948 Federal Register / Vol. 80, No. 67 / Wednesday, April 8, 2015 / Proposed Rules 

13April 1, 2013 letter from James W. Cutbirth, 

Environmental Services Superintendent at GeorgiaPacific Crossett Paper Operations, to Mary 

Pettyjohn, ADEQ. A copy of this letter and all 

attachments can be found in the docket for this 

proposed rulemaking. 

14AP–42, Compilation of Air Pollutant Emission 

Factors, has been published since 1972 as the 

primary compilation of EPA’s emission factor 

information. It contains emission factors and 

process information for more than 200 air pollution 

source categories. The emission factors have been 

developed and compiled from source test data, 

material balance studies, and engineering estimates. 

The Fifth Edition of AP–42 was published in 

January 1995. Since then, EPA has published 

supplements and updates to the fifteen chapters 

available in Volume I, Stationary Point and Area 

Sources. The latest emissions factors are available 

at http://www.epa.gov/ttnchie1/ap42/. 

15Please see the TSD for example calculations of 

the 24-hour emissions rates for the 6A and 9A 

Boilers. See also the April 1, 2013 letter from James 

W. Cutbirth, Environmental Services 

Superintendent at Georgia-Pacific Crossett Paper 

Operations, to Mary Pettyjohn, ADEQ. The 

attachments to the April 1, 2013 letter include 

spreadsheets with the calculated 24-hour emission 

rates for each day during the 2001–2003 baseline 

period for the 6A and 9A Boilers. The letter and all 

attachments are found in the docket for this 

proposed rulemaking. 

16The maximum 24-hour emission rate for PM10

for the 9A Boiler is based on the results of stack 

testing Georgia-Pacific conducted when the boiler 

was firing bark and gas, since the stack test results 

yielded a higher emission rate than what GeorgiaPacific calculated using AP–42 emission factors. 

17See ADEQ Operating Air Permit No. 0597– 

AOP–R14, issued on May 23, 2012. A copy of the 

air permit can be found in the docket for this 

proposed rulemaking. 

demonstrate no cause or contribution to 

visibility impairment by the 6A and 9A 

Boilers, and that the boilers are 

therefore not subject to BART. 

TABLE 1—MAXIMUM MODELED VISIBILITY IMPACTS FROM 6A AND 9A BOILERS

[Georgia-Pacific’s 2011 Dispersion Modeling Analysis] 

Class I area 

Maximum Visibility Impact 

(dv) 

2001 

meteorology 

2002 

meteorology 

2003 

meteorology 

Caney Creek ................................................................................................................................ 0.16 0.359 0.296 

Upper Buffalo ............................................................................................................................... 0.099 0.074 0.099 

Hercules-Glades .......................................................................................................................... 0.08 0.288 0.125 

Mingo ........................................................................................................................................... 0.123 0.093 0.168 

Sipsey .......................................................................................................................................... 0.171 0.184 0.119 

Following discussions with us and 

ADEQ, Georgia-Pacific provided 

additional information and 

documentation to support its contention 

that the 6A and 9A Boilers are not 

subject to BART. Georgia-Pacific 

calculated maximum 24-hour emission 

rates from the 2001–2003 baseline 

period using fuel usage data, and then 

showed that these estimated maximum 

24-hour emission rates are below the 

revised emission rates it used in the 

2011 BART screening modeling. In a 

letter dated April 1, 2013, GeorgiaPacific provided spreadsheets with fuel 

usage data for the 6A and 9A Boilers for 

each day during the 2001–2003 baseline 

period.13 The 6A Boiler burned only 

natural gas during the 2001–2003 

baseline period, while the 9A Boiler 

burned both natural gas and bark. 

Georgia-Pacific used emission factors 

from AP–42, Compilation of Air 

Pollutant Emission Factors,14 to 

calculate 24-hour emission rates for 

SO2, NOX, and PM10 (lb/hr) for the 6A 

and 9A Boilers for each day during the 

baseline years. The gas and bark usage 

value for each day was multiplied by 

the corresponding AP–42 emission 

factor to calculate the 24-hour emission 

rate for each day during the baseline 

period.15 Georgia-Pacific then 

determined the maximum 24-hour 

emission rates for the 6A and 9A Boilers 

during the baseline period (see table 

below).16

TABLE 2—GEORGIA-PACIFIC CROSSETT MILL 6A AND 9A BOILER MAXIMUM 24-HOUR EMISSION RATES FROM THE 2001– 

2003 BASELINE PERIOD

Unit 

Maximum 24-Hour Emission Rates (lb/hr) 

SO2 NOX PM10

6A Boiler ...................................................................................................................................... 0.2 90.7 2.5 

9A Boiler ...................................................................................................................................... 17.9 174.1 72.0 

Georgia-Pacific then compared the 

calculated maximum 24-hour emission 

rates from the baseline period with the 

emission rates it modeled in the 2011 

BART screening modeling and with the 

current Title V permit limits (see table 

below).17 A comparison of these values 

shows that the calculated maximum 24- 

hour emission rates for each pollutant 

are below the emission rates GeorgiaPacific modeled in the 2011 BART 

screening modeling, and also below the 

currently enforceable Title V permit 

limits. 

TABLE 3—GEORGIA-PACIFIC CROSSETT MILL—COMPARISON OF MAXIMUM 24-HOUR EMISSION RATES WITH MODELED

EMISSION RATES AND TITLE V PERMIT LIMITS

SO2 NOX PM10

6A Boiler 

Calculated Maximum 24-hr Emission Rate (lb/hr) ...................................................................... 0.2 90.7 2.5 

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18 77 FR 14604, March 12, 2012. 

19See July 6, 2005 BART Guidelines, 40 CFR 51, 

Regional Haze Regulations and Guidelines for Best 

Available Retrofit Technology Determinations. 

TABLE 3—GEORGIA-PACIFIC CROSSETT MILL—COMPARISON OF MAXIMUM 24-HOUR EMISSION RATES WITH MODELED

EMISSION RATES AND TITLE V PERMIT LIMITS—Continued 

SO2 NOX PM10

Modeled Emission Rate (lb/hr) .................................................................................................... 0.3 120.0 3.3 

Title V permit Limit (lb/hr) ............................................................................................................ 0.3 120.0 3.3 

9A Boiler 

Calculated Maximum 24-hr Emission Rate (lb/hr) ...................................................................... 17.9 174.1 72.0 

Modeled Emission Rate (lb/hr) .................................................................................................... 200.0 218.0 75.8 

Title V permit Limit (lb/hr) ............................................................................................................ 199.8 196.0 77.4 

Because the 2011 BART screening 

modeling showed visibility impacts 

below 0.5 dv from the 6A and 9A 

Boilers and the recently estimated 

maximum 24-hour emission rates from 

the 2001–2003 baseline period are 

below the modeled emission rates, we 

propose that it is reasonable to conclude 

that the boilers had visibility impacts 

below 0.5 dv during the baseline period. 

Accordingly, we believe that 

Georgia-Pacific’s newly provided 

analysis and documentation, as 

described above and in our TSD in more 

detail, is appropriate to demonstrate 

that the 6A and 9A Boilers are not 

subject to BART. In comparison to the 

information available to us when we 

issued our March 12, 2012 final action 

on the 2008 Arkansas RH SIP, we 

believe this newly provided analysis 

allows for a more accurate assessment of 

whether or not the 6A and 9A Boilers 

are subject to BART. Based on this 

newly provided information, we are 

proposing to find that while the 6A 

Boiler is a BART-eligible source, it is 

not subject to BART. The 9A Boiler is 

also BART-eligible (as the State 

determined in the 2008 Arkansas RH 

SIP), but we are also proposing to find 

that the 9A Boiler is not subject to 

BART. Therefore, it is not necessary to 

perform a BART five factor analysis or 

to make BART determinations for the 

Georgia-Pacific Crossett Mill 6A and 9A 

Boilers. 

2. AECC Carl E. Bailey Generating 

Station Unit 1 

In our March 12, 2012 final action on 

the 2008 Arkansas RH SIP, we noted 

that the original meteorological 

databases generated by the Central 

Regional Air Planning Association 

(CENRAP) and used by Arkansas to 

conduct its modeling analyses did not 

include surface and upper air 

meteorological observations as EPA 

guidance recommends. Thus, in its 

evaluation to determine if a source 

exceeds the 0.5 dv contribution 

threshold at potentially affected Class I 

areas, Arkansas used the maximum 

value (i.e., 1st high value) of modeled 

visibility impacts instead of the 98th 

percentile value (i.e., 8th high value). 

The use of the maximum modeled 

values in the 2008 Arkansas RH SIP was 

agreed to by us, representatives of the 

Federal Land Managers, and CENRAP 

stakeholders. In our March 12, 2012 

final action, we also approved Arkansas’ 

determination that the AECC Carl E. 

Bailey Generating Station (AECC Bailey) 

Unit 1 is BART-eligible and subject to 

BART, based on the maximum value of 

modeled visibility impacts. 

Following our March 12, 2012 final 

action on the 2008 Arkansas RH SIP, 

AECC hired a consultant to conduct 

revised modeling of AECC Bailey Unit 

1. Unlike the modeling submitted in the 

2008 Arkansas RH SIP, the revised 

modeling shows visibility impacts from 

Bailey Unit 1 below 0.5 dv, which is the 

threshold used by Arkansas to 

determine if a source is subject to 

BART. However, we already approved 

Arkansas’ determination that the AECC 

Bailey Unit 1 is subject to BART in our 

March 12, 2012 final action on the 2008 

Arkansas RH SIP. 

We do not have the discretion to 

reopen the issue of whether the source 

is subject to BART because we already 

approved the portion of the 2008 

Arkansas RH SIP in which Arkansas 

determined AECC Bailey Unit 1 is 

subject to BART and Arkansas has not 

provided us a SIP revision to replace the 

previous determination.18 We cannot reconsider our approval of that portion of 

the 2008 Arkansas RH SIP to have been 

in error because Arkansas did not 

submit the revised modeling to us with 

a request to remove the source from 

BART and the modeling approach used 

by Arkansas in that SIP is consistent 

with our regional haze regulations and 

was agreed to by us, representatives of 

the Federal Land Managers, and 

CENRAP stakeholders prior to submittal 

of the 2008 Arkansas RH SIP. Therefore, 

our proposed FIP is not reopening the 

issue of whether the source is subject to 

BART, and our final approval of 

Arkansas’ determination that the source 

is subject to BART remains in place and 

in the subsection that follows we 

evaluate AECC Bailey Unit 1 under 

BART. 

B. BART Factors 

The purpose of the BART analysis is 

to identify and evaluate the best system 

of continuous emission reduction based 

on the BART Guidelines.19 In 

determining BART, a state, or EPA if 

promulgating a FIP, must consider the 

five statutory factors in section 169A of 

the CAA: (1) The costs of compliance; 

(2) the energy and nonair 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. See also 40 CFR 

51.308(e)(1)(ii)(A). Following the BART 

Guidelines, the BART analysis is broken 

down into five steps. Steps 1 through 3 

address the availability, technical 

feasibility and effectiveness of retrofit 

control options. The consideration of 

the five statutory factors occurs during 

steps 4 and 5 of the process. 

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. 

• Factor 1: Costs of compliance. 

• Factor 2: Energy and nonair quality 

environmental impacts of compliance. 

• Factor 3: Existing pollution control 

technology in use at the source. 

• Factor 4: Remaining useful life of 

the facility. 

Step 5—Evaluate Visibility Impacts 

• Factor 5: Degree of improvement in 

visibility which may reasonably be 

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18950 Federal Register / Vol. 80, No. 67 / Wednesday, April 8, 2015 / Proposed Rules 

20See the following BART analyses: ‘‘BART Five 

Factor Analysis, Arkansas Electric Cooperative 

Corporation Bailey and McClellan Generating 

Stations,’’ dated March 2014, Version 4, prepared 

by Trinity Consultants Inc. in conjunction with 

Arkansas Electric Cooperative Corporation; and 

‘‘BART Five Factor Analysis- NOX Analysis, 

Addendum to the July 24, 2012 BART Five Factor 

Analysis, Arkansas Electric Cooperative 

Corporation Bailey and McClellan Generating 

Stations,’’ dated December 2013, Version 3. A copy 

of these two BART analyses can be found in the 

docket for our proposed rulemaking. 

21The National Park Service PM speciation 

worksheets are typically used to speciate PM10 into 

SO4, PMc, PMf, SOA, and EC. 

anticipated to result from the use of 

retrofit control technology. 

C. BART Determinations and Proposed 

Federally Enforceable Limits 

1. AECC Carl E. Bailey Generating 

Station 

The AECC Bailey Unit 1 is a wallfired boiler with a gross output of 122 

megawatts (MW) and a maximum heat 

input rate of 1,350 million British 

thermal units per hour (MMBtu/hr). The 

unit is currently permitted to burn 

natural gas and fuel oil. The fuel oil 

burned is currently subject to a sulfur 

content limit of 2.3% by weight. AECC 

hired a consultant to perform a BART 

five factor analysis for Bailey Unit 1.20

The table below summarizes the 

baseline emission rates modeled for the 

source. The SO2 and NOX baseline 

emission rates are the highest actual 24- 

hour emission rates based on 2001–2003 

continuous emission monitoring system 

(CEMS) data, while the PM baseline 

emission rates are based on stack testing 

and AP–42 emission factors. 

TABLE 4—BASELINE EMISSION RATES FOR AECC BAILEY UNIT 1 

Unit/Fuel scenario SO2

(lb/hr) 

NOX

(lb/hr) 

Total 

PM1021

(lb/hr) 

Inorganic 

condensable 

(SO4) 

(lb/hr) 

Coarse soil 

(PMc) 

(lb/hr) 

Fine soil 

(PMf) 

(lb/hr) 

Organic 

condensable PM 

(SOA) 

(lb/hr) 

Elemental 

carbon 

(EC) 

(lb/hr) 

Bailey, Unit 1—Natural Gas firing ......................................... 0.5 443.8 10.2 0.3 0.0 0.0 7.4 2.6 

Bailey, Unit 1—Fuel Oil firing .. 2,375.8 408.8 55.8 4.6 13.7 34.1 0.8 2.7 

The NOX and PM baseline emission 

rates used in AECC’s revised modeling 

for the fuel oil firing scenario were 

revised from what the State modeled in 

the 2008 Arkansas RH SIP. The revised 

NOX emission rates for the fuel oil firing 

scenario are higher than what was 

modeled in the 2008 Arkansas RH SIP, 

while the revised PM10 emission rates 

for fuel oil firing scenario are lower than 

what was modeled in the 2008 Arkansas 

RH SIP. We have some concern with 

AECC’s use of the PM10 baseline 

emission rates, which are based on stack 

testing, because there is no discussion 

provided on how the stack test results 

are representative of the maximum 24- 

hour emissions. However, because the 

visibility impacts due to PM10 emissions 

from Bailey Unit 1 are so small, we 

believe a closer inspection of the revised 

PM10 emission rates and any further 

updates to these would likely not result 

in significant changes to the modeled 

visibility impacts and would not affect 

our proposed BART decision. As shown 

in the table below, the percentage of the 

visibility impairment attributable to 

PM10 from Bailey Unit 1 at the Class I 

area with the highest baseline visibility 

impacts (Mingo) is 8.10% for the natural 

gas firing scenario and 1.26% for the 

fuel oil firing scenario. Most of the 

visibility impairment is attributable to 

NO3 (83.34%) for the natural gas firing 

scenario and to SO4 (93.95%) for the 

fuel oil firing scenario. Therefore, we 

did not take further steps to adjust the 

PM10 emission rates or conduct 

additional modeling. 

AECC’s modeling for the baseline 

emission rates uses the CALPUFF 

dispersion model to determine the 

baseline visibility impairment 

attributable to Bailey Unit 1 at the four 

Class I areas impacted by emissions 

from BART sources in Arkansas. These 

Class I areas are the Caney Creek 

Wilderness Area, Upper Buffalo 

Wilderness Area, Hercules-Glades 

Wilderness Area, and Mingo National 

Wildlife Refuge. The baseline (i.e., 

existing) visibility impairment 

attributable to each unit at each Class I 

area is summarized in the table below. 

TABLE 5—98TH PERCENTILE BASELINE VISIBILITY IMPAIRMENT ATTRIBUTABLE TO AECC BAILEY UNIT 1 (2001–2003) 

Unit/Fuel scenario Maximum 

(Ddv) 

98th percentile 

(Ddv) 

98th percentile 

% SO4

98th percentile 

% NO3

98th percentile 

% PM10

Bailey Unit 1—Natural Gas 

firing.

Caney Creek ......................

Upper Buffalo .....................

0.219 

0.170 

0.083 

0.072 

0.28 

0.29 

96.36 

95.02 

3.35 

3.43 

Hercules-Glades ................. 0.238 0.073 0.22 92.76 3.67 

Mingo .................................. 0.443 0.102 0.45 83.34 8.10 

Bailey Unit 1—Fuel Oil firing Caney Creek ......................

Upper Buffalo .....................

0.970 

0.696 

0.330 

0.348 

87.19 

90.73 

12.11 

8.42 

0.57 

0.83 

Hercules-Glades ................. 0.687 0.368 82.74 14.39 2.08 

Mingo .................................. 1.592 0.379 93.95 4.68 1.26 

a. Proposed BART Analysis and 

Determination for SO2. The source does 

not have existing SO2 pollution control 

technology. AECC identified all 

available control technologies, 

eliminated options that are not 

technically feasible, and evaluated the 

control effectiveness of the remaining 

control options. Each technically 

feasible control option was then 

evaluated in terms of a five factor BART 

analysis. 

AECC’s BART evaluation considered 

both flue gas desulfurization (FGD) and 

fuel switching as possible controls. 

AECC found that FGD applications have 

not been used historically for SO2

control on fuel oil-fired units in the U.S. 

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Federal Register / Vol. 80, No. 67 / Wednesday, April 8, 2015 / Proposed Rules 18951 

22The average cost-effectiveness was calculated 

by dividing the total annual differential cost of 

switching from the baseline fuel oil to the lower 

sulfur fuel. 

23The incremental cost-effectiveness calculation 

compares the costs and performance level of a 

control option to those of the next most stringent 

option, as shown in the following formula (with 

respect to cost per emissions reduction): 

Incremental Cost Effectiveness (dollars per 

incremental ton removed) = (Total annualized costs 

of control option)—(Total annualized costs of next 

control option)/(Control option annual emissions)— 

Next control option annual emissions). See BART 

Guidelines, 40 CFR Part 51, Appendix Y, section 

IV.D.4.e. 

electric industry and therefore 

considered it a technically infeasible 

option for control of Bailey Unit 1. 

Accordingly, AECC did not further 

consider FGD for SO2 BART. We concur 

with AECC’s decision to focus the SO2

BART evaluation on fuel switching. 

Switching to a fuel with a lower sulfur 

content is expected to reduce SO2

emissions in proportion to the reduction 

in the sulfur content of the fuel, 

assuming that the fuels have similar 

heat contents. Bailey Unit 1 burns 

primarily natural gas, but is also 

permitted to burn fuel oil. The baseline 

fuel AECC assumed in the BART 

analysis is No. 6 fuel oil with 1.81% 

sulfur content, based on the average 

sulfur content of the fuel oil from the 

most recent shipment received by the 

facility in December 2006. According to 

the facility, a portion of the fuel oil from 

this shipment still remains in storage at 

the facility for future use. AECC 

evaluated switching to the fuel types 

shown in the table below. 

TABLE 6—CONTROL EFFECTIVENESS

OF FUEL SWITCHING OPTIONS FOR

AECC BAILEY UNIT 1 

Fuel switching options 

Estimated SO2

control 

efficiency 

% 

No. 6 fuel oil, 1% sulfur ........ 45 

No. 6 fuel oil, 0.5% sulfur ..... 72 

Diesel, 0.05% sulfur ............. 97 

Natural gas ........................... 99.9 

AECC estimated the average costeffectiveness of switching Bailey Unit 1 

to No. 6 fuel oil with 1% sulfur content 

to be $1,198 per ton of SO2 removed. 

Switching from the baseline fuel to No. 

6 fuel oil with 0.5% sulfur content was 

estimated to cost $2,559 per ton of SO2

removed. The results of AECC’s cost 

analysis are summarized in the table 

below. For the natural gas switching 

scenario, AECC found that the current 

cost of natural gas is actually lower than 

the cost of the baseline fuel. Therefore, 

the average cost-effectiveness of 

switching from the baseline fuel to 

natural gas is denoted as a negative 

value (cost savings) in the table below. 

TABLE 7—AECC BAILEY UNIT 1: SUMMARY OF COSTS ASSOCIATED WITH FUEL SWITCHING

Fuel 

switching 

scenario 

Average 

sulfur 

content 

(%) 

Baseline 

emission 

rate 

( SO2 tpy) 

Controlled 

emission 

rate 

(SO2 tpy) 

Annual 

emissions 

reductions 

( SO2 tpy) 

Annual fuel 

usage 

(Mgal/yr) 

Fuel cost 

($/MMBtu) 

Total 

annual 

differential 

cost of fuel 

switching 

($/yr) 

Average cost 

effectiveness 22

($/ton) 

Incremental 

cost 

effectiveness 23

($/ton) 

Baseline ............................................... 1.81 37.03 .................. .................. 252.86 16.00 .................. ...................... ..................

No. 6 Fuel Oil—1% ............................. 1.00 .................. 20.67 16.36 252.86 16.50 19,596 1,198 ..................

No. 6 Fuel Oil—0.5% .......................... 0.50 .................. 10.23 26.80 252.86 17.75 68,587 2,559 4,693 

Diesel .................................................. 0.05 .................. 0.99 36.05 287.86 20.95 194,003 5,382 13,558 

Natural Gas ......................................... 0.04 .................. 0.01 37.02 38.77 6.19 ¥384,550 ¥10,387 ¥596,446 

AECC’s evaluation did not identify 

any energy or non-air quality 

environmental impacts associated with 

switching to 1% sulfur No. 6 fuel oil, 

0.5% sulfur No. 6 fuel oil, or diesel. The 

evaluation noted that switching to 

natural gas may have energy impacts 

during periods of natural gas 

curtailment. During periods of natural 

gas curtailment, natural gas 

infrastructure maintenance, and other 

emergencies, the AECC Bailey 

Generating Station relies on the fuel oil 

stored at the plant to maintain electrical 

reliability. AECC’s evaluation notes that 

because of this, it is important to 

maintain the ability to burn fuel oil at 

AECC Bailey, even if fuel oil is currently 

more expensive than natural gas. 

With regard to consideration of the 

remaining useful life of Unit 1, this 

factor does not impact the SO2 BART 

analysis because the emissions control 

approaches being evaluated for BART 

do not require capital cost expenditures. 

Thus, there are no control costs that 

need to be amortized over the lifetime 

of the unit. 

AECC assessed the visibility 

improvement associated with fuel 

switching by comparing the 98th 

percentile modeled visibility impact of 

the baseline scenario to the 98th 

percentile modeled visibility impact of 

each control scenario. The table below 

shows a comparison of the baseline 

visibility impacts and the visibility 

impacts of the different fuel switching 

control scenarios that were evaluated, 

including the cumulative visibility 

benefits. 

TABLE 8—AECC BAILEY UNIT 1: SUMMARY OF 98TH PERCENTILE VISIBILITY IMPACTS AND IMPROVEMENT DUE TO FUEL

SWITCHING

Class I area 

Baseline 

visibility 

impact 

(Ddv) 

No. 6 fuel 

oil—1% 

sulfur 

No. 6 fuel 

oil—0.5% 

sulfur 

Diesel 

Natural gas 

Visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Visibility 

impact 

(Ddv) 

Caney Creek ................................... 0.330 0.193 0.137 0.142 0.188 0.084 0.246 0.083 0.247 

Upper Buffalo .................................. 0.348 0.194 0.154 0.127 0.221 0.069 0.279 0.072 0.276 

Hercules-Glades .............................. 0.368 0.206 0.162 0.135 0.233 0.069 0.299 0.073 0.295 

Mingo ............................................... 0.379 0.206 0.173 0.170 0.209 0.095 0.284 0.102 0.277 

Cumulative Visibility Improvement 

(Ddv) ............................................ .................. .................. 0.626 .................. 0.851 ........................ 1.108 ........................ 1.095 

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18952 Federal Register / Vol. 80, No. 67 / Wednesday, April 8, 2015 / Proposed Rules 

24 ‘‘Controlling Nitrogen Oxides Under the Clean 

Air Act: A Menu of Options,’’ section II, dated July 

1994, State and Territorial Air Pollution Program 

Administrators (STAPPA) and Association of Local 

Air Pollution Control Officials (ALAPCO). 

The table above shows that switching 

to No. 6 fuel oil with 1% sulfur content 

at Bailey Unit 1 is projected to result in 

0.173 dv visibility improvement at 

Mingo (based on the 98th percentile 

modeled visibility impacts). The 

visibility improvement at each of the 

other three affected Class I areas is 

projected to be slightly less than that 

amount, while the cumulative visibility 

improvement at the four Class I areas is 

projected to be 0.626 dv. Switching to 

No. 6 fuel oil with 0.5% sulfur content 

is projected to result in meaningful 

visibility improvement. It is projected to 

result in 0.233 dv visibility 

improvement at Hercules-Glades. The 

visibility improvement at each of the 

other three affected Class I areas is 

projected to be slightly less than that 

amount, while the cumulative visibility 

improvement at the four Class I areas is 

projected to be 0.851 dv. Switching to 

diesel or natural gas is also projected to 

result in meaningful visibility 

improvement. The visibility 

improvement at Hercules-Glades is 

projected to be 0.299 dv for switching to 

diesel and 0.295 dv for switching to 

natural gas, and slightly less than that 

amount at each of the other three 

affected Class I areas. The cumulative 

visibility improvement at the four Class 

I areas is projected to be 1.108 dv for 

switching to diesel and 1.095 dv for 

switching to natural gas. 

Our Proposed SO2 BART 

Determination: Taking into 

consideration the five factors, we are 

proposing to determine that BART for 

the AECC Bailey Unit 1 is switching to 

fuels with 0.5% or lower sulfur content 

by weight. The cost effectiveness of 

switching to No. 6 fuel oil with 0.5% 

sulfur content is within the range of 

what we consider to be cost-effective for 

BART and it is projected to result in 

considerable visibility improvement 

compared to the baseline at the affected 

Class I areas. Switching to No. 6 fuel oil 

with 0.5% sulfur content has an 

estimated average cost-effectiveness of 

$2,559 per ton of SO2 removed and is 

projected to result in visibility 

improvement ranging from 0.188 to 

0.233 dv at each modeled Class I area, 

and a cumulative visibility 

improvement of 0.851 dv at the four 

modeled Class I areas. Switching to 

natural gas would currently cost less 

than the baseline fuel and is projected 

to result in even greater visibility 

improvement than switching to No. 6 

fuel oil with 0.5% sulfur content. 

However, the BART Guidelines provide 

that it is not our intent to direct subjectto-BART sources to switch fuel forms, 

such as from coal or fuel oil to gas (40 

CFR part 51, Appendix Y, section 

IV.D.1). Because natural gas has a sulfur 

content by weight that is well below 

0.5%, the facility may elect to use this 

type of fuel to comply with BART, but 

we are not proposing to require a switch 

to natural gas for Unit 1. Switching to 

diesel is projected to result in an almost 

identical level of visibility improvement 

at each Class I area as switching to 

natural gas. The incremental visibility 

improvement of switching to diesel 

compared to switching to No. 6 fuel oil 

with a sulfur content of 0.5% is 

projected to range from 0.058 dv to 

0.075 dv at each affected Class I area but 

the average cost-effectiveness is 

estimated to be $5,382 per ton of SO2

removed and the incremental costeffectiveness compared to switching to 

No. 6 fuel oil with a sulfur content of 

0.5% is estimated to be $13,558 per ton 

of SO2 removed, which we do not 

consider to be very cost-effective in 

view of the incremental visibility 

improvement. Because diesel also has a 

sulfur content by weight that is well 

below 0.5%, the facility may elect to use 

this type of fuel to comply with BART, 

but we are not proposing to require a 

switch to diesel for Unit 1. We are 

proposing to determine that SO2 BART 

for Bailey Unit 1 is switching to fuels 

with 0.5% or lower sulfur content by 

weight. We propose to require that the 

facility purchase no fuel after the 

effective date of the rule that does not 

meet the sulfur content requirement and 

that 5 years from the effective date of 

the rule no fuel be burned that does not 

meet the requirement. We propose that 

any higher sulfur fuel oil that remains 

from the facility’s 2006 fuel oil 

shipment cannot be burned past this 

point. As discussed above, the unit’s 

baseline fuel is No. 6 fuel oil with 

1.81% sulfur content, based on the 

average sulfur content of the fuel oil 

from the most recent fuel oil shipment 

received by the facility in 2006. Based 

on our discussions with the facility, it 

is our understanding that the unit burns 

fuel oil primarily during periods of 

natural gas curtailment and during 

periodic testing and that the facility still 

has stockpiles of fuel oil from the most 

recent shipment. Because the unit burns 

primarily natural gas and does not 

ordinarily burn fuel oil on a frequent 

basis, we believe it is appropriate to 

allow the facility 5 years to burn its 

existing supply of No. 6 fuel oil, as the 

normal course of business dictates and 

in accordance with any operating 

restrictions enforced by ADEQ. We 

believe that a shorter compliance date 

may result in the facility burning its 

existing supply of higher sulfur No. 6 

fuel oil relatively quickly, resulting in a 

high amount of SO2 emissions being 

emitted by the unit over a short period 

of time. This is not the intent of our 

regional haze regulations. We are also 

proposing regulatory text that includes 

monitoring, reporting, and 

recordkeeping requirements associated 

with this proposed determination. 

b. Proposed BART Analysis and 

Determination for NOX. AECC’s BART 

evaluation examined BART controls for 

NOX for AECC Bailey Unit 1. Bailey 

Unit 1 does not currently have pollution 

control equipment for NOX. AECC’s 

evaluation identified all available 

control technologies, eliminated options 

that are not technically feasible, and 

evaluated the control effectiveness of 

the remaining control options. Each 

technically feasible control option was 

then evaluated in terms of a five factor 

BART analysis. 

For NOX BART, AECC’s evaluation 

considered both combustion and postcombustion controls. The combustion 

controls evaluated by AECC consisted of 

flue gas recirculation (FGR), overfire air 

(OFA), and low NOX burners (LNB). The 

post-combustion controls evaluated 

consisted of selective catalytic reduction 

(SCR) and selective non-catalytic 

reduction (SNCR). AECC found that 

some boilers may be restricted from 

installing OFA retrofits due to physical 

size and space restraints. For purposes 

of the NOX BART evaluation, AECC 

assumed OFA to be a technically 

feasible option for Bailey Unit 1, but 

noted that if OFA was determined to be 

BART based on the evaluation of the 

five BART factors, then further analyses 

would have to be performed to 

determine if: (1) The dimensions of 

AECC Bailey’s main boilers have 

sufficient upper furnace volume for 

OFA mixing and complete combustion 

and (2) the furnace meets the physical 

space requirements for OFA ports and 

air supply ducts. The remaining NOX

control options were found to be 

technically feasible. 

AECC evaluated three control 

scenarios: A combination of combustion 

controls (FGR, OFA, and LNB); the 

combination of combustion controls and 

SNCR; and SCR. Based on literature 

estimates, AECC found that the 

estimated NOX control range for oil and 

gas wall-fired boilers, such as Bailey 

Unit 1, is approximately 0.2–0.4 lb/

MMBtu using FGR and 0.2–0.3 lb/

MMBtu using OFA.24 When LNB is 

combined with OFA and FGR, AECC 

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25EPA’s ‘‘Air Pollution Control Cost Manual,’’ 

Sixth edition, January 2002, is located at 

www.epa.gov/ttncatc1/products.html#cccinfo. 

26See the preceding paragraphs for a discussion 

of the expected controlled emission rates for natural 

gas vs. fuel oil firing. 

27 Id. 

estimated that a NOX controlled 

emission rate of 0.15—0.20 lb/MMBtu 

can be achieved at Bailey Unit 1. The 

NOX controlled emission rate of 

combustion controls combined with 

SNCR is estimated to be 0.12 lb/MMBtu. 

The NOX control efficiency of SCR is 

estimated to be 80–90% for gas fired 

boilers and 70–80% for oil fired boilers, 

which corresponds to a controlled 

emission rate of 0.04–0.08 lb/MMBtu for 

Bailey Unit 1. 

AECC’s cost analysis for NOX controls 

was based on ‘‘budgetary’’ cost 

estimates it obtained by AECC from the 

pollution control equipment vendor, 

Babcock Power Systems. AECC 

estimated the capital and operating 

costs of controls based on the vendor’s 

estimates, engineering estimates, and 

published calculation methods using 

EPA’s Air Pollution Control Cost 

Manual (EPA Control Cost Manual).25

We are not aware of any enforceable 

shutdown date for the AECC Bailey 

Generating Station, nor did AECC’s 

evaluation indicate any future planned 

shutdown. This means that the 

anticipated useful life of the boiler is 

expected to be at least as long as the 

capital cost recovery period of controls. 

Therefore, a 30-year amortization period 

was assumed in the NOX BART analysis 

as the remaining useful life of Unit 1. 

The table below summarizes the 

estimated cost for installation and 

operation of NOX controls for Bailey 

Unit 1. 

TABLE 9—SUMMARY OF NOX CONTROL COSTS FOR AECC BAILEY UNIT 1 

Control scenario 

Baseline emission rate 

(NOX tpy) 

Natural gas 

controlled 

emission level 

(lb/MMBtu) 26

Fuel oil controlled emission level 

(lb/MMBtu) 27

Controlled 

emission rate 

(NOX tpy) 

Annual emissions reductions 

(NOX tpy) 

Total annual 

cost 

($/yr) 

Average costeffectiveness 

($/ton) 

Incremental 

cost-effectiveness($/ton) 

Combustion Controls ......... 49.81 0.15 0.15 30.83 18.98 700,477 36,905 ........................

Combustion Controls + 

SNCR ............................. 49.81 0.12 0.12 24.79 25.02 1,223,157 48,884 86,536 

SCR 28 ............................... 49.81 0.04 0.08 9.65 40.16 1,555,718 38,738 21,966 

AECCestimated the average costeffectiveness of installing and operating 

combustion controls to be $36,905 per 

ton of NOX removed for Bailey Unit 1. 

The combination of combustion controls 

and SNCR was estimated to cost $48,884 

per ton of NOX removed, while SCR was 

estimated to cost $38,738 per ton of 

NOX removed. In its evaluation, AECC 

also explained that it expects the costeffectiveness of NOX controls to be 

lower (i.e., greater dollars per ton 

removed) in future years due to 

projected reduced operation of the unit. 

AECC did not identify any energy or 

non-air quality environmental impacts 

associated with the use of LNB, OFA, or 

FGR. As for SCR and SNCR, we are not 

aware of any unusual circumstances at 

the facility that could create non-air 

quality environmental impacts 

associated with the operation of these 

controls greater than experienced 

elsewhere and that may therefore 

provide a basis for their elimination as 

BART (40 CFR part 51, Appendix Y, 

section IV.D.4.i.2.). Therefore, we do not 

believe there are any energy or non-air 

quality environmental impacts 

associated with NOX controls at AECC 

Bailey Unit 1 that would affect our 

proposed BART determination. 

AECC assessed the visibility 

improvement associated with NOX

controls by modeling the NOX emission 

rates associated with each control 

option using CALPUFF, and then 

comparing the visibility impairment 

associated with the baseline emission 

rates to the visibility impairment 

associated with the controlled emission 

rates as measured by the 98th percentile 

modeled visibility impact. The tables 

below show a comparison of the 

baseline (i.e., existing) visibility impacts 

and the visibility impacts associated 

with NOX controls. 

TABLE 10—AECC BAILEY UNIT 1: SUMMARY OF THE 98TH PERCENTILE VISIBILITY IMPACTS AND IMPROVEMENT DUE TO

NOX CONTROLS—NATURAL GAS FIRING

Class I area 

Baseline 

visibility 

impact 

(Ddv) 

Combustion controls Combustion controls + SNCR SCR 

Visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Caney Creek .............. 0.083 0.039 0.044 0.032 0.051 0.014 0 .069 

Upper Buffalo ............. 0.072 0.034 0.038 0.028 0.044 0.013 0 .059 

Hercules-Glades ........ 0.073 0.035 0.038 0.029 0.044 0.013 0 .06 

Mingo ......................... 0.102 0.051 0.051 0.043 0.059 0.021 0 .081 

Cumulative Visibility 

Improvement (Ddv) ........................ ........................ 0.171 ........................ 0.198 ........................ 0 .269 

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29See ADEQ Operating Air Permit No. 0154– 

AOP–R4, Section IV, Specific Conditions No. 1 and 

7. 

30See ‘‘AP–42, Compilation of Air Pollutant 

Emission Factors,’’ section 1.3.3.1, and Table 1.3– 

1, available at http://www.epa.gov/ttnchie1/ap42/. 

TABLE 11—AECC BAILEY UNIT 1: SUMMARY OF THE 98TH PERCENTILE VISIBILITY IMPACTS AND IMPROVEMENT DUE TO

NOX CONTROLS—FUEL OIL FIRING

Class I area 

Baseline 

visibility 

impact 

(Ddv) 

Combustion controls Combustion controls + SNCR SCR 

Visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Caney Creek ................ 0.330 0.325 0.005 0.325 0.005 0.323 0.007 

Upper Buffalo ............... 0.347 0.332 0.015 0.329 0.018 0.325 0.022 

Hercules-Glades .......... 0.367 0.339 0.028 0.333 0.034 0.325 0.042 

Mingo ........................... 0.378 0.369 0.009 0.367 0.011 0.364 0.014 

Cumulative Visibility Improvement (Ddv) ....... ........................ ........................ 0.057 ........................ 0.068 ........................ 0.085 

The tables above show that the 

installation and operation of NOX

controls is projected to result in a very 

modest visibility improvement from the 

baseline. Combustion controls at Bailey 

Unit 1 are projected to result in 

visibility improvement of up to 0.051 dv 

at any single Class I area for the natural 

gas firing scenario and 0.028 dv for the 

fuel oil firing scenario (based on the 

98th percentile modeled visibility 

impacts). A combination of combustion 

controls and SNCR is projected to result 

in only slight incremental visibility 

improvement over combustion controls 

alone. For example, a combination of 

combustion controls and SNCR at Bailey 

Unit 1 is projected to result in visibility 

improvement of up to 0.059 dv at any 

single Class I area for natural gas firing 

and 0.034 dv for fuel oil firing, which 

is an incremental visibility 

improvement of 0.008 dv for natural gas 

firing and 0.006 dv for fuel oil firing 

compared to combustion controls alone. 

Similarly, the installation and operation 

of SCR is projected to result in only 

slight incremental visibility 

improvement compared to a 

combination of combustion controls and 

SNCR. 

Our Proposed NOX BART 

Determination: Taking into 

consideration the five factors, we are 

proposing to determine that NOX BART 

for the AECC Bailey Unit 1 is no 

additional controls, and are proposing 

that the facility’s existing NOX emission 

limit satisfies BART for NOX. We are 

proposing the existing emission limit of 

887 lb/hr for NOX BART for Bailey 

Unit 1.29 As discussed above, the 

operation of combustion controls at 

Bailey Unit 1 is projected to result in a 

maximum visibility improvement of 

0.051 dv (Mingo), and a smaller amount 

of visibility improvement at each of the 

other affected Class I areas. The 

installation and operation of 

combustion controls at Bailey Unit 1 has 

an average cost-effectiveness of $36,905 

per ton of NOX removed, which is not 

within the range of what we consider 

cost-effective. We believe the relatively 

small visibility benefit projected from 

the operation of combustion controls 

both when combusting fuel oil and 

natural gas does not justify the 

estimated cost of those controls. The 

operation of a combination of 

combustion controls and SNCR is 

estimated to cost $48,884 per ton of 

NOX removed, which is also not within 

the range of what we consider costeffective. A combination of combustion 

controls and SNCR is projected to result 

in only slight incremental visibility 

benefit compared to combustion 

controls alone. The operation of SCR is 

estimated to cost $38,738 per ton of 

NOX removed, which is not costeffective, and is projected to result in 

only slight incremental visibility benefit 

compared to a combination of 

combustion controls and SNCR. We are 

proposing to find that NOX BART for 

Bailey Unit 1 is no additional controls 

and are proposing that the existing NOX

emission limit of 887 lb/hr is BART for 

NOX and that compliance be 

demonstrated using the unit’s existing 

CEMS. We are proposing that this 

emission limitation be complied with 

for BART purposes from the date of 

effectiveness of the finalized action. We 

are also proposing regulatory text that 

includes monitoring, reporting, and 

recordkeeping requirements associated 

with these emission limits. 

c. Proposed BART Analysis and 

Determination for PM. PM emissions are 

inherently low when burning natural 

gas. Bailey Unit 1 does not currently 

have pollution control equipment for 

PM. AECC’s BART evaluation 

considered the following control 

technologies for PM BART: Dry 

electrostatic precipitator (ESP), wet ESP, 

fabric filter, wet scrubber, cyclone (i.e., 

mechanical collector), and fuel 

switching. Residual fuel, such as the 

baseline No. 6 fuel oil burned at Bailey 

Unit 1, has inherent ash that contributes 

to emissions of filterable PM. 

Reductions in filterable PM emissions 

are directly related to the sulfur content 

of the fuel.30 Therefore, switching to No. 

6 fuel oil with a lower sulfur content is 

expected to result in lower filterable PM 

emissions. AECC’s evaluation 

considered switching to No. 6 fuel oil 

with 1% sulfur content by weight, No. 

6 fuel oil with 0.5% sulfur content by 

weight, diesel, and natural gas. These 

are the same lower sulfur fuel types 

evaluated in the SO2 BART analysis for 

the unit. 

AECC’s evaluation noted that the 

particulate matter from oil-fired boilers 

tends to be sticky and small, affecting 

the collection efficiency of dry ESPs and 

fabric filters. Dry ESPs operate by 

placing a charge on the particles 

through a series of electrodes, and then 

capturing the charged particles on 

collection plates, while fabric filters 

work by filtering the PM in the flue gas 

through filter bags. The collected 

particles are periodically removed from 

the filter bag through a pulse jet or 

reverse flow mechanism. Because of the 

sticky nature of particles from oil-fired 

boilers, dry ESPs and fabric filters are 

deemed technically infeasible for use at 

Bailey Unit 1. Wet ESPs, cyclones, wet 

scrubbers, and fuel switching were 

identified as technically feasible options 

for Bailey Unit 1. AECC noted that 

although cyclones and wet scrubbers are 

considered technically feasible for use 

at these boiler types, they are not very 

efficient at controlling particles in the 

smaller size fraction, particularly 

particles smaller than a few microns. 

However, the majority of the PM 

emissions from Bailey Unit 1 are greater 

than a few microns in size. 

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31The final version of AECC’s BART analysis for 

SO2 and PM, upon which our analysis is largely 

based, is titled ‘‘BART Five Factor Analysis 

Arkansas Electric Cooperative Corporation Bailey 

and McClellan Generating Stations, March 2014, 

Version 4.’’ A copy of AECC’s analysis can be found 

in the docket for our proposed rulemaking. 

AECC estimated that switching to a 

lower sulfur fuel has a PM control 

efficiency ranging from approximately 

44%–99%, depending on the fuel type. 

The other technically feasible control 

technologies are estimated to have the 

following PM control efficiency: Wet 

ESP—up to 90%, cyclone—85%, and 

wet scrubber—55%. 

AECC evaluated the capital costs, 

operating costs, and average costeffectiveness of wet ESPs, cyclones, and 

wet scrubbers. It also evaluated the 

average cost-effectiveness of switching 

to No. 6 fuel oil with 1% sulfur content, 

No. 6 fuel oil with 0.5% sulfur content, 

diesel, and natural gas. AECC developed 

the capital and operating costs of a wet 

ESP and wet scrubber using the Electric 

Power Research Institute’s (EPRI) 

Integrated Emissions Control Cost 

Estimating Workbook (IECCOST) 

Software. The capital costs of controls 

(except for fuel switching) were 

annualized over a 15-year period and 

then added to the annual operating costs 

to obtain the total annualized costs. The 

table below summarizes the average 

cost-effectiveness of PM controls. The 

average cost-effectiveness was 

determined by dividing the annualized 

cost of controls by the annual PM 

emissions reductions. The annual 

emissions reductions were determined 

by subtracting the estimated controlled 

annual emission rates from the baseline 

annual emission rates. AECC estimated 

the baseline and controlled annual 

emission rates by conducting a mass 

balance on the sulfur content of the 

various fuels evaluated. 

We disagree with two aspects of 

AECC’s cost evaluation for PM controls. 

First, the total annual cost numbers 

associated with fuel switching should 

be the same as those used in the SO2

BART cost analysis for Bailey Unit 1 

(see Table 7). In earlier draft versions of 

AECC’s BART analysis, which were 

provided to us for review, the cost 

numbers for fuel switching used in the 

PM and SO2 BART analyses were 

identical. In response to comments 

provided by us, the total annual cost 

and average cost-effectiveness numbers 

for fuel switching were revised in the 

final version of AECC’s SO2 BART 

analysis. However, it appears that AECC 

overlooked updating these cost numbers 

in the final PM BART analysis.31 In the 

table below, we have revised the total 

annual cost of fuel switching for the PM 

BART analysis to be consistent with the 

cost estimates from AECC’s SO2 BART 

analysis, and we have also updated the 

PM average cost-effectiveness values. 

The second aspect of AECC’s cost 

evaluation for PM controls that we 

disagree with is the use of a 15-year 

capital cost recovery period for 

calculating the average costeffectiveness of a wet ESP, wet scrubber, 

and cyclone. As previously discussed, 

we are not aware of any enforceable 

shutdown date for the AECC Bailey 

Generating Station, nor did AECC’s 

evaluation indicate any future planned 

shutdown. Therefore, we believe that 

assuming a 30-year equipment life 

rather than a 15-year equipment life 

would be more appropriate for these 

control technologies. Extending the 

amortization period from 15 to 30 years 

has the effect of decreasing the total 

annual cost of each control option, 

thereby improving the average costeffectiveness value of controls (i.e., less 

dollars per ton removed). However, after 

considering all five BART factors, we do 

not believe AECC’s assumption of a 15- 

year amortization period has an impact 

on our proposed BART decision and 

therefore we did not revise the 

amortization period or the average costeffectiveness calculations for the PM 

control options. This is discussed in 

more detail below. The table below 

summarizes the estimated cost for fuel 

switching and the installation and 

operation of PM control equipment for 

Bailey Unit 1. 

TABLE 12—SUMMARY OF COST OF PM CONTROLS FOR AECC BAILEY UNIT 1—BASELINE IS NO. 6 FUEL OIL WITH

1.81% SULFUR CONTENT BY WEIGHT

Control scenario 

Baseline 

emission rate 

(PM tpy) 

Control 

efficiency 

(%) 

Controlled 

emission rate 

(PM tpy) 

Annual 

emissions 

eductions 

(PM tpy) 

Capital cost 

($) 

Total 

annual cost 

($/yr) 

Average 

costeffectiveness 

($/ton) 

Incremental 

costeffectiveness 

($/ton) 

Wet Scrubber ................................ 25.63 55.0 11.53 14.09 140,957,713 50,150,862 3,558,286 ........................

No. 6 Fuel oil—1% S .................... 25.63 65.7 8.80 16.83 ...................... 19,596 1,164 ¥18,296,082 

Cyclone ......................................... 25.63 85.0 3.84 21.78 989,479 1,188,630 54,570 236,168 

No. 6 Fuel oil—0.5% S ................. 25.63 89.3 2.75 22.88 ...................... 68,587 2,997 ¥1,020,948 

Wet ESP ........................................ 25.63 90.0 2.56 23.06 105,141,431 22,638,340 981,583 125,387,517 

Natural Gas ................................... 25.63 99.0 0.26 25.37 ...................... ¥384,550 ¥15,157 ¥9,966,619 

Diesel ............................................ 25.63 99.5 0.13 25.50 ...................... 194,003 7,608 4,450,408 

The table above shows that the 

average cost-effectiveness values of all 

add-on PM control technology options 

evaluated for AECC Bailey Unit 1 

ranged from approximately $55,000 per 

ton of PM removed to more than $3.5 

million per ton of PM removed. The 

incremental cost-effectiveness of add-on 

PM control technology options ranged 

from $236,168 to $125,387,517 per ton 

of PM removed. Switching to No. 6 fuel 

oil with either a 1% or 0.5% sulfur 

content was found to be within the 

range of what we generally consider 

cost-effective for BART. Switching to 

No. 6 fuel oil with 1% sulfur content is 

estimated to cost $1,164 per ton of PM 

removed, while switching to No. 6 fuel 

oil with 0.5% sulfur content is 

estimated to cost $2,997 per ton of PM 

removed. As discussed in the SO2 BART 

analysis, the current cost of natural gas 

is actually lower than the cost of the 

baseline fuel. Therefore, the average 

cost-effectiveness of switching from the 

baseline fuel to natural gas is denoted as 

a negative value in the table above. As 

discussed above, AECC also explained 

that it expects the average costeffectiveness of PM control equipment 

to be lower (i.e., greater dollars per ton 

removed) in future years due to 

projected reduced operation of the unit 

due to a change in the management of 

the load control area in which the 

facility is located. 

AECC did not identify any energy or 

non-air quality environmental impacts 

associated with fuel switching, but did 

identify impacts associated with the use 

of wet ESPs and wet scrubbers due to 

their electricity usage. Energy use in and 

of itself does not disqualify a technology 

(40 CFR part 51, Appendix Y, section 

IV.D.4.h.1.). In addition, the cost of the 

electricity needed to operate this 

equipment has already been factored 

into the cost of controls. AECC also 

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noted that both wet ESPs and wet 

scrubbers generate wastewater streams 

that must either be treated on-site or 

sent to a waste water treatment plant, 

and the wastewater treatment process 

will generate a filter cake that would 

likely require landfilling. The BART 

Guidelines provide that the fact that a 

control device creates liquid and solid 

waste that must be disposed of does not 

necessarily argue against selection of 

that technology as BART, particularly if 

the control device has been applied to 

similar facilities elsewhere and the solid 

or liquid waste is similar to those other 

applications. (40 CFR part 51, Appendix 

Y, section IV.D.4.i.2.). We are not aware 

of any unusual circumstances at the 

AECC Bailey Generating Station that 

could potentially create greater 

problems than experienced elsewhere 

related to the treatment of wastewater 

and any necessary landfilling, nor did 

AECC’s evaluation discuss or mention 

any such unusual circumstances. 

Therefore, the need to treat wastewater 

or landfill any filter cake or other waste 

in and of itself does not provide a basis 

for disqualification or elimination of a 

wet ESP or wet scrubber. 

As previously discussed, we are not 

aware of any enforceable shutdown date 

for the AECC Bailey Generating Station, 

nor did AECC’s evaluation indicate any 

future planned shutdown. Therefore, we 

believe it is appropriate to assume a 30- 

year amortization period in the PM 

BART analysis as the remaining useful 

life of the unit. Assuming a 30-year 

amortization period, these controls 

would have a lower estimated total 

annual cost and would therefore have 

an improved cost-effectiveness (i.e., less 

dollars per ton removed) than estimated 

in AECC’s evaluation. However, we did 

not adjust the amortization period 

because we do not believe this has an 

impact on our proposed BART decision. 

As discussed in the subsection below, 

the visibility benefit expected from the 

installation and operation of PM control 

equipment is too small to justify the cost 

of these controls. Therefore, we did not 

revise the amortization period and the 

average cost-effectiveness calculations 

for the PM control equipment options. 

As switching to lower sulfur fuels has 

impacts on both SO2 and PM emissions, 

AECC’s assessment of the visibility 

improvement associated with fuel 

switching is addressed in the SO2 BART 

analysis for Bailey Unit 1. Table 8 

summarizes the visibility improvement 

associated with controlled emission 

rates for SO2 and PM as a result of fuel 

switching. AECC assessed the visibility 

improvement associated with wet ESPs, 

wet scrubbers, and cyclones by 

modeling the PM emission rates 

associated with each control option 

using CALPUFF, and then comparing 

the visibility impairment associated 

with the baseline emission rates to the 

visibility impairment associated with 

the controlled emission rates as 

measured by the 98th percentile 

modeled visibility impact. The 

controlled PM10 emission rates 

associated with wet ESPs, wet 

scrubbers, and cyclones were calculated 

by reducing the uncontrolled annual 

PM10 emission rates by the pollutant 

removal efficiency of each control 

technology. The SO2 and NOX emission 

rates modeled in the controlled 

scenarios are the same as those from the 

baseline scenario, as it is assumed that 

SO2 and NOX emissions would remain 

unchanged. The table below shows a 

comparison of the baseline (i.e., 

existing) visibility impacts and the 

visibility impacts associated with PM 

controls. 

TABLE 13—AECC BAILEY UNIT 1: SUMMARY OF THE 98TH PERCENTILE VISIBILITY IMPACTS AND IMPROVEMENT FROM PM 

CONTROLS

Class I area 

Baseline 

visibility 

impact 

(Ddv) 

Wet ESP Wet scrubber Cyclone 

Visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Caney Creek .......................................... 0.330 0.327 0.003 0.328 0.002 0.328 0.002 

Upper Buffalo ......................................... 0.347 0.343 0.004 0.345 0.002 0.345 0.002 

Hercules-Glades .................................... 0.367 0.356 0.011 0.360 0.007 0.361 0.006 

Mingo ..................................................... 0.378 0.371 0.007 0.374 0.004 0.374 0.004 

Cumulative Visibility Improvement (Ddv) ...................... .................. 0.025 .................. 0.015 .................. 0.014 

The table above shows that the 

operation of a wet ESP, wet scrubber, or 

cyclone at Bailey Unit 1 is projected to 

result in minimal visibility 

improvement at the four affected Class 

I areas. The modeled visibility 

improvement from switching to No. 6 

fuel oil with 1% sulfur content, No. 6 

fuel oil with 0.5% sulfur content, diesel, 

or natural gas is summarized in Table 8. 

The modeled visibility improvement 

shown in Table 8 reflects both SO2 and 

PM emissions reductions as a result of 

switching to fuels with lower sulfur 

content. However, the majority of the 

baseline visibility impact at each Class 

I area when burning the baseline fuel oil 

is due to SO2 emissions, while PM10

emissions contribute only a small 

portion of the baseline visibility impacts 

at each Class I area (see Table 5). 

Accordingly, the majority of the 

visibility improvement associated with 

switching to lower sulfur fuels can 

reasonably be expected to be the result 

of a reduction in SO2 emissions. 

Our Proposed PM BART 

Determination: Taking into 

consideration the five factors, we 

propose to determine that PM BART for 

the AECC Bailey Unit 1 does not require 

add-on controls. Consistent with our 

proposed determination for SO2 BART, 

we are proposing that PM BART is 

satisfied by Unit 1 switching to fuels 

with 0.5% or lower sulfur content by 

weight. As discussed above, we disagree 

with AECC’s use of a 15-year 

amortization period in the cost analysis 

for a wet ESP, wet scrubber, and 

cyclone. Assuming a 30-year 

amortization period, these controls 

would have lower estimated total 

annual costs and would therefore have 

an improved cost-effectiveness (i.e., less 

dollars per ton removed) compared to 

what was estimated in AECC’s 

evaluation. However, after considering 

all five BART factors, even if we revised 

AECC’s cost estimates to reflect a 30- 

year amortization period, resulting in a 

lower total annual cost and improved 

cost-effectiveness, we would still not be 

able to justify the cost of add-on 

controls in light of the minimal 

visibility benefit of these controls (see 

the table above). 

We are proposing to determine that 

PM BART for Bailey Unit 1 is switching 

to fuels with 0.5% or lower sulfur 

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Federal Register / Vol. 80, No. 67 / Wednesday, April 8, 2015 / Proposed Rules 18957 

32See the following BART analyses: ‘‘BART Five 

Factor Analysis, Arkansas Electric Cooperative 

Corporation Bailey and McClellan Generating 

Stations,’’ dated March 2014, Version 4, prepared 

by Trinity Consultants Inc. in conjunction with 

Arkansas Electric Cooperative Corporation; and 

‘‘BART Five Factor Analysis- NOX Analysis, 

Addendum to the July 24, 2012 BART Five Factor 

Analysis, Arkansas Electric Cooperative 

Corporation Bailey and McClellan Generating 

Stations,’’ dated December 2013, Version 3. A copy 

of these two BART analyses can be found in the 

docket for our proposed rulemaking. 

content by weight. We propose to 

require that the facility purchase no fuel 

after the effective date of the rule that 

does not meet the sulfur content 

requirement and that 5 years from the 

effective date of the rule no fuel be 

burned that does not meet the 

requirement. We propose that any 

higher sulfur fuel oil that remains from 

the facility’s 2006 fuel oil shipment 

cannot be burned past this point. As 

previously discussed, the unit’s baseline 

fuel is No. 6 fuel oil with 1.81% sulfur 

content, based on the average sulfur 

content of the fuel oil from the most 

recent shipment received by the facility 

in 2006. Based on our discussions with 

the facility, it is our understanding that 

the unit burns fuel oil primarily during 

periods of natural gas curtailment and 

during periodic testing and that the 

facility still has stockpiles of fuel oil 

from the most recent fuel oil shipment. 

Because the unit burns primarily natural 

gas and does not ordinarily burn fuel oil 

on a frequent basis, we believe it is 

appropriate to allow the facility 5 years 

to burn its existing supply of No. 6 fuel 

oil, as the normal course of business 

dictates and in accordance with any 

operating restrictions enforced by 

ADEQ. We believe that a shorter 

compliance date may result in the 

facility burning its existing supply of 

higher sulfur No. 6 fuel oil relatively 

quickly, resulting in a high amount of 

SO2 emissions being emitted by the unit 

over a short period of time. This is not 

the intent of our regional haze 

regulations. We are also proposing 

regulatory text that includes monitoring, 

reporting, and recordkeeping 

requirements associated with this 

proposed determination. 

2. AECC John L. McClellan Generating 

Station 

The AECC McClellan Unit 1 is subject 

to BART. As mentioned previously, we 

disapproved Arkansas’ BART 

determinations for SO2, NOX, and PM 

for McClellan Unit 1 in our March 12, 

2012 final action (77 FR 14604). The 

AECC McClellan Unit 1 is a wall-fired 

boiler with a gross output of 134 MW 

and a maximum heat input rate of 1,436 

MMBtu/hr. The unit is currently 

permitted to burn natural gas and fuel 

oil. The fuel oil burned is currently 

subject to a sulfur content limit of 2.8% 

by weight. AECC, through its 

consultant, performed a five-factor 

analysis for McClellan Unit 1 (AECC’s 

BART analysis).32

The table below summarizes the 

baseline emission rates for the source. 

The SO2 and NOX baseline emission 

rates are the highest actual 24-hour 

emission rates based on 2001–2003 

CEMS data, while the PM baseline 

emission rates are based on stack testing 

and AP–42 emission factors. 

TABLE 14—BASELINE EMISSION RATES FOR AECC MCCLELLAN UNIT 1 

Unit/fuel scenario SO2

(lb/hr) 

NOX

(lb/hr) 

Total 

PM10

(lb/hr) 

SO4

(lb/hr) 

PMc 

(lb/hr) 

PMf 

(lb/hr) 

SOA 

(lb/hr) 

EC 

(lb/hr) 

McClellan, Unit 1—Natural Gas ....................... 0.6 423.9 10.9 0.3 0.0 0.0 7.9 2.7 

McClellan, Unit 1—Fuel Oil ............................. 2,747.5 579.8 59.4 5.9 14.2 35.4 1.00 2.8 

The NOX and PM baseline emission 

rates AECC modeled for the fuel oil 

firing scenario were updated from what 

the State modeled in the 2008 Arkansas 

RH SIP. The revised NOX emission rates 

for the fuel oil firing scenario are higher 

than what was modeled in the 2008 

Arkansas RH SIP, while the revised 

PM10 emission rates for fuel oil firing 

scenario are lower than what was 

modeled in the 2008 Arkansas RH SIP. 

We have some concern with AECC’s use 

of the PM10 baseline emission rates, 

which were based on stack testing, 

because there is no discussion provided 

on how the stack test results are 

representative of the maximum 24-hour 

emissions. However, because the 

visibility impacts due to PM10 emissions 

from McClellan Unit 1 are so small, we 

believe a closer inspection of the revised 

PM10 emission rates and any further 

updates to these would likely not result 

in significant changes to the modeled 

visibility impacts and would not affect 

our proposed BART decision. As shown 

in the table below, the percentage of the 

visibility impairment attributable to 

PM10 at the Class I area with the highest 

visibility impacts (Caney Creek) is 

6.63% for the natural gas firing scenario 

and 0.53% for the fuel oil firing 

scenario. Most of the visibility 

impairment is attributable to NO3

(87.09%) for the natural gas firing 

scenario and to SO4 (89.86%) for the 

fuel oil firing scenario. Therefore, we 

did not take further steps to adjust the 

PM10 emission rates or conduct 

additional modeling. 

AECC modeled the baseline emission 

rates using the CALPUFF dispersion 

model to determine the baseline 

visibility impairment attributable to 

McClellan Unit 1 at the four Class I 

areas impacted by emissions from BART 

sources in Arkansas. These Class I areas 

are the Caney Creek Wilderness Area, 

Upper Buffalo Wilderness Area, 

Hercules-Glades Wilderness Area, and 

Mingo National Wildlife Refuge. The 

baseline (i.e., existing) visibility 

impairment attributable to McClellan 

Unit 1 at each Class I area is 

summarized in the table below. 

TABLE 15—98TH PERCENTILE BASELINE VISIBILITY IMPAIRMENT ATTRIBUTABLE TO AECC MCCLELLAN UNIT 1 

[2001–2003] 

Unit/fuel scenario Maximum 

(Ddv) 

98th 

Percentile 

(Ddv) 

98th 

Percentile 

(% SO4) 

98th 

Percentile 

(% NO3) 

98th 

Percentile 

(% PM10) 

98th 

Percentile 

(% NO2) 

McClellan Unit 1—Natural Gas: 

Caney Creek ..................................... 0.670 0.125 0.39 87.09 6.63 5.89 

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18958 Federal Register / Vol. 80, No. 67 / Wednesday, April 8, 2015 / Proposed Rules 

TABLE 15—98TH PERCENTILE BASELINE VISIBILITY IMPAIRMENT ATTRIBUTABLE TO AECC MCCLELLAN UNIT 1—Continued 

[2001–2003] 

Unit/fuel scenario Maximum 

(Ddv) 

98th 

Percentile 

(Ddv) 

98th 

Percentile 

(% SO4) 

98th 

Percentile 

(% NO3) 

98th 

Percentile 

(% PM10) 

98th 

Percentile 

(% NO2) 

Upper Buffalo .................................... 0.258 0.052 0.34 91.78 4.82 3.05 

Hercules-Glades ............................... 0.092 0.040 0.74 86.01 10.18 3.07 

Mingo ................................................ 0.132 0.058 0.33 91.96 5.13 2.58 

McClellan Unit 1—Fuel Oil: 

Caney Creek ..................................... 3.007 0.622 89.86 9.62 0.53 0.00 

Upper Buffalo .................................... 1.323 0.266 98.47 0.95 0.58 0.00 

Hercules-Glades ............................... 0.662 0.231 78.67 20.16 1.17 0.01 

Mingo ................................................ 0.547 0.228 80.90 17.89 1.20 0.01 

a. Proposed BART Analysis and 

Determination for SO2. AECC’s BART 

evaluation examined BART controls for 

SO2 for the AECC McClellan Unit 1. The 

source does not have existing SO2

pollution control technology. AECC 

identified all available control 

technologies, eliminated options that 

are not technically feasible, and 

evaluated the control effectiveness of 

the remaining control options. Each 

technically feasible control option was 

then evaluated in terms of a five factor 

BART analysis. 

The AECC evaluation considered both 

FGD and fuel switching as possible 

controls. AECC found that FGD 

applications have not been used 

historically for SO2 control on fuel oilfired units in the U.S. electric industry 

and therefore considered it a technically 

infeasible option for control of 

McClellan Unit 1. Accordingly, AECC 

did not further consider FGD for SO2

BART. We concur with AECC’s decision 

to focus the SO2 BART evaluation on 

fuel switching. Switching to a fuel with 

a lower sulfur content is expected to 

reduce SO2 emissions in proportion to 

the reduction in the sulfur content of 

the fuel, assuming the fuels have similar 

heat contents. McClellan Unit 1 burns 

primarily natural gas, but is also 

permitted to burn fuel oil. The baseline 

fuel AECC assumed in the BART 

analysis is No. 6 fuel oil with 1.38% 

sulfur content, based on the average 

sulfur content of the fuel oil from the 

most recent fuel oil shipment received 

by the facility in April 2009. A portion 

of the fuel oil from this shipment still 

remains in storage at the facility for 

future use. AECC evaluated switching to 

the fuel types shown in the table below. 

TABLE 16—CONTROL EFFECTIVENESS

OF FUEL SWITCHING OPTIONS FOR

AECC MCCLELLAN UNIT 1 

Fuel switching options 

Estimated 

SO2 control 

efficiency 

(%) 

No. 6 fuel oil, 1% sulfur ...... 28 

No. 6 fuel oil, 0.5% sulfur ... 64 

Diesel, 0.05% sulfur ........... 96 

TABLE 16—CONTROL EFFECTIVENESS

OF FUEL SWITCHING OPTIONS FOR

AECC MCCLELLAN UNIT 1—Continued 

Fuel switching options 

Estimated 

SO2 control 

efficiency 

(%) 

Natural gas ......................... 99 .9 

AECC estimated the average costeffectiveness of switching to No. 6 fuel 

oil with 1% sulfur content to be $2,613 

per ton of SO2 removed for McClellan 

Unit 1. Switching from the baseline fuel 

to No. 6 fuel oil with 0.5% sulfur 

content was estimated to cost $3,823 per 

ton of SO2 removed. The results of 

AECC’s cost analysis are summarized in 

the table below. For the natural gas 

switching scenario, AECC found that the 

current cost of natural gas is actually 

lower than the cost of the baseline fuel. 

Therefore, the average cost-effectiveness 

of switching from the baseline fuel to 

natural gas is denoted as a negative 

value (cost savings) in the table below. 

TABLE 17—AECC MCCLELLAN UNIT 1: SUMMARY OF COSTS ASSOCIATED WITH FUEL SWITCHING

Fuel switching 

scenario 

Average 

sulfur content 

(%) 

Baseline 

emission 

rate 

(SO2 tpy) 

Controlled 

emission 

rate 

(SO2 tpy) 

Annual 

emissions 

reductions 

(SO2 tpy) 

Annual 

fuel usage 

(Mgal/yr) 

Fuel cost 

($/MMBtu) 

Total annual 

differential 

cost of fuel 

switching 

($/yr) 

Average 

cost 

effectiveness 

($/ton) 

Incremental 

cost 

effectiveness 

($/ton) 

Baseline ..................................... 1.38 209.43 .................... .................... 1,882.15 16.00 .................... .................... ....................

No. 6 Fuel Oil—1% ................... 1.00 .................... 153.61 55.81 1,882.15 16.50 145,866 2,613 ....................

No. 6 Fuel Oil—0.5% ................ 0.50 .................... 75.88 133.55 1,882.15 17.75 510,532 3,823 4,691 

Diesel ........................................ 0.05 .................... 7.31 202.11 2,142.73 20.95 1,444,077 7,145 13,616 

Natural Gas ............................... 0.04 .................... 0.07 209.35 288.56 5.97 ¥2,926,874 ¥13,980 ¥603,723 

The AECC BART evaluation did not 

identify any energy or non-air quality 

environmental impacts associated with 

switching to 1% sulfur No. 6 fuel oil, 

0.5% sulfur No. 6 fuel oil, or diesel. The 

evaluation noted that switching to 

natural gas may have energy impacts 

during periods of natural gas 

curtailment. During periods of natural 

gas curtailment, natural gas 

infrastructure maintenance, and other 

emergencies, the McClellan Generating 

Station relies on the fuel oil stored at 

the plant to maintain electrical 

reliability. The AECC evaluation notes 

that because of this, it is important to 

maintain the ability to burn fuel oil at 

McClellan, even if fuel oil is currently 

more expensive to burn than natural 

gas. 

With regard to consideration of the 

remaining useful life of Unit 1, this 

factor does not impact the SO2 BART 

analysis because the emissions control 

approaches being evaluated for BART 

do not require capital cost expenditures. 

Thus, there are no control costs that 

need to be amortized over the lifetime 

of the unit. 

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Federal Register / Vol. 80, No. 67 / Wednesday, April 8, 2015 / Proposed Rules 18959 

AECC assessed the visibility 

improvement associated with fuel 

switching by comparing the 98th 

percentile modeled visibility impact of 

the baseline scenario (i.e., existing) to 

the 98th percentile modeled visibility 

impact of each control scenario. The 

table below shows a comparison of the 

baseline visibility impacts and the 

visibility impacts of the different fuel 

switching control scenarios that were 

evaluated, including the cumulative 

visibility benefits. 

TABLE 18—AECC MCCLELLAN UNIT 1: SUMMARY OF 98TH PERCENTILE VISIBILITY IMPACTS AND IMPROVEMENT DUE TO

FUEL SWITCHING

Class I area 

Baseline 

visibility 

impact 

(Ddv) 

No. 6 fuel oil—1% sulfur No. 6 fuel oil—0.5% sulfur Diesel Natural gas 

Visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Caney Creek ..................... 0.622 0.537 0.085 0.322 0 .3 0.174 0.448 0.125 0 .497 

Upper Buffalo .................... 0.266 0.231 0.035 0.146 0 .12 0.073 0.193 0.052 0 .214 

Hercules-Glades ................ 0.231 0.202 0.029 0.115 0 .116 0.062 0.169 0.040 0 .191 

Mingo ................................. 0.228 0.193 0.035 0.136 0 .092 0.080 0.148 0.058 0 .17 

Cumulative Visibility Improvement (Ddv) ............ .................... .................... 0.184 .................... 0 .628 .................... 0.958 .................... 1 .072 

The table above shows that switching 

to No. 6 fuel oil with 1% sulfur content 

at McClellan Unit 1 is projected to result 

in visibility improvement of 0.085 dv at 

Caney Creek. The visibility 

improvement at each of the other three 

affected Class I areas is projected to be 

0.035 dv or less, while the cumulative 

visibility improvement at the four Class 

I areas is projected to be 0.184 dv. 

Switching to No. 6 fuel oil with 0.5% 

sulfur content is projected to result in 

considerable visibility improvement. It 

is projected to result in 0.3 dv visibility 

improvement at Caney Creek. The 

visibility improvement at each of the 

other three affected Class I areas is 

projected to be 0.12 dv or less, while the 

cumulative visibility improvement at 

the four Class I areas is projected to be 

0.628 dv. Switching to diesel or natural 

gas is also projected to result in 

considerable visibility improvement. 

The visibility improvement at Caney 

Creek is projected to be 0.448 dv for 

switching to diesel and 0.497 dv for 

switching to natural gas. The 

cumulative visibility improvement at 

the four Class I areas is projected to be 

0.958 dv for switching to diesel and 

1.072 dv for switching to natural gas. 

Our Proposed SO2 BART 

Determination: Taking into 

consideration the five factors, we are 

proposing to determine that BART for 

McClellan Unit 1 is switching to fuels 

with 0.5% or lower sulfur content by 

weight. The cost of switching to No. 6 

fuel oil with 0.5% sulfur content is 

within the range of what we consider to 

be cost-effective for BART and it is 

projected to result in considerable 

visibility improvement compared to the 

baseline at the affected Class I areas. 

Switching to No. 6 fuel oil with 0.5% 

sulfur content has an estimated average 

cost-effectiveness of $3,823 per ton of 

SO2 removed and is projected to result 

in visibility improvement ranging from 

0.092 to 0.3 dv at each modeled Class 

I area, and a cumulative visibility 

improvement of 0.628 dv at the four 

affected Class I areas. Switching to 

natural gas currently would cost less 

than the baseline fuel and is projected 

to result in even greater visibility 

improvement than switching to No. 6 

fuel oil with 0.5% sulfur content. 

However, the BART Guidelines provide 

that it is not our intent to direct subjectto-BART sources to switch fuel forms, 

such as from coal or fuel oil to gas (40 

CFR part 51, Appendix Y, section 

IV.D.1). Because natural gas has a sulfur 

content by weight that is well below 

0.5%, the facility may elect to use this 

type of fuel to comply with BART, but 

we are not proposing to require a switch 

to natural gas for Unit 1. Switching to 

diesel is projected to result in 

considerable visibility improvement. 

The visibility improvement of switching 

to diesel is projected to range from 0.148 

to 0.448 dv at each modeled Class I area, 

and the cumulative visibility 

improvement is 0.958 dv at the four 

affected Class I areas. The incremental 

visibility improvement of switching to 

diesel compared to switching to No. 6 

fuel oil with a sulfur content of 0.5% is 

projected to range from 0.056 dv to 

0.148 dv at each affected Class I area. 

However, the average cost-effectiveness 

of switching to diesel is estimated to be 

$7,145 and the incremental costeffectiveness compared to No. 6 fuel oil 

with a sulfur content of 0.5% is $13,616 

per ton of SO2 removed, which we do 

not consider to be cost-effective in view 

of the incremental visibility 

improvement. Since diesel also has a 

sulfur content by weight that is well 

below 0.5%, the facility may elect to use 

this fuel type to comply with BART, but 

we are not proposing to require a switch 

to diesel for Unit 1. We are proposing 

to determine that SO2 BART for 

McClellan Unit 1 is switching to fuels 

with 0.5% or lower sulfur content by 

weight. We propose to require that the 

facility purchase no fuel after the 

effective date of the rule that does not 

meet the sulfur content requirement and 

that 5 years from the effective date of 

the rule no fuel be burned that does not 

meet the requirement. We propose that 

any higher sulfur fuel oil that remains 

from the facility’s 2009 fuel oil 

shipment cannot be burned past this 

point. As discussed above, the unit’s 

baseline fuel is No. 6 fuel oil with 

1.38% sulfur content, based on the 

average sulfur content of the fuel oil 

from the most recent shipment received 

by the facility in 2009. Based on our 

discussions with the facility, it is our 

understanding that the unit burns fuel 

oil primarily during periods of natural 

gas curtailment and during periodic 

testing and that the facility still has 

stockpiles of fuel oil from the most 

recent fuel oil shipment. Because the 

unit burns primarily natural gas and 

does not ordinarily burn fuel oil on a 

frequent basis, we believe it is 

appropriate to allow the facility 5 years 

to burn its existing supply of No. 6 fuel 

oil, as the normal course of business 

dictates and in accordance with any 

operating restrictions enforced by 

ADEQ. We believe that a shorter 

compliance date may result in the 

facility burning its existing supply of 

higher sulfur No. 6 fuel oil relatively 

quickly, resulting in a high amount of 

SO2 emissions being emitted by the unit 

over a short period of time. This is not 

the intent of our regional haze 

regulations. We are also proposing 

regulatory text that includes monitoring, 

reporting, and recordkeeping 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

18960 Federal Register / Vol. 80, No. 67 / Wednesday, April 8, 2015 / Proposed Rules 

33 ‘‘Controlling Nitrogen Oxides Under the Clean 

Air Act: A Menu of Options,’’ section II, dated July 

1994, State and Territorial Air Pollution Program Administrators (STAPPA) and Association of Local 

Air Pollution Control Officials (ALAPCO). 

requirements associated with this 

proposed determination. 

b. Proposed BART Analysis and 

Determination for NOX. The AECC 

evaluation examined BART controls for 

NOX for McClellan Unit 1. McClellan 

Unit 1 does not currently have pollution 

control equipment for NOX. AECC 

identified all available control 

technologies, eliminated options that 

are not technically feasible, and 

evaluated the control effectiveness of 

the remaining control options. Each 

technically feasible control option was 

then evaluated in terms of a five factor 

BART analysis. 

For NOX BART, the AECC evaluation 

considered both combustion and postcombustion controls. The combustion 

controls evaluated by AECC consisted of 

FGR, OFA, and LNB. The postcombustion controls evaluated 

consisted of SCR and SNCR. AECC 

found that some boilers may be 

restricted from installing OFA retrofits 

due to physical size and space 

restraints. For purposes of the NOX

BART evaluation, AECC assumed OFA 

to be a technically feasible option for 

McClellan Unit 1, but noted that if OFA 

was determined to be BART based on 

the evaluation of the five BART factors, 

then further analyses would have to be 

performed to determine if: (1) The 

dimensions of McClellan’s main boilers 

have sufficient upper furnace volume 

for OFA mixing and complete 

combustion and (2) the furnace meets 

the physical space requirements for 

OFA ports and air supply ducts. The 

remaining NOX control options were 

found to be technically feasible. 

AECC evaluated three control 

scenarios: A combination of combustion 

controls (FGR, OFA, and LNB); the 

combination of combustion controls and 

SNCR; and SCR. Based on literature 

estimates, AECC found that the 

estimated NOX control range for oil and 

gas wall-fired boilers, such as McClellan 

Unit 1, is approximately 0.2–0.4 lb/

MMBtu using FGR and 0.2–0.3 lb/

MMBtu using OFA.33 When LNB is 

combined with OFA and FGR, AECC 

estimated that a NOX controlled 

emission rate of 0.15–0.20 lb/MMBtu 

can be achieved at McClellan Unit 1. 

The NOX controlled emission rate of 

combustion controls combined with 

SNCR is estimated to be 0.10–0.12 lb/

MMBtu. The NOX control efficiency of 

SCR is estimated to be 80–90% for gas 

fired boilers and 70–80% for oil fired 

boilers, which corresponds to a 

controlled emission rate of 0.05–0.12 lb/ 

MMBtu for McClellan Unit 1. 

AECC’s cost analysis for NOX controls 

was based on ‘‘budgetary’’ cost 

estimates it obtained from the pollution 

control vendor, Babcock Power Systems. 

AECC estimated the capital and 

operating costs of controls based on the 

vendor’s estimates, engineering 

estimates, and published calculation 

methods using the EPA Control Cost 

Manual. We are not aware of any 

enforceable shutdown date for the 

McClellan Generating Station, nor did 

AECC’s evaluation indicate any future 

planned shutdown. This means that the 

anticipated useful life of the boiler is 

expected to be at least as long as the 

capital cost recovery period of controls. 

Therefore, a 30-year amortization period 

was assumed in the NOX BART analysis 

as the remaining useful life of Unit 1. 

The table below summarizes the 

estimated cost for installation and 

operation of NOX controls for McClellan 

Unit 1. 

TABLE 19—SUMMARY OF NOX CONTROL COSTS FOR AECC MCCLELLAN UNIT 1 

Control scenario 

Baseline 

emission rate 

(NOX tpy) 

Natural gas 

controlled 

emission level 

(lb/MMBtu) 

Fuel oil 

controlled 

emission level 

(lb/MMBtu) 

Controlled 

emission rate 

(tpy) 

Annual 

emissions 

reductions 

(NOX tpy) 

Total 

annual cost 

($/yr) 

Average cost 

effectiveness 

($/ton) 

Incremental 

cost 

($/ton) 

Combustion Controls ......... 294.04 0.15 0.15 174.89 119.15 746,051 6,261 ........................

Combustion Controls + 

SNCR ............................. 294.04 0.12 0.10 136.40 157.64 1,990,988 12,630 32,344 

SCR ................................... 294.04 0.05 0.12 64.98 229.06 1,732,870 7,565 ¥3,614 

AECC estimated the average costeffectiveness of installing and operating 

combustion controls to be $6,261 per 

ton of NOX removed. The combination 

of combustion controls and SNCR was 

estimated to cost $12,630 per ton of 

NOX removed, while SCR was estimated 

to cost $7,565 per ton of NOX removed. 

In its evaluation, AECC also explained 

that AECC expects the average costeffectiveness of NOX controls to be 

lower (i.e., greater dollars per ton 

removed) in future years due to 

projected reduced operation of the unit. 

AECC did not identify any energy or 

non-air quality environmental impacts 

associated with the use of LNB, OFA, or 

FGR. As for SCR and SNCR, we are not 

aware of any unusual circumstances at 

the facility that could create non-air 

quality environmental impacts 

associated with the operation of these 

controls greater than experienced 

elsewhere and that may therefore 

provide a basis for their elimination as 

BART (40 CFR part 51, Appendix Y, 

section IV.D.4.i.2.). Therefore, we do not 

believe there are any energy or non-air 

quality environmental impacts 

associated with NOX controls at AECC 

McClellan Unit 1 that would affect our 

proposed BART determination. 

AECC assessed the visibility 

improvement associated with NOX

controls by modeling the NOX emission 

rates associated with each control 

option using CALPUFF, and then 

comparing the visibility impairment 

associated with the baseline emission 

rates to the visibility impairment 

associated with the controlled emission 

rates as measured by the 98th percentile 

modeled visibility impact. The tables 

below show a comparison of the 

baseline (i.e., existing) visibility impacts 

and the visibility impacts associated 

with NOX controls. 

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Federal Register / Vol. 80, No. 67 / Wednesday, April 8, 2015 / Proposed Rules 18961 

34See ADEQ Operating Air Permit No. 0181– 

AOP–R5, Section IV, Specific Condition No. 1, 3, 

and 13. 

TABLE 20—AECC MCCLELLAN UNIT 1: SUMMARY OF THE 98TH PERCENTILE VISIBILITY IMPACTS AND IMPROVEMENT DUE

TO NOX CONTROLS—NATURAL GAS FIRING

[2001–2003] 

Class I area 

Baseline 

visibility impact 

(Ddv) 

Combustion 

controls 

Combustion 

controls + SNCR 

SCR 

Visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Caney Creek .............. 0.125 0.068 0.057 0.056 0.069 0.027 0 .098 

Upper Buffalo ............. 0.052 0.028 0.024 0.023 0.029 0.012 0 .04 

Hercules-Glades ........ 0.040 0.021 0.019 0.018 0.022 0.009 0 .031 

Mingo ......................... 0.058 0.031 0.027 0.026 0.032 0.012 0 .046 

Cumulative Visibility 

Improvement (Ddv) ........................ ........................ 0.127 ........................ 0.152 ........................ 0 .215 

TABLE 21—AECC MCCLELLAN UNIT 1: SUMMARY OF THE 98TH PERCENTILE VISIBILITY IMPACTS AND IMPROVEMENT DUE

TO NOX CONTROLS—FUEL OIL FIRING

[2001–2003] 

Class I area 

Baseline 

visibility impact 

(Ddv) 

Combustion 

controls 

Combustion 

controls + SNCR 

SCR 

Visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Caney Creek .............. 0.621 0.554 0.067 0.542 0.079 0.548 0 .073 

Upper Buffalo ............. 0.266 0.264 0.002 0.264 0.002 0.264 0 .002 

Hercules-Glades ........ 0.230 0.209 0.021 0.203 0.027 0.207 0 .023 

Mingo ......................... 0.227 0.203 0.024 0.200 0.027 0.201 0 .026 

Cumulative Visibility 

Improvement (Ddv) ........................ ........................ 0.114 ........................ 0.135 ........................ 0 .124 

The tables above show that the 

installation and operation of NOX

controls is projected to result in a very 

modest visibility improvement from the 

baseline. Combustion controls at 

McClellan Unit 1 are projected to result 

in visibility improvement of up to 0.057 

dv at any single Class I area for the 

natural gas firing scenario and 0.067 dv 

for the fuel oil firing scenario. A 

combination of combustion controls and 

SNCR is projected to result in only 

slight incremental visibility 

improvement compared to combustion 

controls alone. For example, a 

combination of combustion controls and 

SNCR at McClellan Unit 1 is projected 

to result in visibility improvement of up 

to 0.069 dv at any single Class I area for 

natural gas firing and 0.079 dv for fuel 

oil firing, which is an incremental 

visibility improvement for each fuel 

firing scenario of 0.012 dv going from 

combustion controls to combustion 

controls in combination with SNCR. 

Similarly, the installation and operation 

of SCR is projected to result in only 

slight incremental visibility 

improvement compared to a 

combination of combustion controls and 

SNCR, except for the fuel oil firing 

scenario. For the fuel oil firing scenario, 

SCR is projected to result in slightly less 

than or equal visibility improvement 

than a combination of combustion 

controls and SNCR. 

Our Proposed NOX BART 

Determination: Taking into 

consideration the five factors, we are 

proposing to determine that NOX BART 

for McClellan Unit 1 is no additional 

controls, and are proposing that the 

facility’s existing NOX emission limits 

satisfy BART for NOX. We are proposing 

the existing emission limits of 869.1 lb/ 

hr for natural gas firing and 705.8 lb/hr 

for fuel oil firing for NOX BART for 

McClellan Unit 1.34 As discussed above, 

the operation of combustion controls at 

McClellan Unit 1 is projected to result 

in a maximum visibility improvement of 

0.067 dv (Caney Creek), and a smaller 

amount of visibility improvement at 

each of the other Class I areas. The 

installation and operation of 

combustion controls at McClellan Unit 

1 has an average cost-effectiveness of 

$6,261 per ton of NOX removed, which 

is not within the range of what we 

generally consider to be cost-effective. 

We believe the relatively small visibility 

benefit projected from the operation of 

combustion controls both when 

combusting fuel oil and natural gas does 

not justify the high estimated cost of 

those controls. The operation of a 

combination of combustion controls and 

SNCR is estimated to cost $12,630 per 

ton of NOX removed, which is not costeffective. A combination of combustion 

controls and SNCR is projected to result 

in only slight incremental visibility 

benefit compared to combustion 

controls alone. The operation of SCR is 

estimated to cost $7,565 per ton of NOX

removed, which is not generally 

considered cost-effective, and is 

projected to result in only slight 

incremental visibility benefit compared 

to a combination of combustion controls 

and SNCR. We are proposing to find 

that NOX BART for McClellan Unit 1 is 

no additional controls and are 

proposing that the existing NOX

emission limits of 869.1 lb/hr for natural 

gas firing and 705.8 lb/hr for fuel oil 

firing are BART for NOX and that 

compliance be demonstrated using the 

unit’s existing CEMS. We are proposing 

that these emissions limitations be 

complied with for BART purposes from 

the date of effectiveness of the finalized 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

18962 Federal Register / Vol. 80, No. 67 / Wednesday, April 8, 2015 / Proposed Rules 

35See ‘‘AP–42, Compilation of Air Pollutant 

Emission Factors,’’ section 1.3.3.1, and Table 1.3– 

1, available at http://www.epa.gov/ttnchie1/ap42/. 

36The final version of AECC’s BART analysis for 

SO2 and PM, upon which our analysis is largely 

based, is titled ‘‘BART Five Factor Analysis 

Arkansas Electric Cooperative Corporation Bailey 

and McClellan Generating Stations, March 2014, 

Version 4.’’ A copy of AECC’s analysis can be found 

in the docket for our proposed rulemaking. 

action. We are also proposing regulatory 

text that includes monitoring, reporting, 

and recordkeeping requirements 

associated with these emission limits. 

c. Proposed BART Analysis and 

Determination for PM. McClellan Unit 1 

does not currently have pollution 

control equipment for PM. For PM 

BART, AECC’s evaluation considered 

the following control technologies: Dry 

ESP, wet ESP, fabric filter, wet scrubber, 

cyclone (i.e., mechanical collector), and 

fuel switching. Residual fuel, such as 

the baseline No. 6 fuel oil burned at 

McClellan Unit 1, has inherent ash that 

contributes to emissions of filterable 

PM. Reductions in filterable PM 

emissions are directly related to the 

sulfur content of the fuel.35 Therefore, 

switching to No. 6 fuel oil with a lower 

sulfur content is expected to result in 

lower filterable PM emissions. The 

AECC evaluation considered switching 

to No. 6 fuel oil with 1% sulfur content 

by weight, No. 6 fuel oil with 0.5% 

sulfur content by weight, diesel, and 

natural gas. These are the same lower 

sulfur fuel types evaluated in the SO2

BART analysis for the unit. 

The AECC evaluation noted that the 

particulate matter from oil-fired boilers 

tends to be sticky and small, affecting 

the collection efficiency of dry ESPs and 

fabric filters. Dry ESPs operate by 

placing a charge on the particles 

through a series of electrodes, and then 

capturing the charged particles on 

collection plates, while fabric filters 

work by filtering the PM in the flue gas 

through filter bags. The collected 

particles are periodically removed from 

the filter bag through a pulse jet or 

reverse flow mechanism. Because of the 

sticky nature of particles from oil-fired 

boilers, dry ESPs and fabric filters are 

deemed technically infeasible for use at 

McClellan Unit 1. Wet ESPs, cyclones, 

wet scrubbers, and fuel switching were 

identified as technically feasible options 

for McClellan Unit 1. AECC noted that 

although cyclones and wet scrubbers are 

considered technically feasible for use 

at these boiler types, they are not very 

efficient at controlling particles in the 

smaller size fraction, particularly 

particles smaller than a few microns. 

However, the majority of the PM 

emissions from McClellan Unit 1 are 

greater than a few microns in size. 

AECC estimated that switching to a 

lower sulfur fuel has a PM control 

efficiency ranging from approximately 

44%–99%, depending on the fuel type. 

The other technically feasible control 

technologies are estimated to have the 

following PM control efficiency: Wet 

ESP—up to 90%, cyclone—85%, and 

wet scrubber—55%. 

AECC evaluated the capital costs, 

operating costs, and average costeffectiveness of wet ESPs, cyclones, and 

wet scrubbers. AECC also evaluated the 

average cost-effectiveness of switching 

to No. 6 fuel oil with 1% sulfur content, 

No. 6 fuel oil with 0.5% sulfur content, 

diesel, and natural gas. AECC developed 

the capital and operating costs of a wet 

ESP and wet scrubber using the Electric 

Power Research Institute’s (EPRI) 

Integrated Emissions Control Cost 

Estimating Workbook (IECCOST) 

Software. The capital costs of controls 

(except for fuel switching) were 

annualized over a 15-year period and 

then added to the annual operating costs 

to obtain the total annualized costs. The 

table below summarizes the average 

cost-effectiveness of PM controls. The 

average cost-effectiveness was 

determined by dividing the annualized 

cost of controls by the annual PM 

emissions reductions. The annual 

emissions reductions were determined 

by subtracting the estimated controlled 

annual emission rates from the baseline 

annual emission rates. AECC estimated 

the baseline and controlled annual 

emission rates by conducting a mass 

balance on the sulfur content of the 

various fuels evaluated. 

We disagree with two aspects of 

AECC’s cost evaluation for PM controls 

for McClellan Unit 1. First, the total 

annual cost numbers associated with 

fuel switching should be the same as 

those used in the SO2 BART cost 

analysis (see Table 17). In earlier draft 

versions of AECC’s analysis, which were 

provided to us for review, the cost 

numbers for fuel switching used in the 

PM and SO2 BART analyses were 

identical. In response to comments 

provided by us, the total annual cost 

and average cost-effectiveness numbers 

for fuel switching were revised in the 

final version of AECC’s SO2 BART 

analysis. However, it appears that AECC 

overlooked updating these cost numbers 

in the final PM BART analysis.36 In the 

table below, we have revised the total 

annual cost of fuel switching for the PM 

BART analysis to be consistent with the 

cost estimates from AECC’s SO2 BART 

analysis, and we have also updated the 

PM average cost-effectiveness values. 

The second aspect of AECC’s cost 

evaluation for PM controls that we 

disagree with is the use of a 15-year 

capital cost recovery period for 

calculating the average costeffectiveness of a wet ESP, wet scrubber, 

and cyclone. As previously discussed, 

we are not aware of any enforceable 

shutdown date for the AECC McClellan 

Generating Station, nor did AECC’s 

BART evaluation indicate any future 

planned shutdown. Therefore, we 

believe that assuming a 30-year 

equipment life rather than a 15-year 

equipment life would be more 

appropriate for these control 

technologies. Extending the 

amortization period from 15 to 30 years 

has the effect of decreasing the total 

annual cost of each control option, 

thereby improving the average costeffectiveness of controls (i.e., less 

dollars per ton removed). However, after 

considering all five BART factors, we do 

not believe AECC’s assumption of a 15- 

year amortization period has an impact 

on our proposed BART decision and 

therefore we did not revise the 

amortization period or the average costeffectiveness calculations for the PM 

control equipment options. This is 

discussed in more detail below. The 

table below summarizes the estimated 

cost for fuel switching and the 

installation and operation of PM control 

equipment for McClellan Unit 1. 

TABLE 22—SUMMARY OF COST OF PM CONTROLS FOR AECC MCCLELLAN UNIT 1 

Control scenario 

Baseline 

emission rate 

(PM tpy) 

Control 

efficiency 

(%) 

Controlled 

emission rate 

(PM tpy) 

Annual 

emissions 

reduction 

(PM tpy) 

Capital cost 

($) 

Total annual 

cost 

($/yr) 

Average PM 

cost 

effectiveness 

($/ton) 

Incremental 

cost 

effectiveness 

(S/ton) 

No. 6 Fuel oil—1% S ........ 136.08 43.6 76.70 59.38 ........................ 145,866 2,456 ........................

Wet Scrubber .................... 136.08 55.0 61.23 74.84 146,303,011 52,056,542 695,549 3,357,741 

No. 6 Fuel oil—0.5% S ..... 136.08 82.4 23.94 112.14 ........................ 510,532 4,553 ¥1,381,931 

Cyclone ............................. 136.08 85.0 20.41 115.67 1,432,971 1,721,384 14,882 343,018 

Wet ESP ............................ 136.08 90.0 13.61 122.47 151,509,333 32,605,907 266,237 4,541,842 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 80, No. 67 / Wednesday, April 8, 2015 / Proposed Rules 18963 

TABLE 22—SUMMARY OF COST OF PM CONTROLS FOR AECC MCCLELLAN UNIT 1—Continued 

Control scenario 

Baseline 

emission rate 

(PM tpy) 

Control 

efficiency 

(%) 

Controlled 

emission rate 

(PM tpy) 

Annual 

emissions 

reduction 

(PM tpy) 

Capital cost 

($) 

Total annual 

cost 

($/yr) 

Average PM 

cost 

effectiveness 

($/ton) 

Incremental 

cost 

effectiveness 

(S/ton) 

Natural Gas ....................... 136.08 99.0 1.36 134.72 ........................ ¥2,926,874 ¥21,725 ¥2,900,635 

Diesel ................................ 136.08 99.2 1.10 134.98 ........................ 1,444,077 10,698 16,811,350 

The table above shows that the 

average cost-effectiveness values of all 

add-on PM control technology options 

evaluated for McClellan Unit 1 ranged 

in cost-effectiveness from approximately 

$15,000 to $700,000 per ton of PM 

removed, based on AECC’s cost 

estimates. The incremental costeffectiveness of add-on PM control 

technology options ranged from 

$343,018 to $16,811,350 per ton of PM 

removed. Switching to No. 6 fuel oil 

with either a 1% or 0.5% sulfur content 

was found to be within the range of 

what we generally consider costeffective for BART. Switching to No. 6 

fuel oil with 1% sulfur content is 

estimated to cost $2,456 per ton of PM 

removed, while switching to No. 6 fuel 

oil with 0.5% sulfur content is 

estimated to cost $4,553 per ton of PM 

removed at McClellan Unit 1. As 

discussed in the SO2 BART analysis, the 

current cost of natural gas is actually 

lower than the cost of the baseline fuel. 

Therefore, the average cost-effectiveness 

of switching from the baseline fuel to 

natural gas is denoted as a negative 

value in the table above. As discussed 

above, AECC also explained that it 

expects the average cost-effectiveness of 

PM control equipment to be lower (i.e., 

greater dollars per ton removed) in 

future years due to projected reduced 

operation of the units due to a change 

in the management of the load control 

area the facilities are located in. Less 

projected operating time is expected to 

result in lower annual emissions, which 

in turn would result in decreased 

average cost-effectiveness for the add-on 

PM control technology options. 

AECC did not identify any energy or 

non-air quality environmental impacts 

associated with fuel switching, but did 

identify impacts associated with the use 

of wet ESPs and wet scrubbers due to 

their electricity usage. Energy use in and 

of itself does not disqualify a technology 

(40 CFR part 51, Appendix Y, section 

IV.D.4.h.1.). In addition, the cost of the 

electricity needed to operate this 

equipment has already been factored 

into the cost of controls. AECC also 

noted that both wet ESPs and wet 

scrubbers generate wastewater streams 

that must either be treated on-site or 

sent to a waste water treatment plant, 

and the wastewater treatment process 

will generate a filter cake that would 

likely require landfilling. The BART 

Guidelines provide that the fact that a 

control device creates liquid and solid 

waste that must be disposed of does not 

necessarily argue against selection of 

that technology as BART, particularly if 

the control device has been applied to 

similar facilities elsewhere and the solid 

or liquid waste is similar to those other 

applications (40 CFR part 51, Appendix 

Y, section IV.D.4.i.2.). We are not aware 

of any unusual circumstances at the 

AECC McClellan Generating Station that 

could potentially create greater 

problems than experienced elsewhere 

related to the treatment of wastewater 

and any necessary landfilling, nor did 

the AECC BART evaluation discuss or 

mention any such unusual 

circumstances. Therefore, the need to 

treat wastewater or landfill any filter 

cake or other waste in and of itself does 

not provide a basis for disqualification 

or elimination of a wet ESP or wet 

scrubber. 

As previously discussed, we are not 

aware of any enforceable shutdown date 

for the AECC McClellan Generating 

Station, nor did the AECC evaluation 

indicate any future planned shutdown. 

Therefore, we believe it is appropriate to 

assume a 30-year amortization period in 

the PM BART analysis as the remaining 

useful life of the unit. Assuming a 30- 

year amortization period, these controls 

would have a lower estimated total 

annual cost and would therefore have 

an improved cost-effectiveness (i.e., less 

dollars per ton removed) compared to 

what was estimated in AECC’s 

evaluation. However, we did not adjust 

the amortization period because we do 

not believe this has an impact on our 

proposed BART decision. As discussed 

in the subsection below, the visibility 

benefit expected from the installation 

and operation of PM control equipment 

is too small to justify the cost of these 

controls. Therefore, we did not revise 

the amortization period and the average 

cost-effectiveness calculations for the 

PM control equipment options. 

As switching to lower sulfur fuels has 

impacts on both SO2 and PM emissions, 

AECC’s assessment of the visibility 

improvement associated with fuel 

switching is addressed in the SO2 BART 

analysis for McClellan Unit 1. Table 18 

summarizes the visibility improvement 

associated with controlled emission 

rates for SO2 and PM as a result of fuel 

switching. AECC assessed the visibility 

improvement associated with wet ESPs, 

wet scrubbers, and cyclones by 

modeling the PM emission rates 

associated with each control option 

using CALPUFF, and then comparing 

the visibility impairment associated 

with the baseline emission rates to the 

visibility impairment associated with 

the controlled emission rates as 

measured by the 98th percentile 

modeled visibility impact. The 

controlled PM10 emission rates 

associated with wet ESPs, wet 

scrubbers, and cyclones were calculated 

by reducing the uncontrolled annual 

PM10 emission rates by the pollutant 

removal efficiency of each control 

technology. The SO2 and NOX emission 

rates modeled in the controlled 

scenarios are the same as those from the 

baseline scenario, as it is assumed that 

SO2 and NOX emissions would remain 

unchanged. The table below shows a 

comparison of the baseline (i.e., 

existing) visibility impacts and the 

visibility impacts associated with PM 

controls. 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

18964 Federal Register / Vol. 80, No. 67 / Wednesday, April 8, 2015 / Proposed Rules 

37See ‘‘BART Five Factor Analysis Flint Creek 

Power Plant Gentry, Arkansas (AFIN 04–00107),’’ 

dated September 2013, Version 4, prepared by 

Trinity Consultants Inc. in conjunction with 

American Electric Power Service Corporation for 

the Southwestern Electric Power Company Flint 

Creek Power Plant. A copy of this BART analysis 

is found in the docket for our proposed rulemaking. 

38The NPS Workbook, ‘‘PC Dry Bottom ESP 

Example.xls’’ updated 03/2006, was obtained from 

the NPS Web site: http://www.nature.nps.gov/air/

Permits/ect/index.cfm. Trinity input the following 

parameters into the workbook for speciation 

determination: total PM10 emission rate of 192.5 lb/ 

hr, heat value of 8,500 Btu/lb, sulfur content of 

0.31%, ash content of 4.9%. 

TABLE 23—AECC MCCLELLAN UNIT 1: SUMMARY OF THE 98TH PERCENTILE VISIBILITY IMPACTS AND IMPROVEMENT

FROM PM CONTROLS

Class I area 

Baseline 

visibility 

impact 

(Ddv) 

Wet ESP Wet scrubber Cyclone 

Visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Caney Creek ................ 0.621 0.617 0.004 0.619 0.002 0.619 0.002 

Upper Buffalo ............... 0.266 0.263 0.003 0.264 0.002 0.265 0.001 

Hercules-Glades .......... 0.230 0.227 0.003 0.228 0.002 0.229 0.001 

Mingo ........................... 0.227 0.223 0.004 0.224 0.003 0.225 0.002 

Cumulative Visibility Improvement (Ddv) ....... ........................ ........................ 0.014 ........................ 0.009 ........................ 0.006 

The table above shows that the 

operation of a wet ESP, wet scrubber, 

and cyclone at McClellan Unit 1 is 

projected to result in minimal visibility 

improvement at the four affected Class 

I areas. The modeled visibility 

improvement from switching to No. 6 

fuel oil with 1% sulfur content; No. 6 

fuel oil with 0.5% sulfur content; diesel; 

and natural gas are summarized in Table 

18. The modeled visibility improvement 

shown in Table 18 reflects both SO2 and 

PM emissions reductions as a result of 

switching to fuels with lower sulfur 

content. However, the majority of the 

baseline visibility impact at each Class 

I area when burning the baseline fuel oil 

is due to SO2 emissions, while PM10

emissions contribute only a small 

portion of the baseline visibility impacts 

at each Class I area (see Table 15). 

Accordingly, the majority of the 

visibility improvement associated with 

switching to lower sulfur fuels can 

reasonably be expected to be the result 

of a reduction in SO2 emissions. 

Our Proposed PM BART 

Determination: Taking into 

consideration the five factors, we 

propose to determine that PM BART for 

AECC McClellan Unit 1 does not require 

add-on controls. Consistent with our 

proposed determination for SO2 BART, 

we are proposing that PM BART is 

satisfied by Unit 1 switching to fuels 

with 0.5% or lower sulfur content by 

weight. As discussed above, we disagree 

with AECC’s use of a 15-year 

amortization period in the cost analysis 

for a wet ESP, wet scrubber, and 

cyclone. Assuming a 30-year 

amortization period, these controls 

would have a lower estimated total 

annual cost and would therefore have 

an improved cost-effectiveness (i.e., less 

dollars per ton removed) compared to 

what was estimated in AECC’s 

evaluation. However, after considering 

all five BART factors, even if we revised 

AECC’s cost estimates to reflect a 30- 

year amortization period, resulting in a 

lower total annual cost and improved 

cost-effectiveness, we would still not be 

able to justify the cost in light of the 

minimal visibility benefit of these 

controls (see the table above). 

We are proposing to determine that 

PM BART for McClellan Unit 1 is 

switching to fuels with 0.5% or lower 

sulfur content by weight. We propose to 

require that the facility purchase no fuel 

after the effective date of the rule that 

does not meet the sulfur content 

requirement and that 5 years from the 

effective date of the rule no fuel be 

burned that does not meet the 

requirement. We propose that any 

higher sulfur fuel oil that remains from 

the facility’s 2009 fuel oil shipment 

cannot be burned past this point. As 

discussed above, the unit’s baseline fuel 

is No. 6 fuel oil with 1.38% sulfur 

content, based on the average sulfur 

content of the fuel oil from the most 

recent shipment received by the facility 

in 2009. Based on our discussions with 

the facility, it is our understanding that 

the unit burns fuel oil primarily during 

periods of natural gas curtailment and 

during periodic testing and that the 

facility still has stockpiles of fuel oil 

from the most recent fuel oil shipment. 

Because the unit burns primarily natural 

gas and does not ordinarily burn fuel oil 

on a frequent basis, we believe it is 

appropriate to allow the facility 5 years 

to burn its existing supply of No. 6 fuel 

oil, as the normal course of business 

dictates and in accordance with any 

operating restrictions enforced by 

ADEQ. We believe that a shorter 

compliance date may result in the 

facility burning its existing supply of 

higher sulfur No. 6 fuel oil relatively 

quickly, resulting in a high amount of 

SO2 emissions being emitted by the unit 

over a short period of time. This is not 

the intent of our regional haze 

regulations. We are also proposing 

regulatory text that includes monitoring, 

reporting, and recordkeeping 

requirements associated with this 

proposed determination. 

3. AEP Flint Creek Power Plant 

The AEP Flint Creek Power Plant Unit 

1 is subject to BART. We previously 

disapproved Arkansas’ BART 

determination for SO2 and NOX for Flint 

Creek Unit 1 in our March 12, 2012 final 

action (77 FR 14604). Flint Creek Unit 

1 is a dry bottom wall-fired boiler with 

a nominal generating capacity rating of 

558 MW and a nominal design 

maximum heat input rate of 6,324 

MMBtu/hr. The unit burns primarily 

low-sulfur western coal and is currently 

equipped with an ESP and low NOX

burners. AEP hired a consultant to 

prepare a BART five-factor analysis for 

the AEP Flint Creek Unit 1 (AEP BART 

analysis).37

The table below summarizes the 

baseline emission rates for this source. 

The SO2 and NOX baseline emission 

rates are the highest actual 24-hour 

emission rates based on 2001–2003 

CEMS data. The emission rates for the 

PM10 species reflect the breakdown of 

the filterable and condensable PM10

determined from the National Park 

Service (NPS) ‘‘speciation spreadsheet’’ 

for Dry Bottom Boiler Burning 

Pulverized Coal using only ESP.38 The 

sulfate (SO4) emission rate was 

calculated using an EPRI methodology 

that considers the SO2 to SO4

conversion rate and SO4 reduction 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 80, No. 67 / Wednesday, April 8, 2015 / Proposed Rules 18965 

39Electric Power Research Institute (EPRI) 

Estimating Total Sulfuric Acid Emissions from 

Stationary Power Plants: Version 2010a. EPRI, Palo 

Alto, CA: 2010. 

40 ‘‘Assessment of Control Technology Options 

for BART-Eligible Sources: Steam Electric Boilers, 

Industrial Boilers, Cement Plants and Paper and 

Pulp Facilities’’ Northeast States for Coordinated 

Air Use Management (NESCAUM), March 2005. 41See ‘‘BART Five Factor Analysis Flint Creek 

Power Plant Gentry, Arkansas (AFIN 04–00107),’’ 

dated September 2013, Version 4, prepared by 

Trinity Consultants Inc. in conjunction with 

American Electric Power Service Corporation for 

the Southwestern Electric Power Company Flint 

Creek Power Plant. AEP’s SO2 control cost 

calculations are found in Appendix A of the BART 

analysis. An Excel file titled ‘‘Consolidated 

Spreadsheet_2013–09–09’’ containing spreadsheets 

with cost information was also provided by AEP 

Flint Creek in support of the cost analysis. A copy 

of the BART analysis and the Excel file is found in 

the docket for our proposed rulemaking. 

factors for various downstream 

equipment.39

TABLE 24—AEP FLINT CREEK UNIT 1: BASELINE MAXIMUM 24-HOUR EMISSION RATES

Source SO2

(lb/hr) 

SO4

(lb/hr) 

NOX

(lb/hr) 

PMc 

(lb/hr) 

PMf 

(lb/hr) 

SOA 

(lb/hr) 

EC 

(lb/hr) 

Unit 1 (SN–01) ..................................................................... 4,728.4 3.1 1,945.0 65.1 50.1 15.1 1.9 

AEP modeled the baseline emission 

rates using the CALPUFF dispersion 

model to determine the baseline 

visibility impairment attributable to 

Flint Creek Unit 1 at the four Class I 

areas impacted by emissions from BART 

sources in Arkansas. These Class I areas 

are the Caney Creek Wilderness Area, 

Upper Buffalo Wilderness Area, 

Hercules-Glades Wilderness Area, and 

Mingo National Wildlife Refuge. The 

baseline (i.e., 2001–2003) visibility 

impairment attributable to the source at 

each Class I area is summarized in the 

table below. 

TABLE 25—BASELINE VISIBILITY IMPAIRMENT ATTRIBUTABLE TO AEP FLINT CREEK UNIT 1 

[2001–2003] 

Unit Caney Creek Upper Buffalo HerculesGlades Mingo 

AEP Flint Creek Unit 1: 

Maximum (Ddv) ......................................................................................... 1.318 2.426 2.103 1.488 

98th Percentile (Ddv) ................................................................................ 0.963 0.965 0.657 0.631 

a. Proposed BART Analysis and 

Determination for SO2. AEP identified 

all available control technologies, 

eliminated options that are not 

technically feasible, and evaluated the 

control effectiveness of the remaining 

control options. Each technically 

feasible control option was then 

evaluated in terms of a five factor BART 

analysis. 

The AEP evaluation considered Dry 

Sorbent Injection (DSI), dry FGD (i.e., 

dry scrubber), and wet FGD (i.e., wet 

scrubber) for SO2 BART. All three 

options were identified as technically 

feasible for use at Flint Creek Unit 1. 

The AEP evaluation noted that 

depending on residence time, gas stream 

temperature, and limitations of the 

particulate control device, DSI control 

efficiency can range between 40 to 

60%.40 Dry FGD control efficiency 

generally ranges from 60 to 95%. There 

are various designs of dry FGD systems, 

including Spray Dryer Absorber (SDA), 

Circulating Dry Scrubbing (CDS), and 

Novel Integrated Desulfurization (NID) 

technology. According to AEP’s 

evaluation, discussions with vendors 

indicated that an outlet emission rate of 

0.06 lb/MMBtu at Flint Creek Unit 1 

would be achievable with NID 

technology. AEP noted that it has no 

data to suggest that lower emission 

levels are sustainably achievable with 

the NID technology in a retrofit 

application, and that equipment 

vendors did not guarantee better 

performance than this. An emission rate 

of 0.06 lb/MMBtu represents 92% 

control from the unit’s baseline 30-day 

average rate of 0.75 lb/MMBtu. AEP’s 

analysis notes that dry FGD using lime 

as the reagent is capable of achieving 80 

to 95% control when used with lower 

sulfur coals such as those burned at 

Flint Creek Unit 1. The remainder of 

AEP’s analysis focused on wet FGD and 

dry FGD (NID). We concur with AEP’s 

decision to focus the remainder of the 

analysis on the two control options with 

the highest control efficiency. 

The estimated capital and operating 

costs of wet FGD and dry FGD (NID) 

developed by AEP and used in the costeffectiveness calculations were based on 

EPA’s Control Cost Manual and 

supplemented, where available, with 

vendor and site-specific information 

obtained by AEP. AEP annualized the 

capital cost of controls over a 30-year 

amortization period and then added 

these to the annual operating costs to 

obtain the total annualized costs. The 

average cost-effectiveness was 

calculated by dividing the total 

annualized cost of controls by the 

annual SO2 emissions reductions. AEP 

estimated the average cost-effectiveness 

of a wet FGD system to be $4,919 per 

ton of SO2 removed, while the average 

cost-effectiveness of NID was estimated 

to be $3,845 per ton of SO2 removed (see 

table below). 

We disagree with one aspect of AEP’s 

cost analysis.41 AEP’s cost estimates are 

based on 2016 dollars, which means 

that they were escalated to a future 

build date. BART cost analyses should 

be based on present dollars, and the 

EPA Control Cost Manual approach 

explicitly excludes future escalation, as 

cost comparisons should be made on a 

current real dollar basis. Escalation of 

costs from past to the current year of 

analysis is permitted, as costs are 

compared based on the time of estimate, 

but future escalation is not allowed. We 

expect that de-escalation to 2014 dollars 

would result in lower cost numbers and 

overall lower average cost-effectiveness 

values for all controls evaluated. We 

believe that wet FGD and NID are both 

more cost-effective (i.e., less dollars per 

SO2 ton removed) than what has been 

estimated by AEP. However, we did not 

adjust the cost numbers and the costeffectiveness values because we do not 

expect this to change our proposed 

BART decision. This is discussed in 

more detail below in the subsection 

titled ‘‘Our Proposed SO2 BART 

Determination.’’ 

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18966 Federal Register / Vol. 80, No. 67 / Wednesday, April 8, 2015 / Proposed Rules 

TABLE 26—SUMMARY OF COST OF SO2 CONTROLS FOR AEP FLINT CREEK UNIT 1 

Control technology 

Baseline 

emission rate 

(SO2 tpy) 

Controlled 

emission rate 

(SO2 lb/

MMBtu) 

Controlled 

emission rate 

(SO2 tpy) 

Annual 

emissions 

reductions 

(SO2 tpy) 

Capital cost 

($) 

Total annual 

cost 

($/yr) 

Average cost 

effectiveness 

($/ton) 

Incremental 

costeffectiveness 

($/ton) 

NID .................................... 11,641 0.06 1,120 10,521 281,738,024 40,448,089 3,845 ........................

Wet Scrubber .................... 11,641 0.04 747 10,894 374,427,351 53,592,663 4,919 35,240 

AEP’s evaluation noted that the 

potential negative energy and non-air 

quality environmental impacts are 

greater with wet FGD systems than dry 

FGD systems. AEP noted that wet FGD 

requires increased water use and 

generates large volumes of wastewater 

and solid waste/sludge that must be 

treated or stabilized before landfilling, 

placing additional burden on the 

wastewater treatment and solid waste 

management capabilities. We do not 

expect that water availability would 

affect the feasibility of wet FGD at Flint 

Creek Unit 1 because the facility is not 

located in an exceptionally arid region. 

Additionally, the BART Guidelines 

provide that the fact that a control 

device creates liquid and solid waste 

that must be disposed of does not 

necessarily argue against selection of 

that technology as BART, particularly if 

the control device has been applied to 

similar facilities elsewhere (40 CFR part 

51, Appendix Y, section IV.D.4.i.2.). In 

cases where the facility can demonstrate 

that there are unusual circumstances 

that would create greater problems than 

experienced elsewhere, this may 

provide a basis for the elimination of 

that control option as BART. But in this 

case, AEP has not indicated that there 

are any such unusual circumstances. 

Another potential negative energy and 

non-air quality environmental impact 

associated with wet FGD is the potential 

for increased power requirements and 

greater reagent usage compared to dry 

FGD. The costs associated with 

increased power requirements and 

greater reagent usage have already been 

factored into the cost analysis for wet 

FGD. 

AEP assessed the visibility 

improvement associated with wet FGD 

and NID technology by modeling the 

SO2 emission rates associated with each 

control option using CALPUFF, and 

then comparing the visibility 

impairment associated with the baseline 

emission rates to the visibility 

impairment associated with the 

controlled emission rates as measured 

by the 98th percentile modeled 

visibility impact. The table below 

compares the baseline (i.e., existing) 

visibility impacts with the visibility 

impacts associated with SO2 controls. 

TABLE 27—AEP FLINT CREEK UNIT 1: SUMMARY OF THE 98TH PERCENTILE VISIBILITY IMPACTS AND IMPROVEMENT DUE

TO SO2 CONTROLS

Class I area 

Baseline 

visibility impact 

(Ddv) 

NID Technology Wet scrubber 

Visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Caney Creek ........................................................................ 0.963 0.348 0.615 0.334 0.629 

Upper Buffalo ....................................................................... 0.965 0.501 0.464 0.488 0.477 

Hercules-Glades .................................................................. 0.657 0.312 0.345 0.305 0.352 

Mingo ................................................................................... 0.631 0.217 0.414 0.208 0.423 

Cumulative Visibility Improvement (Ddv) ............................. ........................ ........................ 1.838 ........................ 1.881 

The table above shows that the 

installation and operation of SO2

controls is projected to result in 

considerable visibility improvement 

from the baseline at the four impacted 

Class I areas. Installation and operation 

of NID technology is projected to result 

in visibility improvement of up to 0.615 

dv at any single Class I area (based on 

the 98th percentile modeled visibility 

impacts), while wet FGD is projected to 

result in visibility improvement of up to 

0.629 dv. Wet FGD is projected to result 

in very minimal incremental visibility 

benefit over NID technology, with the 

projected incremental visibility 

improvement over NID ranging from 

0.007 to 0.014 dv at each Class I area. 

Our Proposed SO2 BART 

Determination: Taking into 

consideration the five factors, we 

propose to determine that BART for 

AEP Flint Creek Unit 1 is an emission 

limit of 0.06 lb/MMBtu on a 30 boileroperating-day rolling average based on 

the installation and operation of NID. 

The operation of NID is projected to 

result in visibility improvement ranging 

from 0.352 to 0.629 dv at each affected 

Class I area (98th percentile basis), and 

based on AEP’s evaluation, is estimated 

to have an average cost-effectiveness of 

$3,845 per ton of SO2 removed. By 

comparison, AEP estimated wet FGD to 

have an average cost-effectiveness of 

$4,919 per ton of SO2 removed and the 

incremental cost-effectiveness of wet 

FGD compared to NID is estimated to be 

$35,240 per ton of SO2 removed. As 

discussed above, we believe that AEP’s 

escalation of the cost of controls to 2016 

dollars has likely resulted in the overestimation of the average costeffectiveness. Therefore, we believe wet 

FGD and NID are both more costeffective (i.e., less dollars per ton of SO2

removed) than estimated by AEP (see 

table above). However, we did not 

adjust the cost numbers and costeffectiveness calculations because we do 

not believe that doing so would change 

our proposed BART determination. We 

believe that the average costeffectiveness of both control options 

was likely over-estimated and the costs 

associated with wet FGD would 

continue to be higher than the costs 

associated with NID if the estimates 

were adjusted, yet the installation and 

operation of wet FGD is projected to 

result in minimal incremental visibility 

improvement over NID. We are 

proposing to determine that SO2 BART 

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Federal Register / Vol. 80, No. 67 / Wednesday, April 8, 2015 / Proposed Rules 18967 

42Section 51.308(e)(1)(iv), requires, ‘‘each source 

subject to BART be required to install and operate 

BART as expeditiously as practicable, but in no event later than 5 years after approval of the 

implementation plan revision.’’ 

for Flint Creek Unit 1 is an emission 

limit of 0.06 lb/MMBtu on a 30 boileroperating-day rolling average based on 

the installation and operation of NID. 

We believe that the full compliance 

time 42 of 5 years is warranted for a new 

scrubber retrofit and so propose to 

require compliance with this 

requirement no later than 5 years from 

the effective date of the final rule. We 

are proposing to require that compliance 

be demonstrated using the unit’s 

existing CEMS. We are also proposing 

regulatory text that includes monitoring, 

reporting, and recordkeeping 

requirements associated with this 

emission limit. 

b. Proposed BART Analysis and 

Determination for NOX. AEP’s BART 

evaluation examined BART controls for 

NOX for Flint Creek Unit 1 by 

identifying all available control 

technologies, eliminating options that 

are not technically feasible, and 

evaluating the control effectiveness of 

the remaining control options. Each 

technically feasible control option was 

then evaluated in terms of a five factor 

BART analysis. 

For NOX BART, the AEP evaluation 

considered both combustion and postcombustion controls. The combustion 

controls considered by AEP consisted of 

FGR, OFA, and LNB. The postcombustion controls considered 

consisted of SCR and SNCR. All control 

options evaluated were found to be 

technically feasible. AEP estimated that 

FGR would be able to achieve a 

controlled emission rate of 0.23–0.29 lb/ 

MMBtu at Unit 1, which is a less 

stringent emission rate than would be 

achieved with LNB/OFA. Therefore, 

FRG was not further considered in the 

BART evaluation, while LNB/OFA were 

further considered. AEP evaluated three 

control scenarios: (1) LNB with OFA 

(LNB/OFA); (2) the combination of LNB 

with OFA and SNCR (LNB/OFA + 

SNCR); and (3) SCR. The baseline NOX

emission rate assumed by AEP in the 

analysis is 0.31 lb/MMBtu. AEP 

estimated that the installation and 

operation of LNB/OFA at Flint Creek 

Unit 1 would achieve a NOX control 

level of approximately 0.23 lb/MMBtu 

on a 30 boiler-operating-day averaging 

basis. It also estimated that LNB/OFA + 

SNCR would achieve a NOX control 

level of approximately 0.20 lb/MMBtu, 

and that SCR would achieve a NOX

control level of approximately 0.07 lb/ 

MMBtu, also on a 30 boiler-operatingday averaging basis. 

AEP estimated the capital costs, 

operating costs, and average costeffectiveness of controls based on 

vendor estimates and published 

calculation methods. AEP noted that the 

EPA Control Cost Manual was followed 

to the extent possible and estimates 

were supplemented with vendor and 

site-specific information where 

available. The cost analysis assumed a 

30-year amortization period for LNB/

OFA and for SCR, and a 20-year 

amortization period for SNCR. We 

discuss the appropriateness of the 

choice of amortization periods below. 

The total annual costs were estimated 

by annualizing the capital cost of 

controls over either a 30-year or 20-year 

period and then adding to this value the 

annual operating cost of controls. AEP 

determined the annual tons reduced 

associated with each NOX control 

option by subtracting the estimated 

controlled annual emission rate from 

the baseline annual emission rate. The 

baseline annual emission rate is the 

average rate as reported by AEP Flint 

Creek in the 2001–2003 air emission 

inventories. The average costeffectiveness of NOX controls was 

calculated by dividing the total annual 

cost of each control option by the 

estimated annual NOX emissions 

reductions. The table below summarizes 

the average-cost effectiveness of NOX

controls for Flint Creek Unit 1. 

TABLE 28—SUMMARY OF NOX CONTROL COSTS FOR FLINT CREEK UNIT 1 

Control technology 

Baseline 

emission rate 

(NOX tpy) 

Controlled 

emission level 

(NOX lb/

MMBtu) 

Controlled 

emission rate 

(NOX tpy) 

Annual 

emissions 

reductions 

(NOX tpy) 

Capital cost 

($) 

Total annual 

cost 

($/yr) 

Average cost 

effectiveness 

($/ton) 

Incremental 

costeffectiveness 

($/ton) 

LNB/OFA ........................... 5,120 0.23 4,295 826 16,000,000 1,454,621 1,761 ........................

LNB/OFA/SNCR ................ 5,120 0.20 3,772 1,348 23,124,235 4,177,782 3,099 5,217 

SCR ................................... 5,120 0.07 1,251 3,869 121,440,000 13,769,599 3,559 3,805 

AEP estimated the average costeffectiveness of installing and operating 

LNB/OFA to be $1,761 per ton of NOX

removed, while the combination of 

LNB/OFA + SNCR is estimated to cost 

$3,099 per ton of NOX removed, and 

SCR is estimated to cost $3,559 per ton 

of NOX removed. 

AEP did not identify any energy or 

non-air quality environmental impacts 

associated with the use of LNB/OFA. As 

for SCR and SNCR, we are not aware of 

any unusual circumstances at the 

facility that could create non-air quality 

environmental impacts associated with 

the operation of these controls greater 

than experienced elsewhere and that 

may therefore provide a basis for their 

elimination as BART (40 CFR part 51, 

Appendix Y, section IV.D.4.i.2.). 

Therefore, we do not believe there are 

any energy or non-air quality 

environmental impacts associated with 

the operation of NOX controls at AEP 

Flint Creek Unit 1 that would affect our 

proposed BART determination. 

Flint Creek Unit 1 is currently 

equipped with early generation low 

NOX burners for control of NOX

emissions. Consideration of the 

presence of existing pollution control 

technology at each source is reflected in 

the BART analysis in two ways: First, in 

the consideration of available control 

technologies, and second, in the 

development of baseline emission rates 

for use in cost calculations and visibility 

modeling. The baseline emission rate 

used in the cost calculations and 

visibility modeling reflects the 

operation of these controls. The newer 

generation low NOX burners evaluated 

by AEP are expected to achieve a higher 

level of NOX control than the currently 

installed early generation low NOX

burners. 

We are not aware of any enforceable 

shutdown date for the AEP Flint Creek 

Power Plant, nor did AEP’s evaluation 

indicate any future planned shutdown. 

This means that the anticipated useful 

life of the boiler is expected to be at 

least as long as the capital cost recovery 

period of controls. AEP assumed a 30- 

year amortization period in the 

evaluation of LNB, OFA, and SCR as the 

remaining useful life of the unit, and a 

20-year amortization period in the 

evaluation of SNCR. We disagree with 

AEP’s assumption of a 20-year 

amortization period in the cost analysis 

of SNCR. Any air pollution controls on 

the unit are expected to have the same 

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18968 Federal Register / Vol. 80, No. 67 / Wednesday, April 8, 2015 / Proposed Rules 

life as the boiler. Therefore, we believe 

it is appropriate to assume a 30-year 

amortization period for SNCR, as was 

done for SCR and combustion controls. 

Assuming a 30-year amortization 

period, SNCR would have a lower 

estimated total annual cost and would 

therefore have an improved costeffectiveness (i.e., less dollars per ton 

removed) compared to what was 

estimated in AEP’s evaluation. 

However, we did not adjust the 

amortization period assumed in AEP’s 

evaluation because we do not believe 

this has an impact on our proposed 

BART decision. As discussed in the 

subsection below, the incremental 

visibility benefit expected from the 

installation and operation of SNCR is 

too small to justify the cost of this 

control compared to combustion 

controls alone. Therefore, we did not 

revise the amortization period and the 

average cost-effectiveness calculations 

for SNCR. 

AEP assessed the visibility 

improvement associated with NOX

controls by modeling the NOX emission 

rates associated with each control 

option using CALPUFF, and then 

comparing the visibility impairment 

associated with the baseline emission 

rate to the visibility impairment 

associated with the controlled emission 

rates as measured by the 98th percentile 

modeled visibility impact. The table 

below shows a comparison of the 

baseline (i.e., existing) visibility impacts 

and the visibility impacts associated 

with NOX controls. 

TABLE 29—AEP FLINT CREEK UNIT 1: SUMMARY OF THE 98TH PERCENTILE VISIBILITY IMPACTS AND IMPROVEMENT DUE

TO NOX CONTROLS

Class I area 

Baseline 

visibility 

impact 

(Ddv) 

LNB/OFA LNB/OFA + SNCR SCR 

Visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Visibility 

impact 

(Ddv) 

Visibility 

Improvement 

from Baseline 

(Ddv) 

Visibility 

Impact 

(Ddv) 

Visibility 

Improvement 

from Baseline 

(Ddv) 

Caney Creek ............................................ 0.963 0.882* 0.081* 0.849 0.114 0.718 0 .245 

Upper Buffalo ........................................... 0.965 0.939 0.026 0.932 0.033 0.895 0 .07 

Hercules-Glades ...................................... 0.657 0.633 0.024 0.623 0.034 0.573 0 .084 

Mingo ....................................................... 0.631 0.617 0.014 0.612 0.019 0.588 0 .043 

Cumulative Visibility Improvement (Ddv) .................. .................. 0.145 .................. 0.2 .................. 0 .442 

* EPA identified a discrepancy in the results presented by AEP and reran the model for the 2003 model year. These values have been adjusted to reflect the results of the EPA model run. 

As shown in the table above, the 

installation and operation of LNB/OFA 

is projected to result in visibility 

improvement of up to 0.081 dv at any 

single Class I area, based on the 98th 

percentile visibility impairment. The 

installation and operation of LNB/OFA 

+ SNCR is projected to result in 

visibility improvement of up to 0.114 dv 

over the baseline. The installation and 

operation of SCR is projected to result 

in visibility improvement of up to 0.245 

dv in any single Class I area. The 

combination of LNB/OFA + SNCR 

would result in slight incremental 

visibility benefit over LNB/OFA at 

Caney Creek and in negligible 

incremental visibility benefit at the 

other three affected Class I areas. SCR 

would result in 0.131 dv incremental 

visibility benefit over LNB/OFA + SNCR 

at Caney Creek and less than half as 

much incremental visibility benefit at 

the other three affected Class I areas. 

Our Proposed NOX BART 

Determination: Taking into 

consideration the five factors, we 

propose to determine that NOX BART 

for Flint Creek Unit 1 is an emission 

limit of 0.23 lb/MMBtu on a 30 boileroperating-day rolling average based on 

the installation and operation of new 

LNB/OFA. The operation of new LNB/ 

OFA is projected to result in visibility 

improvement ranging from 0.014 to 

0.081 dv at each affected Class I area 

(98th percentile basis) and is projected 

to have a cumulative visibility 

improvement of 0.145 dv across the four 

affected Class I areas. The operation of 

LNB/OFA is estimated to have an 

average cost-effectiveness of $1,761 per 

ton of NOX removed, which we consider 

to be very cost-effective. By comparison, 

the operation of LNB/OFA + SNCR is 

projected to result in small incremental 

visibility improvement over LNB/OFA, 

but is estimated to have an average costeffectiveness of $3,099 per ton of NOX

removed and an incremental costeffectiveness of $5,217 per ton of NOX

removed. We believe that AEP’s 

assumption of a 20-year amortization 

period for SNCR has likely resulted in 

lower cost-effectiveness for SNCR. 

Therefore, we believe LNB/OFA + SNCR 

is more cost-effective (i.e., less dollars 

per ton of NOX removed) than estimated 

by AEP (see table above). However, we 

did not adjust the cost numbers and 

cost-effectiveness values because we do 

not believe that doing so would change 

our proposed BART determination, as 

the installation and operation of LNB/

OFA + SNCR is projected to result in 

minimal incremental visibility 

improvement over LNB/OFA alone such 

that the additional cost of SNCR is not 

justified. 

The operation of SCR is projected to 

result in visibility improvement ranging 

from 0.043 to 0.245 dv at each Class I 

area, and has an average costeffectiveness of $3,559 per ton of NOX

removed. The incremental visibility 

benefit of SCR compared to LNB/OFA + 

SNCR is projected to be 0.131 dv at 

Caney Creek and is projected to range 

from 0.024 to 0.05 dv at the remaining 

Class I areas. The incremental costeffectiveness of SCR is estimated to be 

$3,805 per ton of NOX removed. 

Although we are not adjusting the cost 

estimate for the reason discussed above, 

we note that AEP’s assumption of a 20- 

year amortization period for SNCR has 

the effect of making the average costeffectiveness of SCNR appear lower (i.e., 

greater dollars per ton removed), while 

the incremental cost-effectiveness of 

SCR over LNB/OFA + SNCR appears to 

be higher (i.e., less dollars per ton 

removed) than it actually is. Therefore, 

an adjustment of the amortization 

period and average cost effectiveness for 

SNCR is expected to result in an 

incremental cost effectiveness for SCR 

that is less favorable than currently 

estimated. While we believe the average 

and incremental cost-effectiveness of 

SCR, as calculated by AEP, is within the 

range of what we consider to be costeffective, we do not believe the 0.131 dv 

incremental visibility benefit of SCR 

over LNB/OFA + SCNR at a single Class 

I area warrants the higher costs 

associated with SCR. We are proposing 

to determine that NOX BART for Flint 

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Federal Register / Vol. 80, No. 67 / Wednesday, April 8, 2015 / Proposed Rules 18969 

43See ‘‘Revised BART Five Factor Analysis White 

Bluff Steam Electric Station Redfield, Arkansas 

(AFIN 35–00110),’’ dated October 2013, prepared by 

Trinity Consultants Inc. in conjunction with 

Entergy Services Inc. We refer to this BART analysis 

as ‘‘Entergy’s BART analysis’’ throughout this 

proposed rulemaking, and a copy of it is found in 

the docket for our proposed rulemaking. 

44See the ‘‘S&L NOX Control Technology Study,’’ 

which is found in Appendix E to the ‘‘Revised 

BART Five Factor Analysis White Bluff Steam 

Electric Station Redfield, Arkansas (AFIN 35– 

00110),’’ dated October 2013, prepared by Trinity 

Consultants Inc. in conjunction with Entergy 

Services Inc. A copy of this BART analysis and its 

appendices is found in the docket for our proposed 

rulemaking. 

45 40 CFR part 51, Appendix Y, section IV.D.4.c. 

46The NPS Workbook, ‘‘PC Dry Bottom ESP 

Example.xls’’ updated 03/2006, was obtained from 

the NPS Web site: http://www.nature.nps.gov/air/

Permits/ect/index.cfm. Trinity input the following 

parameters into the workbook for speciation 

determination: total PM10 emission rate of 118.6 lb/ 

hr, heat value of 8,950 Btu/lb, sulfur content of 

0.27%, ash content of 4.87%. 

47Electric Power Research Institute (EPRI) 

Estimating Total Sulfuric Acid Emissions from 

Stationary Power Plants: Version 2010a. EPRI, Palo 

Alto, CA: 2010 

Creek Unit 1 is an emission limit of 0.23 

lb/MMBtu on a 30 boiler-operating-day 

rolling average based on the installation 

and operation of new LNB/OFA. We are 

proposing to require that compliance be 

demonstrated using the unit’s existing 

CEMS. We consider 3 years to be an 

adequate time for the installation of 

NOX combustion controls and thus 

propose to require compliance with this 

requirement no later than 3 years from 

the effective date of the final rule. We 

are also proposing regulatory text that 

includes monitoring, reporting, and 

recordkeeping requirements associated 

with this emission limit. 

4. Entergy White Bluff Plant 

The Entergy White Bluff Plant Unit 1, 

Unit 2, and the Auxiliary Boiler are 

subject to BART. As mentioned 

previously, we disapproved Arkansas’ 

BART determinations for SO2 and NOX

for Units 1 and 2 and the BART 

determination for all pollutants for the 

Auxiliary Boiler in our March 12, 2012 

final action (77 FR 14604). White Bluff 

Units 1 and 2 are identical tangentiallyfired boilers with a maximum net power 

rating of 850 MW each and a nominal 

heat input capacity of 8,950 MMBtu/hr 

each. The boilers burn sub-bituminous 

coal as the primary fuel and No. 2 fuel 

oil or biofuel as a start-up fuel. Units 1 

and 2 are currently equipped with ESPs 

for control of PM emissions. The 

Auxiliary Boiler is a 183 MMBtu/hr 

auxiliary boiler that burns only No. 2 

fuel oil or biodiesel, and its purpose is 

to provide steam for the start-up of the 

two primary boilers, Units 1 and 2. The 

Auxiliary Boiler is typically only used 

in the rare instance when both of the 

main boilers are not operating. 

Entergy hired a consultant to conduct 

a BART five-factor analysis for White 

Bluff Units 1, 2, and the Auxiliary 

Boiler (Entergy BART analysis).43 The 

table below summarizes the baseline 

emission rates Entergy assumed in the 

BART analysis for the subject to BART 

units. The SO2 and NOX baseline 

emission rates are the highest actual 24- 

hour emission rates based on data from 

the Clean Air Markets Division (CAMD) 

database from 2001–2003 for SO2 and 

from 2009–2011 for NOX. The 2001– 

2003 period was not used as the 

baseline for NOX because that period no 

longer represents actual operation of the 

boilers. In 2006, Entergy completed the 

addition of a neural network system and 

conducted extensive boiler tuning that 

substantially reduced NOX emissions, 

resulting in an actual change in 

operations and emissions between the 

original baseline period (2001–2003) 

and current operations. Neural network 

systems are online enhancements to 

digital control systems (DCS) and plant 

information systems that improve boiler 

performance parameters such as heat 

rate, NOX emissions, and carbon 

monoxide (CO) levels. According to 

information provided by the facility, the 

purpose of the neural network system 

was to monitor and control the heat rate 

at Units 1 and 2.44 The neural network 

system installed at Units 1 and 2 is 

optimized first for monitoring and 

controlling the heat rate, and second for 

minimizing NOX emissions. We believe 

the use of 2009–2011 as the new 

baseline period for NOX for Units 1 and 

2 is consistent with the BART 

Guidelines, which provide that ‘‘The 

baseline emissions rate should represent 

a realistic depiction of anticipated 

annual emissions for the source.’’ 45 The 

PM10 emission rates are based on 

emission factors from AP–42 for PM 

filterable and PM condensable with a 

99% control efficiency for ESP applied 

to the PM10 filterable. The emission 

rates for the PM10 species reflect the 

breakdown of the PM10 determined from 

the National Park Service (NPS) 

‘‘speciation spreadsheet’’ for Dry Bottom 

Boiler Burning Pulverized Coal using 

only ESP.46 To estimate sulfuric acid 

emissions to model for the baseline and 

control cases, AEP assumed all 

inorganic PM was SO4. We note that this 

methodology can overestimate the 

amount of sulfuric acid emitted from the 

facility and we recommend that sulfuric 

acid emissions from power plants be 

calculated by estimating the amount of 

H2SO4 produced and the amount of 

H2SO4 removed by control equipment 

using information from the Electric 

Power Research Institute (EPRI).47

Rather than assuming that 100% of 

inorganic condensable PM is SO4, the 

EPRI method estimates the amount of 

SO2 that is oxidized to SO3, assumes 

that 100% of SO3 is converted to H2SO4, 

and then accounts for losses due to 

downstream equipment. The sulfuric 

acid emissions for the base and control 

scenarios may be slightly overestimated 

in AEP’s modeling. However, in this 

specific situation, we do not anticipate 

that this difference would significantly 

impact the relative benefits of the SO2

controls examined or impact our BART 

determination since the overall impacts 

and benefits of control are large. 

TABLE 30—ENTERGY WHITE BLUFF: BASELINE MAXIMUM 24-HOUR EMISSION RATES

Subject to BART Unit SO2

(lb/hr) 

NOX

(lb/hr) 

Total 

PM10

(lb/hr) 

SO4

(lb/hr) 

PMc 

(lb/hr) 

PMf 

(lb/hr) 

SOA 

(lb/hr) 

EC 

(lb/hr) 

Unit 1 (SN–01) ................................................. 7,763.5 3,001.4 118.6 36.8 40.4 31.1 9.2 1.2 

Unit 2 (SN–02) ................................................. 7,825.1 3,527.4 118.6 36.8 40.4 31.1 9.2 1.2 

Auxiliary Boiler (SN–05) ................................... 5.8 31.7 2.8 0.9 0.5 1.2 0.2 0.1 

Entergy modeled the baseline 

emission rates using the CALPUFF 

dispersion model to determine the 

baseline visibility impairment 

attributable to White Bluff Unit 1, Unit 

2, and the Auxiliary Boiler at the four 

Class I areas impacted by emissions 

from BART sources in Arkansas. These 

Class I areas are the Caney Creek 

Wilderness Area, Upper Buffalo 

Wilderness Area, Hercules-Glades 

Wilderness Area, and Mingo National 

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18970 Federal Register / Vol. 80, No. 67 / Wednesday, April 8, 2015 / Proposed Rules 

48See the document titled ‘‘Response of Entergy 

Arkansas, Inc. to Arkansas Public Service 

Commission Order No. 17.’’ A copy of this 

document can be found in the docket for this 

proposed rulemaking. 

49See ‘‘Revised BART Five Factor Analysis White 

Bluff Steam Electric Station Redfield, Arkansas 

(AFIN 35–00110),’’ dated October 2013, prepared by 

Trinity Consultants Inc. in conjunction with 

Entergy Services Inc. We refer to this BART analysis 

as ‘‘Entergy’s BART analysis’’ throughout this 

proposed rulemaking, and a copy of it is found in 

the docket for our proposed rulemaking. 

50 ‘‘Assessment of Control Technology Options 

for BART-Eligible Sources: Steam Electric Boilers, 

Industrial Boilers, Cement Plants and Paper and 

Pulp Facilities’’ Northeast States for Coordinated 

Air Use Management (NESCAUM), March 2005. 

51See ‘‘Technical Support Document for the SDA 

Control Cost Analysis for the Entergy White Bluff 

and Independence Facilities Arkansas Regional 

Haze Federal Implementation Plan (SO2 Cost 

TSD).’’ A copy of this document is found in the 

docket for our proposed rulemaking. 

Wildlife Refuge. The baseline (i.e., 

existing) visibility impairment 

attributable to the source at each Class 

I area is summarized in the table below. 

TABLE 31—BASELINE VISIBILITY IMPAIRMENT ATTRIBUTABLE TO ENTERGY WHITE BLUFF

[2001–2003] 

Unit Caney 

Creek 

Upper 

Buffalo 

HerculesGlades Mingo 

Unit 1 (SN–01).

Maximum (Ddv) ................................................................................................. 4.194 2.339 2.230 1.569 

98th Percentile (Ddv) ......................................................................................... 1.628 1.140 1.041 0.887 

Unit 2 (SN–02).

Maximum (Ddv) ................................................................................................. 4.437 2.385 2.263 1.701 

98th Percentile (Ddv) ......................................................................................... 1.695 1.185 1.060 0.903 

Auxiliary Boiler (SN–05).

Maximum (Ddv) ................................................................................................. 0.036 0.014 0.008 0.019 

98th Percentile (Ddv) ......................................................................................... 0.01 0.004 0.004 0.008 

a. Proposed SO2 BART Analysis and 

Determination for Units 1 and 2. In its 

2008 RH SIP Arkansas evaluated FGD 

controls (both wet and dry scrubbers) 

and determined that SO2 BART for 

White Bluff Units 1 and 2 is the 

presumptive emission limit of 0.15 lb/ 

MMBtu based on the installation of FGD 

controls. In our March 12, 2012 final 

action (77 FR 14604), we disapproved 

Arkansas’ SO2 BART determination 

because wet and dry FGD were 

evaluated at the presumptive emission 

limit only and not at the most stringent 

level of control these technologies are 

capable of achieving. In our October 17, 

2011 proposed action we discussed that, 

considering the coal burned in this case, 

wet FGD is typically capable of 

achieving a controlled emission rate of 

0.04 lb/MMBtu, while dry FGD is 

typically capable of achieving a 

controlled emission rate of 0.06 lb/

MMBtu (76 FR 64186). We also 

discussed that operating these controls 

at the most stringent achievable 

controlled emission rate versus the 

presumptive emission limit was not 

expected to increase the capital cost of 

controls. Rather, it was expected that a 

more stringent level of control would 

increase the operation and maintenance 

costs as a result of increased reagent 

usage, among other things. However, we 

expected the increase in annualized cost 

to be offset by the increase in tons of 

SO2 removed, causing the cost 

effectiveness ($/ton) to remain the same 

or slightly improve (i.e., lower $/ton). 

The fact that wet and dry FGD were not 

evaluated at the most stringent level of 

control they are capable of achieving, 

even though installation and operation 

of these control technologies at that 

control level was still expected to be 

cost-effective was the primary reason for 

our March 12, 2012 disapproval of 

Arkansas’ SO2 BART determination for 

White Bluff Units 1 and 2. We note that 

the 2008 Arkansas RH SIP included 

FGD controls for White Bluff Units 1 

and 2, and that Entergy submitted an 

application for a Title V permit 

modification for the White Bluff facility 

on February 4, 2009, for the installation 

of a dry FGD system (i.e., dry scrubbers) 

to satisfy the SO2 BART requirement.48

However, Entergy suspended the project 

for the installation of these SO2 controls 

after our final disapproval of SO2 BART 

for Units 1 and 2. 

The Entergy BART analysis 49

considered Dry Sorbent Injection (DSI), 

dry FGD (dry scrubbers), and wet FGD 

(wet scrubbers) for SO2 BART. All three 

options were identified as technically 

feasible for use at White Bluff Units 1 

and 2. Entergy’s evaluation noted that 

DSI control efficiency ranges between 

40 to 60%,50 dry FGD control efficiency 

ranges from 60 to 95%, and wet FGD 

ranges from 80–95% control efficiency, 

but can achieve up to 97% control 

efficiency when burning higher sulfur 

coal. Entergy evaluated wet FGD at an 

outlet SO2 emission rate of 0.04 lb/

MMBtu for Units 1 and 2. The 

remainder of Entergy’s analysis focused 

on wet FGD and dry FGD. We concur 

with Entergy’s decision to focus the 

remainder of the analysis on the two 

control options with the highest control 

efficiency. 

Our Dry Scrubbing Cost Analysis for 

Entergy White Bluff: Entergy’s estimates 

of the capital and direct operating and 

maintenance costs of a dry scrubber 

were based on vendor estimates. 

Estimates of the indirect operating costs 

were based on calculation methods from 

our Control Cost Manual. The estimates 

of the capital and operating and 

maintenance costs of wet FGD were 

based on vendor estimates obtained by 

Entergy for a system estimated to 

achieve 97% control and calculation 

methods from our Control Cost Manual. 

We have reviewed the cost analysis 

that is part of Entergy’s evaluation and 

have analyzed it for compliance with 

the Regional Haze Rule, and disagree 

with several aspects of the cost analysis 

and have made adjustments to it as 

necessary.51 First, we found that Entergy 

assumed in its dry FGD cost analysis 

that it will burn a coal corresponding to 

an uncontrolled SO2 emission rate of 2.0 

lb/MMBtu—far in excess of the sulfur 

level of the coals it has historically 

burned, presumably for future fuel 

flexibility. For the years 2009–2013, the 

maximum monthly SO2 emission rate 

for Unit 1 is 0.653 lbs/MMBtu and that 

for Unit 2 is 0.679 lbs/MMBtu. Thus, 

Entergy has costed SO2 dry scrubber 

systems for the White Bluff facility that 

are overdesigned compared to its 

historical needs. Such a system, being 

capable of a much higher level of sulfur 

removal than is currently required, has 

a correspondingly higher cost. Entergy 

selected its SO2 emission baseline by 

using ‘‘the average rate from 2001–2003, 

as reported by Entergy in their air 

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Federal Register / Vol. 80, No. 67 / Wednesday, April 8, 2015 / Proposed Rules 18971 

52Revised Bart Five Factor Analysis, White Bluff 

Steam Electric Station, Redfield, Arkansas (AFIN 

35–00110), dated October 2013, prepared by Trinity 

Consultants Inc. in conjunction with Entergy 

Services Inc., Page 5–5. 

53 70 FR 39167. 

54See ‘‘Technical Support Document for the SDA 

Control Cost Analysis for the Entergy White Bluff 

and Independence Facilities Arkansas Regional 

Haze Federal Implementation Plan (SO2 Cost 

TSD),’’ for a detailed discussion of how Entergy’s 

cost analysis was adjusted. 

55Entergy states capital suspense ‘‘is a 

distribution of overhead costs associated with 

administrators, engineers, and supervisors and 

includes function specific rates and A&G (Corporate 

Accounting) rates. Function specific capital 

suspense is dependent upon the personal hours 

allocated to a specific project for a time period. 

However, the percent of a total project that is 

dedicated to capital suspense is not a constant. 

Rather, it is dependent upon the yearly total capital 

expense budget and the budgeted capital spending 

for a specific function.’’ See Entergy Response to 

EPA Region 6 comments on Entergy White Bluff 

draft BART Report 06/10/13.Page 9. A copy of this 

document is found in the docket for this proposed 

rulemaking. 

56White Bluff Station Unit 1 & 2, Wet FGD—2.0 

lb/MMBtu, Order Of Magnitude Cost Estimate 

Summary. Attached as Attachment C to the 6/10/ 

13 Entergy Response to EPA comments on the 

White Bluff draft BART Report. Pdf page 29. Below 

is 

57Section 5.2 Post-Combustion Controls, Chapter 

1—Wet Scrubbers for Acid Gas, Table 1.3. 

58 6/10/13 Entergy Response to EPA comments on 

the White Bluff draft BART Report. Pdf page 11. 

This information was supplemented with a cut 

sheet from the 2011 S&L report via email from 

David Triplett on 2–10–15. Entergy declined to 

provide the full report, citing confidentiality 

concerns. 

59Section 5.2 Post-Combustion Controls, Chapter 

1—Wet Scrubbers for Acid Gas, Table 1.4. 

emission inventories,’’ 52 while selecting 

its annualized costs based on a 2.0 lb/ 

MMBtu coal. In calculating baseline 

emissions, the BART Guidelines assume 

the source in question is otherwise 

unchanged in the future, except for the 

addition of BART controls.53 Thus, we 

believe it is appropriate to adjust the 

cost analysis presented in Entergy’s 

report.54 Additionally, the cost estimate 

for dry FGD presented in Entergy’s 

report includes line items that have not 

been documented, appear to be already 

covered in other cost items, or do not 

appear to be valid costs under our 

Control Cost Manual methodology. This 

includes line items such as capital 

suspense,55 Entergy internal costs, and 

certain line items under balance of plant 

(BOP) costs. Please see our SO2 Cost 

TSD for more details concerning the 

adjustments we propose to make to the 

White Bluff dry FGD cost analysis. A 

summary of our adjusted cost analysis, 

which is based on 2013 dollars, is 

presented in the table below. 

TABLE 32—SUMMARY OF EPA DRY FGD COST ANALYSIS FOR WHITE BLUFF UNITS 1 AND 2 

Item White Bluff 

Unit 1 

White Bluff 

Unit 2 

Total Annualized Cost ............................................................................................................................. $31,981,230 $31,981,230 

Interest Rate (%) ..................................................................................................................................... 7 7 

Equipment Lifetime (years) ...................................................................................................................... 30 30 

Capital Recovery Factor (CRF) ............................................................................................................... 0 .0806 0 .0806 

SO2 Emission Rate (lbs/MMBtu) ............................................................................................................. 0 .65 0 .68 

Controlled SO2 Emission Rate (%) ......................................................................................................... 90 .81 91 .16 

SO2 Emission Baseline (tons) ................................................................................................................. 15,816 16,697 

SO2 Emission Reduction (tons) ............................................................................................................... 14,363 15,221 

Cost Effectiveness ($/ton) ....................................................................................................................... $2,227 $2,101 

Our Wet Scrubbing Cost Analysis for 

Entergy White Bluff: Entergy uses a 2012 

contractor wet FGD estimate for the 

White Bluff Units 1 and 2 as the starting 

point for its cost analysis.56 It then used 

multiplier approximations from our 

Control Cost Manual 57 to calculate the 

Total Capital Investment (TCI). Entergy 

then calculated the direct annual costs, 

using fixed and variable O&M costs 

from another 2011 contractor cost 

summary as a surrogate for the 

apparently unavailable direct annual 

costs from the 2012 estimate.58

Following this, Entergy calculated the 

indirect annual costs using additional 

multiplier approximations from our 

Control Cost Manual.59 Lastly, Entergy 

calculated the annualized capital cost in 

the usual manner by multiplying the 

TCI by the capital recovery factor. 

As with its dry FGD cost estimates, 

Entergy designed its wet FGD systems to 

burn coal corresponding to an 

uncontrolled SO2 emission rate of 2.0 

lb/MMBtu, which are overdesigned 

compared to its historical needs. Please 

see our SO2 Cost TSD for more details 

concerning the adjustments we propose 

to make to the White Bluff wet FGD cost 

analysis, which is similar to our dry 

FGD analysis. A summary of our 

adjusted cost analysis, which is based 

on 2013 dollars, is presented in the table 

below: 

TABLE 33—SUMMARY OF EPA WET FGD COST ANALYSIS FOR WHITE BLUFF UNITS 1 AND 2 

Item White Bluff 

Unit 1 

White Bluff 

Unit 2 

Total Annualized Cost ............................................................................................................................. $49,526,167 $49,526,167 

Interest Rate (%) ..................................................................................................................................... 7 7 

Equipment Lifetime (years) ...................................................................................................................... 30 30 

Capital Recovery Factor (CRF) ............................................................................................................... 0 .0806 0 .0806 

SO2 Emission Rate (lbs/MMBtu) ............................................................................................................. 0 .65 0 .68 

Controlled SO2 Emission Rate (%) ......................................................................................................... 93 .87 94 .11 

SO2 Emission Baseline (tons) ................................................................................................................. 15,816 16,697 

SO2 Emission Reduction (tons) ............................................................................................................... 14,847 15,713 

Cost Effectiveness ($/ton) ....................................................................................................................... $3,336 $3,152 

Entergy’s evaluation noted that the 

potential negative non-air quality 

environmental impacts are greater with 

wet FGD systems than dry FGD systems. 

Entergy noted that wet scrubbers require 

increased water use and generate large 

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18972 Federal Register / Vol. 80, No. 67 / Wednesday, April 8, 2015 / Proposed Rules 

volumes of wastewater and solid waste/ 

sludge that must be treated or stabilized 

before landfilling, placing additional 

burden on the wastewater treatment and 

solid waste management capabilities. 

We do not expect that water availability 

would affect the feasibility of a wet 

scrubber since the facility is not located 

in an exceptionally arid region. 

Additionally, the BART Guidelines 

provide that the fact that a control 

device creates liquid and solid waste 

that must be disposed of does not 

necessarily argue against selection of 

that technology as BART, particularly if 

the control device has been applied to 

similar facilities elsewhere (40 CFR part 

51, Appendix Y, section IV.D.4.i.2.). In 

cases where the facility can demonstrate 

that there are unusual circumstances 

there that would create greater problems 

than experienced elsewhere, this may 

provide a basis for the elimination of 

that control option as BART. But in this 

case, Entergy White Bluff has not 

indicated that there are any such 

unusual circumstances. Another 

potential negative energy and non-air 

quality environmental impact associated 

with wet FGD systems is the potential 

for increased power requirements and 

greater reagent usage compared to dry 

FGD. The costs associated with 

increased power requirements and 

greater reagent usage have already been 

factored into the cost analysis for the 

wet FGD system. 

Entergy assessed the visibility 

improvement associated with wet FGD 

and a dry FGD by modeling the SO2

emission rates associated with each 

control option using CALPUFF, and 

then comparing the visibility 

impairment associated with the baseline 

emission rates to the visibility 

impairment associated with the 

controlled emission rates as measured 

by the 98th percentile modeled 

visibility impact. The tables below 

compare the baseline (i.e., existing) 

visibility impacts with the visibility 

impacts associated with SO2 controls. 

TABLE 34—ENTERGY WHITE BLUFF UNIT 1: SUMMARY OF THE 98TH PERCENTILE VISIBILITY IMPACTS AND IMPROVEMENT

DUE TO SO2 CONTROLS

Class I area 

Visibility impact 

(Ddv) 

Visibility 

improvement over 

baseline 

(dv) 

Incremental 

visibility 

improvement 

of wet FGD 

vs. dry 

scrubber 

Baseline Dry 

scrubber Wet FGD Dry 

scrubber Wet FGD 

Caney Creek .................................................................................... 1.628 0.815 0.794 0.813 0.834 0.021 

Upper Buffalo ................................................................................... 1.140 0.378 0.350 0.762 0.790 0.028 

Hercules-Glades .............................................................................. 1.041 0.358 0.360 0.683 0.681 ¥0.002 

Mingo ............................................................................................... 0.887 0.267 0.271 0.620 0.616 ¥0.004 

Total .......................................................................................... 4.696 1.818 1.775 2.878 2.921 0.043 

TABLE 35—ENTERGY WHITE BLUFF UNIT 2: SUMMARY OF THE 98TH PERCENTILE VISIBILITY IMPACTS AND IMPROVEMENT

DUE TO SO2 CONTROLS

Class I area 

Visibility impact 

(Ddv) 

Visibility 

improvement over 

baseline 

(dv) 

Incremental 

visibility 

improvement 

of wet FGD 

vs. dry 

scrubber 

Baseline Dry 

scrubber Wet FGD Dry 

scrubber Wet FGD 

Caney Creek .................................................................................... 1.695 0.941 0.920 0.754 0.775 0.021 

Upper Buffalo ................................................................................... 1.185 0.418 0.405 0.767 0.780 0.013 

Hercules-Glades .............................................................................. 1.061 0.415 0.416 0.645 0.644 ¥0.001 

Mingo ............................................................................................... 0.903 0.310 0.315 0.593 0.588 ¥0.005 

Total .......................................................................................... 4.844 2.084 2.056 2.759 2.787 0.028 

The tables above show that the 

installation and operation of SO2

controls is projected to result in 

considerable visibility improvement 

over the baseline at the four impacted 

Class I areas. Installation and operation 

of dry FGD is projected to result in 

visibility improvement of up to 0.813 dv 

at any single Class I area for Unit 1 and 

0.767 dv for Unit 2, based on the 98th 

percentile visibility impairment. 

Installation and operation of wet FGD is 

projected to result in visibility 

improvement of up to 0.834 dv at any 

single Class I area for Unit 1 and 0.780 

dv for Unit 2. The installation and 

operation of wet FGD is projected to 

result in very minimal incremental 

visibility benefit over dry FGD at Caney 

Creek and Upper Buffalo, while at 

Hercules-Glades and Mingo, it is 

projected to result in slightly less 

visibility improvement than dry FGD 

(i.e., a slight visibility disbenefit). 

Our Proposed SO2 BART 

Determination: Based on our cost 

analysis, a dry FGD system is estimated 

to have an average cost-effectiveness of 

$2,227 per ton of SO2 removed for Unit 

1 and $2,101 per ton of SO2 removed for 

Unit 2. By comparison, a wet FGD 

system is estimated to have an average 

cost-effectiveness of $3,336 per ton of 

SO2 removed for Unit 1 and $3,152 per 

ton of SO2 removed for Unit 2. 

Therefore, considering the five BART 

factors and the slight visibility benefit at 

Caney Creek and Upper Buffalo and 

slight disbenefit at Hercules-Glades and 

Mingo of wet FGD over dry FGD, we are 

proposing to determine that SO2 BART 

for White Bluff Units 1 and 2 is an 

emission limit of 0.06 lb/MMBtu on a 30 

boiler-operating-day rolling average 

based on the installation and operation 

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Federal Register / Vol. 80, No. 67 / Wednesday, April 8, 2015 / Proposed Rules 18973 

60 40 CFR 51.308(e)(1)(iv). 61See ‘‘Revised BART Five Factor Analysis White 

Bluff Steam Electric Station Redfield, Arkansas 

(AFIN 35–00110),’’ dated October 2013, prepared by 

Trinity Consultants Inc. in conjunction with 

Entergy Services Inc. Entergy’s NOX control cost 

estimates are found in Appendix A of the BART 

analysis and Appendix E contains the ‘‘NOX

Control Technology Cost and Performance Study’’ 

prepared by Sargent & Lundy on behalf of Entergy. 

A copy of the BART analysis and all appendices are 

found in the docket for our proposed rulemaking. 

62See the spreadsheet titled ‘‘EPA NOX Control 

Cost revisions_White Bluff.’’ A copy of this 

spreadsheet is found in the docket for our proposed 

rulemaking. 

of dry FGD or another control 

technology that achieves that level of 

control. We are proposing to require 

compliance with this requirement no 

later than 5 years from the effective date 

of the final rule, consistent with the 

regional haze regulations.60 We are 

proposing to require that compliance be 

demonstrated using the unit’s existing 

CEMS. We are also proposing regulatory 

text that includes monitoring, reporting, 

and recordkeeping requirements 

associated with this emission limit. 

b. Proposed NOX BART Analysis and 

Determination for Units 1 and 2. 

Entergy identified all available control 

technologies, eliminated options that 

are not technically feasible, and 

evaluated the control effectiveness of 

the remaining NOX control options for 

Units 1 and 2. Each technically feasible 

control option was then evaluated in 

terms of a five factor BART analysis. 

For NOX BART, Entergy’s BART 

evaluation considered both combustion 

and post-combustion controls. The 

combustion controls evaluated 

consisted of FGR, separated overfire air 

(SOFA), and LNB. The post-combustion 

controls evaluated consisted of SCR and 

SNCR. Entergy found that FGR 

technology is not currently offered by 

vendors for coal-fired units. Therefore, 

it did not consider FGR to be a 

technically feasible control technology 

for the coal-fired White Bluff Units 1 

and 2. All other available NOX control 

options were identified as technically 

feasible. Entergy evaluated three control 

scenarios: LNB with SOFA (LNB/

SOFA); the combination of LNB, SOFA, 

and SNCR (LNB/SOFA + SNCR); and 

the combination of LNB, SOFA, and 

SCR (LNB/SOFA + SCR). According to 

Entergy, the baseline NOX emission rate 

is approximately 0.31 lb/MMBtu for 

Unit 1 and 0.36 lb/MMBtu for Unit 2. 

Entergy relied on literature control 

ranges and efficiencies, as well as 

vendor estimates to arrive at the 

expected controlled emission rates for 

White Bluff Units 1 and 2. Based on 

contractor evaluations, SOFA is 

expected to achieve a controlled NOX

emission rate of 0.28–0.32 lb/MMBtu for 

Units 1 and 2. When LNB is combined 

with SOFA, it is expected to achieve a 

controlled NOX emission rate of 0.15 lb/ 

MMBtu. When SNCR is combined with 

LNB and SOFA, it is expected to 

achieve a controlled NOX emission rate 

of 0.13 lb/MMBtu for Units 1 and 2, and 

when SCR is combined with LNB and 

SOFA it is expected to achieve a 

controlled NOX emission rate of 0.055 

lb/MMBtu. 

Entergy estimated the capital costs, 

operating costs, and average costeffectiveness of LNB, SOFA, SNCR, and 

SCR. The capital and operating costs of 

controls were based on vendor estimates 

specific to Units 1 and 2. The total 

annual costs were estimated by 

annualizing the capital cost of controls 

over a 30-year period and then adding 

to this value the annual operating cost 

of controls. Entergy determined the 

annual emissions reductions associated 

with each NOX control option by 

subtracting the estimated controlled 

annual emission rate from the baseline 

annual emission rate. The baseline 

annual emission rate is the average rate 

as reported by Entergy in the 2009–2011 

air emission inventories. The average 

cost-effectiveness of controls was 

calculated by dividing the total annual 

cost of each control option by the 

estimated annual NOX emissions 

reductions. 

We note that Entergy’s cost estimate 

for each NOX control option includes 

capital suspense in the total capital 

costs.61 A capital cost suspense of 

$955,673 for both units for LNB/SOFA; 

$1,745,429 for both units for LNB/SOFA 

+ SNCR; and $20,552,528 for Unit 1 and 

$21,332,288 for Unit 2 for LNB/SOFA + 

SCR is included in the capital costs. As 

discussed above, Entergy described 

capital suspense as a distribution of 

overhead costs associated with 

administrators, engineers, and 

supervisors that includes function 

specific rates and corporate accounting 

rates. However, we do not believe 

capital suspense should be included in 

the cost analysis because those costs 

have not been documented by Entergy 

and do not appear to be valid costs 

under the Control Cost Manual 

methodology. We have adjusted the cost 

estimate of NOX controls by subtracting 

the capital suspense line item from the 

capital costs.62 Based on our adjustment 

of Entergy’s cost estimate, the average 

cost-effectiveness of LNB/SOFA is 

estimated to be $350 per ton of NOX

removed for Unit 1 and $340 per ton of 

NOX removed for Unit 2, while the 

average cost-effectiveness of LNB/SOFA 

+ SNCR is estimated to be $1,758 per 

ton of NOX removed for Unit 1 and 

$1,449 per ton of NOX removed for Unit 

2 (see table below). The average costeffectiveness of LNB/SOFA + SCR is 

estimated to be $3,552 per ton of NOX

removed for Unit 1 and $2,749 per ton 

of NOX removed for Unit 2. 

TABLE 36—SUMMARY OF NOX CONTROL COSTS FOR WHITE BLUFF UNITS 1 AND 2 

Control technology 

Baseline 

emission rate 

(NOX tpy) 

Controlled 

emission level 

(lb/MMBtu) 

Controlled 

emission rate 

(tpy) 

Annual 

emissions 

reduction 

(NOX tpy) 

Capital cost 

($) 

Total annual 

cost 

($/yr) 

Average cost 

effectiveness 

($/ton) 

Incremental costeffectiveness 

($/ton) 

Unit 1 (SN–01) 

LNB/SOFA ................... 7,249 0.15 4,145 3,104 9,505,533 1,085,904 350 ..............................

LNB/SOFA/SNCR ....... 7,249 0.13 3,593 3,657 19,625,896 6,430,580 1,758 9,665 

LNB/SOFA/SCR .......... 7,249 0.055 1,520 5,729 209,776,610 20,349,142 3,552 6,717 

Unit 2 (SN–02) 

LNB/SOFA ................... 8,185 0.15 4,060 4,125 13,532,533 1,403,376 340 ..............................

LNB/SOFA/SNCR ....... 8,185 0.13 3,519 4,666 23,652,896 6,759,102 1,449 9,900 

LNB/SOFA/SCR .......... 8,185 0.055 1,489 6,697 185,415,610 18,407,977 2,749 5,736 

Entergy did not identify any energy or 

non-air quality environmental impacts 

associated with the use of LNB/SOFA. 

As for SCR and SNCR, we are not aware 

of any unusual circumstances at the 

facility that could create non-air quality 

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18974 Federal Register / Vol. 80, No. 67 / Wednesday, April 8, 2015 / Proposed Rules 

environmental impacts associated with 

the operation of these controls greater 

than experienced elsewhere and that 

may therefore provide a basis for their 

elimination as BART (40 CFR part 51, 

Appendix Y, section IV.D.4.i.2.). 

Therefore, we do not believe there are 

any energy or non-air quality 

environmental impacts associated with 

the operation of NOX controls at Entergy 

White Bluff Units 1 and 2 that would 

affect our proposed BART 

determination. 

Consideration of the presence of 

existing pollution control technology at 

each source is reflected in the BART 

analysis in two ways: First, in the 

consideration of available control 

technologies, and second, in the 

development of baseline emission rates 

for use in cost calculations and visibility 

modeling. Other than the installation of 

a neural net system in 2006 to optimize 

boiler combustion efficiency that 

resulted in lower NOX emissions 

compared to the 2001–2003 baseline, 

White Bluff Units 1 and 2 have no 

existing NOX pollution control 

technology. The lower NOX emissions 

achieved as a co-benefit of installing the 

neural net system is reflected in the 

analysis by the use of 2009–2011 as the 

baseline for the NOX BART analysis. 

Entergy assessed the visibility 

improvement associated with NOX

controls by modeling the NOX emission 

rates associated with each control 

option using CALPUFF, and then 

comparing the visibility impairment 

associated with the baseline emission 

rate to the visibility impairment 

associated with the controlled emission 

rates as measured by the 98th percentile 

modeled visibility impact. The tables 

below show a comparison of the 

baseline (i.e., existing) visibility impacts 

and the visibility impacts associated 

with NOX controls. 

TABLE 37—ENTERGY WHITE BLUFF UNIT 1: SUMMARY OF THE 98TH PERCENTILE VISIBILITY IMPACTS AND IMPROVEMENT

DUE TO NOX CONTROLS

Class I area 

Baseline visibility impact 

(Ddv) 

LNB/SOFA LNB/SOFA + SNCR LNB/SOFA + SCR 

Visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Caney Creek ................ 1.628 1.462 0.166 1.428 0.2 1.359 0.269 

Upper Buffalo ............... 1.140 1.039 0.101 1.029 0.111 0.991 0.149 

Hercules-Glades .......... 1.041 0.865 0.176 0.844 0.197 0.832 0.209 

Mingo ........................... 0.887 0.849 0.038 0.842 0.045 0.817 0.07 

Cumulative Visibility Improvement (Ddv) ....... ........................ ........................ 0.481 ........................ 0.553 ........................ 0.697 

TABLE 38—ENTERGY WHITE BLUFF UNIT 2: SUMMARY OF THE 98TH PERCENTILE VISIBILITY IMPACTS AND IMPROVEMENT

DUE TO NOX CONTROLS

Class I area 

Baseline visibility impact 

(Ddv) 

LNB/SOFA LNB/SOFA + SNCR LNB/SOFA + SCR 

Visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Caney Creek ................ 1.695 1.47 0.225 1.437 0.258 1.368 0.327 

Upper Buffalo ............... 1.185 1.046 0.139 1.035 0.15 0.997 0.188 

Hercules-Glades .......... 1.060 0.870 0.190 0.849 0.211 0.838 0.222 

Mingo ........................... 0.903 0.856 0.047 0.849 0.054 0.823 0.08 

Cumulative Visibility Improvement (Ddv) ....... ........................ ........................ 0.601 ........................ 0.673 ........................ 0.817 

The tables above show that the 

installation and operation of LNB/SOFA 

is projected to result in visibility 

improvement of up to 0.176 dv at any 

single Class I area for Unit 1 and 0.225 

dv for Unit 2, based on the 98th 

percentile visibility impairment. The 

installation and operation of LNB/SOFA 

+ SNCR is projected to result in 

visibility improvement of up to 0.2 dv 

in any single Class I area for Unit 1 and 

0.258 dv for Unit 2. The installation and 

operation of LNB/SOFA + SCR is 

projected to result in visibility 

improvement of up to 0.269 dv in any 

single Class I area for Unit 1 and 0.327 

dv for Unit 2. The combination of LNB/ 

SOFA + SNCR would result in minimal 

incremental visibility benefit over LNB/ 

SOFA at all affected Class I areas for 

both units. The combination of LNB/

SOFA + SCR at Unit 1 would result in 

incremental visibility benefit over LNB/ 

SOFA + SNCR of 0.069 dv at Caney 

Creek; 0.038 dv at Upper Buffalo; 0.012 

dv at Hercules-Glades; and 0.025 dv at 

Mingo. The combination of LNB/SOFA 

+ SCR at Unit 2 would result in 

incremental visibility benefit over LNB/ 

SOFA + SNCR of 0.069 dv of at Caney 

Creek; 0.038 dv at Upper Buffalo; 0.011 

dv at Hercules-Glades; and 0.026 dv at 

Mingo. 

Our Proposed NOX BART 

Determination for Units 1 and 2: Taking 

into consideration the five factors, we 

propose to determine that BART for 

White Bluff Units 1 and 2 is an emission 

limit of 0.15 lb/MMBtu on a 30 boileroperating-day rolling average based on 

the installation and operation of LNB/

SOFA. The operation of LNB/SOFA is 

projected to result in visibility 

improvement ranging from 0.038 to 

0.176 dv for Unit 1 and 0.047 to 0.225 

dv for Unit 2 at each of the affected 

Class I areas (98th percentile basis). 

Based on our adjustments to the cost 

analysis included in Entergy’s 

evaluation, the operation of LNB/SOFA 

is estimated to have an average costeffectiveness of $350 per ton of NOX

removed for Unit 1 and $340 per ton of 

NOX removed for Unit 2, which we 

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Federal Register / Vol. 80, No. 67 / Wednesday, April 8, 2015 / Proposed Rules 18975 

63 40 CFR 51.308(e)(1)(iv). 

64See ADEQ Operating Air Permit No. 0263– 

AOP–R7, Section IV, Specific Condition No. 32. 

65See ‘‘Revised BART Five Factor Analysis Lake 

Catherine Steam Electric Station Malvern, Arkansas 

(AFIN 30–00011),’’ dated May 2014, prepared by 

Trinity Consultants Inc. in conjunction with 

Entergy Services Inc. A copy of this BART analysis 

is found in the docket for our proposed rulemaking. 

66See ‘‘Revised BART Five Factor Analysis Lake 

Catherine Steam Electric Station Malvern, Arkansas 

(AFIN 30–00011),’’ dated May 2014, prepared by 

Trinity Consultants Inc. in conjunction with 

Entergy Services Inc. A copy of this BART analysis 

is found in the docket for our proposed rulemaking. 

67As stated in the regulatory text for this 

proposed rulemaking, if Lake Catherine Unit 4 

decides to begin burning fuel oil, we will complete 

a BART analysis for each pollutant for the fuel oil 

firing scenario after receiving notification that the 

source will begin burning fuel oil and we will 

revise the FIP as necessary in accordance with 

Regional Haze Rule requirements, including the 

BART provisions in 40 CFR 51.308(e). 

Alternatively, if the State submits a SIP revision 

with BART determinations for the fuel oil firing 

scenario, we will take action on the State’s 

submittal. 

consider to be very cost-effective. The 

operation of LNB/SOFA + SNCR is 

estimated to have an average costeffectiveness of $1,758 per ton of NOX

removed for Unit 1 and $1,449 per ton 

of NOX removed for Unit 2. The 

incremental cost-effectiveness of LNB/

SOFA + SNCR compared to LNB/SOFA 

is $9,665 per ton of NOX removed for 

Unit 1 and $9,900 per ton of NOX

removed for Unit 2.While the average 

cost-effectiveness of LNB/SOFA + SNCR 

is still very cost effective, the 

incremental visibility benefit of LNB/

SOFA + SNCR compared to LNB/SOFA 

is estimated to range from 0.007 to 0.034 

dv for Unit 1 and 0.007 to 0.033 dv for 

Unit 2 at each of the affected Class I 

areas. We do not believe this small 

amount of incremental visibility benefit 

justifies the incremental cost of LNB/

SOFA + SNCR. 

The operation of LNB/SOFA + SCR at 

Unit 1 is projected to result in up to 

0.269 dv visibility improvement over 

the baseline at any single Class I area, 

and based on our adjustments to 

Entergy’s cost analysis, has an average 

cost-effectiveness of $3,552 per ton of 

NOX removed. LNB/SOFA + SCR at 

Unit 1 is projected to result in up to 

0.069 dv of incremental visibility 

improvement over LNB/SOFA + SNCR 

at any single Class I area, and its 

incremental cost-effectiveness is 

estimated to be $6,717 per ton of NOX

removed. The operation of LNB/SOFA + 

SCR at Unit 2 is projected to result in 

up to 0.327 dv visibility improvement 

over the baseline at any single Class I 

area, and has an average costeffectiveness of $2,749 per ton of NOX

removed. LNB/SOFA + SCR at Unit 2 is 

also projected to result in up to 0.069 dv 

of incremental visibility improvement 

over LNB/SOFA + SNCR at any single 

Class I area, and its incremental costeffectiveness is estimated to be $5,736 

per ton of NOX removed. Although the 

average and incremental costeffectiveness of LNB/SOFA + SCR at 

Units 1 and 2 is still within the range 

of what we consider to be cost-effective, 

we believe the incremental visibility 

benefit over LNB/SOFA + SNCR of up 

to 0.069 dv at a single Class I area is 

relatively small considering the 

incremental cost-effectiveness of $6,717 

per ton of NOX removed for Unit 1 and 

$5,736 per ton of NOX removed for Unit 

2. Therefore, we are proposing to 

determine that NOX BART for White 

Bluff Units 1 and 2 is an emission limit 

of 0.15 lb/MMBtu on a 30 boileroperating-day rolling average based on 

the installation and operation of LNB/

SOFA. We are proposing to require 

compliance with this requirement no 

later than 3 years from the effective date 

of the final rule, consistent with our 

regional haze regulations.63 We are 

proposing to require that compliance be 

demonstrated using the unit’s existing 

CEMS. We are also proposing regulatory 

text that includes monitoring, reporting, 

and recordkeeping requirements 

associated with this emission limit. 

c. Proposed BART Analysis and 

Determination for the Auxiliary Boiler. 

As shown in the table above, the 

baseline visibility impairment 

attributable to the Auxiliary Boiler is 

0.01 Ddv at Caney Creek and even lower 

at the other modeled Class I areas (98th 

percentile basis). The BART Rule 

provides: 

‘‘Consistent with the CAA and the 

implementing regulations, States can adopt a 

more streamlined approach to making BART 

determinations where appropriate. Although 

BART determinations are based on the 

totality of circumstances in a given situation, 

such as the distance of the source from a 

Class I area, the type and amount of pollutant 

at issue, and the availability and cost of 

controls, it is clear that in some situations, 

one or more factors will clearly suggest an 

outcome. Thus, for example, a State need not 

undertake an exhaustive analysis of a 

source’s impact on visibility resulting from 

relatively minor emissions of a pollutant 

where it is clear that controls would be costly 

and any improvements in visibility resulting 

from reductions in emissions of that 

pollutant would be negligible.’’ (70 FR 

39116). 

Given the very small baseline 

visibility impacts from the Auxiliary 

Boiler, we believe it is appropriate to 

take a streamlined approach for 

determining BART in this case. Because 

of the very low baseline visibility 

impacts from the Auxiliary Boiler at 

each modeled Class I area, we believe 

that the visibility improvement that 

could be achieved through the 

installation and operation of controls 

would be negligible, such that the cost 

of those controls could not be justified. 

Therefore, we are proposing that the 

existing emission limits satisfy BART 

for SO2, NOX, and PM. We are 

proposing that the existing emission 

limit of 105.2 lb/hr is BART for SO2, the 

existing emission limit of 32.2 lb/hr is 

BART for NOX, and the existing 

emission limit of 4.5 lb/hr is BART for 

PM for the Auxiliary Boiler.64 Because 

we are proposing a BART emission limit 

that represents current operations and 

no control equipment installation is 

necessary, we are proposing that these 

emissions limitations be complied with 

for BART purposes from the date of 

effectiveness of the finalized action. 

5. Entergy Lake Catherine Plant 

The Entergy Lake Catherine Unit 4 is 

subject to BART. We previously 

disapproved Arkansas’ BART 

determinations for NOX for the natural 

gas firing scenario and for SO2, NOX, 

and PM for the fuel oil firing scenario 

in our March 12, 2012 final action (77 

FR 14604). Lake Catherine Unit 4 is a 

tangentially-fired boiler with a nominal 

net power rating of 558 MW and a 

nominal heat input capacity of 5,850 

MMBtu/hr. The boiler is permitted to 

burn natural gas and No. 6 fuel oil. 

Entergy hired a consultant to conduct a 

BART five-factor analysis for Lake 

Catherine Unit 4 (Entergy’s BART 

analysis).65 Entergy’s analysis states that 

Lake Catherine Unit 4 has not burned 

fuel oil since prior to the 2001–2003 

baseline period, currently does not burn 

fuel oil, and that Entergy does not 

project to burn fuel oil at the unit in the 

foreseeable future. Therefore, Entergy’s 

analysis 66 addresses BART for the 

natural gas firing scenario and does not 

consider emissions from fuel oil firing. 

Entergy’s analysis states that if 

conditions change such that it becomes 

economic to burn fuel oil, the facility 

will submit a BART five factor analysis 

for the fuel oil firing scenario to the 

State to be submitted to us as a SIP 

revision, and that fuel oil combustion 

will not take place until final EPA 

approval of BART for the fuel oil firing 

scenario. We concur with this 

commitment.67 Before fuel oil firing is 

allowed to take place at Lake Catherine 

Unit 4, revised BART determinations 

must be promulgated for all pollutants 

for the fuel oil firing scenario through a 

FIP and/or through our action upon and 

approval of revised BART 

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18976 Federal Register / Vol. 80, No. 67 / Wednesday, April 8, 2015 / Proposed Rules 

68See ‘‘NOX Control Technology Cost and 

Performance Study,’’ Final Report, Rev. 4, dated 

May 16, 2013, prepared by Sargent & Lundy. A copy 

of this report is included as Attachment D to 

Entergy’s BART Five Factor Analysis for Lake 

Catherine Unit 4, which can be found in the docket 

for this proposed rulemaking. 

69The capital and operating cost estimates for 

each control option are found in Appendix A to 

Entergy’s BART Five Factor Analysis for Lake 

Catherine Unit 4, which can be found in the docket 

for this proposed rulemaking. 

determinations submitted by the State 

as a SIP revision. We approved 

Arkansas’ BART determinations for 

Lake Catherine Unit 4 for SO2 and PM 

for the natural gas firing scenario in our 

March 12, 2012 final action (77 FR 

14604). Therefore, the only BART 

determination that remains to be 

addressed for the natural gas firing 

scenario is NOX BART. 

The table below summarizes the 

baseline emission rates for Lake 

Catherine Unit 4. The SO2 and NOX

baseline emission rates are the highest 

actual 24-hour emission rates based on 

CAMD data from 2001–2003 for natural 

gas burning. The PM10 emission rate 

reflects the breakdown of the filterable 

and condensable PM10 determined from 

AP–42 Table 1.4–2 Combustion of 

Natural Gas. 

TABLE 39—ENTERGY LAKE CATHERINE UNIT 4 (NATURAL GAS FIRING): BASELINE MAXIMUM 24-HOUR EMISSION RATES

Source SO2

(lb/hr) 

NOX

(lb/hr) 

Total 

PM10

(lb/hr) 

SO4

(lb/hr) 

PMc 

(lb/hr) 

PMf 

(lb/hr) 

SOA 

(lb/hr) 

EC 

(lb/hr) 

Unit 4 ................................................................ 3.1 2,456.4 44.3 1.5 0.0 0.0 31.8 11.0 

Entergy modeled the baseline 

emission rates using the CALPUFF 

dispersion model to determine the 

baseline visibility impairment 

attributable to Lake Catherine Unit 4 at 

the four Class I areas impacted by 

emissions from BART sources in 

Arkansas. These Class I areas are the 

Caney Creek Wilderness Area, Upper 

Buffalo Wilderness Area, HerculesGlades Wilderness Area, and Mingo 

National Wildlife Refuge. The baseline 

(i.e., existing) visibility impairment 

attributable to the source at each Class 

I area is summarized in the table below. 

TABLE 40—BASELINE VISIBILITY IMPAIRMENT ATTRIBUTABLE TO ENTERGY LAKE CATHERINE UNIT 4—NATURAL GAS

FIRING

[2001–2003] 

Unit Caney Creek Upper Buffalo HerculesGlades Mingo 

Unit 4 (SN–01): 

Maximum (Ddv) ......................................................................................... 3.480 2.044 1.016 0.763 

98th Percentile (Ddv) ................................................................................ 1.371 0.489 0.387 0.429 

a. Proposed NOX BART Analysis and 

Determination. Entergy identified all 

available control technologies, 

eliminated options that are not 

technically feasible, and evaluated the 

control effectiveness of the remaining 

control options for Lake Catherine Unit 

4. Each technically feasible control 

option was then evaluated in terms of a 

five factor BART analysis. 

For NOX BART, the Entergy BART 

analysis evaluated both combustion and 

post-combustion controls. The 

combustion controls evaluated 

consisted of Burners out of Service 

(BOOS), FGR, SOFA, and LNB. The 

post-combustion controls evaluated 

consisted of SCR and SNCR. In its 

evaluation, Entergy noted that SNCR 

combined with LNB/SOFA was being 

evaluated as a control option for Lake 

Catherine Unit 4, but SNCR is not 

adaptable to all gas-fired boilers. All 

other available NOX control options 

were identified as technically feasible. 

The baseline NOX emission rate 

Entergy used in the analysis is 0.48 lb/ 

MMBtu. Entergy relied on literature 

control ranges and efficiencies and 

vendor estimates in arriving at the 

expected controlled emission rates for 

Lake Catherine Unit 4. BOOS is a staged 

combustion technique in which fuel is 

introduced through operational burners 

in the lower furnace zone to create fuelrich conditions, while not introducing 

fuel to other burners. The removal of 

fuel from certain zones reduces the 

temperature and the production of 

thermal NOX. Additional air is then 

supplied to the non-operational burners 

to complete combustion. Based on a 

NOX control study developed by Sargent 

& Lundy on behalf of Entergy (Sargent 

& Lundy NOX Control Study), the 

estimated controlled NOX level for Unit 

4 while operating BOOS at maximum 

load is 0.24 lb/MMBtu.68 Based on the 

level of control expected to be achieved 

by BOOS and the expected utilization 

levels at Unit 4, Entergy believes that an 

emission rate of 0.22 lb/MMBtu is 

achievable on a 30 boiler-operating-day 

rolling average basis. Entergy estimated 

the controlled NOX level for Unit 4 

operating with FGR to be 0.19 lb/

MMBtu. Entergy estimated that when 

operated without additional controls, 

SOFA results in NOX emissions for gas 

fired boilers of 0.2—0.4 lb/MMBtu. 

When operated without additional 

controls, the estimated controlled NOX

emission rate for gas fired boilers 

operating with LNB is approximately 

0.25 lb/MMBtu, and when combined 

with SOFA, the estimated controlled 

NOX emission rate is 0.19 lb/MMBtu. 

When SNCR is combined with LNB/

SOFA it is estimated that the controlled 

NOX emission rate is 0.14 lb/MMBtu, 

and when SCR is combined with LNB/ 

SOFA it is estimated that the controlled 

NOX emission rate is 0.03 lb/MMBtu. 

In its evaluation, Entergy noted that 

the Sargent & Lundy NOX Control Study 

estimated that FGR would result in the 

same controlled emission level as LNB/ 

SOFA, but at a higher cost. Therefore, 

Entergy’s evaluation did not further 

consider FGR. The remainder of the 

analysis focused on four control 

scenarios: (1) BOOS; (2) LNB/SOFA; (3) 

the combination of LNB/SOFA + SNCR; 

and (4) the combination of LNB/SOFA 

+ SCR. Entergy estimated the capital 

costs, operating costs, and costeffectiveness of these four control 

scenarios based on cost estimates 

provided by Sargent & Lundy.69 The 

capital cost of each NOX control was 

annualized over a 30-year period and 

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70Based on Entergy’s evaluation, it is anticipated 

that BOOS can be implemented at Unit 4 without 

any capital expenditures, but there are one-time 

costs associated with BOOS implementation. To 

provide an ‘‘apples-to-apples’’ comparison with the 

other NOX control options, these one-time 

additional costs were treated as if they were a 

capital expenditure in calculating the cost 

effectiveness. 

71The annual heat input reflecting a 10% annual 

capacity factor is 5,124,600 MMBtu/yr (5,850 

MMBtu/hr * 8760 hrs/yr * 10% = 5,124,600 

MMBtu/yr). 

72 40 CFR Appendix Y to Part 51—Guidelines for 

BART Determinations Under the Regional Haze 

Rule, section IV.D.4.d. 

73See ‘‘Revised BART Five Factor Analysis Lake 

Catherine Steam Electric Station Malvern, Arkansas 

(AFIN 30–00011),’’ dated May 2014, prepared by 

Trinity Consultants Inc. in conjunction with 

Entergy Services Inc. Entergy’s NOX control cost 

estimates are found in Appendices A and D of the 

BART analysis. A copy of the BART analysis, 

including the appendices, is found in the docket for 

our proposed rulemaking. 

74See the spreadsheet titled ‘‘EPA NOX Control 

Cost revisions_Lake Catherine.xlsx.’’ A copy of this 

spreadsheet is found in the docket for our proposed 

rulemaking. 

then added to the annual operating costs 

to obtain the total annualized costs.70

The annual emissions reductions 

associated with each NOX control 

option were determined by subtracting 

the estimated controlled annual 

emission rate from the baseline annual 

emission rate. The baseline annual 

emission rate was calculated using the 

baseline emission level of 0.48 lb/

MMBtu and an annual heat input 

reflecting a 10% capacity factor.71

Entergy assumed a 10% capacity factor 

because the annual capacity factor of the 

unit during each of the years from 2003– 

2011 was under 10%, and Entergy 

anticipates that future annual capacity 

factors are expected to be comparable to 

those experienced by the unit in 2003– 

2011. We agree that assuming a 10% 

capacity factor is consistent with the 

BART Guidelines, which provide that 

the baseline emission rate should 

represent a realistic depiction of 

anticipated annual emissions for the 

source.72

The controlled annual emission rates 

were based on the lb/MMBtu levels 

believed to be achievable from the 

control technologies multiplied by the 

annual heat input. The average costeffectiveness of NOX controls was 

calculated by dividing the total annual 

cost of each control option by the 

estimated annual NOX emissions 

reductions. The incremental costeffectiveness of controls when 

compared to BOOS was also calculated. 

The table below summarizes the cost of 

NOX controls for Lake Catherine Unit 4. 

Based on Entergy’s analysis, the average 

cost-effectiveness of BOOS at a NOX

controlled emission rate of 0.22 lb/

MMBtu is estimated to be $138 per ton 

of NOX removed, while the average costeffectiveness of LNB/SOFA is estimated 

to be $1,596 per ton of NOX removed. 

The average cost-effectiveness of a 

combination of LNB/SOFA + SNCR is 

estimated to be $3,827 per ton of NOX

removed, while the average costeffectiveness of the combination of 

LNB/SOFA + SCR is estimated to be 

$6,223 per ton of NOX removed. 

We disagree with two aspects of 

Entergy’s cost analysis.73 First, Entergy’s 

cost estimates for LNB/SOFA, LNB/

SOFA + SNCR, and LNB/SOFA + SCR 

include capital suspense as a line item 

under the capital costs. However, we do 

not believe capital suspense should be 

included in the cost analysis because 

those costs have not been documented 

by Entergy and do not appear to be valid 

costs under the Control Cost Manual 

methodology. Second, Entergy’s cost 

estimates for these controls also include 

Allowance for Funds Used During 

Construction (AFUDC). AFUDC is the 

cost of capital that is incurred to finance 

a project during the construction period, 

and is not a valid cost under the 

methodology in the EPA Control Cost 

Manual. The exclusion of capital 

suspense and AFUDC from the capital 

cost estimates results in lower total 

annual costs and improved average costeffectiveness (i.e., less dollars per NOX

ton removed) for the aforementioned 

NOX control options compared to what 

is estimated in Entergy’s evaluation. In 

the table below, we have revised the 

cost-effectiveness of NOX controls for 

Unit 4 to reflect our adjustments to 

Entergy’s cost estimates.74

TABLE 41—SUMMARY OF NOX CONTROL COSTS FOR LAKE CATHERINE UNIT 4 

[Natural gas firing] 

Baseline 

emission rate 

(NOX tpy) 

Controlled 

emission 

level 

(lb/MMBtu) 

Controlled 

emission rate 

(NOX tpy) 

Annual 

emissions 

reduction 

(NOX tpy) 

Capital cost 

($) 

Total annual 

cost 

($/yr) 

Average cost 

effectiveness 

($/ton) 

Incremental 

cost 

effectiveness 

($/ton) 

BOOS ................................................ 1,236 0.22 564 673 893,000 92,964 138 

LNB/SOFA ......................................... 1,236 0.19 495 742 10,508,863 1,075,905 1,450 14,246 

LNB/SOFA/SNCR ............................. 1,236 0.14 371 865 26,015,863 3,047,525 3,523 16,029 

LNB/SOFA/SCR ................................ 1,236 0.03 77 1159 70,370,863 6,506,935 5,614 11,767 

Entergy did not identify any energy or 

non-air quality environmental impacts 

associated with the use of BOOS, LNB, 

or SOFA. As for SCR and SNCR, we are 

not aware of any unusual circumstances 

at the facility that could create non-air 

quality environmental impacts 

associated with the operation of these 

controls greater than experienced 

elsewhere and that may therefore 

provide a basis for their elimination as 

BART (40 CFR part 51, Appendix Y, 

section IV.D.4.i.2.). Therefore, we do not 

believe there are any energy or non-air 

quality environmental impacts 

associated with the operation of NOX

controls at Entergy Lake Catherine Unit 

4 that would affect our proposed BART 

determination. 

Lake Catherine Unit 4 is not currently 

equipped with any NOX pollution 

control equipment. The baseline 

emission rates used in the cost 

calculations and visibility modeling 

reflects this. 

Entergy assessed the visibility 

improvement associated with NOX

controls by modeling the NOX emission 

rates associated with each control 

option using CALPUFF, and then 

comparing the visibility impairment 

associated with the baseline emission 

rate to the visibility impairment 

associated with the controlled emission 

rates as measured by the 98th percentile 

modeled visibility impact. The table 

below shows a comparison of the 

baseline (i.e., existing) visibility impacts 

and the visibility impacts associated 

with NOX controls. 

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18978 Federal Register / Vol. 80, No. 67 / Wednesday, April 8, 2015 / Proposed Rules 

75 40 CFR 51.308(e)(1)(iv). 

TABLE 42—ENTERGY LAKE CATHERINE UNIT 4: SUMMARY OF 98TH PERCENTILE VISIBILITY IMPACTS AND IMPROVEMENT

DUE TO NOX CONTROLS

[Natural gas firing] 

Class I area 

Baseline 

visibility 

impact 

(Ddv) 

BOOS LNB/SOFA LNB/SOFA + SNCR LNB/SOFA + SCR 

Visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Caney Creek ........ 1.371 0.775 0.596 0 .683 0.688 0.529 0.842 0.163 1.208 

Upper Buffalo ....... 0.532 0.284 0.248 0 .25 0.282 0.193 0.339 0.057 0.475 

Hercules-Glades .. 0.387 0.212 0.175 0 .185 0.202 0.141 0.246 0.043 0.344 

Mingo ................... 0.429 0.233 0.196 0 .204 0.225 0.154 0.275 0.042 0.387 

Cumulative Visibility Improvement (Ddv) ........ ................ ................ 1.215 ................ 1.397 ................ 1.702 ................ 2.414 

The table above shows that the 

installation and operation of BOOS is 

projected to result in visibility 

improvement of up to 0.596 dv at any 

single Class I area (based on the 98th 

percentile modeled visibility impacts), 

while LNB/SOFA is projected to result 

in visibility improvement of up to 0.688 

dv. The installation and operation of the 

combination of LNB/SOFA + SNCR is 

projected to result in visibility 

improvement of up to 0.842 dv at any 

single Class I area, while the 

combination of LNB/SOFA + SCR is 

projected to result in visibility 

improvement of up to 1.208 dv. The 

installation and operation of LNB/SOFA 

is projected to result in 0.092 dv of 

incremental visibility benefit over 

BOOS at Caney Creek, and much lower 

incremental visibility benefit over 

BOOS at the other Class I areas. The 

combination of LNB/SOFA + SNCR is 

projected to result in 0.154 dv of 

incremental visibility benefit over LNB/ 

SOFA at Caney Creek, and 0.057 dv or 

less incremental visibility benefit at the 

other affected Class I areas. The 

combination of LNB/SOFA + SCR is 

projected to result in 0.366 dv of 

incremental visibility benefit over LNB/ 

SOFA + SNCR at Caney Creek, 0.136 dv 

at Upper Buffalo, 0.098 Ddv at HerculesGlades, and 0.112 dv at Mingo. 

Our Proposed NOX BART 

Determination: Taking into 

consideration the five factors, we are 

proposing to determine that NOX BART 

for Lake Catherine Unit 4 for the natural 

gas firing scenario is an emission limit 

of 0.22 lb/MMBtu on a 30 boileroperating-day rolling average based on 

the installation and operation of BOOS. 

The operation of BOOS is projected to 

result in visibility improvement ranging 

from 0.175 to 0.596 dv at each affected 

Class I area (98th percentile basis). The 

cumulative visibility improvement 

across the four affected Class I areas is 

projected to be 1.215 dv. The operation 

of BOOS is estimated to have an average 

cost-effectiveness of $138 per ton of 

NOX removed, which we consider to be 

very cost-effective. By comparison, the 

installation and operation of LNB/SOFA 

is estimated to have an average costeffectiveness of $1,450 per ton of NOX

removed, which is still very costeffective. However, the incremental 

cost-effectiveness of LNB/SOFA over 

BOOS is $14,246 per ton of NOX ton 

removed, while the incremental 

visibility benefits are only 0.027 to 

0.092 dv (depending on the Class I area). 

As discussed in the preceding 

paragraph, the operation of a 

combination of LNB/SOFA + SNCR is 

projected to result in visibility 

improvement over the baseline ranging 

from 0.246 to 0.842 dv at each affected 

Class I area and an incremental 

visibility improvement over LNB/SOFA 

ranging from 0.05 to 0.154 dv at each 

Class I area. However, the combination 

of LNB/SOFA + SNCR has an average 

cost-effectiveness of $3,523 per ton of 

NOX removed and an incremental costeffectiveness compared to LNB/SOFA of 

$16,029 per ton of NOX removed. We 

believe that the high incremental costs 

of the combination of LNB/SOFA + 

SNCR when compared to LNB/SOFA do 

not justify the amount of incremental 

visibility benefit projected at the 

affected Class I areas. The operation of 

a combination of LNB/SOFA + SCR is 

projected to result in considerable 

visibility improvement over the 

baseline, ranging from 0.344 to 1.208 dv 

at each affected Class I area. The 

incremental visibility benefit of the 

combination of LNB/SOFA + SCR over 

LNB/SOFA + SNCR ranges from 0.098 

to 0.366 dv at each Class I area. 

However, the combination of LNB/

SOFA + SCR has an average costeffectiveness of $5,614 per ton of NOX

removed and an incremental costeffectiveness (compared to the 

combination of LNB/SOFA + SNCR) of 

$11,767 per ton of NOX removed. While 

the incremental visibility benefit is 

considerable, we do not consider the 

average and the incremental costeffectiveness values of the combination 

of LNB/SOFA + SCR to be cost-effective. 

Therefore, we are proposing to 

determine that NOX BART for Lake 

Catherine Unit 4 for the natural gas 

firing scenario is an emission limit of 

0.22 lb/MMBtu on a 30 boiler-operatingday rolling average based on the 

installation and operation of BOOS. We 

are proposing to require compliance 

with this requirement no later than 3 

years from the effective date of the final 

rule, consistent with our regional haze 

regulations.75 We are proposing to 

require that compliance be 

demonstrated using the unit’s existing 

CEMS. We are inviting public comment 

specifically on whether this proposed 

NOX emission limit is appropriate or 

whether an emission limit based on 

more stringent NOX controls would be 

appropriate. We are also proposing 

regulatory text that includes monitoring, 

reporting, and recordkeeping 

requirements associated with this 

emission limit. 

6. Domtar Ashdown Paper Mill 

The Domtar Ashdown Paper Mill 

Power Boilers No. 1 and 2 are subject to 

BART. As mentioned previously, we 

disapproved Arkansas’ BART 

determinations for SO2 and NOX for 

Power Boiler No. 1 and the BART 

determination for SO2, NOX, and PM for 

the No. 2 Power Boiler in our March 12, 

2012 final action (77 FR 14604). The No. 

1 Power Boiler has a heat input rating 

of 580 MMBtu/hr and an average steam 

generation rate of approximately 

120,000 lb/hr. The No. 1 Power Boiler 

combusts primarily bark, but is also 

permitted to burn wood waste, tiremstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 80, No. 67 / Wednesday, April 8, 2015 / Proposed Rules 18979 

76See ‘‘Supplemental BART Determination 

Information Domtar A.W. LLC, Ashdown Mill 

(AFIN 41–00002),’’ originally dated June 28, 2013 

and revised on May 16, 2014, prepared by Trinity 

Consultants Inc. in conjunction with Domtar A.W. 

LLC. A copy of this BART analysis is found in the 

docket for our proposed rulemaking. 

77See ‘‘Best Available Retrofit Technology 

Determination Domtar Industries Inc., Ashdown 

Mill (AFIN 41–00002),’’ originally dated October 

31, 2006 and revised on March 26, 2007, prepared 

by Trinity Consultants Inc. This BART analysis is 

part of the 2008 Arkansas RH SIP, upon which EPA 

took final action on March 12, 2012 (77 FR 14604). 

A copy of this BART analysis is found in the docket 

for this proposed rulemaking. 

78 In Domtar’s 2014 BART analysis, 2009–2011 

was used as the baseline period for Power Boiler 

No. 1 because a wet ESP was installed on Power 

Boiler No. 1 in 2007. The installation of the wet ESP 

resulted in a reduction in PM and SO2 emissions 

from Power Boiler No. 1. Therefore, 2009–2011 is 

more representative of the boiler’s emissions than 

2001–2003. 

79 40 CFR part 51, Appendix Y, section IV.D.4.c. 

derived fuel (TDF), municipal yard 

waste, pelletized paper fuel (PPF), fuel 

oil, reprocessed fuel oil, and natural gas. 

It is equipped with a traveling grate, a 

combustion air system, and a wet ESP. 

The No. 2 Power Boiler has a heat input 

rating of 820 MMBtu/hr and an average 

steam generation rate of approximately 

600,000 lb/hr. The No. 2 Power Boiler 

combusts primarily pulverized 

bituminous coal, but is also permitted to 

burn bark, PPF, TDF, municipal yard 

waste, fuel oil, used oil, natural gas, 

petroleum coke, and reprocessed fuel 

oil. It is equipped with a traveling grate, 

combustion air system including OFA, 

multiclones for particulate removal, and 

two venturi scrubbers in parallel for 

removal of remaining particulates and 

SO2. Domtar hired a consultant to 

perform a BART five-factor analysis for 

the Domtar Ashdown Mill Power 

Boilers No. 1 and 2 (Domtar’s 2014 

BART analysis).76 In this proposal, we 

also refer to certain parts of the Domtar 

BART evaluation submitted by the State 

in the 2008 Arkansas RH SIP, which we 

are hereafter referring to as the ‘‘2006/ 

2007 Domtar BART analysis.’’ 77

Although we already took action on that 

SIP submittal, we reference the 2006/

2007 Domtar BART analysis as it 

contains the best available information 

we have related to certain NOX controls 

for Power Boilers No. 1 and 2. 

The table below summarizes the 

baseline emission rates for Power 

Boilers No. 1 and 2. The SO2 baseline 

emission rate for Power Boiler No. 1 

used in Domtar’s 2014 BART analysis is 

the highest actual 24-hour emission rate 

estimated using maximum 24-hour fuel 

usage rates during 2009–2011 and sulfur 

content values for each fuel type.78 The 

2009–2011 period was used as the 

baseline in Domtar’s evaluation for 

Power Boiler No. 1 because a wet ESP 

was installed on Power Boiler No. 1 in 

2007 to meet the Maximum Achievable 

Control Technology (MACT) standards 

under CAA section 112, resulting in a 

reduction in PM and SO2 emissions 

from Power Boiler No. 1. Therefore, we 

believe that the 2009–2011 period is 

more representative of the boiler’s 

current emissions than 2001–2003. We 

believe the use of 2009–2011 as the new 

baseline period for Power Boiler No. 1 

is consistent with the BART Guidelines, 

which provide that the baseline 

emissions rate should represent a 

realistic depiction of anticipated annual 

emissions for the source.79 The NOX

and PM baseline emission rates used for 

Power Boiler No. 1 are the highest 

actual 24-hour emission rates estimated 

using the maximum heat input from 

2009–2011 and emission factors 

developed from the analysis of stack 

testing the facility had previously 

conducted. For Power Boiler No. 2, the 

baseline emission rates are the highest 

actual 24-hour emission rates based on 

a combination of 2001–2003 CEMS data, 

source-specific stack testing results, and 

emission factors from AP–42. 

TABLE 43—DOMTAR ASHDOWN MILL: BASELINE MAXIMUM 24-HOUR EMISSION RATES

Subject to BART unit NOX Emissions 

(lb/hr) 

SO2 Emissions 

(lb/hr) 

PM10/PMf

Emissions 

(lb/hr) 

Power Boiler No. 1 .................................................................................................... 207.4 21.0 30.4 

Power Boiler No. 2 .................................................................................................... 526.8 788.2 81.6 

Domtar modeled the baseline 

emission rates using the CALPUFF 

dispersion model to determine the 

baseline visibility impairment 

attributable to the Domtar Ashdown 

Mill’s Power Boilers No. 1 and 2 at the 

four Class I areas impacted by emissions 

from BART sources in Arkansas. These 

Class I areas are the Caney Creek 

Wilderness Area, Upper Buffalo 

Wilderness Area, Hercules-Glades 

Wilderness Area, and Mingo National 

Wildlife Refuge. The baseline visibility 

impairment attributable to the source at 

each Class I area is summarized in the 

table below. 

TABLE 44—BASELINE VISIBILITY IMPAIRMENT ATTRIBUTABLE TO THE DOMTAR ASHDOWN MILL

Emission unit Caney Creek Upper Buffalo HerculesGlades Mingo 

Power Boiler No. 1: 

Maximum (Ddv) ......................................................................................... 0.476 0.090 0.077 0.060 

98th Percentile (Ddv) ................................................................................ 0.335 0.038 0.020 0.014 

Power Boiler No. 2: 

Maximum (Ddv) ......................................................................................... 1.603 0.381 0.329 0.246 

98th Percentile (Ddv) ................................................................................ 0.844 0.146 0.105 0.065 

a. Proposed SO2 BART Analysis and 

Determination for Power Boiler No. 1. 

The table above shows that the baseline 

visibility impairment attributable to 

Power Boiler No. 1 is relatively low 

based on the 98th percentile visibility 

impacts, ranging from 0.014–0.335 dv at 

each Class I area. An examination of the 

species contribution to the 98th 

percentile visibility impacts shows that 

SO2 emissions contribute a very small 

portion of the visibility impairment 

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18980 Federal Register / Vol. 80, No. 67 / Wednesday, April 8, 2015 / Proposed Rules 

80The visibility impact shown represents the 

highest 98th percentile value among the three 

modeled years. 

81 70 FR 39116. 

82The curve equation is Y = 0.4005 * X ¥ 0.2645, 

where Y = pounds of sulfur emitted per ton dry fuel 

feed to the boiler and X = pounds of sulfur input 

per ton of dry bark. The purpose of this equation 

is to factor in the degree of SO2 scrubbing provided 

by the combustion of bark. 

83Background information and an explanation of 

the site specific curve equation provided by Domtar 

can be found in the documents titled ‘‘Site Specific 

Curve Equation Background_Domtar PB No1,’’ and 

‘‘1PB SO2 Emissions from Curve.’’ Copies of these 

documents can be found in the docket for this 

proposed rulemaking. 

84See the document titled ‘‘Domtar Responses to 

ADEQ Regarding Region 6 Comments on Domtar 

BART Analysis,’’ p. 10. A copy of this document 

can be found in the docket for our proposed 

rulemaking. 

85Fuel Tech Proposal titled ‘‘Domtar Paper 

Ashdown, Arkansas—NOX Control Options, Power 

Boilers 1 and 2,’’ dated June 29, 2012. A copy of 

the vendor proposal is included under Appendix D 

to the ‘‘Supplemental BART Determination 

Information Domtar A.W. LLC, Ashdown Mill 

(AFIN 41–00002),’’ originally dated June 28, 2013 

and revised on May 16, 2014, prepared by Trinity 

Consultants Inc. in conjunction with Domtar A.W. 

LLC. A copy of this BART analysis and its 

appendices is found in the docket for our proposed 

rulemaking. 

attributable to Power Boiler No. 1 (see 

the table below). The SO4 species 

contributes only 2.23—4.03% of the 

visibility impairment attributable to 

Power Boiler No. 1 at the modeled Class 

I areas. We also note that Power Boiler 

No. 1 combusts primarily bark, which 

results in very low SO2 emissions due 

to the low sulfur content of bark. 

TABLE 45—BASELINE VISIBILITY IMPAIRMENT AND SPECIES CONTRIBUTION FOR DOMTAR ASHDOWN MILL—POWER BOILER

NO. 1 

Emissions unit Class I area 

98th Percentile 

visibility 

impacts 

(dv) 80

Species contribution to 98th percentile visibility impacts 

98th Percentile 

% SO4

98th Percentile 

% NO3

98th Percentile 

% PM10

98th Percentile 

% NO2

Power Boiler No. 1 .............. Caney Creek ...................... 0.335 2.23 85.26 6.68 5.83 

Upper Buffalo ..................... 0.038 2.75 85.89 8.03 3.32 

Hercules-Glades ................. 0.020 2.70 91.82 3.94 1.55 

Mingo .................................. 0.014 4.03 90.06 5.13 0.78 

As noted above, we believe that the 

BART Rule provides that states, or EPA 

in this case, can adopt a more 

streamlined approach to making BART 

determinations where appropriate.81

Considering the very low baseline 

visibility impairment that is due to SO2

emissions from Power Boiler No. 1 and 

the fact that the boiler combusts 

primarily bark, which has a low sulfur 

content, we believe that any visibility 

improvement that could be achieved as 

a result of emissions reductions 

associated with the installation and 

operation of SO2 controls would be 

negligible, and that the cost of those 

controls could not be justified. 

Therefore, we are proposing that the 

SO2 baseline emission rate of 21.0 lb/hr 

satisfies SO2 BART for Power Boiler No. 

1. We are proposing this SO2 emission 

rate on a 30 boiler-operating-day 

averaging basis, where in this particular 

case boiler-operating-day is defined as a 

24-hour period between 12 midnight 

and the following midnight during 

which any fuel is fed into and/or 

combusted at any time in the Power 

Boiler. Power Boiler No. 1 is not 

currently equipped with a CEMS. To 

demonstrate compliance with this SO2

BART emission limit we are proposing 

to require the facility to use a sitespecific curve equation,82 provided to 

us by the facility, to calculate the SO2

emissions from Power Boiler No. 1 

when combusting bark, and to confirm 

the curve equation using stack testing.83

We are also proposing that to calculate 

the SO2 emissions from fuel oil 

combustion, the facility must assume 

that the SO2 inlet is equal to the SO2

being emitted at the stack. We are 

inviting public comment on whether 

this method of demonstrating 

compliance with the proposed BART 

emission limit is appropriate. Since this 

proposed BART determination does not 

require the installation of control 

equipment, we are proposing that this 

SO2 emission limit be complied with by 

the effective date of the final action. 

b. Proposed NOX BART Analysis and 

Determination for Power Boiler No. 1. 

For NOX BART, Domtar’s 2014 BART 

analysis evaluated SNCR and Methane 

de-NOX (MdN). In the 2006/2007 

Domtar BART analysis, which was 

submitted in the 2008 Arkansas RH SIP, 

other NOX controls were also evaluated 

but found by Arkansas to be either 

already in use or not technically feasible 

for use at Power Boiler No. 1. Fuel 

blending, boiler operational 

modifications, and boiler tuning/

optimization are already in use at the 

source, while FGR, LNB, Ultra Low NOX

Burners (ULNB), OFA, and SCR were 

determined to be technically infeasible 

for use at Power Boiler No. 1. Domtar 

did not further evaluate these NOX

controls in its 2014 BART analysis for 

Power Boiler No. 1, focusing instead on 

SNCR and MdN. 

MdN utilizes the injection of natural 

gas together with recirculated flue gases 

to create an oxygen-rich zone above the 

combustion grate. Air is then injected at 

a higher furnace elevation to burn the 

combustibles. In response to comments 

provided by us regarding Domtar’s 2014 

BART analysis, Domtar stated that 

discussions regarding the technical 

infeasibility of MdN in the 2006/2007 

Domtar BART analysis, submitted as 

part of the 2008 Arkansas RH SIP, 

remain correct.84 The 2006/2007 Domtar 

BART analysis submitted in the 2008 

Arkansas RH SIP discussed that MdN 

has not been fully demonstrated for this 

source type and incorporates FGR, 

which is technically infeasible for use at 

Power Boiler No. 1. Domtar also stated 

it recently completed additional 

research and found that since the 2006/ 

2007 Domtar BART analysis, MdN has 

not been placed into operation in power 

boilers at paper mills or any comparable 

source types. We are also not aware of 

any power boilers at paper mills that 

operate MdN for NOX control, and agree 

that this control can be considered 

technically infeasible for use at Power 

Boiler No. 1 and do not further consider 

it in this evaluation. Domtar also 

questioned the technical feasibility of 

SNCR for bark fired boilers and boilers 

with high load swings such as Power 

Boiler No. 1, but in response to our 

comments, SNCR was evaluated for 

Power Boiler No. 1 in Domtar’s 2014 

BART analysis. 

Domtar’s 2014 BART analysis 

evaluated SNCR at removal efficiencies 

of 20%, 32.5%, and 45% for Power 

Boiler No. 1. The estimated 32.5% and 

45% removal efficiencies were based on 

equipment vendor estimates that came 

from the vendor’s proposal,85 which 

according to the facility, is not an 

appropriations request level quote and 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 80, No. 67 / Wednesday, April 8, 2015 / Proposed Rules 18981 

86See the document titled ‘‘Domtar Responses to 

ADEQ Regarding Region 6 Comments on Domtar 

BART Analysis,’’ p. 9. A copy of this document can be found in the docket for our proposed 

rulemaking. 

therefore needs further refinement.86

For example, Domtar’s 2014 BART 

analysis discusses that for a base loaded 

pulp mill boiler with steady flue gas 

flow patterns and temperature 

distribution across the flue gas pathway, 

SNCR can achieve a 45% removal 

efficiency. However, Power Boiler No. 1 

is not a base loaded boiler. Domtar’s 

2014 BART analysis states that for pulp 

mill boilers with fluctuating loads (i.e., 

high load swing), such as Power Boiler 

No. 1, SNCR is used primarily for 

polishing purposes (i.e., < 20 to 30% 

NOX reduction) and it is uncertain 

whether higher removal efficiencies are 

achievable on a long-term basis. The 

facility believes that 20% removal 

efficiency, which has been 

demonstrated at a similar bark fired 

power boiler at another paper mill, is 

the most reasonable estimate of the 

removal efficiency of SNCR for Power 

Boiler No. 1. 

In Domtar’s 2014 BART analysis, the 

capital costs, operating costs, and costeffectiveness of SNCR were calculated 

based on methods and assumptions 

found in our Control Cost Manual, and 

supplemented with mill-specific cost 

information for water, fuels, and ash 

disposal and urea solution usage 

estimates from the equipment vendor. 

The capital cost was annualized over a 

30-year period and then added to the 

annual operating cost to obtain the total 

annualized costs. The annual emissions 

reductions associated with each NOX

control option were determined by 

subtracting the estimated controlled 

annual emission rate from the baseline 

annual emission rate. The baseline 

annual emissions used in the 

calculations are the uncontrolled actual 

emissions from the 2009–2011 baseline 

period. The average cost-effectiveness 

was calculated by dividing the total 

annual cost by the estimated annual 

NOX emissions reductions. The table 

below summarizes the cost of NOX

controls for Power Boiler No. 1. 

TABLE 46—SUMMARY OF COST OF NOX CONTROLS FOR POWER BOILER NO. 1 

NOX Control 

scenarios 

Baseline 

emission rate 

(NOX tpy) 

NOX Control 

efficiency 

(%) 

Annual 

emissions 

reduction 

(NOX tpy) 

Capital cost 

($) 

Total 

annual cost 

($/yr) 

Average cost 

effectiveness 

($/ton) 

Incremental 

cost-effectiveness 

($/ton) 

SNCR—20% ........ 440 20 88 2,152,365 1,118,178 12,700 ..............................

SNCR—32.5% ..... 440 32 .5 143 2,423,587 1,144,103 7,996 471 

SNCR—45% ........ 440 45 198 2,707,431 1,513,602 7,640 6,718 

Domtar’s 2014 BART analysis did not 

identify any energy or non-air quality 

environmental impacts associated with 

the use of SNCR. We are not aware of 

any unusual circumstances at the 

facility that create greater non-air 

quality environmental impacts than 

experienced elsewhere that may provide 

a basis for the elimination of these 

control options as BART (40 CFR part 

51, Appendix Y, section IV.D.4.i.2.). 

Therefore, we do not believe there are 

any energy or non-air quality 

environmental impacts associated with 

the operation of NOX controls at Power 

Boiler No. 1 that would affect our 

proposed BART determination. 

Consideration of the presence of 

existing pollution control technology at 

the source is reflected in the BART 

analysis in two ways: First, in the 

consideration of available control 

technologies, and second, in the 

development of baseline emission rates 

for use in cost calculations and visibility 

modeling. Power Boiler No. 1 is 

currently equipped with a combustion 

air system to optimize boiler 

combustion efficiency, which has the 

co-benefit of reducing emissions. The 

baseline emission rate used in the cost 

calculations and visibility modeling 

reflects the use of the existing 

combustion air system. 

In the 2014 BART analysis, Domtar 

assessed the visibility improvement 

associated with SNCR by modeling the 

NOX emission rates associated with 

each control option using CALPUFF, 

and then comparing the visibility 

impairment associated with the baseline 

emission rate to the visibility 

impairment associated with the 

controlled emission rates as measured 

by the 98th percentile modeled 

visibility impact. The table below shows 

a comparison of the baseline (i.e., 

existing) visibility impacts and the 

visibility impacts associated with SNCR. 

TABLE 47—DOMTAR ASHDOWN MILL POWER BOILER NO. 1: SUMMARY OF THE 98TH PERCENTILE VISIBILITY IMPACTS AND

IMPROVEMENT DUE TO SNCR 

Class I area 

Baseline 

visibility 

impact 

(dv) 

SNCR—20% SNCR—32.5% SNCR—45% 

Visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Caney Creek ................................................ 0.335 0.274 0.061 0.237 0.098 0.199 0.136 

Upper Buffalo ............................................... 0.038 0.031 0.007 0.027 0.011 0.023 0.015 

Hercules-Glades .......................................... 0.020 0.017 0.003 0.014 0.006 0.012 0.008 

Mingo ........................................................... 0.014 0.011 0.003 0.009 0.005 0.008 0.006 

Cumulative Visibility Improvement (Ddv) ..... ................ ................ 0.074 ................ 0.12 ................ 0.165 

The table above shows that the 

installation and operation of SNCR is 

projected to result in visibility 

improvements of up to 0.136 dv at any 

single Class I area when operated at 

45% removal efficiency, 0.098 dv when 

operated at 32.5% removal efficiency, 

and 0.061 dv when operated at 20% 

mstockstill on DSK4VPTVN1PROD with PROPOSALS2

18982 Federal Register / Vol. 80, No. 67 / Wednesday, April 8, 2015 / Proposed Rules 

87See ‘‘Supplemental BART Determination 

Information Domtar A.W. LLC, Ashdown Mill 

(AFIN 41–00002),’’ originally dated June 28, 2013 

and revised on May 16, 2014, prepared by Trinity 

Consultants Inc. in conjunction with Domtar A.W. 

LLC. A copy of this BART analysis is found in the 

docket for our proposed rulemaking. 

88See ‘‘Lundberg Budget Proposal Spray 

Scrubber—Domtar Industries, Ashdown, AR,’’ 

dated April 17, 2014. The vendor proposal is found 

under Appendix D to Domtar’s BART analysis titled 

‘‘Supplemental BART Determination Information 

Domtar A.W. LLC, Ashdown Mill (AFIN 41– 

00002),’’ originally dated June 28, 2013 and revised 

on May 16, 2014, prepared by Trinity Consultants 

Inc. in conjunction with Domtar A.W. LLC. 

89See Appendices B and D to the ‘‘Supplemental 

BART Determination Information Domtar A.W. 

LLC, Ashdown Mill (AFIN 41–00002),’’ originally 

dated June 28, 2013 and revised on May 16, 2014, 

prepared by Trinity Consultants Inc. in conjunction 

with Domtar A.W. LLC. 

removal efficiency (based on the 98th 

percentile modeled visibility impacts). 

Our Proposed NOX BART 

Determination: Taking into 

consideration the five factors, we are 

proposing to determine that NOX BART 

for the Domtar Ashdown Mill Power 

Boiler No. 1 is an emission limit of 

207.4 lb/hr on a 30 boiler-operating-day 

rolling average, where boiler-operatingday is defined as a 24-hour period 

between 12 midnight and the following 

midnight during which any fuel is fed 

into and/or combusted at any time in 

the Power Boiler. This emission limit is 

based on the boiler’s NOX baseline 

emission rate and therefore represents 

current operating conditions. MdN was 

determined to be not technically 

feasible for use at Power Boiler No. 1 

because it has not been fully 

demonstrated for this source type and 

incorporates FGR, which is technically 

infeasible for use at the boiler. The 

installation and operation of SNCR is 

projected to result in some visibility 

improvement at the Class I areas. As 

discussed in more detail above, we 

concur with Domtar’s position that 20% 

removal efficiency is the most 

reasonable estimate of the level of NOX

control SNCR can achieve at Power 

Boiler No. 1. When operated at 20% 

removal efficiency, SNCR is projected to 

result in visibility improvement of up to 

0.061 dv at any single Class I area and 

is estimated to cost $12,700 per ton of 

NOX removed. We do not believe this 

high cost justifies the modest visibility 

improvement projected from the 

installation and operation of SNCR at 

20% removal efficiency. Although there 

is uncertainty as to whether SNCR can 

achieve a long term removal efficiency 

of 45% or even 32.5% at Power Boiler 

No. 1, we believe that the associated 

costs are also too high to justify the 

small projected visibility benefits. 

Installation and operation of SNCR at a 

45% removal efficiency is projected to 

result in a visibility improvement of up 

to 0.136 dv at any single Class I area and 

is estimated to cost $7,640 per ton of 

NOX removed. The operation of SNCR at 

a 32.5% removal efficiency is projected 

to result in visibility improvement of up 

to 0.098 dv at any single Class I area and 

is estimated to cost $7,996 per ton of 

NOX removed. Therefore, we are 

proposing to determine that NOX BART 

for Power Boiler No. 1 is no additional 

control and are proposing that an 

emission limit of 207.4 lb/hr on a 30 

boiler-operating-day rolling average 

satisfies NOX BART. In this particular 

case, we are defining boiler-operatingday as a 24-hour period between 12 

midnight and the following midnight 

during which any fuel is fed into and/ 

or combusted at any time in the Power 

Boiler. Power Boiler No. 1 is not 

currently equipped with a CEMS. To 

demonstrate compliance with this NOX

BART emission limit we are proposing 

to require annual stack testing. We are 

inviting public comment on the 

appropriateness of this method for 

demonstrating compliance with the 

NOX BART emission limit for Power 

Boiler No. 1. Since this proposed BART 

determination does not require the 

installation of control equipment, we 

are proposing that this NOX emission 

limit be complied with by the effective 

date of the final action. We are also 

proposing regulatory text that includes 

monitoring, reporting, and 

recordkeeping requirements associated 

with this proposed BART 

determination. 

c. Proposed SO2 BART Analysis and 

Determination for Power Boiler No. 2. 

Power Boiler No. 2 is currently 

equipped with two venturi wet 

scrubbers in parallel for removal of 

particulates and SO2. Domtar’s 2014 

BART analysis evaluated upgrades to 

the existing venturi wet scrubbers and 

new add-on spray scrubbers for Power 

Boiler No. 2.87 Domtar’s analysis 

explains that it contracted with a vendor 

to evaluate upgrades to the existing 

venturi scrubbers and provide a quote 

for a new add-on spray scrubber system 

that would be installed downstream of 

the existing venturi scrubbers.88

Domtar’s analysis states that the existing 

venturi scrubbers achieve an SO2

control efficiency of approximately 90% 

and notes that this is within the normal 

range for the highest control efficiency 

achieved by SO2 control technologies. 

Domtar’s analysis indicates that the 

upgrades it considered for the existing 

venturi scrubbers include: (1) The 

elimination of bypass reheat, (2) the 

installation of liquid distribution rings, 

(3) the installation of perforated trays, 

(4) improvements to the auxiliary 

system requirement, and (5) a redesign 

of spray header and nozzle 

configuration. Domtar’s analysis states 

that any additional control that could 

potentially be achieved from 

implementation of such upgrades would 

be marginal, but the facility was unable 

to quantify the potential additional 

control. Therefore, it was determined 

that the installation of new add-on spray 

scrubbers to operate downstream of the 

existing scrubbers was more feasible 

than any upgrade option. The remainder 

of Domtar’s analysis focused on the addon spray scrubber option. Based on the 

information provided to Domtar by the 

vendor, the add-on spray scrubbers 

would utilize sodium hydroxide 

(NaOH), bleach plant EO filtrate (i.e., 

bleaching filtrate), and water as the 

scrubbing reagent. The add-on spray 

scrubbers are estimated to achieve 90% 

control efficiency above the SO2

removal the existing venturi scrubbers 

are currently achieving. In Domtar’s 

analysis, it is estimated that a controlled 

SO2 emission rate of 78.8 lb/hr would be 

achieved by the operation of add-on 

spray scrubbers installed downstream of 

the existing venturi scrubbers. 

Domtar’s estimates of the capital and 

operating and maintenance costs of addon spray scrubbers for Power Boiler No. 

2 were based on the equipment vendor’s 

budget proposal and on calculation 

methods from our Control Cost Manual. 

Domtar annualized the capital cost of 

the add-on spray scrubbers over a 30- 

year amortization period and then 

added these to the annual operating 

costs to obtain the total annualized 

cost.89 The average cost-effectiveness in 

dollars per ton removed was calculated 

by dividing the total annualized cost by 

the annual SO2 emissions reductions. 

The average cost-effectiveness of the 

add-on spray scrubbers for Power Boiler 

No. 2 was estimated to be $5,258 per ton 

of SO2 removed (see table below). 

Domtar’s analysis notes that because of 

constricted space, there is no existing 

property or adequate structure to 

support the add-on spray scrubber 

equipment. In our discussions with 

Domtar, the facility indicated that the 

installation of add-on spray scrubbers 

would require construction at the 

facility to accommodate the equipment, 

but an estimate of these costs was not 

available and therefore not factored into 

the cost estimates presented in Domtar’s 

analysis. 

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Federal Register / Vol. 80, No. 67 / Wednesday, April 8, 2015 / Proposed Rules 18983 

90The baseline visibility impacts reflect the 

operation of the existing venturi scrubbers. 

91See the following: Letters dated July 9, 2014; 

July 21, 2014; August 15, 2014; August 29, 2014; 

and September 12, 2014, from Annabeth Reitter, 

Corporate Manager of Environmental Regulation, 

Domtar, to Dayana Medina, U.S. EPA Region 6. 

Copies of these letters and all attachments are found 

in the docket for our proposed rulemaking. 

TABLE 48—SUMMARY OF COSTS FOR ADD-ON SPRAY SCRUBBER FOR POWER BOILER NO. 2 

Control technology 

Baseline 

emission 

rate 

(SO2 tpy) 

Controlled 

emission 

level 

(lb/hr) 

Controlled 

emission 

rate 

(tpy) 

Annual 

emissions 

reductions 

(SO2 tpy) 

Capital 

cost * 

($) 

Annual 

direct O&M 

cost 

($/yr) 

Annual 

indirect 

O&M 

cost 

($/yr) 

Total 

annual 

cost 

($/yr) 

Average 

cost 

effectiveness 

($/ton) 

Add-on Spray Scrubber ......................... 2,078 78.8 208 1,870 7,175,000 8,833,382 421,789 9,833,378 5,258 

* Capital cost does not include new construction to accommodate equipment. 

Domtar’s 2014 BART analysis did not 

identify any energy or non-air quality 

environmental impacts associated with 

the use of add-on spray scrubbers. We 

are not aware of any unusual 

circumstances at the facility that create 

non-air quality environmental impacts 

associated with the use of add-on spray 

scrubbers greater than experienced 

elsewhere that may therefore provide a 

basis for the elimination of this control 

option as BART (40 CFR part 51, 

Appendix Y, section IV.D.4.i.2.). 

Therefore, we do not believe there are 

any energy or non-air quality 

environmental impacts associated with 

this control option at Power Boiler No. 

2 that would affect our proposed BART 

determination. 

Consideration of the presence of 

existing pollution control technology at 

the source is reflected in the BART 

analysis in two ways: First, in the 

consideration of available control 

technologies, and second, in the 

development of baseline emission rates 

for use in cost calculations and visibility 

modeling. Power Boiler No. 2 is 

equipped with multiclones for 

particulate removal and two venturi 

scrubbers in parallel for control of SO2

emissions. It is also equipped with a 

combustion air system including 

overfire air to optimize boiler 

combustion efficiency, which also helps 

control emissions. The baseline 

emission rate used in the cost 

calculations and visibility modeling 

reflects the use of these existing 

controls. As discussed above, Domtar’s 

analysis also evaluated upgrades to the 

existing venturi scrubbers to potentially 

achieve greater SO2 control efficiency. 

Another option we have identified to 

achieve greater SO2 control efficiency of 

the existing scrubbers involves using 

additional scrubbing reagent, but this 

was not considered in Domtar’s 2014 

BART analysis. Our analysis of this 

control option is presented below, 

following the analysis of add-on spray 

scrubbers. 

In the 2014 BART analysis, Domtar 

assessed the visibility improvement 

associated with the add-on spray 

scrubbers by modeling the controlled 

SO2 emission rate using CALPUFF, and 

then comparing the visibility 

impairment associated with the 

controlled emission rate to that of the 

baseline emission rate as measured by 

the 98th percentile modeled visibility 

impact. The table below shows a 

comparison of the baseline (i.e., 

existing) visibility impacts and the 

visibility impacts associated with the 

add-on spray scrubbers. The installation 

and operation of add-on spray scrubbers 

is projected to result in visibility 

improvement of 0.146 dv at Caney 

Creek. The visibility improvement is 

projected to range from 0.026–0.053 dv 

at each of the other Class I areas. 

TABLE 49—DOMTAR ASHDOWN MILL POWER BOILER NO. 2: SUMMARY OF THE 98TH PERCENTILE VISIBILITY IMPACTS AND

IMPROVEMENT DUE TO ADD-ON SPRAY SCRUBBERS

Class I area 

Baseline 

visibility impact 90

(dv) 

Add-on spray scrubbers 

Visibility impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Caney Creek .............................................................................................................. 0.844 0.698 0.146 

Upper Buffalo ............................................................................................................. 0.146 0.093 0.053 

Hercules-Glades ........................................................................................................ 0.105 0.054 0.051 

Mingo ......................................................................................................................... 0.065 0.039 0.026 

Cumulative Visibility Improvement (Ddv) ................................................................... .............................. .............................. 0.276 

As mentioned above, another option 

not evaluated in Domtar’s 2014 BART 

analysis is the optimization of the 

existing venturi scrubbers to achieve a 

higher SO2 control efficiency through 

the use of additional scrubbing reagent. 

Following discussions between us and 

Domtar, the facility provided additional 

information regarding the existing 

venturi scrubbers, including a 

description of the internal structure of 

the scrubbers, whether any scrubber 

upgrades have taken place, the type of 

reagent used, how the facility 

determines how much reagent to use, 

and the SO2 control efficiency.91 Domtar 

confirmed that no upgrades to the 

scrubbers have ever been performed and 

stated that 100% of the flue gas is 

treated by the scrubber systems. The 

scrubbing solution used in the venturi 

scrubbers is made up of three 

components: 15% caustic solution (i.e., 

NaOH), bleach plant EO filtrate (typical 

pH above 9.0), and demineralizer anion 

rinse water (approximately 2.5% 

NaOH). The bleach plant EO filtrate and 

demineralizer anion rinse water are both 

waste byproducts from the processes at 

the plant. The 15% caustic solution is 

added to adjust the pH of the scrubbing 

solution and maintain it within the 

required range to ensure that sufficient 

SO2 is removed from the flue gas in the 

scrubber to meet the permitted SO2

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18984 Federal Register / Vol. 80, No. 67 / Wednesday, April 8, 2015 / Proposed Rules 

92August 29, 2014 letter from Annabeth Reitter, 

Corporate Manager of Environmental Regulation, 

Domtar, to Dayana Medina, U.S. EPA Region 6. A 

copy of this letter and an Excel file attachment 

titled ‘‘Domtar 2PB Monthly SO2 Data,’’ are found 

in the docket for our proposed rulemaking. 

93See the spreadsheet titled ‘‘Domtar 2PB 

Monthly SO2 Data.’’ This spreadsheet was included 

as an attachment to the August 29, 2014 letter from 

Annabeth Reitter, Corporate Manager of 

Environmental Regulation, Domtar, to Dayana 

Medina, U.S. EPA Region 6. See also the 

spreadsheet titled ‘‘Domtar PB No2—Cost 

Effectiveness calculations.’’ Copies of these 

documents can be found in the docket for this 

proposed rulemaking. 

94See the spreadsheet titled ‘‘Domtar PB No2— 

Cost Effectiveness calculations.’’ A copy of this 

spreadsheet can be found in the docket for this 

proposed rulemaking. 95September 30, 2014 letter from Annabeth 

Reitter, Corporate Manager of Environmental 

Regulation, Domtar, to Dayana Medina, U.S. EPA 

Region 6. See also the spreadsheet titled ‘‘Domtar 

PB No2—Cost of Using Additional Scrubbing 

Reagent. Copies of these documents can be found 

in the docket for this proposed rulemaking. 

96See the spreadsheet titled ‘‘Domtar 2PB 

Monthly SO2 Data.’’ This spreadsheet was included 

as an attachment to the August 29, 2014 letter from 

Annabeth Reitter, Corporate Manager of 

Environmental Regulation, Domtar, to Dayana 

Medina, U.S. EPA Region 6. See also the 

spreadsheet titled ‘‘No2 Boiler_Monthly Avg SO2

emission rate and calculations.’’ Copies of these 

documents can be found in the docket for this 

proposed rulemaking. 

97See the spreadsheet titled ‘‘No2 Boiler_

Monthly Avg SO2 emission rate and calculations.’’ 

A copy of this spreadsheet can be found in the 

docket for this proposed rulemaking. 

98The capital costs consist of two new pumps for 

the existing scrubber system. 

99The operation and maintenance costs consist of 

the following costs: Additional scrubbing reagent, 

treatment of additional wastewater, treatment of 

additional raw water, and additional energy usage. 

emission limit of 1.20 lb/MMBtu on a 

three hour average. Each venturi 

scrubber has a recirculation tank that is 

equipped with level control systems to 

ensure that an adequate supply of the 

scrubbing solution is maintained. There 

are pH controllers in place that provide 

signals for the 15% caustic flow 

controllers to adjust the flow of the 

caustic solution to bring the pH into the 

desired set point range. The pH 

controllers are overridden in the event 

that SO2 levels measured at the stack by 

the CEMS are above the operator set 

point of 0.86 lb/MMBtu on a two hour 

average (the SO2 permit limit is 1.20 lb/ 

MMBtu on a three hour average). This 

allows additional caustic feed to the 

scrubber solution to increase the pH and 

reduce the SO2 measured at the stack. 

According to Domtar, the scrubber 

systems operate in this manner to 

maintain continuous compliance with 

permitted emission limits. 

Domtar provided monthly average 

data for 2011, 2012, and 2013 on 

monitored SO2 emissions from Power 

Boiler No. 2, mass of the fuel burned for 

each fuel type, and the percent sulfur 

content of each fuel type burned.92

Based on the information provided by 

Domtar, the monthly average SO2

control efficiency of the existing 

scrubbers for the 2011–2013 period 

ranged from 57% to 90%. The data 

indicate that the monthly average 

control efficiency of the scrubbers is 

usually below 90%. The information 

provided also indicates that the facility 

could add more scrubbing solution to 

achieve greater SO2 removal than what 

is necessary to meet permit limits. We 

believe that it is feasible for the facility 

to use additional scrubbing solution to 

consistently achieve at least a 90% SO2

removal on a monthly average basis. To 

estimate the SO2 annual emissions 

reductions expected from increasing the 

control efficiency of the scrubbers 

through the use of additional scrubbing 

solution, we calculated the annual 

average SO2 control efficiency of the 

existing scrubbers. Based on the 

monthly average SO2 control efficiency 

data for the 2011–2013 period, we 

estimated the annual average SO2

control efficiency for the three-year 

period to be approximately 69%.93

Considering the baseline annual 

emissions for Power Boiler No. 2 are 

2,078 SO2 tpy, and assuming that the 

scrubbers currently operate at an annual 

average control efficiency of 69%, we 

have estimated that the uncontrolled 

annual emissions would be 6,769 SO2

tpy and that operating the scrubbers at 

90% control efficiency would result in 

controlled annual emissions of 677 SO2

tpy. By subtracting the controlled 

annual emission rate of 677 SO2 tpy 

from the baseline annual emission rate 

of 2,078 SO2 tpy, we estimate that 

increasing the control efficiency of the 

existing venturi scrubbers from current 

levels to 90% control efficiency would 

result in annual emissions reductions of 

1,401 SO2 tpy from baseline levels.94

Based on the cost information provided 

by the facility, increasing the monthly 

average SO2 control efficiency of the 

existing venturi scrubbers from current 

levels to 90% control efficiency would 

require replacing two scrubber pumps, 

which involves capital costs of 

$200,000.95 It would also require 

additional scrubbing reagent, treatment 

of additional wastewater, treatment of 

additional raw water, and additional 

energy usage, which involves annual 

operation and maintenance costs of 

approximately $1.96 million. Based on 

the information provided by Domtar, we 

estimate the average cost-effectiveness 

of using additional scrubbing reagent to 

increase the SO2 control efficiency of 

the existing venturi scrubbers from the 

current control efficiency (estimated to 

be 69%) to 90% is $1,411 per ton of SO2

removed. The cost information is 

presented in the table below. To 

determine the controlled emission rate 

that corresponds to the operation of the 

existing venturi scrubbers at a 90% 

removal efficiency, we first determined 

the SO2 emission rate that corresponds 

to the operation of the scrubbers at the 

current control efficiency of 69%. Based 

on emissions data we obtained from 

Domtar, we determined that the No. 2 

Power Boiler’s annual average SO2

emission rate for the years 2009–2011 

was 280.9 lb/hr.96 This annual average 

SO2 emission rate corresponds to the 

operation of the scrubbers at a 69% 

removal efficiency. We also estimated 

that 100% uncontrolled emissions 

would correspond to an emission rate of 

approximately 915 lb/hr. Application of 

90% control efficiency to this results in 

a controlled emission rate of 91.5 lb/hr, 

or 0.11 lb/MMBtu based on the boiler’s 

maximum heat input of 820 MMBtu.97

TABLE 50—SUMMARY OF COST OF USING ADDITIONAL SCRUBBING REAGENT TO INCREASE CONTROL EFFICIENCY OF

EXISTING VENTURI SCRUBBERS AT POWER BOILER NO. 2 

Control option 

Baseline 

emission rate 

(SO2 tpy) 

Controlled 

emission rate 

(tpy) 

Annual 

emissions 

reductions 

(SO2 tpy) 

Capital 

costs 98

($) 

Operation & 

maintenance 

cost 99

($/yr) 

Total 

annual cost 

($/yr) 

Average cost 

effectiveness 

($/ton) 

Use of Additional Scrubbing Reagent ............................................... 2,078 677 1,401 200,000 1,960,434 1,976,554 1,411 

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Federal Register / Vol. 80, No. 67 / Wednesday, April 8, 2015 / Proposed Rules 18985 

Using the visibility modeling analysis 

of the baseline visibility impacts from 

Power Boiler No. 2 and the visibility 

improvement projected from the 

installation and operation of new addon spray scrubbers, we have 

extrapolated the visibility improvement 

projected as a result of using additional 

scrubbing reagent to increase the SO2

control efficiency of the existing venturi 

scrubbers from the current control 

efficiency (estimated to be 69%) to 90%, 

or an outlet emission rate of 0.11 lb/

MMBtu. We have assumed that the 

maximum 24-hour baseline emission 

rate used in the visibility modeling 

represents the operation of the existing 

venturi scrubbers at a 69% control 

efficiency. We estimate that the 

visibility improvement of using 

additional scrubbing reagent to increase 

the SO2 control efficiency of the existing 

venturi scrubbers to 90% control 

efficiency is 0.139 dv at Caney Creek 

and 0.05 dv or less at each of the other 

Class I areas (see table below). 

TABLE 51—DOMTAR ASHDOWN MILL POWER BOILER NO. 2: SUMMARY OF THE 98TH PERCENTILE VISIBILITY IMPACTS AND

IMPROVEMENT FROM USE OF ADDITIONAL SCRUBBING REAGENT

Class I area 

Baseline 

visibility 

impact 

(dv) 

Add-on spray scrubber 

impacts 

(dv) 

Estimated impacts from use of 

additional reagent 

(dv) 

Visibility 

impact 

(dv) 

Visibility 

improvement 

from baseline 

(dv) 

Visibility 

impact 

(dv) 

Visibility 

improvement 

from baseline 

(dv) 

Caney Creek ........................................................................ 0.844 0.698 0.146 0.705 0.139 

Upper Buffalo ....................................................................... 0.146 0.093 0.053 0.096 0.05 

Hercules-Glades .................................................................. 0.105 0.054 0.051 0.057 0.048 

Mingo ................................................................................... 0.065 0.039 0.026 0.04 0.025 

Cumulative Visibility Improvement (dv) ............................... ........................ ........................ 0.276 ........................ 0.262 

Our Proposed SO2 BART 

Determination: Taking into 

consideration the five factors, we 

propose to determine that SO2 BART for 

Power Boiler No. 2 is an emission limit 

of 0.11 lb/MMBtu on a 30 boileroperating-day rolling average, which we 

estimate is representative of operating 

the existing scrubbers at 90% control 

efficiency. In this particular case, we 

define boiler-operating-day as a 24-hour 

period between 12 midnight and the 

following midnight during which any 

fuel is fed into and/or combusted at any 

time in the Power Boiler. We are 

inviting public comment specifically on 

the appropriateness of this proposed 

SO2 emission limit. We believe that this 

emission limit can be achieved by using 

additional scrubbing reagent in the 

operation of the existing venturi 

scrubbers. We estimate that operating 

the existing scrubbers to achieve this 

level of control would result in visibility 

improvement of 0.139 dv at Caney Creek 

and 0.05 dv or lower at each of the other 

Class I areas. We estimate the 

cumulative visibility improvement at 

the four Class I areas to be 0.262 dv. 

Based on the cost information provided 

by the facility, we have estimated that 

the use of additional scrubbing reagent 

to increase the control efficiency of the 

existing venturi scrubbers is estimated 

to cost $1,411 per ton of SO2 removed. 

Based on Domtar’s BART analysis, new 

add-on spray scrubbers that would be 

operated downstream of the existing 

venturi scrubbers are projected to result 

in visibility improvement of 0.146 dv at 

Caney Creek and 0.053 dv or lower at 

each of the other Class I areas. The 

cumulative visibility improvement at 

the four Class I areas is projected to be 

0.276 dv. The cost of add-on spray 

scrubbers is estimated to be $5,258 per 

ton of SO2 removed, not including 

additional construction costs that would 

likely be incurred to make space to 

house the new scrubbers. We do not 

believe that the amount of visibility 

improvement that is projected from the 

installation and operation of new addon spray scrubbers would justify their 

high average cost-effectiveness. The 

incremental visibility improvement of 

new add-on spray scrubbers compared 

to using additional scrubbing reagent to 

increase the control efficiency of the 

existing venturi scrubbers ranges from 

0.001 to 0.007 dv at each Class I area, 

yet the incremental cost-effectiveness is 

estimated to be $16,752. We do not 

believe the incremental visibility benefit 

warrants the higher cost associated with 

new add-on spray scrubbers. Therefore, 

we are proposing to determine that SO2

BART for Power Boiler No. 2 is an 

emission limit of 0.11 lb/MMBtu on a 30 

boiler-operating-day rolling averaging 

basis, and are inviting comment on the 

appropriateness of this emission limit. 

We propose to require the facility to 

demonstrate compliance with this 

emission limit using the existing CEMS. 

Since the SO2 emission limit we are 

proposing can be achieved with the use 

of the existing venturi scrubbers but will 

require scrubber pump upgrades and 

additional scrubbing reagent, we 

propose to require compliance with this 

BART emission limit no later than 3 

years from the effective date of the final 

action, but are inviting public comment 

on the appropriateness of a compliance 

date anywhere from 1–5 years. 

d. Proposed NOX BART Analysis and 

Determination for Power Boiler No. 2. 

For NOX BART, Domtar’s 2014 BART 

analysis evaluated LNB, SNCR, and 

Methane de-NOX (MdN). In the 2006/

2007 Domtar BART analysis, which was 

submitted in the 2008 Arkansas RH SIP, 

other NOX controls were also evaluated 

but found by the State to be either 

already in use or not technically feasible 

for use at Power Boiler No. 2. Fuel 

blending, boiler operational 

modifications, and boiler tuning/

optimization are already in use at the 

source, while FGR, OFA, and SCR were 

found to be technically infeasible for 

use at Power Boiler No. 2. Domtar did 

not further evaluate these NOX controls, 

and instead focused on LNB, SNCR, and 

MdN in its 2014 BART analysis for 

Power Boiler No. 2. 

MdN utilizes the injection of natural 

gas together with recirculated flue gases 

to create an oxygen-rich zone above the 

combustion grate. Air is then injected at 

a higher furnace elevation to burn the 

combustibles. In response to comments 

provided by us regarding Domtar 2014 

BART analysis, Domtar stated that 

discussions regarding the technical 

infeasibility of MdN in the 2006/2007 

Domtar BART analysis, submitted as 

part of the 2008 Arkansas RH SIP, 

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18986 Federal Register / Vol. 80, No. 67 / Wednesday, April 8, 2015 / Proposed Rules 

100A copy of Domtar’s response is found in the 

docket for this proposed rulemaking. See email 

from Kelly Crouch, dated May 16, 2014. 

101Fuel Tech Proposal titled ‘‘Domtar Paper 

Ashdown, Arkansas- NOX Control Options, Power 

Boilers 1 and 2,’’ dated June 29, 2012. A copy of 

the vendor proposal is included under Appendix D 

to the ‘‘Supplemental BART Determination 

Information Domtar A.W. LLC, Ashdown Mill 

(AFIN 41–00002),’’ originally dated June 28, 2013 

and revised on May 16, 2014, prepared by Trinity 

Consultants Inc. in conjunction with Domtar A.W. 

LLC. A copy of this BART analysis and its 

appendices is found in the docket for our proposed 

rulemaking. 

102See the document titled ‘‘Domtar Responses to 

ADEQ Regarding Region 6 Comments on Domtar 

BART Analysis,’’ p. 9. A copy of this document can 

be found in the docket for our proposed 

rulemaking. 

103September 12, 2014 letter from Annabeth 

Reitter, Corporate Manager of Environmental 

Regulation, Domtar, to Dayana Medina, U.S. EPA 

Region 6. A copy of this letter and its attachments 

are found in the docket for our proposed 

rulemaking. 

104See the spreadsheet titled ‘‘Domtar PB No. 2 

LNB_cost revisions.’’ A copy of this spreadsheet is 

found in the docket for this proposed rulemaking. 

remain correct.100 The 2006/2007 

Domtar BART analysis submitted in the 

2008 Arkansas RH SIP discussed that 

MdN has not been fully demonstrated 

for this type of boiler and incorporates 

FGR, which is considered technically 

infeasible for use at Power Boiler No. 2. 

Domtar also stated it recently completed 

additional research and found that since 

the 2006/2007 Domtar BART analysis, 

MdN has not been placed into operation 

in power boilers at paper mills or any 

comparable source types. We are also 

not aware of any power boilers at paper 

mills that operate MdN for NOX control, 

and agree that this control can be 

considered technically infeasible for use 

at Power Boiler No. 2 and do not further 

consider it in this evaluation. Domtar 

also questioned the technical feasibility 

of SNCR for boilers with high load 

swing such as Power Boiler No. 2, but 

in response to comments from us, SNCR 

was evaluated in Domtar’s 2014 BART 

analysis. 

Based on vendor estimates, the 2006/ 

2007 Domtar BART analysis estimated 

the potential control efficiency of LNB 

to be 30%. In Domtar’s 2014 BART 

analysis, SNCR was evaluated at a 

control efficiency of 27.5% and 35% for 

Power Boiler No. 2. These values were 

based on SNCR control efficiency 

estimates that came from the equipment 

vendor’s proposal,101 which according 

to the facility, is not an appropriations 

request level quote and therefore 

requires further refinement.102 For 

example, Domtar’s 2014 BART analysis 

discusses that for a base loaded coal 

boiler with steady flue gas flow patterns 

and temperature distribution across the 

flue gas pathway, SNCR is typically 

capable of achieving 50% NOX

reduction. However, Power Boiler No. 2 

is not a base loaded boiler and does not 

have steady flue gas flow patterns or 

steady temperature distribution across 

the flue gas pathway. To demonstrate 

the wide range in temperature at Power 

Boiler No. 2 and its relationship to 

steam demand, Domtar obtained an 

analysis of furnace exit gas temperatures 

for Power Boiler No. 2 from an 

engineering consultant.103 The furnace 

exit gas temperatures were analyzed for 

a 12-day period that according to 

Domtar is representative of typical 

boiler operations. The consultant’s 

report indicated that furnace exit gas 

temperatures are representative of 

temperatures in the upper portion of the 

furnace, which is the optimal location 

for installation of the SNCR injection 

nozzles. The consultant estimated that 

1700–1800°F represents the temperature 

range at which SNCR can be expected 

to reach 40% control efficiency at the 

current boiler operating conditions. It 

was found that there is wide variability 

in the furnace exit gas temperatures for 

Power Boiler No. 2, with temperatures 

ranging from 1000–2000°F. The data 

also indicate that there is a direct 

positive relationship between boiler 

steam demand and furnace exit gas 

temperatures. It was also found that 

Power Boiler No. 2 operated in the 

optimal temperature zone at which 

SNCR can be expected to reach 40% 

control efficiency for only a total of 20 

hours over the 12-day period analyzed 

(288 continuous hours), which is 

approximately 7% of the time. 

According to Domtar, the significant 

temperature swings, which are due to 

load following and steam demand 

variability, create a scenario where urea 

injection will either be too high or too 

low. When not enough urea is injected, 

NOX removal will be less than projected 

and when too much urea is injected, 

excess ammonia slip will occur. Domtar 

stated that the observed significant 

temperature swings demonstrate that it 

will be difficult to maintain stable, 

optimal furnace temperatures at which 

urea can be injected to effectively 

reduce NOX with minimal ammonia 

slip. We agree that because of the wide 

variability in steam demand and wide 

range in furnace temperature observed 

at Power Boiler No. 2, the NOX control 

efficiency of SNCR at the boiler would 

not reach optimal control levels on a 

long-term basis. We also believe there is 

uncertainty as to the level of control 

efficiency that SNCR would be able to 

achieve on a long-term basis for Power 

Boiler No. 2. However, we further 

consider SNCR in the remainder of the 

analysis. 

In the 2006/2007 Domtar BART 

analysis, the capital cost, operating cost, 

and cost-effectiveness of LNB were 

estimated based on vendor estimates. 

The analysis was based on a 10-year 

amortization period, based on the 

equipment’s life expectancy. However, 

since we believe a 30-year equipment 

life is a more appropriate estimate for 

LNB, we have revised the cost estimate 

for LNB.104 The annual emissions 

reductions used in the cost-effectiveness 

calculations were determined by 

subtracting the estimated controlled 

annual emission rate from the baseline 

annual emission rate. We have also 

revised the average cost-effectiveness 

calculations presented in the 2006/2007 

Domtar BART analysis for LNB by using 

the boiler’s actual annual uncontrolled 

NOX emissions rather than the 

maximum 24-hour emission rate as the 

baseline annual emissions. The table 

below summarizes the estimated cost of 

LNB for Power Boiler No. 2, based on 

the cost estimates in the 2006/2007 

Domtar BART analysis our revisions 

discussed above. 

In Domtar’s 2014 BART analysis, the 

capital costs, operating costs, and costeffectiveness of SNCR were calculated 

based on methods and assumptions 

found in our Control Cost Manual, and 

supplemented with mill-specific cost 

information for water, fuels, and ash 

disposal and urea solution usage 

estimates from the equipment vendor. 

The two SNCR control scenarios 

evaluated were 27.5% and 35% control 

efficiencies. The capital cost was 

annualized over a 30-year period and 

then added to the annual operating cost 

to obtain the total annualized costs. The 

annual emissions reductions associated 

with each NOX control option were 

determined by subtracting the estimated 

controlled annual emission rate from 

the baseline annual emission rate. The 

baseline annual emissions used in the 

calculations are the uncontrolled actual 

emissions from the 2001–2003 baseline 

period. The average cost-effectiveness 

was calculated by dividing the total 

annual cost by the estimated annual 

NOX emissions reductions. The table 

below summarizes the cost of SNCR for 

Power Boiler No. 2. 

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Federal Register / Vol. 80, No. 67 / Wednesday, April 8, 2015 / Proposed Rules 18987 

TABLE 52—SUMMARY OF COST OF NOX CONTROLS FOR POWER BOILER NO. 2 

NOX Control scenario 

Baseline 

emission rate 

(NOX tpy) 

NOX Removal 

efficiency of 

controls 

(%) 

Annual 

emissions 

reduction 

(NOX tpy) 

Capital cost 

($) 

Total annual 

cost 

($/yr) 

Average cost 

effectiveness 

($/ton) 

Incremental costeffectiveness 

($/ton) 

SNCR—27.5% ........... 1,536 27.5 422 2,681,678 843,575 1,998 ..............................

LNB ............................ 1,536 30 461 6,131,745 899,605 1,951 1,437 

SNCR—35% .............. 1,536 35 537 2,877,523 1,026,214 1,909 1,666 

Domtar’s 2014 BART analysis did not 

identify any energy or non-air quality 

environmental impacts associated with 

the use of LNB or SNCR. We are not 

aware of any unusual circumstances at 

the facility that could create non-air 

quality environmental impacts 

associated with the operation of NOX

controls greater than experienced 

elsewhere and that may therefore 

provide a basis for the elimination of 

these control options as BART (40 CFR 

part 51, Appendix Y, section 

IV.D.4.i.2.). Therefore, we do not believe 

there are any energy or non-air quality 

environmental impacts associated with 

NOX controls at Power Boiler No. 2 that 

would affect our proposed BART 

determination. 

Consideration of the presence of 

existing pollution control technology at 

the source is reflected in the BART 

analysis in two ways: First, in the 

consideration of available control 

technologies, and second, in the 

development of baseline emission rates 

for use in cost calculations and visibility 

modeling. Power Boiler No. 2 is 

equipped with multiclones for 

particulate removal and two venturi 

scrubbers in parallel for control of SO2

emissions. It is also equipped with a 

combustion air system including 

overfire air to optimize boiler 

combustion efficiency, which also helps 

control emissions. The NOX baseline 

emission rate used in the cost 

calculations and visibility modeling 

reflects the use of these existing 

controls. 

In the 2014 BART analysis, Domtar 

assessed the visibility improvement 

associated with LNB and SNCR by 

modeling the NOX emission rates 

associated with each control option 

using CALPUFF, and then comparing 

the visibility impairment associated 

with the baseline emission rate to the 

visibility impairment associated with 

the controlled emission rates as 

measured by the 98th percentile 

modeled visibility impact. The table 

below shows a comparison of the 

baseline (i.e., existing) visibility impacts 

and the visibility impacts associated 

with LNB and SNCR. 

TABLE 53—DOMTAR ASHDOWN MILL POWER BOILER NO. 2: SUMMARY OF THE 98TH PERCENTILE VISIBILITY IMPACTS AND

IMPROVEMENT DUE TO NOX CONTROLS

Class I area 

Baseline 

visibility 

impact 

(dv) 

SNCR—27.5% Control 

efficiency 

LNB 30% Control 

efficiency 

SNCR—35% Control 

efficiency 

Visibility 

impact 

(dv) 

Visibility 

improvement 

from 

baseline 

(dv) 

Visibility 

impact 

(dv) 

Visibility 

improvement 

from 

baseline 

(dv) 

Visibility 

impact 

(dv) 

Visibility 

improvement 

from 

baseline 

(dv) 

Caney Creek ........................................ 0.844 0.678 0.166 0.663 0.181 0.632 0.212 

Upper Buffalo ....................................... 0.146 0.134 0.012 0.132 0.014 0.129 0.017 

Hercules-Glades .................................. 0.105 0.095 0.010 0.094 0.011 0.092 0.013 

Mingo ................................................... 0.065 0.060 0.005 0.060 0.005 0.059 0.006 

Cumulative Visibility Improvement (dv) .................. .................. 0.193 .................. 0.211 .................. 0.248 

The table above shows that the 

installation and operation of SNCR 

when operated at 35% control 

efficiency, if feasible, is projected to 

result in visibility improvement of 0.212 

dv at Caney Creek and 0.017 dv or less 

at each of the other Class I areas. When 

operated at 27.5% control efficiency, if 

feasible, SNCR is projected to result in 

visibility improvement of 0.166 dv at 

Caney Creek and 0.012 dv or less at each 

of the other Class I areas. The 

installation and operation of LNB is 

projected to result in visibility 

improvement of 0.181 dv at Caney Creek 

and 0.014 dv or less at each of the other 

Class I areas. 

Our Proposed NOX BART 

Determination: Taking into 

consideration the five factors, we are 

proposing to determine that NOX BART 

for the Domtar Ashdown Mill Power 

Boiler No. 2 is an emission limit of 345 

lb/hr on a 30 boiler-operating-day 

rolling averaging basis, based on the 

installation and operation of LNB. In 

this particular case, we define boileroperating-day as a 24-hour period 

between 12 midnight and the following 

midnight during which any fuel is fed 

into and/or combusted at any time in 

the Power Boiler. MdN was determined 

to be not technically feasible for use at 

Power Boiler No. 2 because it has not 

been fully demonstrated for this type of 

boiler and incorporates FGR, which is 

technically infeasible for use at the 

boiler. The installation and operation of 

SNCR is projected to result in some 

visibility improvement at the Class I 

areas when operated at 27.5% and 35% 

control efficiency. However, based on 

the information provided by the facility, 

we believe that because of the wide 

variability in steam demand and wide 

range in furnace temperature observed 

in Power Boiler No. 2, the NOX control 

efficiency of SNCR at the boiler would 

not reach optimal control levels on a 

long-term basis. There is uncertainty as 

to the level of control efficiency that 

SNCR would be able to achieve on a 

long-term basis for Power Boiler No. 2. 

The installation and operation of LNB is 

projected to result in visibility 

improvement of 0.181 dv at Caney Creek 

and 0.005–0.014 dv at each of the other 

Class I areas. The installation and 

operation of LNB is estimated to cost 

$1,951 per ton of NOX removed, which 

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18988 Federal Register / Vol. 80, No. 67 / Wednesday, April 8, 2015 / Proposed Rules 

105See letter dated October 28, 2013, from 

Thomas Rheaume, Permits Branch Manager, ADEQ, 

to Ms. Kelly Crouch, Manager of Environmental, 

Energy, and Pulp Tech. at Domtar Ashdown Mill. 

A copy of this letter is found in the docket for this 

proposed rulemaking. 

106 40 CFR part 51, Appendix Y, section IV.C. 

107The cost estimate of new add-on spray 

scrubbers and a wet ESP for Power Boiler No. 2 is 

found in Appendix B to the analysis titled 

‘‘Supplemental BART Determination Information 

Domtar A.W. LLC, Ashdown Mill (AFIN 41– 

00002),’’ dated June 28, 2013, prepared by Trinity 

Consultants Inc. in conjunction with Domtar A.W. 

LLC. A copy of the BART analysis is found in the 

docket for our proposed rulemaking. 

108The visibility impact shown represents the 

highest 98th percentile value among the three 

modeled years. 

we consider to be cost-effective. 

Therefore, we are proposing to 

determine that NOX BART for Power 

Boiler No. 2 is an emission limit of 345 

lb/hr on a 30 boiler-operating-day 

rolling average basis, based on the 

installation and operation of LNB. We 

are proposing to require compliance 

with this emission limit no later than 3 

years from the effective date of the final 

rule, and are inviting public comment 

on the appropriateness of this 

compliance date. We are proposing that 

the facility demonstrate compliance 

with this emission limit using the 

existing CEMS. We are also proposing 

regulatory text that includes monitoring, 

reporting, and recordkeeping 

requirements associated with this 

emission limit. 

e. PM BART Analysis and 

Determination for Power Boiler No. 2. 

PM BART for Power Boiler No. 2 is 

addressed in Domtar’s 2014 BART 

analysis. Power Boiler No. 2 is subject 

to the Boiler MACT standards required 

under CAA section 112, and found at 40 

CFR part 63, subpart DDDDD—National 

Emission Standards for Hazardous Air 

Pollutants for Major Sources: Industrial, 

Commercial, and Institutional Boilers 

and Process Heaters. Domtar 

streamlined the BART analysis for 

Power Boiler No. 2 by relying on the 

Boiler MACT standards for PM to satisfy 

the PM BART requirement. Power 

Boiler No. 2 was determined to fall 

under the ‘‘biomass hybrid suspension 

grate’’ subcategory for the Boiler 

MACT.105 As such, Power Boiler No. 2 

is subject to the Boiler MACT PM 

emission limit of 0.44 lb/MMBtu. The 

BART Guidelines provide that for VOC 

and PM sources subject to MACT 

standards, the BART analysis may be 

streamlined by including a discussion of 

the MACT controls and whether any 

major new technologies have been 

developed subsequent to the MACT 

standards.106 The BART Guidelines 

discuss that there are many VOC and 

PM sources that are well controlled 

because they are regulated by the MACT 

standards, and in many cases it will be 

unlikely that emission controls more 

stringent than the MACT standards will 

be identified without identifying control 

options that would cost many thousands 

of dollars per ton. Therefore, the BART 

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, the MACT standards may be 

relied on for purposes of BART. 

Domtar’s 2014 BART analysis does not 

discuss whether any new technologies 

subsequent to the MACT standards have 

become available and whether they 

would lead to cost-effective increases in 

the level of PM control for Power Boiler 

No. 2. However, Domtar at one point 

estimated the cost of installing both an 

add-on spray scrubber and wet ESP on 

Power Boiler No. 2. Based on this cost 

information previously provided by 

Domtar,107 we have determined that a 

wet ESP alone would have a purchased 

equipment cost (PEC) of $3.22 million 

and capital costs of approximately $11.3 

million. The total annual cost of a wet 

ESP alone is estimated to be 

approximately $1.96 million. The 

average annual PM emissions from 

Power Boiler No. 2 for the 2001–2003 

baseline period were 183 tpy. Assuming 

that the wet ESP has a 95% control 

efficiency for PM emissions, we 

estimate that it would remove 174 PM 

tpy. Based on this, we estimate that the 

average cost-effectiveness of installing 

and operating a wet ESP on Power 

Boiler No. 2 is $11,254 per PM ton 

removed. Additionally, an examination 

of the species contribution to the 98th 

percentile visibility impacts shows that 

PM emissions contribute a very small 

portion of the visibility impairment 

attributable to Power Boiler No. 2. As 

shown in the table below, the baseline 

visibility impairment attributable to 

Power Boiler No. 2 is 0.844 dv at Caney 

Creek and 0.146 dv or less at each of the 

other Class I areas, based on the 98th 

percentile visibility impacts. The PM 

species contribute only 1.06–4.58% of 

the baseline visibility impairment 

attributable to Power Boiler No. 2 at the 

modeled Class I areas. 

TABLE 54—BASELINE VISIBILITY IMPAIRMENT AND SPECIES CONTRIBUTION FOR DOMTAR ASHDOWN MILL—POWER BOILER

NO. 2 

Emissions unit Class I area 

98th 

Percentile 

visibility 

impacts 

(dv) 108

Species contribution to 98th percentile visibility impacts 

98th 

Percentile % 

SO4

98th 

Percentile % 

NO3

98th 

Percentile % 

PM10

98th 

Percentile % 

NO2

Power Boiler No. 2 ............. Caney Creek ...................... 0.844 22.04 70.68 4.58 2.69 

Upper Buffalo ..................... 0.146 76.99 20.76 2.26 0.00 

Hercules-Glades ................. 0.105 61.17 37.68 1.06 0.09 

Mingo .................................. 0.065 81.46 15.47 3.07 0.00 

Because of the very low baseline 

visibility impacts that are due to PM 

emissions from Power Boiler No. 2, we 

believe that there is potential for a very 

small amount of visibility improvement 

from the installation and operation of a 

wet ESP. We conclude that the 

installation and operation of a wet ESP 

for PM control is not cost-effective in 

light of the relatively small 

improvement in visibility. Therefore, we 

are proposing to find that the current 

Boiler MACT PM standard of 0.44 lb/

MMBtu satisfies the PM BART 

requirement for Power Boiler No. 2. We 

are also proposing that the same method 

for demonstrating compliance with the 

Boiler MACT PM standard is to be used 

for demonstrating compliance with the 

PM BART emission limit. Because we 

are proposing a BART emission limit 

that represents current/baseline 

operations and no control equipment 

installation is necessary, we are 

proposing that this emission limitation 

be complied with for BART purposes 

from the date of effectiveness of the 

finalized action. 

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Federal Register / Vol. 80, No. 67 / Wednesday, April 8, 2015 / Proposed Rules 18989 

109 40 CFR 51.308(d)(1)(i)(A) and CAA section 

169A(g)(1). 

110 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). 

111 Id. 

112 40 CFR 51.308(d)(1)(ii). 

113 77 FR 14604, March 12, 2012. 

114See the CENRAP TSD and the August 27, 2007 

CENRAP PSAT tool (CENRAP_PSAT_Tool_

ENVIRON_Aug27_2007.mdb). A copy of the 

CENRAP TSD and instructions for accessing the 

August 27, 2007 CENRAP PSAT tool can be found 

in the docket for this proposed rulemaking. 

IV. Our Proposed Reasonable Progress 

Analysis and Determinations 

The Regional Haze Rule does not 

mandate specific milestones or rates of 

progress towards achieving the national 

visibility goal, but instead calls for 

states to establish goals that provide for 

‘‘reasonable progress’’ toward achieving 

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

conditions. The Regional Haze Rule and 

section 169A of the CAA require the 

states, or us in the case of a FIP, to set 

RPGs by considering four factors: 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 

(collectively ‘‘the RP factors’’).109 States, 

or us in the case of a FIP, have 

considerable flexibility in how they take 

these factors into consideration, as 

noted in our Reasonable Progress 

Guidance.110 The RPGs must provide for 

an improvement in visibility on the 

most impaired days, and ensure no 

degradation in visibility on the least 

impaired days during the planning 

period.111 Furthermore, if the projected 

progress for the worst days is less than 

the Uniform Rate of Progress (URP), 

then the state or EPA must demonstrate, 

based on the factors above, that it is not 

reasonable to provide for a rate of 

progress consistent with the URP.112

In our final action on the Arkansas RH 

SIP published on March 12, 2012, we 

disapproved the RPGs established by 

Arkansas for Caney Creek and Upper 

Buffalo because Arkansas did not 

establish the RPGs in accordance with 

the requirements of the CAA and the 

RHR.113 Specifically, Arkansas did not 

take into consideration the four RP 

factors in establishing its RPGs for 

Caney Creek and Upper Buffalo, stating 

that it was an unnecessary exercise. 

Arkansas believed, incorrectly, that no 

additional analysis of potential 

reasonable progress measures was 

necessary because visibility projections 

for the Class I areas indicated 

improvements in visibility consistent 

with the URP. As discussed in our 

disapproval action, a state must 

determine whether additional control 

measures are reasonable based on a 

consideration of the four RP factors. 

Accordingly, in this proposed rule, we 

are evaluating the four RP factors to 

determine whether additional controls 

are reasonable and we are establishing 

RPGs for Caney Creek and Upper 

Buffalo after consideration of the RP 

factors. 

A. Reasonable Progress Analysis of 

Point Sources 

A discussion of the particular 

pollutants that contribute to visibility 

impairment at Arkansas’ two Class I 

areas was provided in our October 17, 

2011 proposed action on the 2008 

Arkansas RH SIP (see 76 FR 64186). In 

that proposed action, we explained that 

CENRAP used CAMx with its 

Particulate Source Apportionment 

(PSAT) tool to provide source 

apportionment by geographic region and 

major source category (i.e., point, 

natural, on-road, non-road, and area 

sources). Sulfate from all the source 

categories combined contributed 87.05 

inverse megameters (Mm¥ 1) out of 

133.93 Mm¥1 of light extinction at 

Caney Creek and 83.18 Mm¥1 out of 

131.79 Mm¥1 of light extinction at 

Upper Buffalo on the 20% worst days in 

2002, which is approximately 65% and 

63% of the total light extinction at each 

Class I area, respectively. Nitrate from 

all source categories combined 

contributed 13.78 Mm¥1 out of 133.93 

Mm¥1 of light extinction at Caney Creek 

and 13.30 Mm¥1 out of 131.79 Mm¥1

of light extinction at Upper Buffalo, 

which is approximately 10% of the total 

light extinction in 2002 on the 20% 

worst days at each Class I area. The 

source category point sources 

contributed 81.04 Mm¥1 out of 133.93 

Mm¥1 of light extinction at Caney Creek 

and 77.80 Mm¥1 out of 131.79 Mm¥1

of light extinction at Upper Buffalo on 

the 20% worst days in 2002 (see the 

tables below). This represents 

approximately 60% of the total light 

extinction at each Class I area. Each of 

the source categories other than the 

point source category, contribute a 

much smaller proportion of the total 

light extinction at each Class I area. We 

are therefore focusing only on the point 

sources category in our reasonable 

progress analysis for this regional haze 

planning period. Sulfate from point 

sources contributed 75.1 Mm¥1 out of 

133.93 Mm¥1 of light extinction at 

Caney Creek and 72.17 Mm¥1 out of 

131.79 Mm¥1 of light extinction at 

Upper Buffalo, which is approximately 

56% of the total light extinction at 

Caney Creek and 55% of the total light 

extinction at Upper Buffalo. Nitrate 

from point sources contributed 4.06 

Mm¥1 out of 133.93 Mm¥1 of light 

extinction at Caney Creek and 3.93 

Mm¥1 out of 131.79 Mm¥1 of light 

extinction at Upper Buffalo, which is 

approximately 3% of the total light 

extinction at each Class I area. On the 

20% worst days in 2002, sulfate from 

Arkansas point sources contributed 

2.20% of the total light extinction at 

Caney Creek and 1.99% at Upper 

Buffalo, and nitrate from Arkansas point 

sources contributed 0.27% of the total 

light extinction at Caney Creek and 

0.14% at Upper Buffalo.114 For both 

Caney Creek and Upper Buffalo, SO2

emissions (sulfate precursor) are the 

principal driver of regional haze on the 

20% worst days in Arkansas’ Class I 

areas, as visibility impairment in 2002 

on the 20% worst days is largely due to 

sulfate from point sources. 

TABLE 55—MODELED BASELINE 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 

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18990 Federal Register / Vol. 80, No. 67 / Wednesday, April 8, 2015 / Proposed Rules 

115See the CENRAP TSD and the August 27, 2007 

CENRAP PSAT tool (CENRAP_PSAT_Tool_

ENVIRON_Aug27_2007.mdb). A copy of the 

CENRAP TSD and instructions for accessing the 

August 27, 2007 CENRAP PSAT tool can be found 

in the docket for this proposed rulemaking. 

TABLE 55—MODELED BASELINE LIGHT EXTINCTION FOR 20% WORST DAYS AT CANEY CREEK WILDERNESS AREA IN 2002 

(MM¥1)—Continued 

Total 1 Point Natural On-road Non-road Area 

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

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

TABLE 56—MODELED BASELINE LIGHT EXTINCTION FOR 20% 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. Sums include secondary organic matter. 

The CENRAP’s 2018 visibility 

projections show the total extinction at 

Caney Creek for the 20% worst days is 

estimated to be 85.84 Mm¥1, which is 

a reduction of approximately 36% from 

2002 levels (see table below). The total 

extinction at Upper Buffalo for the 20% 

worst days in 2018 is estimated to be 

86.16 Mm¥1, which is a reduction of 

approximately 35% from 2002 levels 

(see the table below).Sulfate from all 

source categories combined is projected 

to contribute 48.95 Mm¥1 out of 85.84 

Mm¥1 of light extinction at Caney Creek 

on the 20% worst days in 2018, or 

approximately 57% of the total light 

extinction. Nitrate from all source 

categories combined is projected to 

contribute 7.57 Mm¥1 out of 85.84 

Mm¥1 of light extinction at Caney Creek 

on the 20% worst days in 2018, or 

approximately 9% of the total light 

extinction. The other source categories 

are each projected to continue 

contributing a much smaller proportion 

of the total light extinction at each Class 

I area. At Upper Buffalo, sulfate from all 

source categories combined is projected 

to contribute 45.38 Mm¥1 out of 86.16 

Mm¥1 of light extinction on the 20% 

worst days in 2018, which is 

approximately 53% of the total light 

extinction. Nitrate from all source 

categories combined is projected to 

contribute 9.22 Mm¥1 out of 86.16 

Mm¥1 of light extinction on the 20% 

worst days at Upper Buffalo, which is 

approximately 11% of the total light 

extinction. Sulfate from point sources is 

projected to contribute 39.83 Mm¥1 out 

of 85.84 Mm¥1 of light extinction at 

Caney Creek on the 20% worst days in 

2018, or approximately 46% of the total 

light extinction. Nitrate from point 

sources is projected to contribute 2.84 

Mm¥1 out of 85.84 Mm¥1 of light 

extinction at Caney Creek on the 20% 

worst days, which is approximately 3% 

of the total light extinction. At Upper 

Buffalo, sulfate from point sources is 

projected to contribute 37.09 Mm¥1 out 

of 86.16 Mm¥1 of light extinction on the 

20% worst days in 2018, which is 

approximately 43% of the total light 

extinction. On the 20% worst days in 

2018, sulfate from Arkansas point 

sources is projected to contribute 3.58% 

of the total light extinction at Caney 

Creek and 3.20% at Upper Buffalo, and 

nitrate from Arkansas point sources is 

projected to contribute 0.29% of the 

total light extinction at Caney Creek and 

0.25% at Upper Buffalo.115 Based on the 

2018 visibility projections, sulfate from 

point sources is expected to continue 

being the principal driver of regional 

haze on the 20% worst days at Arkansas 

Class I areas. 

TABLE 57—MODELED FUTURE 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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Federal Register / Vol. 80, No. 67 / Wednesday, April 8, 2015 / Proposed Rules 18991 

116See NEI 2011 v1. A spreadsheet containing the 

emissions inventory is found in the docket for our 

proposed rulemaking. 

TABLE 58—MODELED FUTURE 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. 

As a starting point in our analysis to 

determine whether additional controls 

on Arkansas sources are reasonable in 

the first regional haze planning period, 

we examined the most recent SO2 and 

NOX emissions inventories for point 

sources in Arkansas. Based on the 2011 

National Emissions Inventory (NEI), the 

Entergy White Bluff Plant, the Entergy 

Independence Plant, and the AEP Flint 

Creek Power Plant are the three largest 

point sources of SO2 and NOx emissions 

in Arkansas (see table below).116 The 

combined annual emissions from these 

three sources make up approximately 

84% of the statewide SO2 point-source 

emissions and 55% of the statewide 

NOX point-source emissions. We have 

evaluated White Bluff Units 1 and 2 and 

Flint Creek Unit 1 for controls under 

BART and are proposing to require 

these units to install SO2 and NOX

controls to meet the BART 

requirements. We believe that our fivefactor BART analysis for these three 

units is adequate for this first planning 

period to eliminate these sources from 

further consideration of controls under 

the reasonable progress requirements for 

this first regional haze planning period. 

Compliance with the BART 

requirements is anticipated to result in 

a substantial reduction in SO2 and NOX

emissions from these two facilities. The 

Entergy Independence Plant is not 

subject to BART, but its emissions were 

30,398 SO2 tpy and 13,411 NOX tpy 

based on the 2011 NEI. The Entergy 

Independence Plant is the second 

largest source of SO2 and NOX pointsource emissions in Arkansas, 

accounting for approximately 36% of 

the SO2 point-source emissions and 

21% of the NOX point-source emissions 

in the State. Additionally, as we discuss 

in more detail in the proceeding 

subsection, the White Bluff and 

Independence Plants are sister facilities 

with nearly identical units. Based on 

this, we expect that the costeffectiveness of controls will be very 

similar for the two facilities. 

TABLE 59—TEN LARGEST SO2 AND NOX POINT SOURCES IN ARKANSAS (NEI 2011 V1) 

Facility name County 

NEI 2011 v1 Emissions 

(tpy) 

SO2 NOX

Entergy Arkansas—White Bluff ................................................................................ Jefferson ........................... * 31,684 * 16,013 

Entergy-Services Inc—Independence Plant ............................................................ Independence ................... 30,398 13,411 

Flint Creek Power Plant (SWEPCO) ....................................................................... Benton ............................... * 8,620 * 5,326 

FutureFuel Chemical Company ............................................................................... Independence ................... 3,421 385 

Plum Point Energy Station Unit 1 ............................................................................ Mississippi ......................... 2,830 1,525 

Evergreen Packaging—Pine Bluff ............................................................................ Jefferson ........................... 1,755 1,010 

Domtar A.W. LLC, Ashdown Mill ............................................................................. Little River ......................... * 1,603 * 3,152 

Albemarle Corporation—South Plant ....................................................................... Columbia ........................... 1,279 443 

Nucor-Yamato Steel Company ................................................................................ Mississippi ......................... 607 263 

Ash Grove Cement Company .................................................................................. Little River ......................... 440 1,081 

Georgia-Pacific LLC—Crossett Paper ..................................................................... Ashley ............................... 215 2,402 

Marion Intermodal .................................................................................................... Crittenden .......................... 12 1,328 

Natural Gas Pipeline Co of America #308 .............................................................. Randolph ........................... 0.4 3,194 

Natural Gas Pipeline Co of America #307 .............................................................. White ................................. 0.4 2,941 

Natural Gas Pipeline Co of America #305 .............................................................. Miller .................................. 0.3 1,731 

* Proposed FIP controls under BART requirements will result in emission reductions. 

Because in our March 12, 2012 final 

partial approval and partial disapproval 

of the 2008 Arkansas RH SIP we made 

a finding that Arkansas did not 

complete a reasonable progress analysis 

and did not properly demonstrate that 

additional controls were not reasonable 

under 40 CFR 51.308(d)(1)(i)(A) and we 

disapproved the RPGs it established for 

Caney Creek and Upper Buffalo, we are 

required to complete the reasonable 

progress analysis and establish revised 

RPGs, unless we first approve a SIP 

revision that corrects the disapproved 

portions of the SIP submittal. As 

Arkansas has not as yet submitted a 

revised SIP following our partial 

disapproval, we must now complete the 

reasonable progress analysis and 

establish revised RPGs for Caney Creek 

and Upper Buffalo. We believe it is 

appropriate that our evaluation of the 

reasonable progress factors focuses on 

the Entergy Independence Power Plant 

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117See 64 FR 35732. 

118While visibility is not an explicitly listed 

factor to consider when determining whether 

additional controls are reasonable, the purpose of 

the four-factor analysis is to determine what degree 

of progress toward natural visibility conditions is 

reasonable. Therefore, it is appropriate to consider 

the projected visibility benefit of the controls when 

determining if the controls are needed to make 

reasonable progress. 

119This spreadsheet, entitled ‘‘EIA Consolidated 

Data_WB and Ind_Y2012.xlsx,’’ is located in the 

docket for our proposed rulemaking. 

120See ‘‘EIA Consolidated Data_WB and IND_

Y2012.xlsx.’’ 

121See ‘‘Technical Support Document for the 

SDA Control Cost Analysis for the Entergy White 

Bluff and Independence Facilities Arkansas 

Regional Haze Federal Implementation Plan (SO2

Cost TSD),’’ Figures 1 and 2. 

122See ‘‘Technical Support Document for the 

SDA Control Cost Analysis for the Entergy White 

Bluff and Independence Facilities Arkansas 

Regional Haze Federal Implementation Plan (SO2

Cost TSD).’’ A copy of this TSD is found in the 

docket for our proposed rulemaking. 

123Baseline emissions were determined by 

examining annual SO2 emissions for the years 

2009–2013, eliminating the year with the highest 

emissions and the year with the lowest emissions, 

and obtaining the average of the three remaining 

years. 

because it is a significant source of SO2

and NOX, as it is the second largest 

point source for both NOX and SO2

point source emissions in the State. 

We believe it is appropriate to 

evaluate Entergy Independence even 

though Arkansas Class I areas and those 

outside of Arkansas most significantly 

impacted by Arkansas sources are 

projected to meet the URP for the first 

planning period. This is because we 

believe that in determining whether 

reasonable progress is being achieved, it 

would be unreasonable to ignore a 

source representing more than a third of 

the State’s SO2 emissions and a 

significant portion of NOX point source 

emissions. The preamble to the Regional 

Haze Rule also states that the URP does 

not establish a ‘‘safe harbor’’ for the 

state in setting its progress goals.117 If 

the state determines that the amount of 

progress identified through the URP 

analysis is reasonable based upon the 

statutory factors, the state, or us in the 

case of a FIP, 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 or we 

determine that additional progress is 

reasonable based on the statutory 

factors, that amount of progress should 

be adopted as the goal for the first longterm strategy. 

In this proposed rulemaking, we are 

proposing controls for the largest and 

third largest point sources for both NOX

and SO2 emissions in Arkansas under 

the BART requirements. As these two 

BART sources combined with 

Independence make up a large majority 

of the SO2 point source emissions (84%) 

and a large proportion of the NOX point 

source emissions (55%) in Arkansas, we 

believe that a sufficient amount of point 

source emissions in the State would be 

addressed in this first regional haze 

planning period by addressing the 

Independence facility in our reasonable 

progress analysis, which as we note 

above is the second largest source of 

both SO2 and NOX. We are proposing 

under Option 1 to control Entergy 

Independence for the first planning 

period for both SO2 and NOX. 

Alternatively, under Option 2, for the 

first planning period, we are proposing 

to control Entergy Independence only 

for SO2. The fourth largest SO2 and NOX

point sources in Arkansas are the Future 

Fuel Chemical Company, with 

emissions of 3,421 SO2 tpy, and the 

Natural Gas Pipeline Company of 

America #308, with emissions of 3,194 

NOX tpy (2011 NEI). In comparison to 

the emissions of the top three sources, 

emissions from these two facilities are 

relatively small. Therefore, we are not 

proposing controls in this first planning 

period for these two facilities because 

we believe it is appropriate to defer the 

consideration of any additional sources 

besides Independence to future regional 

haze planning periods. For 

Independence, however, under Option 

1, in combination with the BART 

sources we would be addressing 84% of 

the SO2 point source emissions in the 

State and over 55% of the NOX point 

source emissions. Under Option 2, we 

would be deferring the consideration of 

additional NOX controls to future 

regional haze planning periods. In the 

next section, we describe our 

consideration of the four reasonable 

progress factors for the Entergy 

Independence Plant as well as the 

CALPUFF modeling we conducted to 

assess the potential visibility benefits of 

controls.118

1. Entergy Independence Plant Units 1 

and 2 

a. Reasonable Progress Analysis for 

SO2 Controls—Costs of Compliance: The 

Entergy Independence Plant is an 

electric generating station with two 

nearly identical coal-fired units (Units 1 

and 2) with a nameplate capacity of 900 

MW each. Units 1 and 2 are 

tangentially-fired boilers that burn subbituminous coal as their primary fuel 

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

start-up fuel. To verify that the White 

Bluff and Independence Plants are sister 

facilities, we have constructed a master 

spreadsheet 119 that contains 

information concerning ownership, 

location, boiler type, environmental 

controls and other pertinent information 

on these facilities. The spreadsheet 

includes information contained within 

EIA Forms 860 and 923. According to 

EIA,120 the boilers were manufactured 

by Combustion Engineering with 

installation dates of 1974 for White 

Bluff, and 1983 and 1984 for 

Independence. The two units at White 

Bluff and the two units at Independence 

are tangentially firing boilers having 

nameplate capacities of 900 MW and 

similar gross ratings. All four units burn 

coal from the Powder River Basin (PRB) 

of Wyoming with similar characteristics. 

All four units employ cold side ESPs for 

particulate collection. Other pertinent 

characteristics are similar. The layout of 

the White Bluff and Independence 

facilities are also very similar.121 Due to 

the similarity of these facilities, we 

applied the total annualized dry FGD 

and wet FGD costs we developed for the 

White Bluff units to the Independence 

units. However, we adjusted the costeffectiveness ($/ton) due to the differing 

baseline SO2 emissions from the units. 

Consistent with the cost estimate we 

developed for White Bluff, we estimated 

a total annual cost for dry FGD at 

Independence of approximately 

$31,981,230 at each unit.122 We expect 

dry FGD to achieve a controlled 

emission level of 0.06 lb/MMBtu, and 

estimate that the annual emissions 

reductions at Unit 1 would be 12,912 

SO2 tpy, assuming baseline 

emissions 123 of 14,269 SO2 tpy (see 

table below). The average costeffectiveness of dry FGD at Unit 1 is 

estimated to be $2,477 per SO2 ton 

removed. For Unit 2, we estimate that 

the annual emissions reductions would 

be 13,990 SO2 tpy, assuming baseline 

emissions of 15,511 SO2 tpy. The 

average cost-effectiveness of dry FGD at 

Unit 2 is estimated to be $2,286 per SO2

ton removed. 

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124See our discussion above of the cost analysis 

for SO2 BART for White Bluff Units 1 and 2, under 

section III.C.4 of this proposed rulemaking. 

125See our Cost Analysis TSD titled ‘‘Technical 

Support Document for the SDA Control Cost 

Analysis for the Entergy White Bluff and 

Independence Facilities Arkansas Regional Haze 

Federal Implementation Plan (SO2 Cost TSD).’’ The 

TSD is found in the docket for our proposed 

rulemaking. 

126Baseline emissions were determined by 

examining annual SO2 emissions for the years 

2009–2013, eliminating the year with the highest 

emissions and the year with the lowest emissions, 

and obtaining the average of the three remaining 

years. 

127As we note in our Oklahoma FIP, we typically 

assume a 30 year equipment life for scrubbers, as 

we do here. Please see Response to Technical 

Comments for Sections E. through H. of the Federal 

Register Notice for the Oklahoma Regional Haze 

and Visibility Transport Federal Implementation 

Plan, Docket No. EPA–R06–OAR–2010–0190. Page 

35. 

128See 79 FR at 74838, 74840, and 74874. 

129See Appendix C to the TSD, titled ‘‘Technical 

Support Document for Visibility Modeling Analysis 

for Entergy Independence Generating Station,’’ for 

a detailed discussion of the visibility modeling 

protocol and model inputs. A copy of the TSD and 

its appendices is found in the docket for this 

proposed rulemaking. 

TABLE 60—SUMMARY OF DRY FGD COSTS FOR ENTERGY INDEPENDENCE UNITS 1 AND 2 

Unit 

Baseline emission 

rate 

(SO2 tpy) 

Controlled 

emission level 

(lb/MMBtu) 

Annual emissions 

reductions 

(SO2 tpy) 

Total annual cost 

($/yr) 

Average cost 

effectiveness 

($/ton) 

Unit 1 ..................................................... 14,269 0.06 12,912 $31,981,230 $2,477 

Unit 2 ..................................................... 15,511 0.06 13,990 31,981,230 2,286 

Because our proposed BART 

determination for the White Bluff 

facility is that dry FGD is more costeffective (lower $/ton) than wet FGD, 

and that the additional visibility 

benefits obtained as a result of the 

greater level of control wet FGD offers 

over dry FGD are not worth the 

additional cost of wet FGD, we expect 

that the same would apply to 

Independence Units 1 and 2. Therefore, 

our evaluation of SO2 controls for 

Independence Units 1 and 2 focuses on 

dry FGD. Nevertheless, we have 

calculated the cost-effectiveness of wet 

FGD for Independence Units 1 and 2 

using the total annualized cost estimate 

provided by Entergy for White Bluff 

Units 1 and 2, with certain adjustments 

we made to the cost estimate provided 

by the facility.124 Consistent with our 

estimate for White Bluff, we estimated 

a total annual cost for wet FGD at 

Independence of approximately 

$49,526,167 at each unit.125 We expect 

wet FGD to achieve a controlled 

emission level of 0.04 lb/MMBtu, and 

estimate that the annual emissions 

reductions at Unit 1 would be 13,364 

SO2 tpy, assuming baseline 

emissions 126 of 14,269 SO2 tpy (see 

table below). The average costeffectiveness of wet FGD at Unit 1 is 

estimated to be $3,706 per SO2 ton 

removed. For Unit 2, we estimate that 

the annual emissions reductions would 

be 14,497 SO2 tpy, assuming baseline 

emissions of 15,511 SO2 tpy. The 

average cost-effectiveness of wet FGD at 

Unit 2 is estimated to be $3,416 per SO2

ton removed. 

TABLE 61—SUMMARY OF WET FGD COSTS FOR ENTERGY INDEPENDENCE UNITS 1 AND 2 

Unit 

Baseline emission 

rate 

(SO2 tpy) 

Controlled 

emission level 

(lb/MMBtu) 

Annual emissions 

reductions 

(SO2 tpy) 

Total annual cost 

($/yr) 

Average cost 

effectiveness 

($/ton) 

Unit 1 ..................................................... 14,269 0.04 13,463 $49,526,167 $3,706 

Unit 2 ..................................................... 15,511 0.04 14,532 49,526,167 3,416 

Time Necessary for Compliance: As is 

generally the case for installation of 

scrubber controls on EGUs, we expect 

that 5 years from the date of our final 

action would be sufficient time for 

Independence to install and operate 

either dry or wet FGD controls at Units 

1 and 2 and to comply with the 

associated emission limits. 

Energy and Non-Air Quality 

Environmental Impacts of Compliance: 

The installation and operation of wet 

FGD at Independence Units 1 and 2 

would require greater energy usage and 

reagent usage compared to dry FGD. The 

cost of this additional energy usage and 

reagent usage has already been factored 

into the cost analysis. Non-air quality 

environmental impacts associated with 

wet FGD systems include increased 

water usage and the generation of large 

volumes of wastewater and solid waste/ 

sludge that must be treated or stabilized 

before landfilling. Because the facility is 

not located in an exceptionally arid 

region, we do not anticipate that there 

would be water-availability issues that 

would affect the feasibility of wet FGD. 

Lastly, wet FGD systems have the 

potential for increased particulate and 

sulfuric acid mist releases that 

contribute to regional haze, which we 

are taking into consideration through an 

evaluation of the visibility benefits of 

each control option. 

Remaining Useful Life: Independence 

Units 1 and 2 were installed in 1983 and 

1984. Unit 1 was placed into operation 

in 1983 and Unit 2 was placed into 

operation in 1985. As there is no 

enforceable shut-down date for Units 1 

and 2, we assume an equipment life of 

30 years.127

Degree of Improvement in Visibility: 

While visibility is not an explicitly 

listed factor to consider when 

determining whether additional controls 

are reasonable under the reasonable 

progress requirements, the purpose of 

the four-factor analysis is to determine 

what degree of progress toward natural 

visibility conditions is reasonable. 

Therefore, it is appropriate to consider 

the projected visibility benefit of the 

controls when determining if the 

controls are needed to make reasonable 

progress.128 There are four Class I areas 

within 300 km of the Entergy 

Independence Plant. We conducted 

CALPUFF modeling to determine the 

visibility improvement of SO2 controls 

at these Class I areas, based on the 98th 

percentile visibility impacts.129 As 

shown in the tables below, both dry 

FGD and wet FGD are projected to result 

in considerable visibility improvement 

from the baseline at each modeled Class 

I area. For Unit 1, dry FGD is projected 

to result in almost 0.5 dv of visibility 

improvement at each modeled Class I 

area, and for Unit 2 it is projected to 

result in almost or slightly greater than 

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0.5 dv of visibility improvement at each 

Class I area. The incremental visibility 

improvement of wet FGD over dry FGD 

is projected to be minimal, ranging from 

0.008–0.028 dv at each Class I area for 

Unit 1 and 0.009–0.022 dv for Unit 2. 

TABLE 62—ENTERGY INDEPENDENCE UNIT 1: EPA MODELED 98TH PERCENTILE VISIBILITY IMPACTS OF SO2 CONTROLS

Class I area Distance 

(km) 

Visibility impact 

(Ddv) 

Visibility improvement over 

baseline 

(dv) 

Incremental 

visibility improvement 

of wet FGD 

vs. dry FGD Baseline Dry FGD Wet FGD Dry FGD Wet FGD 

Caney Creek ............................................ 277 1.133 0.657 0.64 0.476 0.493 0.017 

Upper Buffalo ........................................... 180 0.845 0.385 0.377 0.460 0.468 0.008 

Hercules-Glades ...................................... 173 0.793 0.295 0.267 0.498 0.526 0.028 

Mingo ....................................................... 174 0.739 0.298 0.284 0.441 0.455 0.014 

Total .................................................. .................... 3.51 1.635 1.568 1.875 1.942 0.067 

TABLE 63—ENTERGY INDEPENDENCE UNIT 2: EPA MODELED 98TH PERCENTILE VISIBILITY IMPACTS OF SO2 CONTROLS

Class I area Distance 

(km) 

Visibility impact 

(Ddv) 

Visibility improvement over 

baseline 

(dv) 

Incremental 

visibility improvement 

of wet FGD 

vs. dry FGD Baseline Dry FGD Wet FGD Dry FGD Wet FGD 

Caney Creek ............................................ 277 1.412 0.865 0.843 0.547 0.569 0.022 

Upper Buffalo ........................................... 180 0.997 0.509 0.499 0.488 0.498 0.01 

Hercules-Glades ...................................... 173 0.977 0.364 0.355 0.613 0.622 0.009 

Mingo ....................................................... 174 0.883 0.388 0.374 0.495 0.509 0.014 

Total .................................................. .................... 4.269 2.126 2.071 2.143 2.198 0.055 

TABLE 64—ENTERGY INDEPENDENCE: EPA MODELED 98TH PERCENTILE VISIBILITY IMPACTS OF SO2 CONTROLS

(FACILITY-WIDE) 

Class I area Distance 

(km) 

Visibility impact 

(Ddv) 

Visibility improvement over 

baseline 

(dv) 

Incremental 

visibility improvement 

of wet FGD 

vs. dry FGD Baseline Dry FGD Wet FGD Dry FGD Wet FGD 

Caney Creek ............................................ 277 2.412 1.474 1.442 0.938 0.97 0.032 

Upper Buffalo ........................................... 180 1.764 0.876 0.86 0.888 0.904 0.016 

Hercules-Glades ...................................... 173 1.704 0.648 0.608 1.056 1.096 0.04 

Mingo ....................................................... 174 1.547 0.676 0.649 0.871 0.898 0.027 

Total .................................................. .................... 7.427 3.674 3.559 3.753 3.868 0.115 

Proposed RP Determination for SO2: 

Based on our analysis of the four RP 

factors, as well as the considerable 

projected visibility improvement, we 

propose to require compliance with an 

emission limit of 0.06 lb/MMBtu for 

Independence Units 1 and 2 based on a 

30 boiler-operating-day rolling average 

basis. We propose to find that this 

emission limit, which is based on the 

installation and operation of dry FGD, is 

cost-effective at $2,477 per SO2 ton 

removed for Unit 1 and $2,286 per SO2

ton removed for Unit 2, and would 

result in significant visibility benefits at 

the Caney Creek and Upper Buffalo 

Wilderness Areas and the two Class I 

areas in Missouri. Under either Option 

1 or 2, we are proposing SO2 controls on 

Independence Units 1 and 2 for the first 

planning period. We note that more 

recent emission data show an overall 

increase in SO2 emissions from the 

facility. Therefore anticipated visibility 

improvement from controls would be 

anticipated to be larger and the $/SO2

ton reduced would be smaller had we 

used a more recent time period for the 

baseline emissions modeled. We found 

that in this instance, the cost of wet FGD 

on a dollars per ton removed basis is 

higher than that of dry FGD. We found 

the cost of wet FGD to be $3,706 and 

$3,416 per ton of SO2 removed at Units 

1 and 2, respectively. We found the cost 

of dry FGD to be $2,477 and $2,286 per 

ton of SO2 removed for Units 1 and 2, 

respectively. We do not believe that the 

minimal amount of incremental 

visibility improvement projected to 

result from wet FGD justifies the higher 

cost compared to dry FGD. We are 

proposing to require compliance with 

an emission limit of 0.06 lb/MMBtu 

based on a 30 boiler-operating-day 

rolling average basis for Independence 

Units 1 and 2 no later than 5 years from 

the effective date of the final rule, based 

on the installation and operation of dry 

FGD. We are proposing that the facility 

demonstrate compliance with this 

emission limit using the existing CEMS. 

We are also proposing regulatory text 

that includes monitoring, reporting, and 

recordkeeping requirements associated 

with this emission limit. 

b. Reasonable Progress Analysis for 

NOX controls. As noted previously, 

monitoring data as well as CENRAP’s 

CAMx source apportionment modeling 

results for 2002 and 2018 show that 

visibility impairment is not projected to 

be significantly impacted by nitrate on 

the 20% worst days at Caney Creek or 

Upper Buffalo. Point source emissions 

of NOX are projected to contribute to 

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130 70 FR 39104. 

131Emissions used in CALPUFF modeling 

represented the maximum 24-hour emission rate. 

Based on evaluation of some sources that had both 

annual and maximum 24-hour actual data, EPA 

recommended that sources could use an emission 

rate that was double the annual emission rate (used 

in CAMx) to approximate the maximum 24-hour 

actual emission rates for some sources for 

CALPUFF modeling when there was not enough 

data to generate a maximum 24-hr actual emission 

rate. 

132See our discussion above of the cost analysis 

for NOX BART for White Bluff Units 1 and 2, under 

section III.C.4 of this proposed rulemaking. 

133See the spreadsheet titled ‘‘Independence Cost 

Spreadsheet_LNB–SOFA.’’ A copy of this 

spreadsheet is found in the docket for our proposed 

rulemaking. 

134Baseline emissions were determined by 

examining annual NOX emissions for the years 

2009–2013, eliminating the year with the highest 

emissions and the year with the lowest emissions, 

and obtaining the average of the three remaining 

years. 

less than 5% of the total impairment on 

the 20% worst days in both 2002 and 

2018. The CENRAP CAMx source 

apportionment modeling does not 

provide visibility impairment estimates 

for individual facilities. 

As part of our analysis for 

Independence, we performed modeling 

using CALPUFF to assess the facility’s 

individual visibility impact and the 

visibility benefit of controls, as was 

done for the subject-to-BART units 

discussed above including the sister 

facility, White Bluff. CALPUFF is the 

recommended model 130 for visibility 

impact analysis for BART 

determinations and other single source 

visibility modeling where the Class I 

areas of interest are within 300 km of 

the source. This modeling provided 

information on the total visibility 

impairment from emissions from the 

source, including impacts from SO2 and 

NOX emissions. The primary goal of this 

modeling was to assess the potential 

visibility benefit of SO2 controls, given 

the relatively large emissions of SO2

from the facility and that SO2 emissions 

are the primary cause of visibility 

impairment on the 20% worst days at 

the Class I areas of interest. The results 

of this analysis of SO2 controls are 

discussed in the section above. These 

CALPUFF results also indicated that 

impacts from NOX emissions can be 

significant on some days, and as 

discussed further below, NOX emission 

controls can be anticipated to result in 

a sizeable reduction in the maximum 

impacts from the facility. The analysis 

of the sister facility, Entergy 

Independence, revealed similar results. 

In evaluating CALPUFF modeling 

results for BART, the 98th percentile 

ranked impact (H8H) was used 

consistent with our guideline 

techniques in conducting the CALPUFF 

modeling. CALPUFF modeling provides 

an assessment of the near maximum 

(98th percentile) visibility impairment 

on nearby Class I areas from the source 

of interest based on the facility’s 

maximum short term emissions 

modeled over a three year period. It is 

important to note that a specific 

facility’s maximum impact on a Class I 

area may not correlate with the same 

meteorological conditions or days when 

visibility is most impaired at a 

particular Class I area since CALPUFF 

modeling is only for one facility and 

does not include other facilities and 

emissions sources. Because of the nature 

of visibility impairment, we consider it 

appropriate to assess visibility impacts 

from a single source against a natural 

background. Visibility impairment on 

the 20% worst days may be driven by 

impacts from other facilities and 

different meteorological conditions. 

Identification of the 20% worst days is 

determined by IMPROVE monitor data 

during the baseline period at each Class 

I area. The source apportionment results 

for the 20% worst days are then based 

on CAMx modeling using a single year 

of meteorological data (2002) and using 

estimates of actual emissions from 2002 

and projected to 2018 for all emission 

sources in the modeling domain 

(continental U.S.). Due in large part to 

the difference in metrics between the 

maximum impact as modeled by 

CALPUFF and the average impact 

during the 20% worst days, the 

CALPUFF modeling results discussed 

below indicate a more significant 

impact than suggested by the source 

apportionment CAMx results. We also 

note that differences in the metrics 

examined (maximum 98th percentile 

impact versus average impact during the 

20% worst days), emissions modeled 

(single–source maximum 24-hour actual 

emissions versus actual emissions from 

all emission sources 131), and differences 

in chemistry models result in CAMx 

visibility analysis results for a source or 

group of sources being much lower in 

magnitude than visibility impacts as 

modeled by CALPUFF. 

The single source CALPUFF modeling 

shows that sizeable reductions to the 

maximum 98th percentile visibility 

impact from the Independence facility 

may be achieved through NOX controls. 

We recognize, however, that at this 

time, point source NOX emissions are 

not the main contributors to visibility 

impairment on the 20% worst days at 

Arkansas’ Class I areas, as projected by 

CAMx source apportionment modeling. 

Also, Arkansas Class I areas are 

projected to achieve progress greater 

than that needed to meet the URP. 

Because our assessment of the 

Independence facility indicates that it is 

potentially one of the largest single 

contributors to visibility impairment at 

Class I areas in Arkansas, we believe 

that it is appropriate to evaluate the 

appropriateness of NOX controls during 

this planning period. 

As discussed above, due to the 

similarity of these facilities, we applied 

the total annualized LNB/SOFA cost 

developed by Entergy for White Bluff 

Units 1 and 2, with one line item 

revision made by us, to Independence 

Units 1 and 2.132 However, we adjusted 

the cost-effectiveness ($/ton) due to the 

differing NOX emissions from the units. 

Since our proposed BART 

determination for the White Bluff 

facility is that LNB/SOFA is more cost 

effective (lower $/ton) than SNCR or 

SCR, and that the additional visibility 

benefits obtained as a result of the 

greater level of control SNCR and SCR 

offer over combustion controls are not 

worth the additional cost of SNCR or 

SCR, we expect that the same would 

apply to Independence Units 1 and 2. 

Therefore, our evaluation of NOX

controls for Independence Units 1 and 

2 will focus solely on LNB/SOFA. 

Consistent with the cost estimate 

developed for White Bluff, we estimated 

a total annual cost for LNB/SOFA at 

Independence of approximately 

$1,085,904 at Unit 1 and $1,403,376 at 

Unit 2.133 We expect LNB/SOFA to 

achieve a controlled emission level of 

0.15 lb/MMBtu, and estimate that the 

annual emissions reductions at Unit 1 

would be 2,710 NOX tpy, assuming 

baseline emissions 134 of 6,329 NOX tpy 

(see table below). The average costeffectiveness of LNB/SOFA at Unit 1 is 

estimated to be $401 per NOX ton 

removed. For Unit 2, we estimate that 

the annual emissions reductions would 

be 3,217 NOX tpy, assuming baseline 

emissions of 6,384 NOX tpy. The 

average cost-effectiveness of LNB/SOFA 

at Unit 2 is estimated to be $436 per 

NOX ton removed. 

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135See 79 FR at 74838, 74840, and 74874. 

136See Appendix C to the TSD, titled ‘‘Technical 

Support Document for Visibility Modeling Analysis 

for Entergy Independence Generating Station,’’ for 

a detailed discussion of the visibility modeling 

protocol and model inputs. A copy of the TSD and 

its appendices is found in the docket for this 

proposed rulemaking. 

137 Id. 

138This is discussed in more detail in Appendix 

C to the TSD, titled ‘‘Technical Support Document 

for Visibility Modeling Analysis for Entergy 

Independence Generating Station.’’ 

139Baseline NOX emissions were updated to the 

maximum 24-hr emissions from 2011–2013 for the 

evaluation of the anticipated benefit from NOX

controls. 

TABLE 65—SUMMARY OF LNB/SOFA COSTS FOR ENTERGY INDEPENDENCE UNITS 1 AND 2 

Unit Baseline emission rate 

(NOX tpy) 

Controlled emission 

level 

(lb/MMBtu) 

Annual emissions 

reductions 

(NOX tpy) 

Total annual cost 

($/yr) 

Average cost 

effectiveness 

($/ton) 

Unit 1 6,329 0.15 2,710 $1,085,904 $401 

Unit 2 6,384 0.15 3,217 1,403,376 436 

Time Necessary for Compliance: As is 

generally the case for installation of 

NOX controls on EGUs, we expect that 

3 years from the date of our final action 

would be sufficient time for 

Independence to install and operate 

LNB/SOFA controls at Units 1 and 2 

and to comply with the associated 

emission limits. 

Energy and Non-Air Quality 

Environmental Impacts of Compliance: 

We are not aware of any energy or nonair quality environmental impacts that 

would preclude LNB/SOFA from 

consideration at Independence Units 1 

and 2. 

Remaining Useful Life: Independence 

Units 1 and 2 were installed in 1983 and 

1984. Unit 1 was placed into operation 

in 1983 and Unit 2 was placed into 

operation in 1985. As there is no 

enforceable shut-down date for Units 1 

and 2, we presume that the units would 

continue to operate for greater than 30 

years and fully amortize the cost of 

controls. In our analysis of the cost of 

controls we have assumed an equipment 

life of 30 years. 

Degree of Improvement in Visibility: 

While visibility is not an explicitly 

listed factor to consider when 

determining whether additional controls 

are reasonable under the reasonable 

progress requirements, the purpose of 

the four-factor analysis is to determine 

what degree of progress toward natural 

visibility conditions is reasonable. 

Therefore, it is appropriate to consider 

the projected visibility benefit of the 

controls when determining if the 

controls are needed to make reasonable 

progress.135 There are four Class I areas 

within 300 km of the Entergy 

Independence Plant. We conducted 

CALPUFF modeling to determine the 

visibility improvement of NOX controls 

at these Class I areas, based on the 98th 

percentile visibility impacts.136 As 

shown in the table below, LNB/SOFA is 

projected to result in a visibility 

improvement from the baseline at each 

modeled Class I area.137 On a facilitywide basis, the installation and 

operation of LNB/SOFA on Units 1 and 

2 is projected to result in 0.461 dv in 

visibility improvement at Caney Creek, 

while the projected visibility 

improvement at each of the other 

modeled Class I areas ranges from 

0.213–0.264 dv. We also conducted a 

modeling run of both LNB/OFA and dry 

FGD, which shows projected visibility 

benefits ranging from 1.18–1.48 dv at 

each Class I area.138 As discussed above, 

more recent emission data show an 

overall increase in SO2 emissions from 

the facility. Therefore anticipated 

visibility improvement from controls 

would be anticipated to be larger and 

there would be an improvement in the 

cost-effectiveness (i.e., lower dollars per 

ton removed) of controls had we used a 

more recent time period for the baseline 

emissions modeled. 

TABLE 66—ENTERGY INDEPENDENCE UNITS 1 AND 2 (FACILITY-WIDE): EPA MODELED 98TH PERCENTILE VISIBILITY

IMPACTS OF LNB/SOFA 

Class I area Distance 

(km) 

Visibility impact 

(Ddv) 

Visibility 

improvement 

of LNB/SOFA 

over baseline 

(dv) Baseline 139 LNB/SOFA 

Caney Creek .................................................................................................... 277 2.054 1.593 0.461 

Upper Buffalo ................................................................................................... 180 1.724 1.476 0.248 

Hercules-Glades .............................................................................................. 173 1.482 1.218 0.264 

Mingo ............................................................................................................... 174 1.492 1.279 0.213 

Total .......................................................................................................... ........................ 6.752 5.566 1.186 

Proposed RP Determination for NOX: 

As discussed above, based on the 

CENRAP’s CAMx modeling, sulfate 

from point sources is the driver of 

regional haze at Caney Creek and Upper 

Buffalo on the 20% worst days in both 

2002 and 2018. Nitrate from point 

sources is not considered a driver of 

regional haze at these Class I areas on 

the 20% worst days, contributing only 

approximately 3% of the total light 

extinction. The Regional Haze Rule 

requires that the established RPGs 

provide for an improvement in visibility 

for the most impaired days (i.e., the 20% 

worst days) over the period of the 

implementation plan and ensure no 

degradation in visibility for the least 

impaired days over the same period (40 

CFR 51.308(d)(1)). Because of the small 

contribution of nitrate from point 

sources to the total light extinction at 

Caney Creek and Upper Buffalo on the 

most impaired days, we do not expect 

that NOX controls under the reasonable 

progress requirements would offer as 

much improvement on the most 

impaired days compared to SO2

controls. However, upon evaluation of 

the four reasonable progress factors, we 

found that the installation and operation 

of LNB/SOFA at Independence Units 1 

and 2 is estimated to cost $401/NOX ton 

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140See Appendix C to the TSD, titled ‘‘Technical 

Support Document for Visibility Modeling Analysis 

for Entergy Independence Generating Station,’’ for 

a detailed discussion of the visibility modeling 

protocol and model inputs. A copy of the TSD and 

its appendices is found in the docket for this 

proposed rulemaking. 

141See 77 FR 31692, 31708. 

142See 79 FR 52420, 52468. 

143Please see Appendix C to the TSD, titled 

‘‘Technical Support Document for Visibility 

Modeling Analysis for Entergy Independence 

Generating Station,’’ and the RPG calculation 

spreadsheet for additional details on calculations. 

These documents are found in the docket for our 

proposed rulemaking. 

144 40 CFR 51.308(d)(1)(v). 

removed at Unit 1 and $436/NOX ton 

removed at Unit 2, which we consider 

to be very cost-effective. These NOX

controls are also projected to result in 

significant visibility improvements at 

Arkansas and Missouri Class I areas, 

based on CALPUFF modeling using the 

98th percentile modeled visibility 

impacts. Therefore, under Option 1, for 

the first planning period, we are 

proposing both an SO2 emission limit as 

described above and a NOX emission 

limit of 0.15 lb/MMBtu on a 30 boileroperating-day averaging basis based on 

the installation and operation of LNB/

SOFA, in light of their cost-effectiveness 

and visibility benefit based on 

CALPUFF modeling, even though 

nitrate from point sources is projected to 

contribute a very small proportion of the 

total light extinction at Caney Creek and 

Upper Buffalo on the 20% worst days in 

2018. Based on our visibility modeling 

of both LNB/OFA and dry FGD, 

proposed Option 1 is projected to have 

visibility benefits ranging from 1.18— 

1.48 dv at each Class I area.140 Under 

Option 2, we are proposing only SO2

controls for Independence Units 1 and 

2 under the reasonable progress 

requirements. Based on our visibility 

modeling of dry FGD, proposed Option 

2 is projected to have visibility benefits 

ranging from 0.87—1.06 dv at each Class 

I area. We specifically solicit public 

comment on this proposed alternative 

approach. 

In addition to options 1 and 2, we also 

solicit public comment on any 

alternative SO2 and NOX control 

measures that would address the 

regional haze requirements for Entergy 

White Bluff Units 1 and 2 and Entergy 

Independence Units 1 and 2 for this 

planning period. This includes, but is 

not limited to, a combination of early 

unit shutdowns and other emissions 

control measures that would achieve 

greater reasonable progress than the 

BART and reasonable progress 

requirements we have proposed for 

these four units in this rulemaking. 

B. Reasonable Progress Goals 

We propose RPGs for Caney Creek 

and Upper Buffalo that are consistent 

with the combination of control 

measures from the approved portion of 

the 2008 Arkansas RH SIP and our 

proposed Arkansas RH FIP. In total, 

these final and proposed controls to 

meet the BART and RP requirements 

will result in higher emissions 

reductions and commensurate visibility 

improvements beyond what was in the 

2008 Arkansas RH SIP. Development of 

refined numerical RPGs for Arkansas’ 

Class I areas would require 

photochemical grid modeling of a 

multistate area, involving thousands of 

emission sources, unlike the 

comparatively simple single-source 

CALPUFF modeling used for individual 

BART assessments. In order to 

accurately reflect all emissions 

reductions expected to occur during this 

planning period, the new 

photochemical modeling would require 

an update of the emissions inventory for 

Arkansas and the surrounding states to 

include not just the actions under this 

FIP, but all EPA and state regulatory 

actions on point, area, and mobile 

sources. After the inventory is 

developed and reviewed by the affected 

states for accuracy, it must be converted 

to a model-ready format before air 

quality modeling can be used to 

estimate the future visibility levels at 

the Class I areas. This modeling would 

require specialized and extensive 

computing hardware and expertise. 

Developing all of the necessary input 

files, running the photochemical model, 

and post-processing the model outputs 

would take several months at a 

minimum. Therefore, we are not 

conducting new photochemical grid 

modeling to establish revised numeric 

RPGs for Caney Creek and Upper 

Buffalo. 

In order to provide RPGs that account 

for emission reductions from the FIP 

controls, we have used a method similar 

to the one used in our Regional Haze 

FIP for Hawaii 141 and Arizona,142

which is based on a scaling of visibility 

extinction components in proportion to 

emission changes. To determine the 

new RPGs for Caney Creek and Upper 

Buffalo, we started with the 2018 

projection of extinction components 

from the CENRAP’s CAMx 

photochemical modeling with source 

apportionment. The 2018 CAMx 

emission scenario included some 

assumptions of state BART 

determinations and other SIP controls, 

as well as projected emissions from 

other point, area, and mobile sources. 

We scaled the modeled visibility 

extinction components for sulfate (SO4) 

and nitrate (NO3) from point sources in 

Arkansas in proportion to the FIP’s 

emission reductions for SO2 and NOX, 

respectively. The sulfate scaling factor 

was the 2018 CENRAP emission 

inventory for Arkansas point source SO2

emissions with FIP controls for BART 

and RP sources in place, divided by the 

original 2018 CENRAP emission 

inventory for Arkansas point source SO2

emissions. We conducted the same 

scaling exercise with nitrate and NOX. 

The scaled sulfate and nitrate 

extinctions were added to the unscaled 

extinctions for organic mass and other 

components to get total extinction, and 

then this was used to calculate post-FIP 

RPGs in deciviews. Although we 

recognize that this method is not 

refined, it allows us to translate the 

emission reductions contained in this 

proposed FIP into quantitative RPGs, 

based on modeling previously 

performed by the CENRAP. These RPGs 

reflect rates of progress that are faster 

than the rates projected by Arkansas. 

The revised RPGs for the first planning 

period for the 20% worst days are 22.27 

dv for Caney Creek and 22.33 dv for 

Upper Buffalo. The results of our 

analysis are shown in the table 

below.143 The RPG calculation was 

performed for both our proposed 

Options 1 and 2. Under Option 1 we are 

proposing to control Entergy 

Independence Units 1 and 2 for the first 

planning period for both SO2 and NOX. 

Alternatively, under Option 2, we are 

proposing to control Entergy 

Independence Units 1 and 2 only for 

SO2 for the first planning period. Due to 

the small impact from all Arkansas 

point source NOx emissions combined 

on the 20% worst days and the scaling 

approach utilized to estimate the 

adjustment to the RPG, the difference 

between the two proposed options 

results in a very small difference in the 

calculated RPGs for Caney Creek and 

Upper Buffalo (less than 0.003 dv). We 

note that some FIP controls will not be 

in place by 2018, however, for the 

purpose of this calculation, we included 

reductions from all FIP controls. 

Arkansas will have to re-evaluate during 

the next regional haze planning period 

what BART and reasonable progress 

controls are in place and re-calculate the 

RPGs for the next planning period as 

needed. We also note that RPGs, unlike 

the emission limits that apply to 

specific RP sources, are not directly 

enforceable.144 Rather, they are an 

analytical framework considered by us 

in evaluating whether measures in the 

implementation plan are sufficient to 

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145 64 FR 35733 and 40 CFR 51.308(d)(1)(v). 146 40 CFR 51.308(d)(3). 147 77 FR 14604. 

achieve reasonable progress.145

Arkansas may choose to use these RPGs 

for purposes of its progress report, or 

may develop new RPGs for approval by 

us along with its progress report, based 

on new modeling or other appropriate 

techniques, in accordance with the 

requirements of 40 CFR 51.308(d)(1). 

TABLE 67—PROPOSED REASONABLE PROGRESS GOALS FOR 20% WORST DAYS

[In Deciviews] 

Class I area 2000–2004 

Baseline 

2064 Natural 

conditions 2018 URP 

2018 

Projection by 

CENRAP 

Estimated FIP 

effect 

Estimated FIP 

2018 RPG 

Caney Creek ............................................ 26.36 11.58 22.91 22.48 ¥0.21 22.27 

Upper Buffalo ........................................... 26.27 11.57 22.84 22.52 ¥0.19 22.33 

V. Our Proposed Long-Term Strategy 

Section 169A(b) of the CAA and 40 

CFR 51.308(d)(3) require that states 

include in their SIP a 10 to 15-year 

strategy, referred to as the long-term 

strategy, for making reasonable progress 

for each Class I area within their state. 

This long-term strategy 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 for a particular Class I area. The 

long-term strategy 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.146

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

state consider certain factors (the longterm strategy factors) in developing its 

long-term strategy for each Class I area. 

These factors are the following: (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. Since states are 

required to consider emissions 

limitations and schedules of compliance 

to achieve the RPGs for each Class I 

area, the BART emission limits that are 

in the state’s regional haze SIP are an 

element of the state’s long-term strategy 

(40 CFR 51.308(d)(3)) for each Class I 

area. In our March 11, 2012 final action 

on the 2008 Arkansas RH SIP, since we 

disapproved a portion of Arkansas’ 

BART determinations and both RPGs for 

Arkansas’ two Class I areas, we also 

disapproved these elements and 

approved all other elements of 

Arkansas’ long-term strategy. The BART 

limits and two RPGs for Arkansas’ Class 

I areas that are in this proposed FIP 

address our March 11, 2011 disapproval 

of Arkansas’ BART limits and two RPGs. 

We propose to find that the proposed 

BART limits and two RPGs that are in 

this proposed FIP also correct the 

deficiency in Arkansas’ long-term 

strategy for each of its Class I areas. 

VI. Our Proposal for Interstate 

Visibility Transport 

We received the Arkansas Interstate 

Visibility Transport SIP that addresses 

the interstate visibility transport 

requirements of CAA section 

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

ozone and PM2.5 NAAQS on April 2, 

2008. In its Interstate Visibility 

Transport SIP, Arkansas stated that its 

regional haze regulation, the APC&E 

Commission Regulation 19, chapter 15, 

codifying its Regional Haze SIP, satisfies 

the requirement of section 

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

protection of visibility, and that 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 Arkansas submits and we 

approve the 2008 Arkansas RH SIP. In 

our March 12, 2012 final action, we 

partially approved and partially 

disapproved the Arkansas Interstate 

Visibility Transport SIP because we 

partially approved and partially 

disapproved the 2008 Arkansas RH SIP. 

In particular, we disapproved a large 

portion of Arkansas’ BART 

determinations, and as a result, the 

corresponding emissions reductions 

other states had relied upon in their 

RPG demonstrations under the RHR 

would not take place. Therefore, we 

made a finding that Arkansas’ SIP does 

not fully ensure that emissions from 

sources in Arkansas do not interfere 

with other states’ visibility programs as 

required by section 110(a)(2)(D)(i)(II) of 

the CAA. Our proposed regional haze 

FIP would address all disapproved 

BART determinations for sources in 

Arkansas as well as all other 

disapproved portions of the 2008 

Arkansas RH SIP. Our proposed regional 

haze FIP together with our prior 

approval of portions of the Arkansas 

Regional Haze SIP would ensure that 

the emissions reductions other sates 

relied upon in their RPG demonstrations 

take place. Therefore, we propose to 

find that the deficiencies we identified 

in our prior disapproval action on the 

Arkansas Interstate Visibility Transport 

SIP are addressed by our proposed 

regional haze FIP along with our prior 

approval of portions of the Arkansas 

Regional Haze SIP. We are also 

proposing to find that the requirements 

of CAA section 110(a)(2)(D)(i)(II) with 

respect to visibility transport for the 

1997 8-hour ozone and PM2.5 NAAQS 

will be satisfied by the combination of 

the emission control measures in this 

proposed regional haze FIP and the 

previously approved portion of the 

Arkansas Interstate Visibility Transport 

SIP. 

VII. Summary of Proposed Actions 

A. Regional Haze 

We propose to promulgate a FIP to 

address those portions of Arkansas’ 

regional haze SIP that we disapproved 

on March 12, 2012, which include 

requirements for BART, reasonable 

progress, and the long-term strategy.147

The FIP we are proposing includes 

BART emission limits for sources in 

Arkansas to reduce emissions that 

contribute to regional haze in Arkansas’ 

two Class I areas and other nearby Class 

I areas and make reasonable progress for 

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the first regional haze planning period 

for Arkansas’ two Class I areas. This 

includes more stringent SO2 emission 

limits in comparison to what the 2008 

Arkansas RH SIP contained for the 

AECC Carl E. Bailey Generating Station 

Unit 1, the AECC John L McClellan 

Generating Station Unit 1, the AEP Flint 

Creek Power Plant Unit 1, Entergy 

White Bluff Plant Units 1 and 2, and the 

Domtar Ashdown Paper Mill Power 

Boiler No. 2. We are also proposing in 

the alternative two options for 

addressing the reasonable progress 

requirements for this first planning 

period by controlling the Entergy 

Independence Power Plant for both the 

Caney Creek and Upper Buffalo Class I 

areas. Under Option 1, we propose to 

require SO2 and NOX emission 

reductions from the Entergy 

Independence Power Plant under the 

reasonable progress requirements. 

Under Option 2, we are also proposing 

only SO2 controls for Independence 

Units 1 and 2 under the reasonable 

progress requirements. In particular, we 

are inviting public comment on the 

alternate proposed Options 1 and 2. We 

also solicit public comment on any 

alternative control measures for Entergy 

White Bluff Units 1 and 2 and 

Independence Units 1 and 2 that would 

address the regional haze requirements 

for these four units for this planning 

period. We also propose to find that the 

proposed BART and reasonable progress 

limits and RPGs that are in this 

proposed FIP correct the deficiency in 

Arkansas’ long-term strategy for both 

Class I areas. Our proposed FIP, once 

finalized, along with the previously 

approved portion of the Arkansas 

regional haze SIP, will constitute 

Arkansas’ regional haze program for the 

first planning period that ends in 2018. 

B. Interstate Visibility Transport 

We propose to find that the 

deficiencies we identified in our prior 

disapproval action on the Arkansas 

Interstate Visibility Transport SIP to 

address the requirement of CAA section 

110(a)(2)(D)(i)(II) with respect to 

visibility transport for the 1997 8-hour 

ozone and 1997 PM2.5 NAAQS will be 

remedied by our proposed Arkansas 

Regional Haze FIP along with our March 

2, 2012 partial approval of certain 

elements of the 2008 Arkansas RH SIP. 

In its Interstate Visibility Transport SIP, 

Arkansas stated that its regional haze 

regulation, the APC&E Commission 

Regulation 19, chapter 15, codifying the 

Arkansas Regional Haze SIP, satisfies 

the requirement of section 

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

protection of visibility, and that 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 Arkansas submits and we 

approve the 2008 Arkansas RH SIP. 

Since our FIP addresses the portions of 

Arkansas Regional Haze SIP that we 

previously disapproved, we propose to 

find that the requirements of CAA 

section 110(a)(2)(D)(i)(II) with respect to 

visibility transport for the 1997 8-hour 

ozone and PM2.5 NAAQS will be 

satisfied by the combination of this 

proposed regional haze FIP and the 

previously approved portion of the 

Arkansas Interstate Visibility Transport 

SIP. 

VIII. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Overview 

This proposed action is not a 

‘‘significant regulatory action’’ under 

the terms of Executive Order 12866 (58 

FR 51735, October 4, 1993) and is 

therefore not subject to review under 

Executive Orders 12866 and 13563 (76 

FR 3821, January 21, 2011). The 

proposed FIP would not constitute a 

rule of general applicability, because it 

only proposes source specific 

requirements for particular, identified 

facilities (six total). 

B. Paperwork Reduction Act 

This proposed action does not impose 

an information collection burden under 

the provisions of the Paperwork 

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

Because it does not contain any 

information collection activities, the 

Paperwork Reduction Act does not 

apply. See 5 CFR 1320(c). 

C. Regulatory Flexibility Act 

The Regulatory Flexibility Act (RFA) 

generally requires an agency to conduct 

a regulatory flexibility analysis of any 

rule subject to notice and comment 

rulemaking requirements unless the 

agency certifies that the rule will not 

have a significant economic impact on 

a substantial number of small entities. 

Small entities include small businesses, 

small not-for-profit enterprises, and 

small governmental jurisdictions. For 

purposes of assessing the impacts of 

today’s rule on small entities, small 

entity is defined as: (1) A small business 

as defined by the Small Business 

Administration’s (SBA) regulations at 13 

CFR 121.201; (2) a small governmental 

jurisdiction that is a government of a 

city, county, town, school district or 

special district with a population of less 

than 50,000; and (3) a small 

organization that is any not-for-profit 

enterprise which is independently 

owned and operated and is not 

dominant in its field. After considering 

the economic impacts of today’s 

proposed rule on small entities, I certify 

that this action will not have a 

significant impact on a substantial 

number of small entities. In making this 

determination, the impact of concern is 

any significant adverse economic 

impact on small entities. An agency may 

certify that a rule will not have a 

significant economic impact on a 

substantial number of small entities if 

the rule relieves regulatory burden, has 

no net burden or otherwise has a 

positive economic effect on the small 

entities subject to the rule. This rule 

does not impose any requirements or 

create impacts on small entities. This 

proposed SIP action under Section 110 

of the CAA will not in-and-of itself 

create any new requirements on small 

entities but simply approves or 

disapproves certain state requirements 

for inclusion into the SIP. Accordingly, 

it affords no opportunity for the EPA to 

fashion for small entities less 

burdensome compliance or reporting 

requirements or timetables or 

exemptions from all or part of the rule. 

The fact that the CAA prescribes that 

various consequences (e.g., emission 

limitations) may or will flow from this 

action does not mean that the EPA 

either can or must conduct a regulatory 

flexibility analysis for this action. We 

have therefore concluded that, this 

action will have no net regulatory 

burden for all directly regulated small 

entities. 

D. Unfunded Mandates Reform Act 

Title II of the Unfunded Mandates 

Reform Act of 1995 (UMRA), Public 

Law 104–4, establishes requirements for 

Federal agencies to assess the effects of 

their regulatory actions on state, local, 

and Tribal governments and the private 

sector. Under Section 202 of UMRA, 

EPA generally must prepare a written 

statement, including a cost-benefit 

analysis, for proposed and final rules 

with ‘‘Federal mandates’’ that may 

result in expenditures to state, local, 

and Tribal governments, in the 

aggregate, or to the private sector, of 

$100 million or more (adjusted for 

inflation) in any one year. Before 

promulgating an EPA rule for which a 

written statement is needed, Section 205 

of UMRA generally requires EPA to 

identify and consider a reasonable 

number of regulatory alternatives and 

adopt the least costly, most costeffective, or least burdensome 

alternative that achieves the objectives 

of the rule. The provisions of Section 

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148 62 FR 19885 (Apr. 23, 1997). 

205 of UMRA do not apply when they 

are inconsistent with applicable law. 

Moreover, Section 205 of UMRA allows 

EPA to adopt an alternative other than 

the least costly, most cost-effective, or 

least burdensome alternative if the 

Administrator publishes with the final 

rule an explanation why that alternative 

was not adopted. Before EPA establishes 

any regulatory requirements that may 

significantly or uniquely affect small 

governments, including Tribal 

governments, it must have developed 

under Section 203 of UMRA a small 

government agency plan. The plan must 

provide for notifying potentially 

affected small governments, enabling 

officials of affected small governments 

to have meaningful and timely input in 

the development of EPA regulatory 

proposals with significant Federal 

intergovernmental mandates, and 

informing, educating, and advising 

small governments on compliance with 

the regulatory requirements. 

EPA has determined that Title II of 

UMRA does not apply to this proposed 

rule. In 2 U.S.C. Section 1502(1) all 

terms in Title II of UMRA have the 

meanings set forth in 2 U.S.C. Section 

658, which further provides that the 

terms ‘‘regulation’’ and ‘‘rule’’ have the 

meanings set forth in 5 U.S.C. Section 

601(2). Under 5 U.S.C. Section 601(2), 

‘‘the term ‘rule’ does not include a rule 

of particular applicability relating to 

. . . facilities.’’ Because this proposed 

rule is a rule of particular applicability 

relating to six named facilities, EPA has 

determined that it is not a ‘‘rule’’ for the 

purposes of Title II of UMRA. 

E. Executive Order 13132: Federalism 

This proposed action does not have 

federalism implications. It will not have 

substantial direct effects on the states, 

on the relationship between the national 

government and the states, or on the 

distribution of power and 

responsibilities among the various 

levels of government. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

This proposed rule does not have 

tribal implications, as specified in 

Executive Order 13175. It will not have 

substantial direct effects on tribal 

governments. Thus, Executive Order 

13175 does not apply to this 

rulemaking. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 148 applies to any 

rule that: (1) Is determined to be 

economically significant as defined 

under Executive Order 12866; and (2) 

concerns an environmental health or 

safety risk that we have reason to 

believe may have a disproportionate 

effect on children. EPA interprets EO 

13045 as applying only to those 

regulatory actions that concern health or 

safety risks, such that the analysis 

required under Section 5–501 of the EO 

has the potential to influence the 

regulation. This action is not subject to 

Executive Order 13045 because it is not 

economically significant as defined in 

Executive Order 12866, and because the 

EPA does not believe the environmental 

health or safety risks addressed by this 

action present a disproportionate risk to 

children. This action is not subject to 

EO 13045 because it implements 

specific standards established by 

Congress in statutes. However, to the 

extent this proposed rule will limit 

emissions of SO2, NOX, and PM, the rule 

will have a beneficial effect on 

children’s health by reducing air 

pollution. 

H. Executive Order 13211: Actions That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This proposed action is not subject to 

Executive Order 13211 (66 FR 28355 

(May 22, 2001)), because it is not a 

significant regulatory action under 

Executive Order 12866. 

I. National Technology Transfer and 

Advancement Act 

Section 12 of the National Technology 

Transfer and Advancement Act 

(NTTAA) of 1995 requires Federal 

agencies to evaluate existing technical 

standards when developing a new 

regulation. To comply with NTTAA, 

EPA must consider and use ‘‘voluntary 

consensus standards’’ (VCS) if available 

and applicable when developing 

programs and policies unless doing so 

would be inconsistent with applicable 

law or otherwise impractical. EPA 

believes that VCS are inapplicable to 

this action. Today’s action does not 

require the public to perform activities 

conducive to the use of VCS. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order 12898 (59 FR 7629, 

February 16, 1994), establishes federal 

executive policy on environmental 

justice. Its main provision directs 

federal agencies, to the greatest extent 

practicable and permitted by law, to 

make environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority 

populations and low-income 

populations in the United States. We 

have determined that this proposed 

rule, if finalized, will not have 

disproportionately high and adverse 

human health or environmental effects 

on minority or low-income populations 

because it increases the level of 

environmental protection for all affected 

populations without having any 

disproportionately high and adverse 

human health or environmental effects 

on any population, including any 

minority or low-income population. 

This proposed federal rule limits 

emissions of NOX, SO2, and PM from six 

facilities in Arkansas. 

List of Subjects in 40 CFR Part 52 

Environmental protection, Air 

pollution control, Incorporation by 

reference, Intergovernmental relations, 

Nitrogen dioxide, Ozone, Particulate 

matter, Reporting and recordkeeping 

requirements, Sulfur dioxides, 

Visibility, Interstate transport of 

pollution, Regional haze, Best available 

control technology. 

Dated: March 6, 2015. 

Samuel Coleman, P.E. 

Acting Regional Administrator, Region 6. 

Title 40, chapter I, of the Code of 

Federal Regulations is proposed to be 

amended as follows: 

PART 52—APPROVAL AND 

PROMULGATION OF 

IMPLEMENTATION PLANS 

■ 1. The authority citation for part 52 

continues to read as follows: 

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

Subpart E—Arkansas 

■ 2. Section 52.173 is amended by 

adding paragraphs (c) and (d) to read as 

follows: 

§ 52.173 Visibility protection. 

* * * * * 

(c) Requirements for AECC Carl E. 

Bailey Unit 1; AECC John L. McClellan 

Unit 1; AEP Flint Creek Unit 1; Entergy 

White Bluff Units 1, 2, and Auxiliary 

Boiler; Entergy Lake Catherine Unit 4; 

Domtar Ashdown Paper Mill Power 

Boilers No. 1 and 2; and Entergy 

Independence Units 1 and 2 affecting 

visibility. 

(1) Applicability. The provisions of 

this section shall apply to each owner 

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or operator, or successive owners or 

operators, of the sources designated as: 

AECC Carl E. Bailey Unit 1; AECC John 

L. McClellan Unit 1; AEP Flint Creek 

Unit 1; Entergy White Bluff Units 1, 2, 

and Auxiliary Boiler; Entergy Lake 

Catherine Unit 4; Domtar Ashdown 

Paper Mill Power Boilers No. 1 and 2; 

and Entergy Independence Units 1 and 

2. 

(2) Definitions. All terms used in this 

part but not defined herein shall have 

the meaning given them in the Clean Air 

Act and in parts 51 and 60 of CFR title 

40. For the purposes of this section: 

24-hour period means the period of 

time between 12:01 a.m. and 12 

midnight. 

Air pollution control equipment 

includes selective catalytic control 

units, baghouses, particulate or gaseous 

scrubbers, and any other apparatus 

utilized to control emissions of 

regulated air contaminants which would 

be emitted to the atmosphere. 

Boiler-operating-day for electric 

generating units listed under paragraph 

(c)(1) of this section means any 24- hour 

period between 12:00 midnight and the 

following midnight during which any 

fuel is combusted at any time at the 

steam generating unit. For power boilers 

listed under paragraph (c)(1) of this 

section, we define boiler-operating-day 

as any 24-hour period between 12:00 

midnight and the following midnight 

during which any fuel is fed into and/ 

or combusted at any time in the Power 

Boiler. 

Daily average means the arithmetic 

average of the hourly values measured 

in a 24-hour period. 

Heat input means heat derived from 

combustion of fuel in a unit and does 

not include the heat input from 

preheated combustion air, recirculated 

flue gases, or exhaust gases from other 

sources. Heat input shall be calculated 

in accordance with 40 CFR part 75. 

Owner or Operator means any person 

who owns, leases, operates, controls, or 

supervises any of the units or power 

boilers listed under paragraph (c)(1) of 

this section. 

Regional Administrator means the 

Regional Administrator of EPA Region 6 

or his/her authorized representative. 

Unit means one of the natural gas, fuel 

oil, or coal fired boilers covered under 

paragraph (c) of this section. 

(3) Emissions limitations for AECC 

Bailey Unit 1 and AECC McClellan Unit 

1. The individual SO2, NOX, and PM 

emission limits for each unit shall be as 

listed in the following table. 

Unit SO2 Emission limit NOX Emission limit PM Emission limit 

AECC Bailey Unit 1 ....................... Use of fuel with a sulfur content 

limit of 0.5% by weight.

887 lb/hr ........................................ Use of fuel with a sulfur content 

limit of 0.5% by weight. 

AECC McClellan Unit 1 ................. Use of fuel with a sulfur content 

limit of 0.5% by weight.

869.1 lb/hr (Natural Gas firing) .....

705.8 lb/hr (Fuel Oil firing) ...........

Use of fuel with a sulfur content 

limit of 0.5% by weight. 

(4) Compliance dates for AECC Bailey 

Unit 1 and AECC McClellan Unit. The 

owner or operator of each unit shall 

comply with the SO2 and PM 

requirements listed in paragraph (c)(3) 

of this section within 5 years of the 

effective date of this rule. As of the 

effective date of this rule, the owner/

operator of each unit shall not purchase 

fuel for combustion at the unit that does 

not meet the sulfur content limit in 

paragraph (c)(3) of this section. Five 

years from the effective date of the rule 

only fuel that meets the sulfur content 

limit in paragraph (c)(3) of this section 

shall be burned at each unit. The owner/ 

operator of each unit shall comply with 

the NOX emission limits in paragraph 

(c)(3) of this section as of the effective 

date of this rule. 

(5) Compliance determinations for 

AECC Bailey Unit 1 and AECC 

McClellan Unit—(i) SO2 and PM. To 

determine compliance with the SO2 and 

PM requirements listed in paragraph 

(c)(3) of this section, the owner/operator 

shall sample and analyze each shipment 

of fuel to determine the sulfur content, 

except for natural gas shipments. A 

‘‘shipment’’ is considered delivery of 

the entire amount of each order of fuel 

purchased. Fuel sampling and analysis 

may be performed by the owner or 

operator of an affected unit, an outside 

laboratory, or a fuel supplier. 

(ii) NOX. To determine compliance 

with the NOX emission limits of 

paragraph (c)(3) of this section, the 

owner/operator shall determine the 

average emissions (arithmetic average of 

three contiguous one hour periods) of 

NOX as measured by a CEMS and 

converted to pounds per hour using 

corresponding average (arithmetic 

average of three contiguous one hour 

periods) stack gas flow rates. 

(iii) The owner or operator shall 

continue to maintain and operate a 

CEMS for NOX on the units listed in 

paragraph (c)(3) of this section in 

accordance with 40 CFR 60.8 and 

60.13(e), (f), and (h), and appendix B of 

part 60. The owner or operator shall 

comply with the quality assurance 

procedures for CEMS found in 40 CFR 

part 75. Compliance with the emission 

limits for NOX shall be determined by 

using data from a CEMS. 

(iv) Continuous emissions monitoring 

shall apply during all periods of 

operation of the units listed in 

paragraph (c)(3) of this section, 

including periods of startup, shutdown, 

and malfunction, except for CEMS 

breakdowns, repairs, calibration checks, 

and zero and span adjustments. 

Continuous monitoring systems for 

measuring NOX and diluent gas shall 

complete a minimum of one cycle of 

operation (sampling, analyzing, and 

data recording) for each successive 15- 

minute period. Hourly averages shall be 

computed using at least one data point 

in each fifteen minute quadrant of an 

hour. Notwithstanding this requirement, 

an hourly average may be computed 

from at least two data points separated 

by a minimum of 15 minutes (where the 

unit operates for more than one 

quadrant in an hour) if data are 

unavailable as a result of performance of 

calibration, quality assurance, 

preventive maintenance activities, or 

backups of data from data acquisition 

and handling system, and recertification 

events. When valid NOX pounds per 

hour emission data are not obtained 

because of continuous monitoring 

system breakdowns, repairs, calibration 

checks, or zero and span adjustments, 

emission data must be obtained by using 

other monitoring systems approved by 

the EPA to provide emission data for a 

minimum of 18 hours in each 24 hour 

period and at least 22 out of 30 

successive boiler operating days. 

(6) Emissions limitations for AEP Flint 

Creek Unit 1 and Entergy White Bluff 

Units 1 and 2. The individual SO2 and 

NOX emission limits for each unit shall 

be as listed in the following table in 

pounds per million British thermal 

units (lb/MMBtu) as averaged over a 

rolling 30 boiler-operating-day period. 

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Unit SO2 Emission limit 

(lb/MMBtu) 

NOX Emission limit 

(lb/MMBtu) 

AEP Flint Creek Unit 1 ............................................................................................................ 0.06 0.23 

Entergy White Bluff Unit 1 ....................................................................................................... 0.06 0.15 

Entergy White Bluff Unit 2 ....................................................................................................... 0.06 0.15 

(7) Compliance dates for AEP Flint 

Creek Unit 1 and Entergy White Bluff 

Units 1 and 2. The owner or operator of 

each unit shall comply with the SO2

emission limit listed in paragraph (c)(6) 

of this section within 5 years of the 

effective date of this rule and the NOX

emission limit within 3 years of the 

effective date of this rule. 

(8) Compliance determination for AEP 

Flint Creek Unit 1 and Entergy White 

Bluff Units 1 and 2. (i) For each unit, 

SO2 and NOX emissions for each 

calendar day shall be determined by 

summing the hourly emissions 

measured in pounds of SO2 or pounds 

of NOX. For each unit, heat input for 

each boiler-operating-day shall be 

determined by adding together all 

hourly heat inputs, in millions of BTU. 

Each boiler-operating-day of the thirtyday rolling average for a unit shall be 

determined by adding together the 

pounds of SO2 or NOX from that day 

and the preceding 29 boiler-operatingdays and dividing the total pounds of 

SO2 or NOX by the sum of the heat input 

during the same 30 boiler-operating-day 

period. The result shall be the 30 boileroperating-day rolling average in terms of 

lb/MMBtu emissions of SO2 or NOX. If 

a valid SO2 or NOX pounds per hour or 

heat input is not available for any hour 

for a unit, that heat input and SO2 or 

NOX pounds per hour shall not be used 

in the calculation of the 30 boileroperating-day rolling average for SO2 or 

NOX. 

(ii) The owner or operator shall 

continue to maintain and operate a 

CEMS for SO2 and NOX on the units 

listed in paragraph (c)(6) of this section 

in accordance with 40 CFR 60.8 and 

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

Part 60. The owner or operator shall 

comply with the quality assurance 

procedures for CEMS found in 40 CFR 

part 75. Compliance with the emission 

limits for SO2 and NOX shall be 

determined by using data from a CEMS. 

(iii) Continuous emissions monitoring 

shall apply during all periods of 

operation of the units listed in 

paragraph (c)(6) of this section, 

including periods of startup, shutdown, 

and malfunction, except for CEMS 

breakdowns, repairs, calibration checks, 

and zero and span adjustments. 

Continuous monitoring systems for 

measuring SO2 and NOX and diluent gas 

shall complete a minimum of one cycle 

of operation (sampling, analyzing, and 

data recording) for each successive 15- 

minute period. Hourly averages shall be 

computed using at least one data point 

in each fifteen minute quadrant of an 

hour. Notwithstanding this requirement, 

an hourly average may be computed 

from at least two data points separated 

by a minimum of 15 minutes (where the 

unit operates for more than one 

quadrant in an hour) if data are 

unavailable as a result of performance of 

calibration, quality assurance, 

preventive maintenance activities, or 

backups of data from data acquisition 

and handling system, and recertification 

events. When valid SO2 or NOX pounds 

per hour emission data are not obtained 

because of continuous monitoring 

system breakdowns, repairs, calibration 

checks, or zero and span adjustments, 

emission data must be obtained by using 

other monitoring systems approved by 

the EPA to provide emission data for a 

minimum of 18 hours in each 24 hour 

period and at least 22 out of 30 

successive boiler operating days. 

(9) Emissions limitations for Entergy 

White Bluff Auxiliary Boiler. The 

individual SO2, NOX, and PM emission 

limits for the unit shall be as listed in 

the following table in pounds per hour 

(lb/hr). 

Unit SO2 Emission limit 

(lb/hr) 

NOX Emission limit 

(lb/hr) 

PM Emission limit 

(lb/hr) 

Entergy White Bluff Auxiliary Boiler ............................................. 105.2 32.2 4.5 

(10) Compliance dates for Entergy 

White Bluff Auxiliary Boiler. The owner 

or operator of the unit shall comply 

with the SO2, NOX, and PM emission 

limits listed in paragraph (c)(9) of this 

section as of the effective date of this 

rule. 

(11) Emissions limitations for Entergy 

Lake Catherine Unit 4. The individual 

NOX emission limit for the unit for 

natural gas firing shall be as listed in the 

following table in pounds per million 

British thermal units (lb/MMBtu) as 

averaged over a rolling 30 boileroperating-day period. The unit shall not 

burn fuel oil until BART determinations 

are promulgated for the unit for SO2, 

NOX, and PM for the fuel oil firing 

scenario through a FIP and/or through 

EPA action upon and approval of 

revised BART determinations submitted 

by the State as a SIP revision. 

Unit 

NOX Emission 

limit—natural gas 

firing 

(lb/MMBtu) 

Entergy Lake Catherine 

Unit 4 ........................... 0.22 

(12) Compliance dates for Entergy 

Lake Catherine Unit 4. The owner or 

operator of the unit shall comply with 

the NOX emission limit listed in 

paragraph (c)(11) of this section within 

3 years of the effective date of this rule. 

(13) Compliance determination for 

Entergy Lake Catherine Unit 4. (i) NOX

emissions for each calendar day shall be 

determined by summing the hourly 

emissions measured in pounds of NOX. 

The heat input for each boiler-operatingday shall be determined by adding 

together all hourly heat inputs, in 

millions of BTU. Each boiler-operatingday of the thirty-day rolling average for 

the unit shall be determined by adding 

together the pounds of NOX from that 

day and the preceding 29 boileroperating-days and dividing the total 

pounds of NOX by the sum of the heat 

input during the same 30 boileroperating-day period. The result shall be 

the 30 boiler-operating-day rolling 

average in terms of lb/MMBtu emissions 

of NOX. If a valid NOX pounds per hour 

or heat input is not available for any 

hour for the unit, that heat input and 

NOX pounds per hour shall not be used 

in the calculation of the 30 boileroperating-day rolling average for NOX. 

(ii) The owner or operator shall 

continue to maintain and operate a 

CEMS for NOX on the unit listed in 

paragraph (c)(11) of this section in 

accordance with 40 CFR 60.8 and 

60.13(e), (f), and (h), and appendix B of 

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Federal Register / Vol. 80, No. 67 / Wednesday, April 8, 2015 / Proposed Rules 19003 

part 60. The owner or operator shall 

comply with the quality assurance 

procedures for CEMS found in 40 CFR 

part 75. Compliance with the emission 

limit for NOX shall be determined by 

using data from a CEMS. 

(iii) Continuous emissions monitoring 

shall apply during all periods of 

operation of the unit listed in paragraph 

(c)(11) of this section, including periods 

of startup, shutdown, and malfunction, 

except for CEMS breakdowns, repairs, 

calibration checks, and zero and span 

adjustments. Continuous monitoring 

systems for measuring NOX and diluent 

gas shall complete a minimum of one 

cycle of operation (sampling, analyzing, 

and data recording) for each successive 

15-minute period. Hourly averages shall 

be computed using at least one data 

point in each fifteen minute quadrant of 

an hour. Notwithstanding this 

requirement, an hourly average may be 

computed from at least two data points 

separated by a minimum of 15 minutes 

(where the unit operates for more than 

one quadrant in an hour) if data are 

unavailable as a result of performance of 

calibration, quality assurance, 

preventive maintenance activities, or 

backups of data from data acquisition 

and handling system, and recertification 

events. When valid NOX pounds per 

hour emission data are not obtained 

because of continuous monitoring 

system breakdowns, repairs, calibration 

checks, or zero and span adjustments, 

emission data must be obtained by using 

other monitoring systems approved by 

the EPA to provide emission data for a 

minimum of 18 hours in each 24 hour 

period and at least 22 out of 30 

successive boiler operating days. 

(14) Emissions limitations for Domtar 

Ashdown Paper Mill Power Boiler No.1. 

The individual SO2 and NOX emission 

limits for the power boiler shall be as 

listed in the following table in pounds 

per hour (lb/hr) as averaged over a 

rolling 30 boiler-operating-day period. 

For this power boiler, boiler-operatingday is defined as a 24-hour period 

between 12 midnight and the following 

midnight during which any fuel is fed 

into and/or combusted at any time in 

the power boiler. 

Unit SO2 Emission limit 

(lb/hr) 

NOX Emission limit 

(lb/hr) 

Domtar Ashdown Paper Mill Power Boiler No. 1 .................................................................... 21.0 207.4 

(15) Compliance dates for Domtar 

Ashdown Mill Power Boiler No. 1. The 

owner or operator of the power boiler 

shall comply with the SO2 and NOX

emission limits listed in paragraph 

(c)(14) of this section as of the effective 

date of this rule. 

(16) Compliance determination for 

Domtar Ashdown Paper Mill Power 

Boiler No. 1. (i) SO2 emissions for each 

calendar day shall be determined by 

summing the hourly emissions 

measured in pounds of SO2. SO2

emissions from combustion of bark shall 

be determined by using the following 

site-specific curve equation, which 

accounts for the SO2 scrubbing 

capabilities of bark combustion: 

Y= 0.4005 * X¥0.2645 

Where: 

Y= pounds of sulfur emitted per ton of dry 

fuel feed to the boiler 

X= pounds of sulfur input per ton of dry bark 

The owner or operator shall confirm the 

site-specific curve equation through 

stack testing. No later than 1 year after 

the effective date of this rule, the owner 

or operator shall provide a report to EPA 

showing confirmation of the site 

specific-curve equation accuracy. Stack 

SO2 emissions from combustion of fuel 

oil shall be determined by assuming that 

the SO2 inlet is equal to the SO2 being 

emitted at the stack. 

(ii) To demonstrate compliance with 

the NOX emission limit under paragraph 

(c)(14) of this section, the owner or 

operator shall conduct annual stack 

testing. 

(iii) Each boiler-operating-day of the 

thirty-day rolling average for the power 

boiler shall be determined by adding 

together the pounds of SO2 or NOX from 

that day and the preceding 29 boileroperating-days and dividing the total 

pounds of SO2 or NOX by the sum of the 

total number of hours during the same 

30 boiler-operating-day period. The 

result shall be the 30 boiler-operatingday rolling average in terms of lb/hr 

emissions of SO2 or NOX. If a valid SO2

or NOX pounds per hour is not available 

for any hour for the power boiler, that 

SO2 or NOX pounds per hour shall not 

be used in the calculation of the 

applicable 30 boiler-operating-day 

rolling average. 

(17) SO2 and NOX emissions 

limitations for Domtar Ashdown Paper 

Mill Power Boiler No.2. The individual 

SO2 and NOX emission limits for the 

power boiler shall be as listed in the 

following table in pounds per hour (lb/ 

hr) or pounds per million British 

thermal units (lb/MMBtu) as averaged 

over a rolling 30 boiler-operating-day 

period. For this power boiler, boileroperating-day is defined as a 24-hour 

period between 12 midnight and the 

following midnight during which any 

fuel is fed into and/or combusted at any 

time in the power boiler. 

Unit SO2 Emission limit 

(lb/MMBtu) 

NOX Emission limit 

(lb/hr) 

Domtar Ashdown Paper Mill Power Boiler No. 2 .................................................................... 0.11 345 

(18) SO2 and NOX compliance dates 

for Domtar Ashdown Mill Power Boiler 

No. 2. The owner or operator of the 

power boiler shall comply with the SO2

and NOX emission limits listed in 

paragraph (c)(17) of this section within 

3 year of the effective date of this rule. 

(19) SO2 and NOX compliance 

determination for Domtar Ashdown Mill 

Power Boiler No. 2. (i) SO2 emissions for 

each calendar day shall be determined 

by summing the hourly emissions 

measured in pounds of SO2. The heat 

input for each boiler-operating-day shall 

be determined by adding together all 

hourly heat inputs, in millions of BTU. 

Each boiler-operating-day of the thirtyday rolling average for a unit shall be 

determined by adding together the 

pounds of SO2 from that day and the 

preceding 29 boiler-operating-days and 

dividing the total pounds of SO2 by the 

sum of the heat input during the same 

30 boiler-operating-day period. The 

result shall be the 30 boiler-operatingday rolling average in terms of lb/

MMBtu emissions of SO2. If a valid SO2

pounds per hour or heat input is not 

available for any hour for a unit, that 

heat input and SO2 pounds per hour 

shall not be used in the calculation of 

the 30 boiler-operating-day rolling 

average for SO2. 

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19004 Federal Register / Vol. 80, No. 67 / Wednesday, April 8, 2015 / Proposed Rules 

(ii) NOX emissions for each calendar 

day shall be determined by summing 

the hourly emissions measured in 

pounds of NOX. Each boiler-operatingday of the thirty-day rolling average for 

the power boiler shall be determined by 

adding together the pounds of NOX from 

that day and the preceding 29 boileroperating-days and dividing the total 

pounds of NOX by the sum of the total 

number of hours during the same 30 

boiler-operating-day period. The result 

shall be the 30 boiler-operating-day 

rolling average in terms of lb/hr 

emissions of NOX. If a valid NOX

pounds per hour is not available for any 

hour for the power boiler, that NOX

pounds per hour shall not be used in the 

calculation of the 30 boiler-operatingday rolling average for NOX. 

(iii) The owner or operator shall 

continue to maintain and operate a 

CEMS for SO2 and NOX on the power 

boiler listed in paragraph (c)(17) of this 

section in accordance with 40 CFR 60.8 

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

B of Part 60. The owner or operator shall 

comply with the quality assurance 

procedures for CEMS found in 40 CFR 

part 75. Compliance with the emission 

limits for SO2 and NOX shall be 

determined by using data from a CEMS. 

(iv) Continuous emissions monitoring 

shall apply during all periods of 

operation of the units listed in 

paragraph (c)(17) of this section, 

including periods of startup, shutdown, 

and malfunction, except for CEMS 

breakdowns, repairs, calibration checks, 

and zero and span adjustments. 

Continuous monitoring systems for 

measuring SO2 and NOX and diluent gas 

shall complete a minimum of one cycle 

of operation (sampling, analyzing, and 

data recording) for each successive 15- 

minute period. Hourly averages shall be 

computed using at least one data point 

in each fifteen minute quadrant of an 

hour. Notwithstanding this requirement, 

an hourly average may be computed 

from at least two data points separated 

by a minimum of 15 minutes (where the 

unit operates for more than one 

quadrant in an hour) if data are 

unavailable as a result of performance of 

calibration, quality assurance, 

preventive maintenance activities, or 

backups of data from data acquisition 

and handling system, and recertification 

events. When valid SO2 or NOX pounds 

per hour emission data are not obtained 

because of continuous monitoring 

system breakdowns, repairs, calibration 

checks, or zero and span adjustments, 

emission data must be obtained by using 

other monitoring systems approved by 

the EPA to provide emission data for a 

minimum of 18 hours in each 24 hour 

period and at least 22 out of 30 

successive boiler operating days. 

(20) PM Emissions limitations for 

Domtar Ashdown Paper Mill Power 

Boiler No.2. The individual particulate 

matter emission limit for the power 

boiler shall be as listed in the following 

table in pounds per million British 

thermal units (lb/MMBtu). 

Unit PM Emission limit 

(lb/MMBtu) 

Domtar Ashdown 

Paper Mill Power 

Boiler No. 2 ........... 0.44 

(21) PM compliance dates for Domtar 

Ashdown Mill Power Boiler No. 2. The 

owner or operator of the power boiler 

shall comply with the PM emission 

limit listed in paragraph (c)(20) of this 

section as of the effective date of this 

rule. 

(22) PM compliance determination for 

Domtar Ashdown Paper Mill Power 

Boiler No.2. Compliance with the PM 

emission limit listed in paragraph 

(c)(20) of this section shall be 

determined by maintaining the 30-day 

rolling average wet scrubber pressure 

drop and the 30-day rolling average wet 

scrubber liquid flow rate at or above the 

lowest one-hour average pressure drop 

and the lowest one-hour average liquid 

flow rate, respectively, measured during 

the most recent performance test 

demonstrating compliance with the PM 

emission limit according to 40 CFR 

63.7530(b) and Table 7 to subpart 

DDDDD of part 63. The pressure drop 

and liquid flow rate monitoring system 

data shall be collected according to 40 

CFR 63.7525 and 63.7535; data shall be 

reduced to 30-day rolling averages; and 

the 30-day rolling average pressure drop 

and liquid flow-rate shall be maintained 

at or above the operating limits 

established during the performance test 

according to 40 CFR 63.7530(b). 

(23) Emissions limitations for Entergy 

Independence Units 1 and 2. The 

individual emission limits for each unit 

shall be as listed in the following table 

in pounds per million British thermal 

units (lb/MMBtu) as averaged over a 

rolling 30 boiler-operating-day period. 

EPA is taking comment on two possible 

options. Under Option 1, the SO2 and a 

NOX emission limits as listed in the 

following table shall apply to each unit. 

Under Option 2, only the SO2 emission 

limit as listed in the following table 

shall apply to each unit. EPA expects 

only to finalize one of these options. 

Unit SO2 Emission limit 

(lb/MMBtu) 

NOX Emission limit 

(lb/MMBtu) 

Option 1 ................................... Entergy Independence Unit 1 and 2 ......................................... 0.06 0.15 

Option 2 ................................... Entergy Independence Unit 1 and 2 ......................................... 0.06 ....................................

(24) Compliance dates for Entergy 

Independence Units 1 and 2. The owner 

or operator of each unit shall comply 

with the SO2 emission limit in 

paragraph (c)(23) of this section within 

5 years of the effective date of this rule 

and the NOX emission limit within 3 

years of the effective date of this rule. 

(25) Compliance determination for 

Entergy Independence Units 1 and 2. (i) 

For each unit, SO2 and NOX emissions 

for each calendar day shall be 

determined by summing the hourly 

emissions measured in pounds of SO2 or 

pounds of NOX. For each unit, heat 

input for each boiler-operating-day shall 

be determined by adding together all 

hourly heat inputs, in millions of BTU. 

Each boiler-operating-day of the thirtyday rolling average for a unit shall be 

determined by adding together the 

pounds of SO2 or NOX from that day 

and the preceding 29 boiler-operatingdays and dividing the total pounds of 

SO2 or NOX by the sum of the heat input 

during the same 30 boiler-operating-day 

period. The result shall be the 30 boileroperating-day rolling average in terms of 

lb/MMBtu emissions of SO2 or NOX. If 

a valid SO2 or NOX pounds per hour or 

heat input is not available for any hour 

for a unit, that heat input and SO2 or 

NOX pounds per hour shall not be used 

in the calculation of the applicable 30 

boiler-operating-day rolling average. 

(ii) The owner or operator shall 

continue to maintain and operate a 

CEMS for SO2 and NOX on the units 

listed in paragraph (c)(23) of this section 

in accordance with 40 CFR 60.8 and 

60.13(e), (f), and (h), and appendix B of 

part 60. The owner or operator shall 

comply with the quality assurance 

procedures for CEMS found in 40 CFR 

part 75. Compliance with the emission 

limits for SO2 and NOX shall be 

determined by using data from a CEMS. 

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Federal Register / Vol. 80, No. 67 / Wednesday, April 8, 2015 / Proposed Rules 19005 

(iii) Continuous emissions monitoring 

shall apply during all periods of 

operation of the units listed in 

paragraph (c)(23) of this section, 

including periods of startup, shutdown, 

and malfunction, except for CEMS 

breakdowns, repairs, calibration checks, 

and zero and span adjustments. 

Continuous monitoring systems for 

measuring SO2 and NOX and diluent gas 

shall complete a minimum of one cycle 

of operation (sampling, analyzing, and 

data recording) for each successive 15- 

minute period. Hourly averages shall be 

computed using at least one data point 

in each fifteen minute quadrant of an 

hour. Notwithstanding this requirement, 

an hourly average may be computed 

from at least two data points separated 

by a minimum of 15 minutes (where the 

unit operates for more than one 

quadrant in an hour) if data are 

unavailable as a result of performance of 

calibration, quality assurance, 

preventive maintenance activities, or 

backups of data from data acquisition 

and handling system, and recertification 

events. When valid SO2 or NOX pounds 

per hour emission data are not obtained 

because of continuous monitoring 

system breakdowns, repairs, calibration 

checks, or zero and span adjustments, 

emission data must be obtained by using 

other monitoring systems approved by 

the EPA to provide emission data for a 

minimum of 18 hours in each 24 hour 

period and at least 22 out of 30 

successive boiler operating days. 

(26) Reporting and recordkeeping 

requirements. Unless otherwise stated 

all requests, reports, submittals, 

notifications, and other communications 

to the Regional Administrator required 

under paragraph (c) of this section shall 

be submitted, unless instructed 

otherwise, to the Director, Multimedia 

Planning and Permitting Division, U.S. 

Environmental Protection Agency, 

Region 6, to the attention of Mail Code: 

6PD, at 1445 Ross Avenue, Suite 1200, 

Dallas, Texas 75202–2733. For each unit 

subject to the emissions limitation 

under paragraph (c) of this section, the 

owner or operator shall comply with the 

following requirements: 

(i) For each emissions limit under 

paragraph (c) of this section where 

compliance shall be determined by 

using data from a CEMS, comply with 

the notification, reporting, and 

recordkeeping requirements for CEMS 

compliance monitoring in 40 CFR 

60.7(c) and (d). 

(ii) For each day, provide the total 

SO2 emitted that day by AEP Flint Creek 

Unit 1, Entergy White Bluff Units 1 and 

2, Domtar Ashdown Mill Power Boilers 

No. 1 and 2, and Entergy Independence 

Units 1 and 2. For each day, provide the 

total NOX emitted that day by AECC 

Bailey Unit 1, AECC McClellan Unit 1, 

AEP Flint Creek Unit 1, Entergy White 

Bluff Units 1 and 2, Entergy Lake 

Catherine Unit 4, Domtar Ashdown Mill 

Power Boiler No. 2, and Entergy 

Independence Units 1 and 2. For any 

hours on any unit or power boiler where 

data for hourly pounds or heat input is 

missing, identify the unit number and 

monitoring device that did not produce 

valid data that caused the missing hour. 

(27) Equipment operations. At all 

times, including periods of startup, 

shutdown, and malfunction, the owner 

or operator shall, to the extent 

practicable, maintain and operate the 

unit including associated air pollution 

control equipment in a manner 

consistent with good air pollution 

control practices for minimizing 

emissions. Determination of whether 

acceptable operating and maintenance 

procedures are being used will be based 

on information available to the Regional 

Administrator which may include, but 

is not limited to, monitoring results, 

review of operating and maintenance 

procedures, and inspection of the unit. 

(28) Enforcement. (i) Notwithstanding 

any other provision in this 

implementation plan, any credible 

evidence or information relevant as to 

whether the unit would have been in 

compliance with applicable 

requirements if the appropriate 

performance or compliance test had 

been performed, can be used to establish 

whether or not the owner or operator 

has violated or is in violation of any 

standard or applicable emission limit in 

the plan. 

(ii) Emissions in excess of the level of 

the applicable emission limit or 

requirement that occur due to a 

malfunction shall constitute a violation 

of the applicable emission limit. 

(d) Measures addressing partial 

disapproval of portion of Interstate 

Visibility Transport SIP for the 1997 8- 

hour ozone and PM2.5 NAAQS. (1) The 

deficiencies identified in EPA’s partial 

disapproval of the portion of the SIP 

pertaining to adequate provisions to 

prohibit emissions in Arkansas from 

interfering with measures required in 

another state to protect visibility, 

submitted on March 28, 2008, and 

supplemented on September 27, 2011 

are satisfied by § 52.173. 

(2) [Reserved] 

[FR Doc. 2015–06726 Filed 4–3–15; 11:15 am] 

BILLING CODE 6560–50–P 

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