Vol. 77 Friday, 

No. 140 July 20, 2012 

Part II 

Environmental Protection Agency 

40 CFR Part 51 

Approval, Disapproval and Promulgation of Air Quality Implementation 

Plans; Arizona; Regional Haze State and Federal Implementation Plans; 

Proposed Rule 


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1Although 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.’’ 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 51 

[EPA–R09–OAR–2012–0021, FRL–9700–1] 

Approval, Disapproval and 

Promulgation of Air Quality 

Implementation Plans; Arizona; 

Regional Haze State and Federal 

Implementation Plans 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Proposed rule. 

SUMMARY: EPA is proposing to approve 

partially and disapprove partially a 

revision to Arizona’s State 

Implementation Plan (SIP) to implement 

the regional haze program for the first 

planning period through July 31, 2018. 

This proposed action addresses only the 

portion of the SIP related to Arizona’s 

determination of Best Available Retrofit 

Technology (BART) to control emissions 

from eight units at three electric 

generating stations: Apache Generating 

Station, Cholla Power Plant and 

Coronado Generating Station. EPA 

proposes to approve the State’s 

determination that these sources are 

subject to BART, and to approve the 

emissions limits for sulfur dioxide (SO2) 

and particulate matter (PM10) at all the 

units. EPA proposes to disapprove the 

BART emissions limits for nitrogen 

oxides (NOX) at most of the units. EPA 

also proposes to promulgate a Federal 

Implementation Plan (FIP) containing 

new emissions limits for NOX as well as 

BART compliance requirements for the 

three facilities. We encourage the State 

to submit a revised SIP to replace all 

portions of our FIP, and we stand ready 

to work with the State to develop a 

revised plan. The Clean Air Act (CAA) 

requires states to prevent any future and 

remedy any existing man-made 

impairment of visibility in 156 national 

parks and wilderness areas designated 

as Class I areas. Arizona has a wealth of 

such areas. The three power plants 

affect visibility at 18 national parks and 

wilderness areas, including the Grand 

Canyon, Mesa Verde and the Petrified 

Forest. The State and EPA must work 

together to ensure that plans are in place 

to make progress toward natural 

visibility conditions at these national 

treasures. 

DATES: Written comments must be 

received by the designated contact at the 

address below on or before August 31, 

2012. 

ADDRESSES: See the SUPPLEMENTARY

INFORMATION section for further 

instructions on where and how to learn 

more about this proposal, attend a 

public hearing, or submit comments. 

FOR FURTHER INFORMATION CONTACT: 

Thomas Webb, U.S. EPA, Region 9, 

Planning Office, Air Division, Air-2, 75 

Hawthorne Street, San Francisco, CA 

94105. Thomas Webb can be reached at 

telephone number (415) 947–4139 and 

via electronic mail at 

webb.thomas@epa.gov. 

SUPPLEMENTARY INFORMATION: 

Table of Contents 

I. General Information 

A. Definitions 

B. Docket 

C. Instructions for Submitting Comments to 

EPA 

D. Submitting Confidential Business 

Information 

E. Tips for Preparing Your Comments 

F. Public Hearings 

II. Overview of Proposed Actions 

III. Regional Haze Background 

A. Description of Regional Haze 

B. History of Regional Haze Regulations 

C. Roles of Agencies in Addressing 

Regional Haze 

IV. Requirements for Regional Haze 

Implementation Plans 

A. Regional Haze Rule 

B. The Deciview 

C. Best Available Retrofit Technology 

D. The Grand Canyon Visibility Transport 

Commission and Section 309 

V. SIP and FIP Background 

A. History of State Submittals and EPA 

Actions 

B. EPA’s Authority To Promulgate a FIP 

VI. EPA’s Evaluation of Arizona’s BART 

Analyses and Determinations 

A. Arizona’s Identification of BART 

Sources 

B. Arizona’s BART Control Analysis 

1. Cost of Compliance 

2. Energy and Non-Air Quality 

Environmental Impacts 

3. Existing Pollution Control Technology 

4. Remaining Useful Life of the Source 

5. Degree of Visibility Improvement 

C. Arizona’s BART Determinations 

1. Apache Unit 1 

a. BART for NOX

b. BART for PM10

c. BART for SO2

2. Apache Units 2 and 3 

a. BART for NOX

b. BART for PM10

c. BART for SO2

3. Cholla Units 2, 3 and 4 

a. BART for NOX

b. BART for PM10

c. BART for SO2

4. Coronado Units 1 and 2 

a. BART for NOX

b. BART for PM10

c. BART for SO2

D. Enforceability of BART Limits 

VII. EPA’s Proposed FIP Actions 

A. EPA’s BART Analyses and 

Determinations 

1. Costs of Compliance 

2. Energy and Non-Air Environmental 

Impacts 

3. Pollution Control Equipment in Use at 

the Source 

4. Remaining Useful Life of the Source 

5. Degree of Improvement in Visibility 

a. Modeling Protocol 

b. Baseline Emissions 

c. Emission Reductions for Alternative 

Controls 

d. Visibility Impacts 

B. EPA’s FIP BART Determinations 

1. Apache Units 2 and 3 

a. Costs of Compliance 

b. Visibility Improvement 

c. EPA’s BART Determinations 

2. Cholla Units 2, 3 and 4 

a. Costs of Compliance 

b. Visibility Improvement 

c. EPA’s BART Determinations 

3. Coronado Units 1 and 2 

a. Costs of Compliance 

b. Visibility Improvement 

c. EPA’s BART Determinations 

C. Enforceability Requirements 

VIII. Summary of EPA’s Proposed Action 

IX. Statutory and Executive Order Reviews 

I. General Information 

A. Definitions 

For the purpose of this document, we 

are giving meaning to certain words or 

initials as follows: 

(1) The words or initials Act or CAA 

mean or refer to the Clean Air Act, 

unless the context indicates otherwise. 

(2) The initials ADEQ mean or refer to 

the Arizona Department of 

Environmental Quality. 

(3) The initials AEPCO mean or refer 

to Arizona Electric Power Cooperative. 

(4) The initials AFUDC mean or refer 

to allowance for funds used during 

construction. 

(5) The initials APS mean or refer 

Arizona Public Service Company. 

(6) The words Arizona and State 

mean the State of Arizona. 

(7) The initials BART mean or refer to 

Best Available Retrofit Technology. 

(8) The term Class I area refers to a 

mandatory Class I Federal area.1

(9) The initials CBI mean or refer to 

Confidential Business Information. 

(10) The initials CEMS mean or refer 

to continuous emission monitoring 

system. 

(11) The initials COFA mean or refer 

to close-coupled overfire air. 

(12) The initials CY mean or refer to 

Calendar Year 

(13) The initials EGU mean or refer to 

Electric Generating Unit. 

(14) The initials ESPs mean or refer to 

electrostatic precipitators. 

(15) The words EPA, we, us or our 

mean or refer to the United States 

Environmental Protection Agency. 


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(16) The initials FGD mean or refer to 

flue gas desulfurization. 

(17) The initials FGR mean or refer to 

flue gas recirculation. 

(18) The initials FIP mean or refer to 

Federal Implementation Plan. 

(19) The initials FLMs mean or refer 

to Federal Land Managers. 

(20) The initials IMPROVE mean or 

refer to Interagency Monitoring of 

Protected Visual Environments 

monitoring network. 

(21) The initials IPM mean or refer to 

Integrated Planning Model. 

(22) The initials LNB mean or refer to 

low-NOX burners. 

(23) The initials LTS mean or refer to 

Long-Term Strategy. 

(24) The initials MW mean or refer to 

megawatts. 

(25) The initials NEI mean or refer to 

National Emission Inventory. 

(26) The initials NH3 mean or refer to 

ammonia. 

(27) The initials NOX mean or refer to 

nitrogen oxides. 

(28) The initials NP mean or refer to 

National Park. 

(29) The initials OC mean or refer to 

organic carbon. 

(30) The initials OFA mean or refer to 

over fire air. 

(31) The initials PM mean or refer to 

particulate matter. 

(32) The initials PM2.5 mean or refer 

to fine particulate matter with an 

aerodynamic diameter of less than 2.5 

micrometers. 

(33) The initials PM10 mean or refer to 

particulate matter with an aerodynamic 

diameter of less than 10 micrometers 

(coarse particulate matter). 

(34) The initials PNG mean or refer to 

pipeline natural gas. 

(35) The initials ppm mean or refer to 

parts per million. 

(36) The initials PSD mean or refer to 

Prevention of Significant Deterioration. 

(37) The initials RAVI mean or refer 

to Reasonably Attributable Visibility 

Impairment. 

(38) The initials RMC mean or refer to 

Regional Modeling Center. 

(39) The initials RP mean or refer to 

Reasonable Progress. 

(40) The initials RPG or RPGs mean or 

refer to Reasonable Progress Goal(s). 

(41) The initials RPOs mean or refer 

to regional planning organizations. 

(42) The initials SCR mean or refer to 

Selective Catalytic Reduction. 

(43) The initials SIP mean or refer to 

State Implementation Plan. 

(44) The initials SNCR mean or refer 

to Selective Non-catalytic Reduction. 

(45) The initials SO2 mean or refer to 

sulfur dioxide. 

(46) The initials SOFA mean or refer 

to separated over fire air. 

(47) The initials SRP mean or refer to 

Salt River Project Agricultural 

Improvement and Power District. 

(48) The initials tpy mean tons per 

year. 

(49) The initials TSD mean or refer to 

Technical Support Document. 

(50) The initials VOC mean or refer to 

volatile organic compounds. 

(51) The initials WA mean or refer to 

Wilderness Area. 

(52) The initials WEP mean or refer to 

Weighted Emissions Potential. 

(53) The initials WFGD mean or refer 

to wet flue gas desulfurization. 

(54) The initials WRAP mean or refer 

to the Western Regional Air Partnership. 

B. Docket 

The proposed action relies on 

documents, information and data that 

are listed in the index on http://www.

regulations.gov under docket number 

EPA–R09–OAR–2012–0021. Although 

listed in the index, some information is 

not publicly available (e.g., Confidential 

Business Information (CBI)). Certain 

other material, such as copyrighted 

material, is publicly available only in 

hard copy form. Publicly available 

docket materials are available either 

electronically at http://www.regulations.

gov or in hard copy at the Planning 

Office of the Air Division, AIR–2, EPA 

Region 9, 75 Hawthorne Street, San 

Francisco, CA 94105. EPA requests that 

you contact the individual listed in the 

FOR FURTHER INFORMATION CONTACT

section to view the hard copy of the 

docket. You may view the hard copy of 

the docket Monday through Friday, 9– 

5:00 PDT, excluding Federal holidays. 

C. Instructions for Submitting 

Comments to EPA 

Written comments must be received at 

the address below on or before August 

31, 2012. Submit your comments, 

identified by Docket ID No. EPA–R09– 

OAR–2011–0021, by one of the 

following methods: 

• Federal Rulemaking portal: http://

www.regulations.gov. Follow the on-line 

instructions for submitting comments. 

• Email: Arizona_Regional_Haze@

epa.gov. 

• Fax: 415–947–3579 (Attention: 

Thomas Webb). 

• Mail, Hand Delivery or Courier: 

Thomas Webb, EPA Region 9, Air 

Division (AIR–2), 75 Hawthorne Street, 

San Francisco, California 94105. Hand 

and courier deliveries are only accepted 

Monday through Friday, 8:30 a.m.–4:30 

p.m., excluding Federal holidays. 

Special arrangements should be made 

for deliveries of boxed information. 

EPA’s policy is to include all 

comments received in the public docket 

without change. We may make 

comments available online at http://

www.regulations.gov, including any 

personal information provided, unless 

the comment includes information 

claimed to be CBI or other information 

for which disclosure is restricted by 

statute. Do not submit information that 

you consider to be CBI or that is 

otherwise protected through http://

www.regulations.gov or email. The 

http://www.regulations.gov Web site is 

an ‘‘anonymous access’’ system, which 

means EPA 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 EPA, without going through http://

www.regulations.gov, we will include 

your email address as part of the 

comment that is placed in the public 

docket and made available on the 

Internet. If you submit an electronic 

comment, EPA recommends 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 EPA cannot read your 

comment due to technical difficulties 

and cannot contact you for clarification, 

EPA may not be able to consider your 

comment. Electronic files should not 

include special characters or any form 

of encryption, and be free of any defects 

or viruses. 

D. Submitting Confidential Business 

Information 

Do not submit CBI to EPA through 

http://www.regulations.gov or email. 

Clearly mark the part or all of the 

information that you claim as CBI. For 

CBI information in a disk or CD–ROM 

that you mail to EPA, mark the outside 

of the disk or CD–ROM as CBI and 

identify electronically within the disk or 

CD–ROM the specific information that 

is claimed as CBI. In addition to one 

complete version of the comment that 

includes information claimed as CBI, 

you must submit a copy of the comment 

that does not contain the information 

claimed as CBI for inclusion in the 

public docket. We will not disclose 

information so marked except in 

accordance with procedures set forth in 

40 CFR part 2. 

E. Tips for Preparing Your Comments 

When submitting comments, 

remember to: 

• Identify the rulemaking by docket 

number and other identifying 

information (e.g., subject heading, 

Federal Register date and page number). 

• Explain why you agree or disagree; 

suggest alternatives and substitute 

language for your requested changes. 


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2For each BART source, the SIP must include a 

requirement to install and operate control 

equipment as expeditiously as practicable (40 CFR 

51.308(e)(1)(iv)); a requirement to maintain control 

equipment (40 CFR 51.308(e)(1)(v)); and procedures 

to ensure control equipment is properly operated 

and maintained, including requirements for 

monitoring, recordkeeping and reporting (40 CFR 

51.308(e)(1)(v)). 

• Describe any assumptions and 

provide any technical information and/ 

or data that you used. 

• If you estimate potential costs or 

burdens, explain how you arrived at 

your estimate in sufficient detail to 

allow for it to be reproduced. 

• Provide specific examples to 

illustrate your concerns, and suggest 

alternatives. 

• Explain your views as clearly as 

possible, avoiding the use of profanity 

or personal threats. 

• Make sure to submit your 

comments by the identified comment 

period deadline. 

F. Public Hearings 

EPA will hold a public hearing at the 

date, time and location stated below to 

accept oral and written comments into 

the record. 

Date: July 31, 2012. 

Open House: 4:00–5:00 p.m. 

Public Hearing: 6:00–8:00 p.m. 

Location: Sandra Day O’Connor 

Federal Courthouse (atrium and juror 

room), 401 W. Washington Street, 

Phoenix, AZ 85003–2118. 

To provide opportunities for 

questions and discussion, EPA will hold 

an open house prior to the public 

hearing. During the open house, EPA 

staff will be available informally to 

answer questions on our proposed rule. 

Any comments made to EPA staff 

during the open house must still be 

provided formally in writing or orally 

during a public hearing in order to be 

considered in the record. 

The public hearing will provide the 

public with an opportunity to present 

views or information concerning the 

proposed Regional Haze FIP for 

Arizona. EPA may ask clarifying 

questions during the oral presentations, 

but will not respond to the 

presentations at that time. Simultaneous 

translation in Spanish will be available 

during the public hearing. We will 

consider written statements and 

supporting information submitted 

during the comment period with the 

same weight as any oral comments and 

supporting information presented at the 

public hearing. Please consult section 

I.C, I.D. and I.E of this preamble for 

guidance on how to submit written 

comments to EPA. We will include 

verbatim transcripts of the hearing in 

the docket for this action. The EPA 

Region 9 Web site for the rulemaking, 

which includes the proposal and 

information about the public hearing, is 

at http://www.epa.gov/region9/air/ 

actions. 

II. Overview of Proposed Actions 

EPA proposes to partially approve 

and partially disapprove a portion of 

Arizona’s SIP for Regional Haze 

submitted to EPA Region 9 on February 

28, 2011, to meet the requirements of 

Section 308 of the Regional Haze Rule. 

EPA is proposing to take action only on 

the BART requirements for the three 

electric generating stations and units 

listed in Table 1. At this time, EPA is 

not proposing to take action on the 

State’s other BART determinations or 

any other parts of the SIP regarding the 

remaining requirements of the Regional 

Haze Rule. EPA takes very seriously a 

decision to disapprove a state plan, as 

we believe that it is preferable, and 

preferred in the provisions of the Clean 

Air Act, that these requirements be 

implemented through state plans. A 

state plan need not contain exactly the 

same provisions that EPA might require, 

but EPA must be able to find that the 

state plan is consistent with the 

requirements of the Act. Further, EPA’s 

oversight role requires that it assure fair 

implementation of Clean Air Act 

requirements by states across the 

country, even while acknowledging that 

individual decisions from source to 

source or state to state may not have 

identical outcomes. In this instance, we 

believe that Arizona’s SIP generally 

meets those requirements with respect 

to its SO2 and PM10 limits, but as we 

describe in more detail below, the SIP 

does not include several specifically 

required elements. The NOX BART 

determinations for the coal-fired units 

are neither consistent with the 

requirements of the Act nor with BART 

decisions that other states have made. 

As a result, EPA believes this proposed 

disapproval is the only path that is 

consistent with the Act at this time. 

Specifically, we propose the following: 

• Proposed Approval: EPA proposes 

to approve Arizona’s determination that 

the following sources and units are 

subject to BART: Arizona Electric Power 

Company’s (AEPCO) Apache Generating 

Station (Apache) Units 1, 2 and 3; 

Arizona Public Service’s (APS) Cholla 

Power Plant (Cholla) Units 2, 3 and 4; 

and Salt River Project’s (SRP) Coronado 

Generating Station (Coronado) Units 1 

and 2. We are proposing to approve the 

State’s emissions limits for SO2 and 

PM10 at all of these units, but are 

seeking comment on whether lower 

emissions limits may be warranted for 

any of these units, and whether an 

alternative test method should be 

accepted for measurement of PM10.

Finally, we are proposing to approve the 

emissions limits for NOX, SO2 and PM10

at Apache Unit 1. 

• Proposed Disapproval: Based on 

our evaluation described in this notice, 

we propose to disapprove the State’s 

BART emissions limits for NOX at all 

three sources and units except for 

Coronado Unit 2 and Apache Unit 1. We 

also propose to disapprove the 

compliance and equipment 

maintenance requirements for BART at 

all three sources, since these were not 

included in the revised SIP.2

• Proposed FIP: We propose to 

promulgate a Federal Implementation 

Plan (FIP) that includes emissions 

limitations representing BART for NOX

at all units except for Apache Unit 1. 

The proposed FIP also includes 

compliance schedules and requirements 

for equipment maintenance, monitoring, 

testing, recordkeeping and reporting for 

all the sources and units. The regulatory 

language for the FIP requirements is 

listed under PART 52 at the end of this 

notice. 

TABLE 1—SCOPE OF PROPOSED ACTION

Source name Owner Units Pollutants 

Apache Generating Station ..................... AEPCO ................................................... Steam Units 1, 2 and 3 .......................... NOX, SO2, PM10

Cholla Power Plant .................................. APS ........................................................ Steam Units 2, 3 and 4 .......................... NOX, SO2, PM10

Coronado Generating Station ................. SRP ........................................................ Units 1 and 2 ......................................... NOX, SO2, PM10


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3 Visual range is the greatest distance, in 

kilometers or miles, at which a dark object can be 

viewed against the sky. 

4Areas 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.’’ 

5EPA’s regional haze regulations require 

subsequent updates to the regional haze SIPs. 40 

CFR 51.308(g)–(i). 

6Pursuant to 40 CFR 51.301, ‘‘implementation 

plan’’ is defined as ‘‘any State Implementation Plan, 

Federal Implementation Plan, or Tribal 

Implementation Plan.’’ Therefore, although the 

requirements of the RHR are generally described in 

relation to SIPs, they are also relevant where EPA 

is promulgating a regional haze plan. 

III. Regional Haze Background 

A. Description of Regional Haze 

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 (e.g., sulfates, nitrates, 

organic carbon (OC), elemental carbon 

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

(e.g., sulfur dioxide, nitrogen oxides, 

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 (NPs) and wilderness 

areas (WAs). The average visual range 3

in many Class I areas (i.e., NPs and 

memorial parks, WAs, and international 

parks meeting certain size criteria) in 

the western United States is 100–150 

kilometers, or about one-half to twothirds 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). 

B. History of Regional Haze Regulations 

In section 169A of the 1977 

Amendments to the CAA, Congress 

created a program for protecting 

visibility in the nation’s national parks 

and wilderness areas. This section of the 

CAA establishes as a national goal the 

‘‘prevention of any future, and the 

remedying of any existing, impairment 

of visibility in mandatory Class I 

Federal areas 4 which impairment 

results from manmade air pollution.’’ 

EPA promulgated regulations on 

December 2, 1980, 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.’’ (45 FR 80084, December 

2, 1980). 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. 

As part of the 1990 Amendments to 

the CAA, Congress added section 169B 

to focus attention on regional haze 

issues. EPA promulgated a rule to 

address regional haze on July 1, 1999 

(64 FR 35714, July 1, 1999) codified at 

40 CFR part 51, subpart P (Regional 

Haze Rule). The primary regulatory 

requirements that address regional haze 

are found at 40 CFR 51.308 and 51.309 

and are summarized below. Under 40 

CFR 51.308(b), all states, the District of 

Columbia and the Virgin Islands are 

required to submit an initial state 

implementation plan (SIP) addressing 

regional haze visibility impairment no 

later than December 17, 2007.5

C. Roles of Agencies in Addressing 

Regional Haze 

Successful implementation of the 

regional haze program will require longterm regional coordination among 

states, tribal governments and various 

federal agencies. As noted above, 

pollution affecting the air quality in 

Class I areas can be transported over 

long distances, even hundreds of 

kilometers. Therefore, to effectively 

address the problem of visibility 

impairment in Class I areas, states, or 

the EPA when implementing a FIP, need 

to develop strategies in coordination 

with one another, taking into account 

the effect of emissions from one 

jurisdiction on the air quality in 

another. 

Because the pollutants that lead to 

regional haze can originate from sources 

located across broad geographic areas, 

EPA has encouraged the states and 

tribes across the United States to 

address visibility impairment from a 

regional perspective. Five regional 

planning organizations (RPOs) were 

developed to address regional haze and 

related issues. The RPOs first evaluated 

technical information to better 

understand how their states and tribes 

impact Class I areas across the country, 

and then pursued the development of 

regional strategies to reduce emissions 

of particulate matter and other 

pollutants leading to regional haze. 

The Western Regional Air Partnership 

(WRAP) RPO is a collaborative effort of 

state governments, tribal governments, 

and various federal agencies established 

to initiate and coordinate activities 

associated with the management of 

regional haze, visibility and other air 

quality issues in the western United 

States. WRAP member State 

governments include: Alaska, Arizona, 

California, Colorado, Hawaii, Idaho, 

Montana, New Mexico, North Dakota, 

Oregon, South Dakota, Utah, 

Washington, and Wyoming. Tribal 

members include Campo Band of 

Kumeyaay Indians, Confederated Salish 

and Kootenai Tribes, Cortina Indian 

Rancheria, Hopi Tribe, Hualapai Nation 

of the Grand Canyon, Native Village of 

Shungnak, Nez Perce Tribe, Northern 

Cheyenne Tribe, Pueblo of Acoma, 

Pueblo of San Felipe, and ShoshoneBannock Tribes of Fort Hall. 

IV. Requirements for Regional Haze 

Implementation Plans 

A. Regional Haze Rule 

The Regional Haze Rule (RHR) sets 

out specific requirements for states’ 

initial regional haze implementation 

plans.6 In particular, each state’s plan 

must establish a long-term strategy that 

ensures reasonable progress toward 

achieving natural visibility conditions 

in each Class I area affected by the 

emissions from sources within the state. 

In addition, for each Class I area within 

the state’s boundaries, the plan must 

establish a reasonable progress goal 

(RPG) for the first planning period that 

ends on July 31, 2018. The long-term 

strategy must include enforceable 

emission limits and other measures as 

necessary to achieve the RPG. Regional 

haze plans must also give specific 


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7The preamble to the RHR provides additional 

details about the deciview (64 FR 35714, 35725 July 

1, 1999). 8The set of ‘‘major stationary sources’’ potentially 

subject to BART is listed in CAA section 169A(g)(7). 

9CAA section 169(g)(4); 40 CFR 51.308(e)(1)(iv). 

10 40 CFR 51.308(e)(1)(v). See also CAA section 

302(k) (defining ‘‘emission limitation’’ as ‘‘a 

requirement established by the State or the 

Administrator which limits the quantity, rate, or 

concentration of emissions of air pollutants on a 

continuous basis, including any requirement 

relating to the operation or maintenance of a source 

to assure continuous emission reduction * * *’’) 

(emphasis added). 

11See CAA section 110(a)(2) (requirements for 

SIPs). 

attention to certain stationary sources 

that were in existence on August 7, 

1977, but were not in operation before 

August 7, 1962. These sources, where 

appropriate, are required to install 

BART controls to eliminate or reduce 

visibility impairment. Although such 

BART determinations can be a part of a 

reasonable progress strategy, BART is 

also an independent requirement that 

can be assessed separately from the 

other requirements of the RHR. Because 

this proposal only pertains to BART at 

three specific sources, we do not discuss 

other requirements of the RHR below. 

B. The Deciview 

The RHR establishes the deciview 

(dv) as the principal metric for 

measuring visibility. This visibility 

metric expresses uniform changes in 

haziness in terms of common 

increments across the entire range of 

visibility conditions, from pristine to 

extremely hazy conditions. Visibility 

expressed in deciviews is determined by 

using air quality measurements to 

estimate light extinction and then 

transforming the value of light 

extinction to deciviews using a 

logarithmic function. The deciview is a 

more useful measure for tracking 

progress in improving visibility than 

light extinction because each deciview 

change is an equal incremental change 

in visibility as perceived by the human 

eye.7

C. Best Available Retrofit Technology 

Section 169A of the CAA directs 

states to evaluate the use of retrofit 

controls at certain larger, often 

uncontrolled, older stationary sources in 

order to address visibility impacts from 

these sources. Specifically, section 

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

to revise their SIPs to contain such 

measures as may be necessary to make 

reasonable progress towards the natural 

visibility goal, including a requirement 

that certain categories of existing major 

stationary sources 8 built between 1962 

and 1977 procure, install, and operate 

the ‘‘Best Available Retrofit 

Technology’’ as determined by the state. 

Under the RHR, states are directed to 

conduct BART determinations for such 

‘‘BART-eligible’’ sources that may be 

anticipated to cause or contribute to any 

visibility impairment in a Class I area. 

Rather than requiring source-specific 

BART controls, states also have the 

flexibility to adopt an emissions trading 

program or other alternative program as 

long as the alternative provides greater 

reasonable progress towards improving 

visibility than BART. 

EPA published the Guidelines for 

BART Determinations under the 

Regional Haze Rule at Appendix Y to 40 

CFR part 51 (hereinafter referred to as 

the ‘‘BART Guidelines’’) on July 6, 2005. 

The Guidelines are to assist states in 

determining which of their sources 

should be subject to the BART 

requirements and in determining 

appropriate emission limits for each 

such ‘‘subject-to-BART’’ source. In 

making BART determinations for fossil 

fuel-fired electric generating plants with 

a total generating capacity in excess of 

750 megawatts, states must use the 

approach set forth in the BART 

Guidelines. States are encouraged, but 

not required, to follow the BART 

Guidelines in making BART 

determinations for other types of 

sources. States must address all 

visibility-impairing pollutants emitted 

by a source in the BART determination 

process. The most significant visibility 

impairing pollutants are SO2, NOX and 

PM. EPA has indicated that states 

should use their best judgment in 

determining whether VOC or NH3

compounds impair visibility in Class I 

areas. 

Under the BART Guidelines, states 

may select an exemption threshold 

value for their BART modeling, below 

which a BART-eligible source would 

not be expected to cause or contribute 

to visibility impairment in any Class I 

area. The state must document this 

exemption threshold value in the SIP 

and must state the basis for its selection 

of that value. Any source with 

emissions that model above the 

threshold value would be subject to a 

BART determination review. The BART 

Guidelines acknowledge varying 

circumstances affecting different Class I 

areas. In setting their exemption 

threshold values, states should consider 

the number of emission sources 

affecting the Class I areas at issue and 

the magnitude of the individual sources’ 

impacts. An exemption threshold set by 

the state should not be higher than 0.5 

deciview. 

In their SIPs, states must identify 

potential BART sources, described in 

the RHR as ‘‘BART-eligible sources,’’ 

and document their BART control 

determination analyses. In making 

BART determinations, section 

169A(g)(2) of the CAA requires that 

states consider the following factors: (1) 

The costs of compliance; (2) the energy 

and non-air quality environmental 

impacts of compliance; (3) any existing 

pollution control technology in use at 

the source; (4) the remaining useful life 

of the source; and (5) the degree of 

improvement in visibility which may 

reasonably be anticipated to result from 

the use of such technology. States are 

free to determine the weight and 

significance assigned to each factor, but 

must consider all five factors and 

provide a reasoned explanation for 

adopting the technology selected as 

BART, based on the five factors. 

A regional haze SIP must include 

source-specific BART emission limits 

and compliance schedules for each 

source subject to BART, unless the SIP 

includes an alternative program that 

provides greater reasonable progress 

towards improving visibility than BART 

and meets the other requirements of 40 

CFR 51.308(e)(2). Once a state has made 

its BART determination, the BART 

controls must be installed and in 

operation as expeditiously as 

practicable, but no later than five years 

after the date EPA approves the regional 

haze SIP.9 The Regional Haze SIP must 

also contain a requirement for each 

BART source to maintain the relevant 

control equipment, as well as 

procedures to ensure control equipment 

is properly operated and maintained.10

In addition to what is required by the 

RHR, general SIP requirements mandate 

that the SIP must also include all 

regulatory requirements related to 

monitoring, recordkeeping and 

reporting for the BART emissions 

limitations.11

D. The Grand Canyon Visibility 

Transport Commission and Section 309 

In addition to the general 

requirements of the regional haze 

program, the RHR also includes 40 CFR 

51.309, which contains the strategies 

developed by the Grand Canyon 

Visibility Transport Commission 

(GCVTC), established under Section 

169B(f) of CAA, 42 U.S.C. 7492(f). 

Certain western States and Tribes were 

eligible to submit implementation plans 

under section 309 as an alternative 

method of achieving reasonable progress 

for Class I areas that were covered by 

the GCVTC’s analysis—i.e., the 16 Class 

I areas on the Colorado Plateau. In order 

for States and Tribes to be able to utilize 

this section, however, the rule provided 

that EPA must receive an ‘‘Annex’’ to 


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12Center for Energy and Economic Development 

v. EPA, 398 F.3d 653 (D.C. Circuit 2005). 

13Letter from Stephen A. Owens, ADEQ, to 

Wayne Nastri, EPA (December 14, 2008). 

14See CAA section 110(k)(1)(B). 

the GCVTC’s final recommendations. 

The purpose of the Annex was to 

provide the specific provisions needed 

to translate the GCVTC’s general 

recommendations for stationary source 

SO2 reductions into an enforceable 

regulatory program. The rule provided 

that such an Annex, meeting certain 

requirements, be submitted to EPA no 

later than October 1, 2000, see 40 CFR 

51.309(d)(4) and 51.309(f). The Annex 

was submitted in 2000, and EPA revised 

40 CFR 51.309 in 2003. See 68 FR 

33764, June 5, 2003. 

V. SIP and FIP Background 

A. History of State Submittals and EPA 

Actions 

Since four of its twelve mandatory 

Class I Federal areas are on the Colorado 

Plateau, Arizona had the option of 

submitting a Regional Haze SIP under 

section 309 of the Regional Haze Rule. 

A SIP that is approved by EPA as 

meeting all of the requirements of 

section 309 is ‘‘deemed to comply with 

the requirements for reasonable progress 

with respect to the 16 Class I areas [on 

the Colorado Plateau] for the period 

from approval of the plan through 

2018.’’ 40 CFR 51.309(a). When these 

regulations were first promulgated, 309 

submissions were due no later than 

December 31, 2003. Accordingly, the 

Arizona Department of Environmental 

Quality (ADEQ) submitted to EPA on 

December 23, 2003, a 309 SIP for 

Arizona’s four Class I Areas on the 

Colorado Plateau. ADEQ submitted a 

revision to its 309 SIP, consisting of 

rules on emissions trading and smoke 

management, and a correction to the 

state’s regional haze statutes, on 

December 31, 2004. EPA approved the 

smoke management rules submitted as 

part of the 2004 revisions, see 71 FR 

28270 and 72 FR 25973, but did not 

propose or take final action on any other 

portion of the 309 SIP. 

In response to an adverse court 

decision,12 EPA revised 40 CFR 51.309 

on October 13, 2006, making a number 

of substantive changes and requiring 

states to submit revised 309 SIPs by 

December 17, 2007. See 71 FR 60612. 

Subsequently, ADEQ sent a letter to 

EPA dated December 14, 2008, 

acknowledging that it had not submitted 

a SIP revision to address the 

requirements of 309(d)(4) related to 

stationary sources and 309(g), which 

governs reasonable progress 

requirements for Arizona’s eight 

mandatory Class I areas outside of the 

Colorado Plateau.13

EPA made a finding on January 15, 

2009, that 37 states, including Arizona, 

had failed to make all or part of the 

required SIP submissions to address 

regional haze. See 74 FR 2392. 

Specifically, EPA found that Arizona 

failed to submit the plan elements 

required by 40 CFR 309(d)(4) and (g). 

EPA sent a letter to ADEQ on January 

14, 2009, notifying the state of this 

failure to submit a complete SIP. ADEQ 

later decided to submit a SIP under 

section 308, instead of section 309. 

ADEQ adopted and transmitted its 

Regional Haze SIP under Section 308 of 

the Regional Haze Rule (‘‘Arizona 

Regional Haze SIP’’) to EPA Region 9 in 

a letter dated February 28, 2011. The 

plan was determined complete by 

operation of law on August 28, 2011.14

The SIP was properly noticed by the 

State and available for public comment 

for 30 days prior to a public hearing 

held in Phoenix, Arizona, on December 

2, 2010. Arizona included in its SIP 

responses to written comments from 

EPA Region 9, the National Park 

Service, the U.S. Forest Service, and 

other stakeholders including regulated 

industries and environmental 

organizations. The Arizona Regional 

Haze SIP is available to review in the 

docket for the proposed rule. 

B. EPA’s Authority To Promulgate a FIP 

Under CAA section 110(c), EPA is 

required to promulgate a Federal 

Implementation Plan within two years 

of the effective date of a finding that a 

state has failed to make a required SIP 

submission. The FIP requirement is void 

if a state submits a regional haze SIP, 

and EPA approves that SIP within the 

two-year period. See 74 FR 2392, 

January 15, 2009. Specifically, CAA 

section 110(c) provides: 

(1) The Administrator shall 

promulgate a Federal implementation 

plan at any time within 2 years after the 

Administrator— 

(A) finds that a State has failed to 

make a required submission or finds 

that the plan or plan revision submitted 

by the State does not satisfy the 

minimum criteria established under 

[CAA section 110(k)(1)(A)], or 

(B) disapproves a State 

implementation plan submission in 

whole or in part, unless the State 

corrects the deficiency, and the 

Administrator approves the plan or plan 

revision, before the Administrator 

promulgates such Federal 

implementation plan. 

Section 302(y) defines the term 

‘‘Federal implementation plan’’ in 

pertinent part, as: 

[A] plan (or portion thereof) promulgated 

by the Administrator to fill all or a portion 

of a gap or otherwise correct all or a portion 

of an inadequacy in a State implementation 

plan, and which includes enforceable 

emission limitations or other control 

measures, means or techniques (including 

economic incentives, such as marketable 

permits or auctions or emissions allowances). 

Thus, because we determined that 

Arizona failed to timely submit a 

Regional Haze SIP, we are required to 

promulgate a Regional Haze FIP for 

Arizona, unless we first approve a SIP 

that corrects the non-submittal 

deficiencies identified in our finding of 

January 15, 2009. For the reasons 

explained below, we are proposing to 

partially approve and partially 

disapprove the Arizona Regional Haze 

SIP. Therefore, we are proposing a FIP 

to address those portions of the SIP that 

we are proposing to disapprove. If 

Arizona submits a SIP revision that 

addresses the deficiencies in sufficient 

time for EPA to review the submission, 

then we would prefer to act on that 

submittal, if such action is consistent 

with our obligations under the CAA and 

applicable court orders. 

VI. EPA’s Evaluation of Arizona’s 

BART Analyses and Determinations 

A. Arizona’s Identification of BART 

Sources 

ADEQ’s Analysis: In the first step of 

the BART process, ADEQ identified all 

the BART-eligible sources within the 

jurisdiction of the State and local 

agencies, and applied the three 

eligibility criteria in the RHR (40 CFR 

51.301) to these facilities. The criteria 

are: (1) One or more emission units at 

the facility are classified in one of the 

26 industrial source categories listed in 

the BART Guidelines; (2) the emission 

unit(s) did not operate before August 7, 

1962, but was in existence on August 7, 

1977; and (3) the total potential to emit 

of any visibility impairing pollutant 

from the subject emission units is 

greater or equal to 250 tons per year. 

ADEQ determined that Apache, Cholla 

and Coronado have emissions units that 

meet these criteria. 

In a second step, ADEQ identified 

those BART-eligible sources that may 

reasonably be anticipated to cause or 

contribute to visibility impairment at 

any Class I area. The BART Guidelines 

allow states to consider exempting some 

BART-eligible sources from BART 

review in the event that they may not 


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15 70 FR 39104, 39161, July 6, 2005. 

16See Docket Item B–15. 

17EPA subsequently required the uses of 

CALPUFF and CALMET version 5.8 for new 

modeling applications. However, EPA is accepting 

BART modeling performed according to a 

previously approved protocol, as was the case for 

the WRAP protocol. 

18See Docket Item No. B–12. Visibility impacts as 

listed in ‘‘Summary of WRAP RMC BART Modeling 

for Arizona’’ Draft No. 5, May 7, 2005. Initial draft 

released on April 4, 2005. 

19 40 CFR part 51, appendix Y, § IV.D. 

20Step 4 includes evaluating the cost of 

compliance, energy impacts, non-air quality 

environmental impacts, and remaining useful life. 

21Arizona Regional Haze SIP, pp. 138–143. 

22We note that, while ADEQ refers to its Step 5 

as an evaluation of energy and non-air quality 

environmental impacts, this step also includes 

consideration of the costs of compliance and the 

remaining useful life of the source, consistent with 

the BART Guidelines, 40 CFR part 51, appendix Y, 

§ IV.D.4. 

reasonably be anticipated to cause or 

contribute to any visibility impairment 

in a Class I area. For states using 

modeling to determine the applicability 

of BART to single sources, the BART 

Guidelines note that the first step is to 

set a contribution threshold to assess 

whether the impact of a single source is 

sufficient to cause or contribute to 

visibility impairment at a Class I area. 

Further, the BART Guidelines state that, 

‘‘[a] single source that is responsible for 

a 1.0 deciview change or more should 

be considered to ‘cause’ visibility 

impairment.’’ 15 The BART Guidelines 

also state that ‘‘the appropriate 

threshold for determining whether a 

source contributes to visibility 

impairment’ may reasonably differ 

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

matter, any threshold that you use for 

determining whether a source 

‘contributes’ to visibility impairment 

should not be higher than 0.5 

deciviews.’’ For determining whether a 

source is subject to BART, ADEQ used 

a contribution threshold of 0.50 dv. 

The WRAP’s Regional Modeling 

Center (RMC) developed a modeling 

protocol, entitled ‘‘CALMET/CALPUFF 

Protocol for BART Exemption Screening 

Analysis for Class I Areas in the 

Western United States.’’ 16 The protocol 

specified the use of CALPUFF version 

6.112 and CALMET version 6.211, 

which were the accepted model 

versions at the time.17 The WRAP RMC 

used this protocol to perform CALPUFF 

modeling for each of the western states. 

ADEQ then relied on the RMC’s 

modeling to assess the potential of 

BART-eligible sources to cause or 

contribute to Class I visibility 

impairment. The visibility impacts of 

AEPCO Apache Generating Station, APS 

Cholla Power Plant, and SRP Coronado 

Generating Station are each well above 

the 0.5 dv ‘‘contribution’’ threshold as 

well as the 1.0 dv ‘‘causation’’ 

threshold.18 As a result, ADEQ 

determined that emissions units at the 

Apache, Cholla, and Coronado facilities 

are subject to BART as listed in Table 

2. 

TABLE 2—SOURCES SUBJECT TO BART 

Facility BART emission units Source category Pollutants 

evaluated 

WRAP 

modeled 

impact a

AEPCO Apache Generating Station.Units 1, 2, and 3 ............... Fossil-fuel fired steam electric plants of more than 

250 million British thermal units per hour heat input.

NOX, SO2, PM10 1.95 dv 

APS Cholla Power Plant ... Units 2, 3, and 4 ............... ...................................................................................... NOX, SO2, PM10 2.88 dv 

SRP Coronado Generating 

Station.

Units 1 and 2 .................... ...................................................................................... NOX, SO2, PM10 3.32 dv 

aAverage of the 98th percentile across 2001, 2002 and 2003 for the most affected Class I Area. 

EPA’s Evaluation: We are proposing 

to approve ADEQ’s determination that 

Apache, Cholla, and Coronado are 

eligible for and subject to a BART 

control analysis. Each of the three 

facilities addressed in this notice 

(Apache, Cholla and Coronado) agreed 

with ADEQ’s determination that they 

are subject to BART. While we do not 

agree with all aspects of the process by 

which ADEQ identified its eligible-forBART and subject-to-BART sources, we 

do agree with ADEQ that the three 

facilities in this notice are eligible for 

and subject to BART. Since our action 

today focuses on only the three 

facilities, we will address ADEQ’s other 

subject-to-BART determinations in a 

separate action at a later date. 

B. Arizona’s BART Control Analysis 

The third step of the BART evaluation 

is to perform a five-factor BART analysis 

as the basis for making a BART control 

determination. In performing this 

analysis, 40 CFR 51.308(e)(1)(ii)(A) 

requires that states consider the 

following factors on a pollutant-bypollutant basis: (1) The costs of 

compliance of each technically feasible 

control technology, (2) the energy and 

non-air quality environmental impacts 

of compliance of the control 

technologies, (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. These 

factors are frequently referred to as the 

‘‘five-factor analysis’’ for the RHR BART 

determination. 

The BART Guidelines recommend 

that a BART analysis include the 

following five steps. The Guidelines 

provide detailed instructions on how to 

perform each of these steps.19

• 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,20 and 

• Step 5—Evaluate Visibility Impacts. 

ADEQ’s Analysis: ADEQ’s BART 

analyses mostly followed this approach, 

with the addition of a step to identify 

existing control technologies and a step 

concluding ‘‘selection of BART.’’ 21

Thus, ADEQ’s analyses included the 

following seven steps: 

• Step 1: Identify the Existing Control 

Technologies in Use at the Source 

• Step 2: Identify All Available Retrofit 

Control Options 

• Step 3: Eliminate All Technically 

Infeasible Control Options 

• Step 4: Evaluate Control Effectiveness 

of Remaining Technologies 

• Step 5: Evaluate the Energy and NonAir Quality Environmental Impacts 

and Document Results 22

• Step 6: Evaluate Visibility Impacts 

• Step 7: Select BART 

EPA’s Evaluation: We find that this 

overall approach to the five-factor 

analysis is generally reasonable and 

consistent with the RHR and the BART 

Guidelines. With respect to the three 


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23We do not believe that ADEQ appropriately 

used ‘‘the most stringent emission control level that 

the technology is capable of achieving’’ for SCR per 

the BART Guidelines at 40 CFR part 51, appendix 

Y, § IV.D.3. This issue is addressed on a source-bysource basis under the cost and visibility factors of 

our evaluation in section VI.C. 

24Arizona Regional Haze SIP, Appendix D, p. 63. 

25See, e.g. id. p. 53. 

26Note that the issue here is not whether an 

individual in a given time and place would 

perceive the deciview benefits occurring at different 

Class I areas and under possibly different 

meteorological conditions. Rather, the issue is 

accounting in some way for the full set of expected 

visibility benefits. A national program for 

addressing regional haze must inherently address 

the multiple areas that occur in a region. 

sources covered by this action, we find 

that ADEQ’s implementation of the first 

four steps of its approach is generally 

reasonable and consistent with the RHR 

and the BART Guidelines. However, we 

do not agree with ADEQ’s analysis in 

steps 5 through 7.23 In particular, under 

step 5, we find that the costs of control 

were not calculated in accordance with 

the BART Guidelines; under step 6, we 

find that the visibility impacts were not 

appropriately evaluated and considered; 

and under step 7, we find that ADEQ 

did not provide a sufficient explanation 

and rationale for its determinations. 

While we find these problems in all of 

ADEQ’s BART analyses for the three 

sources, they do not appear to have had 

a substantive impact on ADEQ’s 

selection of controls for SO2 and PM10. 

With respect to ADEQ’s NOX BART 

determinations, however, we find that 

these problems resulted in control 

determinations that are inconsistent 

with the RHR and the BART Guidelines. 

We summarize below how ADEQ 

applied the five factors and identify a 

number of issues common to the three 

relevant sources. 

1. Cost of Compliance 

ADEQ included information relating 

to costs of compliance in its RH SIP, 

including information on total 

annualized costs, cost per ton of 

pollutant removed, and incremental cost 

per ton of pollutant removed for the 

various control options considered. Cost 

calculations were prepared by 

consulting firms on behalf of the 

facilities as part of their BART analyses 

that relied on a combination of vendor 

quotes, facility data, and internal cost 

calculation methodology. These BART 

analyses were subsequently submitted 

to ADEQ. Upon review, ADEQ 

requested certain clarifying information 

from the facilities regarding these cost 

calculations, including greater detail on 

the underlying assumptions and 

additional supporting documentation. 

ADEQ received responses of varying 

detail to these requests, and included 

this information as part of its RH SIP. As 

described in further detail in the 

discussion of each facility, there are 

certain aspects of these cost calculations 

that we find inconsistent with the BART 

Guidelines and EPA’s Control Cost 

Manual. We also disagree with the 

manner in which ADEQ interpreted the 

cost-related information included in its 

RH SIP. 

2. Energy and Non-Air Quality 

Environmental Impacts 

In its BART analyses, ADEQ 

identified only minor energy and nonair quality impacts for SO2 or PM10

control strategies. Regarding NOX

emissions, ADEQ’s BART analyses point 

out that the various control options will 

incur increased energy usage by any 

electric generating unit (EGU) where 

they are installed. In particular, 

Selective Catalytic Reduction (SCR) 

retrofit will cause an additional pressure 

drop in the flue gas system due to the 

catalyst, increasing power requirements. 

Additionally, ADEQ’s SIP submission 

asserts that ammonia levels in fly ash 

due to Selective Non-catalytic 

Reduction (SNCR) and SCR installations 

could affect the decision of facility 

managers to sell or dispose of fly ash.24

Finally, the Arizona SIP notes that 

SNCR and SCR may involve potential 

safety hazards associated with the 

transportation and handling of 

anhydrous ammonia.25 However, ADEQ 

did not cite any of these potential 

energy and non-air impacts as the basis 

for eliminating any otherwise feasible 

control strategies for NOX. EPA concurs 

that these impacts do not warrant 

elimination of any of the control 

options. 

3. Existing Pollution Control 

Technology 

The presence of existing pollution 

control technology is reflected in the 

BART analysis in two ways: First, in the 

consideration of available control 

technologies (step 1 of ADEQ’s 

analysis), and second, in the 

development of baseline emission rates 

for use in cost calculations and visibility 

modeling (steps 5 and 6 of ADEQ’s 

analysis). As described in greater detail 

in the discussion for each facility, 

AEPCO, APS, and SRP used baseline 

time periods that varied from 2001 to 

2007. The respective baseline emissions 

and existing pollution control 

technology used in the BART analyses 

reflect the levels of control in place at 

the time. EPA considers ADEQ’s 

approach to be reasonable and generally 

consistent with the RHR and the BART 

Guidelines. 

4. Remaining Useful Life of the Source 

The remaining useful life of the 

source is usually considered as a 

quantitative factor in estimating the cost 

of compliance. With the exception of 

Apache Generating Station Unit 1, 

ADEQ used the default 20-year 

amortization period in the EPA Cost 

Control Manual as the remaining useful 

life of the facilities in its RH SIP. 

Without commitments for an early shut 

down of an EGU, it is not appropriate 

to consider a shorter amortization 

period in a BART analysis. 

5. Degree of Visibility Improvement 

ADEQ assessed the degree of 

improvement in visibility from 

candidate BART technologies using 

models and procedures generally in 

accord with EPA guidance. ADEQ relied 

on visibility analysis performed by the 

facilities, which used the WRAP RMC’s 

modeling protocol. However, ADEQ’s 

use of the modeling results in making 

BART decisions is problematic in 

several respects. First, ADEQ appears to 

have considered the visibility benefit of 

controls at only a single Class I area for 

each facility, even though there are nine 

to seventeen Class I areas nearby, 

depending on the facility. Since the 

facilities’ modeling results indicated 

that controls would contribute to 

visibility improvement in multiple Class 

I areas, consideration of the benefits in 

additional areas is warranted. Although 

the RHR and the BART Guidelines do 

not prescribe a particular approach to 

calculating or considering visibility 

benefits across multiple Class I areas, 

overlooking significant visibility 

benefits at additional areas considerably 

understates the overall benefit of 

controls to improve visibility. A more 

complete assessment of the degree of 

visibility improvement for candidate 

BART controls would include 

consideration of the number of areas 

affected and the degree of visibility 

improvement expected in all areas. One 

could conduct this type of analysis by 

summing the benefits over the areas, or 

by some other quantitative or qualitative 

procedure.26 The procedure followed by 

ADEQ is not a sufficient basis for 

making BART determinations for 

sources with substantial benefits across 

many Class I areas. 

Second, ADEQ appears to have 

considered benefits from controls on 

only one emitting unit at a time. 

However, because the plumes from 

individual units overlap more or less 

completely by the time they reach a 


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42842 Federal Register / Vol. 77, No. 140 / Friday, July 20, 2012 / Proposed Rules 

27 Interagency Workgroup on Air Quality 

Modeling (IWAQM) Phase 2 Summary Report and 

Recommendations for Modeling Long Range 

Transport Impacts (EPA–454/R–98–019), EPA 

OAQPS, December 1998, http://www.epa.gov/ 

scram001/7thconf/calpuff/phase2.pdf. 

28See Docket Item B–2. Page 2–1 of AEPCO 

Apache 1 BART Analysis. 

Class I area, the visibility benefits from 

controls on multiple units would be 

approximately additive. This issue of 

additive unit benefits could be 

addressed in some way without 

modeling all the units together, but 

ADEQ does not appear to have done 

this, and therefore underestimated the 

degree of visibility improvement from 

controls. 

Finally, the ammonia background 

concentration assumed for Cholla and 

Coronado may be too low, ranging from 

1 ppb to as low as 0.2 ppb. Nitrogen 

oxides and SO2 emissions affect 

visibility after chemically transforming 

into particulate ammonium nitrate and 

ammonium sulfate, respectively. This 

process is limited by the amount of 

ammonia present, so modeling with a 

low assumed ammonia background may 

underestimate visibility impacts and 

thus the visibility benefit of controls. 

Ambient ammonia measurements for 

use as input to modeling are scarce, and 

measurements that include it in the 

form of ammonium even scarcer. In the 

absence of compelling ammonia 

background estimates, EPA guidance 

recommends the use of a 1 ppb 

ammonia background for areas in the 

west.27

C. Arizona’s BART Determinations 

Our evaluation of ADEQ’s BART 

determinations is organized by source, 

unit and pollutant with a focus on the 

cost and visibility factors of the BART 

analysis. A summary of the State’s 

BART determinations for the three 

sources is in Table 3. ADEQ’s BART 

determinations for NOX consist of 

combustion controls, either in the form 

of low-NOX burners (LNB) with flue gas 

recirculation (FGR), or LNB with 

overfire air (OFA) or separated overfire 

air (SOFA). For PM10, ADEQ’s BART 

determinations consist of fuel switching 

to pipeline natural gas (PNG) for Apache 

Unit 1, and add-on particulate controls 

such as electrostatic precipitators (ESPs) 

or fabric filters for the remaining units. 

For SO2, ADEQ’s BART determinations 

consist of fuel-switching to PNG for 

Apache Unit 1, and wet flue gas 

desulfurization (FGD) systems that are 

either already in place or planned for 

the remaining units. 

TABLE 3—SUMMARY OF ARIZONA’S BART DETERMINATIONS

Unit Size 

(MW) Fuel 

NOX PM10 SO2

Control 

technology 

Emission 

limit * 

Control 

technology 

Emission 

limit * 

Control 

technology 

Emission 

limit * 

Apache 1 .................... 75 Natural Gas ....... LNB w/FGR, PNG use 0.056 PNG use ..................... 0.0075 PNG use ..................... 0.00064 

Apache 2 .................... 195 Coal ................... LNB w/OFA ................ 0.31 ESP (upgraded) .......... 0.03 Wet FGD (existing) ..... 0.15 

Apache 3 .................... 195 Coal ................... LNB w/OFA ................ 0.31 ESP (upgraded) .......... 0.03 Wet FGD (existing) ..... 0.15 

Cholla 2 ...................... 305 Coal ................... LNB w/SOFA .............. 0.22 Fabric filter .................. 0.015 Wet FGD (existing) ..... 0.15 

Cholla 3 ...................... 305 Coal ................... LNB w/SOFA .............. 0.22 Fabric filter (existing) .. 0.015 Wet FGD (existing) ..... 0.15 

Cholla 4 ...................... 425 Coal ................... LNB w/SOFA .............. 0.22 Fabric filter (existing) .. 0.015 Wet FGD (existing) ..... 0.15 

Coronado 1 ................. 411 Coal ................... LNB w/OFA ................ 0.32 Hot-side ESP .............. 0.03 Wet FGD (per Consent Decree).0.08 

Coronado 2 ................. 411 Coal ................... LNB w/OFA ................ 0.32 Hot-side ESP .............. 0.03 Wet FGD (per Consent Decree).0.08 

* Emission limits are in lb/MMBtu. 

1. Apache Unit 1 

Apache Generating Station (Apache) 

consists of seven EGUs with a total 

plant-wide generating capacity of 560 

megawatts. Unit 1 is a wall-fired boiler 

with a net unit output of 85 MW that 

burns pipeline-quality natural gas as its 

primary fuel, but also has the capability 

to use No. 2 through No. 6 fuel oils. At 

present, no emissions control 

equipment is installed on Unit 1. 

ADEQ’s BART analyses for Apache Unit 

1 relied largely on data and analyses 

provided by AEPCO and its contractor. 

These data and analyses are 

summarized below, along with ADEQ’s 

determinations for each pollutant and 

EPA’s evaluations of these analyses and 

determinations. 

a. BART for NOX

ADEQ’s Analysis: Unit 1 currently 

operates with no NOX controls. In its 

BART analysis submitted to ADEQ, 

AEPCO developed baseline emissions 

for multiple fuel-use scenarios 

including natural gas, and No. 2 and 

No. 6 fuel oil usage. Baseline natural gas 

emissions were based on the highest 75 

percent load 24-hour NOX emission 

levels reported in EPA’s Acid Rain 

Database for 2006. Since the only fuel 

burned in 2006 was natural gas, baseline 

emissions for No. 2 or No. 6 fuel oil 

usage could not be developed based on 

data from 2006. As a simplifying 

assumption, baseline No. 2 fuel oil NOX

emissions were assumed to be equal to 

natural gas usage. Baseline emissions for 

No. 6 fuel oil usage were estimated 

using AP–42 emission factors.28 A 

summary of baseline emissions for 

various fuels is provided in Table 4. 

TABLE 4—APACHE UNIT 1: ARIZONA’S BASELINE EMISSION FACTORS a

Pollutant 

Natural 

Gas 

(lb/MMBtu) 

No. 2 

Fuel oil 

No. 6 

fuel oil 

NOX .................................................................................................................................................. 0 .147 0.147 0 .301 

PM10 ................................................................................................................................................. 0 .0075 0.014 0 .0737 

SO2 .................................................................................................................................................. 0 .00064 0.051 0 .906 

aSee Docket Item B–02 (Table 3–1 of AEPCO Apache 1 BART Analysis). 


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29See Docket Item B–02. Appendix A (Economic 

Analysis) of AEPCO Apache 1 BART Analysis. 

30See Docket Item B–02. Page 2–1 of AEPCO 

Apache 1 BART Analysis. 

31See Docket Item B–01. Emission rate as 

specified in Table 10.2, Appendix D (Technical 

Support Document) of Arizona Regional Haze SIP. 

32See Docket Item B–02, Page 2–1 of AEPCO 

Apache 1 BART Analysis. 

AEPCO examined multiple control 

technologies and options for Apache 

Unit 1, including combustion controls, 

post combustion add-on controls, and 

fuel-switching. A summary of cost of 

compliance and degree of visibility 

improvement for these options is in 

Table 5. These cost and visibility 

improvement values are based on 

baseline and control case emissions 

corresponding to No. 6 fuel oil usage, 

which of the three fuels considered is 

the fuel type that generates the greatest 

NOX emissions. 

TABLE 5—APACHE UNIT 1: ARIZONA’S COST AND VISIBILITY ANALYSIS FOR NOX

Control option b

Emission 

rate 

(lb/MMBtu) 

Emissions 

removed 

(tons/yr) 

Annualized 

cost 

($/year) 

Costeffectiveness d

($/ton) 

Visibility Improvement c

(dv) 

Average 

Incremental 

(from 

previous) 

Total (from 

base case) 

Incremental 

(from 

previous) 

Baseline ................................... 0.301 .................... .................... .................... ............................ .................... ............................

LNB + FGR .............................. 0.15 297 551,982 1,859 ............................ 0.194 ............................

ROFA ....................................... 0.16 278 939,093 3,378 ¥20,374 0.256 0.062 

SNCR with LNB + FGR ........... 0.11 376 1,079,389 2,871 1,432 0.24 ¥0.016 

ROFA w/Rotamix ..................... 0.11 376 1,505,825 4,005 a NA 0.24 a NA 

SCR with LNB + FGR .............. 0.07 455 5,704,798 12,538 53,152 0.409 0.169 

aThe previous option, SNCR with LNB + FGR has the same emission rate, making an incremental comparison invalid. 

bPer ADEQ’s and AEPCO’s analyses, control options are ranked here by cost, not by emission rate 

cVisibility improvement at Chiricahua Wilderness Area, the Class I area exhibiting the highest impact 

d Cost-effectiveness values obtained from Table 10.3, Appendix D (TSD) of Arizona RH SIP. See Docket Item B–01. 

In its cost calculations for Apache 

Unit 1, AEPCO used a capital recovery 

factor based on a 7.10 percent interest 

rate, and a plant remaining useful life of 

eight years.29 The plant’s remaining 

useful life was based upon Apache Unit 

1 operating until 2021, and an assumed 

BART implementation date of 2013.30

AEPCO eliminated many control 

options, including SCR, based on high 

cost-effectiveness ($/ton), and primarily 

examined the LNB w/FGR and ROFA 

control options. AEPCO noted that LNB 

with FGR resulted in larger incremental 

visibility improvement than ROFA, and 

proposed LNB with FGR, burning either 

natural gas or fuel oil, as BART for NOX

at Apache Unit 1. 

In order to evaluate AEPCO’s BART 

analysis, ADEQ requested supporting 

information explaining assumptions 

used in the economic analysis, baseline 

emissions, and control technology 

options. Based on this additional 

information, as well as on AEPCO’s 

original analysis, ADEQ accepted the 

company’s proposed BART 

recommendation of LNB with FGR for 

Unit 1, but added a fuel restriction to 

allow only the use of natural gas. This 

determination corresponds to a BART 

emission limit for NOX at Apache Unit 

1 of 0.056 lb/MMBtu.31

EPA’s Evaluation: We disagree with 

multiple aspects of the analysis for 

Apache Unit 1. We consider the use of 

eight years for the plant’s remaining 

useful life in the control cost 

calculations as unjustified in the 

absence of documentation that the unit 

will shut down in 2021. We also note 

that control cost calculations include 

costs that are disallowed by EPA’s 

Control Cost Manual, such as owner’s 

costs and AFUDC. Both of these 

elements have the effect of inflating cost 

calculations and thus the costeffectiveness of the various control 

options considered. In addition, we do 

not consider using identical baseline 

emissions for No. 2 fuel oil and natural 

gas appropriate, although this likely did 

not affect either AEPCO’s or ADEQ’s 

BART determination, which was 

informed primarily by emission 

estimates based on No. 6 fuel oil, the 

highest emitting fuel. 

By including a natural gas-only fuel 

restriction, ADEQ’s BART 

determination of LNB with FGR results 

in a NOX emissions limit of 0.056 lb/ 

MMBtu, which is more stringent than 

any of the control options that AEPCO 

and ADEQ considered in conjunction 

with No. 6 or No. 2 fuel oil. Neither 

AEPCO’s nor ADEQ’s analysis, however, 

included visibility modeling for control 

options on a natural gas-only basis. The 

absence of such information does not 

allow us to fully evaluate if options 

more stringent than LNB with FGR are 

appropriate on a natural gas-only basis. 

Nevertheless, we are proposing to 

approve ADEQ’s NOX BART 

determination of LNB with FGR (natural 

gas usage only) with an emission limit 

of 0.056 lb/MMBtu for Apache Unit 1. 

b. BART for PM10

ADEQ’s Analysis: Apache Unit 1 

currently operates with no PM10

controls. In its BART analysis submitted 

to ADEQ, AEPCO developed baseline 

emissions for multiple fuel use 

scenarios including natural gas, and No. 

2 and No. 6 fuel oil usage. Baseline 

PM10 emissions for all fuels were 

calculated based on AP–42 emission 

factors.32 A summary of these emissions 

is in Table 4. 

AEPCO examined multiple control 

options for PM10 at Apache Unit 1, 

including add-on controls and fuel 

switching. A summary of cost of 

compliance and degree of visibility 

improvement for these options is 

summarized in Table 6. These cost and 

visibility improvement values are based 

on baseline and control case emissions 

corresponding to No. 6 fuel oil usage, 

which of the three fuels considered 

generates the greatest PM10 emissions. 

In its BART analysis, AEPCO cited high 

costs of compliance and minimal 

visibility improvements for the PM10

control options, and proposed no PM10

controls as BART for PM10, using either 

natural gas or No. 2 fuel oil. Based on 

the data and analysis provided by 

AEPCO, ADEQ determined that BART 

for PM10 at Apache Unit 1 is no 

additional controls, but also determined 

that a fuel restriction to allow only the 

use of natural gas was appropriate. This 

corresponds to a PM10 BART emission 


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33See Docket Item B–01. Emission rate as 

specified in Table 10.5, Appendix D (Technical 

Support Document) of Arizona Regional Haze SIP. 

34See Docket Item B–02. Page 2–2 of AEPCO 

Apache 1 BART Analysis. 

35See Docket Item B–01. Emission rate as 

specified in Table 10.7, Appendix D (Technical 

Support Document) of Arizona Regional Haze SIP. 

limit for Apache Unit 1 of 0.0075 lb/ 

MMBtu.33

TABLE 6—APACHE UNIT 1: ARIZONA’S COST AND VISIBILITY ANALYSIS FOR PM10

Control option 

Emission 

rate 

(lb/MMBtu) 

Emissions 

removed 

(tons/yr) 

Annualized 

cost 

($/year) 

Cost-effectiveness a

($/ton) 

Visibility Improvement b

(dv) 

Average 

Incremental 

(from 

previous) 

Total 

(from base 

case) 

Incremental 

(from 

previous) 

Baseline ................................................... 0.0737 .................... .................... .................... .................... .................... ....................

Fabric Filter .............................................. 0.015 116 3,615,938 31,172 .................... 0.010 ....................

Fuel switch to PNG .................................. 0.0075 .................... 0 .................... .................... .................... ....................

a Cost-effectiveness values as reported in Table 10.6, Appendix D (TSD) of Arizona RH SIP. See Docket Item B–01. 

bAs summarized in Table 5–12, AEPCO Apache 1 BART Analysis. See Docket Item B–02. Visibility improvement at Chiricahua Wilderness 

Area, the Class I area exhibiting the highest impact. 

EPA’s Evaluation: ADEQ’s PM10

analysis includes many of the same 

issues we noted in its NOX analysis, 

including the use of an eight-year plant 

remaining useful life, and inclusion of 

costs that are disallowed by EPA’s 

Control Cost Manual. Although we do 

not agree with elements of ADEQ’s PM10

BART analysis for Apache Unit 1, we 

find that its conclusion is reasonable, 

given the small visibility improvement 

projected to result from PM10 reductions 

at this Unit. Thus, we are proposing to 

approve ADEQ’s PM10 BART 

determination for Apache Unit 1. 

c. BART for SO2

ADEQ’s Analysis: Apache Unit 1 

currently operates with no SO2 controls. 

In its BART analysis submitted to 

ADEQ, AEPCO developed baseline 

emissions for multiple fuel use 

scenarios including natural gas, and No. 

2 and No. 6 fuel oil. Baseline natural gas 

emissions were based upon the highest 

75 percent load 24-hour SO2 emission 

levels reported in EPA’s Acid Rain 

Database for 2006. Since the only fuel 

burned in 2006 was natural gas, baseline 

emissions for No. 2 or No. 6 fuel oil 

usage could not be developed based on 

data from 2006. Baseline emissions for 

No. 2 and No. 6 fuel oil usage were 

estimated using AP–42 emission 

factors.34 A summary of these emissions 

is summarized in Table 4. 

AEPCO also examined multiple 

control options for SO2 on Apache 1, 

including add-on controls and fuelswitching. A summary of cost of 

compliance and degree of visibility 

improvement for these options is 

summarized in Table 7. These cost and 

visibility improvement values are from 

baseline and control case emissions 

corresponding to No. 6 fuel oil usage, 

which is the fuel type that generates the 

greatest SO2 emissions. In its BART 

analysis, AEPCO cited high costs of 

compliance and minimal visibility 

improvements for the SO2 control 

options, and proposed no additional 

SO2 controls, using either natural gas or 

No. 2 fuel oil, as BART for SO2. ADEQ 

determined that BART for SO2 is no 

additional controls, but added a fuel 

restriction to allow only the use of 

natural gas. This corresponds to an SO2

BART emission limit for Apache Unit 1 

of 0.00064 lb/MMBtu.35

TABLE 7—APACHE UNIT 1: ARIZONA’S COST AND VISIBILITY ANALYSIS FOR SO2

Control option 

Emission 

rate 

(lb/MMBtu) 

Emissions 

removed 

(tons/yr) 

Annualized 

cost 

($/year) 

Cost-effectiveness a

($/ton) 

Visibility Improvement b

(dv) 

Average 

Incremental 

(from 

previous) 

Total 

(from base 

case) 

Incremental 

(from 

previous) 

Baseline ............................................... 0.906 .................... .................... .................... .................... .................... ........................

Fuel switch to low-sulfur fuel oil .......... 0.051 .................... .................... .................... .................... .................... ........................

Spray dryer absorber (dry FGD) 1 ........ 0.10 1,587 3,881,706 2,446 .................... 0.765 ........................

Fuel switch to PNG .............................. 0.00064 .................... 0 .................... .................... .................... ........................

a Cost-effectiveness values as reported in Table 10.8, Appendix D (TSD) of Arizona RH SIP. See Docket Item B–01. 

bAs summarized in Table 5–12, AEPCO Apache 1 BART Analysis. See Docket Item B–02. Visibility improvement at Chiricahua Wilderness 

Area, the Class I area exhibiting the highest impact. 

EPA’s Evaluation: The SO2 analysis 

includes many of the same issues we 

noted in the NOX analysis, including the 

use of an eight-year plant remaining 

useful life, and inclusion of costs that 

are disallowed by EPA’s Control Cost 

Manual. ADEQ’s BART determination, 

requiring the use of only natural gas, 

results in an SO2 emission limit of 

0.00064 lb/MMBtu. This emission rate 

is more stringent than any of the control 

options that ADEQ considered in 

conjunction with No. 6 fuel oil. We are 

proposing to approve ADEQ’s BART 

determination for SO2 as an emission 

limit of 0.00064 lb/MMBtu at Apache 

Unit 1. 

2. Apache Units 2 and 3 

Apache Units 2 and 3 are both drybottom, Riley Stoker turbo-fired boilers, 

each with a gross unit output of 204 

MW. Both units are BART-eligible and 

are coal-fired boilers operating on subbituminous coal. Although there are 

physical differences between the two 

units, ADEQ found that the overall 


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36See Docket Item C–16, Letter from Michelle 

Freeark (AEPCO) to Deborah Jordan (EPA), 

AEPCO’s Comments on BART for Apache 

Generating Station, June 29, 2012. 

37See Docket Item B–03 and B–04, AEPCO 

Apache BART Analyses, page 2–2. 

38See Docket Item B–03 and B–04, AEPCO 

Apache BART Analyses. This information is also 

summarized in Docket Item B–01, Arizona Regional 

Haze SIP, Appendix D, Tables 10.10 through 10.13. 

39As listed in Table 3–2, Docket Items B–03 and 

B–04, AEPCO Apache BART Analyses. 

40As listed in Table 2–1, Docket Items B–03 and 

B–04. Annual capacity factors used for each unit are 

92% (Apache 2), and 87% (Apache 3). 

41Arizona SIP submittal, ‘‘Appendix D: Arizona 

BART—Supplemental Information’’, p. 65. 

differences are minimal and therefore 

considered both units together in its 

BART analysis. As with Apache Unit 1, 

ADEQ’s analysis relied largely on 

information provided by AEPCO and its 

contractor. This information is 

summarized below, along with ADEQ’s 

determinations for each pollutant and 

EPA’s evaluation. 

While the following sections describe 

both ADEQ’s and EPA’s evaluations 

based on the information in the record, 

we note that we received additional 

information from AEPCO on June 29, 

2012, related to the potential adverse 

impacts of the affordability of NOX

controls. AEPCO states that affordability 

is affected by its small size, the low 

income profiles of AEPCO’s service 

area, and AEPCO’s ability to access 

financing. While this information came 

in too late to be evaluated as part of this 

proposed rulemaking, EPA has put the 

information in the docket and will 

evaluate it during the public comment 

period.36

a. BART for NOX

ADEQ’s Analysis: AEPCO developed 

baseline NOX emissions by examining 

the average NOX emissions from 2002 to 

2007, a time period in which both units 

were equipped with OFA as NOX

emission controls.37 AEPCO examined 

several NOX control technologies, 

including combustion controls and addon post-combustion controls. A 

summary of Arizona’s costs of 

compliance and visibility impacts 

associated with these options is 

presented in Table 8. ADEQ relied on 

this information from the facility to 

develop its RH SIP.38 Estimates of 

control technology emission rates were 

developed based on a combination of 

vendor quotes, contractor information, 

and internal AEPCO information 

regarding environmental upgrades.39

Annual emission reductions were 

calculated based on the emission rate 

estimates combined with annual 

capacity factors as specified by 

AEPCO.40 Control costs were developed 

based on a combination of vendor 

quotes and contractor information. 

These cost calculations provided line 

item summaries of capital costs and 

annual operating costs, but did not 

include further supporting information 

such as detailed equipment lists, vendor 

quotes, or the design basis for line item 

costs. 

TABLE 8—APACHE UNITS 2 AND 3: ARIZONA’S COST AND VISIBILITY SUMMARY

Control option 

Emission 

rate 

(lb/MMBtu) 

Emissions 

removed 

(tons/yr) 

Annualized 

cost 

($/year) 

Cost-effectiveness 

($/ton) 

Visibility improvement a

(deciviews) Cost per total 

deciview improvement 

Average ($/dv) 

Incremental 

(from 

previous) 

Total (from 

baseline) 

Incremental 

(from 

previous) 

Apache Unit 2 

OFA (baseline) .......................................................... 0.47 .................. ...................... .................. .................. .................. .................. ......................

LNB + OFA ............................................................... 0.31 1,305 $533,000 $408 .................. 0.267 .................. $1,996,000 

ROFA ........................................................................ 0.26 1,710 1,664,000 973 305 0.359 0.092 4,636,000 

SNCR + LNB + OFA ................................................. 0.23 1,953 1,738,000 890 1,860 0.416 0.057 4,532,000 

ROFA w/Rotamix ...................................................... 0.18 2,358 2,225,000 944 866 0.491 0.075 4,177,000 

SCR + LNB + OFA ................................................... 0.07 3,250 6,102,000 1,878 4,346 0.676 0.185 9,028,000 

Apache Unit 3 

OFA (baseline) .......................................................... 0.43 .................. ...................... .................. .................. .................. .................. ......................

LNB + OFA ............................................................... 0.31 926 532,808 575 .................. 0.206 .................. 2,586,000 

ROFA ........................................................................ 0.26 1,312 1,643,241 1,252 322 0.298 0.092 5,484,000 

SNCR + LNB + OFA ................................................. 0.23 1,543 1,717,633 1,113 1,920 0.356 0.058 5,004,000 

ROFA w/Rotamix ...................................................... 0.18 1,929 2,181,833 1,131 873 0.436 0.080 4,825,000 

SCR + LNB + OFA ................................................... 0.07 2,778 6,062,301 2,182 4,571 0.633 0.197 9,577,000 

aAt the Class I area exhibiting the greatest baseline visibility impact, Chiricahua Wilderness Area. 

Regarding visibility impacts, ADEQ 

relied on visibility modeling submitted 

by AEPCO to evaluate the visibility 

improvement attributable to each of the 

NOX control technologies that it 

considered. This visibility modeling 

was performed using three years of 

meteorological data (2001 to 2003), and 

was generally performed in accordance 

with the WRAP modeling protocol. The 

average of the three 98th percentiles 

from the modeled years 2001 to 2003 

was used as the visibility metric for 

each emission scenario and Class I area. 

For assessing the degree of visibility 

improvement, ADEQ considered only 

the visibility benefits at the area with 

the highest base case (pre-control) 

impact: Chiricahua National Monument 

and Chiricahua Wilderness Area (two 

nearby Class I areas served by one air 

monitor). For each control, ADEQ listed 

visibility improvement in deciviews, 

and cost in millions of dollars per 

deciview improvement.41 Results are 

comparable for both units, with Unit 2 

showing somewhat higher visibility 

benefits and somewhat lower cost per 

improvement than Unit 3. Unit 2 

visibility improvements range from 0.27 

dv for LNB to 0.68 dv for SCR, while the 

costs per deciview range from $2 

million for LNB to over $9 million for 

SCR. ADEQ concluded that LNBs with 

the existing OFA systems represent 

BART for Units 2 and 3, though no 

explicit reasoning is provided for the 

selection. 

ADEQ determined that LNB plus OFA 

constitute BART for NOX at Apache 

Units 2 and 3. In making this 

determination, ADEQ did not provide 

adequate information regarding its 

rationale or weighing of the five factors. 

ADEQ stated only that ‘‘(A)fter 

reviewing the company’s BART 

analysis, and based upon the 

information above, ADEQ has 


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42 Docket Item B–01, Arizona Regional Haze SIP, 

Appendix D, Page 65. 

43See BART Guidelines, § IV.E.2. 

44We do note, however, that AEPCO does provide 

some additional analysis on this position in the 

Apache BART analyses it submitted to ADEQ. 

Aside from stating that it reviewed AEPCO’s 

analysis, ADEQ did not specifically reference or 

include any aspects of AEPCO’s analysis in the RH 

SIP. As a result, we are not assuming that ADEQ 

necessarily agrees with AEPCO’s rationale, and 

have therefore not provided an evaluation of it. 

45See Appendix D, pages 65–69 for ADEQ’s 

BART Analysis for PM10 at Apache Units 2 and 3. 

See AEPCO Apache Unit 2 BART Analysis. 

determined that, for Units 2 and 3 BART 

for NOX is new LNBs and the existing 

OFA system with a NOX emissions limit 

of 0.31 lb/MMBtu * * *.’’ 42

EPA’s Evaluation: We disagree with 

several aspects of the NOX BART 

analysis for Apache Units 2 and 3. The 

control cost calculations included line 

item costs not allowed by the EPA 

Control Cost Manual, such as owner’s 

costs, surcharge, and AFUDC. Inclusion 

of these line items has the effect of 

inflating the total cost of compliance 

and the cost per ton of pollutant 

reduced. 

Regarding visibility improvement as 

shown in Table 8, ADEQ chose LNB as 

BART, which provides the lowest 

visibility benefit of any of the controls 

modeled. By contrast, SCR would 

provide an improvement of more than 

0.5 dv at a single Class I Area, and a 

substantial incremental benefit relative 

to the next more stringent control, 

ROFA-Rotamix. Multiple Class I areas 

have comparable benefits. The visibility 

benefits are larger than those listed, if 

both Units 2 and 3 are considered 

together. (See Table 17 below for EPA’s 

visibility results.) The SCR cost per 

deciview of improvement is lower than 

those for Cholla and Coronado, as 

indicated below in their respective 

sections. 

ADEQ provides little explicit 

reasoning about the visibility basis for 

the BART selection. For example, there 

is no weighing of visibility benefits and 

visibility cost-effectiveness for the 

various candidate controls and the 

various Class I areas. The modeling 

results show that controls more 

stringent than LNB appear to be needed 

to give substantial visibility benefits. 

Visibility impacts at eight nearby Class 

I areas were not considered, and the 

visibility benefits of simultaneous 

controls on both units were not 

considered. For these reasons, EPA 

believes that ADEQ gave insufficient 

consideration to the visibility benefits of 

the various NOX control options 

available at Apache Units 2 and 3. 

In summary, we find that ADEQ has 

not provided an adequate justification 

for adopting LNB with OFA as the 

‘‘best’’ level of control.43 Although 

ADEQ has developed information 

regarding each of the five factors, there 

are problems in both its cost and 

visibility analyses as described above. 

Moreover, ADEQ’s BART analysis does 

not explain how it weighed these 

factors. For example, ADEQ did not 

indicate whether or not it considered 

any cost thresholds to be reasonable or 

expensive in analyzing the costs of 

compliance for the various control 

options. We note that ADEQ has made 

similar NOX BART determinations of 

LNB with OFA at other facilities, such 

as Cholla Power Plant. Although 

ADEQ’s BART determinations for these 

other facilities implied that cost of 

compliance was an important 

consideration, it does not provide a 

rationale for this selection of NOX

BART.44 Thus, we are proposing to 

disapprove ADEQ’s BART 

determination for NOX at Apache Units 

2 and 3, since it does not comply with 

40 CFR 51.308(e)(1)(ii)(A). 

b. BART for PM10

ADEQ’s Analysis: The existing PM10

controls on Apache Units 2 and 3 are 

hot-side Electrostatic Precipitators 

(ESPs).45 AEPCO and ADEQ considered 

three potential retrofit control options 

for PM10: 

• Performance upgrades to existing 

hot-side ESP, 

• Replacement of current ESP with a 

fabric filter, and 

• Installation of a polishing fabric 

filter after ESP. 

ADEQ found that all of these options are 

technically feasible and estimated their 

associated emission rates as shown in 

Table 9. 

TABLE 9—APACHE UNITS 2 AND 3: 

ARIZONA’S CONTROLS AND EMISSION

RATES FOR PM10

Control technology Expected PM10

emission rate 

ESP Upgrades ................... 0.03 lb/MMBtu. 

Full Size Fabric Filter ........ 0.015 lb/MMBtu. 

Polishing Fabric Filter ........ 0.015 lb/MMBtu. 

ADEQ found that a fabric filter, whether 

in addition to or as replacement for the 

ESP, would require additional energy, 

but did not identify any non-air 

environmental impacts from any of the 

three options. The cost of compliance 

and degree of visibility improvement for 

each of these options, as analyzed by 

ADEQ, are summarized in Tables 10 and 

11. 

TABLE 10—APACHE UNIT 2: ARIZONA’S CONTROL COST OF VISIBILITY REDUCTION FOR PM10

Control Deciview 

reduction 

Total 

annualized 

cost 

(million $) 

Cost per 

deciview 

reduced 

(million $/dv) 

Average cost 

($/ton) 

ESP Upgrades ................................................................................................. Unknown Unknown Unknown Unknown 

Polishing Fabric Filter ...................................................................................... 0.085 $2.217 $26.09 $9,121 

Full Size Fabric Filter ....................................................................................... 0.085 2.888 33.98 11,880 

TABLE 11—APACHE UNIT 3: ARIZONA’S CONTROL COST OF VISIBILITY REDUCTION FOR PM10

Control Deciview 

reduction 

Total 

annualized 

cost 

(million $) 

Cost per 

deciview 

reduced 

(million $/dv) 

Average cost 

($/ton) 

ESP Upgrades ................................................................................................. Unknown Unknown Unknown Unknown 

Polishing Fabric Filter ...................................................................................... 0.094 $2.192 $23.32 $9,471 

Full Size Fabric Filter ....................................................................................... 0.094 $2.869 $30.52 12,390 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
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46See AEPCO BART Analysis Technical 

Memorandum dated July 8, 2009, page 12. 

47See 40 CFR part 51 Appendix M. 

48EPA is proposing SCR as BART for all of the 

coal-fired units. See Section VII. 

49See 40 CFR part 60 appendix A. 

50See Arizona Regional Haze SIP, Appendix D, 

pages 69–71 for ADEQ’s BART Analysis for SO2 at 

Apache Units 2 and 3. 

51See AEPCO Apache Unit 2 BART Analysis. 

52See BART Guidelines § IV.E.4. 

53See, e.g. Apache Unit 2 BART Analysis, Table 

3–1. 

54A copy of the coal contract, including 

obligation amounts and coal quality, can be found 

in Docket Item B–09, ‘‘Additional APS Cholla 

BART response’’, Appendix B. 

Based on its analysis of the five BART 

factors, as summarized above, ADEQ 

found BART for PM10 is upgrades to the 

existing ESP and a PM10 emissions limit 

of 0.03 lb/MMBtu for Units 2 and 3. In 

particular, ADEQ referred to installation 

of a flue gas conditioning system, 

improvements to the scrubber bypass 

damper system, and implementation of 

programming optimization measures for 

ESP automatic voltage controls as 

potential upgrades. ADEQ also noted 

that ‘‘PM10 emissions will be measured 

by conducting EPA Method 201/202 

tests.’’ 

EPA’s Evaluation: As noted above, 

AEPCO’s and ADEQ’s control cost 

calculations include costs that are 

disallowed by EPA’s Control Cost 

Manual, such as owner’s costs and 

AFUDC.46 In addition, AEPCO’s and 

ADEQ’s analyses do not demonstrate 

that all potential upgrades to the 

existing ESP were fully evaluated. 

Nonetheless, based on the small 

visibility improvement associated with 

PM10 reductions from these units (e.g., 

less than 0.1 dv improvement from the 

most stringent technology), we conclude 

that additional analyses of control 

options would not result in a different 

BART determination. As a result, we 

propose to approve ADEQ’s PM10 BART 

determination at Apache Units 2 and 3. 

Finally, we are seeking comment on 

whether test methods other than EPA 

Method 201 and 202 47 (chosen by 

ADEQ) should be allowed or required 

for establishing compliance with the 

PM10 limits that we are approving. In 

particular, as explained below, use of 

SCR48 at these units is expected to 

result in increased condensable 

particulate matter in the form of sulfuric 

acid mist (H2SO4). In effect, the 

emission limit would be more stringent 

than intended by ADEQ and would 

likely not be achievable in practice. In 

order to avoid this result, while still 

assuring proper operation of the 

particulate control devices, we are 

requesting on comment on whether to 

allow compliance with the PM10 limit to 

be demonstrated using test methods that 

do not capture condensable particulate 

matter, namely EPA Methods 1 through 

4 and Method 5 or Method 5e.49 Method 

201 is very rarely used for testing. The 

typical method used for filterable PM10

is Method 201A, ‘‘constant sampling 

rate procedure,’’ which is similar to 

Method 201, but is much more practical 

to perform on a stack. 

c. BART for SO2

ADEQ’s Analysis: Apache Units 2 and 

3 currently have wet limestone 

scrubbers installed for SO2 removal.50

Under the BART Guidelines, a state is 

not required to evaluate the replacement 

of the current SO2 controls if their 

removal efficiency is over 50 percent, 

but should consider cost-effective 

scrubber upgrades designed to improve 

the system’s overall SO2 removal 

efficiency. Relying upon the BART 

analysis submitted by AEPCO,51 ADEQ 

found that the following potential 

upgrades to the scrubbers are 

technically feasible: 

• Elimination of bypass reheat, 

• Installation of liquid distribution 

rings, 

• Installation of perforated trays, 

• Use of organic acid additives, 

• Improved or upgraded scrubber 

auxiliary system equipment, and 

• Redesigned spray header or nozzle. 

ADEQ found that any upgrades likely 

would not increase power consumption, 

but would increase scrubber waste 

disposal and makeup water 

requirements, and would reduce the 

stack gas temperature. These three 

factors are the normal outcome of 

treating more of the exhaust gas and 

removing more of the SO2 (increased 

scrubber waste disposal) and should not 

be given much weight in selecting a 

BART emission limit. ADEQ also noted 

that AEPCO had already made the 

following upgrades to the scrubbers: 

Elimination of flue gas bypass; splitting 

the limestone feed to the absorber feed 

tank and tower sump; upgrade of the 

mist eliminator system; installation of 

suction screens at pump intakes; 

automation of pump drain valves, and 

replacement of scrubber packing with 

perforated stainless steel trays. In 

addition, AEPCO tried using dibasic 

acid additive, but found that it did not 

result in significantly higher SO2

removal. ADEQ did not evaluate the 

cost or visibility impacts of any 

additional upgrades to the scrubbers, 

but determined that BART for SO2

emissions was no new controls and an 

emission limit of 0.15 lb/MMBtu on a 

30-day rolling average basis. 

EPA’s Evaluation: We are proposing 

to approve ADEQ’s SO2 BART 

determination for Apache Units 2 and 3. 

Although ADEQ has not demonstrated 

that it fully considered all cost effective 

scrubber upgrades, as recommended by 

the BART Guidelines, ADEQ conducted 

a five-factor BART analysis and its final 

SO2 BART determination for Apache 

Units 2 and 3 is consistent with the 

presumptive BART limit of 0.15 lb/ 

MMBtu for utility boilers.52 We have no 

evidence that additional analysis would 

have resulted in a lower emission limit. 

Therefore, we are proposing to approve 

the SO2 emission limit of 0.15 lb/ 

MMBtu (30-day rolling average) for 

Apache Units 2 and 3. 

However, we note that Apache can 

receive coal from a number of different 

mines that can have differing sulfur 

content and potential for SO2

emissions.53 Therefore, we are seeking 

comment on whether additional costeffective scrubber upgrades are available 

that would warrant a lower emission 

limit. We are also requesting comment 

on whether requiring 90 percent control 

efficiency in addition to the lb/MMBtu 

limit would better assure proper 

operation of the upgraded scrubbers 

when burning some types of low-sulfur 

western coal. If we receive information 

establishing that a lower limit is 

achievable or that a control efficiency 

requirement is needed, then we may 

disapprove the SO2 emissions limit set 

by ADEQ and promulgate a revised limit 

for one or both of these units. 

3. Cholla Units 2, 3 and 4 

Cholla Power Plant consists of four 

primarily coal-fired electricity 

generating units with a total plant-wide 

generating capacity of 1,150 megawatts. 

Unit 1 is a 125 MW tangentially-fired, 

dry-bottom boiler that is not BARTeligible. Units 2, 3 and 4 have capacities 

of 300 MW, 300 MW and 425 MW, 

respectively, and are tangentially-fired, 

dry-bottom boilers that are each BARTeligible. Based on information provided 

by APS, the Cholla units operate on a 

blend of bituminous and subbituminous rank coals from the Lee 

Ranch and El Segundo mines.54

a. BART for NOX

ADEQ’s Analysis: APS submitted a 

BART analysis to ADEQ in January 

2008. At the time of submittal, Cholla 

Units 2, 3 and 4 were equipped with 

close-coupled overfire air (COFA) as 

NOX controls. APS developed baseline 

NOX emissions by examining the 

highest 24-hour average emissions from 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
42848 Federal Register / Vol. 77, No. 140 / Friday, July 20, 2012 / Proposed Rules 

55See Docket Item B–06 through –08, APS Cholla 

BART Analyses, page 2–2. 

56See Docket Item B–06 through –08, APS Cholla 

BART Analyses. This information is also 

summarized in Docket Item B–01, Arizona Regional 

Haze SIP, Appendix D, Tables 11.3 through 11.5. 

57As described in Table 3–2, Docket Items B–06 

through –08, APS Cholla BART Analyses. 

58As listed in Table 2–1, Docket Items B–06 

through –08. Annual capacity factors used for each 

unit are 91 percent (Cholla 2), 86 percent (Cholla 

3), and 93 percent (Cholla 4). 

2001 to 2003.55 APS examined several 

NOX control technologies, including 

combustion controls and add-on post 

combustion controls. A summary of the 

costs of compliance and visibility 

impacts associated with these options is 

presented in Table 12. 

TABLE 12—CHOLLA UNITS 2, 3, AND 4: ARIZONA’S COST AND VISIBILITY SUMMARY FOR NOX

Control option 

Emission 

rate 

(lb/MMBtu) 

Emissions 

removed 

(tons/yr) 

Annualized 

cost 

($/year) 

Cost-effectiveness 

($/ton) 

Visibility improvement a

(deciviews) Cost per total 

deciview 

improvement 

Average ($/dv) 

Incremental 

(from 

previous) 

Total 

(from 

baseline) 

Incremental 

(from 

previous) 

Cholla 2 

COFA (baseline) ....................................................... 0.50 .................. ...................... .................. .................. .................. .................. ......................

LNB + SOFA ............................................................. 0.22 3,314 $635,000 $192 .................. 0.187 .................. $3,400,000 

SNCR + LNB + SOFA .............................................. 0.17 3,900 2,175,000 558 2,628 0.218 0.031 9,980,000 

ROFA ........................................................................ 0.16 4,017 2,297,000 572 1,043 0.232 0.014 9,900,000 

ROFA w/Rotamix ...................................................... 0.12 4,485 3,384,000 755 2,323 0.261 0.029 12,970,000 

SCR + LNB + SOFA ................................................. 0.07 5,071 9,625,000 1,898 10,650 0.287 0.026 33,540,000 

Cholla 3 

COFA (baseline) ....................................................... 0.41 .................. ...................... .................. .................. .................. .................. ......................

LNB + SOFA ............................................................. 0.22 2,096 635,000 303 .................. 0.13 .................. 5,040,000 

SNCR + LNB + SOFA .............................................. 0.17 2,648 2,157,000 815 2,757 0.16 0.038 13,150,000 

ROFA ........................................................................ 0.16 2,758 2,243,000 813 782 0.17 0.005 13,270,000 

ROFA w/Rotamix ...................................................... 0.12 3,200 3,308,000 1,034 2,410 0.20 0.029 16,710,000 

SCR + LNB + SOFA ................................................. 0.07 3,751 9,569,000 2,551 11,363 0.23 0.032 41,610,000 

Cholla 4 

COFA (baseline) ....................................................... 0.42 .................. ...................... .................. .................. .................. .................. ......................

LNB + SOFA ............................................................. 0.22 3,390 820,000 242 .................. 0.21 .................. 3,960,000 

SNCR + LNB + SOFA .............................................. 0.17 4,259 2,852,000 670 2,338 0.27 0.058 10,760,000 

ROFA ........................................................................ 0.16 4,433 3,179,000 717 1,879 0.28 0.016 11,310,000 

ROFA w/Rotamix ...................................................... 0.12 5,129 4,537,000 885 1,951 0.34 0.055 13,500,000 

SCR + LNB + SOFA ................................................. 0.07 5,998 13,230,000 2,206 10,003 0.41 0.072 32,430,000 

aAt the Class I area exhibiting the greatest baseline visibility impact, Petrified Forest National Park. 

This information is contained in the 

Cholla BART analyses for each unit, and 

was relied upon by ADEQ in developing 

its RH SIP.56 Estimates of control 

technology emission rates were 

developed based on a combination of 

vendor quotes, contractor information, 

and internal APS information regarding 

environmental upgrades.57 Annual 

emission reductions were calculated 

based upon the emission rate estimates 

combined with annual capacity factors 

as reported in CAMD data from 2001 to 

2006.58 Control costs were also 

developed based on a combination of 

vendor quotes and contractor 

information. These cost calculations 

provided line item summaries of capital 

costs and annual operating costs, but 

did not provide further supporting 

information such as detailed equipment 

lists, vendor quotes, or the design basis 

for line item costs. 

As part of its BART analysis, APS 

performed visibility modeling in order 

to evaluate the visibility improvement 

attributable to each of the NOX control 

technologies that it considered. This 

visibility modeling was performed using 

three years of meteorological data (2001 

to 2003), and was generally performed 

in accordance with the WRAP protocol, 

with a few exceptions. For example, 

rather than using a constant monthly 

ammonia background concentration of 

1.0 ppb as specified in the WRAP 

protocol, APS used a variable monthly 

background ammonia concentration that 

varied from 0.2 ppb to 1.0 ppb. 

For assessing the degree of visibility 

improvement, ADEQ considered only 

the visibility benefits at the area with 

the highest base case (pre-control) 

impact, the Petrified Forest National 

Park. For each control, ADEQ listed 

visibility improvement in deciviews, 

and visibility cost-effectiveness, 

(Arizona SIP submittal, ‘‘Appendix D: 

Arizona BART—Supplemental 

Information’’, p.77) as in the comparable 

section for Apache. For Unit 2, 

improvements range from 0.19 dv for 

LNB with SOFA to 0.29 dv for SCR. 

Costs per deciview range from $3.4 

million for LNB to $33.5 million for 

SCR. Benefits for Unit 3 are about 20 

percent lower (0.13 to 0.23 deciview), 

and for Unit 4 are about 20 percent 

higher (0.21 to 0.41 deciview), with 

percent differences increasing with 

more stringent control. For Unit 3, costs 

per deciview range from $5 million for 

LNB with SOFA to $41.6 million for 

SCR (about 30 percent higher than for 

Unit 2). For Unit 4, costs range from $4 

million for LNB with SOFA to $32.4 

million for SCR (about 20 percent higher 

except that SCR has a slightly lower cost 

per deciview). 

ADEQ concluded (ibid., p. 79) that 

LNBs with new SOFA systems represent 

BART for all three units, noting that for 

all scenarios the visibility benefits were 

less than 0.5 dv. ADEQ also stated that 

SCR, the most expensive option, 

provides only about 0.1 dv benefit more 

than LNB with SOFA, the least 

expensive option. This statement 

appears to apply only to Units 2 and 3; 

the comparable benefit for Unit 4 is 0.2 

dv. 

In evaluating APS’ BART analysis, 

ADEQ requested supporting information 

explaining certain assumptions used in 

the economic analysis, baseline 

emissions, and control technology 

options. Based on this additional 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 77, No. 140 / Friday, July 20, 2012 / Proposed Rules 42849 

59 Docket Item B–01, Arizona Regional Haze SIP, 

Appendix D, Page 79. 

60 Id. 

61See Arizona Regional Haze SIP, Appendix D, 

pages 79–81 for ADEQ’s BART Analysis for PM10

at Cholla Units 2, 3, and 4. 

62See Arizona Regional Haze SIP, Appendix D, 

pp. 81–83, for ADEQ’s BART Analysis for SO2 at 

Cholla Units 2, 3, and 4. 

63See Docket Item G–01, Consent Decree between 

United States and Salt River Project Agricultural 

Improvement and Power District. 

information as well as APS’ original 

BART analysis, ADEQ determined that 

LNB with SOFA is BART for NOX at 

Cholla Units 2, 3, and 4. In making this 

determination, ADEQ relied almost 

exclusively on the degree of visibility 

improvement. ADEQ cited small 

visibility improvement on a per-unit 

basis, stating that ‘‘the change in 

deciviews between the least expensive 

and most expensive NOX control 

technologies [..] is only 0.104 

deciviews.’’ 59 ADEQ’s determination 

suggests that total capital costs may 

have been a consideration, although it is 

not clear to what extent this may have 

informed ADEQ’s decision making, with 

the RH SIP simply stating, ‘‘[t]he 

corresponding capital costs are $5.4 

million for LNB/SOFA and $82.8 

million for SCR with LNB/SOFA.’’ 60

EPA’s Evaluation: We disagree with 

several aspects of the analyses 

performed for Cholla Units 2, 3, and 4. 

Regarding the control cost calculations, 

we note that certain line item costs not 

allowed by the EPA Control Cost 

Manual were included, such as owner’s 

costs, surcharge, and AFUDC. Inclusion 

of these line items has the effect of 

inflating the total cost of compliance 

and the cost per ton of pollutant 

reduced. As a result, we are proposing 

to find that ADEQ did not follow the 

requirements of section 

51.308(e)(1)(ii)(A) by not properly 

considering the costs of compliance for 

each control option. 

Regarding ADEQ’s analysis of 

visibility impacts, the modeling 

procedures relied on by ADEQ for 

assessing the visibility impacts from 

Cholla were generally in accord with 

EPA guidance, but the use of the 

modeling results in evaluating the 

BART visibility factor was problematic. 

As was the case for Apache, ADEQ 

appears to have considered benefits 

from controls on only one emitting unit 

at a time. EPA believes that ADEQ’s use 

of this procedure substantially 

underestimates the degree of visibility 

improvement from controls. ADEQ also 

overlooked comparable benefits at seven 

Class I areas besides Petrified Forest, 

thereby understating the full visibility 

benefits of the candidate controls. Using 

the default 1 ppb ammonia background 

concentration would also have 

increased estimated impacts and control 

benefits. For these reasons, EPA 

proposes to find that the ADEQ 

selection of LNB for Cholla under the 

degree of visibility improvement BART 

factor is not adequately supported, and 

that more stringent control may be 

warranted. 

b. BART for PM10

ADEQ’s Analysis: As of May 2009, 

Cholla Units 3 and 4 were both 

equipped with fabric filters for PM10

control, while Cholla Unit 2 was 

equipped with a mechanical dust 

collector and a venturi scrubber.61 In its 

BART analysis, ADEQ noted that the 

facility had committed to install a fabric 

filter at Unit 2 by 2015. Because fabric 

filters are the most stringent control 

available for reducing PM10 emissions, 

ADEQ did not conduct a full BART 

analysis, but concluded that fabric 

filters and an emission limit of 0.015 lb/ 

MMBtu are BART for control of PM10 at 

Units 2, 3, and 4. ADEQ also noted that 

‘‘PM10 emissions will be measured by 

conducting EPA Method 201/202 tests.’’ 

EPA’s Evaluation: Given that ADEQ 

has chosen the most stringent control 

technology available and set an 

emissions limit consistent with other 

units employing this technology, we are 

proposing to approve this BART 

determination of an emission limit of 

0.015 lb/MMBtu for PM10 at Cholla 

Units 2, 3, and 4. 

c. BART for SO2

Cholla Units 2, 3, and 4 are all 

equipped with wet lime scrubbers for 

SO2 control.62 Specifically, Unit 2 is 

equipped with four venturi flooded disc 

scrubbers/absorber with lime reagent, 

capable of achieving 0.14 lb/MMBtu to 

0.25 lb/MMBtu of SO2. Units 3 and 4 

were retrofitted in 2009 and 2008, 

respectively, with scrubbers capable of 

achieving 0.15 lb/MMBtu of SO2.

ADEQ’s Analysis: Based on a limited 

five-factor analysis, ADEQ determined 

BART for SO2 at Cholla Unit 2 is 

upgrades to the existing scrubber that 

would achieve a limit of 0.15 lb/ 

MMBtu. Because the BART analysis 

submitted by APS was conducted prior 

to installation of the scrubbers on Units 

3 and 4, it included an analysis of other 

potential control technologies, namely, 

dry flue gas desulfurization and dry 

sodium sorbent injection. However, APS 

had already installed the wet lime 

scrubbers by the time ADEQ conducted 

its own BART analysis. Therefore, 

ADEQ did not consider SO2 controls 

other than wet lime scrubbers for Units 

3 and 4, but determined BART as use of 

these scrubbers with an associated 

emission limit of 0.15 lb/MMBtu of SO2.

EPA’s Evaluation: We are proposing 

to approve ADEQ’s BART determination 

for SO2 at Cholla Units 2, 3, and 4. 

Although ADEQ did not fully consider 

all cost-effective scrubber upgrades as 

recommended by the BART Guidelines, 

we have no basis for concluding that 

additional analysis would have resulted 

in a lower emission limit. Therefore, we 

are proposing to approve the SO2

emission limit of 0.15 lb/MMBtu (30- 

day rolling average) for Cholla Units 2, 

3, and 4. However, we are seeking 

comment on whether additional costeffective scrubber upgrades are available 

that would warrant a lower emission 

limit. If we receive comments 

establishing that a lower limit is 

achievable, then we may disapprove the 

SO2 emissions limit set by ADEQ and 

promulgate a revised limit for one or 

more of these units. 

4. Coronado Units 1 and 2 

Coronado Generating Station consists 

of two EGUs with a total plant-wide 

generating capacity of over 800 MW. 

Units 1 and 2 are both dry-bottom, 

turbo-fired boilers, each with a gross 

unit output of 411 MW. Both units are 

BART-eligible and are coal-fired boilers 

operating on primarily Powder River 

Basin sub-bituminous coal. 

SRP entered into a consent decree 

with EPA in 2008.63 This consent decree 

resolved alleged violations of the CAA 

which occurred at Units 1 and 2 of the 

Coronado Generating Station, arising 

from the construction of modifications 

without obtaining appropriate permits 

under the Prevention of Significant 

Deterioration provisions of the CAA, 

and without installing and applying best 

available control technology. The 

consent decree resolved the claims 

alleged by EPA in exchange for SRP’s 

payment of a civil penalty and SRP’s 

commitment to perform injunctive relief 

including: (1) Installation of pollution 

control technology to control emissions 

of NOX, SO2, and PM—including flue 

gas desulfurization devices to control 

SO2 on Units 1 and 2 at the Coronado 

Station and installation of SCR to 

control NOX on one of the units (Unit 

2); (2) meet specified emission rates or 

removal efficiencies for NOX, SO2, and 

PM; (3) comply with a plant-wide 

emissions cap for NOX; and (4) perform 

$ 4 million worth of mitigation projects. 

The consent decree is not a permit, and 

compliance with the consent decree 

does not guarantee compliance with all 

applicable federal, state, or local laws or 

regulations. The emission rates and 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
42850 Federal Register / Vol. 77, No. 140 / Friday, July 20, 2012 / Proposed Rules 

64See Docket Item B–10, SRP Coronado BART 

Analysis, page 3–1. 

65See Docket Item B–10, SRP Coronado BART 

Analysis, p. 4–5. 

66See Docket Item B–11, Additional SRP 

Coronado response. 

67Arizona RH SIP, Appendix D, p. 112. 

removal efficiencies set forth in the 

consent decree do not relieve SRP from 

any obligation to comply with other 

state and federal requirements under the 

CAA, including SRP’s obligation to 

satisfy any State modeling requirements 

set forth in the Arizona SIP. 

a. BART for NOX

ADEQ’s Analysis: ADEQ’s BART 

analysis relied in large part on an 

analysis submitted by SRP in February 

2008. In its analysis, SRP developed 

baseline NOX emissions by examining 

continuous emission monitoring system 

(CEMS) data from 2001 to 2003.64 SRP 

examined several NOX control 

technologies, including combustion 

controls and add-on post combustion 

controls. A summary of the costs of 

compliance and visibility impacts 

associated with these options is 

presented in Table 13. This information 

was contained in the SRP Coronado 

BART analysis, and was relied on by 

ADEQ in developing its RH SIP. 

Estimates of control technology 

emission rates were developed based on 

information provided by equipment 

vendors.65 SRP’s analysis did not 

provide an estimate of annual 

emissions. 

TABLE 13—CORONADO UNITS 1 AND 2: ARIZONA’S COST AND VISIBILITY SUMMARY FOR NOX

Control option 

Emission rate 

(lb/MMBtu) 

Total 

emissions 

removed a

(tons/yr) 

Total 

annualized 

cost 

($/year) 

Cost-effectiveness b

($/ton) 

Visibility 

improvement c

(deciviews) Cost per 

total 

deciview improvement d

($/dv) 

Improvement in 

visibility index e

(deciviews) 

Unit 1 Unit 2 Average 

Incremental 

(from 

previous) 

Total 

(from 

baseline) 

Incremental 

(from 

previous) 

Total 

(from 

base 

case) 

Incremental 

(from 

previous) 

OFA (baseline) .......... 0 .433 0 .466 ................ .................... ................ ................ ................ ................ .................... ................ ................

Full LNB + OFA ........ 0 .32 0 .32 5,838 $1,227,000 $210 ................ 0.12 ................ $10,225,000 0.11 ................

Full SNCR + LNB + 

OFA ....................... 0 .22 0 .22 10,195 4,654,000 456 787 0.16 0.04 29,087,500 0.19 0.080 

Partial SCR + LNB + 

OFAf ...................... 0 .32 0 .08 11,003 8,557,000 778 4,830 0.24 0.12 35,654,167 0.22 0.030 

Full SCR + LNB + 

SOFA ..................... 0 .08 0 .08 16,730 17,090,000 1,022 1,490 0.39 0.27 43,820,513 0.34 0.120 

aSRP did not provide estimates of annual emissions in its BART analysis. These values are summarized from the Arizona RH SIP. 

b Cost-effectiveness was not presented in the Arizona RH SIP. These values are calculated from the emission removal and annualized costs that were included in 

the RH SIP. cVisibility improvement at the Class I area exhibiting the greatest baseline visibility impact, Petrified Forest National Park, from the SRP Coronado BART Analysis. 

d Cost per total deciview improvement was not presented in the Arizona RH SIP. These values are calculated from the annualized costs that were included in the 

RH SIP, and the visibility improvement at Petrified Forest National Park, from the SRP Coronado BART Analysis. eVisibility index used in the Arizona RH SIP is the average of the impacts over the nine closest Class I areas. 

fThis control option examined LNB+OFA on Unit 1 and SCR on Unit 2. 

Control costs for the various options 

considered were developed by Sargent 

and Lundy, the engineering firm 

retained by SRP for emission control 

projects at Coronado. In its BART 

analysis and subsequent additional 

response to ADEQ, SRP provided 

summaries of total control costs, such as 

total annual operating and maintenance 

costs and total annualized capital cost, 

but did not provide cost information at 

a level of detail that included line item 

costs. 66

As part of its BART analysis, SRP 

performed visibility modeling in order 

to evaluate the visibility improvement 

attributable to each of the NOX control 

technologies that it considered. This 

visibility modeling was performed using 

three years of meteorological data (2001 

to 2003), and relied partially on the 

WRAP protocol with certain revisions 

based on EPA and Federal Land 

Manager guidance that became available 

in the intervening period. For example, 

the WRAP protocol used CALPUFF 

model version 6, whereas SRP used the 

current EPA-approved CALPUFF 

version 5.8. 

For assessing the degree of visibility 

improvement, ADEQ considered a 

visibility index, defined as the average 

of the visibility benefits at the closest 

nine Class I areas. The average included 

the five areas with the highest baseline 

impacts. This metric is unlike that used 

for Apache and Cholla, for which the 

benefits at the single area with 

maximum baseline impact were used. 

Since it is an average, it is somewhat 

similar to the sum of benefits over the 

nine areas, a cumulative metric used in 

other analyses, except it is divided by 

nine to compute the average. (Typically 

the sum would be computed over all 17 

Class I areas impacted by the Coronado 

facility.) For each control, ADEQ listed 

the average visibility improvement in 

deciviews, and cost in millions of 

dollars per average deciview 

improvement.67 Improvements in the 

visibility index ranged from 0.11 dv for 

LNB with OFA to 0.34 dv for SCR. Costs 

per deciview for the index ranged from 

$11.1 million for LNB to $50.3 million 

for SCR (not shown in the Table above). 

While an average of the visibility 

benefits over the nearest areas is an 

informative number, it is not directly 

comparable to the more typical metrics 

of the maximum benefit seen at any 

area, and sum over the areas. Moreover, 

neither the ADEQ RH SIP nor the 

facility’s report (BART Analysis for the 

Coronado Generating Station Units 1 & 

2, Document No. 05830–012–200, ENSR 

Corporation, February 2008) include 

control benefits for individual Class I 

areas. Thus, the maximum area benefit 

cannot be read from either document. 

However, the benefits can be computed 

from the individual area impacts that 

are provided in SRP’s report, including 

for Petrified Forest National Park, which 

had the highest baseline impact. Figures 

that are comparable to those for Apache 

and Cholla are included in the Table 13. 

Coronado’s maximum area visibility 

benefits range from 0.12 dv for LNB to 

0.39 dv for SCR. The costs per deciview 

range from $10.2 million for LNB with 

OFA to $43.8 for SCR. 

In evaluating SRP’s BART analysis, 

ADEQ requested additional supporting 

information from SRP regarding control 

cost calculations, and for further 

explanation regarding SRP’s 

recommendation for BART for NOX. In 

developing its Regional Haze SIP, ADEQ 


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68 Docket Item B–01, Arizona Regional Haze SIP, 

Appendix D, Page 112. 

69Arizona Regional Haze SIP, Appendix D, p. 

112. 

70We do note, however, that SRP does provide 

some additional analysis on this position in the 

BART analysis it submitted to ADEQ and in the 

responses it provided to ADEQ’s additional 

questions. Aside from stating that it reviewed SRP’s 

analysis, ADEQ did not specifically reference or 

include any aspects of SRP’s analysis in the RH SIP. 

As a result, we are not assuming that ADEQ 

necessarily agrees with SRP’s rationale, and have 

therefore not provided an analysis of it. 

71See Arizona Regional Haze SIP, Appendix D, p. 

112 for ADEQ’s BART Analysis for PM10 at 

Coronado Units 1 and 2; and BART Analysis for 

Coronado Generating Station Units 1 and 2 

(February 2008) for SRP’s analysis. 

72 Docket Item G–01, Consent Decree between 

United States and Salt River Project Agricultural 

Improvement and Power District, § V. 

73See 40 CFR part 51 appendix M. 

74See 40 CFR part 60 appendix A. 

75See Arizona Regional Haze SIP, Appendix D, 

pp. 113–15 for ADEQ’s BART Analysis for PM10 at 

Coronado Units 1 and 2; and Docket No. B.10, 

BART Analysis for Coronado Generating Station 

Units 1 and 2 (Feb. 2008) for SRP’s analysis. 

determined that LNB with OFA 

constitutes BART for NOX at Coronado 

Units 1 and 2. In making this 

determination, ADEQ did not provide 

adequate information regarding its 

rationale or weighing of the five factors, 

stating only ‘‘[a]fter reviewing the BART 

analysis provided by the company, and 

based upon the information above, 

ADEQ has determined that BART for 

NOX at Coronado Units 1 and 2 is 

advanced combustion controls (Low 

NOX burners with OFA) with an 

associated NOX emission rate of 0.32 lb/ 

MMBtu [..]’’ 68

EPA’s Evaluation: We disagree with 

several aspects of the BART analysis for 

Coronado Units 1 and 2. Regarding the 

control cost calculations, we note that 

SRP did not provide ADEQ with control 

cost calculations at a level of detail that 

allowed for a comprehensive review. 

Without such a level of review, we do 

not believe that ADEQ was able to 

evaluate whether SRP’s control costs 

were reasonable. As a result, we are 

proposing to find that ADEQ did not 

follow the requirements of section 

51.308(e)(1)(ii)(A) because ADEQ did 

not properly consider the costs of 

compliance for each control option. 

The modeling procedures relied on by 

ADEQ for assessing the visibility 

impacts from Coronado were generally 

in accord with EPA guidance. Coronado 

Units 1 and 2 were modeled together, 

and the modeling was done with the 

current regulatory version 5.8 of the 

CALPUFF modeling system.69 However, 

the use of the modeling results in 

evaluating the BART visibility factor 

was problematic. The modeling results 

show that, of the controls considered, 

only SCR would provide substantial 

visibility benefits; the other controls 

options would provide roughly half the 

0.5 dv contribution benchmark. ADEQ 

did not consider the typical visibility 

metrics of benefit at the area with 

maximum impact, nor benefits summed 

over the areas. Using the default 1 ppb 

ammonia background concentration 

would also have increased estimated 

impacts and control benefits. For these 

reasons, EPA proposes to find that the 

ADEQ selection of LNB with OFA for 

Coronado under the degree of visibility 

improvement BART factor is not 

adequately supported, and that more 

stringent control may be warranted. 

ADEQ provided little reasoning about 

the visibility basis for the Coronado 

BART selection. For example, there is 

no weighing of the visibility benefits 

and visibility cost-effectiveness for the 

various candidate controls and the 

various Class I areas. 

In addition to the problems noted 

above, we find that overall ADEQ has 

not documented its evaluation of the 

results of its five-factor analysis, as 

required by 51.308(e)(1)(ii)(A) and the 

BART Guidelines. Although ADEQ has 

developed information regarding each of 

the five factors, its selection of BART 

does not cite or interpret information 

from its analyses. ADEQ does not, for 

example, indicate whether or not it 

considered any cost thresholds to be 

reasonable or expensive in analyzing the 

costs of compliance for the various 

control options. We note that ADEQ has 

made similar NOX BART determinations 

of LNB with OFA at other facilities, 

such as Cholla Power Plant. Although 

ADEQ’s BART determinations for these 

other facilities implied that cost of 

compliance was an important 

consideration, it does not provide a 

rationale for the determination of NOX

BART at Coronado.70 Therefore, we 

propose to determine that ADEQ did not 

follow the requirements of section 

51.308(e)(1)(ii)(A). We propose to 

disapprove ADEQ’s selection of LNB 

with OFA as BART for NOX at Coronado 

Units 1 and 2. 

b. BART for PM10

Emissions of PM10 from Coronado 

Units 1 and 2 are currently controlled 

by hot-side ESPs.71 Under the terms of 

the Consent Decree described above in 

Section 4, SRP is required to optimize 

its ESPs to achieve a PM10 emission rate 

of 0.030 lb/MMBtu.72

ADEQ’s Analysis: ADEQ conducted a 

streamlined PM10 BART analysis for 

Coronado Units 1 and 2. In particular, 

ADEQ found that ‘‘BART for similar 

emissions units with similar emissions 

controls was determined to be 0.03 lb/ 

MMBtu.’’ ADEQ concluded that because 

Coronado Units 1 and 2 are already 

meeting a limit of 0.03 lb/MMBtu, 

‘‘further analysis was determined to be 

unnecessary.’’ 

EPA’s Evaluation: ADEQ’s analysis 

does not demonstrate that all potential 

upgrades to the existing ESPs were fully 

evaluated. However, we have no 

evidence that additional reductions in 

PM10 emissions would be achievable or 

cost-effective, or that such reductions 

would yield substantial visibility 

benefits. Therefore, we propose to 

approve ADEQ’s PM10 BART 

determination at Coronado. However, 

we are seeking comment on whether 

additional cost-effective upgrades to the 

existing ESPs are available that would 

warrant a lower emission limit. If we 

receive comments establishing that a 

lower limit is achievable, then we may 

disapprove the PM10 emissions limit set 

by ADEQ and promulgate a revised limit 

for one or both of these units. 

Finally, we are seeking comment on 

whether test methods other than EPA 

Method 201 and 202 73 (chosen by 

ADEQ) should be allowed or required 

for establishing compliance with the 

PM10 limits that we are approving. In 

particular, as explained below, use of 

SCR at these units is expected to result 

in increased condensable particulate 

matter in the form of H2SO4. In effect, 

the emission limit would be more 

stringent than intended by ADEQ and 

would likely not be achievable in 

practice. In order to avoid this result, 

while still assuring proper operation of 

the particulate control devices, we are 

requesting on comment on whether to 

allow compliance with the PM10 limit to 

be demonstrated using test methods that 

do not capture condensable particulate 

matter, namely EPA Methods 1 through 

4 and Method 5 or Method 5e.74 Method 

201 is very rarely used for testing. The 

typical method used for filterable PM10

is Method 201A, ‘‘constant sampling 

rate procedure,’’ which is similar to 

Method 201, but is much more practical 

to perform on a stack. 

c. BART for SO2

Emissions of SO2 at Coronado Units 1 

and 2 are currently controlled with the 

use of low-sulfur coal and partial wet 

flue gas.75 However, the consent decree 

between EPA and SRP described above 

requires installation of wet flue gas 

desulfurization (WFGD) systems at 

either Unit 1 or Unit 2 by January 2012, 

and at the remaining unit by January 1, 

2013. Both units must achieve and 

maintain a 30-day rolling average SO2

removal efficiency of at least 95.0 


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76 40 CFR 51.308(e)(1). 

77See, e.g. CAA section 110(a)(2) (F) and 40 CFR 

51.212(c). 

78As described above, ADEQ did specify a test 

method for PM10 for each of the relevant sources 

(Method 201/202). However, we are proposing to 

also allow the use of test methods that do not 

capture condensable particulate matter, namely 

EPA Methods 1 through 4 and Method 5 or Method 

5e. 

79http://www.epa.gov/airmarkt/progsregs/epaipm/BaseCasev410.html#documentation. 

percent or a 30-day rolling average SO2

emissions rate of no greater than 0.080 

lb/MMBtu. 

ADEQ’s Analysis: Because WFGD is 

the most effective control technology 

available for controlling SO2 emissions, 

ADEQ did not evaluate other control 

options. Table 14 summarizes Arizona’s 

the costs of compliance and 

improvement in visibility expected to 

result from installation of WFGD at both 

units. Based on this information, ADEQ 

determined SO2 BART for both units is 

the installation of WFGDs and an 

emission rate of 0.08 lbs/MMBtu on 30- 

day rolling average basis. 

TABLE 14—CORONADO UNITS 1 AND 2: ARIZONA’S BART SUMMARY FOR SO2

Option 1, baseline Option 2, WFGD 

Reduction in Emission (tpy) ..................................................................................................................... ................................ 25,753 

Annualized Cost ....................................................................................................................................... ................................ $44,353,330 

Visibility Index (dv) ................................................................................................................................... 2.66 1.28 

Improvement in Visibility Index (dv) ........................................................................................................ ................................ 1.38 

Incremental Cost-effectiveness ($ per dv) .............................................................................................. ................................ $32,140,094 

EPA’s Evaluation: We are proposing 

to approve ADEQ’s SO2 BART 

determination for Coronado Units 1 and 

2. Although we do not necessarily agree 

with the underlying cost and visibility 

analyses performed by SRP, we have no 

evidence that additional analysis would 

have resulted in a lower emission limit. 

Therefore, we propose to approve 

ADEQ’s SO2 emission limit of 0.08 lb/ 

MMBtu (30-day rolling average) for 

Coronado Units 1 and 2. However, we 

are seeking comment on whether a 

lower emission limit may be achievable 

when the units are burning a lowersulfur coal. If we receive comments 

establishing that a lower limit is 

achievable, then we may disapprove the 

SO2 emissions limit set by ADEQ and 

promulgate a revised limit for one or 

both of these units. 

D. Enforceability of BART Limits 

Regional Haze SIPs must include 

requirements to ensure that BART 

emission limits are enforceable. In 

particular, the RHR requires inclusion of 

(1) A schedule for compliance with 

BART for each source subject to BART; 

(2) a requirement for each BART source 

to maintain the relevant control 

equipment; and (3) procedures to ensure 

control equipment is properly operated 

and maintained.76 General SIP 

requirements also mandate that the SIP 

include all regulatory requirements 

related to monitoring, recordkeeping 

and reporting for the BART emissions 

limitations.77 ADEQ did not include any 

of these elements in its Regional Haze 

SIP.78 Therefore, we are proposing to 

disapprove this aspect of the Regional 

Haze SIP for these three sources and to 

promulgate a FIP to ensure the emission 

limits are enforceable. 

VII. EPA’s Proposed FIP Actions 

A. EPA’s BART Analyses and 

Determinations 

EPA conducted a new five-factor 

BART analysis of the three facilities in 

order to evaluate Arizona’s RH SIP, and 

to document the technical basis for 

proposing BART determinations in our 

FIP. Because EPA generally concurs 

with ADEQ’s BART analyses in Steps 1 

and 2 (Identify All Available Retrofit 

Control Technologies and Eliminate 

Technically Infeasible Options), we 

focused our technical analysis on Steps 

3, 4 and 5 (Evaluate Control 

Effectiveness of Remaining Control 

Technologies, Evaluate Impacts and 

Document Results, and Evaluate 

Visibility Impacts). We relied on 

contractor assistance from the 

University of North Carolina Institute 

for the Environment to evaluate control 

effectiveness, perform cost calculations, 

and conduct new visibility modeling for 

each of the units at the three facilities, 

except Apache Generating Station Unit 

1 for which this level of analysis was 

unnecessary. Our approach to each of 

these factors is explained below, 

followed by our BART determinations 

for the three sources in the next section. 

Copies of the contractor’s reports and 

the details of our BART analyses are in 

our Technical Support Document (TSD) 

available in the docket. 

1. Costs of Compliance 

Cost Estimates and Calculations: In 

estimating the costs of compliance, we 

have relied on facility data from a 

number of sources including ADEQ, the 

Energy Information Administration 

(EIA), and EPA’s Control Cost Manual. 

As discussed previously, ADEQ, in 

developing its RH SIP, requested certain 

clarifying information from the facilities 

regarding their control cost calculations, 

including greater detail regarding the 

underlying assumptions. ADEQ 

received responses of varying detail to 

these requests. Although in some cases 

the facilities provided summaries of 

certain broad line item costs, in no case 

does the supporting information that is 

available provide detail at a level that 

allows for critical review. In the case of 

SRP Coronado Generating Station, 

ADEQ received only a broad summary 

of control costs without itemized 

breakdowns of specific costs. 

As a result, we have used EPA’s 

Integrated Planning Model (IPM) to 

calculate the capital costs and annual 

operating costs associated with the 

various NOX control options. EPA’s 

Clean Air Markets Division (CAMD) 

uses IPM to evaluate the cost and 

emissions impacts of proposed policies 

to limit emissions of SO2, NOX, carbon 

dioxide (CO2), and mercury (Hg) from 

the electric power sector. Developed by 

ICF Consulting, Inc. and used to support 

public and private sector clients, IPM is 

a multi-regional, dynamic, deterministic 

linear programming model of the U.S. 

electric power sector. EPA has used IPM 

in rulemakings such as the Mercury and 

Air Toxics Standard and the Cross-State 

Air Pollution Rule. For the purposes of 

this BART determination, we 

specifically used only the NOX emission 

control technology cost methodologies 

contained in EPA’s IPM Base Case v4.10 

(August 2010).79 For Base Case v4.10, 

EPA’s Clean Air Markets Division 

contracted with engineering firm 

Sargent and Lundy to perform a 

complete bottom-up engineering 

reassessment of the cost and 

performance assumptions for SO2 and 

nitrogen oxides NOX emission controls. 

Summaries of our control cost estimates 

for the various control technology 

options considered for each unit are 

included below. Detailed cost 


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80 40 CFR part 51, appendix Y § IV.D.3. 

81 70 FR 39166. 

82See Docket Items G–04, ‘‘Emissions Control: 

Cost-Effective Layered Technology for Ultra-Low 

NOX Control’’ (2007), Docket Item G–05 ‘‘What’s 

New in SCRs’’ (2006), and Docket Item G–06 

‘‘Nitrogen Oxides Emission Control Options for 

Coal-Fired Electric Utility Boilers’’ (2005). 

83 40 CFR part 51, appendix Y § IV.D.3. 

84 Docket Items C–15 ‘‘Letter from Kelly Barr 

(SRP) to Deborah Jordan (EPA)’’ and C–16 ‘‘Letter 

from Michelle Freeark (AEPCO) to Deborah Jordan 

(EPA).’’ 

85 ‘‘Impact of Ammonia in Fly Ash on its 

Beneficial Use,’’ Memorandum from Nancy Jones 

and Stephen Edgerton, EC/R Incorporated, to Anita 

Continued 

calculations, including our contractor’s 

report and cost calculation 

spreadsheets, are in the Technical 

Support Document. 

We used publicly available 

information to estimate that AEPCO is a 

small utility. EPA requested information 

from AEPCO on the economics of 

operating Apache Generating Station 

and what impact the installation of SCR 

may have on the economics of operating 

Apache Generating Station. Specifically, 

EPA is seeking information on the 

ability of AEPCO to recover the cost of 

pollution control technology through 

rate increases and the impact those rate 

increases may have on AEPCO’s 

customers. If we receive comments 

sufficiently documenting that 

installation of SCR may have a severe 

impact on the economics of operating 

Apache Generating Station, we may 

incorporate such considerations in our 

selection of BART. Our impact analysis 

and request for comment is discussed in 

more detail below, under EPA’s BART 

Determinations for Apache Units 2 and 

3. 

Control Effectiveness: The evaluation 

of control effectiveness is an important 

part of a five-factor analysis because it 

influences both cost-effectiveness and 

visibility benefits. The BART Guidelines 

note that for each technically feasible 

control option: 

‘‘It is important * * * that in analyzing the 

technology you take into account the most 

stringent emission control level that the 

technology is capable of achieving. You 

should consider recent regulatory decisions 

and performance data (e.g., manufacturer’s 

data, engineering estimates and the 

experience of other sources) when 

identifying an emissions performance level 

or levels to evaluate.’’ 80

In general, our estimates of LNB and 

SNCR control effectiveness differ 

slightly from the control effectiveness 

levels considered by ADEQ. In the case 

of LNB, for example, this is the result 

of the fact that actual emissions data for 

LNB performance were available for 

certain units at the time of our analysis. 

ADEQ’s analysis was performed at an 

earlier date when these emissions data 

were not available. More detailed 

information regarding these differences 

is in our discussion of individual 

facilities in the following sections of 

this notice, as well as in our TSD. 

In particular, we find that ADEQ did 

not adequately support its estimate of 

SCR control effectiveness. SCR, as an 

add-on control technology, can be 

installed by itself as a standalone option 

or in conjunction with burner upgrades. 

In cases where units can be upgraded 

with combustion control technology 

such as low-NOx burners, SCR is 

commonly installed as an add-on postcombustion control. When evaluating 

control options with a range of emission 

performance levels, the BART 

Guidelines indicate that ‘‘in analyzing 

the technology you take into account the 

most stringent emission control level 

that the technology is capable of 

achieving.’’ 81 Existing vendor literature 

and technical studies indicate that SCR 

systems are capable of achieving a 0.05 

lb/MMBtu emission rate (approximately 

80–90% control efficiency) and that this 

emission rate can be achieved on a 

retrofit basis, particularly when 

combined with combustion control 

technology such as LNB.82

For control options involving the 

installation SCR in conjunction with 

LNB, ADEQ considered the achievable 

emission rate to be between 0.07 lb/ 

MMbtu (for Apache and Cholla) and 

0.08 lb/MMbtu (for Coronado). These 

emission rates are within a range of SCR 

performance that has been considered 

by other western states in preparing RH 

SIPs, and may possibly be an 

appropriate estimation of the sitespecific level of SCR performance for 

coal-fired units at Apache, Cholla, and 

Coronado. We note that the BART 

Guidelines indicate that, ‘‘In assessing 

the capability of the control alternative, 

latitude exists to consider special 

circumstances pertinent to the specific 

source under review [* * *]. However, 

you should explain the basis for 

choosing the alternate level (or range) of 

control in the BART analysis.’’ 83

Although the alternate levels of 

emission control considered by ADEQ 

for SCR in conjunction with LNB were 

stated in each respective facility’s BART 

analysis, these emission rates were not 

further supported by any calculations, 

engineering analysis, or documentation. 

We do not believe that AEPCO, APS, 

and SRP have provided adequate 

supporting analysis to justify these 

emission rates. We are seeking comment 

on whether it is appropriate to consider 

an emission rate less stringent than 0.05 

lb/MMBtu when evaluating the 

installation SCR in conjunction with 

LNB at Apache, Cholla, and Coronado. 

In the absence of source-specific 

considerations warranting a less 

stringent control level, we presume that 

an emissions limit of 0.05 lb/MMBtu is 

achievable by these units through the 

use of SCR in addition to advanced 

combustion controls. We have recently 

received information from AEPCO and 

SRP regarding potential NOX controls at 

their facilities. This information arrived 

too late to be fully evaluated for this 

proposed rulemaking, and EPA will 

need additional documentation from the 

utilities to support the information that 

they have provided to date. We have put 

the utility information in the docket for 

public review, and we will evaluate the 

information, and any additional 

information that the utilities may want 

to provide prior to making our final 

BART determinations.84 If we receive 

additional comments that sufficiently 

document source-specific 

considerations justifying the use of an 

emission rate less stringent than 0.05 lb/ 

MMBtu, we may incorporate such 

considerations in our selection of BART. 

2. Energy and Non-Air Environmental 

Impacts 

Energy Impacts: With respect to the 

potential energy impacts of the BART 

control options, we note that SCR incurs 

a draft loss that will increase parasitic 

loads, and that other emissions controls 

may also have modest energy impacts. 

The costs for direct energy impacts, i.e., 

power consumption from the control 

equipment and additional draft system 

fans from each control technology, are 

included in the cost analyses and are 

not considered further in this section. 

Indirect energy impacts, such as the 

energy to produce raw materials, are not 

considered, consistent with the BART 

guidelines. 

Ammonia Adsorption: Ammonia 

adsorption (resulting from ammonia 

injection from SCR or selective noncatalytic reduction—SNCR) to fly ash is 

generally not desirable due to odor but 

does not impact the integrity of the use 

of fly ash in concrete. However, other 

NOX control technologies, including 

LNB, also have undesirable impacts on 

fly ash. LNBs increase the amount of 

unburned carbon in the fly ash, also 

known as Loss of Ignition (LOI), which 

does affect the integrity of the concrete. 

Commercial scale technologies exist to 

remove ammonia and LOI from fly ash. 

Moreover, the impact of SCR on fly ash 

is smaller than the impact of LNB on fly 

ash, and in both cases, the adverse 

effects can be mitigated.85 We conclude 


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42854 Federal Register / Vol. 77, No. 140 / Friday, July 20, 2012 / Proposed Rules 

Lee, U.S. EPA/Region 9, August 31, 2010. Also see 

the TSD for further discussion. 

86EPA relied on version 5.8 of CALPUFF because 

it is the EPA-approved version promulgated in the 

Guideline on Air Quality Models (40 CFR part 51, 

Appendix W, section 6.2.1.e; 68 FR 18440, April 15, 

2003. It was also the approved version when EPA 

promulgated the BART Guidelines (70 FR 39122, 

July 6, 2005). EPA updated the specific version to 

be used for regulatory purposes on June 29, 2007, 

including minor revisions as of that date; the 

approved CALPUFF modeling system includes 

CALPUFF version 5.8, level 070623, and CALMET 

version 5.8 level 070623. At this time, any other 

version of the CALPUFF modeling system would be 

considered an ‘‘alternative model’’, subject to the 

provisions of Guideline on Air Quality Models 

section 3.2.2(b), requiring a full theoretical and 

performance evaluation. 

87Technical Analysis for Arizona Regional Haze 

FIPs: Modeling Protocol for Subject-to-BART and 

BART Control Options Analyses, EP–D–07–102 

WA5–12 Task 5, Institute for the Environment, 

University of North Carolina at Chapel Hill, March 

14, 2012 

88CALMET/CALPUFF Protocol for BART 

Exemption Screening Analysis for Class I Areas in 

the Western United States, Western Regional Air 

Partnership (WRAP); Gail Tonnesen, Zion Wang; 

Ralph Morris, Abby Hoats and Yiqin Jia, August 15, 

2006. Available on UCR Regional Modeling Center 

web site, BART CALPUFF Modeling, http:// 

pah.cert.ucr.edu/aqm/308/bart.shtml. 

89Revised BART Analysis for the Navajo 

Generating Station Units 1–3, ENSR Corporation, 

Document No. 05830–012–300, January 2009, Salt 

River Project—Navajo Generating Station, Tempe, 

AZ. 

90 ‘‘Particulate Matter Speciation’’, National Park 

Service, 2006. http://www.nature.nps.gov/air/ 

Permits/ect/index.cfm. 

that the ability of the relevant facilities 

to sell fly ash is unlikely to be affected 

by the installation of SCR and SNCR 

technologies. 

Safety: SCR and SNCR may involve 

potential safety hazards associated with 

the transportation and handling of 

anhydrous ammonia. Since each of the 

relevant facilities is served by a nearby 

railroad line, EPA concludes that the 

use of ammonia does not pose any 

additional safety concern as long as 

established safety procedures are 

followed. 

Thus, EPA proposes to find that 

potential energy and non-air quality 

impacts do not warrant elimination of 

any of the otherwise feasible control 

options for NOX at any of the sources. 

3. Pollution Control Equipment in Use 

at the Source 

The presence of existing pollution 

control technology at each source is 

reflected in our 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. As 

noted above, we largely agree with 

ADEQ’s consideration of available 

control technologies. However, because 

several of the affected units have had 

new controls installed in the last several 

years, we have adjusted the baseline 

emissions periods to reflect current 

control technology at the sources, as 

described further below in our proposed 

BART determinations. 

4. Remaining Useful Life of the Source 

We are considering each source’s 

‘‘remaining useful life’’ as one element 

of the overall cost analysis as allowed 

by the BART Guidelines. Since we are 

not aware of any federally- or Stateenforceable shut-down date for any of 

the affected sources, we have used the 

default 20-year amortization period in 

the EPA Cost Control Manual as the 

remaining useful life of the facilities 

considered in this proposed action. 

5. Degree of Improvement in Visibility 

EPA estimated the degree of visibility 

improvement expected from a BART 

control based on the difference between 

baseline visibility impacts prior to 

controls and visibility impacts with 

controls in operation. EPA used the 

CALPUFF model version 5.8 86 to 

determine the baseline and post-control 

visibility impacts for all three facilities. 

EPA followed the modeling approach 

recommended in the BART Guidelines. 

We developed a modeling protocol, 

used maximum daily emissions as a 

baseline, applied estimated percent 

reductions for alternative control 

technologies, and used the CALPUFF 

model to estimate visibility impacts at 

Class I areas within 300 kilometers. 

a. Modeling Protocol 

A modeling protocol was developed 

by our contractor 87 at the University of 

North Carolina that is based largely on 

the WRAP protocol,88 although there are 

a few differences between our protocol 

and that of the WRAP. Both protocols 

used meteorological inputs for 2001, 

2002, and 2003 based on the Mesoscale 

Model version 5 (MM5). EPA 

meteorological inputs differed from the 

WRAP’s in that the WRAP incorporated 

upper air data, as recommended by the 

Federal Land Managers, and also values 

for some parameters that enabled 

smoother and more realistic wind fields. 

These CALMET inputs were developed 

by the ENSR corporation for modeling 

of emissions at the Navajo Generating 

Station.89 Another key difference was 

EPA’s use of the current regulatory 

version of the CALPUFF modeling 

system, version 5.8. Facility stack 

parameters, such as stack height and 

exit temperature, were generally the 

same as those provided by WRAP 

member states to the WRAP, except that 

in some cases updated parameters were 

provided by the facilities at EPA’s 

request. 

We performed separate CALPUFF 

modeling runs using baseline emissions, 

and using the emissions remaining after 

each candidate control technology was 

applied to the baseline. For baseline PM 

emissions, EPA used the WRAP’s 

estimates. However, following 

procedures developed by the National 

Park Service,90 EPA divided those 

emissions into separate chemical 

species, and into separate coarse and 

fine particle fractions, to reflect better 

their varying visibility impacts. 

Although costs and emission 

reductions for each candidate BART 

control technology must necessarily be 

calculated separately for each emitting 

unit of a facility, emissions from all the 

units will be emitted into the air 

simultaneously. EPA modeled all units 

(stacks) and pollutants simultaneously. 

That is, even though only NOX BART 

alternatives were evaluated, SO2 and 

PM10 emissions were also included in 

the modeling. Modeling all emissions 

from all the units accounts for the 

chemical interaction between multiple 

plumes, and between the plumes and 

the background concentrations. This 

also accounts for the facts that deciview 

benefits from individual units are not 

additive, and that each EPA BART 

proposal is for the facility as a whole. 

b. Baseline Emissions 

Baseline NOX and SO2 emissions for 

the facilities were generally based on 

the maximum daily emissions from 

recent data in EPA’s CAMD database, 

with data examined for 2008 to 2011. 

The CAMD data derive from Continuous 

Emissions Monitoring in place at the 

facilities, and give the actual emissions 

that occurred. However, in cases where 

EPA is proposing to approve the BART 

emissions limits submitted by ADEQ, 

EPA used emission rates based on those 

limits, in lb/MMBtu, in combination 

with the maximum daily heat rate in 

MMBtu/hour from the CAMD data. The 

baseline emissions used by EPA reflect 

current fuels and control technologies in 

place at the facilities, as well as 

regulatory requirements the facilities 

will be required to meet independent of 

EPA’s BART determination. This results 

in a more realistic estimate of current 

visibility impacts, and of the 

improvements that one would expect to 

result from implementation of EPA’s 

proposed BART controls. 


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91Estimating Total Sulfuric Acid Emissions from 

Stationary Power Plants, Version 2010a, 1020636, 

Technical Update, Electric Power Research 

Institute, April 2010. 

92Pitchford, Marc, 2006, ‘‘New IMPROVE 

algorithm for estimating light extinction approved 

for use’’, The IMPROVE Newsletter, Volume 14, 

Number 4, Air Resource Specialists, Inc.; Web page: 

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

Publications/news_letters.htm. 

93 Federal Land Managers’ Air Quality Related 

Values Work Group (FLAG) Phase I Report— 

Revised (2010), U.S. Forest Service, National Park 

Service, U.S. Fish and Wildlife Service, October 

2010. Available on Web page http:// 

www.nature.nps.gov/air/Permits/flag/. 

94BART Guidelines, 70 FR 39125, July 6, 2005. 

‘‘Finally, these final BART guidelines use the 

natural visibility baseline for the 20 percent best 

visibility days for comparison to the ‘cause or 

contribute’ applicability thresholds.’’ 

95 ‘‘Regional Haze Regulations and Guidelines for 

Best Available Retrofit Technology (BART) 

Determinations’’, memorandum from Joseph W. 

Paisie, EPA OAQPS, July 19, 2006, p.2. 

96Additional Regional Haze Questions’’, 

September 27, 2006 Revision, EPA OAQPS. 

c. Emission Reductions for Alternative 

Controls 

For the CALPUFF modeling to assess 

visibility after application of a control 

technology, the percent control 

expected from the technology was 

applied to the baseline maximum daily 

emissions just described, as 

recommended in the BART Guidelines. 

As discussed elsewhere, LNB and SNCR 

each were assumed to reduce NOX by 30 

percent, and SCR was assumed to 

reduce NOX by 90 percent. However, for 

SCR, we used a lower bound of 0.05 lb/ 

MMBtu NOX, an emission rate that we 

have confidence is achievable, as 

discussed above under ‘‘Control 

Effectiveness’’. The percent reduction 

actually applied to the maximum daily 

emissions was whatever was required to 

reduce the CAMD annual average 

emission factor down to this 0.05 lb/ 

MMBtu NOX. For the various emitting 

units at the facilities, this ranged from 

80 to 89 percent, instead of a full 90 

percent reduction. Finally, in modeling 

the visibility impact of SCR, EPA 

accounted for the increased sulfuric 

acid emissions that occur when the SCR 

catalyst oxidizes SO2 present in the flue 

gas, using an estimation procedure 

developed by the Electric Power 

Research Institute91. (Estimating Total 

Sulfuric Acid Emissions from Stationary 

Power Plants, Version 2010a, 1020636, 

Technical Update, Electric Power 

Research Institute, April 2010) This side 

effect of SCR’s NOX reduction increases 

sulfate emissions and decreases the 

visibility benefits of SCR by around 5 

percent. 

d. Visibility Impacts 

CALPUFF Modeling: EPA followed 

the BART Guidelines in assessing 

visibility impacts. For each Class I area 

within 300 km of a facility, the 

CALPUFF model is used to simulate the 

baseline visibility impact of each facility 

and the impacts resulting after 

alternative controls are applied. 

However, certain aspects of assessing 

visibility with CALPUFF are not fully 

addressed in the Guidelines. These 

aspects include which ‘‘98th percentile’’ 

from the model to use, the visibility 

calculation method (old vs. revised 

IMPROVE equation), and natural 

background concentrations (annual 

average versus best 20 percent of days). 

As recommended in the BART 

Guidelines, the 98th percentile daily 

impact in deciviews is used as the basic 

metric of visibility impact. (For a given 

Class I area, and for each modeled day, 

the model finds the maximum impact. 

From among the 365 maximum daily 

values, the 98th percentile is chosen, 

that is, the 8th highest.) Since multiple 

years of meteorology are modeled, there 

are at least three ways to use the model 

results: The maximum from among the 

98th percentiles for the individual years 

2001, 2002, and 2003 (‘‘maximum’’); the 

average of these three (‘‘average’’), or a 

single 98th percentile computed from 

all three years of data together 

(‘‘merged’’, the 22nd high among 1095 

daily values). The average and merged 

values are both unbiased estimates of 

the true 98th percentile; for this 

proposal EPA has used the merged 

value. The more conservative maximum 

value would be appropriate for a 

screening purpose, such as for 

determining whether a source is subject 

to BART. 

Visibility Calculation Method: The 

visibility calculation method relied on 

by EPA differed from that used by 

ADEQ. Visibility impacts may be 

simulated with CALPUFF using either 

the old or the revised IMPROVE 

equation for translating pollutant 

concentrations into deciviews; these are 

respectively CALPUFF visibility 

methods 6 and 8 (implemented in the 

CALPOST post-processor). Many BART 

assessments were performed before 

method 8 was incorporated into 

CALPUFF, so method 6 was generally 

for past assessments. However, in this 

proposal EPA is primarily relying on 

method 8. Method 8 is currently 

preferred by the Federal Land Managers; 

since the revised IMPROVE equation 

performs better at estimating 

visibility.92 For the facilities examined 

in this proposal, baseline impacts using 

method 6 would average about 10 

percent higher than those using method 

8 (with a range of 3 percent lower to 22 

percent higher depending on facility 

and Class I area; the effect for areas 

showing the largest benefit from control 

was similar to the average). 

Another CALPUFF choice is whether 

to calculate visibility impacts relative to 

annual average natural conditions, or 

relative to the best 20 percent of natural 

background days; these may be referred 

to as ‘‘a’’ and ‘‘b’’. For both ‘‘a’’ and ‘‘b’’, 

background concentrations for each 

Class I area are available in a Federal 

Land Managers’ document.93 EPA 

Guidance allows for the use of either 

‘‘a’’ or ‘‘b.’’94 95 Since the annual average 

has worse visibility and higher 

deciviews than the best days do, a given 

facility impact will be smaller relative to 

the average than it is relative to the best 

days. That is, a facility’s impact will 

stand out less under poorer visibility 

conditions. Thus, modeled facility 

impacts and control benefits appear 

smaller when ‘‘a’’ is used than when 

‘‘b’’ is used. In this proposal, EPA is 

relying on ‘‘b’’, best 20 percent, 

consistent with initial EPA 

recommendations for BART 

assessments. For the facilities examined 

in this proposal, baseline impacts would 

average about 20 percent lower using 

background ‘‘a’’ than those using 

background ‘‘b’’ (with a range of 18 

percent to 28 percent lower depending 

on facility and Class I area; the effect for 

areas showing the largest benefit from 

control was similar to the average). 

Considering visibility method and 

choice of background together, the 

BART visibility assessments relied on 

by ADEQ used method ‘‘6a’’, the old 

IMPROVE equation, and impacts 

relative to annual average natural 

conditions. This is a valid approach, 

and is consistent with EPA guidance.96

However, for this proposal, EPA 

considered all four combinations of 

IMPROVE equation version and natural 

background: 6a, 6b, 8a, and 8b. EPA 

primarily relied on method ‘‘8b’’, that is, 

the revised IMPROVE equation, and 

impacts relative to the best 20 percent 

of natural background days. This is most 

consistent with our current 

understanding of how best to assess 

source specific visibility impacts. 

Combining the differences in visibility 

method and chosen background, for the 

facilities examined in this proposal, 

baseline impacts would average about 

15 percent lower using method ‘‘6a’’ 

than those using method ‘‘8b’’ (with a 

range of 3 percent to 37 percent lower 

depending on facility and Class I area; 

the effect for areas showing the largest 

benefit from control was similar to the 

average). Results for all the various 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
42856 Federal Register / Vol. 77, No. 140 / Friday, July 20, 2012 / Proposed Rules 

97BART Guidelines, 40 CFR part 51, appendix P, 

Section IV.D.4.d. 

98As listed in Table 2–1 in Docket Items B–03 

and B–04, Apache BART Analyses. 

99We note that there are multiple reasons why 

our annual emission estimates (and estimates of 

emission removal) are lower than AEPCO’s and 

ADEQ’s estimates. We are not implying that the use 

of capacity factor is the sole, or even dominant, 

reason for this difference, simply that the use of 

lower capacity factors will result in lower annual 

emission estimates. 

visibility methods are available in the 

TSD. 

B. EPA’s FIP BART Determinations 

1. Apache Units 2 and 3 

a. Costs of Compliance 

Our general approach to calculating 

the costs of compliance is described in 

VII.A.1., while issues unique to Apache 

Units 2 and 3 are described herein. In 

particular, we highlight below certain 

aspects of our analysis of this factor that 

differ from ADEQ’s and AEPCO’s 

analysis. 

i. Selection of Baseline Period 

AEPCO’s BART analysis used a 2002 

to 2007 time period in order to establish 

its baseline NOX emissions. In our 

analysis, we decided to make use of the 

most recent Acid Rain Program 

emission data reported to CAMD, 

which, at the time that we began our 

analysis in 2011, was the three-year 

period from 2008 to 2010. Based on 

CAMD documentation, no new control 

technology beyond the existing OFA 

system has been installed on either 

Apache Unit 2 or 3. We consider the use 

of this more recent baseline period to be 

a realistic depiction of anticipated 

future emissions.97

ii. SCR Control Efficiency 

In determining the control efficiency 

of SCR, we have relied upon an SCR 

level of performance of 0.05 lb/MMBtu, 

which is more stringent than the level 

of performance used by ADEQ in its SIP. 

In the Apache BART analyses submitted 

to ADEQ, AEPCO indicated an SCR 

level of performance of 0.07 lb/MMBtu, 

but did not provide site-specific 

information describing how this 

emission rate was developed or 

discussing why a more stringent 0.05 lb/ 

MMBtu level of performance could not 

be attained. Our control cost 

calculations for the SCR and LNB with 

OFA control options are based upon the 

control efficiency of SCR (combined 

with LNB) summarized in Table 15. 

TABLE 15—APACHE 2 AND 3: EPA’S SCR (COMBINED WITH LNB) CONTROL EFFICIENCY

Unit 

Baseline 

emission rate 1

(lb/MMBtu) 

SCR emission 

rate 

SCR control 

efficiency 

(percentage) 

Apache 2 .......................................................................................................................... 0.371 0.05 87 

Apache 3 .......................................................................................................................... 0.438 0.05 89 

1This baseline emission rate represents operation of OFA only. 

iii. Capacity Factor 

As noted previously, AEPCO 

calculated annual emission estimates for 

its control scenarios, in tons per year, 

using annual capacity factors developed 

internally over an unspecified time 

frame.98 The annual capacity factors 

AEPCO used for each unit were 92 

percent (Apache 2), and 87 percent 

(Apache 3). We have also calculated 

annual emission estimates for our 

control scenarios using capacity factors, 

but have used information developed 

from CAMD information, and over a 

more recent 2008 to 2011 time frame. 

The annual capacity factors we have 

used for each unit are 62 percent 

(Apache 2), and 71 percent (Apache 3). 

We recognize that these capacity factors 

are lower than those used by AEPCO, 

and that by using these lower capacity 

factors, our estimates of total annual 

emissions (and correspondingly, the 

annual emission reductions) for each 

control scenario are lower than 

AEPCO’s estimates.99 Since costeffectiveness ($/ton) is calculated by 

dividing annual control costs ($/year) by 

annual emission reductions (tons/year), 

the use of emission reductions based on 

lower capacity factors will increase the 

cost per ton of pollutant reduced. 

We have elected to use the capacity 

factors specified above, as based on a 

2008 to 2011 time frame, in order to 

remain consistent with the time frame 

used to develop baseline annual 

emissions for Apache and the other 

power plants that are the subject of 

today’s proposed action. 

iv. Summary of Control Cost Estimates 

A summary of our control cost 

estimates for the various control 

technology options considered for 

Apache Units 2 and 3 is in Table 16. 

Detailed cost calculations, including our 

contractor’s report and cost calculation 

spreadsheets, are available in our 

Technical Support Document. 

TABLE 16—APACHE UNITS 2 AND 3: EPA’S CONTROL COST SUMMARY

Control option 

Emission 

factor 

(lb/MMBtu) 

Emission rate 

Emissions 

removed 

(tpy) 

Annual cost 

($/yr) 

Cost-effectiveness 

($/ton) 

(lb/hr) (tpy) Ave 

Incremental 

(from 

previous) 

Apache 2 

OFA (baseline) ................................... 0 .371 859 2,333 .................... .................... .................... ........................

LNB+OFA ........................................... 0 .26 601 1,633 700 1,142,120 1,632 ........................

SNCR+LNB+OFA .............................. 0 .18 421 1,143 1,190 2,652,841 2,230 3,084 

SCR+LNB+OFA ................................. 0 .05 116 314 2,019 5,869,299 2,908 3,881 


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100Apache Unit 4, which consists of four simplecycle gas turbines, was not included in the 

modeling because its NOX emissions are less than 

1 percent of the emissions of units 2 and 3, and are 

therefore expected to have a de minimis effect on 

modeled visibility impacts. 

101Arizona Regional Haze SIP, Appendix E, 

Public Process, NPS General BART Comments on 

ADEQ BART Analyses (November 29, 2010), p. 4. 

TABLE 16—APACHE UNITS 2 AND 3: EPA’S CONTROL COST SUMMARY—Continued 

Control option 

Emission 

factor 

(lb/MMBtu) 

Emission rate 

Emissions 

removed 

(tpy) 

Annual cost 

($/yr) 

Cost-effectiveness 

($/ton) 

(lb/hr) (tpy) Ave 

Incremental 

(from 

previous) 

Apache 3 

OFA (baseline) ................................... 0 .438 974 3,028 .................... .................... .................... ........................

LNB+OFA ........................................... 0 .31 682 2,120 908 1,153,378 1,270 ........................

SNCR+LNB+OFA .............................. 0 .22 477 1,484 1,544 2,968,611 1,922 2,854 

SCR+LNB+OFA ................................. 0 .05 111 346 2,683 6,103,078 2,275 2,754 

As seen in Table 16, our calculations 

indicate that the SCR-based control 

options have average cost-effectiveness 

values of $2,275/ton to $2,908/ton, 

which falls in a range that we consider 

cost-effective. In addition, our 

calculations indicate that the SCR-based 

control options have an incremental 

cost-effectiveness of $2,754/ton to 

$3,881/ton, which is also in a range that 

we would consider cost-effective. As a 

result, our analysis of this factor 

indicates that the costs of compliance 

(average or incremental) are not 

sufficiently large to warrant eliminating 

any of the control options from 

consideration. 

b. Visibility Improvement 

The overall visibility modeling 

approach was described above; aspects 

of the modeling specific to Apache are 

described here. EPA is proposing a NOX

BART determination only for Apache 

units 2 and 3, but Unit 1 was also 

included in the modeling runs for 

greater realism in assessing the full 

facility’s visibility impacts.100 For Unit 

1’s NOX emissions, ADEQ’s emission 

factor of 0.56 lb/MMBtu was combined 

with the maximum MMBtu/hr heat rate 

from EPA’s CAMD database for 2008 to 

2010. The baseline emissions used for 

these units were the maximum daily 

emissions in lb/hr from 2008 to 2010; 

the maxima occurred in early 2008. The 

base case reflects only OFA as the 

control in place. 

EPA evaluated LNB, SNCR (including 

LNB), and SCR (including LNB) applied 

to both Units 2 and 3; as mentioned 

above the SCR simulation accounted for 

the increase in sulfuric acid emissions 

due to catalyst oxidation of SO2. SCR 

was assumed to give a control 

effectiveness of 87 percent and 89 

percent for Units 2 and 3, respectively 

(less than 90 percent due to the 0.05 lb/ 

MMBtu NOX lower limit assumed for 

SCR). The nine Class I areas within 300 

km of Apache were modeled; they are 

in the states of Arizona and New 

Mexico. The 98th percentile of delta 

deciviews over all three years of data 

was computed for each area and 

emission scenario. 

Table 17 shows the impact for the 

base case, and the improvement from 

that baseline impact when controls are 

applied, all in deciviews, for each area. 

The Class I area types are National 

Monument (NM), Wilderness Area 

(WA), and National Park (NP). Also 

shown are the cumulative deciviews, 

the simple sum of impacts or 

improvements over all the Class I areas, 

and the number of areas with a baseline 

impact or improvement of at least 0.5 

dv. Finally, the table includes two 

‘‘dollars per deciview’’ measures of costeffectiveness, both of which take the 

annual cost of the control in millions of 

dollars per year, and divide by an 

improvement in deciviews. For the first 

metric, ‘‘$/max dv’’, cost is divided by 

the deciview improvement at the Class 

I area with the greatest improvement. 

The second metric, ‘‘$/cumulative dv’’, 

divides cost by the cumulative deciview 

improvement. In assessing the degree of 

visibility improvement from controls, 

EPA relied heavily on the maximum dv 

improvement and the number of areas 

showing improvement, with cumulative 

improvement providing a supplemental 

measure that combines information on 

the number of areas and on individual 

area improvement. The dollars per 

deciview metrics provided information 

supplemental to the dollars per ton that 

was considered in the cost factor. 

In its comments on Arizona’s 

proposed Regional Haze SIP, the 

National Park Service noted that: 

Compared to the typical control cost 

analysis in which estimates fall into the 

range of $2,000–$10,000 per ton of pollutant 

removed, spending millions of dollars per 

deciview (dv) to improve visibility may 

appear extraordinarily expensive. However, 

our compilation of BART analyses across the 

U.S. reveals that the average cost per dv 

proposed by either a state or a BART source 

is $14–$18 million.101

While we do not necessarily consider 

$14 to $18 million/dv as being a 

reasonable range in all cases, we note 

that for all of the NOX control options, 

including SCR, both the $/max dv and 

the $/cumulative dv are well below this 

range. 

The area with the greatest dv 

improvement was the Chiricahua 

Wilderness Area; the improvement from 

LNB was 0.5 dv, from SNCR was 1 dv, 

and from SCR was 1.6 dv. Any of these 

improvements would contribute to 

improved visibility, with SCR being the 

superior option for visibility. The 

corresponding cumulative 

improvements are 2.1, 3.8, and 6.5. Both 

SNCR and SCR give improvements 

exceeding 0.5 dv at four areas, but for 

SCR the improvements at those areas 

also exceed a full 1 dv. The 

improvements from SCR are 

substantially greater than for the other 

candidate controls. The modeled degree 

of visibility improvement supports SCR 

as BART for Apache. 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
42858 Federal Register / Vol. 77, No. 140 / Friday, July 20, 2012 / Proposed Rules 

102 70 FR 39171. 

103See Docket Item H–1Arizona Electric Power 

Cooperative, Inc. Annual Report Electric for Year 

Ending December 31, 2011 submitted to Arizona 

Corporation Commission Utilities Division, 

available at http://www.azcc.gov/Divisions/Utilities/ 

Annual%20Reports/2011/Electric/ 

Arizona_Electric_Power_Cooperative_Inc.pdf. 

104 Docket Item C–16, Letter from Michelle 

Freeark (AEPCO) to Deborah Jordan (EPA), 

AEPCO’s Comments on BART for Apache 

Generating Station, June 29, 2012. 

TABLE 17—APACHE UNITS 2 AND 3: EPA’S VISIBILITY IMPROVEMENT FROM NOX CONTROLS

Class I Area 

Baseline 

impact 

(dv) 

Improvement 

from LNB 

(dv) 

Improvement 

from SNCR 

(dv) 

Improvement 

from SCR 

(dv) 

Chiricahua NM ........................................................................................... 3.41 0 .44 0 .82 1 .51 

Chiricahua WA ........................................................................................... 3.46 0 .53 1 .00 1 .59 

Galiuro WA ................................................................................................ 2.22 0 .39 0 .65 1 .10 

Gila WA ...................................................................................................... 0.63 0 .14 0 .22 0 .37 

Mazatzal WA .............................................................................................. 0.28 0 .05 0 .09 0 .14 

Mount Baldy WA ........................................................................................ 0.28 0 .07 0 .11 0 .18 

Saguaro NP ............................................................................................... 2.49 0 .38 0 .66 1 .16 

Sierra Ancha WA ....................................................................................... 0.29 0 .06 0 .10 0 .14 

Superstition WA ......................................................................................... 0.61 0 .10 0 .19 0 .31 

Cumulative dv ............................................................................................ 13.67 2 .14 3 .83 6 .51 

# areas >=0.5 ............................................................................................ 6 1 4 4 

$/max dv, millions ...................................................................................... ........................ $4 .8 $6 .0 $8 .7 

$/cumulative dv, millions ............................................................................ ........................ $1.2 $1 .6 $2 .1 

c. EPA’s BART Determination 

In considering the results of the fivefactor analysis, we note that the 

remaining useful life of the source, as 

indicated previously by the plant 

economic life of Apache Units 2 and 3, 

is incorporated into control cost 

calculations as a 20-year amortization 

period. In addition, the presence of 

existing pollution control technology is 

reflected in the cost and visibility 

factors as a result of selection of the 

baseline period for cost calculations and 

visibility modeling. For Apache Units 2 

and 3, a baseline period (2008 to 2010) 

was selected that reflects the currently 

existing pollution control technology 

(OFA). In examining energy and non-air 

quality impacts, we note certain 

potential impacts resulting from the use 

of ammonia injection associated with 

the SNCR and SCR control options, but 

do not consider these impacts sufficient 

enough to warrant eliminating any of 

the available control technologies. 

Our consideration of degree of 

visibility improvement focuses 

primarily on the improvement from base 

case impacts associated with each 

control option. While each of the 

available NOX control options achieves 

some degree of visibility improvement, 

we consider the improvement 

associated with the most stringent 

option, SCR with LNB and OFA, to be 

substantial. Our consideration of cost of 

compliance focuses primarily on the 

cost-effectiveness of each control 

option, as measured in cost per ton and 

incremental cost per ton of each control 

option. Despite the fact that the most 

stringent option, SCR with LNB and 

OFA, is the most expensive of the 

available control options, we consider it 

cost-effective on an average basis as well 

as on an incremental basis when 

compared to the next most stringent 

option, SNCR with LNB and OFA. 

As a result, we consider the most 

stringent available control option, SCR 

with LNB and OFA, to be both costeffective and to result in substantial 

visibility improvement, and that the 

energy and non-air quality impacts are 

not sufficient to warrant eliminating it 

from consideration. Therefore, the 

results of our five-factor analysis 

indicate that NOX BART for Apache 

Units 2 and 3 is SCR with LNB and 

OFA. 

However, we note that the BART 

guidelines state that: 

Even if the control technology is costeffective, there may be cases where the 

installation of controls would affect the 

viability of continued plant operations. 

[...]You may take into consideration the 

conditions of the plant and the economic 

effects of requiring the use of a control 

technology. Where these effects are judged to 

have a severe impact on plant operations you 

may consider them in the selection process, 

but you may wish to provide an economic 

analysis that demonstrates, in sufficient 

detail for public review, the specific 

economic effects, parameters, and 

reasoning.’’ 102

As explained in Section IX.C below, 

because AEPCO is a ‘‘small entity’’, as 

defined under the Regulatory Flexibility 

Act, we have conducted an initial 

assessment of the potential adverse 

impacts on AEPCO of requiring SCR 

with LNB and OFA. Using publicly 

available information, EPA estimates 

that the annualized cost of requiring 

SCR in Units 1 and 2 would likely be 

in the range of 3 percent of AEPCO’s 

assets and between 6 and 7 percent of 

AEPCO’s annual sales. The projected 

costs of SCR with LNB and OFA are 

approximately $12 million per year. 

This exceeds AEPCO’s net margins of 

$9.5 million in 2010 and $1.9 million in 

2011.103

In addition to conducting this initial 

economic impact assessment, we 

requested information from AEPCO on 

the economics of operating Apache 

Generating Station and what impact the 

installation of SCR may have on the 

economics of operating Apache 

Generating Station. We have just 

received a description of plant 

conditions and potential economic 

effects and are placing this information 

in the docket for this action.104 We will 

consider this information and any 

additional information received during 

the comment period as part of our final 

action. If our analysis of this 

information indicates that installation of 

SCR will have a severe impact on the 

economics of operating Apache 

Generating Station, we will incorporate 

such considerations in our selection of 

BART. 

Nonetheless, based on the available 

control technologies and the five factors 

discussed above, EPA is proposing to 

require Apache Generating Station to 

meet an emission limit for NOX on Units 

2 and 3 of 0.050 lb/MMBtu. Each of 

these emission limits is based on a 

rolling 30-boiler-operating-day average. 

2. Cholla Units 2, 3 and 4 

a. Costs of Compliance 

Our general approach to calculating 

the costs of compliance is described in 

section VII.A.1 above. Issues unique to 

Cholla Units 2, 3 and 4 are explained 


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Federal Register / Vol. 77, No. 140 / Friday, July 20, 2012 / Proposed Rules 42859 

105A copy of the coal contract, including 

obligation amounts and coal quality, can be found 

in Docket Item B–09, ‘‘Additional APS Cholla 

BART response’’, Appendix B. 

106As listed in Table 2–1 in Docket Items B–06 

through B–08, Cholla BART Analyses. 107We note that there are multiple reasons why 

our annual emission estimates (and estimates of 

emission removal) are lower than APS’ and ADEQ’s 

estimates. We are not implying that the use of 

capacity factor is the sole, or even dominant, reason 

for this difference, simply that the use of lower 

capacity factors will result in lower annual 

emission estimates. 

herein. There are several aspects of our 

analysis of this factor that differ from 

ADEQ’s and APS’ analysis and we 

discuss the most important of these 

below. 

i. Selection of Baseline Period 

APS’ BART analysis used a 2001–03 

time period in order to establish its 

baseline NOX emissions. As noted 

previously, the NOX control technology 

present on Cholla Units 2 through 4 

during that time period was closecoupled over fire air (COFA). APS has 

since installed low-NOX burners with 

separated over fire air (SOFA) on Cholla 

Units 2 through 4. In order to properly 

consider the second BART factor 

(pollution control equipment in use at 

the source) and to ensure that actual 

conditions at the plant were reflected in 

our baseline NOX emissions, we decided 

to make use of the most recent Acid 

Rain Program emission data reported to 

CAMD, which, at the time that we began 

our analysis in 2011, was the three-year 

period from 2008 to 2010. Based on 

CAMD documentation, the low-NOX

burners were installed on the Cholla 

units at different times during 2008 and 

2009, making it necessary for us to 

clearly distinguish between the pre-LNB 

and post-LNB periods of emission data 

for each unit. 

The use of a 2008 to 2010 baseline 

was, however, complicated by the fact 

that the Cholla plant operates under a 

new coal contract for Lee Ranch/El 

Segundo coal, which is a higher NOXemitting coal than what was previously 

used.105 This coal contract indicates 

that steadily increasing minimum 

quantities of coal shall be delivered, 

starting with 325,000 tons in 2006 and 

up to 3,700,000 tons in 2010. This 

gradual transition to the newer, higherNOX emitting coal source made it 

difficult to determine the extent to 

which a particular year’s emissions 

were representative of anticipated 

annual emissions. In the absence of 

more detailed fuel usage records on a 

per-unit basis, it was not possible for us 

to identify which units may have 

operated using the newer coal during 

the 2006 to 2010 transition period to the 

newer coal type. We note, however, that 

the coal contract specifically states that, 

for 2010 to 2024, no later than July 1 of 

each year, the buyer shall indicate the 

annual tonnage for the following 

calendar year, and that in no case shall 

the annual tonnage be less than 

3,700,000 tons. As a result, 2011 

represents the first complete calendar 

year at which we can be certain that the 

Cholla plant operated at the new coal 

contract’s ‘‘full’’ minimum purchase 

quantity of 3,700,000 tons per year. 

Since 2011 Acid Rain Program 

emission data became available during 

the intervening time between the start of 

our analysis and our proposed action 

today, we have selected 2011 as the time 

period for establishing baseline annual 

NOX emissions. Although this 

represents only a single year of data, we 

believe the use of this more recent 

baseline period represents the most 

realistic depiction of anticipated annual 

emissions, as it is the only time period 

that ensures each of the Cholla units is 

operating using the new coal and LNB 

with SOFA. 

ii. SCR Control Efficiency 

In determining the control efficiency 

of SCR, we have relied upon an SCR 

level of performance of 0.05 lb/MMBtu, 

which is more stringent than the level 

of performance used by ADEQ in its SIP. 

In the Cholla BART analysis submitted 

to ADEQ, APS indicated an SCR level of 

performance of 0.07 lb/MMBtu, but did 

not provide site-specific information 

describing how this emission rate was 

developed or discussing why a more 

stringent 0.05 lb/MMBtu level of 

performance could not be attained. Our 

control cost calculations for the SCR 

and LNB with OFA control options are 

based upon the SCR control efficiencies 

summarized below. These control 

efficiencies reflect the emission 

reductions associated with controlling 

from an annual average baseline 

emission rate that represents LNB with 

OFA (as described previously) down to 

an SCR emission rate of 0.05 lb/MMBtu. 

TABLE 18—CHOLLA UNITS 2, 3 AND 4: EPA’S SCR CONTROL EFFICIENCY

Unit 

Baseline 

emission rate 1

(lb/MMBtu) 

SCR emission 

rate 

SCR control 

efficiency 

(percentage) 

Cholla 2 ............................................................................................................................ 0.295 0.05 83 

Cholla 3 ............................................................................................................................ 0.254 0.05 80 

Cholla 4 ............................................................................................................................ 0.260 0.05 81 

1As noted previously, this baseline emission rate reflects the installation of LNB+OFA 

iii. Capacity Factor 

As noted previously, APS calculated 

annual emission estimates for its control 

scenarios, in tons per year, using annual 

capacity factors based on Acid Rain 

Program data from CAMD over a 2001 

to 2006 time frame.106 The annual 

capacity factors APS used for each unit 

were 91 percent (Cholla 2), 86 percent 

(Cholla 3), and 93 percent (Cholla 4). 

We have also calculated annual 

emission estimates for our control 

scenarios using capacity factors 

developed from CAMD information, but 

have instead used a more recent 2008 to 

2011 time frame. The annual capacity 

factors we have used for each unit are 

74 percent (Cholla 2), 75 percent (Cholla 

3), and 71 percent (Cholla 4). We 

recognize that these capacity factors are 

lower than those used by APS, and that 

by using these lower capacity factors, 

our estimates of total annual emissions 

(and correspondingly, the annual 

emission reductions) for each control 

scenario are lower than APS’ 

estimates.107 Since cost-effectiveness ($/ 

ton) is calculated by dividing annual 

control costs ($/year) by annual 

emission reductions (tons/year), the use 

of emission reductions based on lower 

capacity factors will increase the cost 

per ton of pollutant reduced. 

We have elected to use the capacity 

factors specified above, as based on a 

2008 to 2011 time frame, in order to 

remain consistent with the time frame 

used to develop baseline annual 

emissions for Cholla and the other 


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42860 Federal Register / Vol. 77, No. 140 / Friday, July 20, 2012 / Proposed Rules 

108We recognize that there are more aggressive 

approaches we could adopt that could justify the 

use of higher capacity factors, which would thereby 

lower the cost per ton of pollutant reduced. For 

example, instead of using historical data to develop 

a capacity factor value for each unit, we could use 

a single capacity factor value for each unit, one that 

represented a reasonable depiction of anticipated 

annual baseload operations. Alternately, we could 

also use the capacity factor estimates from APS’ 

Cholla BART analyses, as based on a 2001–06 time 

frame, or develop new capacity factors based on a 

longer 2001 to 2011 time frame. 

power plants that are the subject of 

today’s proposed action.108

iv. Summary of Control Costs 

A summary of our control cost 

estimates for the various control 

technology options considered for is 

included below. Detailed cost 

calculations, including our contractor’s 

report and cost calculation 

spreadsheets, can be found in our TSD. 

TABLE 19—CHOLLA UNITS 2, 3 AND 4: EPA’S CONTROL COST SUMMARY

Control option 

Emission 

factor 

(lb/MMBtu) 

Emission rate 

Emissions 

removed 

(tpy) 

Annual cost 

($/yr) 

Cost-effectiveness ($/ton) 

(lb/hr) (tpy) Ave 

Incremental 

(from 

previous) 

Cholla 2 

OFA .................................................... NA; LNB+OFA is the currently installed technology 

LNB+OFA (baseline) .......................... 0 .295 892 2,890 .................... .................... .................... ........................

SNCR+LNB+OFA .............................. 0 .21 624 2,023 867 2,482,318 2,863 ........................

SCR+LNB+OFA ................................. 0 .05 151 490 2,400 7,475,028 3,114 3,257 

Cholla 3 

OFA .................................................... NA; LNB+OFA is the currently installed technology 

LNB+OFA (baseline) .......................... 0 .254 885 2,908 .................... .................... .................... ........................

SNCR+LNB+OFA .............................. 0 .18 620 2,036 872 2,533,432 2,904 ........................

SCR+LNB+OFA ................................. 0 .05 174 572 2,337 8,113,131 3,472 3,811 

Cholla 4 

OFA .................................................... NA; LNB+OFA is the currently installed technology 

LNB+OFA (baseline) .......................... 0 .260 1144 3,609 .................... .................... .................... ........................

SNCR+LNB+OFA .............................. 0 .18 801 2,526 1,083 3,185,822 2,943 ........................

SCR+LNB+OFA ................................. 0 .05 220 694 2,915 9,894,796 3,395 3,661 

As indicated in Table 19, our 

calculations indicate that the SCR-based 

control options have average costeffectiveness values of $3,114/ton to 

$3,472/ton, which falls in a range that 

we would consider cost-effective. In 

addition, our calculations indicate that 

the SCR-based control options have an 

incremental cost-effectiveness of 

$3,257/ton to $3,811/ton, which is also 

in a range that we would consider costeffective. As a result, our analysis of this 

factor indicates that the costs of 

compliance (average or incremental) are 

not sufficiently large to warrant 

eliminating any of the control options 

from consideration. 

b. Visibility Improvement 

The overall visibility modeling 

approach was described above; aspects 

of the modeling specific to Cholla are 

described here. EPA made a NOX BART 

determination for Cholla Units 2, 3 and 

4, but Unit 1 (which is not BARTeligible) was also included in the 

modeling runs for greater realism in 

assessing the full facility’s visibility 

impacts. For Unit 1’s NOX emissions, 

the maximum daily emissions from 

EPA’s CAMD database for 2008 to 2010 

were used; the maximum occurred in 

early 2008. LNB was installed on Units 

2 and 4 early in 2008, and on Unit 3 in 

mid-2009; for a realistic base case, the 

baseline emissions used for these units 

were the maximum daily emissions in 

lb/hr from 2008–2010 occurring after 

the respective LNB installation dates. 

The maximum for unit 2 occurred in 

mid-2009, and the maxima for Units 2 

and 3 occurred in late 2010. The base 

case reflects LNB as the control in place. 

EPA evaluated SNCR (including LNB) 

and SCR (including LNB) applied to 

Units 2, 3 and 4. SCR was assumed to 

give a control effectiveness of 83 

percent, 80 percent, and 81 percent for 

units 2, 3 and 4, respectively (less than 

90 percent due to the 0.05 lb/MMBtu 

NOX lower limit assumed for SCR). For 

Cholla, the increase in sulfuric acid due 

to SCR was not simulated, because the 

baghouse (fabric filter) installed for 

particulate matter control would reduce 

this increased sulfate by 99 percent, 

resulting in a negligible effect on the 

visibility estimate. The 13 Class I areas 

within 300 km of Cholla were modeled; 

they are in the states of Arizona, 

Colorado, New Mexico, and Utah. The 

98th percentile delta deciview using all 

three years of data together was 

computed for each area and emission 

scenario. 

Table 20 shows baseline visibility 

impacts and the visibility improvement 

when controls are applied; the various 

table entries are described above in the 

discussion of the comparable table for 

Apache. The area with the greatest dv 

improvement was the Petrified Forest 

National Park; the improvement from 

SNCR was just under 0.5 dv and from 

SCR was 1.3 dv. Either of these 

improvements would contribute to 

improved visibility, with SCR being the 

superior option for visibility. The 

corresponding cumulative 

improvements are 2.7 and 7.2. Only SCR 

gives improvements exceeding 0.5 dv, 

and it does so at eight areas, two of 

which have improvements above a full 

1 dv. The modeled degree of visibility 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
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109See Docket Item G–01, ‘‘Consent Decree 

Between U.S. and SRP (final as entered).’’ See also 

ADEQ Title V Permit Renewal Number 52639, 

SRP—Coronado Generating Station, section 

II.E.1.a.iii (December 06, 2011). 

110See 40 CFR part 51, appendix Y, Section 

IV.D.4.d. 

improvements supports SCR as BART 

for Cholla. 

TABLE 20—CHOLLA UNITS 2, 3 AND 4: EPA’S VISIBILITY IMPROVEMENT FROM NOX CONTROLS

Class I area Baseline impact 

(dv) 

Improvement from 

SNCR 

(dv) 

Improvement from 

SCR 

(dv) 

Capitol Reef NP ........................................................................................................... 1.46 0 .27 0 .76 

Galiuro WA .................................................................................................................. 0.45 0 .05 0 .14 

Gila WA ........................................................................................................................ 0.70 0 .09 0 .22 

Grand Canyon NP ....................................................................................................... 2.22 0 .37 1 .06 

Mazatzal WA ................................................................................................................ 1.19 0 .16 0 .43 

Mesa Verde NP ........................................................................................................... 1.34 0 .26 0 .70 

Mount Baldy WA .......................................................................................................... 1.21 0 .27 0 .52 

Petrified Forest NP ...................................................................................................... 4.53 0.47 1 .34 

Pine Mountain WA ....................................................................................................... 0.85 0 .12 0 .31 

Saguaro NP ................................................................................................................. 0.30 0 .02 0 .05 

Sierra Ancha WA ......................................................................................................... 1.36 0 .20 0 .51 

Superstition WA ........................................................................................................... 1.27 0 .17 0 .51 

Sycamore Canyon WA ................................................................................................ 1.42 0 .27 0 .68 

Cumulative dv .............................................................................................................. 18.30 2 .71 7 .21 

# areas >=0.5 .............................................................................................................. 11 0 8 

$/max dv, millions ........................................................................................................ ............................ $17 .8 $20 .8 

$/cumulative dv, millions .............................................................................................. ............................ $3 .1 $3 .8 

c. EPA’s BART Determination 

As noted above, the remaining useful 

life of the source is incorporated into 

control cost calculations as a 20-year 

amortization period. In addition, the 

presence of existing pollution control 

technology is reflected in the cost and 

visibility factors as a result of selection 

of the baseline period for cost 

calculations and visibility modeling. For 

Cholla Units 2, 3, and 4, a baseline 

period (2011) was selected that reflects 

the currently existing pollution control 

technology (LNB with OFA). In 

examining energy and non-air quality 

impacts, we note certain potential 

impacts resulting from the use of 

ammonia injection associated with the 

SNCR and SCR control options, but do 

not consider these impacts sufficient 

enough to warrant eliminating any of 

the available control technologies. 

Our consideration of degree of 

visibility improvement focuses 

primarily on the improvement from base 

case impacts associated with each 

control option. While each of the 

available NOX control options achieves 

some degree of visibility improvement, 

we consider the improvement 

associated with the most stringent 

option, SCR with LNB and OFA, to be 

substantial. 

Our consideration of cost of 

compliance focuses primarily on the 

cost-effectiveness of each control 

option, as measured in cost per ton and 

incremental cost per ton of each control 

option. Despite the fact that the most 

stringent option, SCR with LNB and 

OFA, is the most expensive of the 

available control options, we consider it 

cost-effective on average basis as well as 

on an incremental basis when compared 

to the next most stringent option, SNCR 

with LNB and OFA. 

As a result, we consider the most 

stringent available control option, SCR 

with LNB and OFA, to be both costeffective and to result in substantial 

visibility improvement, and that the 

energy and non-air quality impacts are 

not sufficient to warrant eliminating it 

from consideration. Therefore, we 

propose to determine that NOX BART 

for Cholla Units 2, 3, and 4 is SCR with 

LNB and OFA, with an associated 

emission limit for NOX on each of Units 

2, 3, and 4 of 0.050 pounds per million 

British thermal units (lb/MMBtu), based 

on a rolling 30-boiler-operating-day 

average. 

3. Coronado Units 1 and 2 

a. Costs of Compliance 

Our general approach to calculating 

the costs of compliance is described in 

section VII.A.2 above, while 

considerations unique to Coronado 

Units 1 and 2 are explained herein. 

There are several aspects of our analysis 

of this factor that differ from ADEQ’s 

and SRP’s analysis and we describe the 

most important elements below. 

i. Selection of Baseline Period and 

Baseline Control Technology 

SRP’s BART analysis used a 2001–03 

time period in order to establish its 

baseline NOX emissions. Since that time 

period, SRP has since installed LNB 

with OFA on Coronado Units 1 and 2. 

In order to ensure that actual conditions 

at the plant are reflected in our baseline 

NOX emissions, we decided to make use 

of the most recent Acid Rain Program 

emission data reported to CAMD, 

which, at the time that we began our 

analysis in 2011, was the three-year 

period from CY2008–10. Based on 

CAMD documentation, the low-NOX

burners were installed on Coronado 

Unit 1 on May 16, 2009, making it 

necessary for us to clearly distinguish 

between the pre-LNB and post-LNB 

periods of emission data for Coronado 

Unit 1. In our analysis, we have decided 

to make use of CAMD emission data 

corresponding to the post-LNB period 

extending from May 16, 2009 to 

December 31, 2010. We believe the use 

of this more recent baseline period 

represents the most realistic depiction 

of anticipated annual emissions, as it 

reflects operation of Coronado Unit 1 

with LNB and OFA. 

For Coronado Unit 2, we note that a 

consent decree between SRP and EPA 

requires the installation of SCR and 

compliance with an emission limit of 

0.080 lb/MMBtu (30-day rolling average) 

by June 1, 2014.109 Although we realize 

this SCR system has not yet been 

installed on Coronado Unit 2, this limit 

is federally enforceable and represents a 

realistic depiction of anticipated future 

emissions.110 As a result, we consider 

0.080 lb/MMBtu to be the baseline 

emission rate in our BART analysis and 

are examining only one control scenario 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
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111A discussion of our rationale for considering 

SCR at an emission rate of 0.05 lb/MMBtu can be 

found in Section VII.A.2 (Control Effectiveness) of 

this notice. 

112See Docket Item B–10, SRP Coronado BART 

Analysis, page 4–5 

113We note that there are multiple reasons why 

our annual emission estimates (and estimates of 

emission removal) are lower than AEPCO’s and 

ADEQ’s estimates. We are not implying that the use 

of capacity factor is the sole, or even dominant, 

reason for this difference, simply that the use of 

lower capacity factors will result in lower annual 

emission estimates. 

114We recognize that there are more aggressive 

approaches we could adopt that could justify the 

use of higher capacity factors, which would thereby 

lower the cost per ton of pollutant reduced. For 

example, instead of using historical data to develop 

a capacity factor value for each unit, we could use 

a single capacity factor value for each unit, one that 

represented a reasonable depiction of anticipated 

annual baseload operations. Alternately, we could 

also use a 100% capacity factor, or develop new 

capacity factors based on a longer 2001 to 2011 time 

frame. 

in our analysis for Unit 2, SCR at a more 

stringent emission rate of 0.050 lb/ 

MMBtu.111

ii. SCR Control Efficiency 

In determining the control efficiency 

of SCR in our BART analysis, we have 

relied upon an SCR level of performance 

of 0.05 lb/MMBtu, which is more 

stringent than the level of performance 

used by ADEQ in its SIP, or by SRP in 

its Coronado BART analysis. In the 

Coronado BART analysis submitted to 

ADEQ, SRP indicated an SCR level of 

performance of 0.08 lb/MMBtu, and 

noted that ‘‘If inlet NOX concentrations 

are less than 250 ppmvd, SCR can 

achieve NOX control efficiencies ranging 

only from 70 to 80 percent.’’ 112 SRP 

suggests that the 75 percent reduction 

(and associated 0.08 lb/MMBtu 

emission rate) it estimates for SCR is the 

result of low inlet NOX concentration, 

but does not provide specific 

information regarding inlet NOX

concentration at Coronado, or how a 75 

percent reduction was determined. Our 

control cost calculations for the SCR 

control option at Coronado Unit 1 are 

based upon the SCR control efficiency 

summarized below. This control 

efficiency reflects the emission 

reductions associated with controlling 

from an annual average baseline 

emission rate that represents LNB+OFA 

(as described previously) down to an 

SCR emission rate of 0.05 lb/MMBtu. 

TABLE 21—CORONADO UNIT 1: EPA’S SCR CONTROL EFFICIENCY

Unit No. 

Baseline 

emission rate 

(lb/MMBtu) 

SCR emission 

rate 

SCR control 

efficiency 

(percentage) 

Coronado 1 ...................................................................................................................... 0.303 0.05 83.5 

iii. Capacity Factor 

SRP did not calculate annual 

emission estimates for its control 

scenarios, in tons per year, in its BART 

analysis submitted to ADEQ. In 

developing its RH SIP, ADEQ estimated 

annual emission reductions based upon 

8,760 hours/year of operation (i.e., 100 

percent capacity factor). We have 

calculated annual emission estimates for 

our control scenarios using capacity 

factors developed over a CY2008–11 

time frame. The annual capacity factors 

we have used for each unit are 81 

percent (Coronado 1), and 89 percent 

(Coronado 2). We recognize that these 

capacity factors are lower than those 

used by ADEQ, and that by using these 

lower capacity factors, our estimates of 

total annual emissions (and 

correspondingly, the annual emission 

reductions) for each control scenario are 

lower than ADEQ’s estimates.113 Since 

cost-effectiveness ($/ton) is calculated 

by dividing annual control costs ($/year) 

by annual emission reductions (tons/ 

year), the use of emission reductions 

based on lower capacity factors will 

increase the cost per ton of pollutant 

reduced. 

We have elected to use the capacity 

factors specified above, as based on a 

2008 to 2011 time frame, in order to 

remain consistent with the time frame 

used to develop baseline annual 

emissions for Coronado and the other 

power plants that are the subject of 

today’s proposed action.114

iv. Summary and Conclusions 

Regarding Costs of Control 

A summary of our control cost 

estimates for the various control 

technology options considered for 

Coronado Units 1 and 2 is in Table 22. 

Detailed cost calculations, including our 

contractor’s report and cost calculation 

spreadsheets, are in our TSD. 

TABLE 22—CORONADO UNITS 1 AND 2: EPA’S CONTROL COST SUMMARY

Control option 

Emission 

factor 

(lb/MMBtu) 

Emission rate 

Emissions 

removed 

(tpy) 

Annual cost 

($/yr) 

Cost-effectiveness 

($/ton) 

(lb/hr) (tpy) Average Incremental 

(from previous) 

Coronado 1 

OFA ................................................ NA; LNB+OFA is the currently installed technology 

LNB+OFA (baseline) ...................... 0 .303 1,308 4,639 .................... .................... .................... ............................

SNCR+LNB+OFA .......................... 0 .21 915 3,248 1,392 3,825,556 2,749 ............................

SCR+LNB+OFA ............................. 0 .05 216 766 3,874 9,315,313 2,405 2,212 

Coronado 2 

SCR@0.08 lb/MMBtu .....................

(baseline) ....................................... 0 .08 319 1,242 .................... 1 8,721,636 .................... ............................

SCR@0.05 lb/MMBtu ..................... 0 .05 199 776 466 8,993,116 .................... 583 

1Annual cost for the baseline scenario is provided here only to allow calculation of the incremental cost associated with a control option of 

SCR@0.05 lb/MMBtu. 


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For Coronado 1, our calculations 

indicate that the SCR-based control 

option has an average cost-effectiveness 

value of $2,405/ton and an incremental 

cost-effectiveness of $2,212/ton, both of 

which we consider cost-effective. As 

described further below, our analysis for 

Coronado 2 relied upon SCR at an 

emission rate of 0.08 lb/MMBtu as a 

baseline scenario. As a result, the only 

control option we examined for 

Coronado 2 was an SCR-based option at 

a more stringent level of performance, 

0.05 lb/MMBtu. Our initial analysis 

indicates that the incremental costeffectiveness of such an option is $583/ 

ton, making it a control option that we 

would consider cost-effective. However, 

we received information from SRP 

indicating that design and construction 

of the SCR system for this unit are well 

under way. In its letter, SRP states that 

‘‘if SRP were required to abandon the 

current design, incur procurement 

losses, possibly remove foundations, 

and undertake new design and 

procurement, such steps would vastly 

increase the cost of the SCR retrofit.’’ 

Since these types of additional costs 

were not factored into our original 

analysis, the average and incremental 

cost-effectiveness of requiring Coronado 

Unit 2 to meet an emissions limit of 

0.050 lb/MMBtu may in fact be greater 

than indicated by our analysis. 

However, we intend to request further 

documentation in order to determine 

the extent of these costs and how they 

would affect our cost-effectiveness 

calculations. We will include all nonCBI material received in the docket for 

this action and will consider it as part 

of our final action. We are specifically 

interested in information from SRP 

concerning the number of layers of 

catalyst for the SCR at Unit 2, how they 

plan to manage replacement of the 

catalyst, and whether the catalyst could 

be installed and managed to allow Unit 

2 to meet a lower emission limit than 

0.08 lb/MMBtu. 

Thus, our initial analysis of this factor 

indicates that the costs of compliance 

(average or incremental) are not 

sufficiently large to warrant eliminating 

any of the control options from 

consideration. However, we note that, 

based on preliminary information 

received from SRP, the average and 

incremental costs of achieving an 

emission rate of 0.050 lb/MMBtu at Unit 

2 may be much greater than our initial 

analysis suggests. 

b. Visibility Improvement 

The overall modeling approach was 

described above; aspects of the 

modeling specific to Coronado are 

described here. LNB was installed on 

Unit 1 in mid-2009, and on Unit 2 in 

mid-2011. For Unit 1’s NOX emissions, 

the maximum daily emissions in EPA’s 

CAMD database for 2008 to 2010 was 

used; the maximum post-LNB 

installation emissions occurred in late 

2010. For unit 2 emissions, the consent 

decree-mandated NOX emission limit of 

0.08 lb/MMBtu was combined with the 

maximum heat rate from 2008–2010 

CAMD data, which occurred in late 

2008. Since this limit has a 30-day 

averaging time, daily emissions may be 

larger than the emissions EPA modeled; 

the emission and visibility benefit 

would also be larger. Thus, visibility 

benefits from control applied to the base 

case may actually be larger than 

presented here. The base case reflects 

LNB as the control in place on Unit 1, 

and SCR at 0.08 lb/MMBtu NOX on 

Unit 2. 

EPA evaluated SNCR applied to Unit 

1, and SCR at 0.05 lb/MMBtu applied to 

both Units 1 and 2. SCR was assumed 

to give a control effectiveness of 83.5 

percent for unit 1 (less than 90 percent 

due to the 0.05 lb/MMBtu NOX lower 

limit assumed for SCR). SCR at 0.05 lb/ 

MMBtu NOX was assumed to give a 

control effectiveness of 37.5 percent 

over the base case 0.08 lb/MMBtu. As 

mentioned above, the SCR simulation 

accounted for the increase in sulfuric 

acid emissions due to catalyst oxidation 

of SO2. However, the simulation with 

SNCR applied to unit 1 did not account 

for this effect. If this additional Unit 2 

sulfate were accounted for, it could 

make some background ammonia 

unavailable to form visibility-affecting 

particulate from Unit 1’s NOX

emissions, thus reducing the visibility 

impact and also the visibility benefit 

from SNCR. We expect this to have very 

little effect on the estimated SNCR 

visibility benefit, since it was computed 

relative to an alternative base case that 

likewise did not include the catalyst 

oxidation effect, but the visibility 

benefits from SNCR may thus be slightly 

less than reported here, weakening the 

case for SNCR. 

Sixteen Class I areas within 300 km of 

Coronado were modeled; they are in the 

states of Arizona, Colorado, and New 

Mexico. A 17th area, the Bosque del 

Apache Wilderness Area in New 

Mexico, was inadvertently omitted. 

Since it is in the same general direction 

from Coronado as the Gila Wilderness 

Area, but farther way, visibility impacts 

and control benefits at Bosque del 

Apache are likely to be lower than for 

Gila, so the maximum dv benefit would 

not be affected by this omission. 

However, the cumulative impacts and 

benefits would be higher than reported 

here since Bosque del Apache is omitted 

from the sum. The 98th percentile delta 

deciviews over all three years of data 

were computed for each area and 

emission scenario. 

Table 23 shows baseline visibility 

impacts and the visibility improvement 

when controls are applied; the various 

table entries are described above in the 

discussion of the comparable table for 

Apache. The area with the greatest dv 

improvement was the Gila Wilderness 

Area; there is an improvement of 0.3 dv 

from SNCR, 0.6 dv from SCR on unit 1, 

and 0.7 dv from SCR at 0.05 lb/MMBtu 

on both units. These improvements are 

smaller than for the other facilities 

because the benefit from SCR at 0.08 lb/ 

MMBtu on unit 2 is subsumed in the 

baseline. Any of these improvements 

would contribute to improved visibility, 

though SNCR on unit 2 only marginally 

so. SCR is the superior option for 

visibility, with the more stringent SCR 

at 0.05 lb/MMBtu on unit 2 giving a 

slightly greater benefit than when that 

limit is applied only to unit 1. The 

cumulative improvements 

corresponding to the three control 

scenarios are 1.3 dv, 2.8 dv, and 3.1 dv. 

Only the SCR scenarios give 

improvements exceeding 0.5 dv. The 

modeled degree of visibility 

improvements supports either SCR 

scenario as BART for Coronado. 

TABLE 23—CORONADO UNITS 1 AND 2: EPA’S VISIBILITY IMPROVEMENTS FROM NOX CONTROLS

Class I area 

Baseline 

impact 

(dv) 

Improvement 

from SNCR on 

unit 1 (dv) 

Improvement 

from SCR .05 

on unit 1 (dv) 

Improvement 

from SCR, 0.05 

lb/MMBtu (dv) 

Bandelier NM ............................................................................................. 0.37 0 .07 0 .19 0 .20 

Chiricahua NM ........................................................................................... 0.20 0 .03 0 .07 0 .08 

Chiricahua WA ........................................................................................... 0.21 0 .04 0 .08 0 .09 

Galiuro WA ................................................................................................ 0.20 0 .03 0 .08 0 .09 

Gila WA ...................................................................................................... 1.23 0 .33 0 .60 0 .66 


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TABLE 23—CORONADO UNITS 1 AND 2: EPA’S VISIBILITY IMPROVEMENTS FROM NOX CONTROLS—Continued 

Class I area 

Baseline 

impact 

(dv) 

Improvement 

from SNCR on 

unit 1 (dv) 

Improvement 

from SCR .05 

on unit 1 (dv) 

Improvement 

from SCR, 0.05 

lb/MMBtu (dv) 

Grand Canyon NP ..................................................................................... 0.24 0 .03 0 .10 0 .11 

Mazatzal WA .............................................................................................. 0.20 0 .03 0 .06 0 .07 

Mesa Verde NP ......................................................................................... 0.40 0 .10 0 .19 0 .20 

Mount Baldy WA ........................................................................................ 0.87 0 .16 0 .42 0 .44 

Petrified Forest NP .................................................................................... 1.22 0 .22 0 .47 0 .56 

Pine Mountain WA ..................................................................................... 0.14 0 .02 0 .04 0 .05 

Saguaro NP ............................................................................................... 0.12 0 .01 0 .03 0 .04 

San Pedro Parks WA ................................................................................ 0.54 0 .11 0 .28 0 .30 

Sierra Ancha WA ....................................................................................... 0.24 0 .04 0 .06 0 .07 

Superstition WA ......................................................................................... 0.21 0 .02 0 .06 0 .06 

Sycamore Canyon WA .............................................................................. 0.16 0 .02 0 .06 0 .06 

Cumulative dv ............................................................................................ 6.54 1 .25 2 .78 3 .07 

# areas >=0.5 ............................................................................................ 4 0 1 2 

$/max dv, millions ...................................................................................... ........................ $11 .9 $16 .2 $15 .0 

$/cumulative dv, millions ............................................................................ ........................ $3.1 $3 .5 $3 .2 

Note: Costs of implementing SCR at 0.08 lb/MMBtu on unit 2 are not included. 

c. EPA’s BART Determinations 

As noted above, we have considered 

the remaining useful life of the source 

by incorporating a 20-year amortization 

period into our control cost 

calculations. The presence of existing 

pollution control technology is reflected 

in the cost and visibility factors as a 

result of selection of the baseline period 

for cost calculations and visibility 

modeling. For Coronado Unit 1, a 

baseline period (May 2009 to December 

2010) was selected that reflects the 

currently existing pollution control 

technology (LNB with OFA). For 

Coronado Unit 2, a baseline of 0.080 lb/ 

MMBtu was selected to reflect the 

requirements of the consent decree 

decribed above. In addition, as noted 

above, we have received information 

from SRP indicating that the design and 

construction of SCR at Unit 2 have 

aleady progressed significantly. To the 

extent that we receive additional 

documentation establishing the status of 

this effort, we will take this information 

into consideration under the factors of 

‘‘costs of compliance’’ and ‘‘existing 

controls.’’ 

In examining energy and non-air 

quality impacts, we note certain 

potential impacts resulting from the use 

of ammonia injection associated with 

the SNCR and SCR control options, but 

do not consider these impacts sufficient 

enough to warrant eliminating any of 

the available control technologies. 

Our consideration of degree of 

visibility improvement focuses 

primarily on the improvement from base 

case impacts associated with each 

control option. While each of the 

available NOX control options achieves 

some degree of visibility improvement, 

we consider the improvement 

associated with the most stringent 

option, SCR with LNB and OFA, to be 

substantial. Our consideration of cost of 

compliance focuses primarily on the 

cost-effectiveness of each control 

option, as measured in cost per ton and 

incremental cost per ton of each control 

option. Despite the fact that the most 

stringent option, SCR with LNB and 

OFA, is the most expensive of the 

available control options, we consider it 

cost-effective on average basis as well as 

on an incremental basis when compared 

to the next most stringent option, SNCR 

with LNB and OFA. 

As a result, we consider the most 

stringent available control option, SCR 

with LNB and OFA, to be cost-effective 

and to result in substantial visibility 

improvement, and that the energy and 

non-air quality impacts are not 

sufficient to warrant eliminating it from 

consideration. Therefore, we propose to 

determine that NOX BART for Coronado 

Units 1 and 2 is SCR with LNB and 

OFA. At Unit1 we propose an emission 

limit for NOX of 0.050 lb/MMBtu, based 

on a rolling 30-boiler-operating-day 

average. 

At Unit 2, we propose an emission 

limit of 0.080 lb/MMBtu, which is 

consistent with the emission limit in the 

consent decree. We acknowledge that 

the emission limit of 0.080 lb/MMBtu 

established in the consent decree was 

not the result of a BART five-factor 

analysis, nor does the consent decree 

indicate that SCR at 0.080 lb/MMBtu 

represents BART. Nonetheless, given 

the compliance schedule established in 

the consent decree and the preliminary 

information received from SRP 

regarding the status of design and 

construction of the SCR system, it 

appears that achieving a 0.050 lb/ 

MMBtu emission rate may not be 

technically feasible. Even if it is 

feasible, achievement of this emission 

rate may not be cost-effective. Therefore, 

we are proposing an emission limit of 

0.080 lb/MMBtu as BART for NOX at 

Unit 2. However, if we do not receive 

sufficient documentation establishing 

that achievement of a more stringent 

limit is infeasible or not cost-effective, 

then we may determine that a more 

stringent limit for this unit is required 

in our final action. 

For Coronado Unit 2, we are 

proposing a compliance date of June 1, 

2014 for the NOX limit, consistent with 

the consent decree described above. 

Finally, at Coronado Unit 1, we are 

proposing to require compliance with 

the NOX limit within five years of final 

promulgation of this FIP consistent with 

the compliance times for the NOX limits 

at the other units. However, we are 

seeking comment on whether a shorter 

compliance schedule may be practicable 

for this unit. 

C. Enforceability Requirements 

In order to meet the requirements of 

the RHR and the CAA and to ensure that 

the BART limits are practically 

enforeceable, we propose to include the 

following elements in the FIP: 

1. Requirements for use of continuous 

emission monitoring systems (CEMS) 

(and associated quality assurance 

procedures) to determine compliance 

with NOX and SO2 limits. 

2. Use of 30-day rolling averaging 

period and definition of boiler operating 

day, consistent with the BART 

Guidelines. 

3. Requirements for annual 

performance stack tests and 

implementation of Compliance 

Assurance Monitoring (CAM) plan to 

establish compliance with PM emission 

limits. 


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115Available on regulations.gov, docket no. EPA– 

R06–OAR–2010–0846, pp. 70–72. See also 76 FR at 

52408–09. 

116 J. Edward Cichanowicz, Implementation 

Schedule for Selective Catalytic Reduction (SCR) 

and Flue Gas Desulfurization (FGD) Process 

Equipment (Oct. 10, 2010). 

117 76 FR at 52408–09. 

4. Recordkeeping and reporting 

requirements. 

5. Requirement to maintain and 

operate the unit including associated air 

pollution control equipment in a 

manner consistent with good air 

pollution control practices for 

minimizing emissions. 

The foregoing requirements would 

apply to all units. 

In addition, we are proposing specific 

compliance deadlines for each of 

ADEQ’s BART emissions limits that we 

are proposing to approve. In most 

instances, the control technologies 

required to meet these limits have 

already been installed. See Table 3. 

Therefore, we are proposing to require 

compliance with the applicable 

emissions limits for PM and SO2 within 

180 days of final promulgation of this 

FIP, except that at Cholla Unit 2, we 

propose to require compliance with the 

PM limit by January 1, 2015, consistent 

with ADEQ’s BART determination. 

Regarding NOX, we propose to allow 

up to five years from final promulgation 

of this FIP for each unit subject to an 

emission limit consistent with SCR, 

with the exception of Coronado Unit 2. 

This proposal is based on the results of 

two analyses of SCR installation times, 

as summarized in EPA Region 6’s 

Complete Response to Comments for 

NM Regional Haze/Visibility Transport 

FIP.115 An analysis performed by EPA 

Region 6, based on a review of a number 

of sources, found that the design and 

installation of SCR took between 18 and 

69 months. A separate analysis 

performed for the Utility Air Regulatory 

Group (UARG) found that it took 28 to 

62 months to design and install the 14 

SCRs in its sample.116 In the case of the 

BART FIP for San Juan Generating 

Station, EPA Region 6 initially proposed 

to allow a three-year compliance time 

frame for design and installation of SCR, 

but ultimately allowed for a five-year 

compliance schedule.117 We also note 

that SCR installations often trigger 

Prevention of Significant of 

Deterioration permitting requirements 

because they constitute physical 

changes to an existing emission unit 

that may result in increased emissions 

of sulfuric acid mist. Therefore, we are 

proposing a five-year compliance time 

frame, which would provide adequate 

time for SCR design and installation 

based on the high-end of the range of 

dates in the analyses cited above. 

However, we are seeking comment on 

whether these compliance dates are 

reasonable and consistent with the 

requirement of the CAA and the RHR 

that BART be installed ‘‘as 

expeditiously as practicable.’’ We are 

specifically seeking comment on 

whether the outage schedule for any of 

these units may warrant a shorter 

compliance schedule (up to five years). 

If we receive information during the 

comment period that establishes that a 

shorter compliance timeframe is 

appropriate for one or more of these 

units, we may finalize a different 

compliance date. 

VIII. Summary of EPA’s Proposed 

Action 

Based on the available control 

technologies and the five factors 

discussed in more detail below, EPA is 

proposing to require these facilities to 

meet NOX, PM10 and SO2 emission 

limits as listed in Table 24. With the 

exception of Apache Unit 1, the NOX

emission limits in Table 24 are 

proposed as part of EPA’s FIP, based on 

the five factor analyses summarized in 

Section VII. The PM10 and SO2 emission 

limits in Table 24 are taken from 

ADEQ’s BART determinations for these 

facilities, proposed for EPA approval in 

this action. EPA is seeking comment on 

alternative PM10 and SO2 emissions 

limits for Apache Generating Station 

Units 2 and 3; Cholla Power Plant Units 

2, 3 and 4; and Coronado Units 1 and 

2 as described in Section VI.B. We are 

also seeking comment on whether a test 

method other than EPA Method 201/202 

should be allowed or required for 

establishing compliance with the PM10

limits that we are proposing to approve. 

Finally, we are proposing compliance 

dates and specific requirements for 

monitoring, recordkeeping, reporting 

and equipment operation and 

maintenance for all of the units covered 

by this action. Our proposed 

compliance dates are summarized in 

Table 25. We are seeking comment on 

whether these compliance dates are 

reasonable and consistent with the 

requirement of the CAA and the RHR 

that BART be installed ‘‘as 

expeditiously as practicable.’’ We are 

also taking comment on whether it 

would be technically feasible and costeffective for Coronado Unit 2 to meet an 

emissions limit of 0.050 lb/MMBtu for 

NOX. 

EPA takes very seriously a decision to 

disapprove a state plan. In this instance, 

we believe that Arizona’s SIP meets the 

CAA requirements with respect to its 

SO2 and PM10 limits, but the NOX BART 

determinations for the coal-fired units 

are neither consistent with the 

requirements of the Act nor with BART 

decisions that other states have made. 

As a result, EPA considers that this 

proposed disapproval is the only path 

that is consistent with the Act at this 

time. 

TABLE 24—SUMMARY OF BART EMISSION LIMITS

Unit 

Emission limitation (lb/MMBtu) 

(rolling 30-boiler-operating-day average) 

NOX PM10 SO2

Apache Generating Station Unit 1 ................................................................................... 0.056 0.0075 0.00064 

Apache Generating Station Unit 2 ................................................................................... 0.050 0.03 0.15 

Apache Generating Station Unit 3 ................................................................................... 0.050 0.03 0.15 

Cholla Power Plant Unit 2 ............................................................................................... 0.050 0.015 0.15 

Cholla Power Plant Unit 3 ............................................................................................... 0.050 0.015 0.15 

Cholla Power Plant Unit 4 ............................................................................................... 0.050 0.015 0.15 

Coronado Generating Station Unit 1 ............................................................................... 0.050 0.03 0.08 

Coronado Generating Station Unit 2 ............................................................................... 0.080 0.03 0.08 


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TABLE 25—SUMMARY OF BART COMPLIANCE DATES

Unit 

Compliance date 

NOX PM10 SO2

Apache Generating Station Unit 1 ...................................................................................... Five years ......... 180 days ........... 180 days. 

Apache Generating Station Unit 2 ...................................................................................... Five years ......... 180 days ........... 180 days. 

Apache Generating Station Unit 3 ...................................................................................... Five years ......... 180 days ........... 180 days. 

Cholla Power Plant Unit 2 .................................................................................................. Five years ......... January 1, 2015 180 days. 

Cholla Power Plant Unit 3 .................................................................................................. Five years ......... 180 days ........... 180 days. 

Cholla Power Plant Unit 4 .................................................................................................. Five years ......... 180 days ........... 180 days. 

Coronado Generating Station Unit 1 .................................................................................. Five years ......... 180 days ........... 180 days. 

Coronado Generating Station Unit 2 .................................................................................. June 1, 2014 .... 180 days ........... 180 days. 

TABLE 26—SUMMARY OF ARIZONA’S PROPOSED BART EMISSION LIMITS

Unit 

Emission limitation (lb/MMBtu) 

(rolling 30-boiler-operating-day average) 

NOX PM10 SO2

Apache Generating Station Unit 1 ................................................................................... 0.056 0.0075 0.00064 

Apache Generating Station Unit 2 ................................................................................... n/a 0.03 0.15 

Apache Generating Station Unit 3 ................................................................................... n/a 0.03 0.15 

Cholla Power Plant Unit 2 ............................................................................................... n/a 0.015 0.15 

Cholla Power Plant Unit 3 ............................................................................................... n/a 0.015 0.15 

Cholla Power Plant Unit 4 ............................................................................................... n/a 0.015 0.15 

Coronado Generating Station Unit 1 ............................................................................... n/a 0.03 0.08 

Coronado Generating Station Unit 2 ............................................................................... n/a 0.03 0.08 

TABLE 27—SUMMARY OF EPA’S PROPOSED FIP BART EMISSION LIMITS

Unit 

Emission limitation (lb/MMBtu) 

(rolling 30-boiler-operating-day average) 

NOX PM10 SO2

Apache Generating Station Unit 1 ................................................................................... n/a n/a n/a 

Apache Generating Station Unit 2 ................................................................................... 0.050 n/a n/a 

Apache Generating Station Unit 3 ................................................................................... 0.050 n/a n/a 

Cholla Power Plant Unit 2 ............................................................................................... 0.050 n/a n/a 

Cholla Power Plant Unit 3 ............................................................................................... 0.050 n/a n/a 

Cholla Power Plant Unit 4 ............................................................................................... 0.050 n/a n/a 

Coronado Generating Station Unit 1 ............................................................................... 0.050 n/a n/a 

Coronado Generating Station Unit 2 ............................................................................... 0.080 n/a n/a 

IX. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review 

This proposed action is not a 

‘‘significant regulatory action’’ under 

the terms of Executive Order 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). As 

discussed in detail in section C below, 

the proposed FIP applies to only three 

facilities. It is therefore not a rule of 

general applicability. 

B. Paperwork Reduction Act 

This proposed action does not impose 

an information collection burden under 

the provisions of the Paperwork 

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

Under the Paperwork Reduction Act, a 

‘‘collection of information’’ is defined as 

a requirement for ‘‘answers to * * * 

identical reporting or recordkeeping 

requirements imposed on ten or more 

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

Because the proposed FIP applies to just 

three facilities, the Paperwork 

Reduction Act does not apply. See 5 

CFR 1320(c). Burden means the total 

time, effort, or financial resources 

expended by persons to generate, 

maintain, retain, or disclose or provide 

information to or for a Federal agency. 

This includes the time needed to review 

instructions; develop, acquire, install, 

and utilize technology and systems for 

the purposes of collecting, validating, 

and verifying information, processing 

and maintaining information, and 

disclosing and providing information; 

adjust the existing ways to comply with 

any previously applicable instructions 

and requirements; train personnel to be 

able to respond to a collection of 

information; search data sources; 

complete and review the collection of 

information; and transmit or otherwise 

disclose the information. An agency 

may not conduct or sponsor, and a 

person is not required to respond to a 

collection of information unless it 

displays a currently valid Office of 

Management and Budget (OMB) control 

number. The OMB control numbers for 

our regulations in 40 CFR are listed in 

40 CFR part 9. 

C. Regulatory Flexibility Act 

The Regulatory Flexibility Act (RFA) 

generally requires an agency to prepare 

a regulatory flexibility analysis of any 

rule subject to notice and comment 

rulemaking requirements under the 

Administrative Procedure Act or any 

other statute unless the agency certifies 

that the rule will not have a significant 

economic impact on a substantial 


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118See Docket Item A–22 Final Guidance for 

EPA Rulewriters: Regulatory Flexibility Act as 

Amended by the Small Business and Regulatory 

Enforcement Fairness Act, November 2006 at 3. 119See Docket Item H–1 Arizona Electric Power 

Cooperative, Inc. Annual Report Electric for Year 

Ending December 31, 2011 submitted to Arizona 

Corporation Commission Utilities Division, 

available at http://www.azcc.gov/Divisions/Utilities/ 

Annual%20Reports/2011/Electric/ 

Arizona_Electric_Power_Cooperative_Inc.pdf. 

number of small entities. Small entities 

include small businesses, small 

organizations, and small governmental 

jurisdictions. For purposes of assessing 

the impacts of today’s proposed rule on 

small entities, small entity is defined as: 

(1) A small business as defined by the 

Small Business Administration’s (SBA) 

regulations at 13 CFR 121.201; (2) a 

small governmental jurisdiction that is a 

government of a city, county, town, 

school district or special district with a 

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

a small organization that is any not-for 

profit enterprise which is independently 

owned and operated and is not 

dominant in its field. Firms primarily 

engaged in the generation, transmission, 

and/or distribution of electric energy for 

sale are small if, including affiliates, the 

total electric output for the preceding 

fiscal year did not exceed 4 million 

megawatt hours. AEPCO sold under 3 

million megawatt hours in 2011. APS 

and SRP are not small entities. After 

considering the economic impacts of 

this proposed action on small entities, I 

certify that this proposed action will not 

have a significant economic impact on 

a substantial number of small entities. 

The FIP for the three Arizona facilities 

being proposed today does not impose 

new requirements on a substantial 

number of small entities. The proposed 

partial approval of the SIP, if finalized, 

merely approves state law as meeting 

Federal requirements and imposes no 

additional requirements beyond those 

imposed by state law. See Mid-Tex 

Electric Cooperative, Inc. v. FERC, 773 

F.2d 327 (DC Cir. 1985). Although a 

regulatory flexibility analysis as 

specified by the RFA is not required 

when a rule has some impact on one 

small entity, EPA policy is to assess the 

direct adverse impact of every rule on 

small entities and minimize any adverse 

impact to the extent feasible, regardless 

of the magnitude of the impact or 

number of small entities affected.118

Using easily available public 

information,119 EPA estimates that the 

annualized cost of requiring SCR in 

Units 1 and 2 would likely be in the 

range of 3 percent of AEPCO’s assets 

and between 6 and 7 percent of 

AEPCO’s annual sales. EPA requested 

information from AEPCO on the 

economics of operating Apache 

Generating Station and what impact the 

installation of SCR may have on the 

economics of operating Apache 

Generating Station. 

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 1 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 

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. 

Under Title II of UMRA, EPA has 

determined that this proposed rule does 

not contain a Federal mandate that may 

result in expenditures that exceed the 

inflation-adjusted UMRA threshold of 

$100 million by State, local, or Tribal 

governments or the private sector in any 

1 year. In addition, this proposed rule 

does not contain a significant Federal 

intergovernmental mandate as described 

by section 203 of UMRA nor does it 

contain any regulatory requirements 

that might significantly or uniquely 

affect small governments. 

E. Executive Order 13132: Federalism 

Federalism (64 FR 43255, August 10, 

1999) revokes and replaces Executive 

Orders 12612 (Federalism) and 12875 

(Enhancing the Intergovernmental 

Partnership). Executive Order 13132 

requires EPA to develop an accountable 

process to ensure ‘‘meaningful and 

timely input by State and local officials 

in the development of regulatory 

policies that have federalism 

implications.’’ ‘‘Policies that have 

federalism implications’’ is defined in 

the Executive Order to include 

regulations that have ‘‘substantial direct 

effects on the States, on the relationship 

between the national government and 

the States, or on the distribution of 

power and responsibilities among the 

various levels of government.’’ Under 

Executive Order 13132, EPA may not 

issue a regulation that has federalism 

implications, that imposes substantial 

direct compliance costs, and that is not 

required by statute, unless the Federal 

government provides the funds 

necessary to pay the direct compliance 

costs incurred by State and local 

governments, or EPA consults with 

State and local officials early in the 

process of developing the proposed 

regulation. EPA also may not issue a 

regulation that has federalism 

implications and that preempts State 

law unless the Agency consults with 

State and local officials early in the 

process of developing the proposed 

regulation. 

This rule will not have substantial 

direct effects on the States, on the 

relationship between the national 

government and the States, or on the 

distribution of power and 

responsibilities among the various 

levels of government, as specified in 

Executive Order 13132, because it 

addresses the State not fully meeting its 

obligation to prohibit emissions from 

interfering with other states measures to 

protect visibility established in the 

CAA. Thus, Executive Order 13132 does 

not apply to this action. In the spirit of 

Executive Order 13132, and consistent 

with EPA policy to promote 

communications between EPA and State 

and local governments, EPA specifically 

solicits comment on this proposed rule 

from State and local officials. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

Executive Order 13175, entitled 

Consultation and Coordination With 

Indian Tribal Governments (65 FR 

67249, November 9, 2000), requires EPA 


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to develop an accountable process to 

ensure ‘‘meaningful and timely input by 

tribal officials in the development of 

regulatory policies that have tribal 

implications.’’ This proposed rule does 

not have tribal implications, as specified 

in Executive Order 13175. It will not 

have substantial direct effects on tribal 

governments. Thus, Executive Order 

13175 does not apply to this rule. EPA 

specifically solicits additional comment 

on this proposed rule from tribal 

officials. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks (62 FR 

19885,April 23, 1997), applies to any 

rule that: (1) Is determined to be 

economically significant as defined 

under Executive Order 12866; and (2) 

concerns an environmental health or 

safety risk that we have reason to 

believe may have a disproportionate 

effect on children. 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 

EO 13045 because it implements 

specific standards established by 

Congress in statutes. However, to the 

extent this proposed rule will limit 

emissions of NOX, SO2, and PM10, the 

rule will have a beneficial effect on 

children’s health by reducing air 

pollution. 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This action is not subject to Executive 

Order 13211 (66 FR 28355 (May 22, 

2001)), because it is not a significant 

regulatory action under Executive Order 

12866. 

I. National Technology Transfer and 

Advancement Act 

Section 12 of the National Technology 

Transfer and Advancement Act 

(NTTAA) of 1995 requires Federal 

agencies to evaluate existing technical 

standards when developing a new 

regulation. To comply with NTTAA, 

EPA must consider and use ‘‘voluntary 

consensus standards’’ (VCS) if available 

and applicable when developing 

programs and policies unless doing so 

would be inconsistent with applicable 

law or otherwise impractical. The EPA 

believes that VCS are inapplicable to 

this action. Today’s action does not 

require the public to perform activities 

conducive to the use of VCS. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order 12898 (59 FR 7629, 

February 16, 1994), establishes federal 

executive policy on environmental 

justice. Its main provision directs 

federal agencies, to the greatest extent 

practicable and permitted by law, to 

make environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority 

populations and low-income 

populations in the United States. 

We have determined that this 

proposed rule, if finalized, will not have 

disproportionately high and adverse 

human health or environmental effects 

on minority or low-income populations 

because it increases the level of 

environmental protection for all affected 

populations without having any 

disproportionately high and adverse 

human health or environmental effects 

on any population, including any 

minority or low-income population. 

This proposed federal rule limits 

emissions of NOX, from three facilities 

in Arizona. The partial approval of the 

SIP for SO2, and PM10, if finalized, 

merely approves state law as meeting 

Federal requirements and imposes no 

additional requirements beyond those 

imposed by state law. 

List of Subjects in 40 CFR Part 52 

Environmental protection, Air 

pollution control, Incorporation by 

reference, Intergovernmental relations, 

Nitrogen dioxide, Particulate matter, 

Reporting and recordkeeping 

requirements, Sulfur dioxide, Visibility, 

Volatile organic compounds. 

Dated: July 2, 2012. 

Jared Blumenfeld, 

Regional Administrator, Region 9. 

Part 52, chapter I, title 40 of the Code 

of Federal Regulations is proposed to be 

amended as follows: 

PART 52—[AMENDED] 

1. The authority citation for Part 52 

continues to read as follows: 

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

Subpart D—Arizona 

2. Add paragraph (e) to § 52.145, to 

read as follows: 

§ 52.145 Visibility Protection. 

* * * * * 

(e) Federal implementation plan for 

regional haze. 

(1) Applicability. This paragraph (e) 

applies to each owner/operator of the 

following coal-fired electricity 

generating units (EGUs) in the state of 

Arizona: Apache Generating Station, 

Units 2 and 3; Cholla Power Plant, Units 

2, 3, and 4; and Coronado Generating 

Station, Units 1 and 2. This paragraph 

(e) also applies to each owner/operator 

of the following natural gas-fired EGU in 

the state of Arizona: Apache Generating 

Station Unit 1. The provisions of this 

paragraph (e) are severable, and if any 

provision of this paragraph (e), or the 

application of any provision of this 

paragraph (e) to any owner/operator or 

circumstance, is held invalid, the 

application of such provision to other 

owner/operators and other 

circumstances, and the remainder of 

this paragraph (e), shall not be affected 

thereby. 

(2) Definitions. Terms not defined 

below shall have the meaning given to 

them in the Clean Air Act or EPA’s 

regulations implementing the Clean Air 

Act. For purposes of this paragraph (e): 

ADEQ means the Arizona Department 

of Environmental Quality. 

Boiler operating day means a 24-hour 

period between 12 midnight and the 

following midnight during which any 

fuel is combusted at any time in the 

steam-generating unit. It is not 

necessary for fuel to be combusted the 

entire 24-hour period. 

Coal-fired unit means any of the EGUs 

identified in paragraph (e)(1) of this 

section, except for Apache Generating 

Station, Unit 1. 

Continuous emission monitoring 

system or CEMS means the equipment 

required by 40 CFR part 75 and this 

paragraph (e). 

Emissions limitation or emissions 

limit means the Federal emissions 

limitation required by this paragraph (e) 

and the applicable PM10 and SO2

emissions limits for Apache Generating 

Station, Cholla Power Plant, and 

Coronada Generating Station submitted 

to EPA as part of the Arizona Regional 

Haze State Implementation Plan in a 

letter dated February 28, 2011 and 

approved into the Arizona state 

implementation plan on [INSERT DATE 

OF PUBLICATION OF FINAL ACTION 

IN THE Federal Register]. 

lb means pound(s). 

NOX means nitrogen oxides expressed 

as nitrogen dioxide (NO2). 

Owner(s)/operator(s) means any 

person(s) who own(s) or who operate(s), 

control(s), or supervise(s) one more of 


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Federal Register / Vol. 77, No. 140 / Friday, July 20, 2012 / Proposed Rules 42869 

the units identified in paragraph (e)(1) 

of this section. 

MMBtu means million British thermal 

unit(s). 

Operating hour means any hour that 

fossil fuel is fired in the unit. 

Pipeline natural gas means a naturally 

occurring fluid mixture of hydrocarbons 

(e.g., methane, ethane, or propane) 

produced in geological formations 

beneath the Earth’s surface that 

maintains a gaseous state at standard 

atmospheric temperature and pressure 

under ordinary conditions, and which is 

provided by a supplier through a 

pipeline. Pipeline natural gas contains 

0.5 grains or less of total sulfur per 100 

standard cubic feet. Additionally, 

pipeline natural gas must either be 

composed of at least 70 percent methane 

by volume or have a gross calorific 

value between 950 and 1100 Btu per 

standard cubic foot. 

PM10 means filterable total particulate 

matter less than 10 microns and the 

condensable material in the impingers 

as measured by Methods 201A and 202. 

Regional Administrator means the 

Regional Administrator of EPA Region 

IX or his/her authorized representative. 

SO2 means sulfur dioxide. 

Unit means any of the EGUs identified 

in paragraph (e)(1) of this section. 

(3) Emission Limitations. The owner/ 

operator of each unit subject to this 

paragraph (e) shall not emit or cause to 

be emitted NOX in excess of the 

following limitations, in pounds per 

million British thermal units (lb/ 

MMBtu). Each emission limit shall be 

based on a rolling 30-boiler-operatingday average, unless otherwise indicated 

in specific paragraphs. Apache 

Generating Station Unit 1 shall operate 

only on pipeline natural gas. 

Unit 

Federal emission limit 

NOX

Apache Generating Station Unit 1 ....................................................................................................................................................... 0 .056 

Apache Generating Station Unit 2 ....................................................................................................................................................... 0 .050 

Apache Generating Station Unit 3 ....................................................................................................................................................... 0 .050 

Cholla Power Plant Unit 2 ................................................................................................................................................................... 0 .050 

Cholla Power Plant Unit 3 ................................................................................................................................................................... 0 .050 

Cholla Power Plant Unit 4 ................................................................................................................................................................... 0 .050 

Coronado Generating Station Unit 1 ................................................................................................................................................... 0 .050 

Coronado Generating Station Unit 2 ................................................................................................................................................... 0 .08 

(4) Compliance Dates. 

i. The owners/operators of each unit 

subject to paragraph (e) shall comply 

with the emissions limitations and other 

requirements of this paragraph (e) as 

expeditiously as practicable, but in no 

event later than the following dates: 

Unit 

Compliance date 

NOX PM10 SO2

Apache Generating Station, Unit 1 [INSERT DATE FIVE YEARS 

AFTER DATE OF PUBLICATION OF FINAL ACTION IN 

THE Federal Register].

[INSERT DATE 180 DAYS 

AFTER DATE OF PUBLICATION OF FINAL ACTION IN 

THE Federal Register].

[INSERT DATE 180 DAYS 

AFTER DATE OF PUBLICATION OF FINAL ACTION IN 

THE Federal Register] 

Apache Generating Station, Unit 2 [INSERT DATE FIVE YEARS 

AFTER DATE OF PUBLICATION OF FINAL ACTION IN 

THE Federal Register].

[INSERT DATE 180 DAYS 

AFTER DATE OF PUBLICATION OF FINAL ACTION IN 

THE Federal Register].

[INSERT DATE 180 DAYS 

AFTER DATE OF PUBLICATION OF FINAL ACTION IN 

THE Federal Register] 

Apache Generating Station, Unit 3 [INSERT DATE FIVE YEARS 

AFTER DATE OF PUBLICATION OF FINAL ACTION IN 

THE Federal Register].

[INSERT DATE 180 DAYS 

AFTER DATE OF PUBLICATION OF FINAL ACTION IN 

THE Federal Register].

[INSERT DATE 180 DAYS 

AFTER DATE OF PUBLICATION OF FINAL ACTION IN 

THE Federal Register] 

Cholla Power Plant, Unit 2 ............ [INSERT DATE FIVE YEARS 

AFTER DATE OF PUBLICATION OF FINAL ACTION IN 

THE Federal Register].

January 1, 2015 ............................ [INSERT DATE 180 DAYS 

AFTER DATE OF PUBLICATION OF FINAL ACTION IN 

THE Federal Register] 

Cholla Power Plant, Unit 3 ............ [INSERT DATE FIVE YEARS 

AFTER DATE OF PUBLICATION IN THE Federal Register].

[INSERT DATE 180 DAYS 

AFTER DATE OF PUBLICATION OF FINAL ACTION IN 

THE Federal Register].

[INSERT DATE 180 DAYS 

AFTER DATE OF PUBLICATION OF FINAL ACTION IN 

THE Federal Register] 

Cholla Power Plant, Unit 4 ............ [INSERT DATE FIVE YEARS 

AFTER DATE OF PUBLICATION IN THE Federal Register].

[INSERT DATE 180 DAYS 

AFTER DATE OF PUBLICATION IN THE Federal Register].

[INSERT DATE 180 DAYS 

AFTER DATE OF PUBLICATION IN THE Federal Register] 

Coronado Generating Station, Unit 

1.

[INSERT DATE FIVE YEARS 

AFTER DATE OF PUBLICATION OF FINAL ACTION IN 

THE Federal Register].

[INSERT DATE 180 DAYS 

AFTER DATE OF PUBLICATION OF FINAL ACTION IN 

THE Federal Register].

[INSERT DATE 180 DAYS 

AFTER DATE OF PUBLICATION OF FINAL ACTION IN 

THE Federal Register] 

Coronado Generating Station, Unit 

2.

June 1, 2014 ................................. [INSERT DATE 180 DAYS 

AFTER DATE OF PUBLICATION OF FINAL ACTION IN 

THE Federal Register].

[INSERT DATE 180 DAYS 

AFTER DATE OF PUBLICATION OF FINAL ACTION IN 

THE Federal Register] 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
42870 Federal Register / Vol. 77, No. 140 / Friday, July 20, 2012 / Proposed Rules 

(5) Compliance determinations for 

NOX and SO2. 

i. Continuous emission monitoring 

system. 

A. At all times after the compliance 

date specified in paragraph (e)(4) of this 

section, the owner/operator of each 

coal-fired unit shall maintain, calibrate, 

and operate a CEMS, in full compliance 

with the requirements found at 40 CFR 

part 75, to accurately measure SO2, 

NOX, diluent, and stack gas volumetric 

flow rate from each unit. Apache Unit 

1 NOX and diluent CEMs shall be 

operated to meet the requirements of 

Part 75. Valid data means data recorded 

when the CEMS is not out-of-control as 

defined by Part 75. All valid CEMS 

hourly data shall be used to determine 

compliance with the emission 

limitations for NOX and SO2 in 

paragraph (e)(3) of this section for each 

unit. When the CEMS is out-of-control 

as defined by Part 75, that CEMs data 

shall be treated as missing data and not 

used to calculate the emission average. 

B. The owner/operator of each unit 

shall comply with the quality assurance 

procedures for CEMS found in 40 CFR 

part 75. In addition to these Part 75 

requirements, relative accuracy test 

audits shall be performed for both the 

NOX pounds per hour measurement and 

the heat input measurement. These shall 

have relative accuracies of less than 

20%. This testing shall be evaluated 

each time the CEMS undergo relative 

accuracy testing. Heat input for Apache 

Unit 1 shall be measured in accordance 

with Part 75 fuel gas measurement 

procedures found in Part 75 Appendix 

D. 

ii. Compliance determinations for 

NOX. 

A. The 30-day rolling average NOX

emission rate for each unit shall be 

calculated in accordance with the 

following procedure: First, sum the total 

pounds of NOX emitted from the unit 

during the current boiler operating day 

and the previous twenty-nine (29) 

boiler-operating days; second, sum the 

total heat input to the unit in MMBtu 

during the current boiler operating day 

and the previous twenty-nine (29) 

boiler-operating days; and third, divide 

the total number of pounds of NOX

emitted during the thirty (30) boileroperating days by the total heat input 

during the thirty (30) boiler-operating 

days. A new 30-day rolling average NOX

emission rate shall be calculated for 

each new boiler operating day. Each 

30-day rolling average NOX emission 

rate shall include all emissions that 

occur during all periods within any 

boiler operating day, including 

emissions from startup, shutdown, and 

malfunction. 

B. If a valid NOX pounds per hour or 

heat input is not available for any hour 

for a unit, that heat input and NOX

pounds per hour shall not be used in the 

calculation of the 30-day rolling 

average. Each unit must obtain valid 

hourly data for at least 90% of the 

operating hours for each calendar 

quarter. 

iii. Compliance determinations for 

SO2. 

A. The 30-day rolling average SO2

emission rate for each coal-fired unit 

shall be calculated in accordance with 

the following procedure: First, sum the 

total pounds of SO2 emitted from the 

unit during the current boiler operating 

day and the previous twenty-nine (29) 

boiler-operating days; second, sum the 

total heat input to the unit in MMBtu 

during the current boiler-operating day 

and the previous twenty-nine (29) 

boiler-operating day; and third, divide 

the total number of pounds of SO2

emitted during the thirty (30) boileroperating days by the total heat input 

during the thirty (30) boiler-operating 

days. A new 30-day rolling average SO2

emission rate shall be calculated for 

each new boiler operating day. Each 

30-day rolling average SO2 emission rate 

shall include all emissions that occur 

during all periods within any boileroperating day, including emissions from 

startup, shutdown, and malfunction. 

B. If a valid SO2 pounds per hour or 

heat input is not available for any hour 

for a unit, that heat input and SO2

pounds per hour shall not be used in the 

calculation of the 30-day rolling 

average. Each unit must obtain valid 

hourly data for at least 90% of the 

operating hours for each calendar 

quarter. 

(6) Compliance Determinations for 

Particulate Matter. Compliance with the 

particulate matter emission limitation 

for each coal-fired unit shall be 

determined from annual performance 

stack tests. Within sixty (60) days of the 

compliance deadline specified in 

paragraph (e)(4) of this section, and on 

at least an annual basis thereafter, the 

owner/operator of each unit shall 

conduct a stack test on each unit to 

measure PM–10 using 40 CFR part 51, 

appendix M, Method 201A/202. A test 

protocol shall be submitted to EPA a 

minimum of 30 days prior to the 

scheduled testing. Each test shall 

consist of three runs, with each run at 

least 120 minutes in duration and each 

run collecting a minimum sample of 60 

dry standard cubic feet. Results shall be 

reported in lb/MMBtu using the 

calculation in 40 CFR part 60 appendix 

A Method 19. In addition to annual 

stack tests, owner/operator shall 

monitor particulate emissions for 

compliance with the emission 

limitations in accordance with the 

applicable Compliance Assurance 

Monitoring (CAM) plan developed and 

approved in accordance with 40 CFR 

part 64. The averaging time for any 

other demonstration of the PM–10 

compliance or exceedance shall be 

based on a 6-hour average. 

(7) Recordkeeping. The owner or 

operator of each unit shall maintain the 

following records for at least five years: 

a. All CEMS data, including the date, 

place, and time of sampling or 

measurement; parameters sampled or 

measured; and results. 

b. Daily 30-day rolling emission rates 

for NOX and SO2 for each unit, 

calculated in accordance with paragraph 

(e)(5) of this section. 

c. Records of quality assurance and 

quality control activities for emissions 

measuring systems including, but not 

limited to, any records required by 40 

CFR part 75. 

d. Records of the relative accuracy test 

for NOX and SO2 lb/hr measurement 

and hourly heat input. 

e. Records of all major maintenance 

activities conducted on emission units, 

air pollution control equipment, and 

CEMS. 

f. Any other records required by 

40 CFR part 75. 

(8) Reporting. All reports and 

notifications under this paragraph (e) 

shall be submitted to the Director of 

Enforcement Division, U.S. EPA Region 

IX, at 75 Hawthorne Street, San 

Francisco, CA 94105. 

a. The owner/operator shall notify 

EPA within two weeks after completion 

of installation of combustion controls or 

Selective Catalytic Reactors on any of 

the units subject to this section. 

b. Within 30 days after the applicable 

compliance date(s) in paragraph (e)(4) of 

this section and within 30 days of the 

end of each calendar quarter thereafter, 

the owner/operator of each unit shall 

submit a report that lists the daily 30- 

day rolling emission rates for NOX and 

SO2 for each unit, calculated in 

accordance with paragraph (e)(5) of this 

section. Included in this report shall be 

the results of any relative accuracy test 

audit performed during the calendar 

quarter. 

(9) Enforcement. 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 


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Federal Register / Vol. 77, No. 140 / Friday, July 20, 2012 / Proposed Rules 42871 

of any standard or applicable emission 

limit in the plan. 

(10) 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. 

(11) Affirmative Defense for 

Malfunctions. The following regulations 

are incorporated by reference and made 

part of this federal implementation plan: 

Rules R18–2–310 and R18–2–310.01, 

approved into the Arizona SIP at 40 CFR 

52.120(c)(97)(i)(A). 

[FR Doc. 2012–17659 Filed 7–19–12; 8:45 am] 

BILLING CODE 6560–50–P 


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