The EPA Regional Administrator, Jared Blumenfeld, signed the following proposed rule on July

2, 2012, and EPA is submitting it for publication in the Federal Register (FR). While we have 

taken steps to ensure the accuracy of this Internet version of the rule, it is not the official version 

of the rule for purposes of public comment. Please refer to the official version in a forthcoming 

FR publication, which will appear on the Government Printing Office's website 

(http://fdsys.gpo.gov/fdsys/search/home.action) and on Regulations.gov 

(http://www.regulations.gov) in Docket No. EPA-R09-OAR-2012-0021. Once the official 

version of this document is published in the FR, we will remove this version from the Internet 

and replace it with a link to the official version.

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 51

[EPA-R09-OAR-2012-0021, FRL- ]

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 
2

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
3

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
4

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
5

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
6

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.

 

1 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.”
7

(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.

(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.
8

(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.
9

(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 
10

(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.

 E-mail: 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 
11

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 e-mail. 

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 e-mail comment directly to EPA, without going through 

http://www.regulations.gov, we will include your e-mail 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 e-mail. 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.
12

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.

 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 pm

Public Hearing: 6:00-8:00 pm

Location: Sandra Day O’Connor Federal Courthouse (atrium and juror room)

401 W. Washington Street
13

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 
14

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.
15

 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

III. Regional Haze Background 

 

2

For 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)).
16

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 range3in 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 two-thirds of the visual range that would exist without 

anthropogenic air pollution. In most of the eastern Class I areas of the United States, the average 

visual range is less than 30 kilometers, or about one-fifth of the visual range that would exist 

under estimated natural conditions. 64 FR 35715 (July 1, 1999).

 

3 Visual range is the greatest distance, in kilometers or miles, at which a dark object can be viewed against the sky.
17

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 areas4 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 

 

4 Areas 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.”
18

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 long-term regional 

coordination among states, tribal governments and various federal agencies. As noted above, 

pollution affecting the air quality in Class I areas can be transported over long distances, even 

hundreds of kilometers. Therefore, to 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, 

 

5 EPA’s regional haze regulations require subsequent updates to the regional haze SIPs. 40 CFR 51.308(g) – (i).
19

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 Shoshone-Bannock 

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.6In 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 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 

 

6

Pursuant 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. 
20

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

sources8built 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 

 

7 The preamble to the RHR provides additional details about the deciview. 64 FR 35714, 35725 (July 1, 1999).

8 The set of “major stationary sources” potentially subject to BART is listed in CAA section 169A(g)(7).
21

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.
22

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.9The 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 

 

9 CAA 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).
23

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 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 

 

11 See CAA section 110(a)(2) (requirements for SIPs).
24

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.

 

12 Center for Energy and Economic Development v. EPA, 398 F.3d 653 (D.C. Circuit 2005)

13 Letter from Stephen A. Owens, ADEQ, to Wayne Nastri, EPA (December 14, 2008). 
25

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 US 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. 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.

 

14 See CAA section 110(k)(1)(B). 
26

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 BARTeligible 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 
27

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 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 

 

15 70 FR 39104, 39161

16 See Docket Item B-15.
28

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 

Impacta

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

a Average 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-for-BART and subject-to-BART sources, we do 

 

17 EPA 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.

18 See 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.
29

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-by-pollutant 

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

 

19 40 CFR Part 51, Appendix Y, § IV.D.
30

 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 Non-Air Quality Environmental Impacts and Document 

Results22

 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 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. 

 

20 Step 4 includes evaluating the cost of compliance, energy impacts, non-air quality environmental impacts, and 

remaining useful life.

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

22 We 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.
31

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 

 

23 We 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-by-source basis under the cost and visibility factors of our evaluation in section VI.C.
32

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 non-air 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 

 

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

25 See, e.g. id. p. 53. 
33

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 
34

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 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

 

26 Note 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.
35

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

 

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
36

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. AEPCO Apache Generating Station 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
37

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 FACTORSA

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

a

See Docket Item B-02 (Table 3-1 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

 

28 See Docket Item B-2. Page 2-1 of AEPCO Apache 1 BART Analysis

Control Optionb Emission Emissions Annualized 

Cost-effectivenessd

($/ton)

Visibility Improvementc

(dv)
38

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 

 

29 See Docket Item B-02. Appendix A (Economic Analysis) of AEPCO Apache 1 BART Analysis.

30 See Docket Item B-02. Page 2-1 of AEPCO Apache 1 BART Analysis 

Rate

(lb/MMBtu)

Removed

(tons/yr)

Cost

($/year)

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 NAa0.24 NAa

SCR with LNB + 

FGR 0.07 455 5,704,798 12,538 53,152 0.409 0.169

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

b

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

c Visibility 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.
39

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 cost-effectiveness 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

 

31 See Docket Item B-01. Emission rate as specified in Table 10.2, Appendix D (Technical Support Document) of 

Arizona Regional Haze SIP
40

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 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-effectivenessa

($/ton)

Visibility Improvementb

(dv)

Average Incremental 

(from 

previous)

Total (from 

base case)

Incremental 

(from 

previous)

 

32 See Docket Item B-02, Page 2-1 of AEPCO Apache 1 BART Analysis.

33 See Docket Item B-01. Emission rate as specified in Table 10.5, Appendix D (Technical Support Document) of 

Arizona Regional Haze SIP
41

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.

b As 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.

 

34 See Docket Item B-02. Page 2-2 of AEPCO Apache 1 BART Analysis
42

AEPCO also examined multiple control options for SO2 on Apache 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 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-effectivenessa

($/ton)

Visibility Improvementb

(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 B01.

b As 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.

 

35 See Docket Item B-01. Emission rate as specified in Table 10.7, Appendix D (Technical Support Document) of 

Arizona Regional Haze SIP
43

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 dry-bottom, 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 sub-bituminous coal. Although there are physical differences between the two units, ADEQ 

found that the overall 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 
44

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 add-on 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.

 

36 See 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.

37 See Docket Item B-03 and B-04, AEPCO Apache BART Analyses, page 2-2.

38 See 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

39 As listed in Table 3-2, Docket Items B-03 and B-04, AEPCO Apache BART Analyses.

40 As 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)
45

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 Improvementa

(deciviews)

Cost per 

Deciv

Improve

($/dv

Average 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 -- $1,99

ROFA 0.26 1,710 $1,664,000 $973 $305 0.359 0.092 $4,63

SNCR + LNB + 

OFA

0.23 1,953 $1,738,000 $890 $1,860 0.416 0.057 $4,53

ROFA w/ Rotamix 0.18 2,358 $2,225,000 $944 $866 0.491 0.075 $4,17

SCR + LNB + OFA 0.07 3,250 $6,102,000 $1,878 $4,346 0.676 0.185 $9,02

Apache Unit 3

OFA (baseline) 0.43 -- -- -- -- -- --

LNB + OFA 0.31 926 $532,808 $575 -- 0.206 -- $2,58

ROFA 0.26 1,312 $1,643,241 $1,252 $322 0.298 0.092 $5,48

SNCR + LNB + 

OFA

0.23 1,543 $1,717,633 $1,113 $1,920 0.356 0.058 $5,00

ROFA w/ Rotamix 0.18 1,929 $2,181,833 $1,131 $873 0.436 0.080 $4,82

SCR + LNB + OFA 0.07 2,778 $6,062,301 $2,182 $4,571 0.633 0.197 $9,57

a At 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
46

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 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 

 

41 Arizona SIP submittal, "Appendix D: Arizona BART – Supplemental Information", p.65.

42 Docket Item B-01, Arizona Regional Haze SIP, Appendix D, Page 65. 
47

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 

 

43 See BART Guidelines, § IV.E.2.

44 We 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 
48

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. 

 

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. 

45 See 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.
49

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

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

 

46 See AEPCO BART Analysis Technical Memorandum dated July 8, 2009, page 12. 
50

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 20247 (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 

 

47 See 40 CFR Part 51 Appendix M.

48 EPA is proposing SCR as BART for all of the coal-fired units. See Section VII.

49 See 40 CFR Part 60 Appendix A.

50 See Arizona Regional Haze SIP, Appendix D, pages 69-71 for ADEQ’s BART Analysis for SO2 at Apache Units 

2 and 3. 
51

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 

 

51 See AEPCO Apache Unit 2 BART Analysis
52

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 fivefactor 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 cost-effective 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

 

52 See BART Guidelines § IV.E.4. 

53 See, e.g. Apache Unit 2 BART Analysis, Table 3-1. 
53

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 BART-eligible. 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 

BART-eligible. Based on information provided by APS, the Cholla units operate on a blend of 

bituminous and sub-bituminous 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 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 Improvementa

(deciviews)

Cost per 

decivie

improvem

($/dv

Average 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 -- $3,4

SNCR + LNB + 

SOFA 0.17 3,900 $2,175,000 $558 $2,628 0.218 0.031 $9,9

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

 

54 A 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. 

55 See Docket Item B-06 through -08, APS Cholla BART Analyses, page 2-2.
54

ROFA w/ 

Rotamix 0.12 4,485 $3,384,000 $755 $2,323 0.261 0.029 $12,9

SCR + LNB + 

SOFA 0.07 5,071 $9,625,000 $1,898 $10,650 0.287 0.026 $33,5

Cholla 3

COFA (baseline) 0.41 -- -- -- -- -- --

LNB + SOFA 0.22 2,096 $635,000 $303 -- 0.13 -- $5,0

SNCR + LNB + 

SOFA 0.17 2,648 $2,157,000 $815 $2,757 0.16 0.038 $13,1

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

ROFA w/ 

Rotamix 0.12 3,200 $3,308,000 $1,034 $2,410 0.20 0.029 $16,7

SCR + LNB + 

SOFA 0.07 3,751 $9,569,000 $2,551 $11,363 0.23 0.032 $41,6

Cholla 4

COFA (baseline) 0.42 -- -- -- -- -- --

LNB + SOFA 0.22 3,390 $820,000 $242 -- 0.21 -- $3,9

SNCR + LNB + 

SOFA 0.17 4,259 $2,852,000 $670 $2,338 0.27 0.058 $10,7

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

ROFA w/ 

Rotamix 0.12 5,129 $4,537,000 $885 $1,951 0.34 0.055 $13,5

SCR + LNB + 

SOFA 0.07 5,998 $13,230,000 $2,206 $10,003 0.41 0.072 $32,4

a At 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 

 

56 See 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.

57 As described in Table 3-2, Docket Items B-06 through -08, APS Cholla BART Analyses.

58 As listed in Table 2-1, Docket Items B-06 through -08. Annual capacity factors used for each unit are 91 percent

(Cholla 2), 86percent (Cholla 3), and 93 percent (Cholla 4).
55

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 costeffectiveness, (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 and $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). 
56

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 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 

 

59 Docket Item B-01, Arizona Regional Haze SIP, Appendix D, Page 79.

60 Id.
57

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 

 

61 See Arizona Regional Haze SIP, Appendix D, pages 79-81 for ADEQ’s BART Analysis for PM10 at Cholla Units 

2, 3 and 4.
58

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.

 

62 See Arizona Regional Haze SIP, Appendix D, pp. 81-83, for ADEQ’s BART Analysis for SO2 at Cholla Units 2, 

3 and 4.
59

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 cost-effective 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 

 

63 See Docket Item G-01, Consent Decree between United States and Salt River Project Agricultural Improvement 

and Power District.
60

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 plantwide 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 

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. 

 

64 See Docket Item B-10, SRP Coronado BART Analysis, page 3-1.

65 See Docket Item B-10, SRP Coronado BART Analysis, p 4-5.
61

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

Control 

Option

Emission Rate 

(lb/MMBtu) Total 

Emissions 

Removeda

(tons/yr)

Total 

Annualized 

Cost

($/year)

Cost-effectivenessb

($/ton)

Visibility Improvementc

(deciviews)

Cost per total 

deciview 

improvementd

($/dv)

Imp

Visi

(d

Unit 1 Unit 2 Average Incremental 

(from 

previous)

Total 

(from 

baseline)

Incremental 

(from 

previous)

Total 

(from 

base 

case)

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

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

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

a

SRP 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 c

included in the RH SIP.

c Visibility improvement at the Class I area exhibiting the greatest baseline visibility impact, Petrified Forest National Park, from the SR

BART Analysis.

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

included in the RH SIP, and the visibility improvement at Petrified Forest National Park, from the SRP Coronado BART Analysis.

e Visibility index used in the Arizona RH SIP is the average of the impacts over the nine closest Class I areas.

f This 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. 

 

66 See Docket Item B-11, Additional SRP Coronado response 
62

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. 

 

67 Arizona RH SIP, Appendix D, p.112.
63

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 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. 

 

68 Docket Item B-01, Arizona Regional Haze SIP, Appendix D, Page 112. 
64

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 

 

69 Arizona Regional Haze SIP, Appendix D, p. 112.
65

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 

 

70 We 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. 

71 See 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.. 
66

determination at Coronado. However, we are seeking comment on whether additional costeffective 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 20273 (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 lowsulfur coal and partial wet flue gas.75 However, the consent decree between EPA and SRP 

 

73 See 40 CFR Part 51 Appendix M.

74 See 40 CFR Part 60 Appendix A.

75 See 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.
67

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 percent or 

a 30-day rolling average SO2emissions 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 Costeffectiveness ($ 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 
68

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 lower-sulfur 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

 

76 40 CFR 51.308(e)(1). 

77 See, e.g. CAA section 110(a)(2) (F) and 40 CFR 51.212(c).

78 As 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.
69

A. EPA’s BART Analysis for NOx

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. Cost 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 
70

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 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 

 

79 http://www.epa.gov/airmarkt/progsregs/epa-ipm/BaseCasev410.html#documentation
71

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.

 

80 40 CFR Part 51, Appendix Y § IV.D.3. 
72

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 addon post-combustion 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 site-specific 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 

 

81 70 FR 39166

82 See 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. 
73

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 

 

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).” 
74

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 non-catalytic 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 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

 

85 “Impact of Ammonia in Fly Ash on its Beneficial Use,” Memorandum from Nancy Jones and Stephen Edgerton, 

EC/R Incorporated, to Anita Lee, U.S. EPA/Region 9, August 31, 2010. Also see the TSD for further discussion.
75

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 

State-enforceable 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 5.886 to determine

the baseline and post-control visibility impacts for all three facilities. EPA followed the modeling 

 

86 EPA relied on version 5.8 of CALPUFF because it is the EPA-approved version promulgated in the Guideline on 

Air Quality Models (40 CFR 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 39122-39123, 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.
76

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 contractor87 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. 

 

87 Technical 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

88 CALMET/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 .

89 Revised 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.
77

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

 

90 “Particulate Matter Speciation”, National Park Service, 2006. 

http://www.nature.nps.gov/air/Permits/ect/index.cfm
78

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.

 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.

 

91 Estimating Total Sulfuric Acid Emissions from Stationary Power Plants, Version 2010a, 1020636, Technical 

Update, Electric Power Research Institute, April 2010
79

 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 
80

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 

 

92 Pitchford, 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/

94 BART 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
81

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 visibility

methods are available in the TSD.

 B. EPA’s BART Determinations

 1. Apache Units 2 and 3

 a. Costs of Compliance

 

96 Additional Regional Haze Questions”, September 27, 2006 Revision, EPA OAQPS
82

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. 

 

97 BART Guidelines, 40 CFR Part 51, Appendix P, Section IV.D.4.d
83

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

Unit Baseline 

Emission 

Rate1

(lb/MMBtu)

SCR 

Emission 

Rate

SCR 

Control 

Efficiency

(percentage)

Apache 2 0.371 0.05 87%

Apache 3 0.438 0.05 89%

1

This 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. 

 

98 As listed in Table 2-1 in Docket Items B-03 and B-04, Apache BART Analyses

99 We 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. 
84

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/MMB

tu)

Emission Rate Emissions 

Removed

Annual Cost Cost-effectiveness ($/ton)

(lb/hr) (tpy) (tpy) ($/yr) 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

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 
85

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 

 

100 Apache Unit 4, which consists of four simple-cycle 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.
86

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 cost-effectiveness, 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

 

101 Arizona Regional Haze SIP, Appendix E, Public Process, NPS General BART Comments on ADEQ BART 

Analyses (November 29, 2010), p. 4. 
87

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.
88

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

 c. EPA’s BART Determination

In considering the results of the five-factor 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

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
89

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 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, 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 cost-effective, there may be cases where the installation

of controls would affect the viability of continued plant operations. [...]You may take 
90

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 

 

102 70 FR 39171

103 See 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_Coo

perative_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.
91

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 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 close-coupled over fire air (COFA). APS has since installed lowNOx 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 
92

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, higher-NOx 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 

 

105 A 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. 
93

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 

Rate1

(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%

1 As noted previously, this baseline emission rate 

reflects the installation of LNB+OFA
94

 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 power plants that are the subject of today’s proposed 

action.108

 

106 As listed in Table 2-1 in Docket Items B-06 through B-08, Cholla BART Analyses

107 We 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. 

108 We 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 
95

 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

 

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.
96

As indicated in Table 19, our calculations indicate that the SCR-based control options 

have average cost-effectiveness 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 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 Cholla are described here. EPA made a NOx BART determination for Cholla Units 2, 

3 and 4, but Unit 1 (which is not BART-eligible) 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, 
97

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 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
98

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. 
99

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 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 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. 
100

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 

 

109 See 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).

110 See 40 CFR Part 51, Appendix Y, Section IV.D.4.d.
101

emission rate in our BART analysis and are examining only one control scenario 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%

 

111 A 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.

112 See Docket Item B-10, SRP Coronado BART Analysis, page 4-5
102

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

 

113 We 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. 

114 We 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.
103

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 -- 8,721,6361-- --

SCR@0.05 

lb/MMBtu 0.05 199 776 466 8,993,116 -- 583

1 Annual 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.

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 

cost-effectiveness of such an option is $583/ton, making it a control option that we would 
104

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 non-CBI 

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-
105

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. 
106

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)
107

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

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 Determination

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 
108

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. 
109

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. 
110

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.

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 
111

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 threeyear compliance time frame for design and installation of SCR, but ultimately allowed for a fiveyear 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 

 

115 Available 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
112

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 cost-effective for Coronado Unit 

2 to meet an emissions limit of 0.050 lb/MMBtu for NOx.
113

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

TABLE 25–SUMMARY OF BART COMPLIANCE DATES

Unit

Compliance Date

NOx PM10 SO2

Apache Generating Station Unit 1 Five years 180 days 180 days
114

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
115

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 
116

Reduction Act, a ‘‘collection of information’’ is defined as a requirement for ‘‘answers to * * * 

identical reporting or recordkeeping requirements imposed on ten or more persons * * *.’’ 44 

U.S.C. 3502(3)(A). Because the proposed FIP applies to just three facilities, the Paperwork 

Reduction Act does not apply. See 5 CFR 1320(c). Burden means the total time, effort, or 

financial resources expended by persons to generate, maintain, retain, or disclose or provide 

information to or for a Federal agency. This includes the time needed to review instructions; 

develop, acquire, install, and utilize technology and systems for the purposes of collecting, 

validating, and verifying information, processing and maintaining information, and disclosing 

and providing information; adjust the existing ways to comply with any previously applicable 

instructions and requirements; train personnel to be able to respond to a collection of 

information; search data sources; complete and review the collection of information; and 

transmit or otherwise disclose the information. An agency may not conduct or sponsor, and a 

person is not required to respond to a collection of information unless it displays a currently valid 

Office of Management and Budget (OMB) control number. The OMB control numbers for our 

regulations in 40 CFR are listed in 40 CFR part 9.

C. Regulatory Flexibility Act

The Regulatory Flexibility Act (RFA) generally requires an agency to prepare a 

regulatory flexibility analysis of any rule subject to notice and comment rulemaking 

requirements under the Administrative Procedure Act or any other statute unless the agency

certifies that the rule will not have a significant economic impact on a substantial number of 

small entities. Small entities include small businesses, small organizations, and small 

governmental jurisdictions. For purposes of assessing the impacts of today’s proposed rule on 

small entities, small entity is defined as: (1) A small business as defined by the Small Business 
117

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 (D.C. 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 

 

118 See 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.

119 See 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_Po

wer_Cooperative_Inc.pdf. 
118

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 cost-effective, 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
119

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 
120

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 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 
121

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
122

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 lowincome 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 oxides, Sulfur dioxide, Particulate matter, Reporting and 

recordkeeping requirements, Visibility, Volatile organic compounds. 

July 2, 2012 / signed by /

________________ ______________________

Dated: Jared Blumenfeld

Regional Administrator, Region 9
123

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. 

D—Arizona 

2. Add new paragraph (e) to §52.145 Visibility Protection, to read as follows: 

§ 52.145 (e) Federal implementation plan for regional haze. 

(1) Applicability. This paragraph (e) applies to each owner/operator of the following coalfired 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.
124

(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). 
125

Owner(s)/operator(s) means any person(s) who own(s) or who operate(s), control(s), or 

supervise(s) one more of 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.

PM-10 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 
126

million British thermal units (lb/MMBtu). Each emission limit shall be based on a rolling 

30-boiler-operating-day 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. 

a. 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:

Compliance Date

Unit NOx PM10 SO2

Apache Generating 

Station, Unit 1 

[INSERT DATE 

FIVE YEARS

AFTER DATE OF 

[INSERT DATE 

180 DAYS AFTER 

DATE OF 

[INSERT DATE 

180 DAYS 

AFTER DATE OF 
127

PUBLICATION OF 

FINAL ACTION IN 

THE FEDERAL 

REGISTER].

PUBLICATION 

OF FINAL 

ACTION IN THE 

FEDERAL 

REGISTER]

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 

[INSERT DATE 

180 DAYS AFTER 

DATE OF 

PUBLICATION IN 

THE FEDERAL 

[INSERT DATE 

180 DAYS 

AFTER DATE OF 

PUBLICATION 

IN THE 
128

REGISTER]. REGISTER] 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]

(5) Compliance determinations for NOX and SO2. 

a. Continuous emission monitoring system.

i. 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 
129

defined by Part 75, that CEMs data shall be treated as missing data and not used 

to calculate the emission average.

ii. 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. 

b. Compliance determinations for NOX. 

i. 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) boiler-operating 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 
130

within any boiler operating day, including emissions from startup, shutdown, and 

malfunction. 

ii. 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. 

c. Compliance determinations for SO2. 

i. 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) boiler-operating 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 boiler-operating day, including emissions 

from startup, shutdown, and malfunction. 

ii. 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 
131

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. 
132

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 
133

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 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).